Study for LNG Fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 1 Background and Purposes

Home , Bangladesh Last House, Fenchuganj Upazila, Kumargaon, Petrobangla, Raozan power station, Siddhirganj

Fiscal Year 2018 Project Implementation Feasibility Study for High-Quality Energy Infrastructure Overseas Development

Study for LNG fired Combined Cycle Power Plant in Bangladesh

Final Report

March, 2019 Ministry of Economy, Trade and Industry Infrastructure System and Water Industry Manufacturing Industries Bureau

Subcontractor Marubeni Power Systems Corporation

Terms of Reference

Chapter 1Background and Purposes 1.1 Background of the Study ...... 1-1 1.2 Purpose of the Study ...... 1-2 Chapter 2 Electric Power Supply and Demand in Bangladesh and Background of the Project 2.1 Current Situation between Electric Power Supply and Demand, Supply Plans in Bangladesh ... 2-1 2.2 Development of LNG Receiving Terminals in Bangladesh and Corresponding Power Plant Projects 2-4 2.3 Discussion from the Perspective of Development History in Japan ...... 2-5 2.3.1 Position of LNG in Power Generation Mix in Japan ...... 2-5 2.3.2 Possibility of Development of Japan’s Project Development Technologies in Bangladesh ...... 2-6 Chapter 3Study for Basic Plan of the Project 3.1 Basic Concept of the Project ...... 3-1 3.2 Basic study of project business model...... 3-2 3.3 Study for project basic plan and major items of the power plant ...... 3-4 3.4 Concept of candidate site for this project ...... 3-5 3.5 Study for overall schedule of the project ...... 3-6 Chapter 4 Select of Project Candidate Site 4.1 Select of Project Candidate Site ...... 4-1 4.2 Field survey ...... 4-2 4.2.1 Siddhirganj Thermal Power Plant (BPDB) ...... 4-3 4.2.2 Feni Thermal Power Plant (EGCB) ...... 4-5 4.2.3 Gazaria Thermal Power Plant (RPCL) ...... 4-7 4.3 Comprehensive evaluation of candidate project site ...... 4-8 4.3.1 Siddhirganj Thermal Power Plant (BPDB) ...... 4-9 4.3.2 Feni Thermal Power Plant (EGCB) ...... 4-9 4.3.3 Gazaria Thermal Power Plant (RPCL) ...... 4-10 Chapter 5Study for Power Plant 5.1 Conceptual Design ...... 5-1 5.1.1 Design condition ...... 5-1 5.1.2 Outline of power plant system ...... 5-2 5.1.3 Examination for Shaft Configuration ...... 5-3 5.1.4 Gas Turbine Candidates...... 5-5 5.2 Basic Systems in Power Plant Design ...... 5-12 5.2.1 Gas Turbine System ...... 5-12 5.2.2 Heat Recovery Steam Generator (HRSG) and Auxiliary Equipment ...... 5-19 5.2.3 Steam Turbine System ...... 5-23 5.2.4 Electrical equipment ...... 5-27 5.2.5 Plant C&I system (Common for three sites) ...... 5-33 5.2.6 Common facilities ...... 5-36

5.2.7 Switchyard ...... 5-41 5.3 Study for plant layout of power plant ...... 5-42 5.3.1 Design condition ...... 5-42 5.3.2 Plant layout ...... 5-42 5.4 Study for construction schedule of power plant ...... 5-46 Chapter 6Study of Power Evacuation 6.1 Basic Study of Power Evacuation ...... 6-1 6.1.1 Precondition ...... 6-1 6.1.2 Study of Transmission Line Voltage ...... 6-1 6.1.3 Study of Conductor Size...... 6-2 6.1.4 Study of insulator ...... 6-3 6.1.5 Study of transmission line tower design ...... 6-4 6.1.6 Estimated transmission line cost per kilometer ...... 6-6 6.2 Planning of transmission line route ...... 6-6 6.2.1 Planning condition ...... 6-6 6.2.2 Estimation of Power Flow ...... 6-6 6.2.3 Study of the route of transmission line ...... 6-16 6.2.4 Estimation of budget costs of transmission line for power evacuation ...... 6-23 6.2.5 Expected construction schedule of transmission line for grid ...... 6-24 Chpater 7Environmental Evaluation 7.1 Siddhirganj Power Station ...... 7-1 7.1.1 Study Area ...... 7-1 7.1.2 Geographical Features ...... 7-2 7.1.3 Environmental Evaluation and Expected Risk ...... 7-3 7.1.3.1 Influence on Ecosystem ...... 7-3 7.1.3.2 Influence on Air and Water Quality ...... 7-3 7.1.4 Countermeasure ...... 7-3 7.2 Feni Power Station ...... 7-6 7.2.1 Study Area ...... 7-6 7.2.2 Geographical Features ...... 7-7 7.2.3 Environmental Evaluation and Expected Risk ...... 7-8 7.2.3.1 Influence on Ecosystem ...... 7-8 7.2.3.2 Influence on Air and Water Quality ...... 7-8 7.2.4 Countermeasure ...... 7-8 7.3 Gazaria Power Station ...... 7-10 7.3.1 Study Area ...... 7-10 7.3.2 Geographical Features ...... 7-11 7.3.3 Environmental Evaluation and Expected Risk ...... 7-11 7.3.3.1 Influence on Ecosystem ...... 7-11 7.3.3.2 Influence on Air and Water Quality ...... 7-12 7.3.4 Countermeasure ...... 7-12

Chapter 8Examinations of Carbon Dioxide (CO2) Reduction

8.1 How to Determine the Amount of CO2 Emissions ...... 8-1 8.1.1 Calculation Method ...... 8-5

8.1.2 How to Determine the Baseline and Method for Calculating the CO2 Reduction Effect 8-6

8.2 Examination and Evaluation of CO2 Emission Reduction by the Project ...... 8-7 8.3 Summary ...... 8-7 Chapter 9Study of Fuel Procurement 9.1 Supply of LNG ...... 9-1 9.1.1 Production of Natural Gas and LNG ...... 9-1 9.1.2 Trends in the Major Producers ...... 9-4 9.2 LNG Demand ...... 9-12 9.2.1 Natural Gas and LNG Demand ...... 9-12 9.2.2 Demand Trends in the Major Countries ...... 9-12 9.3 LNG Supply-Demand Trends ...... 9-14 9.3.1 Current LNG Supply-Demand Trends...... 9-14 9.3.2 Long-Term LNG Supply-Demand Trends ...... 9-17 9.3.3 Gas Supply-Demand Situation in Bangladesh ...... 9-19 9.3.3.1 Gas Managing Companies ...... 9-19 9.3.3.2 Natural Gas Supply-Demand Situation in Bangladesh ...... 9-20 9.4 LNG Import Plan in Bangladesh ...... 9-22 9.5 Gas Pipeline...... 9-24 9.5.1 Construction Plant of Gas Pipeline in Bangladesh ...... 9-24 9.5.2 Study for Each Candidate Power Station ...... 9-25 9.6 LNG Price Trends ...... 9-27 9.6.1 Current LNG Price ...... 9-27 9.6.2 Long-Term LNG Price Forecast ...... 9-28 9.7 Conclusion ...... 9-32 Chapter 10 Economic Evaluation of the Project 10.1 Finance Overview ...... 10-1 10.2 Yen Credit Loan ...... 10-1 10.3 Export Credit ...... 10-2 10.4 Project Finance (Investment Finance) ...... 10-3 10.5 Public Private Partner ...... 10-3 10.6 Project Model Study ...... 10-4 10.7 Financial Analysis Method ...... 10-4 10.7.1 Calculation of Financial Internal Rate of Return (FIRR) and Benefit Cost Ratio (B/C Ratio) ...... 10-12 10.7.2 Calculation of FIRR and electricity cost based on LNG cost ...... 10-17 10.8 Calculation of Economic Internal Rate of Return ...... 10-19 Chapter 11Comprehensive Evaluation

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11.1 Technical Evaluation of the Project ...... 11-1

11.2 Evaluation of CO2 Reduction and Exhaust Gas ...... 11-1 11.3 Matters to Be Considered to Ensure Business Feasibility for the Project ...... 11-1 11.4 Examinations of Business Model and Concept Recommended for the Candidate Sites and Its Economical Efficiency ...... 11-2 11.5 Examinations on Finance ...... 11-3 11.6 Examinations on Superiority of Japanese Companies ...... 11-3 11.6.1 Superiority in Technical Area ...... 11-3 11.6.2 Superiority in Business Area ...... 11-3 11.6.3 Superiority in Financial Area ...... 11-3 11.7 Examinations of Possibilities of Participation of Japanese Companies in Project Implementation11-4 Chapter 12Conclusion 12.1 Conclusion ...... 12-1 12.1.1 Technical Evaluation and Candidate Sites...... 12-1 12.1.2 Economic Evaluation ...... 12-1 12.2 Suggestion ...... 12-1 12.2.1 Feasibility of candidate construction sites ...... 12-1

Table Summary

Table 2.1-1 Power Development plan in PSMP2016 ...... 2-1 Table 2.1-2 List of Gas Fired Power Plant commissioned by 2020 ...... 2-1 Table 2.1-3 List of Gas Fired Power Plant commissioned by 2020 ...... 2-3 Table 2.2-1 Development Project listed in PSMP2016 ...... 2-4 Table 2.3.2-1 Outline of Kawasaki Thermal Power Plant ...... 2-7 Table 3.2-1 Expected Enterprises ...... 3-4 Table 3.3-1 Project Basic Plan and Major Items of the Power Plant ...... 3-5 Table 4.1-1 Candidate Site ...... 4-1 Table 4.1-2 Basic Information of Each Candidate Site ...... 4-1 Table 5.1.1-1 Design Conditions and Specifications ...... 5-1 Table 5.1.3-1 Comparison of Type A, B, and C shaft configurations ...... 5-5 Table 5.2.3-1 Steam Turbine Specification ...... 5-24 Table 5.2.3-2 Condenser Specification ...... 5-27 Table 5.2.4-1 Generator Specification ...... 5-30 Table 5.2.5-1 Control Mode by DCS...... 5-35 Table 6.1.1-1 Electric Generating Entities, Proposed Site and Capacity of Power Plant ...... 6-1 Table 6.1.3-1 Transmission Capacity Calculation Conditions ...... 6-2 Table 6.1.3-2 Conductor currently used EHV T/L in Bangladesh ...... 6-2 Table 6.1.3-3 Capacity of single circuit transmission line [Unit: MW, Power factor: 0.85] ...... 6-3 Table 6.1.3-4 High capacity conductor parameters ...... 6-3 Table 6.1.4-1 Insulator design conditions ...... 6-4 Table 6.1.4-2 Types of number of insulator in various transmission towers ...... 6-4 Table 6.1.6-1 Transmission line construction cost per km ...... 6-6 Table 6.1.6-2 Inflation rate in Bangladesh ...... 6-6 Table 6.2.2-1 Summary of Power Flow Diagrams ...... 6-7 Table 6.2.4-1 Budget costs of transmission line ...... 6-23 Table 8.1-1 Plant Wise Generation (FY 2016-17) (Public Sector) ...... 8-1 Table 8.1-2 Plant Wise Generation (FY 2016-17) (Private Sector) ...... 8-3 Table 8.1-3 Plant Wise Generation Calculation Result ...... 8-5

Table 8.1.1-1 Calculation of CO2 Baseline ...... 8-6

Table 8.1.2-1 Calculation of Annual CO2 Reduction ...... 8-7 Table 9.1.2-1 LNG projects List in the United States ...... 9-6 Table 9.1.2-2 LNG projects List in the Australia ...... 9-10 Table 9.3.1-1 LNG Project under Construction（Excluded United State and Australia） ...... 9-14 Table 9.3.3.1-1 Demarcation of Gas Company in Bangladesh ...... 9-19 Table 9.4-1 Project List of LNG Onshore Terminal in Bangladesh ...... 9-23 Table 9.4-2 Project List of FSRU in Bangladesh ...... 9-23 Table 10.2-1 ODA Loan Table ...... 10-1 Table 10.3-1 CIRR Condition Table ...... 10-3

Table 10.7.1-1 Summary of Siddhirganj Power Station ...... 10-12 Table 10.7.1-2 Summary of Feni Power Station ...... 10-13 Table 10.7.1-3 Summary of Gazaria Power Station ...... 10-14 Table 10.7.1-4 Electricity Tariff vs FIRR ...... 10-15 Table 10.7.2-1 Fuel Cost at Power Station ...... 10-18

Figure Summary

Figure 2.1-1 Long term power demand and supply forecast in Bangladesh ...... 2-2 Figure 2.1-2 Expected Total Output of Gas Fired Power Plant in near future (MW） ...... 2-3 Figure 2.3.1-1 Histogram of power generation volume by energy resource in Japan ...... 2-6 Figure 2.3.2-1 Historical Power generation efficiency at Kaswasaki Thermal Power Plant ...... 2-8 Figure 2.3.2-2 NOx and SOx emission per kWh (international comparison) ...... 2-8 Figure 3.2-1 Overall Schematic Diagram of the Project Business Model ...... 3-3 Figure 3.5-1 Overall Schedule of the Project in case Yen Credit ...... 3-6 Figure 3.5-2 Overall Schedule of the Project in case ECA ...... 3-7 Figure 4.2-1 Location of field survey ...... 4-2 Figure 4.2.1-1 Surrounding area of Siddhirganj thermal power plant ...... 4-3 Figure 4.2.2-1 Surrounding area of Feni ...... 4-5 Figure 4.2.3-1 Surrounding area of Gazaria ...... 4-7 Figure 5.1.3-1 Schematic diagrams for Type A, B, and C shaft configurations ...... 5-4 Figure 5.2.1-1 Longitudinal Section of Typical Gas Turbine/ J Series ...... 5-14 Figure 5.2.1-2 Typical Lube Oil System ...... 5-16 Figure 5.2.1-3 Typical air intake system equipped with two-stage filtration system ...... 5-19 Figure 5.2.2-1 Cross Section of Vertical Type HRSG ...... 5-20 Figure 5.2.3-1 Typical Steam Turbine Unit ...... 5-26 Figure 5.2.4-1 Generator Main Circuit at Siddhirganj ...... 5-28 Figure 5.2.4-2 Generator Main Circuit at Feni and Gazaria ...... 5-29 Figure 5.2.4-3 Generator Typical Sectional View ...... 5-30 Figure 5.2.5-1 Configuration for GTCC Control ...... 5-33 Figure 5.2.6-1 Schematic diagram of compressed air system ...... 5-37 Figure 5.2.6-2 Schematic diagram of fire-fighting system ...... 5-38 Figure 5.2.6-3 Schematic Diagram of Water Treatment System ...... 5-39 Figure 5.2.6-4 Schematic Diagram of Wastewater Treatment System ...... 5-40 Figure 5.2.7-1 Single Line Diagram of Switchyard ...... 5-41 Figure 5.3.2-1 Layout Plan (Siddhirganj) ...... 5-43 Figure 5.3.2-2 Layout Plan (Feni) ...... 5-44 Figure 5.3.2-3 Layout Plan (Gazaria) ...... 5-45 Figure 5.4-1 Construction schedule of power plant ...... 5-46 Figure 6.1.5-1 400 kV Suspension tower ...... 6-5 Figure 6.1.5-2 400 kV Tension tower ...... 6-5 Figure 6.1.5-3 230 kV Suspension tower ...... 6-5 Figure 6.1.5-4 230 kV Tension tower ...... 6-5 Figure 6.2.2-1 400 kV System Diagram for Southeast Region of Bangladesh with Expected Power Flow in 2025 ...... 6-10 Figure 6.2.2-2 400 kV System Diagram for Southeast Region of Bangladesh with Expected Power Flow in 2025 ...... 6-11

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Figure 6.2.2-3 400 kV and 765 kV System Diagram for Southeast Region of Bangladesh with Expected Power Flow in 2035 ...... 6-12 Figure 6.2.2-4 400 kV and 765 kV System Diagram for Southeast Region of Bangladesh with Expected Power Flow in 2035 ...... 6-13 Figure 6.2.2-5 400 kV and 765 kV System Diagram for Southeast Region of Bangladesh with Expected Power Flow in 2035 ...... 6-14 Figure 6.2.2-6 400 kV and 765 kV System Diagram for Southeast Region of Bangladesh with Expected Power Flow in 2035 ...... 6-15 Figure 6.2.3-1 Proposed route of the transmission line ...... 6-16 Figure 6.2.3-2 Situation of the connected substation (Siddhirganj) ...... 6-17 Figure 6.2.3-3 Photo and Image drawing of existing transmission tower (TW2) ...... 6-18 Figure 6.2.3-4 Photo and Image drawing of existing transmission tower (TW1) ...... 6-19 Figure 6.2.3-5 Image drawing of conductor placing of substation ...... 6-19 Figure 6.2.3-6 Proposed route of the transmission line ...... 6-20 Figure 6.2.3-7 The way of connecting to 400kV Meghnaghat Substation ...... 6-21 Figure 6.2.3-8 Proposed route of the transmission line ...... 6-22 Figure 6.2.5-1 Schematic construction schedule of transmission line for grid...... 6-24 Figure 7.1.1-1 Study area around Siddhirganj site for IEE ...... 7-1 Figure 7.2.1-1 Study area around Feni site for IEE ...... 7-6 Figure 7.3.1-1 Study area around Gazaria site for IEE ...... 7-10

Figure 9.1.1-1 CO2 Emission by Natural gas, Oil and Coal ...... 9-1 Figure 9.1.1-2 The proven reserves of natural gas in the world ...... 9-2 Figure 9.1.1-3 Natural Gas Production Change in 2017 ...... 9-3 Figure 9.1.1-4 The production of natural gas in each country in 2017）...... 9-3 Figure 9.1.1-5 Amount of LNG exports in each country in 2017...... 9-4 Figure 9.1.2-1 Amount of LNG Exports in each country in 2017 ...... 9-5 Figure 9.1.2-2 The positions of the natural gas liquefaction projects in United States ...... 9-6 Figure 9.1.2-3 The LNG exports to each export destination by Qatar ...... 9-8 Figure 9.1.2-4 Gas Field (South Pars and North Field) ...... 9-8 Figure 9.1.2-5 Amount of LNG Export Forecast in Qatar ...... 9-9 Figure 9.1.2-6 LNG Project List in Australia ...... 9-10 Figure 9.1.2-7 The LNG exports to each export destination by Australia in 2016 ...... 9-11 Figure 9.1.2-8 Amount of LNG Export Forecast in Australia ...... 9-11 Figure 9.2.1-1 Changes in Natural Gas Consumption in Each Region ...... 9-12 Figure 9.2.2-1 The LNG demand in each of the major countries ...... 9-13 Figure 9.2.2-2 The LNG demand forecast in Divisional Region ...... 9-13 Figure 9.3.1-1 Natural Gas Production Forecast in in divisional Region ...... 9-15 Figure 9.3.1-2 Long Term LNG Export Forecast ...... 9-16 Figure 9.3.1-3 Long Term LNG Demand Forecast in The World ...... 9-17 Figure 9.3.2-1 LNG Supply and Demand Forecast in The World ...... 9-18 Figure 9.3.3.1-1 Distribution Company Map in Bangladesh ...... 9-20

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Figure 9.3.3.2-2 Gas Demand and Supply Forecast in Bangladesh-With Further Upstream Success 9-21 Figure 9.3.3.2-3 Gas Demand and Supply Forecast in Bangladesh – Without Further Upstream Success ...... 9-22 Figure 9.4-1 Location of LNG Onshore Terminal and FSRU Candidate Area ...... 9-23 Figure 9.5.1-1 Gas Pipeline Network in Bangladesh ...... 9-24 Figure 9.5.2-1 Candidate Route of Gas Pipeline at Siddhirganj ...... 9-25 Figure 9.5.2-2 Candidate Route of Gas Pipeline at Feni ...... 9-26 Figure 9.5.2-3 Candidate Route of Gas Pipeline at Gazaria ...... 9-27 Figure 9.6.1-1 Changes in Gas and LNG Price in Major Countries ...... 9-28 Figure 9.6.2-1 Changes in Long-Term Contracts and Short-Term/Spot Contracts ...... 9-29 Figure 9.6.2-2 Trend and Forecast of Natural Gas Price in main area and country ...... 9-30 Figure 10.7.1-1 Electricity Tariff vs FIRR ...... 10-16 Figure 10.7.1-2 Cumulative Cash Flow ...... 10-17

Abbreviations

Abbreviations Proper Name ACSR Aluminum Conductors Steel Reinforced AC Alternating Current AIS Air Insulated Switchgear ASHRAE American Society of Heating Refrigerating and Air-Conditioning Engineers The American Society of Mechanical Engineers, Boiler and Pressure Vessel ASME B&PV Code Code ASTM American Society for Testing and Materials AVR Automatic Voltage Regulator B/C Buyer’s Credit B/C Ratio Benefit-Cost Ratio B/L Bank Loan BAPEX Bangladesh Petroleum Exploration and Production Company Limited Bcm Billion Cubic Metre BCMCL: Barapukuria Coal Mining Company Limited BDT Bangladeshi Taka BGDCL Bakhrabad Gas Distribution Company Limited BGFCL Bangladesh Gas Fields Company Limited BIG-B Bay of Bengal Industrial Growth Belt BMPP Barge Mounted Power Plant BOP Balance of Plant BP British Petroleum BPDB Bangladesh Power Development Board BSDG Black Start Diesel Generator BSRM Bangladesh Steel Re-Rolling Mills BTG Boiler Turbine Generator Btu British Thermal Unit C&I Control and Instrumentation CCR Central Control Room Cct Circuit CCTV Closed Circuit Television CEMS Continuous Emission System CIGRE Conseil International des Grands Reseaux Electriques CIRR Commercial Interest Reference Rate

CO2 Carbon Dioxide COD Commercial Operation Date CRF Capital Recovery Factor DC System Direct Current System

DCS Distributed Control System DC Direct Current DO Dissolved Oxygen DES Delivered Ex-Ship DESCO Dhaka Electricity Supply Company Limited DOE Department of Environment EC Electrical Conductivity ECA Export Credit Agency ECR Environmental Conservation Regulation EDG Emergency Diesel Generator EGCB Electricity Generation Company of Bangladesh EMP Environmental Management Plan ETP Effluent Treatment Plant EIA Environmental Impact Assessment FID Final Investment Decision FIRR Financial Internal Rate of Return FSRU Floating Storage Regasification Unit FY Fiscal Year GCB Gas Circuit Generator GDP Gross Domestic Product GE General Electric Company GEN Generator GHG Green House Gas Emission GIS Gas Insulated Switchgear GNI Gross National Income GSUT Generator Step-Up Transformer GT Gas Turbine GTCC Gas Turbine Combined Cycle GTCL Gas Transmission Company Limited GWh Giga Watt hour GWh Giga Watt hour HEPA Filter High Efficiency Particulate Air Filter HFO Heavy Fuel Oil HMI Human Machine Interface HP High Pressure HRSG Heat Recovery Steam Generator HSD High Speed Diesel Hz Hertz I/O Input/Output

IEA International Energy Agency IEC International Electronical Commission IEE Initial Environmental Examination IEEE Institute of Electrical and Electronics Engineers IGU International Gas Union IMF International Monetary Fund INDC Intended Nationally Determined Contributions IP Internal Pressure IPB Isolated-phase Bus JBIC Japan Bank of International Cooperation JGTDSL Jalalabad Gas Transmission and Distribution System Limited JICA Japan International Cooperation Agency JOGMEC Japan Oil, Gas and Metals National Corporation KGDCL: Karnaphuli Gas Distribution Company Limited kJ Kilo Joule km Kilo meter kN Kilo Newton kPa Kilo Pascal kV Kilo Volt LDC Lower Development Company LHV Lower Heating Value LIBOR London Interbank Offered Rate LIWV Lightning Impulse Withstand Voltage LNG Liquefied Natural Gas LP Low Pressure LTSA Long Term Service Agreement LV SWGR Low Voltage Switchgear MACC More Advanced Combined Cycle MCC Motor Control Center MCF Million Cubic Feet MCM Million Cubic Metre MGMCL: Maddhapara Granite Mining Company Limited MHPS Mitsubishi Hitachi Power Systems, Ltd MMCFD Million Cubic Feet per day MoPEMR Ministry of Power Energy and Mineral Resources MPa abs Maga Pascal absolute MPag Mega Pascal Gauge MT Million Ton MTPA Million Ton Per Annum

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MV SWGR Medium Voltage Switchgear MW Mega Watt NEXI Nippon Export and Investment Insurance NFPA National Fire Protection Association NOx Nitrogen Oxides NPW Net Present Worth NTP Notice to Proceed ODAF Oil Direct Air Forced OECD Organization for Economic Co-operation and Development OEM Original Equipment Manufacturer OLR Overhead Relay ONAN Oil Natural Air Natural OPEC Organization Petroleum Exporting Countries OTC Offshore Technology Conference PABX Private Automatic Branch Exchange Petrobangla Bangladesh Oil, Gas & Mineral Cooperation PGCB Power Grid Company of Bangladesh Limited PGCL: Pashchimanchal Gas Company Limited PP Power Plant ppm Parts Per Million PPP Public Private Partner PQ Pre-Qualification Pre-FS Pre-Feasibility Study PSMP 2016 People’s Republic of Bangladesh Power & Energy Sector Master Plan 2016 PWC Price Water House Coopers RE Renewable Energy RH Relative Humidity RMS Regulating Metering Station RPCL Rural Power Company Limited RPGCL: Rupantarita Prakritik Gas Company Limited SAT Station Auxiliary Transformer SGCL: Sundarban Gas Company Limited SGFL Sylhet Gas Fields Limited SGX Singapore Exchange Siemens Siemens AG SIWV Switching Impulse Withstand Voltage SOx Sulfur Oxides SPC Special Purpose Company SPM Suspended Particulate Matter

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SSS Clutch Synchro Self Shifting Clutch ST Steam Turbine STEP Special Terms for Economic Partnership SWGR Switch Gear TGTDCL Titas Gas Transmission and Distribution Company Limited TDS Total Dissolved Solids TJ Ton Joule UAT Unit Auxiliary Transformer UPS Uninterruptible Power Supply USC Ultra Super Critical Power Plant USD United State Dollar VAT Value Added Tax W/cm2 Watt per square cent meter WEO World Energy Outlook Δ-Star Delta-Star

xiv Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 1 Background and Purposes

Chapter 1 Background and Purposes Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 1 Background and Purposes

1.1 Background of the Study The real Gross Domestic Product (GDP) of the People's Republic of Bangladesh has been continuously growing at more than 6%/annum for over 10 years. The December 2018 data announced by the World Bank shows that the growth rate of the real GDP of Bangladesh reached approximately 6.5% in 2018; the same level of GDP growth is forecast to be maintained also in the future. According to PwC (PricewaterhouseCoopers), the GDP growth rate until 2050 of the country is expected to become third in the world. In addition, the Gross National Income (GNI) per capita exceeded 1,000 US dollars in 2016, and in around 2015, Bangladesh entered its demographic bonus period1, which is expected to continue for approximately 40 years. Those facts suggest that the time has been ripe for high economic growth. During the period from 2009 to 2015, electric power demand in Bangladesh recorded a very high rate of increase, approximately 12% per year on average. According to "People’s Republic of Bangladesh Power & Energy Sector Master Plan"(PSMP 2016) issued in 2016, Bangladesh aims to become a developed country by 2041, and electric power demand is expected to have increased to approximately 50,000 MW in 2041. The Bangladeshi government has been making efforts to accelerate economic growth and to cope with accompanying rapid increase in electric power demand, with the purpose of increasing the power plant capacity to 24,000 MW and the national electrification rate to 100% (the actual electrification rate was 83% in June 2017) by 2021 and boosting the power plant capacity to 60,000 MW by 2041 (annual growth rate of 4.69%). In order to achieve this goal, each electric power company has drawn up plans for constructing electric power installations. In Bangladesh, gas-fired power generation that uses natural gas as main fuel accounts for most of the power generation mix (the rate of the power supply brought about by natural gas is approximately 66% of the total power supply at the end of FY2016). With consideration given to energy security, generating cost, environmental friendliness, and other related matters, the country has drawn up plans for increasing the ratios of coal-fired power generation, hydroelectric power generation, nuclear power generation, and renewable energy generation. However, thermal power generation using natural gas is still expected to play significant roles as base load power supply. The supply of domestic natural gas reached its peak in 2017 and is currently decreasing due to the exhaustion of natural gas reserves in existing gas fields. Although there are some plans for developing new gas fields, the supply capability is not enough to meet demand. In order to bridge the gap between supply and demand, the Bangladeshi government has been taking action on the import of liquefied natural gas (LNG) in 2018, the government started importing 500 Million Cubic Feet per day (MMCFD) of LNG with the aid of a Floating Storage Regasification Unit (FSRU). In 2019, a second FSRU (capacity: 500 MMCFD) will be inogurated. The supply of natural gas is thus increasingly shifting from domestic gas to import LNG; simultaneously, construction of efficient Gas Turbine Combined Cycle (GTCC) power plants2 is increasingly drawing attention. In such a situation, Japan and Bangladesh made an agreement in 2014 on the basis of the concept of Bangladesh growth strategy called the "Bay of Bengal Industrial Growth Belt (BIG-B)." BIG-B consists

1-1 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 1 Background and Purposes

mainly of the following three elements: 1) development of economic infrastructures; 2) stable supply of electric power; 3) development of special economic zones. Japan will cooperate with Bangladesh in such a manner as to allow Bangladesh to establish high-quality infrastructures by making the most of Japan's advanced technologies. In accordance with the agreement, concrete project development for infrastructure construction is underway in cooperation between the two countries. Various projects, such as an ultra supercritical coal-fired thermal power generation project and a fundamental transmission network enhancement project, are under implementation as Japan's yen-loan projects. It is expected that further enhancement in the electric power infrastructure section will be implemented in cooperation with Japan.

1.2 Purpose of the Study This study examines the feasibility of a new gas-fired power plant and its related facilities. The power plant, which will combust import LNG, is planned to cope with power shortage in Bangladesh and to spread Japan's high-quality energy infrastructure technologies. On the premise that GTCC is to be applied as power generation method, the study draws up specifications that are appropriate for this project when it is implemented in candidate construction sites, and surveys and analyzes its effectiveness and necessity. Candidate construction sites are listed through the surveys of the current situation of electric power supply and demand in Bangladesh and the hearings that are held on needs with major electric power generation companies. The candidate construction sites subject to this study are then selected from the listed sites through evaluation and comparison and through prioritization taking the corresponding electric power generation companies into account. The feasibility of power plant construction is examined from a comprehensive viewpoint through the selection of GTCC design conditions/specifications for major equipment, the estimation of the project cost, the formulation of the project schedule for stages after this study, Initial Environmental Examination (IEE), the examination of environmental burdens and other related matters, and the evaluation of economical efficiency, based on the selected candidate construction sites.

1-2 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 2 Electric Power Supply and Demand in Bangladesh and Background of the Project

Chapter 2 Electric Power Supply and Demand in Bangladesh and Background of the Project Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 2 Electric Power Supply and Demand in Bangladesh and Background of the Project

2.1 Current Situation between Electric Power Supply and Demand, Supply Plans in Bangladesh In Bangladesh, electric power development plans are drawn up under the following basic policies based on Power System Master Plan 2016 (PSMP2016): (1) enhancement of energy infrastructures; (2) effective use of domestic resources, such as natural gas and coal; (3) build-up of high-quality energy systems; (4) use of environmentally-friendly clean energy; (5) human resources development for stably supplying electric power. As described above, Bangladesh aims to become a developed country by 2041, and PSMP2016 plans to increase the installed power plant capacity (approximately 17,000 MW at present) to 24,000 MW (approximately 1.4 times) by 2021 and to 60,000 MW (approximately 3.5 times) by 2041.

Table 2.1-1 Power Development plan in PSMP2016 （Unit：MW） Year 2015 2020 2025 2030 2035 2041 Electricity Demand 8,920 13,300 19,900 27,400 37,300 51,000 Coal 182 5,873 6,977 9,377 11,777 20,195 Gas fuel 6,781 9,928 8,516 9,432 15,447 20,177 Crude oil 3,203 3,900 4,005 3,550 1,673 0 Import Electricity 500 1,200 2,500 5,000 7,000 9,000 Neuclear 0 0 2,232 3,432 4,632 7,032 Hydro power 230 230 230 330 330 330 [Source：PSMP2016]

Table 2.1-2 List of Gas Fired Power Plant commissioned by 2020 （Share by Type） Year 2015 2020 2025 2030 2035 2041 Coal 1.67% 27.79% 28.52% 30.13% 28.82% 35.60% Gas fuel 62.23% 46.98% 34.82% 30.31% 37.81% 35.56% Crude oil 29.40% 18.46% 16.37% 11.41% 4.09% 0.00% Import Electricity 4.59% 5.68% 10.22% 16.07% 17.13% 15.86% Neuclear 0.00% 0.00% 9.13% 11.03% 11.34% 12.39% Hydro power 2.11% 1.09% 0.94% 1.06% 0.81% 0.58% [Source：PSMP2016]

2-1 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 2 Electric Power Supply and Demand in Bangladesh and Background of the Project

60,000

50,000

40,000 Hydro Nuclear 30,000 Import Oil Base 20,000 Gas Coal

Gross Output Gross Output Capacity(MW) 10,000 Power Demand

0 2015 2020 2025 2030 2035 2041 Year

Figure 2.1-1 Long term power demand and supply forecast in Bangladesh [Source：PSMP2016]

In 2015, natural-gas-fired power generation accounted for approximately 62% of the power generation capacity. To achieve 3E+S (Energy Security, Energy Efficiency, Environment + Safety), Bangladesh has decided to increase particularly the share of coal-fired power generation and nuclear power generation. The Bangladeshi government has stated the construction of coal-fired power plants as a key policy; the construction requires a coal terminal, railroad transport facilities, and storehouses to be ready. In Matarbari Island at present, the government is steadily advancing the development of a deep sea port, the construction of an ultra supercritical(USC) coal-fired power plant, and accompanying port construction works. Although Bangladesh has no domestic experience in operating a nuclear power plant, a Russian national nuclear energy enterprise, ROSATOM, has reached an agreement with the Bangladeshi government on construction of nuclear power plants (power generation capacity: 1200 MW  2), aiming to start commercial operation in 2024 or 2025. Thus, the construction of coal-fired power plants and nuclear power plants and the development of accompanying ancillary facilities have become active in order to increase the capacity of the base load power supply. In parallel, projects for constructing gas-fired power plants are also underway. Since the ground level of Bangladesh is low, the country is substantially affected by climate change. The occurrence of floods, droughts, and cyclones due to global warming is accordingly presumed to become substantial impediment to the economic development of the country. In September before the 21st Conference of Parties (COP21) of the United Nations Framework Convention on Climate Change was held in Paris, France, in 2015, Bangladesh submitted Intended Nationally Determined Contributions (INDC), stating that the country will commit to 5% reduction of greenhouse gas emission (GHG) by 2030 in the industrial sector, such as electric power and transport areas, and 15% GHG reduction in exchange for support from other countries. The Bangladeshi government regards the GTCC construction as an effective approach for reducing GHG in accordance with the INDC. The momentum toward construction of GTCC power plants has increased in

2-2 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 2 Electric Power Supply and Demand in Bangladesh and Background of the Project

various areas in Bangladesh as a means for satisfying both the tight electric power demand and environmental friendliness.

6000

5000

4000

3000

2000

Gross Output Gross Output Capacity(MW) 1000

0 2016 2017 2018 2019 2020 Year

Figure 2.1-2 Expected Total Output of Gas Fired Power Plant in near future (MW） [Source：PSMP2016]

Table 2.1-3 List of Gas Fired Power Plant commissioned by 2020 No. Gas Plant (Committed) COD Output (MW) 1 Bhola 225 MW CCPP: SC GT Unit 2016 189 2 Siddirganj 335 MW CCPP: SC GT Unit 2016 328 3 Ashuganj (South) 450 MW CCPP 2016 361 4 Shajibazar CCPP 2016 322 5 Ashuganj (South) 450 MW CCPP 2017 370 6 Ghorasal 363 MW (7th Unit) CCPP 2017 352 7 Shikalbaha 225 MW CCPP 2017 218 8 Bibiana South CCPP BPDB 2018 372 9 Bheramara 414 MW CCPP 2018 402 10 Sylhet 150 MW PP Conversion (Additional 75MW) 2018 221 11 Ghorasal 3rd Unit Repowering (Capacity Addition) 2018 776 12 Kusiara 163 MW CCPP 2018 163 13 Shahajibazar 100 MW 2018 98 14 Bibiana III CCPP BPDB 2019 388 15 Fenchugonj 50 MW Power Plant 2019 50 16 Bagabari 100 MW PP Conversion 2020 102 17 Sirajganj 414 MW CCPP (4th unit) 2020 414 [Source：PSMP2016]

2-3 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 2 Electric Power Supply and Demand in Bangladesh and Background of the Project

2.2 Development of LNG Receiving Terminals in Bangladesh and Corresponding Power Plant Projects To cope with decline in production at domestic gas fields and the tight electric power demand, the Bangladeshi government has decided to promote the development of LNG receiving terminals in various areas in the southern region, such as the Moheshkhali and Matarbari areas. (Details are described in Chapter 9.) PSMP2016 therefore expects that development in the southern region will become active. Although the client has not yet obtained approvals and permissions at this stage, the development of some projects is expected to start in the future. Those projects are listed as follows.

Table 2.2-1 Development Project listed in PSMP2016 Gas Plant No. Type COD Output (MW) (Candidate) GTCC800 1 Mohesikali Gas 2032 800 2 Mohesikali Gas 2033 800 3 Mohesikali Gas 2034 800 4 Pyra Gas 2034 800 5 Pyra Gas 2035 800 6 Pyra Gas 2035 800 7 Pyra Gas 2035 800

8 Gas800 after 2035 Gas 2036 800

9 Gas800 after 2035 Gas 2037 800

10 Gas800 after 2035 Gas 2038 800

11 Gas800 after 2035 Gas 2039 800

12 Gas800 after 2035 Gas 2039 800

13 Gas800 after 2035 Gas 2040 800

14 Gas800 after 2035 Gas 2041 800

GTCC500 15 Mohesikali Gas 2028 500 16 Mohesikali Gas 2029 500 GTCC250 17 Anowara Gas 2026 250 18 Anowara Gas 2029 250 19 Anowara Gas 2031 250

2-4 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 2 Electric Power Supply and Demand in Bangladesh and Background of the Project

20 Pyra Gas 2032 250 21 Pyra Gas 2033 250 22 Pyra Gas 2034 250 23 Pyra Gas 2035 250

24 Gas250 after 2035 Gas 2036 250

25 Gas250 after 2035 Gas 2036 250

26 Gas250 after 2035 Gas 2037 250

27 Gas250 after 2035 Gas 2037 250

28 Gas250 after 2035 Gas 2038 250

29 Gas250 after 2035 Gas 2039 250

30 Gas250 after 2035 Gas 2041 250

SGT100 31 SGT100 -1 Gas 2027 100 32 SGT100 -2 Gas 2028 100 33 SGT100 -3 Gas 2028 100 34 SGT100 -4 Gas 2029 100 35 SGT100 -5 Gas 2029 100 36 SGT100 -6 Gas 2029 100 37 SGT100 -7 Gas 2029 100 [Source：PSMP2016]

To cope with the tight electric power demand, the Bangladeshi government has started examinations for the development of the LNG receiving terminals and the development for GTCC in accordance with PSMP2016. The government understands that particularly LNG import is a bottleneck in power plant construction projects, and is addressing this issue as an urgent matter.

2.3 Discussion from the Perspective of Development History in Japan 2.3.1 Position of LNG in Power Generation Mix in Japan The following describes changes in the power generation mix in Japan and discusses the position of LNG. In the power generation mix in Japan, the main fuel changed from firewood and charcoal to coal at the Meiji Restoration. After that, during the high economic growth period in which Japan aimed to reconstruct the country from World War II, oil-fired power plants played important roles in supporting the expanding electric power market. Until the first oil crisis, which occurred in 1973, oil-fired power generation accounted for 77% of the total energy supply. After the oil crisis, mainly the ratios of coal-fired power generation, nuclear power generation, and natural-gas-fired power generation were increased in order to reduce

2-5 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 2 Electric Power Supply and Demand in Bangladesh and Background of the Project

dependence on petroleum. However, the accident occurred at the Fukushima Daiichi Nuclear Power Plant of Tokyo Electric Power Company due to the 2011 Great East Japan Earthquake and Tsunami. As a result, the ratio of nuclear power generation in the power generation mix deceased from 30% to 1% in 2016, and the ratio of LNG-fired power generation increased, instead of nuclear power generation. The following illustrates changes in the power generation mix in Japan.

Hundred million kWh

■ New resources

■ Pump-up water

■ Oil, etc.

■ LNG

■ Hydropower

■ Coal

■ Nuclear

(Fiscal Year) Figure 2.3.1-1 Histogram of power generation volume by energy resource in Japan [Source： Agency for Natural Resources and Energy「Energy White Paper 2017」]

As illustrated above, gas-fired power generation accounts for a large portion in the power generation mix in Japan. In addition, fuel for power generation has been transitioning to import resources, such as LNG, due to decrease in domestic resources (particularly, natural gas). This fact suggests that the power generation mix in Japan and the power generation mix that Bangladesh will adopt are similar.

2.3.2 Possibility of Development of Japan’s Project Development Technologies in Bangladesh As described above, the history of energy in Bangladesh is similar to the history of electric power supply and demand in Japan. The trends in both countries are presumed to be the same particularly in that gas-fired power generation using import LNG will play important roles as future base load power supply. This fact suggests that Japan's high-quality energy infrastructures can be deployed overseas (promotion of export of the latest combined thermal power generation installations to Bangladesh and spread of their use) by implementing surveys and providing proposals in cooperation with a consulting firm in which Japanese electric power companies are involved (they have rich experience and knowledge of LNG-fired power generation projects), Japanese manufacturers, and an environmental research company under the management of the Department of Environment, Ministry of Environment, Forest, and Climate Change of

2-6 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 2 Electric Power Supply and Demand in Bangladesh and Background of the Project

Bangladesh. This study regards the Kawasaki Thermal Power Plant of Tokyo Electric Power Company as a model case of the latest LNG-fired combined power plant for Bangladesh. The Kawasaki Thermal Power Plant is equipped with world's largest MACC (More Advanced Combined Cycle) and MACC II power generation systems and has adopted 1500C-class and 1600C-class GTCC. The outlines of the power plant are as follows.

Table 2.3.2-1 Outline of Kawasaki Thermal Power Plant GTCC Rated Output 3,420 MW Site Area 280,000m2 Fuel LNG Design Thermal Efficiency（%）（ LHV） 61% [Source：TEPCO Fuel & Power, Incorporated Homepage]

For the Kawasaki Thermal Power Plant, a coal-fired power generation system (total output: 1950000 kW) was used before. However, aged deterioration was found, and modification works were proposed. The modification works were done from the perspective of environmental friendliness and pollution prevention, and the power generation system was converted from coal-fired to naphtha-fired, and then, naphtha-fired to LNG-fired. LNG is supplied from Higashiogishima LNG receiving terminal. The Kawasaki Thermal Power Plant is equipped with six shafts in total; for the Unit-1 system (first to third shafts) and the first shaft of the Unit-2 system, MACC has been adopted, and for the second and third shafts of the Unit-2 system, MACC II has been adopted. The plant started its commercial operation in June 2016, and all its modification works were completed in March 2017. A characteristic of the power plant is its high design thermal efficiency (LHV standard). It exhibits a design thermal efficiency of approximately 61%, a world's highest efficiency. The modification improved the generating efficiency by approximately 30% with respect to that of the early LNG-fired GTCC that was introduced in Japan (47.2% → 61.0%). This improvement contributed to reduction in fuel consumption, reducing CO2 emissions by approximately 30%.

2-7 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 2 Electric Power Supply and Demand in Bangladesh and Background of the Project

Figure 2.3.2-1 Historical Power generation efficiency at Kaswasaki Thermal Power Plant [Source：TEPSCO.]

In addition, the power plant is equipped with an exhaust gas treatment facility from the perspective of environmental friendliness to reduce the emissions of sulfur oxides (SOx), which cause acid rain, and nitrogen oxides (NOx), which cause air pollution. Thereby, NOx and SOx emissions per kWh have substantially been reduced.

Figure 2.3.2-2 NOx and SOx emission per kWh (international comparison) [Source：NOx and SOx emission / OECD. Stat Extracts, complete databases available from the OECD Library. Output / IEA Energy Balances of OECD Countries, 2016 Edition.]

The above-mentioned Japan's high-quality energy infrastructure (LNG-fired combined power plant) technologies are presumed to be optimum technologies to satisfy both the tight electric power demand in Bangladesh and environmental friendliness based on the Paris Agreement. They are expected to allow the

2-8 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 2 Electric Power Supply and Demand in Bangladesh and Background of the Project

country to make the most of them to achieve the goal.

2-9 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 3 Study for Basic Plan of the Project

Chapter 3 Study for Basic Plan of the Project

Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 3 Study for Basic Plan of the Project

3.1 Basic Concept of the Project The purpose of this study is to construct a high-efficiency large capacity power plant promptly and promote the advanced technology having proven operational experience which is using Japanese state of art technology, high reliability and durable power generation for improvement of chronological power shortage in the People’s Republic of Bangladesh (hereinafter Bangladesh). Since the LNG import has been started from August 2018 in Bangladesh and the sufficient fuel gas for operation of power plant is secured, it is to investigate and verify of proper specification, availability and necessity of the project at candidate site based on following five basic concepts for implementation of development for imported LNG fired high-efficiency large capacity power plant and related facilities.

◼ High-efficiency and large capacity gas fired power plant ◼ Low environmental impact ◼ Contribution to stable electric power supply system in Bangladesh ◼ Expandability in future ◼ Low construction cost and short construction period

Generally, gas turbine combined cycle power plant (hereinafter GTCC) and ultra-supercritical thermal power plant (hereinafter USC) are candidate as high-efficiency large power plant. Result of comparative study which is based on the actual operation of existing thermal power plant in Japan and overseas, though it is common knowledge, since GTCC has advantages as following main reason, detailed study will be conducted based on the premise of GTCC introduction.

◼ Gross Thermal Efficiency at Generator Terminals (LHV basis): GTCC is more than 60% (the latest model is more than 64%), and USC is around 43%. ◼ Exhaust gas NOx: GTCC with dry low NOx burner is less than 25 ppm(vd) and it is satisfied with environmental standard of World Bank without flue gas denitrification system. On the other hand, USC is difficult to control less than 100 ppm even if dry low NOx burner is applied and it is necessary to install flue gas denitrification system to satisfy the environmental standard.

Currently, the latest model of the gas turbine installed power plant is J type or H type which has proven and commercial operation. The proposed net output of GTCC is approx. 600MW (±10%) per unit that the counterpart desired to install the candidate site during 1st site survey is targeted of this study. The detailed study for expected performance of power plant is shown in “Chapter 5 Study of the Power Plant”.

The study of power plant is considered that; - Plan for GTCC with dry low NOx burner - Study for the method of taking and discharging cooling water and boiler make-up water - Plan for low environmental impact GTCC in consideration of Bangladesh environmental

3-1

Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 3 Study for Basic Plan of the Project

standards related to exhaust gas, waste water and noise level

The study of plant layout at candidate site is considered that; - Availability of site area - Connection and branch point between power plant and related facilities such as transmission line and gas pipeline - Expandability for additional power plant in future

The study of connection into the transmission line is considered that; - PSMP 2016 (Power & Energy Sector Master Plan) conducted by JICA study team in 2016 basis - Clarify the technical requirement for connection to the Bangladesh National Grid - Conduct the Preliminary Power Flow Study The detailed study is shown in “Chapter 6 Study of Power Evacuation”.

The study of fuel procurement is considered that the LNG import plan and its feasibility. The detailed study is shown in “Chapter 9 Study of Gas Fuel Procurement”.

3.2 Basic study of project business model Overall schematic diagram of the project business model and expected enterprises are shown in below.

3-2 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 3 Study for Basic Plan of the Project

Gas Company (Petrobangla, GTCL etc.): Stable fuel procurement and fuel supply to GTCC

FSRU or LNG Procurement LNG Receiving Terminal

Gas Pipeline RMS

Power Generation Company (BPDB, EGCB, RPCL etc.): Stable power generation and power supply

GTCC

Power Transmission & Distribution Company (PGCB, DEDCO etc.): Stable power transmission and power distribution

Switchyard Transmission Line Substation Distribution Line

Figure 3.2-1 Overall Schematic Diagram of the Project Business Model [Source: Study Team]

3-3 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 3 Study for Basic Plan of the Project

Table 3.2-1 Expected Enterprises Expected Enterprises Item Operation & Plan and Order Construction Maintenance Land acquisition Power Generation 1 related to GTCC - - Company construction

Power Generation Power Generation Power Generation 2 GTCC Company Company Company

Switchyard and Power Power Generation Power Generation 3 Substation related to Transmission Company Company item No. 2 Company Transmission Line Power related to item No. 2 Power Generation Power Generation 4 Transmission (Connection to existing Company Company Company transmission line)

Gas Pipeline from main Power Generation Power Generation 5 Gas Company gas pipeline to GTCC Company Company

6 Main Gas Pipeline Gas Company Gas Company Gas Company LNG Receiving 7 Terminal included Gas Company Gas Company Gas Company FSRU 8 LNG Procurement Gas Company - Gas Company [Source: Study Team]

In this study, it is conducted to study conceptual design, initial environmental examination and economic analysis, etc. of project business model for power generation company who is counterpart will be expected enterprises. Also it is implemented to investigate for the fuel procurement method based on the LNG import plan in Bangladesh.

3.3 Study for project basic plan and major items of the power plant The project basic plan and major items of the power plant are shown below.

3-4 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 3 Study for Basic Plan of the Project

Table 3.3-1 Project Basic Plan and Major Items of the Power Plant Power Generation BPDB EGCB RPCL Company Candidate Site Siddhirganj Feni Gazaria Total Output at 1,200 ± 10% MW 1,200 ± 10% MW 600 ± 10% MW Terminal Point (600 ± 10% MW x 2) (600 ± 10% MW x 2) Approx. 320,000 m2 Approx. 320,000 m2 Site Area*1 Approx. 98,000 m2 (400 m x 800 m) (400 m x 800 m) Power Generation Type 1600 °C Class GTCC

Number of GTCC*2 1 on 1 x 1 1 on 1 x 2 1 on 1 x 2

Shaft Configuration Single Shaft (without Bypass Stack & Bypass Damper) Wet Type Wet Type Condenser Cooling Once-through Cooling Tower Cooling Tower Method (River Water) (Ground Water) (River Water) Main Fuel LNG or Natural Gas / NA / Backup Fuel *1: Site Area includes existing facilities which will be demolished or reused at Siddhirganj *2: Plot Plan will be reported at 4 units included future plant at Feni and Gazaria [Source: Study Team]

3.4 Concept of candidate site for this project This study will be started from selection of the candidate site which is suitable location for construction of the power plant shown in Section 3.3. The candidate sites planned by Bangladesh Power Development Board (hereinafter BPDB), Electricity Generation Company of Bangladesh (hereinafter ECGB) and Rural Power Company Limited (hereinafter RPCL) was listed in total 9 places. However, the detailed comparative study is conducted at 6 candidate sites in consideration of the result of the preliminary meeting with the Power Secretary of Bangladesh in March 2018 which was held before starting of this study. The detailed comparative study of candidate sites is shown in “Chapter 4 Select of Project Candidate Site”.

3-5 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 3 Study for Basic Plan of the Project

3.5 Study for overall schedule of the project Based on completion of this study in February 2019, the overall project schedule conducted by Yen Credit is shown in below. Environmental Impact Assessment (EIA) shall be implemented by expected entity and it is necessary to submit report to Japanese Government before requirement of Yen Credit. The standard processing period from the requirement of Yen Credit for the Ministry of Foreign Affairs to the signing of the loan agreement is nine months. And also, it takes 24 months to select project consultant and EPC contractor before commencement of the construction work according to the JICA standard. The construction period is supposed 30 month in case of one unit, which is the standard construction period of GTCC. However this period is considered after the completion of land filling and levelling including embankment work. Hence in order to proceed the project smoothly, it is recommended to complete not only land acquisition but also land filling including embankment work and access loads before commencement of the construction work.

2018 2019 2020 2021 2022 2023 2024 2025

Feasibility Study 8M Submit the final report to METI by end of Feb. 2019

Initial Environmental Examination 8M Submit the final report to METI by end of Feb. 2019 (IEE)

Environmental Impact Assessment by Counterpart 6M Environmental Certificate before Yen Credit Request

Yen Credit requested by Counterpart 6M

Exchange Note & Loan Agreement 9M

Selection of Consultant 9M

Selection of Contractor 15M

Construction Period 30M

Figure 3.5-1 Overall Schedule of the Project in case Yen Credit [Source: Study Team]

3-6 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 3 Study for Basic Plan of the Project

In addition, in case of Export Credit Agency (ECA) loan, the overall schedule of the project up to completion can be significantly shortened as compared with the above Yen credit case since intergovernmental negotiations is not required. The shortest case of overall schedule is shown in below.

2018 2019 2020 2021 2022 2023 2024 2025

Feasibility Study 8M Submit the final report to METI by end of Feb. 2019

Initial Environmental Examination 8M Submit the final report to METI by end of Feb. 2019 (IEE)

Environmental Impact Assessment by Counterpart 6M Environmental Certificate before Environmental Screening

Selection of Consultant 6M

Selection of Contractor 9M

Negotiating Loan Agreement with JBIC 12M L/I, Preliminary Offer and Financial Offer by JBIC

Conditions Precedent and Apply to NEXI 12M Legal Opinion, Letter of Guarantee, Specimen Signature

Construction Period 30M

Figure 3.5-2 Overall Schedule of the Project in case ECA [Source: Study Team]

3-7 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 4 Select of Project Candidate Site

Chapter 4 Select of Project Candidate Site

Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 4 Select of Project Candidate Site

4.1 Select of Project Candidate Site The candidate sites planned by Bangladesh Power Development Board (hereinafter BPDB), Electricity Generation Company of Bangladesh (hereinafter ECGB) and Rural Power Company Limited (hereinafter RPCL) was listed in total 3 sites as shown below Table 4.1-1.

Table 4.1-1 Candidate Site Power Generation Entity Candidate Site 1 BPDB Siddhirganj 2 EGCB Feni 5 RPCL Gazaria [Source：Study Team]

Table 4.1-2 Basic Information of Each Candidate Site

1 2 3 Power Generation Entity BPDB EGCB RPCL Candidate Site Siddhirganj Feni Gazaria Province Dhaka Chittagong Dhaka Distance from Dhaka Southeast Southeast Southeast 20 km 150 km 40 km [Source: Study Team]

4-1 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 4 Select of Project Candidate Site

4.2 Field survey This study team conducted field survey for 3 candidate sites (Siddhirganj, (BPDB), Feni (EGCB), Gazaria (RPCL)) from end of September to beginning of October, 2018.

Dhaka

Siddhirganj

Gazaria

Feni

Figure 4.2-1 Location of field survey [Source: Google Earth touched up by Study Team]

4-2 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 4 Select of Project Candidate Site

4.2.1 Siddhirganj Thermal Power Plant (BPDB) An enlarged surrounding area of Siddhirganj thermal power plant and the related information to be described is shown in below.

Legend 230kV Siddhirganj SS Existing BTG Blue frame：New GTCC Construction site

EGCB 120MW x 2 Gas Turbine Plant

EGCB 335MW x 1 CCPP

Main Gate Existing RMS Sitalakhya River 100MW IPP Diesel Plant

Outfall

Figure 4.2.1-1 Surrounding area of Siddhirganj thermal power plant [Source: Google Earth touched up by Study Team]

(1) Access The candidate construction site for new GTCC is vacant space in the existing Siddhirganj thermal power plant which is about 2.5 km away from the Dhaka - Chittagong highway. Since the road condition from highway to power plant is terrible and the road width is not enough for passing heavy vehicle during construction period, it is recommended to improve and expand the access road from highway to power plant. Also, for transporting of heavy equipment such as gas turbine, generator, transformers, it is recommended to be transported by barge etc. on Sitalakhya River which is located on the east side of Siddhirganj thermal power plant. It seems to be able to use existing unloading jetty which is located in existing Siddhirganj thermal power plant after conducting the necessary improvement such as reinforcement.

(2) Site

4-3 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 4 Select of Project Candidate Site

In the beginning plan, the new GTCC is planned to construct in vacant space where is west side of existing BTG, however it was confirmed during 2nd site survey when field survey was conducted that it is not enough space to construct new GTCC in case only vacant space can be used. Since BPDB instructed study team to consider including reused and removal of existing facilities, the blue frame shown in the Figure 4.2.1-1 is set as the planned construction area of GTCC. This area includes existing facilities such as cooling water intake / discharge system, water treatment system, pipe rack, hydrogen generating system, hydrogen storage facility, and IPP diesel plant etc.

(3) Natural environment and social environment Please refer to “Chapter 7 Environmental Evaluation”.

(4) Cooling water Since other power plants located along the Sitalakhya River take cooling water from Sitalakhya River and discharge to same river without any problem, the new GTCC is also planned to apply once-through type of cooling system using Sitalakhya River water. The installed location of cooling water equipment for new GTCC is already arranged in the existing cooling water pump building and it can be reused. Even though once-through type of cooling system is planned in consideration of limited area and BPDB’s intention which existing facilities should be utilized as much as possible, the securement for installation space of cooling tower will be studied at plant layout since there is possibility to change cooling system due to DOE (Department of Environment) guide line.

(5) Fuel gas The RMS (Regulating Metering Station) whose design of gas supply capacity is 200 MMCFD is already installed as fuel gas supply system for BPDB existing BTG 210MW x 1, EGCB Gas Turbine Simple Cycle Plant 120MW x 2 and EGCB GTCC 335MW x 1 in the Siddhirganj Thermal Power Plant. Since the total gas consumption of these 3 existing power plants is approx. 137 MMCFD and new GTCC’s gas consumption is about 90MMCFD, the total gas consumption will be 227 MMCFD after operating of new GTCC, which gas consumption is larger than RMS design capacity. However, it is possible to supply fuel gas to the high efficiency new GTCC by stopping existing low efficiency power plant. In addition, RMS has 12 inch branch pipe that can be used for new GTCC.

(6) Transmission line The transmission line is planned to connect to the existing 230 kV Siddhirganj substation in the Siddhirganj Power Plant. The existing substation has 2 vacant bays to connect the incoming feeders from GTCC. This incoming feeders will be underground cable for a part of section, and through connected to free arms of existing transmission line tower.

4-4 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 4 Select of Project Candidate Site

The detailed study and the transmission route are shown in “Chapter 6 Study of Power Evacuation”.

4.2.2 Feni Thermal Power Plant (EGCB) An enlarged surrounding area of planning to construct Feni thermal power plant and the related information to be described is shown in below.

Letend Red frame：EGCB land acquired Blue frame：New GTCC Construction site

Fuel Gas Valve Station

230kV Mirsarai SS

Figure 4.2.2-1 Surrounding area of Feni [Source: Google Earth touched up by Study Team]

(1) Access The candidate construction site for new GTCC is agricultural field which is approx. 24 km away from the Dhaka - Chittagong highway. Since the road condition from highway to power plant is terrible and the road width is not enough for passing heavy vehicle during construction period, it is recommended to improve and expand the access road from highway to power plant. Also, for transporting of heavy equipment such as gas turbine, generator, transformers, it is recommended to be transported by barge etc. on Feni River which is located on the east side of candidate site. It is necessary to construct not only jetty and unloading facilities but also access road between candidate site and jetty.

4-5 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 4 Select of Project Candidate Site

(2) Site The red frame shown in Figure 4.2.2-1 is already acquired by EGCB, the total area is 999.65 acres (= 4,045,440 m2). Since it is also planned to install together with solar power plant and wind power plant inside the red frame, the enough area is secured for construction of new GTCC. On the other hand, since the existing ground level is as low as approx. 3 m above mean sea level, it is necessary to conduct site preparation work such as land filling and embankment work in consideration of the flood level and it is recommended to complete this work before commencement work of new GTCC.

(3) Natural environment and social environment Please refer to “Chapter 7 Environmental Evaluation”.

(4) Cooling water During 3rd site survey when field survey is conducted, it is confirmed that ◼ Feni River which located on the east side of candidate site has dam ◼ The purpose of this dam is to prevent contamination of irrigation water from salty water due to sea water ◼ The sea water level of downstream of dam is huge fluctuated through the year ◼ The distance from Feni River to candidate site is minimum 2.5 km Therefore, it is very difficult to take stable cooling water through the year, the source of cooling water is planned to use groundwater at candidate site and apply wet type cooling tower.

(5) Fuel gas The fuel gas supply tap-off point for new GTCC is planned Chandpur Valve Station which is located approx. 19 km away from candidate site. The detailed study and specific gas pipeline route between Chandpur Valve Station which is planning as branch point from 51 inch main gas pipeline and candidate site is shown in “Chapter 9 Study of Fuel Procurement”.

(6) Transmission line The connecting point of transmission line from candidate site is planned to be 400 kV Mirsarai substation in Mirsarai Industrial Area which is located approx. 7 km away from candidate site. Since it is planned to upgrade 400 kV transmission line from Mirsarai substation, transmission line from candidate site is designed as 400 kV and operated as 230 kV initially. The detailed study and the transmission route are shown in “Chapter 6 Study of Power Evacuation”.

4-6 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 4 Select of Project Candidate Site

4.2.3 Gazaria Thermal Power Plant (RPCL) An enlarged surrounding area of planning to construct Gazaria thermal power plant and the related information to be described is shown in below.

Legend: Red frame：RPCL land acquired Blue frame：New GTCC construction site

400kV Meghnaghat SS

Fuel Gas Valve Station

Figure 4.2.3-1 Surrounding area of Gazaria [Source: Google Earth touched up by Study Team]

(1) Access The candidate construction site for new GTCC is agricultural field which is approx. 21 km away from the Dhaka - Chittagong highway. Since the road condition from highway to power plant is terrible and the road width is not enough for passing heavy vehicle during construction period, it is recommended to improve and expand the access road from highway to power plant. Also, for transporting of heavy equipment such as gas turbine, generator, transformers, it is recommended to be transported by barge etc. through Meghna River which is located on the west side of candidate site.

(2) Site The red frame shown in Figure 4.2.3-1 is already acquired by RPCL, the total area is 252.56 acres (= 1,022,074 m2).

4-7 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 4 Select of Project Candidate Site

On the other hand, since the existing ground level is as low as approx. 3 m above mean sea level, it is necessary to conduct site preparation work such as land filling and embankment work in consideration of the flood level and it is recommended to complete this work before commencement work of new GTCC.

(3) Natural environment and social environment Please refer to “Chapter 7 Environmental Evaluation”.

(4) Cooling water Since other power plants located along the Meghna River take cooling water from Meghna River without any problem, the new GTCC is also planned to apply wet type cooling tower of cooling system used Meghna River water.

(5) Fuel gas The fuel gas supply tap-off point for new GTCC is planned Srinagar Valve Station which is located approx. 8 km away from candidate site. The detailed study and specific gas pipeline route between Srinagar Valve Station which has 20 inch branch point from 30 inch main gas pipeline and candidate site is shown in “Chapter 9 Study of Fuel Procurement”.

(6) Transmission line The connecting point of transmission line from candidate site is planned to be 400 kV Meghnaghat substation which is located approx. 14 km away from candidate site. The detailed study and the transmission route are shown in “Chapter 6 Study of Power Evacuation”.

(7) Special conditions Since RPCL has planning to construct residential quarter on the north side of acquired land, candidate site for new GTCC is planned southwest side of this land (blue frame shown in the Figure 4.2.3-1) The plant layout for 4 GTCCs including future plan which considered RPCL intension is studied in “Chapter 5 Study for Power Plant”. Since the period of completion for 4 GTCCs will be taken long time, the study for transmission line will be conducted as for 2 GTCCs. During 3rd site survey when field survey and interview with RPCL are conducted, it is confirmed that land filling and embankment work at candidate site has already started and access road from highway to candidate site is under progress according to the plan.

4.3 Comprehensive evaluation of candidate project site Regarding studied 3 sites as final candidate site, the tasks for construction of new GTCC, further necessary study and possibility of candidate site are summarized as below.

4-8 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 4 Select of Project Candidate Site

4.3.1 Siddhirganj Thermal Power Plant (BPDB) (1) It is recommended to improve and expand the access road from highway to power plant since the road width is not enough for passing heavy vehicle during construction period. (2) It is necessary to reconsider whether existing unloading system at Shiddhirganj thermal power plant can be used and unloading period is limited etc., even though transporting of heavy equipment is planned to unload from Sitalakhya River. (3) It is studied in consideration of BPDB intention which is necessity of reused, remodeling, relocate and removal of existing facilities since vacant space is not enough for construction of new GTCC. (4) It is necessary to study improvement of water quality since it is found that water quality of Sitalakhya River does not meet for power plant operation even though cooling water for new GTCC will be taken from Sitalakhya River same as other power plants along the Sitalakhya River. (5) It is concerned about insufficient capacity of existing RMS, however it is possible to be solved by increasing operational pressure of gas pipeline and fuel gas is suppling to new high efficiency GTCC by priority. (6) The transmission line from new GTCC is planned to be connected to Siddhirganj substation via 230 kV underground cable and transmission tower of Siddhirganj power plant since Siddhirganj substation has two vacant bays, the transmission tower in Siddhirganj power plant has free space to connect cable and there are no plans to use these space now.

4.3.2 Feni Thermal Power Plant (EGCB) (1) It is recommended to complete the preparation work such as construction of access road from highway to candidate site and from unloading jetty of heavy equipment to candidate site before commencement work of new GTCC. (2) It is also recommended to complete land preparation work such as filling and embankment work before commencement work of new GTCC. (3) It is possibility to limit the unloading period of heavy equipment due to river water level is fluctuated even though transporting heavy equipment is planned to use Feni River whose depth can not be secured through the year. (4) Since there is enough space for construction of new GTCC, plant layout will be studied as 4 GTCCs in consideration of EGCB intention. However, study for transmission line will be studied as 2 GTCCs by occasion of clause 4.4.2 (7). (5) It is planned to use underground water as water source of cooling water as well as HRSG make-up water at candidate site since it is difficult to take stable cooling water through the year in case source of cooling water is Feni River. However it is found that high salt concentration is observed. (6) It is confirmed that the location of fuel gas tap-off point and there is sufficiently possibility of supplying fuel gas to new GTCC. However it is necessary to confirm the schedule of construction work of main gas pipeline and Chandpur Valve Station since construction work has not yet started. (7) The connecting point of transmission line from new GTCC is planned to be 230 kV Mirsarai substation (will be upgraded to 400 kV in future) in Mirsarai Industrial Area which is approx. 7 km away from candidate site. However, it is necessary to confirm the schedule of construction work of Mirsarai substation and transmission

4-9 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 4 Select of Project Candidate Site

line between Mirsarai substation and BSRM substation since these works are undergoing. (8) It is necessary to install the set up transformer or 230kV/400kV which can be corresponded to timing of upgrading of transmission line system.

4.3.3 Gazaria Thermal Power Plant (RPCL) (1) It is recommended to complete the preparation work such as construction of access road from highway to candidate site before commencement work of new GTCC. (2) It is also recommended to complete land filling and embankment work before commencement work of new GTCC. (3) It is possibility to limit the unloading period of heavy equipment due to river water level is fluctuated even though transporting heavy equipment is planned to use Meghna River. (4) Since there is enough space for construction of new GTCC, plant layout will be studied as 4 GTCCs in consideration of RPCL intention. However, study for transmission line will be studied as 2 GTCCs by occasion of clause 4.4.3 (7). (5) Even though the water source of cooling water for new GTCC is planned Meghna River which is the third of largest river in Bangladesh, it is concerned warm discharged water will affect environmental impact due to requirement of huge cooling water in case one-through type is applied. Hence the wet type cooling tower is applied as cooling method. (6) It is confirmed that the location of fuel gas tap-off point and there is sufficiently possibility of supplying fuel gas to new GTCC. (7) The connecting point of transmission line from new GTCC is planned to be 400 kV Meghnaghat substation which is approx. 14 km away from candidate site. However, it is necessary to confirm the schedule of construction work of Meghnaghat substation and Dhaka – Chittagong transmission line project since there is possibility to interfere.

4-10 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant

Chapter 5 Study for Power Plant

Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant

5.1 Conceptual Design 5.1.1 Design condition The design condition of power plant applied to this study is shown in below. This design condition is considered Pre-FS report, IEE report, EIA report made by counterpart and the result of 1st site survey, and the result of confirmation of counterpart intention during 2nd and 3rd site survey.

Table 5.1.1-1 Design Conditions and Specifications Description Conditions and/or Specifications Counterpart BPDB, EGCB, RPCL Candidate site BPDB: Siddhirganj EGCB: Feni RPCL: Gazaria Site area (Refer to chapter 4 in detail) Siddhirganj: 98,000 m2 (included existing plant area to be demolished and of reused facilities) Feni: 320,000 m2 (400 m x 800 m) Gazaria: 320,000 m2 (400 m x 800 m) Dry bulb temperature 35 °C Barometric pressure 101.3 kPa Relative humidity 80% Annual rainfall 2,200 mm Final ground level (PWD) Siddhirganj: Existing ground level (6.46 m) (Land preparation work such as Feni: 8.62 m (high water level 5.62 m + 3 m filling and embankment) embankment work will be conducted by Gazaria: 8.03 m (Existing ground level 3.08 m + 4.95 m filling and counterpart) embankment) The source of cooling water and make- Siddhirganj: Sitalakhya river water up water Feni: Groundwater Gazaria: Meghna river water Type of steam turbine condenser Siddhirganj: Once-through cooling system Feni: Wet Type Cooling Tower Gazaria: Wet Type Cooling Tower Primary fuel LNG Supply pressure of fuel gas at terminal 5.3 MPag point of Gas turbine Supply temperature of fuel gas at More than 5 °C terminal point of Gas turbine Properties of fuel gas (design basis) Composition (mol %)

5-1 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant

Description Conditions and/or Specifications

Methane (CH4) 96.39

Ethane (C2H6) 2.1

Propane (C3H8) 0.41

n-butane (n-C4H10) 0.12

2-methylpropane (i-C4H10) 0.08

n-pentane (n-C5H12) 0.15

2-methylbutane (i-C5H12) 0.04

Hexane (C6+) 0

Nitrogenous (N2) 0.71

Carbon dioxide (CO2) 0

Hydrogen (H2) 0 Net specific energy 49,235 kJ/kg (lower heating value) (LHV) Specific gravity 0.7483 kg/Nm3 Secondary fuel (Back-up) Not applicable Black start capability Applicable Operating period 25 years Annual available operating hours 7,972 hours (Average operating rate 91%) Simple cycle operation Not applicable [Source: Study team]

5.1.2 Outline of power plant system The new power plant consists of one unit GTCC at Siddhirganj, and each of two units GTCC at Feni and Gazaria respectively (each of four units GTCC included future plan will be considered for study of plant layout). The shaft configuration of power plant is single shaft type in which gas turbine, generator, and steam turbine are arranged with synchronism clutch (hereinafter called as “SSS clutch”) on the same shaft. The power plant is mainly configured from gas turbine, steam turbine, generator, HRSG, condenser, condenser cooling system, fuel gas supply system, water treatment system, waste water treatment system, fire-fighting system, electrical system, instrument & control system, transformers, switchyard and etc. The gas turbine shall be adopted a state-of-the-art large capacity J type or H type that is enough proven result of commercial operation and can be installed in the world market. The HRSG shall be three pressure reheat cycle type. Generally, J type and H type gas turbine is adopted three pressure reheat cycle type in order to improve the thermal efficiency of the plant.

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The steam turbine will be of single cylinder or two cylinders, three mixed pressure, variable pressure type, axial flow, downward flow or side flow exhaust type, with thermally insulating and noise attenuation covers, installed indoors with overhead cranes for maintenance of heavy equipment. The exhaust steam from steam turbine is cooled and condensed by circulating water at condenser which located at axial direction, downward direction or side direction.

5.1.3 Examination for Shaft Configuration (1) Types of shaft configuration Shaft configuration is basically classified into two types. One of them is the single-shaft type, in which a gas turbine, a steam turbine, and a generator are connected on one shaft. For this shaft configuration, a large- capacity generator is selected so that it will be shared by both a gas turbine and a steam turbine. This shaft configuration is further divided into two types. One of them is equipped with a synchronous clutch (SSS clutch) between the generator and the steam turbine. In this examination for shaft configuration, this type is called Type A. The other is not equipped with a clutch; this type is called Type B. The other shaft configuration type is the multi-shaft type, in which the gas turbine shaft and the steam turbine shaft are separate. This shaft configuration is further divided into two types. One of them has a structure in which one gas turbine and one steam turbine are installed separately on different shafts; this type is called the one-on-one multi-shaft type (called Type C). The other has a structure in which some gas turbines are combined with one shared steam turbine, and the steam turbine is supplied with steam from some heat recovery steam generator (HRSG) units; this type is called the two-on-one, three-on-one or four-on-one multi-shaft type. In this shaft configuration, when the gas turbines used are of the same model, the capacity of the steam turbine becomes almost double, triple or four times the capacity of the steam turbine used in the one-on-one multi-shaft configuration, and the plant output per GTCC block also becomes large accordingly. Since this examination targets on plants producing 650-MW class output per GTCC block, two-on-one multi- shaft configurations, which produce 1300-MW class output, are excluded from the comparison targets of this examination. For the multi-shaft type, a bypass stack equipped with a diverter damper is generally installed to allow gas turbines to perform simple-cycle mode operation. With increase in the capacity of gas turbines, the size of diverter dampers is also increased; 50-Hz H or J class gas turbines require a damper that occupies an area larger than an 8-m square. However, highly-reliable long-term operation cannot be expected out of huge dampers that operate in hot exhaust gas at temperatures higher than 600C. Even when a Type C shaft configuration is applied, accordingly, the installation of a bypass stack equipped with a diverter damper shall not be considered. Comparisons and examinations were made on the above three types of GTCC shaft configurations from the following viewpoints: thermal efficiency of plant, operational flexibility, operational usability, requirements for starting, operational reliability of plant, plant maintenance cost, installation area, step-by-step construction, construction cost, generating cost, transport, and influence on the power system network.

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Figure 5.1.3-1 shows schematic diagrams for Type A, B, and C shaft configurations.

Type A: Single-shaft configuration with clutch

Stac k Clutch HRSG GT GEN ST

Type B: Single-shaft configuration without clutch

Stack

HRSG GT ST GEN

Type C: 1 on 1 Multi-shaft configuration

Stack

HRSG GT GEN

ST GEN

HRS G Heat Recovery Steam Generator

Generator GT Gas Turbine ST Steam Turbine GEN

[Source：Study Team] Figure 5.1.3-1 Schematic diagrams for Type A, B, and C shaft configurations

As described above, the Type A and Type B shaft configurations use one large-capacity generator that is shared by a gas turbine and a steam turbine. The Type C shaft configuration uses one generator separately for

5-4 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant each of its gas turbine and steam turbine. Table 5.1.3-1 summarizes the results of the comparisons and examinations performed on the Type A, B, and C shaft configurations. Each yellow-highlighted cell indicates that the corresponding shaft configuration has an advantage over other shaft configurations in the relevant comparison item. When a shaft configuration is to be selected on the basis of the total number of cells highlighted in this table, the highest priority is given to the Type A shaft configuration. However, the type of the shaft configuration to be selected differs depending on what comparison item to place importance on. Therefore, some think that a shaft configuration should not be selected on the basis of the total number of highlighted cells. In the introduction of the project, construction cost and generating cost are markedly important comparison items. For Siddhirganj Power Plant, which is constructed in a small site, the installation area is also an important comparison item. According to Table 5.1.3-1, the Type A shaft configuration has the greatest advantage in these matters. On the basis of the above discussion, the study team recommends GTCC with the Type A shaft configuration.

Table 5.1.3-1 Comparison of Type A, B, and C shaft configurations Shaft Configuration Item Type A Type B Type C 1. Thermal Efficiency Base Equivalent Worse

2. Operation Flexibility Base Equivalent Equivalent

3. Operability Base Equivalent Equivalent

4.Start-up Start-up Steam Base Larger Equivalent condition Power Consumption Base Larger Base

5. Maintenance Cost Base Equivalent Equivalent

6. Site Area Base Equivalent Larger

7. Phase Construction NA NA Possible

8. Construction Cost Base Higher Higher

9. Power Generation Cost Base Equivalent Higher

10. Transportation Cost Base Equivalent Higher

11. Impact for Grid Base Equivalent Smaller [Source：Study Team]

5.1.4 Gas Turbine Candidates (1) Candidate models Gas turbines are the most important components that determine the operational reliability of GTCC, and

5-5 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant required to have the highest level of operational reliability and thermal efficiency. Steam turbines are custom- made and designed in accordance with received orders. As gas turbines, in contrast, manufacturers' standard design models are generally used in order to shorten their manufacturing period and to reduce costs for designing. Specifically, an appropriate gas turbine model that meets project requirements is generally selected from a standard product lineup of a gas turbine OEM (original equipment manufacturer). The OEM in this context refers to a manufacturer that continuously upgrades the prototype of proposed equipment after having completed the development of the prototype. OEMs have a sufficient understanding of the essentials of the design of equipment that they have developed; therefore, they are capable of coping with troubles by new approaches. That is the reason why equipment is procured from OEMs. New gas turbines are continuously developed with performance improvement, and their design parameters are upgraded every year. H and J class gas turbines, which deliver higher performance than F class gas turbines, have recently been introduced. Each of the H and J class gas turbines has a proven track record of 100,000 hours or more of actual commercial operation; they are thought to be sufficiently mature models. A gas turbine for 50 Hz (hereinafter, referred to as 50-Hz turbine) is often created by scale design based on a gas turbine for 60 Hz (hereinafter, referred to as 60-Hz turbine), and both have theoretically the same mechanical strength characteristics. This fact suggests that both 50-Hz turbines and 60-Hz turbines have the same operational reliability. In addition, MHPS M701J Series (J class 50-Hz turbines) and M501J Series (J class 60-Hz turbines) have been used in 600,000 hours or more of commercial operation; it can be judged that operational reliability has been ensured for them. In the latest M701J Series, combustion chambers have been changed from the original steam-cooling type to the air-cooling type, which is superior in operability. On the other hand, GE 9HA.01 (H class 50-Hz turbines) and 7HA.01 (H class 60-Hz turbines) have been used in 230,000 hours or more of commercial operation. And Siemens 8000H series of 50Hz type and 60Hz type have been used in 1,000,000 hours or more of commercial operation. Therefore, MHPS/J series, GE/H series and Siemens/H series have sufficient operating experience. Currently, the number of MHPS M701J series units in commercial operation is reported to be two units. On the basis of the above discussion, the study team selected the following three types of gas turbine models as targets of this study: "J Series (H Series)"

5.2 Basic Systems in Power Plant Design 5.2.1 Gas Turbine System (1) Gas turbine The gas turbines are H or J class temperature level (1600degC class turbine inlet temperature) gas turbines with high durability. They are open-cycle single-shaft type gas turbines and equipped with a dry low-NOx combustor suitable for specified fuel gas. Gas turbines must be designed to minimize the number of bearings and to be installed on a steel frame or an appropriate steel structure and a concrete foundation. The designed gas turbines must be able to withstand either the transient torque on the shaft occurring due to a short circuit of the generator or that occurring due to its phase-shift synchronization, whichever is larger. The output shall be extracted at their

5-6 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant cold end. Each gas turbine must be equipped with a starting system, a lubricating oil supply and cooling system, an intake air filtering system, a fuel gas supply system, a turning gear, and control and monitoring devices necessary for performing safe, reliable, and efficient operation on specified fuel. The gas turbines are designed to be installed indoors to meet requirements specified for noise prevention. The gas turbines are designed to combust fuel gas with a composition within a specified range, and thereby, to start, perform continuous base-load operation, and stop in accordance with the standards determined by their manufacturers. Each gas turbine is equipped with an automatic-starting and stopping, and automatic-control system that can be operated from the central control room of the relevant power plant. Each gas-turbine control system needs to be capable of performing the following operations for combined cycles.

• Operation in which a load between the minimum and maximum loads is always continuously applied • Governor-free (speed droop) operation • Operation in which the turbine inlet temperature is constant • No-load operation that is performed without synchronization during a specified period • Operation with the steam turbine bypass valve fully closed under a minimum load in a combined cycle • Automatic purge cycle that ensures specified natural gas be removed from the whole gas turbine, the whole exhaust system, and the stack; the purge time is adjustable. • Load rejection from a full-load state that is performed without any trip in order to facilitate re- synchronization

Each gas turbine needs to have a structure in which its casing can be horizontally divided, and thereby, convenience for maintenance and management is ensured, allowing the states of rotor and stator blades to be easily checked. The casing of the whole gas turbine has a structure that allows the casing to be removed in overhaul inspections and checks and to be easily replaced. The casing is covered with a material having heat- insulating and soundproof properties. The heat-insulating material shall not contain asbestos and shall be incombustible and chemically inert; it shall be covered with a metal sheet or glass cloth. The heat- insulating material and the soundproof material are designed to prevent lubricating oil from permeating into them. Around each gas turbine, a space is ensured for work to be done without being disturbed by piping, wiring, walls, or the like. As journal bearing, a sleeve bearing shall be used. Under consistently stable operation conditions, the thrust

5-7 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant in the shaft direction is applied in one direction and received by the thrust bearing. All the bearings are fluid bearings. Outlet lubricating oil thermometer and a monitoring device for the thermometer and a vibration sensor and a monitoring device for the vibration sensor are provided. The monitoring devices generate warning and trip signals in accordance with the standards determined by their manufacturers. Important internal parts can be checked by using a borescope without removing the casing.

Figure 5.2.1-1 illustrates the longitudinal section of a typical J class gas turbine, a gas turbine that may be used in this project.

5-8 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant

Figure 5.2.1-1 Longitudinal Section of Typical Gas Turbine/ J Series [Source：Study Team]

5-9 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant

(2) Starter The starter and the power supply facility related to it must be suitable for the acceleration of the gas turbine and the generator and combustible gas purging from the gas turbine. The rating of the starter is specified appropriately so that a sufficient starting torque and a sufficient accelerating torque will be generated to allow the gas turbine and the generator to be accelerated easily from standstill state to the rated speed within 25 minutes (excluding the time for purging and synchronization) in any equipment state without any problems in all the specified environmental temperature range. The capacity of the starter and that of the corresponding power supply shall be minimized in the range in which acceleration to the rated speed is possible within the specified time. For starters used to start J class gas turbines and generators, the relevant generators shall be used as synchronous motors equipped with a static frequency converter (thyristor type) because other types of starters are not suitable from technical and economical viewpoints.

An interlock must be incorporated so as to prevent the gas turbine and the generator from starting when the oil pressure of lubricating oil is not sufficient to rotate the rotor of the gas turbine or that of the generator. The starter is automatically separated and stopped before the rated speed is reached. It is generally separated when the gas turbine has reached the self-sustaining speed, and out of operation while the gas turbine is operating. In case of failure in separation, the starting operation will be automatically suspended. The gas turbine and the generator must be able to be immediately started from the resting state while they are in a standby state. The startup control system that performs turning and other prestart operations shall allow the following automatic operations to be performed.

Automatic startup: The startup sequence automatically proceeds up to a state with the preset governor minimum speed, a state of the completion of preparation for combining synchronizing, or a state with a preset load.

The startup control system must be equipped with an automatic purging function in order to ensure safe operation.

(3) Lubricating oil supply system The lubricating oil supply system is designed basically on the basis of performance data provided by its equipment supplier. It is provided with a jacking oil system, an oil purification system, and drain equipment for waist oil from the gas turbine, steam turbine and the generator on an as-needed basis. The lubricating oil supply system shall have the capability of sufficiently satisfying the requirements of the system to which lubricating oil is to be supplied. The system shall be designed not to constrain the plant operation even when some parts of the equipment

5-10 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant of the lubricating oil supply system such as oil filters are replaced for maintenance, and sufficient quantities of spare parts shall be kept. In a single-shaft configuration, the lubricating oil supply system shall be shared with the steam turbine. When the oil supply system has not yet sufficiently been used in actual commercial operation, the total lubrication capacity is determined on the basis of performance data provided by its equipment supplier in such a manner that the retention time calculated from the lubrication capacity in the minimum operation level or a lower level and the ordinary lubrication capacity will not be shorter than 5 minutes.

It must be designed to, at least, issue a warning in case of any of the following events. ➢ Decrease in supply pressure of lubricating oil ➢ Decrease in lubricating oil level in oil tank ➢ Increase in discharge temperature of lubricating oil ➢ Increase in supply temperature of lubricating oil ➢ Increase in differential pressure of lubricating oil in oil filters

All the bearing drain-oil pipe lines are equipped with a visible indicator that can be checked on the equipment installation floor surface or in the operation room. When the AC power supply is stopped, an emergency DC oil pump for stopping the rotating shaft and cooling the bearings is automatically activated. A pump driven by AC and DC motors connected in tandem must not be used. When the same system is to be used for supplying lubricating oil to two or more machines, the characteristics of the lubricating oil must be specified by the contractor. The contractor must confirm that the specified lubricating oil satisfies the requirements of the different machines, and that it can be locally procured. Figure 5.2.1-2 shows a typical flow of a lubricating oil supply system.

Each Bearing

Cooler Oil

Main Oil Tank Oil FilterOil FilterOil

P P P P

Emergency Oil Pump Main Oil Pump Prefilter CoalescerFilter

Oil Purifier Pump Figure 5.2.1-2 Typical Lube Oil System

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[Source：Study Team] (4) Fuel supply system The gas turbine combustion system shall be designed to use a dry low-NOx combustor for combusting fuel gas. The gas turbine shall be capable of continuous operation on fuel gas. The gas turbine combustion system must be designed to satisfy requirements for specified NOx emission concentrations while combusting fuel gas with no water or steam injection. Connection of the gas piping is established inside the fence on the power plant border. The fuel gas supply system must be equipped with all the devices necessary for the start, stop, and continuous operation of the gas turbine that uses fuel gas. Those devices include a control valve, a shut-off valve, a flowmeter, a microfiltration filter, and a distribution manifold. Some gas turbine manufacturers provide gas turbines equipped with fuel gas heating equipment to improve the thermal efficiency of power plants. This equipment is capable of heating fuel gas by using feed water or air that is extracted from the corresponding gas turbine compressor to cool the hot parts of the corresponding gas turbine.

(5) Air intake system a) General matters Air for the gas turbine is taken through an air inlet on the top or side of the outside of the gas turbine building. The air inlet must be installed in an appropriate position with consideration given to the predominant wind directions in the site so that the air inlet will not suffer the intake of exhaust gas from stacks. The air inlet must be designed to allow air to reach the air filtration system easily. After filtration, air will flow toward the air intake flange of the gas turbine compressor. The air intake system shall be equipped with an inlet louver, an airtight duct leading from the filter to the inlet of the compressor, a silencer, and all the devices and components necessary for safe operation. The number of the access points and entry ports used for the maintenance and checks of the air intake system must be minimized. Figure 5.2.1-3 illustrates a typical air intake system equipped with two-stage filtration system. b) Air filtration system The air filtration system is a multi-stage dry type system that consists of a prefilter and a high efficiency particulate air (HEPA) filter with performance equivalent to Class E12 of EN 1822. The air filtration system is designed in such a manner that its initial weight efficiency will not be lower than 99.5% for dust for ASHRAE (American Society of Heating, Refrigerating and Air-Conditioning Engineers) test. For a dust concentration for the ASHRAE test of 0.1 mg/m3, the filter replacement cycle must not be shorter than 6,000 operation hours. At the air inlet, a silencer is installed in the downstream side of the filtration system. The whole duct is tightly sealed so that unfiltered air will not enter. A filter to be used shall not shorten the service life of the gas turbine equipment and must be suitable to

5-12 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant reduce the sand, dust, and salt contained in the atmosphere under the most harmful atmospheric condition in the site. The air filtration system shall be designed to minimize the pressure drop in the air intake system. The number of components and devices shall also be minimized, and a differential pressure monitor must be installed in each stage of the air filtration system. c) Air inlet ducts The air inlet ducts shall be equipped with all the necessary expansion joints, guide vanes, supports and supporting steel frames, vibration absorbers, flanges, silencer, outer covering, and other parts necessary for complementing the system. Expansion joints are provided in such a manner that a load or force larger than or equal to the specified magnitude will not be applied to the inlet flange of the gas turbine compressor. Sliding joints shall not be used for the ducts. All the expansion joints must be equipped with a flange for removal without affecting major ducts. Nuts, bolts, or rivets with no drop stopper must not be used inside ducts present in the downstream side of the air filtration system. In order to protect the air intake equipment, a protecting system for monitoring the differential pressure between the pressure in the air intake chamber and the atmospheric pressure is installed. d) Silencer The silencer is installed in order to reduce noise from the air compressor to a level lower than a specified level. Soundproof panels to be used for the silencer are designed appropriately so that they can be used for 30 years with the gas turbine being in a full-load state. Soundproof panels to be used for the silencer shall be made of stainless steel. Filler and panels shall be able to completely withstand the most harmful atmospheric condition that is expected for the site. To prevent the subsidence and coagulation of the filler, preventive measures are taken. The material of the filler is an insectproof material.

5-13 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant

Weather Louver

Air Inlet Duct

Prefilter

Silencer

HEPA filterHEPA ProtectionFOD Screen

Figure 5.2.1-3 Typical air intake system equipped with two-stage filtration system [Source：Study Team]

5.2.2 Heat Recovery Steam Generator (HRSG) and Auxiliary Equipment (1) General matters HRSG shall be of a triple pressure, natural- or forced-circulation, reheat, and outdoor type. It shall be designed on the basis of data on actual experience in accordance with ASME Boiler and Pressure Vessel Code or its equivalent standards. HRSG is generally designed to receive the maximum exhaust gas flow under the gas turbine base load at the specified minimum atmospheric temperature. The heat transfer surface is designed with consideration given to the patterns of change in the temperature/flow rate of gas turbine exhaust gas under various atmospheric conditions and various gas turbine loads. HRSG shall be provided with a structure that does not develop excessive thermal stresses under the start and stop conditions unique to the gas turbine. HRSG is designed appropriately so that it can be operated by gas turbine exhaust gas generated by combusting specified gas fuel. HRSG shall generate steam under predetermined conditions while keeping the exhaust pressure of the gas turbine low. The heat transfer module shall be made large to the extent possible so that its installation time will be reduced, and put through a factory test before shipment.

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Figure 5.2.2-1 shows an example of vertical flue gas flow HRSG.

Figure 5.2.2-1 Cross Section of Vertical Type HRSG [Source：Study Team]

HRSG is provided with a structure that allows checks to be easily made on the gas path section, heat exchanger tubes, and other pressure parts in order to minimize the suspension time required for maintenance and checks. It is equipped with an access door or access hatch for maintenance and checks with a sealed structure for preventing leakage to the atmosphere. HRSG is of an outdoor type, and the whole HRSG is designed to be waterproof. It is equipped with a roof to protect humans and components (drum accessories, valves, and circulating pumps) from the external environment. The drum capacity is determined appropriately so that when one boiler feed pump trips, HRSG will not trip before a backup feed pump is activated. HRSG has drums, superheaters, reheaters, evaporators, economizers, headers, downcast pipes, and attendant piping and is supported by a steel structure. This structure except ordinary passages, frames, stairway, and other connecting portions is separate from other buildings. Appropriate consideration shall be given to HRSG, auxiliary equipment, and accessories particularly in design of parts and structures so as to allow them to cope with both the base load and cyclic loading. Design consideration shall be given to HRSG so that it can perform temperature matching with the steam turbine.

(2) Design and operation conditions

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HRSG is designed to be suitable for the normal and abnormal operation conditions of a combined cycle plant backed by its actual experience. The gas side of HRSG is designed to cope with the maximum temperature, pressure, and flow rate of flue gas under all the predicted operation conditions (including trip conditions). In case of full load rejection, the heat load on HRSG will be released to a condenser by a turbine bypass system without making a safety valve blow. HRSG is planned to start simultaneously with the gas turbine. HRSG is optimally designed so that it can continuously perform efficient operation in the whole operation range of the gas turbine. The quality of feed water must satisfy the criteria for application and meet the requirements of HRSG and the steam turbine.

(3) Design standards and criteria Materials, design, manufacture, construction, tests, and inspections shall all comply with the regulations and recommendations stipulated in relevant standards and criteria. Pressure parts, built-in articles, accessories, and assemblies are all designed, manufactured, constructed, and inspected in accordance with the requirements of authorized inspection agencies.

(4) Design and structure of HRSG

1) HRSG flue gas path The flue gas path for gas turbine exhaust gas flowing through HRSG is of a horizontal or vertical type depending on the manufacturer's standard design. Water and steam heat exchanger tubes are horizontally or vertically arranged in directions perpendicular to the gas flow also in accordance with the standard design. The heat transfer surface of each heat transfer module present in the flue gas path reduces the gas temperature depending on the properties of gas fed to the gas turbine within a range in which corrosion due to low temperature gas at economizer outlets or inside the stack can be avoided. To ensure protection from corrosion due to carbonates and sulfates, control of the feed water temperature at the inlet of the low-pressure economizer is performed in such a manner that the metal temperature of any portion of the economizer will become higher than or equal to the dew point. The heat exchanger tubes and headers of each heat transfer section shall be fully drainable and be arranged appropriately so that maintenance and checks can be performed.

2) Heat exchanger tubes For heat exchanger tubes, solid-drawn steel tubes or electric resistance welded steel tubes shall be selected in accordance with the experience of the equipment supplier. The design, manufacture, and testing of heat exchanger tubes shall be performed in accordance with relevant standard specifications. To minimize the disturbance that may occur in water circulation in response to a rapid startup or change of

5-16 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant load, an appropriate circulation ratio is set. To enhance the heat transfer characteristic, fin tubes, heat exchanger tubes with fins attached on their outer surface by continuous welding, are used.

3) Superheaters and reheaters The arrangement of the superheater tubes of the high-pressure superheater is generally designed to allow the rated temperature to be ensured without desuperheater spraying when the gas turbine is in continuous base load operation at the design atmospheric temperature. Superheaters and reheaters shall be designed to be capable of coping with the variation character of the flow rate of the exhaust gas of the gas turbine. The high-, intermediate-, and low-pressure superheaters are designed to make the steam flow rate evenly distributed within heat exchanger tubes in the whole load range. Superheaters and reheaters shall be made fully drainable. The design shall be made with consideration given also to operation with no steam at startup.

4) Evaporators The high-, intermediate-, and low-pressure evaporators are designed to be capable of operating without fouling or vibrations in the whole load range and to make the flow rate evenly distributed within heat exchanger tubes. The elements of the evaporators shall be made drainable.

5) Economizers The high-, intermediate-, and low-pressure economizers are designed to be capable of performing safe operation with a single-phase flow without steaming throughout the whole load range of HRSG. The elements of the economizers shall be made drainable.

6) Steam temperature control The outlet steam temperature of the superheaters and reheaters is controlled by direct-spray type desuperheaters. The capacity of the desuperheaters is determined by taking all the operation conditions into account. Spray water regulating valves are equipped with an electric stop valve in the common line and interlock to close the stop valve automatically to prevent water induction into the steam turbine when the steam temperature becomes lower than the preset temperature.

7) Feed water temperature control The feed water temperature at the inlet of the low-pressure economizer is set to a temperature higher than or equal to the dew point so as to prevent corrosion due to condensation accompanied by carbonates and sulfates. A low-pressure economizer circulation pump for adjusting water circulation and a temperature control valve are installed. The feed water temperature at the inlet of the low-pressure economizer is controlled with the aid of the installed circulation pump and temperature control valve by circulating part of the outlet feed water heated by the low-temperature economizer.

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8) Safety valves The number, volumes, and installation locations of safety valves are specified in accordance with the requirements of related international standards.

9) Heat insulation and housing of HRSG The inner and/or outer faces of the whole HRSG are thermally insulated. For heat insulation of the outer face, an all-weather housing suitable for outdoor installation is provided. The heat insulating material shall be suitable for continuous operation at the maximum operation temperature.

10) Access door or access hatch For the maintenance and cleaning of the flue gas path and pressure parts of HRSG, an access door or access hatch of an appropriate type and with an appropriate size is installed to allow free access to the relevant sections.

11) Blowdown and drain For the drums, continuous blowdown line is provided. An appropriate number of electrically-operated valves and adjusting valves are installed as blowdown valves and superheater and reheater drain valves. Those valves are automatically opened and closed at the time of the starting, load, stopping operations of HRSG. HRSG shall be equipped with a blowdown tank receiving blow water and drain water.

5.2.3 Steam Turbine System (1) Steam turbine The steam turbine is of a triple mixed-pressure (triple-pressure) reheating and condensing type. High- pressure steam generated by HRSG flows through the main stop valve and the control valve and enters into the high-pressure turbine. After producing the power in the high-pressure turbine, the steam is mixed with intermediate-pressure steam generated by HRSG and heated by an HRSG reheater. Then, the steam enters into the intermediate-pressure turbine and produces the power. After that, the steam from the intermediate- pressure turbine enters into the low-pressure turbine; in this process, LP steam from HRSG is mixed with the intermediate-pressure turbine exhaust. Exhaust steam from the low-pressure turbine is cooled to be condensate in the condenser arranged in an axial direction (or a downward or side direction) and supplied as feed water to HRSG. The steam turbine is of a triple pressure type, consisting of high-, intermediate-, and low-pressure sections. The steam turbine and its auxiliaries are designed to perform continuous operation under all the predetermined conditions during the period of the service life specified for the power plant. The maximum capacity of the steam turbine is determined appropriately so that it can respond to such parameters as the pressure, temperature, and flow rate of steam generated by HRSG when the gas turbine

5-18 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant operates at its maximum capacity under the site conditions. The steam turbine is equipped with all the auxiliaries, such as a condenser, a lubricating oil system, a control oil system, a high-pressure main stop valve and a control valve, a reheat stop valve and an intercept valve, a low-pressure main stop valve and a low-pressure control valve, turbine bypass equipment, a speed governor, a turning gear, a gland steam system, and the control and protection systems and monitoring equipment that are necessary for safe, reliable, and efficient operation. As turbine control equipment, electric-hydraulic control governor is used. The steam turbine is of an indoor type; it is designed to be installed indoors so as to satisfy requirements for the specified noise level.

Table 5.2.3-1 shows the basic specifications of the steam turbine (when the power plant is a combined cycle plant using a J series gas turbine in the Type A shaft configuration with a condenser arranged in an axial direction). The steam turbine consists of two casings or a single casing and is connected to the generator via an SSS clutch.

Table 5.2.3-1 Steam Turbine Specification Item Specification Type Tandem Compound axial flow, TC1F, or Single Casing axial flow, SC1F Steam condition HP： 16.5 MPa abs/600 ℃ (ST inlet) IP： 3.5 MPa abs/600 ℃ LP： 0.6 MPa abs Speed 3000 rpm Casing HP: 1, IP & LP: 1(or Single casing) Condenser Press. Siddhirganj：7.87 kPa Feni & Gazaria：10.67 kPa [Source：Study Team]

The steam turbine is designed to minimize the number of bearings and to be installed on a steel base foundation, or an appropriate steel structure and a concrete foundation. The shafting shall withstand either the transient torque on the rotor occurring due to a short circuit of the generator or that occurring due to asynchronous connection establishment, whichever is larger. The generator is located in the front of the turbine. The height of the mounting surface of the steam turbine is minimized by adopting axial-exhaust or side- exhaust, and thereby, the height of the turbine building is reduced. The turbine blades are designed to be capable of withstanding continuous operation under any load when the frequency of the system is somewhere between 48.5 and 51.5 Hz (with an allowable time limit set up when

5-19 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 5 Study for Power Plant the frequency is lower than 48.5 Hz). The blades in the low-pressure stage must be thoroughly protected from erosion due to wet steam. The rotor blades in the wet region including blades in the final stage are protected by applying flame hardening or using an erosion protector made of Stellite or some other appropriate material. For the stationary blades in several low-pressure stages and the turbine casing side of those stages, erosion protective measures using slits for removing drain water and a drain-water catching structure are considered when the effectiveness of those measures has been verified. The steam turbine is designed appropriately so that when it is operated under specified conditions, the consumption of the service lives that is expected for major components will not exceed the service lives expected on the basis of the specified operation hours. The turbine is provided with a necessary number of ports for a borescope for periodically inspecting the state of blades. The steam turbine is designed to be manufactured by using proven materials that have a strong track record for actual commercial operation under similar operation conditions. In particular, it is necessary to be careful especially about the materials of the mono-block rotor when operation conditions are different among the high-, intermediate-, and low-pressure sections. When casings are to be connected with piping, the possibility that the strictest pressure condition and the strictest temperature condition will simultaneously occur shall be taken into account. In addition to the calculated minimum casing thickness, consideration must also be given when casings are not made of a corrosion-resistance material. The rotor is designed to be safe at a speed at least 10% higher than the momentary maximum speed that may occur when the full load is applied under the severest environmental condition. If the rotor is of a built- up structure, the disk must be safe at the above speed. Figure 5.2.3-1 shows an image (bird's-eye view) of a typical steam turbine applied to a model case.

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Condenser LP Turbine

HP Turbine

IP Turbine

Figure 5.2.3-1 Typical Steam Turbine Unit [Source：Study Team]

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(2) Condenser The condenser is of a single-shell and one pass (or two pass) type of surface cooling. The material of condenser tubes is generally titanium.

Table 5.2.3-2 Condenser Specification Item Specification Type Surface, single pressure, single casing, one pass or two pass Site Siddhirganj Feni & Gazaria Condenser Pressure 7.87kPa 10.67kPa Condenser Tube Material Titanium Cooling media River water Wet type cooling tower water (make-up water is river water or ground water) Cooling water inlet 30℃ 36℃ temperature Cooling water outlet 38.1℃ 44.1℃ temperature Cooling water temperature 8.1℃ 8.1℃ rise Cooling water flow 37,000m3/hr 37,000m3/hr Condenser support [Source：Study Team] Ancillary Tube cleaning facility [Source：Study Team]

5.2.4 Electrical equipment (1) Generator main circuit and switchyard 1) Siddhirganj The single line of generator main circuit, auxiliary circuits and 230 kV switchyard are shown in Figure 5.2.4-1. It is planned that the switchyard is composed of double bus bars and 1.5 CB system, and to be connected with 245 kV XLPE cable and existing overhead transmission lines using two (2) empty bays of 230 kV switchyard. The electrical system for one GTCC will be designed on the basis of the single shaft configuration having one Generator (hereinafter called as “Gen”), one Generator Step-up Transformer (hereinafter called as “GSUT”), one Unit Auxiliary Transformer (hereinafter called as “UAT”), one Start-up Auxiliary Transformer (hereinafter called as “SAT”) and other electrical equipment (Medium Voltage Switchgear (MV SWGR), Low Voltage Switchgear (LV SWGR), Motor Control Center (MCC), DC System and Uninterruptible Power System (UPS)) and etc.

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Also, the power supply system of common equipment, Emergency Diesel Generator (EDG) and Black Start Diesel Generator (BSDG) for restart the power plant when blackout is happened should be considered in this system. The main circuit of new GTCC will be connected to existing facilities. Though the generation voltage of generator is planned at 23 kV, it will be designed by equipment supplier conclusively. The generation voltage is stepped up to 230 kV by GSUT, and fed to 230 kV National Grid.

230kV GIS Switchyard

Generator Start-up Transformer Step-Up Transformer

GCB

Unit Auxiliary Gen Generator Transformer

MV Switchgear

Connected to Existing MV Black Start Diesel Switchgear Generator G

LV Transformer

LV Switchgear

Emergency Diesel G Generator

Figure 5.2.4-1 Generator Main Circuit at Siddhirganj [Source: Study Team]

During the GTCC operation, the power source to the unit auxiliary loads under 6.9 kV unit bus will be fed from the UAT and distributed to each MV SWGR. During the GTCC start-up, the power source to the unit auxiliary loads will be fed from 230 kV Switchyard via GSUT and UAT or SAT. The GTG will be synchronized the grid network system by closing of Generator Circuit Breaker (GCB).

2) Feni and Gazaria The single line of generator main circuit, auxiliary circuits and 400 kV switchyard are shown in Figure 5.2.4-2. It is planned that the switchyard is composed of double bus bars and 1.5 CB system.

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The electrical system for one GTCC will be designed on the basis of the single shaft configuration having one Generator (hereinafter called as “Gen”), one Generator Step-up Transformer (hereinafter called as “GSUT”), one Unit Auxiliary Transformer (hereinafter called as “UAT”), and other electrical equipment (Medium Voltage Switchgear (MV SWGR), Low Voltage Switchgear (LV SWGR), Motor Control Center (MCC), DC System and Uninterruptible Power System (UPS)) and etc. Also, the power supply system of common equipment, Emergency Diesel Generator (EDG) and Black Start Diesel Generator for restart the power plant when blackout is happened should be considered in this system. Though the generation voltage of generator is planned at 23 kV, it will be designed by equipment supplier conclusively. The generation voltage is stepped up to 400 kV by GSUT, and fed to 400 kV National Grid.

400kV AIS Switchyard

Generator Generator Step-Up Transformer Step-Up Transformer

GCB GCB Unit Auxiliary Unit Auxiliary Gen Generator Transformer Gen Generator Transformer

MV Switchgear

Black Start Diesel Generator G

LV Transformer

LV Switchgear

G Emergency Diesel Generator

Figure 5.2.4-2 Generator Main Circuit at Feni and Gazaria [Source: Study Team]

During the GTCC operation, the power source to the unit auxiliary loads under 6.9 kV unit bus will be fed from the UAT and distributed to each MV SWGR. During the GTCC start-up, the power source to the unit auxiliary loads will be fed from 400 kV Switchyard via GSUT and UAT. The configuration of unit power supply system should be able to back-up each other unit for high reliability. The GTG will be synchronized the grid network system by closing of Generator Circuit Breaker (GCB).

(2) Generator 1) Generator Generator specification is shown as follow.

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Table 5.2.4-1 Generator Specification Item Specification Type Horizontal cylindrical rotating field type synchronous generator Number of Pole 2 Number of Phase 3 Amount of Power Generation（at 35C） 660 MW Maximum Amount of Power Generation 680 MW （Maximum Output at sending-end 660 MW） Rated Output 850 MVA Frequency 50 Hz Rated speed 3,000 rpm Rated Voltage 23 kV Power Factor 0.80（lag.）,0.95（lead） Short Circuit Ratio Not less than 0.5 Rotor Cooling Method Hydrogen Stator Cooling Method Hydrogen [Source：Study Team]

Figure 5.2.4-3 Generator Typical Sectional View [Source：Study Team ]

2) Generator Circuit Breaker（GCB） GCB is installed in the primary side GSUT(Between the GSUT and the Generator) and used for

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synchronizing with power grid. In case of electric failure at generator, GCB interrupt fault current and generator is isolated from electric system.

3) Gas Turbine Start up method Gas turbine is started by generator as synchronous motor with using Thyristor invertor starting system

4) Excitation System Static Thyristor Direct Excitation System is employed as excitation system, it is composed of excitation transformer, thyristor rectifier, field circuit breaker and Automatic Voltage Regulator (AVR) equipped with Power System Stabilizer (PSS). Generated voltage at generator is controlled to a set values by AVR.

5) Generator Cooling System Hydrogen gas is filled in generator as coolant. Hot gas is heat-exchanged for cooling water through the hydrogen gas cooler.

6) Generator Seal Oil system In case of hydrogen cooled generator, seal oil system is required for preventing hydrogen gas leakage from bearing part of the generator. The seal oil pump is installed not only the AC motor drive but also the DC motor drive for emergency blackout case.

7) Hydrogen Supply System Hydrogen gas is supplied by pressure reducing regulating valve from hydrogen generation unit or storage tank to the generator.

8) Isolated-Phase Bus (IPB) IPB are composed of main circuit to GSUT via generator circuit breaker from output terminal of generator and branch circuit to UAT and excitation transformer from main circuit.

(3) Transformer 1) GTG Step-up Transformer (GSUT) (Common for three sites) The GSUT will step up from the GTG voltage to the switchyard voltage (400kV or 230 kV) and will be oil immersed three phase transformer with an on load tap changing mechanism. The cooling type will be ONAN (Oil Natural Air Natural) / ONAF (Oil Natural Air Forced) or ONAN/ODAF (Oil Direct Air Forced) type and phase connection will be Delta-Star (Δ-Y) type.

2) Unit Auxiliary Transformer (UAT) (Common three sites) The UAT will step down from the GTG voltage to the unit bus (6.9 kV) and distribute to MV SWGR and will be oil immersed three phase transformer with an on load tap changing mechanism. The cooling type will be ONAN / ONAF type.

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Since the UAT is large capacity, the transformer will be three winding transformer that the secondary winding is dual helical winding. The capacity will be decided taking into consideration the unit loads.

3) Station Auxiliary Transformer (SAT) (Siddhirganj only) The SAT will step down from the receiving voltage of grid network system 230 kV to the unit bus (6.9 kV) and distribute to MV SWGR and will be oil immersed three phase transformer with an on load tap changing mechanism. The cooling type will be ONAN / ONAF type. Since the SAT is large capacity, the transformer will be three winding transformer that the secondary winding is dual helical winding. The capacity will be decided taking into consideration the unit load.

(4) Unit power supply (Common for three sites) The unit power supply will be configured from UAT or SAT at Siddhirganj. The unit power supply will be configured from UAT or UAT of another unit at Feni and Gazaria. As the electric power source for each power plant in an emergency, one set of three phase emergency diesel generator (EDG) will be installed for safety shut-down of the power plant.

1) MV SWGR The voltage of MV SWGR will be 6.9 kV. The MV SWGR will supply the power to auxiliary equipment of power plant and LV SWGR through power center transformer and will be installed at indoor.

2) LV SWGR The voltage of LV SWGR will be 400 V / 230 V. The LV SWGR will supply the power to auxiliary equipment of power plant and MCC and will be installed at indoor.

3) DC supply system The 220 V DC supply system will have battery, charger, and distribution board. DC load will be supplied by the power from DC distribution board. It is necessary to have sufficient battery capacity so that power plant can shutdown safely.

4) Uninterruptible Power Supply (UPS) The UPS will supply continuous AC power to the essential AC bus to supply indispensable AC power to control system uninterruptedly.

5) Emergency Diesel Generator (EDG) The EDG will have capable of suppling emergency power and will supply power to 400 V emergency unit bus for safe shutdown of the power plant.

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6) Black Start Diesel Generator (BSDG) The BSDG will supply power to the power plant for restart up when power plant is blackout due to grid network system failure.

7) Site grounding IEEE 80 recommendation will be used to determine grounding system design for the power plant. The entire ground grid system will exclusively utilize copper conductors and grounding rods with exothermic connection for in-ground connections.

5.2.5 Plant C&I system (Common for three sites) (1) Control philosophy The control system will control and monitor the status of equipment and process variables associated with the GTCC to ensure safe and efficient operation within the applicable specifications and performance requirements. All control and monitoring functions necessary for start-up, normal operation, and shutdown of the GTCC will be provided in the Central Control Room (CCR). The CCR will be normally manned.

(2) System configuration of Distributed Control System (DCS) Figure 5.2.5-1 shows the configuration for GTCC control.

Figure 5.2.5-1 Configuration for GTCC Control [Source: Study Team]

The design of all instrumentation and control systems will provide maximum security for plant personnel and equipment, while safely and efficiently operating the new GTCC under all conditions with the highest possible availability.

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Operator workstation with Human Machine Interface (HMI) and a microprocessor based Distributed Control System (DCS), including redundant controllers using a plant-wide redundant communication highway, will be provided to allow the operators to control the GTCC and to receive monitoring and alarm information.

➢ DCS control module and power supply module are duplexed, however I/O card is single type. ➢ Dual power supply system (1 AC system and 1 DC system) ➢ Performed by HMI during normal operation

The operating and monitoring system of the power plant will be configured from the DCS, the information management system, maintenance and repair system, network system, and related equipment. The DCS is comprised of the HMI, turbine control system, data assembly system, sequence control system, process I/O system, and peripheral equipment. Each independent system is interfaced with the DCS.

(3) Plant control and monitoring system The design of the control system for the new GTCC will utilize state-of-the-art DCS with data logging system in combination with proprietary controls furnished with the gas turbine, steam turbine, HRSG, generator and Balance of Plant (BOP), and so on. The operator console of the plant installed in the CCR will be used for the primary operator interface and will contain an HMI with keyboards and mouse. The CCR will be equipped with a shift operator’s room, locker room, WC & shower room, etc., in order to create better environmental condition for operators. The gas turbine control system, steam turbine control system, HRSG and BOP control system will be tied into the DCS with redundant communications networks and hardwired signals for critical control signals. The remaining control and monitoring signals for the gas compressor control system (if necessary), and so on will be brought directly or via Remote I/O into the DCS I/O cabinets. The HMI graphics will provide the operator with control, monitoring, recording / trending, status, and alarms of equipment and process conditions. The detectors / instruments for protection / control of gas turbines, steam turbines and HRSG will be double or triple configuration to enhance the reliability of the plant. The control system will be designed to operate and control the plant automatically, and will give information on the condition of the new plant and guidance to the operators on alarm which indicates the occurrence of abnormal status during start-up, steady state operation, and shutdown. The configuration of control logic and graphic display of the control system will be designed for maintenance engineers to be able to easily and correctly modify and change them on site. The DCS will have the following functions. ➢ Turbine automatic operation control system ⚫ Gas turbine operation, control, and protection including gas turbine supervisory instruments ⚫ Steam turbine operation, control and protection including steam turbine supervisory

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instruments ⚫ HRSG control and protection ⚫ Generator protection, excitation, voltage regulation, and synchronization systems ⚫ Electrical equipment control and protection including supervisory instruments ⚫ Balance of plant control ➢ Data collection ⚫ Scan and alert ⚫ Process computation (including performance computation) ⚫ Data logging function and data display ➢ Common equipment to be operated and monitored by DCS ⚫ Gas booster compressor system (if necessary) ⚫ Water treatment system ⚫ Wastewater treatment system ⚫ Switchyard system etc. ➢ Maintenance function: Maintenance tools, so called Engineering Work Station (EWS) for the maintenance of the DCS, will be installed and these tools will have the following functions. ⚫ Control system setting / modification function ⚫ Logic diagram setting / modification function

These systems have independent monitoring and control. In the event of a defect in the devices, the impact on the power plant will be large. For this reason, the calculation system, power supply system, etc., are multiplexed in order to contribute to the reliable operation of system. The operator can select each mode to correspond to the plant condition. The typical control modes are shown in the following table.

Table 5.2.5-1 Control Mode by DCS Control mode Event Full-Automatic In the “Full-Automatic” mode, the start-up or shut down will be done by a one- push button. The main master sequence is connected to each master sequence and operation status on the unit side. As a result, start-up is automatically executed from preparation to full load under normal operation via GTCC start- up process. Semi-automatic In the “Semi-Automatic” mode, the start-up or shut down will be done step by step. The operator can proceed to the GTCC startup and shut down process to recognize each breakpoint accomplishment by master sequence. Manual In the “Individual” mode, the start-up or shut down will be done manually. (Individual) [Source: Study Team]

(4) C&I equipment power supply

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AC power source will be supplied from UPS distribution board. DC power source for DCS will be supplied from DC 220 V distribution board.

(5) Central Control Room (CCR) The CCR will be able to accommodate the operating staff. The lockable cabinets, desks, and chair sets will be installed there. The lighting will be designed for maximum comfort and HMI glare will be adjustable. Coordinated colors and materials for floors, walls, and ceilings will be provided. Rooms will be designed to absorb noise. Double doors and the corridors will be of sufficient size. A raised floor (i.e. free-access floor) will be installed.

The space of existing CCR is designed for including future planned BTG at Siddhirganj. However, it is not planned to construct future planned BTG currently. Based on counterpart intension, since the empty space at existing CCR is enough space for new GTCC, it is planned to reuse a part of existing CCR for new GTCC in case there are no technical issues,. Please note that since it is impossible to secure the space for control room and electrical room of new GTCC at existing BTG area, it is necessary to install new control room and electrical room of new GTCC at another place even though new CCR of GTCC can be installed at existing CCR.

(6) Field instrumentation Field instrumentation for the GTCC such as pressure / level / flow / temperature - sensors / switches / instruments, flue gas analyzers, vibration detector, etc., will be provided for monitoring the status of equipment and the process variables associated with the GTCC to ensure safe, efficient operation and performance requirements. All units are established according to the International System of Units (SI). The main field instrumentation will be as follows: ➢ Pressure / differential pressure / level / flow indicating and measurements ➢ Temperature measurements ➢ Chemical measurements (pH, conductivity etc.) ➢ Vibration measurements ➢ Position indicators of dampers / valves ➢ Continuous Emission Monitoring System (CEMS) All outdoor mounted instruments will be designed to withstand outdoor ambient temperatures.

(7) Telecommunication system and security system Telecommunication will be composed of PABX (Private Automatic Branch Exchange), handset stations, speakers and associated equipment. The site security will be kept by CCTV system.

5.2.6 Common facilities (1) Compressed air system

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1) General The compressed air is classified into control air and service air. The control air is supplied to the drive sources for air operated control valves and other air operated control devises. The control air should be oil- free. The service air is used for sealing, cleaning and maintenance of plant auxiliaries. Also, the service air can supply to control air system as back-up in case of decreasing the pressure of control air. The following shows a schematic diagram of compressed air system.

Instrument Air Air Dryer Instrument Compressor Air Receiver

Equipment Instrument Air Compressor Air Dryer

100% x 2 100% x 2

Instrument Air Receiver

Service Air Compressor Service 100% x 2 Air Equipment Receiver Service Air Compressor

100% x 2 100% x 1

Figure 5.2.6-1 Schematic diagram of compressed air system [Source: Study Team]

2) Siddhirganj The compressed service air system (Capacity: 28.4 Nm3/min) and the receiver (2 x 10 m3) are in operation for existing BTG. It is recommended to install new compressed control air system with general design concept and comprehensive remodel of compressed air system since it is high possibility that air control valves are installed to new GTCC.

(2) Fire-fighting system 1) General The facilities such as gas turbine, steam turbine, HRSG, generator, transformer, fuel system and facilities designed to handle hazardous materials should be provided with fire hydrants, fixed fire extinguish systems, clean gas fire protection system, fire alarm and detectors. Fire-fighting system is designed and constructed to comply with relevant Bangladesh regulations and in accordance with international standards such as National Fire Protection Association (NFPA). The CCR should be provided with fire protection and fire alarm panels in order to ensure centralized monitoring of the fire extinguishing / preventing / monitoring equipment. The following shows a schematic diagram of fire-fighting system.

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Fire Water Tank HRSG CO2 System GT Enclosure Diesel Driven Pump GT / ST FM200 CCR

Electric Driven Pump BOP Control Panel Room

Transformer MV, LV & PDC Room

Jocky Pump Switchyard Dry Chemical Turbine Lubricant System

Buildings Fuel Gas System Jocky Pump Other Portable Extinguisher

Figure 5.2.6-2 Schematic diagram of fire-fighting system [Source: Study Team]

2) Siddhirganj The fire-fighting tank (2 x 1,000 m3), jockey pump (2 x 25 m3/h), electrical motor driven pump (2 x 400 m3/h) and emergency diesel engine driven pumps (2 x 400 m3/h) are in operation for existing BTG. It is recommended to comprehensive remodel of fire-fighting system with general design concept.

(3) Water treatment system 1) General The raw water supplied to GTCC is treated by water treatment system to be used as water required for power plant, such as make up water to HRSG, make up water for auxiliary cooling water system, service water for washing and maintenance of facilities, fire-fighting water, potable water and sanitary water. The water treatment system will consist of pre-treatment system, filtered water tank, demineralization plant and potable water system. The raw water supplied to GTCC at the terminal point is coagulated and sedimented, as necessary, to obtain filtered water that will be used as service water and fire-fighting water. The filtered water is treated by demineralization plant through ion exchange process which produces demineralized water to be supplied as make up water to HRSG, make up water for auxiliary cooling water system and other requirements. The detail of water treatment system will be determined considering quality of supplied raw water, required water quantity and quality requirement of power plant. The raw water is taken from river or underground. The following shows a schematic diagram of water treatment system.

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River Water Desalination Raw Water *1 Clarifier Multi Media Filter Deep Well Water Plant Tank To WWTP Depend on Depend on Quality of Raw Water Quality of Raw Water

Fire Water Fire-fighting Water Tank

Service Water

Wet Type Condenser Cooling Water Cooling Tower

To WWTP Auxiliary Cooling Water

*1 Demineralized Water DM Tank Plant Power Block (makeup, GT compressor washing etc) To WWTP

To WWTP Potable Water

Closed Cooling Water

Auxiliary Boiler

Figure 5.2.6-3 Schematic Diagram of Water Treatment System [Source: Study Team]

2) Siddhirganj The demineralization plant (40 t/h x 100%), demineralized water tank (2 x 1000 m3) and wastewater tank (1 x 1000 m3) are in operation for existing BTG. The analysis results of demineralized water dated 15th Nov, 2018 are as follows. Conductivity: 0.6-0.7 μS/cm pH: 5.86-5.90 p-alkalinity: 0 Silica: 4.65-5.84 μg/l (ppb) Hardness: 0 Iron: 5.50-6.25 μg/l (ppb) It is recommended to remodel the existing water treatment system with general design concept to be able to supply the water quality and quantity which is required from new GTCC power plant.

(4) Wastewater treatment system (Common for three sites) The wastewater from the processes of GTCC is treated by wastewater treatment system to fulfil environmental requirement stipulated by relevant regulations at discharge point of GTCC boundary. The wastewater treatment system will consist of wastewater pond, coagulation and sedimentation pond, filters, neutralization pond, sludge thickener and dehydrator.

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The detail of wastewater treatment system will be determined considering quality, quantity and frequency of effluents from GTCC and requirement of environmental regulations. The following shows a schematic diagram of wastewater treatment system.

Wastewater Wastewater Coagulation & Final Treated pH Control Pit Filtration Neutralization from GTCC Storage Pond Sedimentation Wastewater

Sludge

Sludge Pit

Dehydrator

Sludge Cake

Oily Water from Oily Water Separator GTCC Storage Pond

Oil

Figure 5.2.6-4 Schematic Diagram of Wastewater Treatment System [Source: Study Team]

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5.2.7 Switchyard The Gas Insulated Switchgear (GIS) is planned at Siddhirganj and Air Insulated Switchgear (AIS) is planned at Feni and Gazaria. The double bus bars and 1.5 CB systems is applied to each switchyard. However, even though the completion of construction period is not yet fixed at Feni, it is necessary to decide the secondary voltage of GSUT and operating voltage of switchyard in consideration of following construction and operation plan of transmission line planned by PGCB. 1) Construction of Mirsarai 230 kV substation and transmission line between Mirsarai substation and BSRM substation (400 kV design). 2) The operation voltage of transmission line is 230 kV after above 1) is completed. 3) Construction of 400 kV transmission line between BSRM substation and Korerhat substation 4) Upgrade terminal voltage at power plant to 400 kV 5) The operation voltage of transmission line is 400 kV after above 4) is completed It may be possible to reduce cost, installation area and adapt to changing the operation voltage of grid network system easily in order to the double rating voltage type apply to GSUT because the commercial operation date of new GTCC is not clear for the timing of above-mentioned plan.

230kV Transmission Line 400kV Transmission Line

Legend

: Circuit Breaker G : Generator

: Isolator : Transformer

Start-up Transformer

1G 1G 2G Siddhirganj Feni and Gazaria Figure 5.2.7-1 Single Line Diagram of Switchyard [Source: Study Team]

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5.3 Study for plant layout of power plant 5.3.1 Design condition The design conditions for studying plant layout of power plant are as follows. 1) Siddhirganj ➢ Number of unit is 1 on 1 x 1 ➢ Shaft configuration is single shaft type ➢ Steam turbine condenser cooling system is once-through cooling system ➢ Due to narrow space, the switchyard is GIS. And connection between GSUT and GIS is 230 kV cable. ➢ The existing facilities are planned to reuse at the same position in consideration of remodeling and expandability. (cooling water pump house, water treatment plant, demineralized water tank, fire-fighting tank, service air compressed system, hydrogen generation plant, warehouse, workshop) ➢ No interfere with the existing piping rack ➢ The removal space of existing facilities including 100MW rental diesel generation plant will be effectively utilized based on the result of 2nd site survey ➢ It is planned that the CCR of new GTCC will be constructed as new one in order to confirm the maximum necessary space of new GTCC and considering of existing CCR is not able to reuse ➢ There is possibility to change the type of cooling system to wet type cooling tower since wet type cooling tower is recommended by Department of Environment (DOE). However it is recommended once-through cooling system in consideration of using existing facilities as much as possible and affecting to surrounding area even though it is secured the space (24 m x 60 m) for installation of wet type cooling tower

2) Feni and Gazaria ➢ Number of unit is 1 on 1 x 4 including future plant. (Since two units are for future plant, study of transmission line is 1 on 1 x 2 in consideration of differential construction period) ➢ Shaft configuration is single shaft type ➢ The arrangement of power block is in parallel ➢ Steam turbine condenser cooling system is wet type cooling tower ➢ The switchyard is AIS ➢ The common facilities such as water treatment plant, waste water treatment plant and switchyard are planned to use in common with two units.

5.3.2 Plant layout The three site of plant layout which is based on the chapter 5.3.1 is shown in below.

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Figure 5.3.2-1 Layout Plan (Siddhirganj) [Source: Google Earth touched up by Study Team]

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Figure 5.3.2-2 Layout Plan (Feni) [Source: Google Earth touched up by Study Team]

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Figure 5.3.2-3 Layout Plan (Gazaria) [Source: Google Earth touched up by Study Team]

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5.4 Study for construction schedule of power plant The typical construction schedule of new GTCC (J/H class, single shaft, with clutch) is shown in below. The construction period from NTP (Notice to Proceed) to taking over per unit is around 30 months. One unit is constructed in Siddhirganj and two units are constructed in Feni and Gazaria. In case of two units are constructed, the construction of 2nd unit is started three month after the construction of 1st unit is started.

Month 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 26 27 28 29 30 31 32 33 34 Taking Over NTP GT on base

Unit 1

GT First Firing Steam Admission

Taking Over NTP GT on base

Unit 2

GT First Firing Steam Admission

Figure 5.4-1 Construction schedule of power plant [Source: Study Team]

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Chapter 6 Study of Power Evacuation

Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 6 Study of Power Evacuation

6.1 Basic Study of Power Evacuation Precondition The study of this section is carried out based on existing JICA Report “Bangladesh Energy Master Plan 2016 (PSMP2016)” and the obtained current unit cost (Million USD / km). For the generating capacity of the power plants, the final formation is shown in Table 6.1.1-1 below, however Gazaria and Feni is planned to construct 660 MW x 2 respectively as for the first transmission line, because it is considered to start operation in steps according to the load demand and development of related substations and transmission lines.

Table 6.1.1-1 Electric Generating Entities, Proposed Site and Capacity of Power Plant Electric Generating Entities BPDB RPCL EGCB Site Location Siddhirganj Gazaria Feni Net output at Transmission Terminal 660 MW x 1 unit 660 MW x 4 units 660 MW x 4 units [Source: Study Team]

Study of Transmission Line Voltage (1) Siddhirganj Thermal Power Plant Since the net output of power plant is 660 MW, and considering transmission line of two (2) bundle conductors with the transmission current capacity of about 1 kA per single conductor, the transmission voltage (assuming a power factor of 0.85) is 230 kV or higher. 660 MW ÷ √3 ÷ (1 kA x 2 conductors) ÷ 0.85 = 224 kV Considering the voltage class of current and planned transmission system, the voltage shall be 230 kV or 400 kV. Two 230 kV substations of Siddhirganj and Haripur are exist nearby, and there are no 400 kV substation in the vicinity. So it is selected to transmit at 230 kV.

(2) Gazaria and Feni Thermal Power Plant Since the net output of power plant is 1,320 MW, and considering transmission line of four (4) bundle conductors with the transmission current capacity of about 1 kA per single conductor, the transmission voltage (assuming a power factor of 0.85) is 230 kV or higher. 1,320 MW ÷ √3 ÷ (1 kA x 4 conductors) ÷ 0.85 = 224 kV Considering the voltage class current and planned transmission system, the voltage shall be 230 kV or 400 kV. However, the consideration of that the capacity is more than 1,000 MW and transmission line loss, it is selected to transmit at 400 kV.

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Study of Conductor Size In this study, each capacity of the transmission line was calculated by the CIGRE method under the conditions in Table 6.1.3-1 below.

Table 6.1.3-1 Transmission Capacity Calculation Conditions Ambient temperature 40 °C Conductor temperature 80 °C Wind velocity 0.5 m/sec Wind angle 45° Global solar radiation 0.1 W/cm2 Absorptivity of Conductor surface 0.9 Emissivity of Conductor surface 0.9 Height above sea level 0 m [Source: Study Team based on CIGRE]

Table 6.1.3-2 shows the number of electric wires and conductors (number of one phase) normally used for over 230 kV conductor.

Table 6.1.3-2 Conductor currently used EHV T/L in Bangladesh Outer Number of Allowable Number of Type of conductor diameter wire / size current conductors Remarks 【mm】【qty/φ】【A】 per phase Al54/3.647 ACSR Finch 1113MCM 32.83 855 1 or 2 ASTM standard St19/2.189 ACSR Mallard Al30/4.135 28.95 715 1 or 2 ASTM standard 795MCM St19/2.482 Al30/3.698 ACSR Egret 636MCM 25.89 623 2 or 4 ASTM standard St19/2.220 [Source: Study Team]

Usually, 230 kV conductor is comprised single conductor or two (2) bundle (twin) conductor, and 400 kV conductor is comprised two (2) bundle (twin) conductor or four (4) bundle (quad) conductor. Therefore the capacity of transmission line per single circuit is shown in Table 6.1.3-3.

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Table 6.1.3-3 Capacity of single circuit transmission line [Unit: MW, Power factor: 0.85] 230 kV 400 kV Conductor Type single twin quad twin quad ACSR Finch 1113MCM 289 579 1,158 1,073 2,014 ACSR Mallard 795MCM 242 484 968 842 1,684 ACSR Egret 636MCM 210 421 843 733 1,467 [Source: Study Team]

To transmit 1,320 MW (660 MW x 2) with 400 kV, it is possible to transmit with ACSR Egret 636MCM x 4 conductors (1,467 MW). To transmit 660 MW (660 MW x 1) with 230 kV, it is possible to transmit with ACSR Egret 636MCM x 4 conductors (843 MW). However, according to the result of survey for the situation of the site, the route of the transmission line in case of Siddhirganj, there are 2 vacant circuits on existing transmission tower. And it is used ASCR Mallard x 2 conductors. According to the table above, the transmission line capacity is 484 MW < 660 MW. So it is necessary to install high capacity conductor (High Temperature Low Sag conductor) with an allowable current of about 1,000 A or more per one conductor. The calculation of conductor capacity is shown below. 660 MW ÷ √3 ÷ 230 kV ÷ 2 conductors ÷ 0.85 = 974 A And the high capacity conductor parameters of ACSR Mallard are shown in Table 6.1.3-4 below.

Table 6.1.3-4 High capacity conductor parameters Calculated Outer Ultimate Weight Allowable current Capacity Conductors Type sectional diameter strength 【kg/m】【A】【MW】*2 area【mm2】【mm】【kN】 ACSR Mallard 402.8 28.95 1.839 171.2 715 (80 °C*1) 484 ZTACIR/AS Drake 413.4 28.5 1.626 124.6 1,062 (110 °C*1) 719 GTACSR Drake 413.2 27.8 1.616 149.2 1,034 (110 °C*1) 700 *1: Conductor temperature, *2: Voltage 230 kV, 2 conductors, Power factor 0.85 [Source: Study Team]

Study of insulator (1) Types of insulators The insulator design conditions for 400 kV and 230 kV transmission line in Bangladesh is shown in Table 6.1.4-1. The creepage distance per 1 kV is considered heavy pollution and medium pollution.

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Table 6.1.4-1 Insulator design conditions Items Unit Design value Nominal voltage kV 230 400 Maximum voltage kV 245 420 Switching surge withstand voltage kV 850 1,050 Lighting impulse 50%FO voltage kV 1,050 1,425 Pollution level - Medium Medium Heavy Nominal Creepage distance mm/kV 20 20 25 [Source: Study Team]

(2) Number and length of insulator Based on the concept of the 400 kV Dhaka-Chittagong main transmission line (hereinafter D-C line), study team supposed that the area of Siddhirganj and Gazaria are medium pollution level of IEC standard. However, Feni area is heavy pollution level of IEC standard because of considering location near the sea. The necessary number of insulator was calculated in consideration of the creepage distance, lighting impulse withstand voltage (LIWV) and switching impulse withstand voltage (SIWV).

Table 6.1.4-2 Types of number of insulator in various transmission towers 230 kV Tower 400 kV Tower Items Unit Tension / Suspension Tension / Suspension Medium Medium Heavy IEC Designation - U210B U300B U300B Electro-mechanical kN 210 300 300 failing load Diameter mm 280 320 320 Height mm 170 195 195 Minimum nominal mm 405 505 505 creepage distance Number of insulator - 15 21 21 Length of insulator mm 2,550 4,095 4,095 string [Source: Study Team]

Study of transmission line tower design The typical type of transmission line tower design of 400 kV x 2 circuits and 230 kV x 2 circuits selected from various design of transmission tower are shown in Figure 6.1.5-1 to 6.1.5-4.

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Figure 6.1.5-1 400 kV Suspension tower Figure 6.1.5-2 400 kV Tension tower [Source: Study Team] [Source: Study Team]

Figure 6.1.5-3 230 kV Suspension tower Figure 6.1.5-4 230 kV Tension tower [Source: Study Team] [Source: Study Team]

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Estimated transmission line cost per kilometer According to information of Power Grid Company of Bangladesh Limited (hereinafter PGCB) research (as of September 2018), the current average transmission line construction unit cost is shown in Table 6.1.6- 1. The 400 kV river crossing overhead transmission line is evaluated as multiples of flat area.

Table 6.1.6-1 Transmission line construction cost per km Items Answer of PGCB Unit conversion Remarks 400 kV x 2 circuits 3.41 Crore BDT 34.1 million BDT 400 kV x 2 circuits 5 times of the flat area - 170.5 million BDT (River crossing) 230 kV x 2 circuits 2.70 Crore BDT 27.0 million BDT [Source: PGCB, Study Team]

Based on the above price and considering price escalation by 2023 as below the Table 6.1.6-2, the budget construction unit cost (USD) is calculated as follows by exchange rate (October 2018 average value 83.83 BDT / USD). 400 kV x 2 circuits 34.1 million BDT ÷ 83.83 BDT / USD x 1.25 = USD 0.51 million /km 170.5 million BDT ÷ 83.83 BDT / USD x 1.25 = USD 2.55 million /km (River crossing) 230 kV x 2 circuits 27.0 million BDT ÷ 83.83 BDT / USD x 1.25 = USD 0.41 million /km

Table 6.1.6-2 Inflation rate in Bangladesh Year 2018 2019 2020 2021 2022 2023 Inflation rate 6.0 6.0 5.9 5.8 5.6 5.5 Ratio with 2018 - 1.06 1.12 1.19 1.25 1.32 [Source: IMF-World Economic Outlook Database (2018.4), modified by Study Team]

6.2 Planning of transmission line route Planning condition In studying the transmission line route, the plan shall be established based on information from PGCB and the transmission line and substation facility plan obtained in the field survey of proposed sites.

Estimation of Power Flow Based on the existing JICA’s report, “ People’s Republic of Bangladesh Power & Energy Sector Master Plan (PSMP2016) Final Report September 2016 “, hereinafter referred to as "JICA Report", the Study Team examined the expected power flow after execution of proposed power station constructions.

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The JICA Report contains expected power flow diagrams of years 2025 and 2035. Based on this information, the Study Team carried out estimation of the power flow on the conditions of basic study of transmission lines in Chapter 6.1. The summary of power flow diagrams examined is as follows.

Table 6.2.2-1 Summary of Power Flow Diagrams Power flow diagrams in Included Proposed Power Stations JICA Report No. Diagram No. used as information BPDB RPCL EGCB source in the diagram Siddhirganj Gazaria Feni

1 Figure 6.2.2-1 2025 * 1 660 MW x 0 unit 660 MW x 0 unit 660 MW x 0 unit

2 Figure 6.2.2-2 2025* 1 660 MW x 1 unit 660 MW x 2 units 660 MW x 2 units

3 Figure 6.2.2-3 2035* 2 660 MW x 0 unit 660 MW x 0 unit 660 MW x 0 unit

4 Figure 6.2.2-4 2035* 2 660 MW x 1 unit 660 MW x 4 units 660 MW x 4 units

5 Figure 6.2.2-5 2035* 2 660 MW x 1 unit 660 MW x 4 units 660 MW x 4 units

6 Figure 6.2.2-6 2035* 2 660 MW x 1 unit 660 MW x 4 units 660 MW x 4 units * 1 JICA Report: Figure 15-3 Map of Bangladesh System with Expected Power Flow in 2025 (Nation- wide) Figure 15-4 400 kV System Diagram for Bangladesh with Expected Power Flow in 2025 Figure 15-5 Map of Bangladesh System with Expected Power Flow in 2035 (Dhaka Area) * 2 JICA Report Figure 15-8 Map of Bangladesh System with Expected Power Flow in 2035 (Nation- wide) Figure 15-9 400 kV System Diagram for Bangladesh with Expected Power Flow in 2035 Figure 15-10 Map of Bangladesh System with Expected Power Flow in 2035 (Dhaka Area) [Source: Study Team]

Figure 6.2.2-1 and Figure 6.2.2-3 exclude the proposed development of power stations. That is, it is the power flow diagram of 2025 or 2035 in the JICA Report, and based on them, the estimation of power flow was examined for the development of proposed power stations. Figure 6.2.2-2 shows the expected power flow in 2025, including proposed power stations of one unit of Siddhirganj, two units of Gazaria, and two units of Feni respectively. Since the total power flow of two circuits between Meghnaghat and Mirsarai is 1,533 MW and it is less than 1,982 MW of transmission line capacity of one circuit (cct), it is possible to transmit all of the evacuated power from the proposed power stations without difficulties even in case of one circuit (cct) fault. Figure 6.2.2-4 shows the expected power flow in 2035, including proposed power stations of one unit of

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Siddhirganj, four units of Gazaria, and four units of Feni respectively. Since the total power flow of two circuits between Meghnaghat and Mirsarai is 4,350 MW and it exceeds 3,964 MW (= 1,982 MW x 2) of the transmission line capacity of two circuits (cct) by 386 MW (9.7%), it is constantly impossible to transmit all of the evacuated power from proposed power stations even in case of normal operating conditions. For this reason, it is necessary to modify the transmission system planning made by PGCB, and the Study Team has established the following two alternatives as a countermeasure.

Countermeasure I By changing the impedance (13.5%) of the Moheskhali's 765 kV / 400 kV transformer to a low impedance, it is possible to easily increase the power flow generated 400 kV side generators into 765 kV system. As shown in Figure 6.2.2-5 with this countermeasure, the power flow of the 400 kV system can be reduced, and the constant overload between Meghnaghat and Mirsarai can be eliminated. However, in case of one circuit (cct) fault of the transmission line occurred, since its power flow exceeds 1,982 MW of the transmission line capacity of the remaining one circuit (cct), it is required to reduce the output power of the power stations or to shut off generators. For this purpose, the overload relay (OLR) system for transmission lines protection is installed.

Countermeasure II By shifting the connection of two units (1,200 MW) of four machines of 400 kV side of Moheskhali to the 765 kV side, the overload under normal operating conditions between Meghnaghat and Mirsarai can be eliminated. As shown in Figure 6.2.2-6, reducing the power flow of the 400 kV system by this countermeasure, the overload under normal operating conditions between Meghnaghat and Mirsarai can be eliminated. However, in case of one circuit (cct) fault of the transmission line occurred, since its power flow exceeds 1,982 MW of the transmission line capacity of the remaining one circuit (cct), it is required to reduce the output power of the power stations or to shut off generators. For this purpose, the overload relay (OLR) system for transmission lines protection is installed.

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Legend in Figure

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Siddhirganj: 0 unit Gazaria: 0 unit Feni: 0 unit Figure 6.2.2-1 400 kV System Diagram for Southeast Region of Bangladesh with Expected Power Flow in 2025 [Source: Study Team]

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Siddhirganj: 1 unit Gazaria: 2 units Feni: 2 units Figure 6.2.2-2 400 kV System Diagram for Southeast Region of Bangladesh with Expected Power Flow in 2025 [Source: Study Team]

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Siddhirganj: 0 unit Gazaria: 0 unit Feni: 0 unit Figure 6.2.2-3 400 kV and 765 kV System Diagram for Southeast Region of Bangladesh with Expected Power Flow in 2035 [Source: Study Team]

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Siddhirganj: 1 unit Gazaria: 4 units Feni: 4 units Figure 6.2.2-4 400 kV and 765 kV System Diagram for Southeast Region of Bangladesh with Expected Power Flow in 2035 [Source: Study Team]

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Siddhirganj: 1 unit Gazaria: 4 units Feni: 4 units Figure 6.2.2-5 400 kV and 765 kV System Diagram for Southeast Region of Bangladesh with Expected Power Flow in 2035 [Source: Study Team]

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Siddhirganj: 1 unit Gazaria: 4 units Feni: 4 units Figure 6.2.2-6 400 kV and 765 kV System Diagram for Southeast Region of Bangladesh with Expected Power Flow in 2035 [Source: Study Team]

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Study of the route of transmission line (1) Siddhirganj Thermal Power Plant Figure 6.2.3-1 shows proposed route of the transmission line on the Google earth.

Figure 6.2.3-1 Proposed route of the transmission line [Google Earth touched by Study Team]

As a result of considering current surrounding situation at the field survey, it is appropriate to use vacant circuit of the existing transmission tower (TW1 to TW2 in the drawing). The distance between New Tower and Substation is 0.5 km. According to the PGCB, the transmission tower is designed the conductor type for 230 kV_ASCR Mallard x 2 conductors. However, since this type of conductor is not possible to carry 660 MW, it is recommended to use high capacity conductor instead. Up to the Siddhirganj substation, there are many facilities and the vacant space is also limited. So it is difficult to construct new transmission line from new GTCC, hence, the underground 230 kV cable placing from new GTCC to transmission line at TW2 is planned. The situation of substation bay, there are two (2) vacant bays shown in Figure 6.2.3-2 and the study team confirmed with the PGCB that these two bays are not planned to use for the future. It is recommended to order early for using because it is on a first-come-first-served basis. The circuit breaker rated current is 2,500 A, and interrupting capacity is 50 kA. These are enough to power evacuate new GTCC.

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[Google Earth touched by Study Team]

Figure 6.2.3-2 Situation of the connected substation (Siddhirganj) [Source: Study Team]

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The existing tower TW2 is designed for four circuits power transmission tower as shown Figure 6.2.3-3 below. The lower two circuits are not used and can be used (necessary for reconfirmation design situation). However, there are two issues. First, regarding to the position of new termination structure (red square in the drawing Figure 6.2.3-1), it is necessary to remove the existing facilities as shown in Figure 6.2.3-1 route of the transmission line above. The study team got reply from the power station engineer that it is possible to be removed in the interview at field survey. The detail position is decided taking into consideration the design conditions of TW2 and separation and clearance from other facilities. Second, regarding to the existing transmission tower TW1, existing 132 kV transmission line has placed on the tower as shown in Figure 6.2.3-4. Therefore, though the 132 kV transmission line shall be removed or relocate before placing new circuits, the study team got reply that it is possible to be replaced in the meeting with PGCB.

Figure 6.2.3-3 Photo and Image drawing of existing transmission tower (TW2) [Source: Study Team]

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Figure 6.2.3-4 Photo and Image drawing of existing transmission tower (TW1) [Source: Study Team]

Figure 6.2.3-5 Image drawing of conductor placing of substation [Google Earth touched by Study Team]

(2) Gazaria Thermal Power Plant Figure 6.2.3-6 shows the proposed route of the transmission line on the Google earth.

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Figure 6.2.3-6 Proposed route of the transmission line [Google Earth touched by Study Team]

There are four alternative routes for this project. As a breakdown shown in Figure 6.2.3-6 above that; Plan 1-1 (Yellow line) and plan 1-2 (Purple line) are shown planned transmission line to be connected to planned 400 kV substation. Plan 2 (Blue line) is shown planned transmission line to be connected to 400 kV transmission line (Red line). Plan 3 (Light blue line) is shown the planned transmission line to be connected to planned 230 kV substation. The route which is connected to under construction 400 kV substation is selected based on these above four routes, considering the power generation plan and recommended connection point by PGCB. To connect to 400 kV substation is considered two ways as shown in Figure 6.2.3-7 (Plan 1-1 and Plan 1-2). Considering the route of D-C line construction project, making use of the bay of 400 kV Meghnaghat substation, and the result of field survey, the recommended plan is plan 1-1 (the line distance is 13.0 km). Although a part of this route is flood area during rainy season, the transmission line should be constructed in dry season. Although there are some buildings and private houses on proposed route, transmission line can be constructed avoiding them. It is long span to cross Meghna river whose width is about 1,100 m, but it is not problem because the D-C line which is preceding project of this project is studied to be able to construct.

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Figure 6.2.3-7 The way of connecting to 400kV Meghnaghat Substation [Source: Study Team]

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(3) Feni thermal power Plant Figure 6.2.3-8 shows the proposed route of the transmission line on the Google earth.

Figure 6.2.3-8 Proposed route of the transmission line [Google Earth touched by Study Team]

There are two alternative routes for this project. As a breakdown shown in Figure 6.2.3-8 above that; Plan 1 (Yellow line) is shown planned transmission line to be connected to planned 400 kV Mirsarai substation which is based on information from PGCB. The line distance is 7.4 km Plan 2 (Blue line) is shown planned transmission line to be connected to planned 400 kV substation at D- C Line. The line distance is 29.1 km. However, the position of Korerhat substation is assumed. Considering the current generation capacity of the power plant and the construction cost of the transmission line and the interview result with the PGCB, it is reasonable to connect to the 400 kV Mirsarai substation (under planning) of the industrial park under construction, which is recommended by the PGCB (Plan-1 route). However, it is necessary to consider the construction plan of Mirsarai substation and Korerhat substation and their associated transmission lines. Although this area is flood area during rainy season (It requires more detail survey), it is possible to be constructed in dry season. There are no buildings and private houses in the surveyed area. And also these could not be found on Google earth.

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According to information from EGCB, it is likely that the Mirsarai substation will not receive 400 kV and will receive 230 kV at the completion of new GTCC. Also it is likely to be operated at 230 kV with preceding solar power plant (50 MW). In that case, the transmission line is designed as 400 kV and will be operated at 230 kV. It is necessary to plan considering conversion method after 400 kV power transmission reception.

Estimation of budget costs of transmission line for power evacuation Table 6.2.4-1 shows summary of the budget costs of transmission line for power evacuation based on the Clause 6.1.6.

Table 6.2.4-1 Budget costs of transmission line Voltage Distance Estimate cost Power Plant Number of line Remarks [kV] [km] 【mil US＄】 Not Consider of GIS of power plant Siddhirganj 230 2 0.6 0.13* side and 230kV cables Gazaria 400 2 13.0 9.18 Including river crossing about 1km Feni 400 2 7.4 3.78 *: 50% of per km in order to divert the existing transmission tower [Source: Study Team]

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Expected construction schedule of transmission line for grid As for the transmission line construction schedule, the delay of the site problem etc. is not taken into consideration, and referring to the past project, the expected construction schedule of transmission line around Gazaria Power Plant which needs a long distance line is shown in Figure 6.2.5-1 below.

Figure 6.2.5-1 Schematic construction schedule of transmission line for grid [Source: Study Team]

6-24 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chpater 7 Environmental Evaluation

Chpater 7 Environmental Evaluation

Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chpater 7 Environmental Evaluation

7.1 Siddhirganj Power Station 7.1.1 Study Area Study area around Siddhirganj for IEE are as follow.

Figure 7.1.1-1 Study area around Siddhirganj site for IEE [Source：Study Team]

7-1 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chpater 7 Environmental Evaluation

The proposed Project falls under the ‘Red’ category under the Environment Conservation Rules (ECR), 1997 of Bangladesh Government and needs both Initial Environmental Examination (IEE) and as pre- examination of Environmental Impact Assessment (EIA) study for site clearance certificate from the Department of Environment (DoE). This report is limited to the IEE study of 600 ±10% MW Gas fired Combined Cycle Power Plant at Siddhirganj for obtaining site clearance certificate.

7.1.2 Geographical Features The existing Power Plant site is located at Ward no. 5 of Siddhirganj Upazila in Narayanganj district. It is expected that the proposed CCPP will greatly supersede the power production efficiency compared to the traditional coal based Power Plant. From an environmental point of view, the gas and steam turbine operated Power Plant will significantly reduce the environmental pollution and hence reduce ecological health risks. Considering the vicinity to a distributary channel of Jamuna river, locally called Shitalakhya River water for Power Plant usage, proven resistance of vulnerability to seismic hazards, existing facilities for the workers and most importantly availability of suitable land resource within the urban setting, made that area a good choice for the new 600 ±10% MW gas fired CCPP installation. Finally, the environment friendly mechanical equipment has been explored to select the best alternative. Those options have to be further assessed in detail with respect to site specific environment and social significance in the EIA stage.The proposed Project with rated capacity of 600 ±10% MW will be located on the right bank of the River Shitalakhya. The topography of the project area is already raised for protecting from the flood when existing power plant was constructed. The seismic intensity of this Zone is 0.15 g which indicates the proposed project site is moderate vulnerable in terms of earthquake risk. The Meghna lineament is about 15 km south of the proposed project area. The seismicity and the tectonic activities of this project area may be governed by Meghna Lineament. The nearest meteorological station from the project site is located in Dhaka which has a tropical wet and dry climate. Data collected from the station states that an annual average temperature of 25.94°C (78.7 °F) and monthly means varying between 19 - 20°C in January and 28 - 29°C in April is observed. The data also shows that the annual average rainfall of 2,000 millimeters (78.74 inch) occurs during the monsoon season which last from May till the end of September. The major River network in the study area is Shitalakhya, Dhaleswari, Buriganga, Dhanagoda, Meghna and upper Meghna. Water level of those rivers is comparatively high from July to October. In the month of September, the water level reaches to peak with an approximate value of 7.87 m PWD in high tide. But the minimum values of water level at 0.26 m PWD in low tide during the month of January. There is no fish pond or other water bodies located on the proposed project area. However, major fish habitat in the study area is the Shitalakhya River where numbers of industrial effluent disposed through the year. As a fish habitat, this river remains suitable from the month of July to September, and becoming deteriorated from December to March. On the other hand, bentho-pelagic fish species are recorded as the Dissolved Oxygen (DO) level in surface water sharply decreases in dry season. Fisherman usually catch fish mainly in the Shitalakhya River from June to early October. Generally, 50 of fish species have been informed

7-2 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chpater 7 Environmental Evaluation

by local fishermen in the study area under the catchment of Shitalakhya River. Ecosystems of the study area characterized by urban and semi-urban natures and the River Shitalakhya hold the major aquatic ecosystem which does not support significant population of aquatic animals due to pollution by urban and industrial waste. However, the Ganges River dolphin occurs in this River for 3-4 months in peak monsoon. Shitalakhya River is an Ecologically Critical Area passing beside Siddhirganj Power Station. Except this River, there is no designated protected area located within the site or 10 km surroundings of the study area. The site does not hold any core habitat of any endangered wildlife. As the project will be implemented inside the previously occupied land of Power Plant, no direct land or agricultural loss will happen. About 2,541,696 population in 591,307 nos. of households with the average density of 4,858 people per kilometer are residing in the study area. Sex ratio of 112 indicates that there are 112 male against of 100 female. The area is found to be dominated by service holders, as 57% of employed population are serving in different government and non-government organization in the study area.

7.1.3 Environmental Evaluation and Expected Risk 7.1.3.1 Influence on Ecosystem Clearance of vegetation and thus relocation of existing wildlife from the site and interrupt wildlife movement are suspecting the referable impacts on ecological resources in construction phase. Therefore, proper layout planning, fencing at construction site, awareness of labour about wildlife conservation activities can minimize the vegetation loss as well as wildlife threats.

7.1.3.2 Influence on Air and Water Quality Water quality may be deteriorated in case of oil spillages, disposal of kitchen waste. Drainage system inside the project area may be affected due to arbitrary falling of demolished or construction materials and improper management of the drainage system. Accidental event may increase in the study area due to increment in vehicles movement During, operation phase, air pollution and at the worst case scenario, high air pollution may occur cumulatively due to the emission of NOx, CO, CO2 and SPM. Installation of low NOx burner and stack height of 60m will keep NOx, SPM level below the DoE standard. Development of green belt at fallow land inside the project area may reduce CO2. Air pollution monitoring devices will be installed at the sensitive point for continuous monitoring of the ambient pollution level.

7.1.4 Countermeasure In consideration of the above points, the below concrete plan is required to mitigate environmental impact.

1. The visual beauty or the scenic view may be changed only during demolition and evacuation stages of the existing Power Plant which will revive enormously after construction of this Combined Cycle Power Plant. During demolition and construction stage, Suspended Particular Matter (SPM), debris and loose

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soil, Green House Gases (GHGs) from machinery, engines and vehicles may release but it is small impact environmentally. Garbage, sanitary waste and domestic waste may be generated from labour sheds. Considering these impacts, water spraying, temporary STP, use of low GHG emission equipment and machineries must be used. Generation of high noise should be protected at sources and temporary noise barrier during demolition and construction stages should be used.

2. Establishment of this Power Plant at the existing one implies no agricultural loss. Soil quality inside the project area might be affected due to oil or chemical substances spill or leaking. Leaching or percolation of liquid waste may pollute ground water. But use of efficient concrete drainage network, safety handling, oil separator, ETP will reduce this chance effectively.

3. The proposed activities are expected to create more pressure on riverine fish habitat condition of Shitalakhya river and fish diversity even in monsoon season. It is expected that once through thermal plume (about 7℃ from the ambient intake water) will increase temperature at certain part of the river and may hinder the migration of fishes. Therefore, thermal plume discharge must be limited to maximum 3℃ higher from the ambient receiving water bodies at the edge of scientifically established (mostly 100m from the outfall) mixing zone boundaries. Even the intake velocity for once through cooling system should be maintained for keeping the velocity within the permissible limit.

4. In terms of social issue – labour recruitment and employment opportunity are found as most important for community health, safety and risk. Health and safety management is the major concern from pre- construction phase (demolishing stage) to construction phase. Adequate measures are suggested for resolving the health safety impact and for improving the employment generation condition for the local stakeholders.

5. For this IEE study, a preliminary Hazard and Risk assessment has been carried out during pre- construction, construction and operation phase of the Project. However a more detail analysis and assessment with mitigation measures will be carried out at the EIA stage and incorporated in the EIA report.

6. Implementation of such a 600 ±10% MW Gas fired Combined Cycle Power Plant Project with advanced technology requires significant skill up gradation and capacity building of the workforce of BPDB for successful operation and maintenance of the Combined Cycle Power Plant.

7. Generation of high noise should be protected at sources and temporary noise barrier during demolition and construction stages should be used.

8. Installation of low NOx burner will keep NOx, SPM level below the DoE standard.

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9. Development of green belt at fallow land inside the project area may reduce CO2

Compliance with the above countermeasure leads to mitigate the environmental impact and therefore it is expected below the DoE standard.

7-5 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chpater 7 Environmental Evaluation

7.2 Feni Power Station 7.2.1 Study Area Study area around Feni for IEE are as follow.

Figure 7.2.1-1 Study area around Feni site for IEE [Source: Study Team] The proposed Project falls under the ‘Red’ category under ECR, 1997 of Bangladesh Government and needs both Initial Environmental Examination (IEE) as pre-examination of Environmental Impact Assessment (EIA) study for site clearance certificate from the DoE. This Report is limited to the IEE study of 2 x

7-6 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chpater 7 Environmental Evaluation

600±10% MW gas fired combined cycle power plant (hereinafter called as ‘The Project’) at Sonagazi Upazila for obtaining site clearance certificate.

7.2.2 Geographical Features The proposed power plant site is located at Sonagazi Upazila in Feni District of Bangladesh. It is expected that the proposed CCPP will greatly supersede the power production efficiency compared to the traditional coal based power plant. From environmental point of view, the gas and steam turbine operated power plant will significantly reduce the environmental pollution and hence reduce ecological and health risks. Considering the vicinity to the distributary channels such as Muhuri, Little Feni, and Feni Rivers water for power plant usage, availability of suitable land resource, absence of any ecological habitat and no population, made that area a good choice for the installation of the proposed 2 x 600±10% MW Gas fired CCPP at that location. Finally, the environment friendly mechanical equipment has been proposed as the best among the alternatives. Those options need to be further assessed with respect to site specific significance in EIA stage. Physio graphically, the project area lies within the young Meghna estuarine floodplain. Tectonically, the proposed project area falls in Zone II (0.15 g), which indicates moderate vulnerability in terms of earthquake risk. Due to its location very close to the two major tectonic units (Hatiya trough and Indo-Burman ranges), the probability of future seismic events need to be evaluated using available surface geophysical methods. According to Bio-ecological Zones (BEZ), the project site is located in Meghna Estuarine floodplain, Coastal and Marine water zone. There is no vegetation inside the proposed power plant site. However, the surrounding area of the project site has diverse vegetation which can be categorized as homestead vegetation, crop-field vegetation, coastal, road and embankment-side vegetation. Local and migratory birds are the major faunal species found in and around the project site. Birds are mainly concentrated near the water bodies of the project site. The study area airshed is affected with the SPM solid particulate matter (PM2.5 and PM10) pollution like maximum part of Bangladesh. The major sources of noise around the project area are winds and chirping of birds at that barren land. The proposed project area noted as tropical climate where the average temperature is 25.6 °C and average annual rainfall is 2,673 mm. Two khals locally known as Sonagazi-Dangi Khal and Mosjid Khal originates from the north and merges into Little Feni River within the study area. The major river network existing in and around the study area is Little Feni River, Muhuri or Feni River and Sandwip channel of Meghna river. The in-situ tested water parameters like temperature, pH, EC, TDS etc. have been found within the DOE standard. The proposed gas fired CCPP would be constructed on 28.27 ha area used as grazing land for the cattle and hoards. Major cropping pattern of the study area is Fallow-HYV Aman-HYV Boro, which is 40% of the study area. Total annual crop production of the study area is 79,409 tons of which rice production is 61,709 tons (78%) and non-rice is 17,700 tons (22%) respectively. In case of fisheries, estimated total fish production from the study area comes about 8,780 MT annually where the fish production of project area is very insignificant. There is no house or temporary residence within the project boundary. According to the local people, there

7-7 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chpater 7 Environmental Evaluation

were negotiation meetings between affected land owners and project proponent to consider the rate of land compensation while BDT 9000 per decimal was determined. The most suitable road access to the power- plant site is Feni-Sonagazi road which is connected with Dhaka Chittagong highway and ends at Sonagazi Upazila. From there, the site can be accessed by Sonagazi-Muhurigonj project road. The materials needed for construction of the power-plant will be transported to the site using the river route along with road network

7.2.3 Environmental Evaluation and Expected Risk 7.2.3.1 Influence on Ecosystem Site development may interrupt wild animal movement during the construction phase. Therefore, proper layout planning, fencing at construction site, awareness of onsite labours about wildlife conservation activities might minimize the vegetation loss as well as wildlife threats.

7.2.3.2 Influence on Air and Water Quality During pre-construction and construction stage, Suspended Particulate Matter (SPM), debris and loose soil, Green House Gases (GHGs) from machinery, engines and vehicles might be released. Moreover, garbage, sanitary waste and domestic waste would be generated from labour sheds. During Construction and land development stage obstruction to rainfall runoff and drainage congestion may occur due to land filling. Turbidity may be increased in water column of the river near the construction area and project intersecting channel. During, operation stage, air pollution may occur due to emission of pollutants like NOx, PM2.5 and PM10 and SO2 from stacks of Power Plant. Internal drainage system may cause severe water logs in the plant area. Discharge of polluted water to the Sonagazi-Dangi Khal may impact to fish habitat. Moreover, ground water may be polluted by leakage of oil and chemical from tank or storage. When a preliminary Hazard and Risk assessment has been carried out during pre-construction, construction and operation phase, Ecological risk assessment matrix shows that the risk is higher for rivers and khals; and grazing land. Therefore, some countermeasure for mitigation of the above risk shall be considered.

7.2.4 Countermeasure In consideration of the above points, the below concrete plan is required to mitigate environmental impact.

1. Low noise and low GHG emission equipment and machineries must be used. 2. Temporary wire fencing should be given around the Project area 3. Temporary noise barrier during construction and operation stages should be used. 4. Vehicles carrying landfill soil should be well covered 5. Installation of water spraying system for mitigation of dust. 6. Abstaining from dumping solid and liquid wastes of different kinds near the River/water body. 7. Regular excavation and cleaning

7-8 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chpater 7 Environmental Evaluation

8. The vessels should not be overloaded during materials and equipment transportation. 9. proper air effluent mitigating equipment, water spraying system, speed limiting signs, water treatment/effluent Treatment Plant should be implemented with proper monitoring

Additionally, making the EMP for mitigation of environmental impact during pre-construction, construction and operation stage is recommended but a more detail analysis and assessment with mitigation needs to be carried out at the EIA stage and incorporated in the EIA report. Compliance with the above countermeasure leads to mitigate the environmental impact and therefore it is expected below the DoE standard.

7-9 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chpater 7 Environmental Evaluation

7.3 Gazaria Power Station 7.3.1 Study Area Study area around Gazaria for IEE are as follow.

Figure 7.3.1-1 Study area around Gazaria site for IEE

The proposed Project falls under the ‘Red’ category under the ECR, 1997 of Bangladesh Government which needs both Initial Environmental Examination (IEE) as pre-examination of Environmental Impact Assessment (EIA) study for site clearance certificate from the DoE. This report is limited to only the IEE

7-10 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chpater 7 Environmental Evaluation

study of 2 x 600±10% MW combined cycle Power Plant at Gazaria for obtaining site clearance certificate.

7.3.2 Geographical Features Physio-graphy, the proposed Gazaria Power Plant area lies within the Middle Meghna River floodplain. Tectonically, the proposed project site is situated in Bengal fore deep more specifically near the east central brink of Faridpur Trough of the Bengal basin. The seismic intensity of this Zone is 0.15 g which indicates that the proposed project site is moderate vulnerable in terms of earthquake risk. The site is located in a flood prone area. A major part of the project site as well as the surrounding areas go under water during the peak flood time. So the project area needs earth filling to raise the land above the flood level (Design level) taking dredged earthen materials from the River or from some other external sources. The proposed Project area has hot, wet and humid climate like Dhaka where the nearest meteorological station is located. The study area falls within the margins of four bioecological zones among which the proposed site falls within one bioecological zone namely ‘Major Rivers’. The site contains floodplains ecosystems in monsoon and crop field ecosystems in dry season with seasonal growing undergrowth vegetation. Among the wildlife, local avifauna are major group, which are roaming here for occasional feeding, and grazing purposes especially during the dry season. The site as well as the study area do not possess any protected area or important habitat for any threatened species. The proposed project and entire area is agricultural land. Currently, total NCA of the project area is practicing B. Aman, HYV Boro, vegetables, jute and potatoes. Fish habitat in the study area including river and Khal, floodplain and cultured fishpond is about 23,982 hectares (ha). Among the fish habitats, the project area occupies about 31 ha of floodplain habitat. The floodplain habitat functions as breeding, nursing and grazing ground for small indigenous species (SIS) of fishes. Estimated total fish production from the project area makes about 8 metric-ton annually. About 490,162 population in 105,781 households with the average density of 1,599 people per sq. kilometre are residing in the study area. The ratio of the total male and female family members are close to 1:1. Most of the people in the proposed study area live on different kinds of farming activities. Among them about 58% of the total employed population are engaged with agriculture practices.

7.3.3 Environmental Evaluation and Expected Risk 7.3.3.1 Influence on Ecosystem The installation of the CCPP might cause temporal and even permanent impacts which can affect the environment in all three phases (pre-construction, construction and operation phases) of project activities. The impacts during the pre-construction stage include drainage congestion, reduction in growth of vegetation and damage to wildlife habitat etc. Clearance of vegetation and thus relocation of existing wildlife from the site and interrupt wildlife movement, roosting places of birds are suspecting perceptible impacts on ecological resources. About 31 hector of agriculture land will be transformed in to industrial land through construction of Power Plant causing thereby a permanent loss of 311 tons of food grain per year.

7-11 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chpater 7 Environmental Evaluation

7.3.3.2 Influence on Air and Water Quality

Emission of minor amount of CO, CO2, NOx, SOx, may cause air pollution, which might have adverse effects on community health and sensitive biota of the ecosystems, but these emissions can be almost ignored because gas fired power station. Water quality may be deteriorated due to spillages, disposal of kitchen waste. Drainage system inside the project area may be affected due to arbitrary staking of construction materials and improper management of the drainage system. Accidental event may increase in the study area due to increment of vehicles movement. High air pollution may occur cumulatively due to the emission of NOx, CO and SPM. Noise generated from the GT, HRSG, Cooling Tower and others may affect the nearest community. Effluent discharge, chemical discharge etc. may affect the fisheries and riverine ecology of the Meghna River and adjoining flood plain areas. Moreover, the induced impact may pressurize the local inhabitants.

7.3.4 Countermeasure In consideration of the above points, the below concrete plan is required to mitigate environmental impact.

1. To protect impulse noise, temporary noise barrier might be adopted to enclose the noise sources. 2. Proper layout planning, fencing at construction site, aware labor about wildlife conservation activities etc. can minimize the vegetation loss as well as wildlife threats. 3. To avoid disturbance in agricultural activities in the surrounding areas during construction phase, the spoil of soil materials, surface runoff and generation of dusts requires to be managed through regular monitoring and reporting to the concerned bodies of the project

4. Installation of low NOx burner will keep NOX level below the DoE standard.

5. Development of green belt at fallow land inside the project may reduce CO2 emission.

6. To mitigate CO2 emission high efficiency operation of generation equipment should be conducted. 7. Air pollution monitoring devices will be installed at the sensitive point for continuous monitoring of the ambient pollution level. 8. Moreover, electrification, improve communication and industrialization will create enormous job opportunity for the local communities in future.

7-12 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 8 Examinations of Carbon Dioxide (CO2) Reduction

Chapter 8 Examinations of Carbon Dioxide

(CO2) Reduction Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 8 Examinations of Carbon Dioxide (CO2) Reduction

8.1 How to Determine the Amount of CO2 Emissions In Bangladesh, generating power is provided mainly by thermal power generation, and thermal power plants account for approximately 94% of all the power plants in 2017. Fuels for thermal power generation are natural gas (69%), heavy oil (22%), light oil (7%), and coal (2%). Generally, the Ministry of Environment, environmental regulation authorities, discloses fuel consumption and the amount of emissions of CO2, a greenhouse gas, as information on each energy-using sector. In Bangladesh, however, such data is not disclosed; the amount of CO2 generated through electric power generation is calculated as the total amount of CO2 emissions from the thermal power plants and the amount of CO2 generated per unit power generation on the basis of the data (the electric energy generated by each power plant, fuel types used by each power plant, and annual consumption) described in the FY2016/17 Annual Report issued by BPDB.Table 8.1-1~Table 8.1-3 lists data on all the thermal power plants [Source: BPDB Annual Report].

Table 8.1-1 Plant Wise Generation (FY 2016-17) (Public Sector)

Sl.No. Name of Power Plant Fuel Capacity (MW) Generation (GWh) Efficiency (%) Fuel Consumption (TJ)

1 Rauzan 210 MW (1st) Gas 180 249.38 26.10 3,439.72

2 Rauzan 210 MW (2nd) Gas 180 609.42 26.57 8,257.10

3 Chitagon 1 x 60 MW ST Gas 40 67.16 24.26 996.60

4 Shikalbahw 150 MW PP Gas 150 401.50 29.50 4,899.66

5 Shikalbahw 225 MW PP Gas 150 118.79 30.39 1,407.19

6 Ashuganj 2 x 64 MW ST Gas 53 205.93 25.00 2,965.39

7 Ashuganj 3 x 150 MW ST Gas 398 2,928.25 33.04 31,905.87

8 Ashuganj (South) 450 MW CCPP Gas 260 1,643.39 41.02 14,422.73

9 Ashuganj (North) 450 MW CCPP Gas 360 268.86 35.86 2,699.10

10 Ashuganj 50MW Gas 45 226.00 38.33 2,122.62

11 Ashugenj 225 MW CCPP Gas 221 1,093.00 40.47 9,722.76

12 Chandpur 150 MW CCPP Gas 163 608.49 30.65 7,147.03

13 Ghorasal 2 x 55 MW ST Gas 85 414.73 26.78 5,575.16

14 Ghorasal 2 x 210 MW ST Gas 350 1,887.53 32.05 21,201.59

15 Ghorasal 210 MW ST Gas 190 237.60 30.68 2,788.01

16 Siddhirgabj 201 MW ST Gas 150 678.25 30.71 7,950.83

17 Siddhirgabj 2 x 120 MW GT Gas 210 506.94 23.88 7,642.31

18 Haripur 3 x 33 MW GT Gas 40 197.51 20.62 3,448.28

19 Haripur 412 MW CCPP Gas 412 2,874.64 56.08 18,453.47

20 Shahjibazar 60 MW GT Gas 66 214.53 25.79 2,994.60

21 Shahjibazar 330 MW CCPP Gas 330 906.95 47.38 6,891.14

22 Sylhet 20 MW GT Gas 20 25.73 23.66 391.50

23 Sylhet 150 MW GT Gas 142 502.36 25.79 7,012.39

8-1 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 8 Examinations of Carbon Dioxide (CO2) Reduction

24 Fenchuganj CCPP U.1 Gas 80 446.92 25.06 6,420.24

25 Fenchuganj CCPP U.2 Gas 90 389.95 27.85 5,040.65

26 Bheramara 360 MW CCPP Gas 278 252.10 37.58 2,415.01

27 Baghabari 71 MW GT Gas 71 390.41 27.50 5,110.82

28 Baghabari 100 MW GT Gas 100 104.60 29.12 1,293.13

29 Bhola 225 MW CCPP Gas 194 1,032.96 47.53 7,823.81

30 Shirajgonj 210 MW CCPP Gas 210 1,566.49 46.12 12,227.59

Sub-total 21,050.37 214,666.29

CO2 Emmission (ton) 10,625,981

31 Hatazari 100 MW peaking PP HFO 98 111.89 38.75 1,039.49

32 Sangu, Dohazari 100 MW PPP HFO 102 263.08 41.58 2,277.75

33 RPCL Raozan 25 MW HFO 25 117.03 38.84 1,084.73

34 RPCL Gazipur 52 MW HFO 52 241.44 38.80 2,240.16

35 Faridpur 50 MW PPP HFO 54 28.54 39.37 260.97

36 Gapalgonj 100 MW PPP HFO 109 177.08 38.16 1,670.57

37 Bagabari 50 MW RE HFO 52 88.90 37.12 862.18

38 Bera 70 MW RE HFO 71 109.16 41.67 943.07

39 Santahar 50 MW PP HFO 50 104.40 36.58 1,027.45

40 Katakhari 50 MW PP HFO 50 108.52 37.75 1,034.89

41 Chapainobgonj 100 MW PP, Amura HFO 100 43.01 38.88 398.24

Sub-total 1393.05 12,839.50

CO2 Emmission (ton) 918,024

42 Shikalbaha 150 MW PPP HSD 150 111.6 27.28 1,472.73

43 Shikalbaha 225 MW PPP HSD 150 13.37 27.07 177.81

44 Barisal 2 x 20 MW GT HSD 46 57.98 21.88 953.97

45 Khulna 150 MW (NWPGCL) HSD 230 967.01 40.58 8,578.70

46 Rangpur 20 MW GT HSD 20 26.75 19.6 491.33

47 Saidpur 20 MW GT HSD 20 33.37 22.18 541.62

Sub-total 1210.08 12,216.15

CO2 Emmission (ton) 837,621

48 Barapukuria 2 x 125 MW ST Coal 200 1,008.84 24.24 14,982.77

Sub-total 1,008.84 14,982.77

CO2 Emmission (ton) 1,356,940

Total Public Sector CO2 Emmission (ton) 24,662.34 13,738,565

(GWh) 557 gr/kWh

[Source: BPDB Annual Report]

8-2 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 8 Examinations of Carbon Dioxide (CO2) Reduction

Table 8.1-2 Plant Wise Generation (FY 2016-17) (Private Sector)

Sl.No. Name of Power Plant Fuel Capacity (MW) Generation (GWh) Efficiency (%) Fuel Consumption (TJ)

IPP

1 RPCL 210MW (Mymensingh) Gas 202 1,092.05 45.15 8,707.38

2 CDC Haripur Gas 360 2,362.91 49.05 17,342.46

3 CDC Meghnaghat Gas 450 2,599.08 45.17 20,714.39

4 Ashuganj 50 MW Midland Gas 51 229.39 35.51 2,325.55

5 Ghorashal 108 MW (Regent Power) Gas 108 653.34 37.26 6,312.46

6 Ashuganji mod 195 MW (United P) Gas 195 958.71 42.51 8,118.93

7 Bibiyana 2 (Summith) 341 MW Gas 341 2,061.22 28.88 25,693.88

Sub-total 9,956.70 89,215.04

CO2 Emmission (ton) 4,416,145

8 KPCL(Khulna BMPP) HFO 110 414.34 39.09 3,815.87

9 NEPC (Haripur BMPP) HFO 110 220.35 41.03 1,933.37

10 Natore, Rajshahi 50 MW PP HFO 52 201.28 43.57 1,663.09

11 Gogonnogor 102 MW PP HFO 102 421.09 41.25 3,674.97

12 Baraka-Potengga 50 MW PP HFO 50 276.51 43.05 2,312.28

13 Potiya, Chitagong 108 MW (ECPV) HFO 108 487.89 43.05 4,079.92

14 Comilla 52 MW ((LB) HFO 52 83.05 43.57 686.21

15 Katpotti, Mushingonj 50 MW (SP) HFO 51 162.60 42.90 1,364.48

16 Nawabganj 55 MW (DS) HFO 55 271.97 44.40 2,205.16

17 Doreen Northern Power HFO 55 234.55 44.40 1,901.76

18 Madangonj 55 MW IPP (Summit) HFO 55 254.07 42.54 2,150.10

19 Sumit Barisal 110 MW HFO 110 710.88 42.54 6,015.91

20 CLC 108 MW Bosila Keraniganj HFO 108 124.29 43.20 1,035.75

21 Jamalpur 95 MW PP HFO 95 274.45 43.57 2,267.66

Sub-total 4,137.32 35,106.51

CO2 Emmission (ton) 2,510,115

22 Megnaghat Power Co. (Summit) HSD 305 1,023.96 25.54 14,433.27

Sub-total 1,023.96 14,433.27

CO2 Emmission (ton) 989,641

Rental & SIPP

23 Bogra Rental (GBB) Gas 22 173.50 31.62 1,975.33

24 Kumargaon (Energy Prima) Gas 50 266.00 34.25 2,795.91

25 Sahzibazar RPP (Sahzibazar P) Gas 86 402.95 27.25 5,323.38

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26 Sahzibazar RPP (Energy Prima) Gas 50 144.38 28.41 1,829.52

27 Tangail SIPP (22MW) Gas 22 139.61 38.26 1,313.63

28 Feni SIPP (22 MW) Gas 22 152.37 38.26 1,433.70

29 Kumargao 10 MW (Desh Energy) Gas 10 55.24 43.05 461.94

30 Barabkundu Gas 22 127.33 38.26 1,198.09

31 Bhola RPP (34.5 MW) Gas 33 88.24 28.49 1,115.00

32 Jangalia, Comilla (33 MW) Gas 33 194.55 38.23 1,832.02

33 Fenchganj 51 MW RPP Gas 51 281.85 37.91 2,676.50

34 Ashgonj 55 MW (PE) Gas 55 234.12 32.5 2,593.33

35 Fenchganj 50 MW (EP) Gas 44 271.04 31.28 3,119.39

36 Ghorashal 100 MW RPP Gas 100 659.69 35.96 6,604.24

37 B. Baria 70 MW QRPP Gas 85 436.45 35.96 4,369.35

38 Ghorashal 78 MW QRPP (MP) Gas 78 441.30 35.85 4,431.46

39 Ashganj 80 MW QRPP Gas 0 180.23 35.96 1,804.30

40 Ashganji 53 MW QEPP Gas 53 183.03 36.31 1,814.67

41 Bogra RPP (EP) Gas 10 63.20 34.25 664.29

Sub-total 4495.08 47,356.06

CO2 Emmission (ton) 2,344,125

42 Shikalbaha 55 MW RPP HFO 51 229.54 43.00 1,921.73

43 Madangonj 100 MW QRPP HFO 100 463.06 41.79 3,989.03

44 khulna 115 MW QRPP HFO 115 517.53 40.15 4,640.37

45 Naopara 40 MW QRPP HFO 40 194.57 41.11 1,703.85

46 Megnaghat 100 MW QRPP HFO 100 369.32 41.29 3,220.03

47 Siddhirganj 100 Mw QRPP HFO 100 464.82 41.29 4,052.68

48 Amunura 50MW QRPP HFO 50 224.37 41.79 1,932.84

49 Keranigonj 100 MW QRPP HFO 100 332.01 40.98 2,916.63

50 Julda 100 MW QRPP HFO 100 605.93 43.22 5,047.08

51 Katakhari 50 MW QRPP HFO 50 186.42 41.29 1,625.36

Sub-total 3,587.57 31,049.60

CO2 Emmission (ton) 2,220,047

52 Thakurgaon 50 MW RPP HSD 0 29.94 36.69 293.77

52 Ghorashal 45 MW RPP HSD 45 336.96 35.96 3,373.35

54 khulna 115 MW QRPP HSD 55 78.09 32.5 865.00

55 Pagla 50 MW (DPA) HSD 50 83.71 38.33 786.21

56 Siddhirganj 100 MW QRPP HSD 100 160.39 39.24 1,471.47

Sub-total 689.09 6,789.80

CO2 Emmission (ton) 465,554

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Total Private Sector CO2 Emmission (ton) 23,890 12,945,626

GWh 542 (gr/kWh)

[Source：BPDB Annual Report]

Table 8.1-3 Plant Wise Generation Calculation Result Total Annual Generation (GWh): 48,552.06 CO2 Generation (ton): 26,684,192 Average CO2 Reduction per kWh 550 [Source：BPDB Annual Report]

8.1.1 Calculation Method Table 8.1-1~Table 8.1-3lists the fuel, rated output, annual energy production, thermal efficiency, and annual fuel usage of each power plant. The amount of CO2 generated by all the thermal power stations is calculated on the basis of the data. The calculation was made in accordance with "Guidelines for Calculating Total Amount of Greenhouse Gas Emissions Ver. 1.0 2017 March" issued by the Ministry of the Environment, Japan. In the calculation, the following equivalent carbon emission factors were used in accordance with the Guidelines.

◼ Natural gas: 13.5 ton-C/TJ(Tera Joule) ◼ Light oil: 18.7

◼ Heavy oil: 19.5

◼ Coal: 24.7

The calculation is made as follows: "Amount of generated CO2 (tons) = Fuel usage (TJ)  Carbon equivalent emission factor (ton-C/TJ)  44/12."

The following Table 8.1.1-1 lists the generated energy and the amount of CO2 emissions as calculated results corresponding to each fuel type in each sector. The FY2016/17 gross generation of thermal power generation in Bangladesh was 48,552.06 GWh, and the total fuel consumption reached 28,018,958 TJ. The annual amount of CO2 emissions was 26,684,192 tons, and the amount of CO2 emissions per unit power generation was calculated to be 550 gr/kWh. The CO2 reduction is calculated by using this data as a baseline.

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Table 8.1.1-1 Calculation of CO2 Baseline Generating Fuel CO2 CO2 Type of Power Station Fuel Power Consumption Emission Emission （GWh） (TJ) (ton) (gr/kWh) 1 Public Sector (1) Gas Thermal Gas 21,050.37 214,666.29 10,625,981 (2) Heavy Fuel Oil Thermal HFO 1,393.05 12,839.50 918,024 (3) Light Fuel Oil/Diesel LFO 1,210.08 12,216.15 837,621 (4) Coal Thermal Coal 1,008.84 14,982.77 1,356,940 Sub-total 24,662.34 254,704.71 13,738,566 557 gr/kWh 2 Private Seector IPP (1) Gas Thermal Gas 9,956.70 89,215.04 4,416,145 (2) Heavy Fuel Oil Thermal HFO 4,137.32 35,106.51 2,510,115 (3) Light Fuel oil/Diesel LFO 1,023.96 14,433.27 989,641 Rental & SIPP (1) Gas Thermal Gas 4,495.08 47,356.06 2,344,125 (2) Heavy Fuel Oil Thermal HFO 3,587.57 31,049.60 2,220,047 (3) Light Fuel Oil/Diesel LFO 689.09 6,789.80 465,554 Subtotal 23,890.00 223,950.28 12,945,626 542 gr/kWh Total 48,552.34 478,654.99 26,684,192 550 gr/kWh

8.1.2 How to Determine the Baseline and Method for Calculating the CO2 Reduction Effect

As a baseline of the amount of CO2 emissions from each power station, the average of the actual amount of CO2 emissions (gr/kWh) for the last three years is generally used. However, this data is not found in the environment-related data in Bangladesh. In this FS study, accordingly, the average amount of CO2 emissions, 550 gr/kWh, is used as a baseline. As described in Section 8.1.1, this value was calculated on the basis of the FY2016/17 "BPDB Annual Report" data listed in Table 8.1-3.

In addition, the CO2 emission factor (gr/kWh) was calculated for each project case. Table 8.1.2-1 lists the calculation results.

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Table 8.1.2-1 Calculation of Annual CO2 Reduction Siddhirganj Items Fen PS Gazaria PS PS 1 Power Station Rated Output (kW) [Site Rating・New & Clean] 664,000 1,320,000 1,320,000 2 Averaged Output Degradation (2%) 650,720 1,293,600 1,293,600 3 Power Station Heat Rate (kJ/kWh) [Site Rating・New & Clean] 5,725 5,760 5,760 4 Averaged Heat Rate Degradation (1.5%) 5,811 5,846 5,846 5 Averaged CO2 Emission at Generator Terminals (gr/kWh) 288 289 289 Annual Generation (kWh) [Availavility 91.0％、Load factor 8,765,252,49 8,765,252,49 6 4,409,187,619 85.0％] 6 6 7 Annual CO2 Reduction (ton/year) [Base 550 gr/kWh] 1,156,802 2,284,253 2,284,253 8 Total 3 sites Annual CO2 Reduction (ton/year) 5,725,308

Table 8.1.2-1 shows that the CO2 emission factor at the generating end of each power station is reduced to approximately 52% of the baseline (average emission factor) as follows. ◼ Baseline: 550 gr/kWh (100%)

◼ Siddhirganj PS: 288 gr/kWh (52.4%)

◼ Feni PS: 289 gr/kWh (52.5%)

◼ Gazaria PS: 289 gr/kWh (52.5%)

Table 8.1.2-1 shows that the CO2 emission reduction at each power station calculated on the basis of expected generated energy is as follows. ◼ Siddhirganj PS: 1,156,802 ton/year

◼ Feni PS: 2,284,253 ton/year

◼ Gazaria PS: 2,284,253 ton/year

◼ Total for the three sites: 5,725,308 ton/year

8.2 Examination and Evaluation of CO2 Emission Reduction by the Project In the project cases, the heat rate is reduced to almost half the average heat rate of the baseline by adopting high-efficiency GTCC. Significant reduction of carbon dioxide is expected from the adoption of GTCC. In this project, five blocks of most-advanced 600-MW class GTCC will be constructed in three sites, and an annual CO2 emission reduction of approximately 5720000 tons is expected from the construction. On the assumption that CO2 reduction value is USD 20.00 /ton-CO2, the annual expected value reaches USD 114.4 million. 8.3 Summary

As shown in Table 8.1.1-1, the annual amount of CO2 emissions in Bangladesh reached 26.7 million tons in

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FY2016/17. This project will reduce CO2 emissions by approximately 20% of the total amount of CO2 emissions. It is therefore a very important project from an environmental perspective as well.

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Chapter 9 Study of Fuel Procurement

Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 9 Study of Fuel ProcurementStudy of Fuel Procurement

9.1 Supply of LNG 9.1.1 Production of Natural Gas and LNG Natural gas is flammable gas whose principle component is methane (CH4). As compared with other fossil fuels (oil and coal), it is a clean energy source with less emissions of carbon dioxide (CO2), nitrogen oxides (NOx), and sulfur oxides (SOx). Natural gas is lighter than air, diffusing up in the air rather than staying close to the ground, so that it is less likely to cause explosions and other accidents. From this fact combined with the fact that it does not contain carbon monoxide or other toxic substances, it is regarded as a highly safe fuel as compared with oil, coal, and other fossil fuels.

Figure 9.1.1-1 CO2 Emission by Natural gas, Oil and Coal [Source：the Agency of Natural Resources and Energy（Energy White Paper）]

The proven reserves of natural gas in the world are 186.6 trillion (m3) according to the document below. According to an estimate based on the existing technology and the present price, the reserve-production ratio is said to be 52.5 years. By region, the Middle East accounts for 42.5% of the total (a single country, Iran, accounting for 18% of the world total), Russia 17.3%, Europe and the former Soviet Union excluding Russia 13.1%, Africa 7.6%, the Asia-Pacific region 9.4%, the United States of America 4.7%, North America excluding the United States 1.3%, and Central and South America 4.1%.

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Russia

1.3%4.1% 4.7% 17.3% Europe and Former Soviet Union Except Russia 9.4% Middle East

Africa 186.6 Trillion m3 7.6% 13.1% Reserve-to- Asia Ocean Pacific production ratio 52.5 Years United State

North America except US

42.5% South America

Figure 9.1.1-2 The proven reserves of natural gas in the world [Source：British Petroleum（BP）]

As shown in Figure 9.1.1-2, the regional uneven distribution of natural gas is lower than those of other energy resources. The reserves are expected to increase in the future due to the active development of non- conventional natural gases, exemplified by the shale gas revolution in the United States.

Next, changes in natural gas production are shown in Figure 9.1.1-3. On the whole, production is on the rise year by year with an average annual growth rate of 2.5%. At the end of 2016, production stood at about 3.55 trillion m3. By region, North America accounts for about 26% of world production, Europe, Russia, and the former Soviet Union countries about 29%, the Middle East about 18%, the Asia-Pacific region about 16%, Africa about 6%, and Central and South America about 5%.

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4000

3500

） 3000 Total Asia Pacific 2500 Total Africa 2000 Total Middle East Total CIS 1500 Total Europe Billion cubic metres 1000

（ Total S. & Cent. America

500 Total North America Amount Amount Natural of Production Gas 0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Year

Figure 9.1.1-3 Natural Gas Production Change in 2017 [Source：BP]

The production of natural gas in each country in 2017 is as shown below. The United States has the world's largest production of natural gas, accounting for about 20% of the total. Considering the further gas production from shale gas, the world market share of the country is expected to continue to increase. The world total production of natural gas in 2017 stood at about 3,680 Billion Cubic Metre (abbreviated to Bcm in the remainder of this document). According to BP, gas demand is expected to increase stably. From this fact combined with the fact that natural gas is inexpensive than other energy resources, natural gas production is considered to increase in the future.

800 US, 734.5 700 Russian Federation, 635.6

） 600 Iran, 223.9 Canada, 176.3 500 Qatar, 175.7 China, 149.2 400 Norway, 123.2 300 Australia, 113.5 Saudi Arabia,

Billion Cubic Cubic Metre Billion 200 111.4 （ Algeria, 91.2

100 Amountof Natural Gas Production

Figure 9.1.1-4 The production of natural gas in each country in 2017） [Source： BP]

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Next, LNG exports are shown below. Qatar ranks first in the world in the transport and supply of LNG, accounting for about 26% of total LNG exports, followed by Australia with 19%. At present, an FSRU with a capacity of about 5.2 Bcm/year operates in Bangladesh, importing LNG from Qatar.

120.00 103.40 100.00

80.00 75.90 ）

57.20 /Year 60.00

Bcm 38.90 （ 40.00

Amountof LNG Export 21.70 17.40 19.10 16.60 20.00 13.40 15.50 5.80 5.80 1.00 0.00

Figure 9.1.1-5 Amount of LNG exports in each country in 2017 [Source： BP]

The BP Outlook has reported that from the facts that the economic growth of the least developed countries and poor countries, as well as the global power demand (particularly in Asia and African countries), is expected to increase and that China, which is a large coal consumer, will shift its main resource from coal to natural gas, those regions that can supply gas at relative low price, such as North America and the Middle East, will expand exports. LNG exports are considered to increase by 40% for the next five years, and are anticipated to serve as a platform supporting economic growth.

9.1.2 Trends in the Major Producers The following describes the trends in the United States, Qatar, and Australia, which are assumed to rank high in LNG exports in the future among the major producers of natural gas mentioned above.

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Figure 9.1.2-1 Amount of LNG Exports in each country in 2017 [Source：BP]

(1) Trends in the United States As mentioned above, the United States has had the world's large production of natural gas since 2016, with the major producing states being Texas, Pennsylvania, and Louisiana, and its production is on the increase year by year. From its historical background, in which Saudi Arabia, Russia, and other oil and natural gas producing countries had a competitive advantage, the United States has regarded the development of technologies for natural gas in the country as one of its top-priority issues in an attempt to increase its energy self-sufficiency rate. Accordingly, the country has promoted the development of technologies for recovering non-conventional natural gases, such as shale gas and Coal Bed Methane, the reserves of which have recently been confirmed to be bountiful in the United States. In 2016, the first shipment of natural gas derived from shale gas (LNG) was made to Brazil and in the same year, shipment to Japan was started. Thus, LNG exports have started on a full scale. It was previously believed that non-conventional natural gases were difficult to commercialize because of their high production cost. With recent advances in technology development and the injection of funds for this, combined with the fact that the country hammered out deregulation policies to boost production, the break-even point of shale gas has gone below those of conventional natural gases, making it possible to supply gas at low price. At present, there are already over ten natural gas liquefaction projects planned in the United States, with development being active mainly in states in the South, such as Texas and Louisiana. Table 9.1.2-1 lists the typical LNG projects planned in the United States. Figure 9.1.2-2 shows the positions of the natural gas liquefaction projects for which proposals have been submitted to the US Federal Energy Regulatory Commission.

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Table 9.1.2-1 LNG projects List in the United States Expected Capacity Project Commercial Plant Site （Bcm/Year） Operation Date 1 Gulf LNG Liquefaction 15.5 2020 Mississippi 2 Venture Global Calcasieu Pass 14.6 2022 Louisiana 3 Texas LNG Brownsville 5.7 2022 Texas 4 Rio Grande LNG 37.2 2020 Texas 5 Annova LNG Brownsville 9.3 2019 Texas 6 Port Arthur LNG 19.2 2021 Texas 7 Eagle LNG Partners 1.4 2018 Florida 8 Venture Global LNG 35.1 2022 Louisiana 9 Driftwood LNG 41.3 2023 Louisiana 10 Freeport LNG Dev 7.4 2018 Texas 11 Jordan Cove 11.2 2024 Oregon 12 Corpus Christi LNG 19.2 2022 Texas [Source：U.S. Department of Energy Study Team]

Figure 9.1.2-2 the positions of the natural gas liquefaction projects in United States [Source：Google Earth touched by Study Team]

As of 2015, the exports of LNG from the United States stood at 1.03 Bcm/year, and the country is said to plan to export LNG at 61.5 Bcm/year in 2020, 157.8 Bcm/year in 2030, and 203 Bcm/year in 2040, which is

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expected to increase its world market share to about 26%. Accordingly, the United States has a potential to become the world's largest LNG exporter. For the natural gas and LNG pricing system, Europe and Asia adopt the oil price linkage system, in which the prices are linked to petroleum product price fluctuations, whereas the United States, which basically meets demand with its natural gas without relying on imports and has an advanced pipeline network, adopts the Henry Hub price system to ensure liquidity in the market (the Henry Hub is a gas pipeline hub located in Louisiana, USA, and the Henry Hub price refers to the price of natural gas traded there. Because of the large amount traded there, the price serves as the price of natural gas futures in the United States), so that the gas price, volume, and date can be determined between seller and buyer. Because the system has a low linkage to the oil price, the natural gas price in the United States continues to decrease from the impact of the shale gas revolution. In recent years, the influence of the Henry Hub price on the natural gas market has increased. In Europe and Asia, which have adopted the oil price linkage system, the oil price fluctuation range has recently been expanded and, in addition, the imports of LNG produced in the United States have been started. For this and other reasons, pricing systems based on the Henry Hub price have been becoming mainstream worldwide. Thus, the natural gas and LNG market structure is going through great change due to LNG production increase and exports in North America, and the liquidity in LNG transactions is anticipated to increase.

(2) Trends in Qatar Among the recent trends in Qatar are the announcement of its withdrawal from OPEC in January 2019 in an attempt to concentrate on the production of natural gas that will contribute to the long-term policy of the country and the establishment of a system for focusing on further production increase in natural gas while ensuring a departure from dependence on oil. In the country, the North Field gas field development project was started in around 1991 in an area of about 6,000 km2 mainly in the north of the country, under support from Bechtel in the United States. At present, Qatar's LNG exports have been the world's largest since 2006, and as described above, Qatar has been a big exporter that accounts for about 26% of the world total LNG exports. Besides, Qatar ranks fourth in natural gas production after the United States, Russia, and Iran. For this reason, the country is recognized worldwide as having a great deal of resources, as well as know-how and knowledge for enabling large-scale transport. Thus far, the mainstream type of LNG export contracts in Qatar has been long-term contract adopting the oil price linkage system, but for these several years, there has been a shift to short-term and spot contracts. Short-term contracts and spot contracts together account for about 25% of the LNG exported as of 2012. Qatargas (state-owned company producing natural gas) has also started short-term contracts adopting the continental Europe price, and it is considered that further diversification of contract types will be promoted in the future. The following shows the LNG exports to each export destination, as well as future LNG export forecasts in Qatar.

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Amount Amount of Natural Gas(Bcm/Year) 2

Figure 9.1.2-3The LNG exports to each export destination by Qatar [Source：International Energy Agency （IEA） Natural Gas Information]

Figure 9.1.2-4 Gas Field (South Pars and North Field) [Source：Google Earth Study Team]

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100

80 ）

60 /year

Bcm 40 （

Amountof LNG Export 20

0 2017 2018 2019 2020 2021 2022 2023 Year

Figure 9.1.2-5 Amount of LNG Export Forecast in Qatar [Source：BP, IEA Natural Gas Information Study Team]

The present largest importers of LNG from Qatar are Asian countries such as Korea, Japan, and India. According to an IEA report, although in recent years, the policy guideline of the Qatari government has been to place emphasis on exports to neighboring United Arab Emirates and Oman, using gas pipelines, it is forecast that as of 2023, Qatar will rank first in LNG exports over the United States and Australia. As shown in Figure 9.1.2-5, there are hardly any changes in LNG exports, but this is due to the fact that the development of the gas field located in the north of the country was suspended. In recent years, however, the Qatari government has shown interest in the development of LNG plants capable of exporting LNG at about 30 Bcm/year. The commercial operation of the plants is expected to start at around the end of 2023. If the development of these LNG plants is progressed, it is anticipated that the volume to supply to Asian countries will increase, and with the completion of the construction of gas pipelines, it is anticipated that exports will be expanded to the Middle East and Africa, including Jordan and Egypt.

(3) Trends in Australia LNG exports in Australia have increased at an average rate of about 18.0% every year since 2011. The country ranks second in the world after Qatar in LNG exports in 2017, exporting at about 76 Bcm/year. Although the natural gas production in Australia in 2000 stood at about 3.4 Bcm/year, it increased sharply due to the natural gas development off the west coast of the country and increasing domestic demand. The production has increased by a factor of about 1.8 in ten years. As indicated in Table 9.1.2-2, LNG exports have also increased remarkably in recent years.

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Table 9.1.2-2 LNG projects List in the Australia

Capacity Commercial Name Location (Bcm/Year) Date

1 North West Shelf West 22.2 1989 2 DarwinLNG LNG North 5.0 2006 3 Pluto LNG West 5.9 2012 4 Queensland East 11.6 2014 5 CurtisGLNG LNG East 10.6 2015 6 Australia Pacific East 12.2 2015 7 GorgonLNG LNG West 21.2 2016 8 Wheatstone LNG West 6.1 2017 9 Ichthys LNG North 12.1 2018* 10 Prelude FLNG West 4.9 2018* [Source：Geopolitical Intelligence Services Study Team]

Figure 9.1.2-6 LNG Project List in Australia [Source：Google Earth Study Team]

Thus far, the mainstream type of LNG export contracts in Australia has been long-term purchasing contract with the oil price linkage system. Exports to the Asia-Pacific region, including Japan, China, Korea, and Taiwan, are active. Figure 9.1.2-7shows the LNG exports of Australia to each country, and Figure 9.1.2-8 shows changes in LNG exports in the country.

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15 (Bcm/Year) 10

Amount of Natural Gas Natural of Amount 5

Figure 9.1.2-7 The LNG exports to each export destination by Australia in 2016 [Source：IEA Natural gas information 2018]

140

120

100 ）

80 /Year

Bcm （

40 Amountof LNG Export 20

0 2014 2015 2020 2025 2030 2035

Figure 9.1.2-8 Amount of LNG Export Forecast in Australia [Source：BP]

Whereas exports to the Asian region are planned to be reinforced with new LNG developments and the stable supply of LNG in the United States and Qatar, as described above, exports to the Asia-Pacific region are reinforced in Australia as well, based on 20-year long-term contracts, with the LNG exports in 2023 being expected to be about 107 Bcm/year. This is expected to place the country in third place in the world after Qatar and the United States. These three top countries together are expected to account for about 60% of world LNG exports. It is therefore necessary to continue to pay close attention to the future efforts of the

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country toward LNG as well as the efforts of the two countries mentioned above.

9.2 LNG Demand 9.2.1 Natural Gas and LNG Demand Natural gas demand in 2017 increased by about 3% from that in 2016. For the past several years, the demand growth rate has been about 1.5% on average. Thus far, North America, Europe, and Russia have accounted for the majority of world natural gas demand, but in recent years, the demand in Asian countries has been remarkable due to economic growth and population increase. Figure 9.2.1-1 shows changes in natural gas consumption in each region.

4000

3500 ）

3000

/Year Asia Pacific

2500 Africa Bcm

（ 2000 Middle East

1500 CIS Europe 1000

S. & Cent. America Amountof Natrural Gas

Consumption 500 North America 0 1990 1995 2000 2005 2010 2016 Year

Figure 9.2.1-1 Changes in Natural Gas Consumption in Each Region [Source：BP]

As described above, natural gas consumption is the highest in North America, followed by Russia, Europe, Asia, the Middle East, Central and South America, and Africa. It can be seen from Figure 9.2.1-1 that the demand growth in the Asian region is high. The cause of such demand expansion is considered to be the tightening of environmental regulation by China. In China, power generation methods using coal as a main fuel have so far accounted for the majority of the power generation mix. In recent years, however, the country aims to shift from coal to natural gas as a measure to lesson environmental pollution, and is proceeding with the development of LNG receiving terminals and the establishment of FSRUs, which have short construction periods and are capable to accommodating sudden gas demand increases, at a rapid pace.

9.2.2 Demand Trends in the Major Countries The LNG demand and the LNG demand forecast in each of the major countries are shown in Figure 9.2.2-1 and Figure 9.2.2-2, respectively. It can be seen from the figures that countries in the Asia-Pacific region rank high in LNG exports.

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140

120

100

60 (Bcm/Year) 40

Amountof LNG Import 20

Figure 9.2.2-1 The LNG demand in each of the major countries [Source：IEA Natural Gas Information 2018]

600

500

Africa 400 Middle East Latin America

300 North America

China (Bcm/year) Other Asia 200

Europe Amountof LNG Import Japan and Korea 100

0 2010 2017 2023

Figure 9.2.2-2 The LNG demand forecast in Divisional Region [Source：IEA Natural Gas Information 2018]

The LNG demand forecasts indicate that the increase rate is high in China and Asian countries except

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China, Korea, and Japan. These countries account for about 90% of the total demand growth rate. This is considered due to the fact that China is attempting to convert from coal-derived power generation methods to natural gas-derived ones, as described above. Such LNG demand increases require the development of LNG export terminals and gas fields by natural gas-producing countries. It is expected that the above- mentioned three major countries (United States, Qatar, and Australia) will lead the market as big LNG exporters for Asia in the future.

9.3 LNG Supply-Demand Trends 9.3.1 Current LNG Supply-Demand Trends (1) LNG supply side As of 2017, the LNG supply is about 393 Bcm/year (about 0.3 billion t/year). As for LNG supply capacity, Qatar continues to maintain stable, high supply capacity, as described above. In addition, the development of export LNG terminals has been expanded mainly in Australia and the United States, and in 2017, natural gas liquefaction projects with a capacity of about 25 million t/year have started commercial operation. These projects are being developed according to the demand expansion forecasts in those Asian countries with remarkable economic growth, such as India, Pakistan, and Bangladesh, in addition to China, which has a policy to increase the ratio of natural gas in its power generation mix. The current LNG supply-demand situation is described as oversupply. This is due to the fact that the gas demand growth rate in China has been at a level lower than that previously forecast. It is pointed out that over the period of 2019 to 2020 in the future, the gas supply-demand gap can result in an oversupply of 60 million tons/year. On the other hand, it is forecast that the demand in the Middle East, in addition to Asian countries, will continue to increase, so that medium- to long-term LNG development is necessary. There is a good likelihood that in and after 2023, undersupply can occur. LNG projects that will start commercial operation in and after 2018 are planned in not only in the United States and Australia, as described above, but also Cameroon, Indonesia, Russia, Malaysia, and Mozambique (see Figure 9.3.1-1), and the supply capacity is expected to reach 88 million tons/year in total. It is considered that if the development of these and other projects is carried out on the assumption of the ensuring of further demand, demand increases can be accommodated sufficiently. It is therefore considered necessary to determine the right time for development investment in the future while paying attention to the gas demand all over the world, particularly the trends in those Asian countries with remarkable economic growth.

Table 9.3.1-1 LNG Project under Construction（Excluded United State and Australia） Expected Capacity Name Country Commercial Date （Ten Thousand Ton/Year） Cameroon FLNG Cameroon 2018 120 Senkang Indonesia 2018 200 Yamal LNG Russia 2018 1,100 Petronas FLNG 2 Malaysia 2020 150 Tangguh Indonesia 2020 380

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Coral FLNG Mozambique 2022 340 [Source：IEA, Japan Oil, Gas and Metals National Corporation（JOGMEC）]

As a summary of the above explanations, Figure 9.3.1-1 shows changes in natural gas production in each region. It is forecast that in almost all countries, natural gas production will increase considerably from the 2016 level according to demand. As described above, the natural gas production growth rate in North America is the highest, which is considered to be largely due to the shale gas revolution. It is anticipated that in the Middle East, mainly in Qatar, LNG exports will increase in the long term, although in Iran, the progress of natural gas development projects may be delayed because of the impact of the recent economic sanctions from the United States.

1600 1400 1200 1000

） 800 600

400 2016 Bcm/Year 2040 （ 200

0 Amountof Natural Gas Production

Figure 9.3.1-1 Natural Gas Production Forecast in in divisional Region [Source：BP]

Next, LNG export forecasts are shown in Figure 9.3.1-2. If the LNG projects for which the final investment has already been decided and those that are considered as development plans proceed uneventfully, the LNG supply capacity of Australia will increase in 2040 by a factor of about 2.5 from the 2016 level (3.9→12.8 Bcf/day). In the United States, the capacity is expected to increase by a factor of about 200 (0.1→19.8 Bcf/day).

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900

800

） 700

600 Others Australia 500

Africa Natural Natural Gas

of 400 Middle East

300 Russia

N America Amount

Billion Cubic BillionCubic Feet day per 200 （ 100

0 2010 2015 2020 2025 2030 2035 2040

Figure 9.3.1-2 Long Term LNG Export Forecast [Source：BP]

As for long-term LNG supply, countries in the Middle East, particularly Qatar, have previously been main LNG suppliers, but it is expected that the United States, in which the development of new LNG projects is remarkable due to increasing recoverable reserves of natural gas due to shale gas, will rank first in the world in LNG exports in the future. It is forecast that the Middle East and Australia will follow, ranking second and third in the world, respectively. It is considered that in Mozambique, Senegal, Tanzania, and other African countries and Argentina and other South American countries, these countries will also play an important role as gas suppliers, promoting diversity. On the other hand, it is considered that exports of LNG from Southeast Asia will decrease in and after 2025 and the countries will become net LNG importers in around 2040, dependent on imports mainly from Australia and the Middle and Near East. While LNG projects are progressing all over the world, as noted above, securing materials and equipment, as well as personnel, is considered to be a constraining factor in advancing these projects smoothly. While the power generation fuel is being shifted from coal to natural gas due to the global power generation mix conversion and the number of natural gas development projects is increasing sharply, it is considered to become an issue whether drilling rigs can be secured and whether the materials and equipment for the construction of production facilities, as well as personnel knowledgeable about development, can be secured. The higher the difficulty of development, the bigger the constraining factors and the more difficult the procurement. Thus, it is desired to continue to pay attention to the factors.

(2) LNG demand side As for LNG demand trends, it is considered that the increase in demand will be remarkable in Asian countries, particularly China. It is expected that in 2023, the demand will increase to 505 Bcm/year, increasing by about 30% from the 2017 level. Figure 9.3.1-3 shows the LNG demand forecast of each region of the world (IEA survey).

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900

800

700 Others 600 ） Europe 500

/Year OECD Asia

400 China Bcm

（ 300 India

200 Other Emerging Asia Amountof Natural Gas

100

0 2010 2015 2020 2025 2030 2035 2040

Figure 9.3.1-3 Long Term LNG Demand Forecast in The World [Source：IEA]

From Figure 9.3.1-3, the increase in demand is larger in emerging Asian countries with remarkable economic growth, such as China and India, than in other countries, and it is expected that the entire Asian region will account for about 70% of world LNG exports in 2040. It is considered that Asia will become the heart of the LNG market in the future. At present, Japan ranks first in the world in LNG imports, but in 2030, China is assumed to mark imports more than double the current amounts and is forecast to rank first in the world over Japan. Meanwhile, the domestic demand is considered to decrease in developed Asian countries such as Japan and Korea. Similarly, in India, where the population increase is remarkable, the production of domestic natural gas cannot be anticipated, but imports are forecast to increase, and it is considered that in 2023, imports will be increased by a factor of at least about two from the 2013 level. It is also expected that the LNG demand will also increase in emerging countries such as Bangladesh and Pakistan.

9.3.2 Long-Term LNG Supply-Demand Trends This section discusses natural gas and LNG supply-demand trends on a long-term basis and in a comprehensive manner. Figure 9.3.2-1 shows a global long-term LNG supply-demand balance.

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■Capacity (Under Planning (Before FID))

■Capacity (Under Construction Capacity)

■Capacity (Working)

■Expected Supply (Availability 90%)

■Expected Demand

■Demand and

Supply Gap

Figure 9.3.2-1 LNG Supply and Demand Forecast in The World [Source：JOGMEC]

IEA and Bloomberg examine global long-term LNG demand forecasts, as well as demand trends in Asian countries, such as China and India, and African countries, in which the demand growth is forecast to be remarkable. As a result of checking the views of the two companies with Figure 9.3.2 1, LNG supply will surpass demand to create an oversupply situation as of 2020, and this is presumed to be due to the fact that the United States and Australia have invested aggressively in natural gas liquefaction projects in an effort to accommodate increases in demand in emerging Asian countries, particularly the sharp increase in China, as described above. Almost all liquefaction projects that are currently under way or for which a Final Investment Decision (FID) has already been made are expected to start commercial operation by 2024. It is forecast that as long as these projects progress smoothly, the countries will have sufficient supply capacity to accommodate demand at the beginning of 2020. As of 2018, LNG demand stands at about 250 million tons. It is considered that demand will continue to increase at an annual average rate of about 4 to 5% for the next ten years or so, and it is expected that in 2030, annual LNG demand will increase to about 500 million tons. It is therefore considered necessary to continue to invest in ongoing natural gas liquefaction projects, and it is considered vital to proceed with the development of projects in not only the United States and Australia but also the rest of the world. Qatar, which ranks first in the world in LNG exports, studies the expansion of the North Field gas field in and after 2023, seeking ways to increase the supply capacity to 110 million tons. In Tanzania, new investments have started to accommodate medium- to long-term demand increases. For example, a liquefaction project boasting of a supply capacity of about 20 million tons is planned (due to start commercial operation in 2026 to 2027). Nevertheless, even if new investments are canceled or an FID is made, there is a good likelihood that terminal operation may be stopped due to construction delays and supply faults. Thus, it can be assumed that in the medium and short term, the supply-demand situation may change to LNG undersupply. In addition, because it usually takes about five years from an FID to the start of commercial operation, potential tight

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supply-demand situation due to lead time is assumed to occur, and because of this, there are concerns about the soaring of spot prices. As for the development of new projects, it will be necessary to continue to pay attention to the trends, including the trends of those projects that are under construction.

9.3.3 Gas Supply-Demand Situation in Bangladesh 9.3.3.1 Gas Managing Companies

In Bangladesh, Petrobangla, which is under the umbrella of the Ministry of Power, Energy and Mineral Resources (MoPEMR), manages all operations relating to gas in the up, middle, and down streams, such as ①resource development, ②transport, ③supply, ④compressed natural gas and liquefied natural gas, and ⑤drilling, and the companies listed below manage operations as subsidiaries of Petrobangla.

Table 9.3.3.1-1 Demarcation of Gas Company in Bangladesh Item Company Name ① Resource Develoment BAPEX, BGFCL, SGFL ② Transport GTCL ③ Distribution TGTDCL, BGDCL, JGTDSL, PGCL, KGDCL, SGCL ④ Compressed Natural Gas and LNG RPGCL ⑤ Drilling BCMCL, MGMCL [Source：Gas Sector Master Plan 2017 （GSMP2017）]

BAPEX: Bangladesh Petroleum Exploration and Production Company Limited BGFCL: Bangladesh Gas Fields Company Limited SGFL: Sylhet Gas Fields Limited GTCL: Gas Transmission Company Limited TGTDCL: Titas Gas Transmission and Distribution Company Limited BGDCL: Bakhrabad Gas Distribution Company Limited JGTDSL: Jalalabad Gas Transmission and Distribution System Limited PGCL: Pashchimanchal Gas Company Limited KGDCL: Karnaphuli Gas Distribution Company Limited SGCL: Sundarban Gas Company Limited RPGCL: Rupantarita Prakritik Gas Company Limited BCMCL: Barapukuria Coal Mining Company Limited MGMCL: Maddhapara Granite Mining Company Limited

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Figure 9.3.3.1-1 Distribution Company Map in Bangladesh [Source：GSMP2017]

9.3.3.2 Natural Gas Supply-Demand Situation in Bangladesh The gas resource supply-demand balance in Bangladesh is as shown below.

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9000

8000

7000 Gas Supply-Import(Mainly LNG) 6000 Gas Supply- Yet to Find

5000 Gas Supply Thin Bed and Accelerated E&P 4000 Gas Supply -Additional 3P

3000

Gas Amount Amount Gas (mmcfd) Gas Supply -Additional 2P 2000 Gas Supply- Existing Fields 1000 Total Gas Demand 0

Year

Figure 9.3.3.2-2 Gas Demand and Supply Forecast in Bangladesh-With Further Upstream Success [Source：GSMP2017]

At present, gas demand surpasses supply due to the depletion of domestic natural gas resources, creating an undersupply situation, and it has become an urgent issue in the country to increase the natural gas supply capacity promptly. According to GSMP2017, it can be seen that, although the government of the country should make investment in domestic natural gas production and is anticipated to make appropriate gas field research in the future, it is indispensable to import LNG because the supply cannot meet the domestic huge gas demand even if the undiscovered areas shown in Figure 9.3.3.2-2 are included. For the undiscovered areas, suppliability is unclear at this moment, and it is clear that if no natural gas is produced from them, the country needs to rely entirely on imported LNG (or LNG imported from the neighboring India using a pipeline) in a planned manner. (Figure 9.3.3.2-3)

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9000

8000

7000 Gas Supply-Import(Mainly 6000 LNG) Gas Supply Thin Bed and 5000 Accelerated E&P Gas Supply -Additional 3P 4000 Gas Supply -Additional 2P

3000 Gas Amount Amount Gas (mmcfd)

2000 Gas Supply- Existing Fields

1000 Total Gas Demand

Year

Figure 9.3.3.2-3 Gas Demand and Supply Forecast in Bangladesh – Without Further Upstream Success [Source：GSMP2017]

9.4 LNG Import Plan in Bangladesh According to GSMP2017, the total capacity of the natural gas liquefaction plants in the world as of January 2017 is 340 MTPA (Million Tons Per Annum), and it is expected to increase by 114.6 MTPA in several years from now, but is anticipated to further increase due to the shale gas revolution in the United States and other factors. The World IGU Report forecasts that in the near future, the capacity will increase to 879 MTPA, and because the regasification capacity is close to 800 MTPA at the beginning of 2017, a sufficient capacity is already obtained. Accordingly, the global LNG turnover is on the rise, and in the period from 2015 to 2017, it has risen at an annual rate of about 5% (13.1 MT). This tendency is expected to continue in the future. As can be seen from the above, with the expansion of the global LNG market, the development of LNG terminals in Bangladesh has been active. According to GSMP2017, the country has a policy to promote the development of land LNG terminals and FSRUs in the Moheshakali, Kutubdia, and Bashkali areas in an effort to accommodate decreases in domestic natural gas production and increases in gas demand. The following lists the development projects proposed at this moment.

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Table 9.4-1 Project List of LNG Onshore Terminal in Bangladesh

No. Capacity（MMCFD） Location Expected Commercial Date Company

1 1000 Moheshkhali December, 2021 HQC

2 1000 Kutubdia December, 2021 Petronet

3 1000 Moheshkhali December, 2022 Sembcorp [Source：GSMP2017] Table 9.4-2 Project List of FSRU in Bangladesh No. Capacity（MMCFD） Location Expected Commercial Date Company Excelerate 1 500 Moheshkhali April, 2018 Energy Bangladesh Summit 2 500 Moheshkhali October, 2018 LNG Beximco 3 600-1000 Bashkali - and TUMAS [Source：GSMP2017]

Figure 9.4-1 Location of LNG Onshore Terminal and FSRU Candidate Area [Source：Google Earth touched by Study Team]

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9.5 Gas Pipeline 9.5.1 Construction Plant of Gas Pipeline in Bangladesh In order to accommodate for LNG Import Plan described at Clause 9.1, the gas pipeline network in Bangladesh planned by Gas Transmission Company Limited (GTCL) is shown in Figure 9.5.1-1.

Figure 9.5.1-1 Gas Pipeline Network in Bangladesh [Source: Study Team]

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9.5.2 Study for Each Candidate Power Station (1) Siddhirganj As per described at Chapter 4, the tap-off point of fuel gas supply for new GTCC is planned at 12 inch branch piping of existing RMS. The candidate route of gas pipeline between existing RMS and new GTCC is shown in Figure 9.5.2-1. The route of gas pipeline will be finalized during detail engineering stage. Since fuel gas supply pressure at outlet of RMS will be operated at 150 psig - 350 psig (1.03 MPag - 2.41 MPag) by GTCL, it is necessary to install gas booster compressor at new GTCC area in order to meet the requirement for fuel gas pressure (5.3 MPag) of gas turbine.

Legend: Red Line: Candidate Route of Gas Pipeline

Tap off Point of Fuel Gas Supply

Existing RMS

Figure 9.5.2-1 Candidate Route of Gas Pipeline at Siddhirganj [Source: Study Team]

(2) Feni As per described at Chapter 4, the tap-off point of fuel gas supply for new GTCC is planned at Chandpur Valve Station where is approx. 19 km away from new GTCC. The diameter of main gas pipeline connected to Chandpur Valve Station is planned 36 inch. The diameter of gas pipeline between Chandpur Valve Station and new GTCC is planned 20 inch since fuel gas consumption of new GTCC (2 units) will be approx. 180 MMCFD. The candidate route of gas pipeline between Chandpur Valve Station and new GTCC is shown in Figure Figure 9.5.2-2. The No. 1 candidate route avoided residential area is recommended though the route of gas pipeline will be finalized during detail engineering stage. Since fuel gas supply pressure at outlet of RMS will be operated at 150 psig - 350 psig (1.03 MPag- 2.41 MPag) by GTCL, it is necessary to install gas booster compressor and RMS at new GTCC area in order to meet the requirement for fuel gas pressure (5.3 MPag) of gas turbine.

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Legend: Green Line: No. 1 Candidate Route of Gas Pipeline Purple Line: No. 2 Candidate Route of Gas Pipeline

Tap off Point of Fuel Gas Supply (Chandpur)

Candidate Site for new GTCC

Figure 9.5.2-2 Candidate Route of Gas Pipeline at Feni [Source: Study Team]

(3) Gazaria As per described at Chapter 4, the tap-off point of fuel gas supply for new GTCC is planned at 20 inch branch piping of Srinagar Valve Station where is approx. 8 km away from new GTCC. The diameter of main gas pipeline connected to Srinagar Valve Station is planned 30 inch. The diameter of gas pipeline between Srinagar Valve Station and new GTCC is planned 20 inch branch piping since fuel gas consumption of new GTCC (2 units) will be approx. 180 MMCFD. The candidate route of gas pipeline between Srinagar Valve Station and new GTCC is shown in Figure 9.5.2-3. The No. 1 candidate route avoided residential area is recommended though the route of gas pipeline will be finalized during detail engineering stage. Since fuel gas supply pressure at outlet of RMS will be operated at 150 psig - 350 psig (1.03 MPag - 2.41 MPag) by GTCL, it is necessary to install gas booster compressor and RMS at new GTCC area in order to meet the requirement for fuel gas pressure (5.3 MPag) of gas turbine.

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Legend: Green Line: No. 1 Candidate Route of Gas Pipeline Purple Line: No. 2 Candidate Route of Gas Pipeline

Tap off Point of Fuel Gas Supply (Srinagar)

Candidate Site for new GTCC

Figure 9.5.2-3Candidate Route of Gas Pipeline at Gazaria [Source: Study Team]

9.6 LNG Price Trends 9.6.1 Current LNG Price The LNG pricing methods are divided into those for the United States, which is a principle natural gas- producing country; European countries, which import gas using gas pipelines or as LNG; and Northeast Asian countries, such as Korea and Japan, which import gas only as LNG. As described above, the United States has an advanced gas pipeline network, and adopts the market price based on the supply-demand balance of the country (Henry Hub price system). In continental Europe, on the other hand, due to the fact that LNG has been handled as a competing product for conventional oil-related products (such as kerosene and light oil), the system in which the natural gas price is determined in conjunction with the oil price (oil price linkage system) has been adopted. In recent years, in response to expanding gas trading markets and soaring oil prices, the introduction of the market price based on the supply-demand balance has been progressed. As of 2005, the oil price linkage system accounted for 78% of all gas trading markets, but in 2015, the percentage decreased to 30%, while the Henry Hub system increased from 15% to 64%. In Northeast Asia, the oil price linkage system is adopted. Constructing LNG production facilities and receiving terminals involves enormous costs, and besides, if the supply source is to be changed, a substitute is hard to find. Thus, when LNG production facilities are constructed, investment risks are reduced and stable supply is secured by concluding a long-term purchasing contract between supplier and consumer. For this reason, transactions between two parties (supplier and consumer) have been mainstream. This means that there is no concept of trading market, so that the LNG price has been determined by using the oil price as a reference index. In recent years, however, with the introduction of the market price associated with expanding natural gas markets, as described above, the number of spot price transactions not covered by long-term contracts is on the rise.

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The following shows changes in gas and LNG price in major countries in each category (United States, continental Europe, and Northeast Asia).

16 Japan LNG ） 14

12 Average German Import Price3 10

USD/MMBtu 8 （ Netherlands TTF 6

Gas Gas Price US 2

Figure 9.6.1-1 Changes in Gas and LNG Price in Major Countries [Source：BP]

It can be seen from Figure 9.6.1-1 that the gas/LNG price differs greatly between the United States, Europe, and Northeast Asia. In Northeast Asia and Europe, in which the natural gas/LNG price has been linked to the oil price, as described above, the natural gas/LNG price is on the rise due to soaring oil prices. In the 2000s, the price rose to about 12 USD/million British Thermal Unit (referred to as MMBtu in the remainder of this document). In the 2010s, due to the tight LNG supply-demand situation in the Asian markets, the price further soared in both Northeast Asia and Europe. In Japan, in particular, the sharp increase in gas demand associated with the shutdown of nuclear power plants due to the Great East Japan Earthquake, which occurred in 2011, is also a factor. Due to lower oil prices in and after 2015, the introduction of the spot price, and the LNG oversupply situation, the LNG price declined. In 2016, the price declined to 6.94 USD/MMBtu in Japan and to about 4.6 USD/MMBtu in Europe (Netherland and Germany). In 2017, due to an increase in gas demand associated with the cancelation of the construction of coal-fired power plants in China, the demand increase was higher than the conventional forecast, with the result that the natural gas/LNG price rose. The United States supplies the natural gas produced in the country throughout the country, using pipelines, and no liquefaction costs are incurred and the transport costs are lower than those for LNG. Thus, natural gas is less expensive than LNG, which can be seen from Figure 9.6.1-1. At present, the supply-demand balance is in an oversupply situation due to the further increase in supply capacity with projects for the development of non-conventional natural gases such as shale gas in recent years. Partly because of this, the natural gas price is on the decline.

9.6.2 Long-Term LNG Price Forecast In studying the LNG price, it is important to understand the current state of contract types.

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The following shows changes in long-term contracts and short-term/spot contracts.

Million Ton / Year

■Spot and Short-Term ■Total Deal ■ Spot and Short Term Ratio

Figure 9.6.2-1 Changes in Long-Term Contracts and Short-Term/Spot Contracts [Source：JOGMEC]

In 2015, total imports of LNG stood at about 245 million tons, and short-term/spot contracts accounted for 28% of the total. Considering how LNG markets originated, it is evident that long-term contracts are mainstream. It can be seen, however, that the percentage of short-term/spot contracts is on the rise due to the opening up of markets. In general, long-term contracts do not permit the changing of the LNG destination, but the number of contracts that permit the changing is on the rise due to the movement toward the natural gas market diversification in recent years, and retrading such as reselling is conducted. It is considered that such movements have led to the formation of the LNG market price, causing sharp increases in the percentage of LNG spot contracts. Meanwhile, in Japan, China, and Korea, which rank high in LNG imports, the ratio of spot contracts declines slightly. This is due to the fact that in response to the conversion from coal to natural gas for the purpose of the prevention of air pollution and the shutdown of nuclear power plants due to the accident at the Fukushima No. 1 nuclear power plant, there occurred additional demand for natural gas, which tightened the supply-demand situation, and to cope with this, LNG imports based on long-term contracts increased. Note, however, that the trading volume of spot/short-term contracts in units of several years was around 10% at the beginning of the 2000s, but at present, they have increased to about 30%. This tendency is considered to continue in the future. Based on the above, the LNG price is assumed to be as described below.

 The LNG production capacity is expected to increase considerably mainly in the United States and

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Australia. In Qatar, LNG exports are expected to continue to be stable. Note, however, that although there are a large number of LNG development plans to accommodate demand, undersupply may temporarily occur, considering the lead time from an FID to the start of operation.  The LNG price in Asia can be a reference index for the trading price in Japan, China, and Korea, where the import volume is large.  For the LNG price in Asia, the oil price linkage system has been mainstream due to the existing LNG industry structure, so that the price has been higher than the United States price. It is, however, assumed that due to the liquidity and diversity of the LNG market, the price will be influenced by the Henry Hub system in the United States and the spot price, and it is considered that in the long term, the price of LNG for Asia will decrease. It is, however, considered that the price difference due to LNG liquefaction costs and transport costs will still remain, and it is assumed that LNG transactions referring to oil will remain slightly. An LNG price trend forecast summarizing the above in a comprehensive manner is shown in Figure 9.6.2-2.

12 ）

10 /MMBtu

USD （

4 Natural Gas Price Gas Natural

0 2000 2010 2016 2025 2030 2035 2040 Year

Figure 9.6.2-2 Trend and Forecast of Natural Gas Price in main area and country [Source：IEA]

In Figure 9.6.2-2, the prices in and before 2016 are the real prices contained in World Energy Outlook 2017 of IEA (referred to as WEO 2017 in the remainder of this document), while the prices after 2016 are

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price forecasts based on WEO 2017. For the United States, Henry Hub prices are shown; for Japan, LNG prices at customs; and for Europe and China, prices with consideration given to pipelines and imported LNG. The LNG price forecast scenarios are largely divided into the Current Policies scenario (scenario that only considers the policies implemented by the countries as of 2017), the New Policies scenario (scenario that considers the INDC and other items of countries submitted at COP21, in addition to the policies already implemented), and the Sustainable Development scenario (scenario that keeps the average temperature rise as of 2100 to less than 2C from the average temperature before the Industrial Revolution). In the New Policies case, it is assumed that due to rising oil prices, the production of shale gas in the United States will increase, resulting in oversupply. It is, therefore, considered that in the middle of 2020, the United States price will decline, and it is assumed that in 2025, it will be around 3.7 USD/MMBtu. From a long-term perspective, the shale gas currently dug out is extracted from gas fields with a relatively low difficulty in accordance with existing technology, and it is considered that if attempts are made to dig from gas fields with a high difficulty in the future, the production cost will increase, so that the United States price will increase to 5.6 USD/MMBtu in 2040. In Europe and Northeast Asia (Japan and China) as well, it is forecast that LNG will remain at low prices so as to follow a natural gas oversupply situation. The LNG price in each region in 2035 is presumed to be 7.9 USD/MMBtu in Europe, 9.4 USD/MMBtu in China, and 10.3 USD/MMBtu in Japan. It is assumed that in 2040, due to diversifying markets, not only the oil price but also the Henry Hub price will be introduced, and it is therefore assumed that the price increase rate will slow down due to the discount effect of the hub price. It is presumed that the price will be 9.6 USD/MMBtu in Europe, 10.2 USD/MMBtu in China, and 10.6 USD/MMBtu in Japan. In the Current Policies case, it is forecast that due to the expansion of demand as compared with the New Policies case, the LNG price will further rise. On the assumption that the annual gas demand growth rate will be 1.9% and that in 2040, LNG will account for about 24% of the world energy supply, it is presumed that the LNG price in the United States will be 6.5 USD/MMBtu in 2040, 10.5 USD/MMBtu in Europe, 11.1 USD/MMBtu in China, and 11.5 USD/MMBtu in Japan. In the Sustainable Development case, in which the average temperature rise in the present century is kept to less than 2C, as described above, it is forecast that because natural gas has lower environmental load than oil and coal, natural gas demand will expand stably until the middle of 2020, but it is forecast that after that, demand cannot be expected to increase. This is due to the fact that while natural gas is desired to play an important role as a base load power supply in the long term, natural gas demand will continue to remain at a certain level because power generation with renewable energies such as solar and wind will be introduced actively. Thus, it is presumed that due to sluggish gas demand, the LNG price will also become sluggish, and it is presumed that the LNG price in the United States will be 3.9 USD/MMBtu in 2040, 7.9 USD/MMBtu in Europe, 8.5.1 USD/MMBtu in China, and 9.0 USD/MMBtu in Japan. In comparison with the IEA forecast released in 2015, the prices forecast for any region in the future are low, and in particular, the LNG prices in Northeast Asian countries such as China and Japan will decline considerably due to an increasing number of contracts that adopt the Henry Hub price. As described above, at present, the LNG price is linked to the oil price, but because the exports of LNG by the United States have begun, there is a good likelihood that the Henry Hub price will become an international index for the LNG price. Thus, it is forecast that the LNG price will become the Henry Hub price plus the liquefaction cost and

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the ocean transport cost. Considering the above comprehensively, it is assumed that the characteristics of the LNG price and other items in Asian countries such as Bangladesh are as described below. Considering the progress of the present natural gas liquefaction projects and the transport distance, the LNG suppliers are assumed to be Qatar, the United States, and Australia.

 The LNG price will be a reference index even in the future for the trading price in Japan, China, and Korea, where mass imports of LNG are forecast.  It is considered that the price of LNG for Asia will decline, and it is assumed that in the long term, the LNG price will become the Henry Hub price plus the LNG liquefaction cost and the transport cost.  It is assumed that in the medium term, the LNG price in Bangladesh will be determined in conjunction with the oil price based on a long-term contract. In view of the situation of the development of new LNG projects in the United States and Australia in recent years and considering the transport cost difference, it is assumed that the price may change in the range of 5 USD/MMBtu to 11 USD/MMBtu.  9.7 Conclusion From the above considerations, LNG procurement should be studied in conjunction with power demand forecasts and power generation plans. Also, as described above, procurement schemes are complex and wide- ranging, and their risks cannot be denied. Operation should be performed in accordance with an operation plan based on experience and extensive knowledge. Japan, which lacks in natural resources, has accumulated experience of more than 40 years in the past in LNG procurement and its operation. We are confident that the great deal of knowledge obtained in Japan can be put to use in LNG introduction plans in Bangladesh. As previously mentioned, in Bangladesh, existing domestic natural gas resources are depleted despite the current gas demand. A comparison between the current situation and future demand increase forecasts reveals that statistically, the country will fall into a serious undersupply condition. In order to achieve the economic growth policy formulated by the government, "Vision 2021," and then the policy "Vision 2041," it is necessary to activate the economic and industrial activities in a healthy manner. It can be said that for this purpose, constructing new large-size combined power plants using natural gas as a clean energy source is indispensable. It can, therefore, be said that the very important issue in the relevant ministries and agencies to attain this objective is to procure imported LNG in a planned and stable manner while: constructing land terminals for LNG in the Moheshakali, Kutubdia, and Bashkali areas with the above-mentioned GSMP2017; periodically monitoring the status of FSRU development promotion; analyzing the LNG market conditions; studying procurement policies; and making flexible modifications as needed. It is considered very meaningful to share the knowledge about LNG procurement possessed by Japan with the relevant ministries and agencies of Bangladesh and establish partnership beneficial to both

9-32 Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 9 Study of Fuel ProcurementStudy of Fuel Procurement

countries, in anticipation of a possibility of expanding Japan's high-quality energy infrastructure to Bangladesh.

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Chapter 10 Economic Evaluation of the Project

Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 10 Economic Evaluation of the Project

10.1 Finance Overview Assumed finance scheme for new GTCC project in Bangladesh are as follow. ① Yen Credit Loan (JICA etc.) ② Export Credit Agency Finance (JBIC etc.) ③ Project Finance ④ Finance from Local Bank in Bangladesh ⑤ Public Private Partner as the above combination

The three proposed sites in this study are set the expected commercial operation by every entity, and therefore, examine of the finance schemes from the various point of feasibility and easiness of finance arrangement relatively. In this study, ①~③ of which the period for finance arrangement are relatively short will be examined.

10.2 Yen Credit Loan Yen credit loan is one of the direct loan-type assistances by Japanese government. The characteristics is favorable condition for development country such as low interest rate and long repayment period. Yen credit loan are utilized for not only power plant development but also large-scale infrastructures development project in development countries. The subject to Yen Credit loan is mostly occupied construction of bridge, road, railway, port and power plant. In 2016, Yen Credit loan is composed of Transportation sector (55.3%), Power and Gas sector (15.0%) and the others sector such as agriculture, water and sewerage system, human resource for foreign student. In South-East Asia, Bangladesh is one of the biggest borrowers regarding Yen Credit loan. As for the finance scheme in this study, Yen credit loan would be applied as project loan to assist the p roject development for power plant construction and consulting service (project formation and bidding arra ngement). Generally, Japanese government determines the loan conditions in consideration of the income level of the Borrower. Bangladesh is categorized in LDC (Low Development Country) or poor country that means less than GNI：USD 1,005 per person. The loan condition for LDC or poor country is as below table.

Table 10.2-1 ODA Loan Table GNI Repayment Grace Conditions f Fixed/ Standard/ Interest Category Per Capital Terms Period Period or Floating Option Rate ( %) ( 2016) (years) (years) Procurement

STEP 2 Fixed Standard 0. 10 40 12 Tied

Standard 0. 25 30 10 Preferential Fixed Option1 0. 20 25 7 Terms for High Specification Option2 0. 15 20 6 3 Option3 0. 10 15 5 Longer ¥LI 40 12 option BOR+35bp ¥LI Floating 5 Standard 30 10 BOR+25bp ¥LI Option1 25 7 BOR+20bp Preferential ¥LI Option2 20 6 Terms 4 BOR+15bp Least Devel oped ¥LI Option3 15 5 Count r i es BOR+10bp Standard 0. 85 30 10

or Fixed Option1 0. 70 25 7 Untied

Option2 0. 55 20 6 Low I ncome Count r i Option3 0. 40 15 5 es Longer ¥LI （ - US$ 1, 005） 40 12 option BOR+45bp

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 10 Economic Evaluation of the Project

¥LI Standard 30 10 BOR+35bp ¥LI Floating Option1 25 7 BOR+30bp ¥LI Option2 20 6 BOR+25bp General ¥LI Option3 15 5 Terms BOR+20bp Standard 0. 95 30 10

Fixed Option1 0. 80 25 7

Option2 0. 65 20 6

Option3 0. 50 15 5

[Source：JICA]

Note：

（1）STEP（Special Terms for Economic Partnership）： This is tied loan following OECD rules and applicable if technology/knowledge owned by Japan company could be utilized and development country offers the application of STEP. STEP is used only for the cou ntry that can be borrowed the tied loan based on OECD official export arrangement except for LDC. （2）High Spec Loan This is applicable for the project that is specially regarded as promoting the high-quality infrastructure. (Every Project would be examined.) （3）Priority Condition This is applicable for environmental・climate change, medical, disaster prevention and human resource sect or. （4）Floating Rate Yen-LIBOR (6 months) portion is floated only and on the other hands, spread employs fixed spread loan for fixation. Minimum floating rate is 0.1%. [Source：JICA]

10.3 Export Credit Export Credit by JBIC is loaned for development country when produced/manufactured facilities and equipment is exported or when Japan provides technology such as survey, engineering, consulting and civil and construction work. Generally, the purpose of export credit is used for supporting the export and therefore, it is applicable this credit in case that export value from Japan is higher than 30% of project cost. There is two type direct financing: Buyer’s credit (B/C) and Bang Loan (B/L). B/C is loaned to oversea s importer. On the other hands, B/L is loaned to overseas finance institutions and then lend it as fund to overseas importer. When the loan agreement is contracted, government guarantee is required to counterpart country in most case. The currencies available from JIBIC are yen, USD and EURO and the conditions is based on OECD Exp ort Credit Arrangement. The maximum loan ration is 50% for category I country and 60% for Category I I that is belonged to Bangladesh. The reminder is loaned by commercial bank as co-finance. Maximum repayment period for power plant, except nuclear power plant is 12 years irrespective category I or category II. The currencies available from JBIC are yen, US dollar, and euro, and the basic loan conditions conform t o the OECD Export Credit Arrangement. The maximum loan-to-cost ratio is 50% for category I and 60% for category II, which Vietnam belongs to. The remainder is co-financed by commercial banks. The reimbursement period for loans for power plants, except nuclear power plants, is up to 12 years, rega rdless of country and category. The calculation of interest rate is different ways depending on yen or USD. When JIBIC loan as yen, fi xed rate is composed of the risk premium correspond to borrower and Commercial Interest Reference Rat e (CIRR), which is mentioned in ECA common guideline. In case of USD, interest rate is composed of J

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 10 Economic Evaluation of the Project

BIC portion and commercial bank portion. JBIC portion is fixed rate added CIRR to JBIC risk premium l ikewise Yen. Commercial bank portion is added margin to LIBOR. CIRR announced by OECD office is as follow as of 8th January, 2019. (Applicable period is from 15th Ja nuary to 14th February 2019.)

Table 10.3-1 CIRR Condition Table Repayment Period CIRR (JPY) CIRR (USD) < 5Years 0.84% 3.52% 5~8.5Years 0.84% 3.54% > 8.5Years 0.85% 3.61% [Source：JBIC]

10.4 Project Finance (Investment Finance) Project Finance refers to funding systems, when the operator raises the funds, the borrowers is not the operator but SPC (Special Purpose Company), which executes the project. Basically, project finance is non-recourse finance that is not required to guarantee the debt. The repayment resource is based the cash flow emerged from relevant project only. The advantages of project finance are as follow, [Source：Pfinet.jp https://www.pfinet.jp/about/finance.php]

① Mitigation of financial burden In finance arrangement, when the company raise the funds by corporate finance using company creditabilit y, the debt ratio on balance sheet will be increased. In this case, the financial condition is regarded as w eaken and then there is a possibility that creditability leads to be deterioration and new finance arrangeme nt is restricted. Meanwhile, in case of project finance, SPC financially separates from sponsor in general. Borrowed money is recorded on sponsor’s balance sheet as debt.

② Expansion of availability of funding Implementing body, which constitutes SPC can raise the funds regardless financial condition and corporatio n creditability if project plan・economic potential are appropriate.

③ Mitigation of risk The relevant company subdivides the risk of the project respectively and take the individual responsibility in range which can be manage appropriately (the risk of project is subdivided for minimizing their risk.) Therefore, in project finance, the sponsor can mitigate with compared to corporate finance that is loaned t o specific company.

Loan condition is basically determined through examination of each project. As for overseas investment by Japanese company, project finance utilizing investment finance that is applicable for long-term loan and l ow interest rate is representative. In Bangladesh currently, government generation company and private co mpany establish the SPC and employ the BOO (Build, Operate and Own) formula. Representative example of project finance in Bangladesh is Sirajganj 400MW GTCC and Pyra 1320 coal fired power plant.

10.5 Public Private Partner Public Private Partner (PPP) is one of the finance schemes by which project cost and risk are shared between public sector and private company. In Bangladesh, this scheme will be considered in the future. In PPP formula, when the area in project has low profitability and high publicness, public sector takes the lead in its area. In contrast, when the area in project has high profitability, private company basically participates. Therefore, PPP formula is effectiveness when the amount of investment is not only large but also private sector cannot cover the risk of development because of large risk. Additionally, it is effect for public sector when borrowers cannot develop the project due to large financial burden.

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 10 Economic Evaluation of the Project

10.6 Project Model Study In consideration of the characteristic and condition regarding the above finance option, this study suggest the following necessary finance arrangement and project model. This study recommends that BPDB, EGCB and RPCL should utilized Yen Credit Loan by JICA and Exp ort Credit Finance by JBIC. On the other hands, if project cost is fully covered by public development finance, financial burden is la rge for private sector of Bangladesh. Additionally, it is not realistic that project is developed by private in vestment because amount of investment is large for private sector. Therefore, it is effectiveness that gover nment generation company and private sector establish the SPC and then project is developed by using pr oject finance. From the above characteristics, in considering financial condition in Bangladesh, the condition of each gen eration company and the execution ability of project development, this study recommends that any financi al/project model should be chosen・determined.

10.7 Financial Analysis Method In financial analysis methods applied to power generation projects, the Financial Internal Rate of Return (FIRR) is often used as criterion for evaluating their profitability. The profitability of this project is also evaluated by using FIRR as criterion. FIRR is calculated by a discounted cash flow analysis. The Net Present Worth (NPW), FIRR, and the Benefit-Cost Ratio (B/C Ratio) are determined by a discounted cash flow analysis. A discounted cash flow analysis is also used for a cost-benefit analysis. The financial expenses and the financial benefits in each fiscal year during the project life period are rebated to the present worth, and compared and examined as present worth. When the total amount of the financial expenses is equal to that of the financial benefits, the discount rate that was used for calculating the present worth is referred to as Financial Internal Rate of Return (FIRR). The calculated FIRR is used as a major index of the financial internal profitability evaluation of the project. Its evaluation criterion is determined by taking the inflation rate, borrowing rate level, and other factors of the relevant country into account. For this project, the evaluation criterion is set to 10% on the premise that low interest-rate loans provided by JBIC and the like will be used.

10.7.1 Calculation of Financial Internal Rate of Return (FIRR) and Benefit Cost Ratio (B/C Ratio) The Financial Internal Rate of Return (FIRR) was calculated on the assumption of a power plant operating period of 25 years on the basis of the following values : project cost, payment schedule, fixed cost for operation and maintenance, variable cost for operation and maintenance, fuel cost, and revenue from sales of electric power as follow. According to BPDB, the current kWh Bulk Tariff of BPDB is BDT 4.82/kWh.

4.82 BDK/kWh = 0.0567 USD/kWh = 6.521 JPY/kWh (*) (*) USD 1.00 = BDT 85.00 USD 1.00 = BDT 115.

For fuel cost, the 2017/2018 price approved by the government is very low, compared with the international market trade price. It is set to BDT 89.4812 for every 1000 SCF. The gas price increased from 79.82 BDT/MCF of 2009 to 89.46 BDT/MCF of 2017 to be 1.121 times in eight years. Since the average annual rate of increase is 1.44%, the financial evaluation is performed on the premise that the gas price will become 1.074 times, 96.10 BDT/MCF (96.10 BDT/GJ = 130 JPY/GJ), at the start of operation after five years. On an import LNG basis, the LNG exercise price is linked to the crude oil price, and the fuel cost beco mes very high, compared with the current fuel cost.

LNG exercise price [USD/MMBtu] = Brent Price × 0.112 + 0.5 [USD/MMBtu] On the assumption that the Brent Price is 75.00 USD/barrel, the fuel cost is calculated as follows. = 75 × 0.112 + 0.5 = 8.90 USD/MMBtu -> 1,080 JPY/GJ

At the consumer end, the price becomes approximately 1,200 JPY/GJ, 9.23 times of the current price. Sin ce the cost of fuel gas is uncertain when LNG is used in this project, this value is not used in this fina

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 10 Economic Evaluation of the Project ncial evaluation. The current light oil (HSD) price for power generation is 66 BDT/Litre.

(1) Siddhirganj Power Station One block of single-shaft combined cycle unit using the latest H or J class gas turbine

Table 10.7.1-1 Summary of Siddhirganj Power Station Item Value 58,710 million yen [Tax Excluded] (eq. USD 510.52 million) Construction Cost 67,510 million yen [Including Tax] (eq. USD 587.04 million) 2019： 0.43% 2020：0.72% Payment Schedule 2021：30.24% 2022：20.90% 2023： 20.39% Annual 352.26 million yen Fixed cost for operation and maintenance [Excluded Tax] (0.6% of thepower plant construction cost) Annual 405.06 million yen [Included Tax] Unit price for selling electric power: 2.00 USD/MWh (eq. 0.230 yen/kWh) per unit The unit price at sending end electric power generation (1.0 MWh) (The reasonable profit is excluded). Sending End Fuel Gas Cost 0.779 Yen/kWh Case in which tax is excluded: 2.841 Yen/kWh (Case-1a) Case in which tax is included: 3.116 Yen/kWh (Case-1b) The BPDB kWh Bulk Tariff. Case in which tax is excluded: 6.521 Yen/kWh (Case-1c) Case in which tax is included: 6.521 Yen/kWh (Case-1d) [Source : Study Team]

FIRR and B/C-ratio calculation results and judgment on project feasibility ◼ Case-1a unit price at sending end (tax excluded) : High project feasibility FIRR = 10.97% B/C = 2.187 ◼ Case-1b unit price at sending end (including tax) : High project feasibility FIRR = 10.97% B/C = 2.187 ◼Case-1c BPDB Bulk Tariff (tax excluded) : Very high project feasibility FIRR = 31.94% B/C = 8.889 ◼Case-1d BPDB Bulk Tariff (including tax) : Very high project feasibility FIRR = 28.35% B/C = 7.580 (2) Feni Power Plant Two blocks of single-shaft combined cycle unit using the latest H or J class gas turbine.

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 10 Economic Evaluation of the Project

Table 10.7.1-2 Summary of Feni Power Station Item Value 123,510 million yen (eq. USD 1,074.00 million) [Excluded Tax] Construction Cost 142,010 million yen（eq. USD 1,234,87 million） [Included Tax] 2019 (0.28%) 2020 (0.48%) 2021 (29.03%) Payment Schedule 2022 (39.21%) 2023 (4.81%) 2024 (9.99%) Fixed cost for operation and maintenance Annual 741.06 million yen [Excluded Tax] (0.6% of the power plant construction cost) Annual 852.06 million yen [Included Tax] Unit price for selling electric power: USD 2.00/MWh (eq.0.230 yen/ kWh) The unit price at sending end (The reasonable profit is excluded). Sending End Fuel Gas Cost 0.785 yen/kWh Case in which tax is excluded: 2.985 yen/kWh (Case-2a) Case in which tax is included: 3.249 yen/kWh (Case-2b) The BPDB kWh Bulk Tariff. Case in which tax is excluded: 6.521 yen/kWh (Case-2c) Case in which tax is included: 6.521 yen/kWh (Case-2d) [Source : Study Team]

FIRR and B/C-ratio calculation results and judgment on project feasibility ◼ Case-2a unit price at sending end (tax excluded) : High project feasibility FIRR = 10.83% B/C = 2.187 ◼ Case-2b unit price at sending end (including tax) : High project feasibility FIRR = 10.83% B/C = 2.187 ◼Case-2c BPDB Bulk Tariff (tax excluded) : Very high project feasibility FIRR = 29.61% B/C = 8.306

◼Case-2d BPDB Bulk Tariff (including tax) : Very high project feasibility FIRR = 26.31% B/C = 7.074

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 10 Economic Evaluation of the Project

(3) Gazaria Power Plant Two blocks of single-shaft combined cycle unit using the latest H or J class gas turbine

Table 10.7.1-3 Summary of Gazaria Power Station Item Value 121,600 million yen (eq. USD 1,057.39 million) [Excluded Tax] Construction Cost 139,840 million yen（eq. USD 1,216.00 million） [Included Tax] 2019 年 (0.29%) 2020 年 (0.40%) 2021 年 (29.48%) Payment Schedule 2022 年 (38.58%) 2023 年 (21.02%) 2024 年 (10.15%) Fixed cost for operation and maintenance Annual 729,60 million yen [Excluded Tax] (0.6% of the power plant construction cost) Annual 839,04 million yen [Included Tax] Unit price for selling electric power: USD 2.00/MWh (eq.0.230 yen/ kWh) The unit price at sending end (The reasonable profit is excluded). Case in which tax is excluded: Sending End Fuel Gas Cost 0.785 Yen/kWh Case in which tax is excluded: 2.928 yen/kWh (Case-3a) Case in which tax is included: 3.218 yen/kWh (Case-3b) The BPDB kWh Bulk Tariff. Case in which tax is excluded: 6.521 yen/kWh (Case-3c) Case in which tax is included: 6.521 yen/kWh (Case-3d) [Source : Study Team]

FIRR and B/C-ratio calculation results and judgment on project feasibility ◼ Case-3a unit price at sending end (tax excluded): High project feasibility FIRR = 10.83% B/C = 2.187 ◼ Case-3b unit price at sending end (including tax) : High project feasibility FIRR = 10.84% B/C = 2.192 ◼Case-3c BPDB Bulk Tariff (tax excluded) : Very high project feasibility FIRR = 29.98% B/C = 8.455 ◼Case-3d BPDB Bulk Tariff (including tax) : Very high project feasibility FIRR = 26.64% B/C = 7.202 (4) Relationship between unit price for selling electric power and FIRR The relationship between unit price for selling electric power with tax excluded and that with tax included is as shown in Table 10.7.1-4

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 10 Economic Evaluation of the Project

Table 10.7.1-4 Electricity Tariff vs FIRR BDT 2.00 BDT 2.50 BDT 3.00 BDT 3.50 BDT 4.0 BDT 4.50 BDT 5.00

/kWh /kWh /kWh /kWh 0.kWh /kWh /kWh Siddhirganj PS 1 9.98 14.64 18.81 22.68 26.32 29.80 33.12 [Excluded tax] Siddhirganj PS 2 8.29 12.59 16.40 19.92 23.24 26.40 29.42 [Included tax] Feni 3 9.10 13.51 17.43 21.04 24.43 27.64 30.70 [Excluded tax] Feni 4 7.49 11.58 15.18 18.48 21.57 24.50 27.30 [Included tax] Gazaria 5 9.29 13.74 17.69 21.33 24.75 27.99 31.08 [Excluded tax] Gazaria 6 7.66 11.79 15.41 18.74 21.86 24.82 27.64 [Included tax] [Source：Study Team]

For all the power plants, when the unit price for selling electric power exceeds 3.50 BDT/kWh (4.73 yen/ kWh), FIRR satisfies FIRR > 18.4, and the project is financially feasible to a sufficient degree. This can be seen in the following graph.

Siddｈirganj PS (w/o tax) Siddhirganj PS (w tax) Feni (w/o tax) Feni (w tax) Gazaria (w/o tax) Gazaria (w tax) 35.00

30.00

25.00

20.00

FIRR 15.00

10.00

5.00

0.00 B D T B D T B D T B D T B D T B D T B D T 2 . 0 0 / K W H 2 . 5 0 / K W H 3 . 0 0 / K W H 3 . 5 0 / K W H 4 . 0 0 . K W H 4 . 5 0 / K W H 5 . 0 0 / K W H POWER SELLING PRICE

Figure 10.7.1-1 Electricity Tariff vs FIRR [Source：Study Team]

(5) Cash flow The cash flow after the implementation of the project was estimated on the assumption of the use of ECA finance, which covers import taxes and the like and a large portion of interest cost. The estimate was made on the premise

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 10 Economic Evaluation of the Project that for the construction cost, 85% of the total construction cost would be covered by a low interest-rate loan using ECA finance provided by JBIC or the like, and that the remaining 15% of the total construction cost and the interest rate during the construction would be covered by the own capital of the project implementing organization. The borrowing rate, the term of redemption, the date of the start of repayment, and the unit price for selling electric power were assumed as follows.

➢ Borrowing rate:Annual interest of 4.50% ➢ Term of redemption:12 years after the start of repayment ➢ Date of the start of repayment:End of the fiscal year in which service operation starts ➢ Unit price for selling electric power:3.50 BDT/kWh (4.735JPY/kWh)

Figure 10.7.1-2 shows the results of the cash flow verification that was made for each power plant under the above conditions. The largest debt during the power plant construction is 65,400 million yen for Siddhirganj Power Plant, 144,800 million yen for Feni Power Plant, and 142,400 million yen for Gazaria Power Plant. However, accumulated debts will also be eliminated in nine to ten years after the start of the operation of power generating installations. According to the results, 243,700 million yen (B/C = 3.73) for Siddhirganj Power Plant, 463,400 million yen (B/C = 3.20) for Feni Power Plant, and 466,100 million yen (B/C = 3.27) for Gazaria Power Plant will be left as accumulated profit before tax at the end of the operation of 25 years, which is regarded as operational life of power plants. This fact suggests that the project is sufficiently profitable.

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 10 Economic Evaluation of the Project

Shhidhirgabj PS Feni PS Gazaria PS

500,000,000,000

400,000,000,000

300,000,000,000

200,000,000,000 JPY 100,000,000,000

- 1 2 3 4 5 6 7 8 9 101112131415161718192021222324252627282930

(100,000,000,000)

(200,000,000,000) Year

Figure 10.7.1-2 Cumulative Cash Flow [Source：Study Team]

10.7.2 Calculation of FIRR and electricity cost based on LNG cost This study conducted the financial evaluation by using fuel cost (BDT 96.10 / MCF) (eq. JPY 130/ GJ) added current price (BDT 89.4812/MCF) to inflation. This price is equaled to one third of international market price. However, when the electricity is generated by using LNG, LNG price at terminal end is officially calculated by Brent Oil price in Bangladesh.

LNG purchase price at Terminal end (USD¥Bll) = Brent Price (USD/Bll) x 0.112 + 0.5 [Source：Petrobangla]

From the above equation, when the Brent Price is 50, 80,110, LNG purchase price at terminal end are as follow.

Brent Price (USD/Bll) LNG price (USD/MMBtu) 50 (Low) 6.10 (eq.518.5 BDT/MCF -> JPY 701/GJ) 80 (Middle) 9.46 (eq.804.1 BDT/MCF -> JPY 1,088/GJ) 110 (High) 12.82 (eq.1,089.7 BDT/MCF -> JPY 1,474/GJ)

The fuel cost at power station are as follow and it will be increased by 5.4 ~ 11.5 time compared to cur rent cost.

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 10 Economic Evaluation of the Project

Table 10.7.2-1 Fuel Cost at Power Station LNG Unit Cost 701 1,088 1,474 (LNG Price [JPY/GJ]) Siddhirganj PS [JPY/kWh] 4.20 6.52 8.83 Feni PS [JPY/kWh] 4.23 6.57 8.90 Gazaria PS [JPY/kWh] 4.23 6.57 8.90 [Source : Study Team]

When the FIRR is calculated based on the above fuel cost, it is approximately 11% and therefore is almo st equaled to chapter 10.7.1.

On the other hands, when the electricity tariff is set so that FIRR is 18%, it is equaled to 1.64 ~ 2.69 times of current electricity tariff as follow. Therefore, every entity needs to mitigate it by using grant etc., from Bangladesh government.

Siddhirganj PS： LNG Price：JPY 701/GJ (eq. 6.43 USD/MMBtu): BDT 5.75/kWh LNG Price：JPY 1,088/GJ (eq. 9.98 USD/MMBtu): BDT 7.46/kWh LNG Price：JPY 1,474/GJ (eq. 13.52 USD/MMBtu): BDT 9.17/kWh

Feni PS： LNG Price：JPY 701/GJ (eq. 6.43 USD/MMBtu): BDT 5.97/kWh LNG Price：JPY 1,088/GJ (eq. 9.98 USD/MMBtu): BDT 7.70/kWh LNG Price：JPY 1,474/GJ (eq. 13.52 USD/MMBtu): BDT 9.42/kWh

Gazaria PS： LNG Price：JPY 701/GJ (eq. 6.43 USD/MMBtu): BDT 5.93/kWh LNG Price：JPY 1,088/GJ (eq. 9.98 USD/MMBtu)：BDT 7.66/kWh LNG Price：JPY 1,474/GJ (eq. 13.52 USD/MMBtu)：BDT 9.38/kWh

10.8 Calculation of Economic Internal Rate of Return At present in Bangladesh, many areas still cannot connect to the National Grid; they are supplied with electric power from dispersed power sources, depending on unstable power supply. The main power sources for those areas are small diesel generators operating on light oil. By using the cost of the diesel power generation as "Willing to Pay Cost," the Economic Internal Rate of Return (EIRR) is calculated. In those areas, generally, the electric power rate is supported by government subsidies. EIRR is accordingly calculated on the basis of the tax-excluded project cost. In this calculation, the same values as those used for the FIRR calculation in 10.1.4 of Chapter 10 are used for tax- excluded project cost, payment schedule, fixed cost for operation and maintenance, variable cost for operation and maintenance, and fuel cost, and a power plant operating period of 25 years is applied. As Willing to Pay Cost, the current actual cost of diesel power generation at BPDB, 19.39 BDT/kWh (Note: data provided by BPDB) (equivalent to 26.23 JPY/kWh) is used (The amount is converted as follo ws: 19.39 BDT/kWh 0.2281 USD/kWh 26.23 JPY/kWh).

The results of the EIRR calculation are as follows. The results suggest that very high economic returns c an be expected out of the relevant project. The implementation of the project is presumed to produce ver y large economic effects.

(1) Siddhirganj Power Plant (BPDB) EIRR = 98.51%

(2) Feni Power Plant (EGCB) EIRR = 90.22%

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 10 Economic Evaluation of the Project

(3) Gazaria Power Plant (RPCL) EIRR = 90.94%

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 11 Comprehensive Evaluation

Chapter 11 Comprehensive Evaluation

Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 11 Comprehensive Evaluation

11.1 Technical Evaluation of the Project This project is aimed at constructing high-efficiency large gas-fired power plants. Its candidate plant models are a GTCC plant using the latest H or J class gas turbine and an ultra supercritical pressure steam power plant. GTCC is superior in the net thermal efficiency (62%:45%), construction cost (1:1.5), and construction period (35:60 in months). We therefore decided to introduce GTCC plants as main units in this project. Similar plant models have been introduced by major electric power companies in Japan, and some of them have already started their commercial operation. Since the total cumulative operating hours of those plant models in the world are more than two million hours, those plant models can be safely regarded as proved plants. GE H Series, MHPS J Series, and Siemens H Series are currently used in actual operation. In this project, therefore, examinations were made basically on those three models. In the examinations, the upper limit of the unit output of the power plants was set to 660 MW with consideration given to the limits of the static and dynamic stability of the system at the time of occurrence of a unit load rejection. The upper limit of output may become larger depending on the timing of the implementation of the project. For the project, financing from Japan and the Japan's latest technologies will be applied. Technology transfer from Japan is also sufficiently possible.

11.2 Evaluation of CO2 Reduction and Exhaust Gas As described in Chapter 8, the amount of CO2 emissions related to thermal power generation in Bangladesh reached 26.68 million tons per year in FY2016/2017. Its average for thermal power generation is 550 gr/kWh. The amount of CO2 emissions from the latest model of the high-efficiency GTCC that will be introduced to the three planned sites will be 289 gr/kWh, a value reduced by approximately 47.5%. The amount of the annual reduction in CO2 emissions that will be brought about by operation of the power generating installations in those three sites is estimated at 5.72 million ton (equivalent to 21.4%). On the assumption that the CO2 reduction value is 20 USD/ton, the annual reduction value is expected to be USD 114.4 million. The NOx emission level can be maintained at 25 ppm (vd) or lower by LNG-fired GTCC without installing water spraying equipment or De-NOx equipment. This level is sufficiently low, compared with the emission level of existing thermal power plants, several hundreds of ppm/kWh.

11.3 Matters to Be Considered to Ensure Business Feasibility for the Project Matters to be considered to ensure business feasibility for the large gas-fired GTCC project are as follows. (1) Stable supply of fuel gas (domestic gas production in Bangladesh has reached its peak and is decreasing) is important. Particularly, it is essential to ensure LNG through import (LNG import started in 2018) according to an import plan drawn up appropriately to meet demand. At present, the fuel gas price for power generation is maintained at a very low level, a fraction of the international market price. How the fuel gas price for power generation will be adjusted in response to the circulation of import LNG is very important for the future of the project. Careful attention needs to be paid to this matter. (2) For stable operation of the large gas-fired GTCC plants, ensuring of stable electric power demand can be expected sufficiently for the future. As described in Chapter 3, the power plant capacity, which is approximately 16,000 MW at present, is planned to be increased to approximately 60,000 MW by 2041 as part of the electric power master plan drawn up in 2016 (PSMP2016). This means that a new power supply of 1,760 MW is required to be ensured every year. Since a total electric power of 3,300 MW generated in the three sites of this project will contribute as part of the new and additional construction plan of the master plan, stable demand can be ensured. (3) A power transmission system development plan appropriate for the power generating installations development plan needs to be implemented so that power evacuation from the new power plants will not be disturbed. We made examinations on the adequacy of the power plant plans on the basis of the power transmission system enhancement plan described in PSMP2016, confirming that no problems will occur in power evacuation. (4) To check for problems with the environment, an IEE was performed at each of the three sites, and no special problems were raised. However, when some problem is raised in a future EIA examination, we need to make earnest efforts for solution. The Siddhirganj site, one of the three sites, is located in an existing power plant. The

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 11 Comprehensive Evaluation

other two sites, Feni Power Plant and Gazaria Power Plant, are newly developed sites; expropriation of land for the sites has already been completed, and good relationships have been established with neighborhood residents. We accordingly think that the possibility that some critical problem will occur is very low. (5) All the electric power companies show a keen interest in early implementation of the project and the focus in the next stage is how early the project will be completed. We therefore need to keep in close touch with each electric power company to discuss on such matters as the arrangement of financing, and advance the project to achieve early commencement and early completion of work.

11.4 Examinations of Business Model and Concept Recommended for the Candidate Sites and Its Economical Efficiency A purpose of this project is to construct high-efficiency large gas-fired power generating installations promptly as means to eliminate constant power shortages. Another purpose of the project is to put advanced technologies into widespread use in Bangladesh; those technologies are related to highly-reliable, durable power generating installations that have been used for actual operation based on Japan's technologies. Bangladesh started LNG import in August 2018, and thereby, a sufficient amount of fuel gas necessary for operating thermal power plants is expected to be ensured. Therefore, the country decided to aim to develop high-efficiency large gas-fired power plants. On the premise that the thermal power plants satisfy the five fundamental concepts below, we made examinations on the appropriate specifications, effectiveness, and necessity of this project (for details, see Chapter 5). ➢ High-efficiency large gas-fired power plants ➢ Low environmental burdens ➢ Contribution to the stability of the electric power network ➢ Future expandability ➢ Low construction cost and short delivery time For large gas-fired power generating installations, GTCC plants and ultra supercritical pressure steam power (USC) plants are candidates. When importance is placed on such factors as efficiency, construction cost, and construction period, GTCC is always superior. Accordingly, GTCC using the latest large H or J class gas turbine that has been used for actual commercial operation was selected as a candidate model. We made examinations on various parameters through comparison on the premise that the sending-end output is 660 MW per unit, and thereby, decided to introduce single-shaft GTCC. GE 9HA.01, MHPS 701J, and Siemens 8000H have been used for actual operation and are therefore selected as candidate models. The allowable range of the sending-end output of the sites for bidding was set to 600 MW 10%. Since thermal efficiency is expected to be 62% or so at the sending end, the minimum allowable thermal efficiency for bidding was set to 58%. An economic analysis was performed for an operating period of 25 years by doing economic calculations on the assumptions of an annual availability factor of 91% and an annual load factor of 85% by setting the net sending-end output of power generating installations as follows (for details, see Chapter 10).

➢ Siddhirganj Power Plant (BPDB): 664 MW ➢ Feni Power Plant (EGCB): 1,320 MW (2,640 MW in the future) ➢ Gazaria Power Plant (RPCL): 1,320 MW (2,640 MW in the future) In an FIRR analysis, the power plant construction costs were estimated as follows.

Tax excluded Tax included ➢ Siddhirganj Power Plant: JPY 58,710 million JPY 67,110 million (eq. USD 510.52 million) (eq. USD 583.56 million)

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 11 Comprehensive Evaluation

➢ Feni Power Plant: JPY 123,510 million JPY 142,010 million (eq. USD 1,074.00 million) (eq. USD 1,234.87 million) ➢ Gazaria Power Plant: JPY 114,400 million JPY 121,600 million (eq. 994.78 million) (eq. USD 1,057.39 million)

According to the results of the FIRR analysis, FIRR with tax included ranges from 18.48% to 19.92% on the assumption of a unit price for selling electric power at sending end of 3.50 BDT/kWh. However, sufficiently high economical efficiency is ensured even when ECA finance is used.

11.5 Examinations on Finance The hurdle for yen credit supply is very high for the electric power sector, which is high in business profitability. In addition, the size of the finance is large. We accordingly think that financing by a low-interest loan using ECA finance provided by JBIC and the like is the best way to choose. When ECA finance is to be used, 15% of the project cost will be covered by the own capital of the electric power company, and the remaining 85% will be covered by the ECA finance. In this scheme, 60% of the 85% will be borrowed from JBIC, and the remaining 40% will be borrowed from city banks. The average interest rate is presumed to be 4.5% per year or so (in actual cases, since the interest rate is determined separately for each project, it may be slightly higher or lower than this value), and the payout period is presumed to be 12 years. ECA finance does not require government-level talks, accordingly allowing the time of completion to be moved up by one year or more in contrast with JICA finance.

11.6 Examinations on Superiority of Japanese Companies 11.6.1 Superiority in Technical Area Actual cases of operation of LNG-fired GTCC in Japan account for most actual cases in the world. It can be said that Japan is the leading country not only in the Gas To Power Project area but also in the actual operation of GTCC using the latest high-efficiency H and J class gas turbines. On the basis of such experience, Japanese companies can contribute to the enhancement of the reliability of plants, the extension of time available for power generation, reduction in operating cost by implementing optimum maintenance plans, and other matters through project consulting services, EPC business including supply of major equipment, optimum project operation based on rich experience in Bangladesh, and long-term contracts for maintenance after the start of operation.

11.6.2 Superiority in Business Area The main part of this scheme is a power generation project that is aimed not at realizing Gas to Power but at constructing power plants as main purpose. On the basis of rich experience in Japan and rich experience in large- power-plant construction projects in Bangladesh, we are planning to provide various types of supports including the following: construction planning; establishment of a financial scheme; assistance with environmental assessment; assistance with EPC contract; project consulting service; participation in trial run and acceptance test; assistance with operation and repair planning for power plants and other activities for operation; training of electric power companies’ engineers. We need not only to keep in close touch with electric power companies to pave the way for the realization of the project but also to offer optimum advice in timings necessary for the project to achieve early commencement and completion of the project.

11.6.3 Superiority in Financial Area Yen credit supply for the power generation sector is currently difficult to ensure. It is accordingly necessary to recommend finance economically advantageous to electric power companies by establishing a financial scheme based on ECA finance. Since Japan currently has an advantage in the interest rate over other countries, superiority can be ensured by using Japanese finance. We therefore think that it is highly significant for Japan to participate in the project development and to assist and participate in the project from a financial aspect.

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 11 Comprehensive Evaluation

11.7 Examinations of Possibilities of Participation of Japanese Companies in Project Implementation Japanese companies are expected to participate in the following areas of the project. (1) Equity participation as business operator in the electric utility industry (expected companies: business operator in the power industry and general trading company) (2) Project consultation (expected companies: business operator in the power industry and consulting firm) (3) Contract on a GTCC power plant as EPC builder (expected companies: heavy electrical machinery manufacturer, general contractor, and general trading company) (4) Engineering work for foundation and construction work (expected companies: general contractor and general trading company) (5) Long-term contract for maintenance after the start of operation (expected companies: heavy electrical machinery manufacturer and general trading company)

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Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 12 Conclusion

Chapter 12 Conclusion

Feasibility Study for LNG fired Combined Cycle Power Plant in Bangladesh Final Report Chapter 12 Conclusion

12.1 Conclusion 12.1.1 Technical Evaluation and Candidate Sites Candidate construction sites were selected from kick-off meeting with each customer, hearing and confirmation (Land acquisition, Natural gas source, Transmission line and water resource) by site survey. As a result, Siddhirganj (BPDB), Feni (EGCB) and Gazaria (RPCL) are appropriate for construction site and the subject to this study. Additionally, GTCC power plant is appropriate to cope with power shortage in Bangladesh and H Series or J Series that is high efficiency gas turbine is effectiveness from the view point of efficiency, construction cost, construction period and experience of commercial operation. However, the further detail survey is required.

12.1.2 Economic Evaluation As a result of examination of electricity cost at candidate sites, it is BDT 2.30 ~ 2.40 /kWh (eq. USD 2.71 ~ 2.83 /kWh). When the electricity tariff is BDT 3.5 /kWh (eq. USD4.12 /kWh) based on hearing from generation company, FIRR is 18.48% ~ 19.92% and therefore it is expected profit so much. However, it is forecasted that LNG import will be increased in Bangladesh and so, fuel cost will be increased. therefore, it will be necessary to keep a careful eye on economic trend in Bangladesh. Additionally, in finance evaluation, as per mentioned Chapter 10, ECA finance or JICA ODA loan is one of the best finance arrangements in several option because of low interest rate.

12.2 Suggestion 12.2.1 Feasibility of candidate construction sites Siddhirganj, Feni and Gazaria site are feasible for GTCC construction site. To meet with the expected commissioning schedule of the projects under the Long List (Power Generation Capacity Addition Plan), the generation companies are expected to perform any required formalities related to construction of CCPP, including EIA (Environmental Impact Assessment), determination of the procurement method, preparation of site (embankment, access road and etc.), approval etc. , Meanwhile, this study suggests that relevant companies should contact generation companies them for preparation of early project development.

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