Feasibility Study for Introduction of LNG Receiving Facilities in

Transcription

Study on Economic Partnership Projects
in Developing Countries in FY2013
Feasibility Study for Introduction of LNG Receiving
Facilities in Myanmar
Final Report
February 2014
Prepared for:
The Ministry of Economy, Trade and Industry
Ernst & Young ShinNihon LLC
Japan External Trade Organization
Prepared by:
The Japan Research Institute, Limited
Mitsui O. S. K. Lines, Ltd.
JGC Corporation
Sumitomo Mitsui Banking Corporation
Reproduction Prohibited
Study on Economic Partnership Projects in Developing Countries in FY2013
Feasibility Study for Introduction of LNG Receiving Facilities in Myanmar
February 2014
The Ministry of Economy, Trade and Industry, Ernst & Young ShinNihon LLC, Japan External Trade Organization
Prepared by: The Japan Research Institute, Limited
Preface
The report summarizes the results of the Study on Economic Partnership Projects in Developing
Countries in FY2013, entrusted to The Japan Research Institute, Limited, Mitsui O. S. K. Lines,
Ltd., JGC Corporation and Sumitomo Mitsui Banking Corporation by the Ministry of Economy,
Trade and Industry.
This study entitled “Feasibility Study for Introduction of LNG Receiving Facilities in Myanmar”
was carried out in order to assess the feasibility of the project to construct FSRU, jetty and pipeline
at total cost of around 77 billion yen. The aim of this project is to solve the problem of gas supply
shortage for power generation in Myanmar.
We sincerely hope this report will contribute to the implementation of the aforementioned project and provide
practical information to parties concerned in Japan.
February 2014
The Japan Research Institute, Limited
Mitsui O. S. K. Lines, Ltd.
JGC Corporation
Sumitomo Mitsui Banking Corporation
Project Site Map
Proposed Site for FSRU and Pipeline Routes
Source：Prepared by Study Team
Details of Proposed Pipeline Routes
Source：Prepared by Study Team
List of Abbreviation
Abbreviation
Full Name
ADB
Asian Development Bank
CDM
Clean Development Mechanism
CSO
Central Statistical Organization
EIA
Environmental Impact Assessment
EIRR
Economic Internal Rate of Return
EMC
Energy Management Committee
EPD
Energy Planning Department
ESE
Electricity Supply Enterprise
FIRR
Financial Internal Rate of Return
FSRU
Floating Storage and Regasification Unit
HPGE
Hydropower Generation Enterprise
IEE
Initial Environmental Examination
IFC
International Finance Corporation
IPP
Independent Power Producer
JBIC
Japan Bank for International Cooperation
JETRO
Japan External Trade Organization
JICA
Japan International Cooperation Agency
LNG
Liquefied Natural Gas
MECF
Myanmar Environmental Conversation and Forestry
MEPE
Myanmar Electricity Supply Enterprise
MIC
Myanmar Investment Commission
MOE
Ministry of Energy
MOEP
Ministry of Electric Power
MOF
Ministry of Finance
MOGE
Myanmar Oil and Gas Enterprise
MOT
Ministry of Transport
MOU
memorandum of understanding
MPA
Myanmar Port Authority
MPPE
Myanmar Petroleum Products Enterprise
MPE
Myanmar Petrochemical Enterprise
NEMC
National Energy Management Committee
NLD
National League of Democracy
NPV
Net Present Value
ODA
Official Development Assistance
PPA
Power Purchase Agreement
SAIFI
System Average Interruption Frequency Index
SLORC
State Law and Order Restoration Council
SPDC
State Peace and Development Council
SRV
Shuttle Regasification Vessel
VGF
Viability Gap Funding
YESB
Yangon City Electricity Supply Board
Table of Contents
Preface
Project Site Map
List of Abbreviations
Table of Contents
Executive Summary
(1)Background and Necessity of the Project ················································································ S-1
1. The Myanmar Government’s Development Programs in the Gas and Electricity Sectors; Priorities of Projects
Based on Future Prospects ····································································································· S-1
2. Project Scope and Expected Users ······················································································ S-2
3. Effects of the Project······································································································ S-3
(2) Parameters/ Items in Determining Project Details ···································································· S-4
1. Demand Forecast ·········································································································· S-4
2. Identifying and Analyzing Issues before Exploring and Determining Project Details ·························· S-5
(3) Project Outline··············································································································· S-6
1. Project Site ················································································································· S-6
2. Specifications for Equipment Introduced ·············································································· S-6
3. Project Cost ················································································································ S-7
4. Financial and Economic Evaluation ···················································································· S-7
(4) Project Implementation Schedule ························································································S-11
1. Preconditions for project implementation ··········································································S-11
2. Project Schedule (Proposed) ··························································································S-12
(5) Feasibility to Implement the Project·····················································································S-13
(6) Potential Business Scheme ·······························································································S-15
(7) Technical and Economic Advantage of Japanese Companies ·······················································S-17
(8) Maps, which shows the site for the project in the country surveyed ················································S-19
Chapter 1 Overview of the Host Country and Sector
(1) Economic and Financial Status···························································································· 1-1
1. Myanmar: Summary ····································································································· 1-1
2. Society and Economy of Myanmar ····················································································· 1-4
(2) Summary of Targeted Sectors ····························································································· 1-6
1. Energy Related Organizations in Myanmar ·········································································· 1-6
2. Primary Energy Composition in Myanmar ··········································································· 1-7
3. Gas Demand Situation in Myanmar ··················································································· 1-8
4.Electricity Supply and Demand in Myanmar ········································································· 1-10
5.Efforts and Issues to Resolve Electricity Shortages in Myanmar ·················································· 1-12
(3) Situation in Subject Areas ······························································································· 1-13
1. Current Situation of Gas-Fired Power Plants and Gas Pipeline Network in Yangon ························· 1-13
2. The Current Situation of Yangon River Basin and Andaman Sea ··············································· 1-16
Chapter 2 Study Methodology
(1) Scope of Works·············································································································· 2-1
(2) Study Methodology and Structure ······················································································ 2-3
1. Study Methodology ······································································································ 2-3
2. Structure of the Team ··································································································· 2-3
(3) Study Schedule ············································································································· 2-9
Chapter 3 Justification, Objectives and Technical Feasibility of the Project
(1) Project Background: Why the Project Is Needed ····································································· 3-1
1. The Myanmar Government’s Development Programs in the Gas and Electricity Sectors;
Priorities of Projects Based on Future Prospects ···································································· 3-1
2. Project Scope and Expected Users
················································································· 3-3
3. Issues Expected in Case of Absence of the Project
····························································· 3-3
4. Effects and Impacts of the Project
················································································ 3-4
5. Alternatives to the Import of LNG
················································································ 3-4
(2) Upgrading and Streamlining Energy Use ·············································································· 3-6
(3) Factors to Examine for Determining Project Contents ······························································· 3-6
1. Demand Forecast ········································································································ 3-6
2. Identifying and Analyzing Issues before Exploring and Determining Project Details
······················· 3-0
3. Examination of the Proposed Project Site: Conclusion ···························································· 3-10
4. How to Source LNG
······························································································· 3-15
5. Technical Approaches (compared to alternatives)
································································ 3-19
(4) Project Plan Outline ······································································································ 3-25
1. Basic Policies for Determining Project Details ····································································· 3-25
2. Conceptual Design and Specifications of Applied Facilities and Equipment ································· 3-25
3. Proposed Project Details (Site and Investment Cost for the Project) ············································· 3-30
4. Issues on Proposed Technologies and System;Solutions ·························································· 3-31
Chapter 4 Evaluation of Environmental and Social Impacts
(1) Analysis of Environmental/ Social Aspects ··········································································· 4-1
1. Project Areas ············································································································· 4-1
2. Future Forecast ··········································································································· 4-2
(2) Environmental Improvement Achieved through Project Implementation ········································· 4-2
(3) Environmental and Social Impacts Associated with the Project ····················································· 4-3
1. Reviewing Environmental and Social Considerations ······························································· 4-3
2. The Environmental Impacts of the Alternative Proposals
····················································· 4-18
3. Result of Information Collected on Environmental and Social Impacts·········································· 4-18
(4) Overview of the Country’s Environmental and Social Related Regulations and Necessary Measures ······ 4-20
1. Overview of Regulations and Schemes Related to the Environment ············································· 4-20
2. EIA Related Matters
······························································································· 4-20
(5) Requirements to Deliver Projects in This Country
(by Implementing Organizations and Related Organizations)·························································· 4-21
Chapter 5 Financial and Economic Evaluation
(1) Estimated Project Costs ··································································································· 5-1
1. Cost Estimate Breakdown ······························································································ 5-1
2. Project Costs
········································································································· 5-1
3. Disbursing Plan of the Project Costs ·················································································· 5-4
(2) Summary of the Result of Preliminary Financial/ Economic Analysis ············································ 5-5
1. Financial Analysis ······································································································· 5-5
2. Economic Analysis ······································································································ 5-8
Chapter 6 Planned Project Schedule
(1) Project Implementation Schedule ························································································· 6-1
1. Preconditions for Project Implementation ············································································ 6-1
2. Project Schedule (Proposed) ····························································································· 6-1
Chapter 7 Implementing Organization
(1) Relevant Ministries Agencies and Their Roles ········································································ 7-1
(2) Required Capabilities for the project implementation ································································ 7-2
Chapter 8 Technical Advantages of Japanese Company
(1) Assumable Forms of Participation by Japanese Enterprises ························································· 8-1
(2) Superiority of Japanese Enterprises in Implementing This Project (Technologically and Economically) ····· 8-5
(3) Measures Necessary to Help Japanese Enterprises Win Contracts ················································· 8-6
Chapter 9 Potential Funding Source for the Project
(1) Reviewing Fund Sources and Financing Plans ········································································· 9-1
(2) Feasibility of Fund-Raising ································································································ 9-2
1. ODA by the Japanese Government ····················································································· 9-2
2. Investments by Japanese Companies ··················································································· 9-4
3. Loans/ Guarantees from Japanese Export Credit Agencies ························································· 9-5
(3) Cash Flow Analysis ········································································································· 9-6
1. Financial Analysis ········································································································· 9-6
2. Economic Analysis ········································································································ 9-9
Executive Summary
(1) Background and Necessity of the Project
1.
The Myanmar Government’s Development Programs in the Gas and Electricity Sectors; Priorities of Projects
Based on Future Prospects
a. Ministry of Energy’s gas production and supply plans
Myanmar produces natural gas. The Ministry of Energy (MOE), which is responsible for oil and gas sector from
gas exploration and production to distribution, has been promoting the development of offshore gas fields; for
example, Zawtika and Shwe fields are expected to start gas production in 2014, and M3 field in 2020. Most of the
produced gas within Myanmar, however, is exported to China and Thailand, so the domestic gas demand cannot
be sufficiently satisfied.
b. Ministry of Electric Power’s power development plan
The Ministry of Electric Power (“MOEP”) has drawn up power development plan that covers years up to 2030.
The Ministry plans to increase power capacity in tandem with the demand growth. The MOEP plans to build
several new gas-fired power plants to secure short-term power sources, especially for the dry season in Yangon
where electricity demand is very large. These plants are scheduled to start operating sometime between 2013 and
February 2016, with their planned capacity up to about 4.2 GW (see the chart below). The IPPs plan to build three
new power plants (BKB, UREC, Hydrolanchang) and are in discussion with MEPE for the signings of MOUs
(Memoranda of Understanding) for the Feasibility Study and/or PPA (Power Purchase Agreement).
S-1
Table Summary-1: Gas-Fired Power Plants Being Built or To Be Built in Myanmar
Name
Zeya
Hlawga
Ywama
Hydrolanchang
（IPP,China)
MSP
EGAT
Ahlone
Toyo-Thai
Thaketa
CIC
BKB
(IPP,Korea)
UREC
(IPP,China)
Yangon
Hlaingtharyar
Thilawa
Ayeyarwaddy
Mawlamyaing
Other area
in Myanmar
2014
2014
2014
2016
2013
2014
2014
2015
2013
2015
2016
2014
2016
2016
2016
2021
2015
2016
Capacity
(MW)
26
28.55
243
243
52
240
82
39
53.6
167
336
127
386
500
50
500
98
132
2014
50
2015
2016
2016
2013
175
350
250
100
start year
Myanmar Lighting
Kyaukphyu/Rak
MOEP
hine State
Dawei Power
Kanpouk
Utilities
Myin Gyan
Myin Gyan
Kyause
Rental
Source: Created by the research team based on information provided by the MEPE and an interview with the
NEWJEC
Although the MOEP and IPP projects have been proceeding with the construction of additional gas-fired power
generation facilities, they have been unable to increase the natural gas supply for the power generations, owing to
the tight gas supply-and-demand situation in the country.
Under these circumstances, the MOEP asked for a public bidding for importing LNG for gas-fired power
generation in July 2013. The study team interviewed the MEPE and found out that this was to obtain gas for IPPs
that are supposed to newly engage in gas-fired power generation mainly in the Yangon area. Applications are
received and reviewed by the Yangon Electricity Supply Board (YESB), which is a Yangon-based government
entity owned by the MOEP.
2.
Project Scope and Expected Users
This study firstly examined the LNG supply chain from the LNG purchase to its consumption, and then clarified
certain project to be developed using expertise of private sector, in which Japanese enterprises will support to
S-2
install storage and regasification facilities (i.e., facilities for receiving LNG) and facilities for gas transport to the
point of demand or the point of delivery designated by gas users.
It is difficult to analyze future national gas demand with limited research period, which is acceptable for the
investment decision of LNG import facility,. Therefore, this research assumes that imported gas is used to meet
the demand only for gas-fired power generation based on the master plan developed by MEPE
The MEPE owned by the MOEP purchases from the MOE home produced gas supplied to existing gas-fired
power plants. Through the interview with the MEPE and other relevant entities, the study team concludes that
MEPE will be able to play the same role for not only domestic gas produced but also imported LNG. Namely,
MEPE becomes the purchaser from LNG supplier and distributor to IPPs. Since MEPE is the sole entity to import
LNG in Myanmar, it is expected to have bargaining power to negotiate the LNG price with suppliers.
3.
Effects of the Project
As stated earlier, domestic demand for natural gas has not been filled in Myanmar. Natural gas is used not only for
power generation, but also for petroleum refining, fertilizer production, iron manufacturing, utility gas, and other
purposes. The natural gas supply is vital for Myanmar, in order to accelerate the economic development.
Installation of FSRU will enable Myanmar to receive LNG with a relatively short lead time. This will contribute
to balancing natural gas supply-demand, hopefully bringing the following effects:
• The operating rates of gas-fired power plants will rise and more electricity will be generated, which will
make outages shorter and less frequent.
•
Increased electricity supply will enlarge the national industrial platform increasing manufacturing and
production capacity of the country that will lead to improve standard of living of the population.
•
There will be larger domestic supplies of gas for petroleum refining, fertilizer production, iron
manufacturing and utility gas, which will strengthen cost competitiveness and increase industrial
production volumes.
S-3
(2) Parameters/ Items in Determining Project Details
1.
Demand Forecast
Demand estimation for LNG gas using the formula below:
Demand for LNG import = Quantity of gas needed for gas-fired power generation – Domestic gas
production x Percentage of gas distributed to electric power sector
Quantity of gas needed for gas-fired power generation
As mentioned before, the MOEP has drawn up power development plans that cover years up to 2030. This study
assumes that additional gas-fired power plants will be built according to the plans. The current plans state that
additional power plants will be completed by 2016 or 2017, and that the government will ensure steady electricity
supplies mainly through hydropower generation plants that require some development period.
With regard to the domestic gas production, many onshore and offshore projects are underway as mentioned
above, although many of them have not specified when production will begin and how much gas they aim to
produce except for certain gas fields. This study assumed only the production volumes from the ZawtikaShwe,
and M3 gas fields, for which the MOE is scheduled to launch development projects additional domestic gas
production volumes. The supply from domestic gas fields will be 290 BBtud between 2013 and 2014, and then
476 BBtud between 2020 and 2021.According to the MOE, how much domestic gas production will be distributed
for electricity generation in the future has not yet been decided, while 60 to 80 percent of the domestic gas
production has usually been reserved for electricity supply. This study assumed that the 65 percent of gas to be
supplied by the MOE will be distributed to electricity sector during 2013 and 2014. Additionally, although specific
LNG supply sources have yet to be determined, the team assumed that the calorific value of LNG is 1,040 Btu/cf,
which is the typical level in the market.
Given these assumptions, LNG demand for gas-fired power generation is expected to rise to 72 mmscfd between
2013 and 2014, and then to 354 mmscfd between 2016 and 2017. From 2020 onward, the demand will depend on
trends in the development of new domestic gas fields, while it is expected to be around 350 to 450 mmscfd.
S-4
Figure Summary-1: Demand for Imported LNG in Myanmar
Source: Created by the research team
2.
Identifying and Analyzing Issues before Exploring and Determining Project Details
To define the detail of the project, the below items are studied/ studied;
Site to install FSRU and specification
Options for ownership FSRU
Options for introducing an FSRU
Jetty design
Pipeline construction route and specifications
Financing pipeline construction
LNG procurement
S-5
(3) Project Outline
To overcome electricity shortage as soon as possible, MOEP is considering LNG import for electric power
generation. As the demand forecast shows, the amount of gas needed is meant to fill the gap between domestic gas
supply and gas demand based on the capacity of gas-fired power plants in the power development plan.
Given this background, MOEP intends to realize quick start of LNG import. However, further discussion on the
detail including required cost to be held through, among MOEP and relevant entities. In this study, the team
examined project details in accordance with the physical and financial restrictions mentioned earlier, and with the
needs of the various Myanmar government organizations.
1. Project Site
Taking into account such factors as the intention of the Myanmar government physical constraints and economic
efficiency, FSRU should be installed 80km offshore from the Yangon River, and a gas pipeline route will be laid
up to South Dagon in the existing pipeline network in Yangon.
The water depths should be at least 13m for a regular LNG carrier to safely approach. However, as detailed data
on the depth of water from recent years is unavailable, the team used a nautical chart to pick areas about 15 m
deep just to be on a safer side.
The team regard to pipeline, analyzed the three cases, considering location of an FSRU, the distance and route to
the land, ensuring that the route between S. Dagon and Thilawa is in line with the Myanmar government’s
expansion plan. The required length of onshore pipeline on the route will be 50 km.
The Myanmar Port Authority (MPA) in charge of the Yangon River requested that the offshore gas pipeline route
bypass the Yangon River (i.e., the pipeline should not run across the riverbed)), if possible The team took this
request into account in selecting recommended pipeline route. With regard to the offshore pipeline, we based our
examination on the parts immune from the plan for building the large deep-water port and other plans.
2. Specifications for Equipment Introduced
a.
FSRU specifications
The team assumed a newly-built FSRU with the tank capacity of 173,000 m3, which is close to the capacity of
150,000 – 160,000 m3 that many of the countries placed their orders in the recent years.
b.
Jetty design
The location of FSRU will be as far away as 80 km from the port, which makes it difficult for tugboats to be
deployed for quick rescue should the FSRU has to leave the jetty in an emergency. Therefore, the study team
assumes the design based on the cross-jetty system.
S-6
c.
Size of pipelines
From the viewpoint of minimizing the initial cost, and from the required capability of the gas transportation, it is
suggested that 24 inches pipeline size needs to be set.
3. Project Cost
The total investment cost is about US$624 million, and the annual running cost about US$24.0 million.
Table Summary-2: Initial Cost of the Project
Cost
($1 million)
Expense Items
Foreign Currency
($1 million)
514
278
82
154
15
Construction/Equipment Cost Total
FSRU
Jetty
Pipeline (offshore)
Consulting Cost
Interest in construction period
and handling fee
Tax for capex
Initial cost total
69
25
624
4. Financial and Economic Evaluation
a.
Preconditions of financial analysis
The following table shows the preconditions set for the project.
S-7
460
264
57
138
12
Local Currency
（1 million Kyat）
52,503
13,622
23,936
14,945
3,748
Table Summary-3: Financial Analysis Preconditions
Project period
25 years
Research/Construction period
5 years
Operating period
20 years
Regasification capacity
360 mmscfd
Profit
Charter FSRU, Jetty, and offshore pipeline (including fuel cost of FSRU
operation of USD 10.8 million per year: assumed LNG unit price:
approx. $14/mmbtu): $135 million/year
Initial cost
624MMUSD
Operating cost
24.0 MMUSD /year
Capital ration
25%
Interest rate on borrowing
Initial rate 10% (incl. handling fee), 3% during the loan period
Payback period of borrowing
18 years from date of draw down
Depreciation period
FSRU, jetty: 20 years, Pipeline: 10 years
(Straight-line depreciation for both. Salvage value after the closure of the
business is not estimated).
Corporate tax rate
25%
Commercial tax
5%
Custom duties
0.5%
Hurdle rate of FIRR
10% (Long-term interest rate in Myanmar as of October 2012)
Sensitivity analysis
Case1: The location of the FSRU is 100 km offshore (80 km for the base
case)
Case2: The operational period is 10 years.:
Sources: Created by the research team
The following table shows profitability of the project.
Table Summary-4: Result of Calculation of Performance Indicators
NPV（discount rate 12%）
132MMUSD
B/C (discount rate 12%)
165%
IRR
11.5%
(Long-term interest in Myanmar 10%)
Case1: IRR_offshore100km
10.5%
Case2: IRR_operation period is 10
6.9%
years
Based on the result above, it is estimated that the project has good financial viability even if the FSRU is
constructed 100km offshore, with a higher rate than the long-term interest of 10% in Myanmar.
S-8
If the duration of operations is cut by 50% to 10 years with the chartering cost unchanged, IRR will remain at
6.9%.
b.
Economic Evaluation
The advantage that the implementation of the project could bring to the economy of Myanmar is the financial
effect delivered through increased electricity supply and avoidance of power outage. To calculate the economic
effect of the project, it is necessary to evaluate the difference by comparing the effect of the project with a
baseline case, where the project does not take place. This study made a rather conservative assumption that in the
case where the project did not materialize, the hydropower generation plants would be developed instead,
generating the equivalent amount of electricity per year. However, Myanmar has a dry season for 3 months, and
therefore it was also presumed that there will be rolling power cuts caused by electricity shortage, deriving from
the inability of hydropower generation especially in the last half of the dry season. The difference in economic
effect between the baseline case and the case the project is implemented can be the difference created by avoiding
power failures during the dry season, as well as the difference between the construction and operational costs of
hydropower plants and the operational costs of gas-fired power plants.
Capex and opex of new onshore pipelines that MOGE may build and own are assumed to be covered by MOGE,
not by the project.
c.
Evaluation of economic feasibility
The preconditions for economic analysis are as below.
S-9
Table Summary-5: Preconditions for Economic Analysis
Project period
25 years
5 years
Operation period
20 years
360 mmscfd
Profit
Reduction of the cost of power cut in last half of the dry season (1.5
months) (Power shortage amount in the dry season1,555
GWh×$1/kWh1)-（New land gas pipeline costs +operational costs of
gas-fired power plant – construction/operational costs of a
hydropower plant）
Initial cost
624 MMUSD
Operational cost
24.0 MMUSD/ year
Hurdle rate of FIRR
12% (Average figure of opportunity cost in developing countries2)
Case1: The location of the FSRU is 100 km offshore (80 km for the
base case)
Case2: The operational period is 10 years.
To estimate the volume of power shortage during the dry season, the expected output of gas-fired power plants is
calculated based on the below assumptions;
(i) the electricity volume generated from 360mmscd of gas with a generating efficiency of 40% for 18 hours per
day excluding off- peak season for 1.5 months (46 days)
(ii) transmission loss (21%)1
The operational cost of a gas-fired power plant (excluding fuel costs), construction/operational costs of
hydropower plant are adopted from the average operational cost in China (gas fired: 10.88/kWh, hydropower:
$36/kWh) in the “Projected Costs of Generating Electricity 2010 Edition” by the OECD. For the fuel cost of a
gas-fired power plant, this study team applied the price deducing $0.5/mmbtu (=equivalent of the transport cost
between Myanmar and Japan, assuming it will be transported from the Middle East,) from Japanese LNG prices
described in the “New Policies Scenario” in the IEA’s “World Energy Outlook 2012”. The price is drifting at
$14/mmbtu during the operational period.
1
Source: FY 2011 Infrastructure System Export Promotion Investigations (Project formation of yen loan/private
infrastructure investigations), Study on the substation rehabilitation project in Yangon, the Republic of the Union of
Myanmar (November, 2012)
2
Guidelines for Preparing Performance Evaluation Reports for Public Sector Operations, ADB (2006)
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The profitability of the project is as below.
Table Summary-6: Result of Calculation of Performance Indicator
632MMUSD
504%
IRR
28.0%
（opportunity cost for developing country 12%）
Case1: IRR_100 km
26.2%
offshore
Case2: IRR_Operational
26.6%
period is 10 years
As shown in the above table, the result exceeds a 12% opportunity cost under the both cases where we assume
FSRU is located 100km offshore or project period of 10 years. However, the calculation of the above performance
indicators are based mainly on various assumptions, as including matters and elements outside the scope of the
study and therefore contains some uncertainties in its result, It is necessary to conduct further detailed study in the
future.
5. Analysis of Environmental/ Social Aspects
(1) Analysis of Environmental/ Social Aspects
Except for some items in which relevant permits are needed
in the future as Myanmar is now under the process
to making relevant laws and regulations, most check items were not applicable for this project, or its effect is
expected to be relatively small.
(4) Project Implementation Schedule
1.
Preconditions for project implementation
For the successful completion of the project, the following preconditions need to be decided by the relevant
companies/entities or by the discussion among them.
The determination of these preconditions will expedite the project.
•
Appointment for the responsible entity of the project, and the main body of the counterpart governments for
charter ship contract
•
Decisions of basic conditions of fuel gas procurement (quantity/gas components etc.)
•
Decision of gas delivery point

Change of the gas delivery point influences on the whole project design of gas pipeline including project
schedule, etc.
•
Policy on fund sourcing
S-11

•
Schedule of legislation for Environmental Impact Assessment (“EIA”)

2.
Development of appropriate financing plan related FSRU / pipeline introduction, the LNG purchase.
Affected by preparation of the EIA process and progress of parliamentary approval
Project Schedule (Proposed)
From basic development plan to gas delivery, the project is composed of three stages:
1. From making basic development plan to final investment decision (FID)
2. From FID to installation of FSRU, jetty facilities and pipelines
3. Connecting the facilities to the existing gas pipeline network
The schedule in this study is made based on the assumptions that the above preconditions have been appropriately
satisfied at each stage, and that the schedule of one stage does not influence on that of other stages each other.
Figure Summary-2: Detailed Schedule for Project Implementation
LINE DESCRIPTION
1
Main Milestone
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
35
36
37
38
39
40
41
42
42
43
2
3
4
5
6
7
8
9
Basic
planning
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 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Complete
of basic
design
Start of the
Project
Start of the
Construction
LNG
Receiving
Basic planning
Basic plan
Basic design
Comfirmation of project base
Collect additional data and survey marine data
Write EIA report
Environmental approval received work
Inquiry plan
Inquiry・Select sub-constructor
Detailed design
Final Investment Decision
Order sub-constructor
Lower side of jetty
Contract
Detailed design・Construction design
Site work
ipper side of jetty
Offshore Pipeline
Detailed design
Equipment purchase
Equipment carried
Installation and piping, electrical
and instrumentation work
Contract
Material purchase /on-site installation
FSRU
Contract
basic design
detailed design
Production design
Construction and manufacturing
Transport and installation to the site
Preparation for operation
Whole system inspection
Ready　For　LNG　Receiving
Followings are the estimated duration in the main tasks:
• Basic Plan: 3 months
•
Basic Design/Ministries approval: 12 months
•
Detailed Design: 6 months (part of this work can begin earlier)
•
FSRU: LNG reception can begin 33 months after order placement
•
Jetty Facilities: complete in 31 months after order placement, in 23 months after the start of construction
•
Setting up of Pipeline and Valve Station: complete in 30 months after order placement
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(5) Feasibility to Implement the Project
FSRU business has been implemented in several countries with the good track records of bankable finance
scheme.. Such project will become feasible when reliable equipment, operation, funding, etc. are provided by
experienced parties through the cooperation of the host country’s government.
Considering the roles of related ministries and agencies as well as implementation capabilities needed for this
project, it is suggested that the MOEP/ MEPE/ YESB and the MOE/ MOGE need to collaborate each other.
However, based on the fact that the MOEP requires immediate import of LNG to overcome the domestic energy
shortages mainly due to the rapid increase of electricity consumption, it would be beneficial to unify the business
contact window of the government, to promote this project quickly. Currently, since the LNG import is mainly for
gas-fired power plant, it is suggested MOEP should be the primal contact window for project
participants/stakeholders.
Although the MOEP has appointed the YESB as the managing body of a public bidding for LNG import, it would
be very challenging for YESB because it is an unprecedented project in Myanmar, thus YESB does not have any
past experiences. This may become one of the obstacles for companies to enter into this market. In addition,
inadequacy of transmission and the distribution network also will be an obstacle in electricity supply, which
generates another risk to newcomers. Therefore, to enhance the feasibility of the project, well-organized
development plan and project management for not only power generation plants but also transmission/distribution
grid expansion are critical.
Considering the abovementioned aspects, new organization under MOEP would be required, whose missions are
to become the supervisory agency for firepower sector and LNG import, to manage this project and relevant
agencies such as the transmission sector of the MEPE and YESB. MEPE is an organization with an
implementation capability and robust operating competency for the plan. Furthermore the firepower sector of the
MEPE has signed a memorandum of understanding about the gas-fired power generation plan with South Korean
and Chinese companies, so it would be suitable for MEPE supervisees the IPP players’ power plant developing
plans. So, MOEP can control the power generation plan by supervising the MEPE to the implementation of the
IPP business as planned.
This study suggests that the MEPE should be the purchaser of the LNG, which has the contract directly with LNG
supplier because of the two main reasons. First, MEPE is already the purchaser for domestically produced natural
gas to fuel gas-fired power plants. Therefore, MEPE would be able to play the role in adjusting domestic demand
and supply gap for the consumption of gas-fired power plants. Second, sole entity to purchase the natural gas from
overseas can be expected to have a bargaining power to acquire the lower LNG price, contributing to supply
cheaper electricity price to consumers.
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About the chartered ship to the FSRU and also the pipeline transportation service, the MEPE would favorably be a
contract entity, in terms of consistency of the contract, as well as the unification of the business access posts.
Furthermore, capacity building would be necessary for the MOEP/MEPE, to manage and supervise IPP players,
realize the electric power development as planned, and enable the operators to carry on business in a stable
manner because the delay of the construction and/or the critical problems of the operation would adversely affect
the FSRU project as well.
In addition, for the success of the power plant development, financial assistance would be vital. Especially, it is
necessary to complement the revenue shortages for purchasing gas, in order to make it cover costs. Financial
enhancement by the government guarantee, secured by the MOF, is needed.
Lastly, to involvement of the MOE/MOGE, would be important because of their expertise of the development,
and provision of on-shore pipeline to support the MOEP/MEPE. Though this project assumes that the imported
LNG is utilized only for gas-fired power plant, LNG would be supplied to other consumers such as petrochemical
industry in the future. Considering this, MOE/MOGE should be involved at the early stage of this project to
understand the logistics of imported gas and to get the know-how to handle the gas, because the role of these
entities will be very important to distribute natural gas to such different users in the future.
Based on the above, the chart below shows the suggestion of role sharing in the LNG import & transport project
Figure Summary-3: The Suggestion of Role Sharing in the LNG Import & Transport Project
Source: Prepared by Study Team
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(6) Potential Business Scheme
There will be two ways for how to cover the costs: owning the FSRU and the pipeline on its own, or chartering
FSRU from the owner of the FSRU and requesting wheeling through the pipeline.
The advantage of the owning FSRU is that the possessor can fully customize and upgrade the specifications
during the period of operation as per the requirement of the terminal. This allows for the configuration flexibility
with respect to regasification capacity, layout, shore integration and any future enhancements. While this case has
the disadvantage in increased work burden including higher initial investment, and all ship management tasks to
be conducted by the possessor, such as the arrangement and administration of crew. Based on the above study,
this project adopts the charter scheme, which holds down initial investment for the counterpart in the case of
FSRU, and has low work burden to the counterpart when initially installing FSRU.
On the other hand, as to the land pipeline, it will be effective to construct a state-run grid because in most cases,
grids are not built by private companies for their inherent purposes, but are built as national common-use
infrastructure in nature, when building pipelines in terms of responding to wide-ranging gas demand not only for
this electricity generating purposes, but also for commercial use except electricity generation in the medium and
long run.
In addition, it will be desirable for private operators and the entire economy in Myanmar for MOGE with a track
record of construction and operation to own a pipeline for constructing and operating it, though the initial costs
are higher, considering that the compulsory purchase of land will become an issue for private operators in building
pipelines. MOGE will be incentivized with increased profit through wheeling and an increase in the utility value
of the entired related infrastructure, with the extended pipeline networks and capacity.
Regarding offshore pipelines, which are different from land pipelines in nature, it is difficult to plan their
diversification and development except their main purpose, and existing sea pipelines were commissioned to
foreign private companies. Considering that MOGE has no experience of constructing them, it will be desirable
for the counterpart to use wheeling in view of the work and initial investment burdens, as in the case of FSRU.
A unit of SPC in which Japanese companies invest is considered to own, maintain, and operate FSRU and
offshore pipeline and lease the facility to charterer. The FSRU receives LNG from tankers, regasify the LNG and
transports gas to such points of delivery as designated by charterer.
Our team assumed the buyer of gas from an LNG portfolio supplier will be MEPE as mentioned before, which has
operated gas-fired power plants, in addition to procuring gas domestically.
Based on the above, the table below shows a plan of introduced equipment and player make-up, assumed by this
study team.
S-15
Figure Summary-4: Introduced Equipment and Player Make-up (Planned)
Regarding financing, it is necessary for FSRUs, the pipeline and the SPC to secure funds as the initial investment
for the project. The SPC is assumed to raise funds from Japanese financial institutions, including Export Credit
Agencies and commercial banks, as well as investment from Japanese and foreign companies.
In addition, it is assumed that MEPE as the off-taker or its upper organization MOEP will supply equity in the
SPC because such financing may help enhance the prospect for realizing this business from the viewpoints of
easing the investment burden and risk that foreign companies may face, as well as lowering the risk bar for the off
taker arising out of cancelation of the project. However, generally speaking, under this arrangement, conflict may
occur about how to handle the assets for liquidation after the project is over, or the realistic and best structure in
terms of tax cannot be made because of government involvement. (For instance, there may be restrictions which
do not allow establishment of an SPC in low-tax countries like Singapore, making the requirement that it must be
a Myanmarese corporation possible.) Also, quick decision-making can be compromised by governmental
influence over operating the SPC. The above can be disadvantageous to this arrangement. As after all, this is only
one option of schemes. Therefore, it is necessary first to judge whether MOEP intends to invest in this project or
not, from the viewpoint of acquiring technology/know-how for similar projects in the future. If so, it will be
necessary to investigate the ratio of ownership, roles, rights, obligations, etc., of each parties. If MOEP invests in
the SPC, utilizing the back finance of the funds by ODA to secure financing, will be useful bringing down the
initial costs of the Myanmar side, and in reducing the risk of investors (a risk of investment shortage).
Furthermore, it is necessary to study how to procure LNG and finance FSRU chartering. It will be desirable to
enter a contract with MEPE in consideration of integrating the contacts for actual work of procuring LNG,
chartering FSRU, and pipeline wheeling.
MEPE will be able to reduce the initial investment in equipment and facilities related to receiving LNG, by
chartering FSRUs under the scheme that was proposed by this study. Also, as the imported LNG through this
project will be eventually used for generating electricity, fees for use of FSRU and the pipeline should be paid
S-16
basically by government subsidies. However, given that it is not easy to raise electricity rates due to objection
among the population, and that government finances are tight, there is a possibility that this project cannot secure
enough profits to be viable only with additional funds from the Myanmar side (a possible gap between costs and
profits). Viability gap funding, as a measure to help fill the gaps, the back financing of this fund by ODAs can be
utilized.
With the above issues sorted out, the table below shows a project scheme
Figure Summary-5: Project Scheme (Proposed)
(7) Technical and Economic Advantage of Japanese Companies
a.
Provision of highly reliable long-term operation services for the FSRU
Since the contract period of providing FSRU chartering and operation services persists over a long period of time,
ranging from a few years to 20 years, stability and reliability of operator are essential elements required to provide
constant services during the contract period.
As the world’s largest LNG carrier, Mitsui O.S.K. Lines has established top-level know-how of LNG transport,
handling technologies and vessel management know-how all essential for the operation of the FSRU.
While there are currently only a few companies that enjoy a track record of offering operation services of
regasification through FSRU on a global basis, Mitsui O.S.K. Lines has accumulated unique know-how on FSRU
since participating jointly in the shipboard LNG regasification project on the east coast of North America
(“Neptune project”) with a partner shipping company in Norway from 2006, and independently signed a
S-17
long-term charter party for FSRU with a subsidiary of GDF Suez S.A., a French company, in October 2013, to
make a full-scale entry into the FSRU business. Among FSRU operators, Mitsui O.S.K. Lines has more stable
financial foundation compared with other providers, and high reliability in provision of long-term services.
b.
Support in fund securing
To materialize the project, funding arrangement to pay costs for implementation of the FSRU, jetties and pipelines
is necessary, and it is essential to realize investment and lending to the planned SPC.
SMBC, a Japanese financial institution, has a strong track record in LNG-related project finance including FSRU,
and may possibly take part in this business as a financial advisory, or in the form of lending.
Having a record of participation to the investment in two LNG ships with shipboard regasifiers (FSRU)
(investment ratio: 48.5%) in the Neptune project described above, Mitsui O.S.K. Lines might have strong interest
of investment for the project.
In addition, advantage of Japanese companies includes a possibility of securing ODA loan by Japanese
government, and the Japanese export credit agencies.
Such experience enables the company to offer services for the entire LNG value chain that includes financing.
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(8) Maps, which shows the site for the project in the country surveyed
Figure Summary-6: Proposed Site for FSRU and Pipeline Routes
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Figure Summary-7: Details of Proposed Pipeline Routes
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Chapter 1 Overview of the Host Country and Sectors
(1) Economic and Financial Status
1.
Myanmar: Summary
The Republic of the Union of Myanmar (hereinafter, Myanmar) is located in South East Asia, bordered by
Thailand and Laos on the east, and India and Bangladesh on the west. The population is around 60 million (2010),
of which around 70% is Bamar with the rest comprised of a number of ethnic minorities. The capital city is
Naypyidaw and its economic center is its largest city, Yangon.
1-1
Figure1-1: Myanmar Summary
Naypyidaw
Yangon
Time Difference
between Japan and
-2.5 hours *No daylight savings time
Myanmar
1MMK (kyat) ＝ 0.10 yen
Exchange Rate
<Source> Trade Statistics of Japan “Foreign Exchange Rate” (22.09.2913 –
28.09)
Capital City
National Territory
Naypyidaw
676,578 km2 *1.8 times larger than Japan
Area
Ethnic Groups
Bamar - about 70%
Religion
Buddhist: 89.4%, Christian: 4.9%, Islam: 3.9%, Hindu: 0.5%
Language
Burmese (official language)
Government
Presidential, Constitutional Republic *Head of State – President, Thein Sein
Total Population
59.78 million (2010) (according to documents released by the Government of
Myanmar)
Source: Prepared by Study Team based on various sources
1-2
Figure1-2: Weather at Yangon
Average precipitation
Average minimum temperature
Average maximum temperature
32.2
34.5
36
30
20
17.9 19.3
21.6
37
700
33.4
24.3
25
30.2 29.7 29.6 30.4 31.5
24.5 24.1 24.1 24.2 24.2
32
31.5
500
22.4
19
5
2
7
200
368
303
206
15
400
300
547 559 602
10
600
100
60
7
0
Average precipitation （mm）
Average temperature（℃）
40
0
Jan Feb Mar Apr May Jun
Jul Aug Sep Oct Nov Dec
Source: Prepared by Study Team based on various sources
Myanmar has long been criticized by the international community for its suppression of democracy by the long
serving military regime, since its independence in 1948. However, after achieving the transition to civilian rule,
there has been an increased interest from the international community in its large population and potential
economic growth.
1-3
Table1-1: History of Myanmar
Year
Month
1948
-
Gained independence, becoming the Union of Burma
1974
-
Established the Socialist Republic of the Union of Burma. General Ne Win as President.
1988
-
1989
-
1990
May
1997
-
2003
Mar
2008
May
2010
Nov
Changed the name of the country to the Republic of the Union of Myanmar.
2010
Nov
Held a general election in accordance with new constitution.
Jan
The first assembly was called, and the Vice President was elected.
Mar
In a shift to civilian rule, the new government led by President Thein Sein was founded.
Nov
US President Obama visited, announcing a partial trade embargo lift.
Jan
Ceasefire agreement with the Karen National Union after 60 yearlong conflicts made.
Nov
Established the Union of Myanmar Foreign Investment Law
2011
2012
2013
May
2014
-
Events
The Socialist government, which lasted for 26 years, was brought down by pro-democratic
demonstrations.
Military forces suppressed pro-democratic demonstrations and formed the State Law and
Order Restoration Council (SLORC), which then seized power.
A general election was held, with the National League for Democracy (NLD) led by Aung San
Suu Kyi winning the majority; with the SLORC rejecting transfer of power.
Joined ASEAN, and the SLORC was dissolved, with the State Peace and Development
Council (SPDC) established.
Announced the Seven-Step Roadmap to Democratization.
The ratification of the new constitution by referendum, with a general election to take place in
2010.
Japanese Prime Minister Abe visited, deciding to provide yen loans to the country after a gap
of 26 years.
Chairmanship of ASEAN (planned)
Source: Prepared by Study Team based on various sources and press reports
2.
Society and Economy of Myanmar
The population of Myanmar is steadily increasing, and reached around 60 million as of 2010, according to
information provided by the Government of Myanmar. 10% of the total population is concentrated in the Yangon
Region, with the numbers gradually increasing.
Statistics from international institutions show that GDP per capita of Myanmar as of 2012 is 868 USD which is
relatively low in comparison to other ASEAN countries. This figure is expected to grow rapidly to 1,344 USD
(estimate) in 2018, which will still be low compared with other ASEAN countries, however, a high pace of
growth is expected to continue following in the footsteps of Laos and Cambodia, with expectations for future
growth linked to its large population.
1-4
Figure1-3: Total Population and Change in Percentage of Population in Yangon Division
Source: Prepared by Study Team based on “Statistical Yearbook 2011”
by Central Statistical Organization Nay Pyi Taw, Myanmar
Figure1-4: Comparison of GDP, GDP per Capita, and Growth Rate of GDP
2012
2018 (estimate)
9
Lao
8
Cambodia
Phillipines
7
Myanmar
Thailand
Indonesia
6
Bangladesh
Malaysia
Vietnam
5
4
0
Lao
Cambodia
8
Gross domestic product,
constant prices (%)
Gross domestic product,
constant prices（%）
9
5,000
10,000
Myanmar
7
Bangladesh
6
Indonesia
Phillipines
5
Vietnam
Malaysia
Thailand
4
15,000
0
Gross domestic product per capita, current price（USD）
5,000
10,000
15,000
Gross domestic product per capita, current price （USD）
*Bubble shows GDP (current prices) of the country.
Source: Prepared by Study Team based on “World Economic Outlook October 2013” by IMF
There has been a change in industrial structures after 2003, as the percentage of GDP accounted for by primary
industry dropped more than 10%. On the other hand, however, the proportion influenced by the manufacturing
and transportation sectors has increased.
1-5
Figure1-5: Change in the Percentage of GDP Accounted for by Primary Industry
Commercial
100%
Other Services
90%
Social/ Administrative Service
80%
70%
60%
50%
Financial Business
7%
8%
8%
10%
11%
11%
9%
9%
10%
40%
11%
11%
12%
12%
42%
41%
40%
Communication
Transportation
14%
15%
16%
17%
8%
8%
8%
8%
7%
34%
32%
30%
37%
19%
Construction
Electricity
30%
20%
12%
Manufacturing Industry
Mining
36%
10%
Energy
Forestry
0%
Stockraising/ Fishery
Agriculture
*Standard Year = FY1985, 2000, 2005 (From April to March)
Source: Prepared by Study Team based on JETRO website
(2) Summary of Targeted Sectors
1.
Energy Related Organizations in Myanmar
There are various ministries and agencies associated with natural gas. The main stakeholders in this study are the
MOE (the Ministry of Energy) and the MOEP (the Ministry of Electric Power). The MOE has 4 lower branches,
of which the counterparts for the current study are the Energy Planning Department, which is responsible for the
planning of gas production and supply, and the MOGE (the Myanmar Oil and Gas Enterprise), which is
responsible for building and operating the pipeline from E&P in the domestic gas sector. The MOEP also has
public corporations beneath it, each responsible for electric power generation, electric power transmission and the
delivery of electricity. The counterparts for this study are the MEPE (Myanmar Electric Power Enterprise), which
is responsible for development and operation of gas-fired power plants, as well as supplying gas to IPPs
(Independent Power Producers), the YESB (Yangon City Electricity Supply Board) which is responsible for
controlling delivery of electricity in the Yangon Region, and has also acted as the public offering office for LNG
imports, which will be referred to later in the study, and the MOEP.
1-6
Figure1-6: MOE Organization Chart and Division of Major Roles
Ministry of Energy
(MOE)
Energy Planning
Department
(EPD)
Myanmar
Petrochemical
Enterprise
(MPE)
Myanmar Oil and Gas
Enterprise
(MOGE)
• Regulation
• Adjustment of plans
• Gas production and
distribution
management
• Gas development
and production
• Pipeline
construction and
operation
• CNG production
• Petroleum refinery
• Production of
fertilizer, LPG,
CO2 and methane
Myanmar Petroleum
Products Enterprise
(MPPE)
• Marketing and sale
of petroleum
products
Source: Prepared by Study Team based on MOE materials
Figure1-7: Operating Structure of MOEP
Public corporations under the umbrella of MOEP
Electricity generation
HPGE
MEPE
(Hydraulic and coal-fired)
(Gas/oil thermal)
Electricity transmission
Electricity distribution
IPPs
MEPE
YESB
ESE
(Yangon)
(Outside Yangon)
Consumers
Source: Prepared by Study Team based on MOEP materials
2.
Primary Energy Composition in Myanmar
Primary Energy Composition in Myanmar is dominated by biomass, which makes up around 70% of the total,
followed by natural gas that makes up around 20%.
1-7
Figure1-8: Primary Energy Composition
Coal
1%
Hydro Power
2%
Oil
10%
Natural Gas
18%
Biomass
69%
Source: Prepared by Study Team based on ”Myanmar Energy Sector Initial Assessment”
(2012) by ADB materials
3.
Gas Demand Situation in Myanmar
The transition in the volume of domestic natural gas production shows that it has increased dramatically after the
2000, 2 years after offshore production began.
Myanmar exports most domestically produced natural gas, and the ratio between export and domestic
consumption is 86:14. Exports account for 85-90% of total production, which has remained unchanged over the
past 10 years.
This is because the Government of Myanmar promoted the development of resources with the aid of foreign
capital, intending to secure foreign currency, despite economic sanctions. Resources development in Myanmar
was advanced under a scheme where companies provided the capital to develop resources in Myanmar,
maintaining complete control over the use of said resources, on condition that they would provide 10% of the
output for domestic use. This still remains the case, and most of the country's output is exported outside the
country.
1-8
Figure1-9: Natural Gas Production History of Myanmar
Source: MOE materials (2013)
Figure1-10: Change in Percentage of Domestic Use and Export of Natural Gas
(million ft3)
500,000
450,000
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
18%
16%
14%
12%
10%
8%
6%
4%
2%
0%
2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
(Year)
Domestic Use (Left)
Export (Left)
Percentage of the Domestic Use (Right)
Source: Prepared by Study Team based on ”Myanmar Energy Sector Initial
Assessment” (2012) by ADB
As described before, domestic demand for natural gas is much greater than supply in Myanmar, as the country
exports most of the natural gas produced in the country overseas.
1-9
Figure1-11: Gap in Demand and Supply of Natural Gas
(mmcfd)
1,000
900
800
700
600
500
400
300
200
100
0
918
Suuply
Demand
515
471
265
FY2012
FY2013
The main use of natural gas produced in Myanmar is for electricity generation, accounting for 65%.
Figure1- 12: The Main Use of Nnatural Gas Produced in Myanmar (July 2013)
0.9% 0.2%
1.5%
1.9%
Electricity
7.2%
Government Factories
Fertilizer
7.9%
CNG
Refinery
20.0%
60.4%
LPG
Private Factories
Others
4.
Electricity Supply and Demand in Myanmar
The amount of electricity generated in Myanmar increased dramatically after 2010, seeing the average annual
growth rate of 12.7% from 2009 to 2012, as opposed to 4.3% from 2003 to 2009.
1-10
Figure1-13: Change in Generation of Electricity
(million kW)
12,000
10,424
10,000
10,965
8,633
6,971
6,164 6,409 6,622
6,064
5,426 5,608
8,000
6,000
4,000
2,000
0
(Year)
Source: Prepared by Study Team based on MOEP materials (2013)
The main source of power generation in Myanmar is hydropower, which makes up most of total power generation.
The breakdown in 2010-2011 was 72% hydropower, 21% for gas and 7% for steam and diesel.
Figure1-14: Change in Power Generation by Source
（GWh）
10,000
8,625
9,000
8,000
7,000
5,608
6,000
6,064 6,164
6,398 6,622
6,964
Steam
5,118
5,000
Gas-fired
3,762
4,000
3,000
Deasel
Hydro
2,643
2,000
1,000
0
*Number above the graph shows the total power generation.
Source: Prepared by Study Team based on
“Statistical Yearbook 2011” by Central Statistical Organization of Myanmar
1-11
Due to the dependence on hydropower generation, the electricity supply drops in drier seasons, creating shortages
with supplies falling below demand to the extent that timed outages takes place regularly every dry season;
especially in Yangon city.
Figure1- 15: Demand and Supply for Electricity and Supply by Season (Estimate)
(MW)
5,000
4,500
4,000
4,584
Demand
Supply (dry season)
Supply (rainy season)
3,911
3,259
3,500
3,000
2,500
2,000
2,509
2,420
2,060
1,841
1,500
1,000
500
0
2013
2014
2015
Source: Prepared by Study Team based on MEPE materials (2013)
5.
Efforts and Issues to Resolve Electricity Shortages in Myanmar
As described above, due to electricity shortages in drier seasons, the MOEP plans to change the electricity source
structure from one centered on hydropower generation, to one more focused on gas-fired power generation. The
plan is to focus on developing around 2GW of power resources in Yangon.
1-12
Figure1-16: Plan for Developing Power Resources (2013-2016)
(MW)
8,000
7,000
6,000
5,000
The Others
470
Hydro
Gas-fired (except Yangon）
Gas-fired (Yangon）
4,000
120
1,099
3,000
2,000
2,259
2,494
244
1,000
0
2,760
(year)
471
2013
2016
Source: Prepared by Study Team based on MEPE materials (2013)
While expansion of gas-fired power generation facilities by the MOEP and IPP projects is moving forward, the
situation nevertheless remains that they cannot increase the electric-generation capacity of gas-fired power plants,
as natural gas supplies for power generation cannot be increased, due to the strains on domestic gas supplies. For
this reason, the MOEP asked for a public offering for LNG imports for thermal power plants in July 2013.
(3) Situation in Subject Areas
The subject area of this study is the Yangon Region, where there is a plan for building large scale gas-fired power
plants, that requires the government’s actions for gas imports.
1.
Current Situation of Gas-Fired Power Plants and Gas Pipeline Network in Yangon
Currently gas-fired power plants are located in four areas in Yangon: Hlawga; Ywama; Thaketa; and Ahlon, and
power plant expansion is in progress in each of these areas. The capacity of power plants was around 470 MW
before 2012, however, there are 5 more power plants (Zeya, MSP, EGAT, Toyo-Thai and CIC) that will start
operation or are planned to start operating between 2013 to September 2014, making total capacity around 520
MW. Furthermore, the IPPs plan to build three new power plants (BKB, UREC, Hydrolanchang) and are in
discussion with MEPE for the signings of MOUs (Memoranda of Understanding) for the Feasibility Study and/or
PPA (Power Purchase Agreement), being discussed with the thermal power section of MEPE. There also are
construction plans in Thilawa, Hlaingtharyar and Ayeyarwaddy.
1-13
Table1-2: Gas-Fired Power Plants in Yangon (Existing and Planning)
Name
Hlawga
Start year
Existing GT/ST
Zeya
Ywama
Ahlone
Hydrolanchang
（IPP,China)
Existing GT/ST
MSP
EGAT
Existing GT/ST
Toyo-Thai
Thaketa
Existing GT/ST
CIC
BKB
(IPP,Korea)
UREC
(IPP,China)
Hlaingtharyar
Thilawa
Ayeyarwaddy
1996/1999
2013.05
2014.02
2014.11
2015.05
1980/2004
2013.07
2014.02
1995/1999
2013.06
2014.09
1990/1997
2013.07
2015.02
2016.01
2014.12
2016.03
2016
2016
2021
Capacity
(MW)
154.2
26
28.55
243
243
70.3
52
240
154.2
82
39
92
53.6
167
336
127
386
500
50
500
Source: Prepared by Study Team based on information provided by the MOEPE and an interview with the
NEWJEC
Existing gas-fired power plants are connected to gas pipelines, and gas is also supplied from the offshore gas field
in Yadana. Expansion and the additional construction of pipelines is needed to enlarge gas supply capacity, as
there is no extra capacity in existing pipelines in Yangon city. According to what have been heard by the team
from the MOGE, the construction of a 30-inch gas pipeline network is planned on the same route as the existing
14-inch gas pipeline. It has also become clear that to connect an external pipeline to the existing gas pipeline
network, it will have to be connected from the South Dagon Junction near the Thaketa power plants.
1-14
Figure1- 17: Flow of Gas Supply in Yangon
Source: Prepared by Study Team based on information provided by the Yangon Electricity Supply Board (YESB)
1-15
Figure1-18: Pipeline Network in Yangon
Source: MOGE materials
2.
The Current Situation of Yangon River Basin and Andaman Sea
The Yangon River runs from Yangon into The Andaman Sea. The Yangon River is navigable for seagoing vessels,
and ships run via a pilot station in the estuary region to Yangon Port, near Yangon city and Thilawa Port, 25km
south of Yangon.
The difference between the high and low tides of the Yangon River is extreme3, and there is an extensive outflow
of soil. As a result, the colour of the river is muddy as far as the estuary mouth, as the soil carried away creates a
shallow sea bed. It is presumed that soil is suspended in the sea where the sea bed is shallow. According to
observations of the Yangon River area by the study team, there were no signs of large fishing boats operating, or
of plants such as mangroves often found in the tropics.
The Yangon River, Yangon Port and Thilawa Port are managed by the MPA (the Myanmar Port Authority).
3
According to interviews in the local area, the water depth is 6.4m at high tide, and 0.3m at low tide at Elephant
Point (where the water depth is shallowest).
1-16
Figure1-19: Map of Yangon River and its Basin
1-17
Chapter 2 Study Methodology
(1) Scope of Works
The objective of this study is to improve energy supplies in the Republic of the Union of Myanmar as Myanmar is
considering importing liquefied natural gas to improve the current domestic energy supply situation. This will be
done by comprehensively considering their needs such as: improvement of the existing facilities at lower costs; a
speedy commencement of operations; the suitability of temporary operations; reviewing the intake of LNG off the
shore from Myanmar (The Andaman Sea); and installation of a Floating Storage and Regasification Unit
(hereinafter, FSRU) and the improvement of energy supply in the country while also linking this facility to the
onshore gasification of the Myanmar Bay facilities.
Myanmar has promoted the development of natural resources through foreign capital, as a way to obtain foreign
capital while under the economic sanctions imposed at a time Under the usual scheme for natural resources
development, the Government of Myanmar (Myanmar Oil and Gas Enterprise), authorized schemes to be
executed with capital provided by foreign sources, while controlling over the resources developed, on condition
that 10% of output be shared for domestic use. Development of natural resources has advanced in Myanmar under
this rules and ordinances, with which the most of output are exported overseas, while domestic supply has
remained tight. Suppression of public dissatisfaction by the military government collapsed after democratization,
and the quick improvement of the current energy supply situation became necessary to improve living standard of
the population. Furthermore, development of LNG sourced has become the most important issue, due to the rise of
popular movements after nationwide democratization and sentiment against building new power generating
facilities that have large environmental impact, such as hydropower and coal-fired power.
Given the situation above, Myanmar is now planning to further drive the development of domestic natural
resources to improve supply and demand balance of primary energy. However, since the development of natural
resources requires a long period of time from planning to the start of production, even in an optimistic scenario,
actual improvements in the development of domestic natural resources could only take place after 2020. For this
reason, the government of Myanmar is planning to import LNG to improve the present balance of supply and
demand, while concurrently developing resources in order to improve the mid to long-term balance of supply and
demand. As offshore gas field development in Myanmar is progressing and pipeline networks are, to a certain
extent, in place, the important factors for realizing LNG imports are functioning for the creation of new LNG
intake facilities quickly and at lower costs, as well as assisting in dealing with the temporary strain on the balance
of supply and demand (around 10 years operation could be sufficient).
Taking the above situation into consideration, this study reviews energy supply and demand balance in Myanmar
forecast (including the current shortfall), options for LNG importation and LNG receiving facilities and
operational schemes, in addition to related issues for commercialization(e.g. decision of pipeline possession).
Below is the scope of work
i.
Summary of the country and sectors
ii.
Understanding the priorities of the commercialization process
2-1
iii.
Reviewing the sophisticated and rational use of energy
iv.
Demand predictions
v.
Reviewing the contents of the project and technical aspects
vi.
Reviewing the environmental/social aspects
vii.
Financial/economic feasibility
viii.
Implementation schedule of the project
ix.
Capability of the country’s implementing organizations
x.
The technical superiority of Japanese companies
xi.
Project fund securing forecasts
xii.
Action plans and issues for implementation
2-2
(2) Study Methodology and Structure
1.
Study Methodology
Below are the methods used for the study:
• Collecting information through the Internet (desk research in Japan)
•
Collecting information and data from companies and related Ministries in Japan
•
Collecting information and data from counterparts in Myanmar such as the Ministry of Energy (hereinafter,
MOE), Myanmar Oil and Gas Enterprise (hereinafter, MOGE) and Myanmar Electric Power Enterprise
(hereinafter, MEPE).
•
Collecting information and data by Field Research in Myanmar
•
Collecting information and data from Hearing Sessions and Discussions with counterparts in Myanmar
Figure2-1: Flow Chart of Study Methodology
2.
Structure of the Team
The Structure of the Study Team and Myanmar Counterparts are as below.
2-3
Table2-1: Members of the Survey Team and Areas in Charge
Company
Name
Koichiro Danno
Role
Project Manager
Analysis of
The Japan Research
Yutaka Miki
Environmental/Social
Aspects
Institute, Ltd
Yasuhiro Yamamoto
Survey Team
Yuko Kinoshita
Survey Team
Department / Position
Society & Industry Design
Senior Manager
Senior Manager
Consultant
Researcher
General Manager, Offshore
Yasushi Noma
Survey Team
Business Office, LNG Carrier
Division
Mitsui O. S. K.
Lines, Ltd.
Deputy General Manager, Offshore
Kazuya Sasaki
Survey Team
Division
Assistant Manager, Offshore
Shinsuke Umada
Survey Team
Division
Senior Manager, Business
Toru Itabashi
Survey Team
Development Department, Business
Promotion & Execution Division
Group Leader, Business
Hiroaki Nakamura
Survey Team
JGC Corporation
Project Engineer, Business
Tomohito Moteki
Survey Team
Yoshio Yatsuhashi
Noboru Kato
Sumitomo Mitsui
Takehisa Manabe
Banking
Corporation
Wijnand Van Eck
Analysis of Technical
Technical Adviser, LNG & Offshore
aspects
Strategy Department Division
Analysis of Economic/
General Manager,
Financial aspects
Investment Banking Asia
First Vice President, Project Finance
Financial aspects
Financial aspects
2-4
Head of Oil & Gas, Project Finance
Akira Hiyama
Teiko Kudo
Sumitomo Mitsui
Kenji Baba
Banking
Corporation
Shinji Isono
Yoshiyuki Morii
Wint Sandar
Financial aspects
Vice president, Project Finance
Project & Export Finance
Financial aspects
Department (Tokyo)
Financial aspects
Financial aspects
Head of Group, Growth Industry
Cluster Department, Project &
Export Finance Department
Vice President, Growth Industry
Cluster Department, Project &
Export Finance Department
Chief Representative, Yangon
Financial aspects
Representative Office
Financial aspects
2-5
Yangon Representative Office
Table2-2: Counterpart in Myanmar (Members who Participated in this Survey and Discussions)
(Pre-Field Survey)
Date
11 September
Organization/ Company
Yangon Electricity Supply Board
Chief Engineer
(YESB)
Executive Engineer, Chairman Office
Director, EPD
Ministry of Energy
Deputy, Director, EPD
(MOE)
General Manager (Pipeline), MOGE
Director(Planning), MPE
Deputy Director General
Power System Department,
12 September
Ministry of Electric Power (MOEP)
Myanmar Electric Power Enterprise
Director(finance),
Director (Planning)
(MOGE)
General Manager (Pipeline)
(MPE)
Ministry of Finance (MOF)
13 September
Director (Planning)
Deputy Director General, Budget Dept.
Central Statistical
Director
Organization(CSO)
Deputy Director
2-6
(First Field Survey)
Date
Director (Planning)
Director (Engineering)
(MOGE)
Director (Production)
Director (Finance)
30 October
Managing Director
(MEPE)
Executive Engineer
Deputy Chief Engineer
Deputy Director, Environmental Conservation Dept.
Myanmar Environmental
Conversation and Forestry (MECF)
Director (Policy and Planning), Environmental
Conservation Dept.
Master Attendant, MOT & MPA
Chief Civil Engineer, MPA
1 November
Myanmar Port Authority (MPA)
Deputy Chief Civil Engineer
Chief Engineer
(Second Field Survey)
Date
Chief Engineer Thermal Power Plant Department
Ministry of Electric Power (MOEP)
Deputy Director DEP
Executive Engineer Thermal Power Plant
Department
Deputy Minister
3 December
Ministry of Energy
Director General, Energy Planning Department
(MOE)
Managing Director for MOGE
Managing Director for MPE
General Manager(Pipeline)
(MOGE)
Planning
Department of Meteorology and
Director
Hydrology (DMH)
4 December
Deputy Director
MPA (Myanmar Port Authority)
Master Attendant, MOT & MPA
2-7
(Third Field Survey)
Date
Department/ Position
Managing Director
Director
(MPE)
Assistant Director
Assistant Director
Staff Officer
Energy Planning Department (EPD)
Staff Officer
Director (Planning)
(MOGE)
Director (Planning)
Director (Production)
Assistant Ex. Engineer (Production)
Assistant. Ex. Engineer ( Production)
(MOGE)
General Manager (Pipeline)
Executive Engineer (Mechanical)
Assistant Ex. Engineer (Transport)
Deputy Director
Department of Electric Power
16 January
Assistant Director
(DEP)
Staff Officer
Deputy Chief Engineer
Executive Engineer
Assistant Engineer
(MEPE)
Assistant Engineer
Assistant Engineer
Assistant Engineer
Executive Engineer (Chairman’s office)
Executive Engineer
Yangon City Electric Supply Board
Junior Engineer
(YESB)
Staff Officer
Staff
Staff
Foreign Economic Relation
Advisor for Aid Coordination
Department (FERD)
Directorate of Investment & Co.,
Administration (DICA)
Directorate of Industry
Deputy Director
2-8
Assistant Director
Ministry of Environmental
Director
Conservation and Forestry
Staff Officer
Ministry of Science and
Deputy Director
Technology
Deputy Director
Ministry of Finance and Revenue
Deputy Director, Budget Department
(3) Study Schedule
This study was conducted from September 27th in FY 2013 to February 21st in FY 2014.
Table2-6: Study Schedule
2013
September
October
2014
November December
January
February
Preparation for the field survey/
Information gathering
Pre-field survey
Preparation for the field survey/
Information gathering
The first field survey
Analysis of the result of the survey/
Preparation of the draft report
Mid-term reporting session
The second field survey
Analysis of the result of the survey/
Preparation of the draft report
Submission of the draft report
Preparation of the final report
The third field survey
Submission of the final report
Final reporting session
Table2-7: Schedule for Pre-Field Survey
Date
City
Visiting place
10 September (Tue)
Japan→Yangon
11 September (Wed)
Yangon→Naypyidaw
12 September (Thu)
Naypyidaw
MOE, MOEP, MOGE, MPE
13 September (Fri)
Naypyidaw
MOF, CSO
14 September (Sat)
Naypyidaw→Yangon→Japan
Time for traveling
Time for traveling
YESB, Japan Embassy, JETRO
Time for traveling
2-9
Table2-8: Schedule for the First Field Survey
Date
City
29 October (Tue)
Japan→Yangon
30 October (Wed)
Yangon→Naypyidaw
31 October (Thu)
Naypyidaw→Yangon
1 November (Fri)
Yangon→Japan
Visiting place
Time for traveling
MOGE, MEPE, MECF
Time for traveling
JICA, JETRO
Time for traveling
MPA
Time for traveling
Table2-9: Schedule for the Second Field Survey
Date
2 December (Mon)
3 December (Tue)
4 December (Wed)
5 December (Thu)
City
Visiting place
Japan→Yangon
Time for traveling
Yangon→Naypyidaw→Yangon
MOEP, MOE, MOGE, DMH
Time for traveling
JETRO, MPA
Yangon
Time for traveling
MPA (Site visit)
Yangon→Japan
Time for traveling
Table2-10: Schedule for the Third Field Survey
Date
15 January (Wed)
City
Visiting place
Japan→Yangon
Time for traveling
MOE, MOGE, MPE, MOEP, MEPE,
16 January (Thu)
Yangon→Naypyidaw→Yangon
YESB, MST, MECF, MOF
Time for traveling
17 January (Fri)
Yangon→Japan
Time for traveling
2-10
Chapter 3 Justification, Objectives and Technical
Feasibility of the Project
(1) Project Background: Why the Project Is Needed
1.
The Myanmar Government’s Development Programs in the Gas and Electricity Sectors; Priorities of
Projects Based on Future Prospects
a.
Ministry of Energy’s gas production and supply plans
As stated in Chapter 1 herein this document, Myanmar produces natural gas. Most of the produced gas within
Myanmar, however, is exported to China and Thailand, so the domestic gas demand cannot be sufficiently
satisfied. The MOE, which is responsible for oil and gas sector from gas exploration and production to
distribution, been promoting the development of offshore gas fields; Zawtika and Shwe fields are expected to start
gas production in 2014, and M3 field in 2020 (see the demand forecasts for specific production volumes). Since
the country’s economic growth is anticipated to increase the demand for gas, the development of additional gas
fields is currently underway. The MOE has divided onshore and offshore fields into blocks, and selected a
developer for each of the blocks through a bidding process.
Figure3-1: Gas Fields Field Development Zones in Myanmar
Source: Publicly available information from the MOGE (2012)
3-1
b. Ministry of Electric Power’s power source development plans
The Ministry of Electric Power (“MOEP”) has drawn up power development plan that covers years up to 2030.
The Ministry plans to increase power capacity in tandem with the demand growth. The MOEP plans to boost
power source capacity in tandem with an increase in demand, assuming that the demand for electricity will
continue to grow. As stated in Chapter 1, the MOEP plans to build more gas-fired power plants to secure
short-term power sources for the dry season, especially in Yangon where electricity is in great demand. These
plants are scheduled to start operating sometime between 2013 and February 2016, with their planned capacity up
to about 4.2 GW (see the table below).
Table3-1: Gas-Fired Power Plants Being Built or to be Built in Myanmar
Name
Zeya
Hlawga
Ywama
Hydrolanchang
（IPP,China)
MSP
EGAT
Ahlone
Toyo-Thai
Thaketa
CIC
BKB
(IPP,Korea)
UREC
(IPP,China)
Yangon
Hlaingtharyar
Thilawa
Ayeyarwaddy
Mawlamyaing
Other area
in Myanmar
2014
2014
2014
2016
2013
2014
2014
2015
2013
2015
2016
2014
2016
2016
2016
2021
2015
2016
Capacity
(MW)
26
28.55
243
243
52
240
82
39
53.6
167
336
127
386
500
50
500
98
132
2014
50
2015
2016
2016
2013
175
350
250
100
start year
Myanmar Lighting
Kyaukphyu/Rak
MOEP
hine State
Dawei Power
Kanpouk
Utilities
Myin Gyan
Myin Gyan
Kyause
Rental
Source: Prepared by Study Team based on information provided by the MEPE and the NEWJEC
Although the MOEP and IPP projects have been proceeding with the construction of additional gas-fired power
generation facilities, they have been unable to boost the natural gas supply for power generation, owing to the
tight gas supply-and-demand situation in the country.
3-2
Under these circumstances, the MOEP asked for a public bidding for importing LNG for gas-fired power
generation in July 2013. The team interviewed the MEPE and found out that this was to obtain gas for IPPs that
are supposed to newly engage in gas-fired power generation mainly in the Yangon area. Applications are received
and reviewed by the Yangon Electricity Supply Board (YESB), which is a Yangon-based government entity
owned by the MOEP.
2.
Project Scope and Expected Users
This study firstly examined the LNG supply chain from the LNG purchase to its consumption, and then clarified
certain project to be developed using expertise of private sector, in which Japanese enterprises will support to
install storage and regasification facilities (i.e., facilities for receiving LNG) and facilities for gas transport to the
point of demand or the point of delivery designated by gas users.
It is difficult to analyze future national gas demand with limited research period, which is acceptable for the
investment decision of LNG import facility,. Therefore, this research assumes that imported gas is used to meet
the demand only for gas-fired power generation based on the master plan developed by MEPE
The MEPE owned by the MOEP purchases from the MOE home produced gas supplied to existing gas-fired
power plants. Through the interview with the MEPE and other relevant entities The study team concludes that
MEPE will be able to play the same role for not only domestic gas produced but also imported LNG. Namely,
MEPE becomes the purchaser from LNG supplier and distributor to IPPs. Since MEPE is the sole entity to import
LNG in Myanmar, it is expected to have bargaining power to negotiate the LNG price with suppliers.
3.
Issues Expected in Case of Absence of the Project
Should LNG cannot be imported, or is imported with significant delay, the following problems could take place:
• A drop in the operating rates of gas-fired power plants, which eventually lead to frequent power failures
and longer outages
•
a.
An increase in hydropower and coal-fired power generation as long-term alternatives
A drop in the operating rates of gas-fired power plants, which then lead to frequent power failure and
longer outages
In Myanmar, the MOE allocates a supply of domestically produced gas to each sector for domestic consumption.
In recent years, 60 to 65 percent of the gas is allocated, and practically there is no policy or plan intending to cut
the gas supply to other sectors for increasing the percentage of gas for electric power generation. This is likely to
lead to a shortage of gas for gas-fired power plants, and eventually to severe electricity shortages.
In Myanmar, power supplies to plants and offices are opt to be cut if electricity for households is in short supply.
During the serious power shortages that were caused by lengthy outages in the dry season in 2012, industrial parks
had no electricity supply for the entire month of May. If power fails frequently for a prolonged period, Japanese
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companies currently operating or planning to operate in Myanmar will not be able to launch and continue their
economic activities.
b.
An increase in hydropower and coal-fired power generation as long-term alternatives
As stated in Chapter 1, there is a development plan for hydropower generation expected to begin in 2016. If LNG
cannot be imported and power shortages continue even longer than expected, it is likely that the required power
for hydropower generation will increase and more coal-fired power generation plants will be built. As details are
mentioned in Chapter 4, the development of hydropower generation may cause such problems as eviction of
residents in the mountainous regions and the destruction of the environment, and the development of coal-fired
power generation may trigger air pollution and coal ash disposal.
4.
Effects and Impacts of the Project
As stated above, domestic demand for natural gas has not been met in Myanmar. Natural gas is used not only for
power generation, but also for petroleum refinery, fertilizer production, iron and steel manufacturing, utility gas,
and other purposes. The natural gas supply is vital for Myanmar, in order to accelerate the economic development.
Adopting an FSRU will enable Myanmar to receive LNG with a relatively short lead time (two to three years).
This will contribute to balancing natural gas supply-demand, hopefully bringing the following effects:
• The operating rates of gas-fired power plants will rise and more electricity will be generated, which
will make outages shorter and less frequent.
•
Increased electricity supply will enlarge the national industrial platform increasing manufacturing and
production capacity of the country that will lead to improve standard of living of the population.
•
There will be larger domestic supplies of gas for petroleum refining, fertilizer production, iron
manufacturing and utility gas, which will strengthen cost competitiveness and increase industrial
production volumes.
5.
Alternatives to the Import of LNG
There are three alternatives to importing LNG using the FSRU: buying back exported gas, building onshore
facilities for receiving LNG and adopting a Shuttle Regasification Vessel (SRV).
To buy back exported gas, changes must be made to the sales contract signed with the importer country. The
contract is basically of long-term nature, so making changes to it may require the Myanmar government to make
bilateral compensation. Additionally, it requires time and money to build long-distance gas pipelines between gas
fields and Yangon, although the Myanmar government has already invested in to export gas to China and
Thailand. If this alternative is chosen, the government will be unable to recover part of the construction costs, or
will have to shift the unrecovered costs to domestic users because it is assumed the pipeline construction cost is
recovered from gas sales revenue.
Building onshore facilities for receiving LNG offers advantages over using an FSRU as onshore facilities can
be expanded without much trouble whilst being operated much stably than floating vessel operation off the shore
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As stated above, however, the Myanmar government hopes to import gas for gas-fired power plants as soon as
possible to meet the greatly increasing demand for electricity, and so installing an FSRU is an even more
attractive option, in light of time for completion for a vessel installation. Also, there is still a possibility that
LNG imports will not be needed if the development of new gas fields leads demand for imported gas fluctuate,
and more gas is domestically produced than planned. For example, two FSRUs (Golar Winter and Golar Spirit) in
Golar LNG’s project in Brazil are designed to be used at both the Pecém terminal and Guanabara Bay in Brazil.
Once installed, an installed FSRU can be relocated for a different project, so the government may sign a contract
for a fixed-term charter with a termination clause specified, assuming that there will be no more demand for
imported gas. In terms of cash flow, operating an FSRU is lower in capital expenditure (capex) and higher in
operating expenses (opex) than running onshore facilities.
To compare an SRV with an FRSU, the partner government’s requests, as well as the depth of water in the area
must be considered as physical constraints. The followings are findings of the team.
As the figure below shows, shallow waters extend from the shore of Yangon. They are 10m deep about 40 km
offshore, and 15m deep about 80 km offshore. To receive LNG, the water around the port needs to be at least 13m
deep, so that an average LNG carrier can enter safely. An SRV, on the other hand, moors at a floating structure
called a turret buoy as the regasification facility. The SRV and the buoy are connected offshore to regasify LNG
onsite (see the figure below). To moor the buoy, the water needs to be at least 100m deep. This means that an
SRV needs to travel 100 km from Yangon, so using the regasification facility in the Andaman Sea is not a realistic
option for Myanmar. Besides, building onshore facilities on the Yangon River is impossible because the water is
not deep enough, so LNG needs to be received at a location far from Yangon, and transported to the places of
consumption in the form of gas or electricity.
Figure3-2: Image of Turret Buoy Connected to an LNG Carrier
Source: Research on Offshore Bases for Receiving Natural Gas through an LNG Carrier with Regasification
Equipment, The Cooperative Association of Japan Shipbuilders; Japan Ship Technology Research Association,
2010
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It is worthy of note that an SRV should be one of the likely options for waters with adequate depths, as the vessel
requires less equipment, time and money to be adopted than an FSRU.
Figure3-3: Options for Receiving LNG
(2) Upgrading and Streamlining Energy Use
A steady supply of natural gas leads to the construction of natural gas-fired power plants, which will contribute to
meeting an ever-increasing demand for electricity. The adoption of natural gas-fired power generation also means
departure from that of coal-fired power generation, which will help reduce CO2 emissions.
As previously stated, there has not been a sufficient supply of electricity to meet demand in Myanmar. The
country developed mainly hydropower generation and coal-fired power generation, which caused serious damage
to the environment. Thus these power sources met opposition from the public, especially the communities of
ethnic minorities that suffered directly, and the development efforts have not made any progress since. So the
government of Myanmar is trying to shift its focus to conserving the environment, and it is likely that natural
gas-fired power generation will be adopted as an option that will enable the government to meet electricity
demand and protect the environment.
(3) Factors to Examine for Determining Project Contents
1. Demand Forecast
Demand estimation for LNG gas using the formula below:
Demand for LNG import = Quantity of gas needed for gas-fired power generation – Domestic gas
production x Percentage of gas distributed to electric sector
a.
Quantity of gas needed for gas-fired power generation
As mentioned earlier, the MOEP has drawn up power source development plans that cover years up to 2030.
This study assumes that additional gas-fired power plants will be built according to the plans. The current plans
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demonstrate that additional power plants will be completed by 2016 or 2017, and that the government will
ensure steady electricity supplies mainly through hydropower generation plants that require some development
period.
The team calculated the volume of gas needed until 2017 in accordance with the planned capacity of power
generation above. The calculations are based on information provided by the MOEP, and findings by NEWJEC
and the Kansai Electric Power Company, which have been entrusted by JICA with “The Preparatory Study for
Electricity Development Program in Myanmar.” it is assumed that gas-fired power generation plants will stay at
high operation rates (75%), meaning that gas demand will remain the same from 2017 onward (see the figure
below).
Figure3-4: Forecast of Gas-Fired Power Plants’ Capacity and Demand for Gas for Power Plants
Source: Prepared by Study Team based on information provided by the MOEP (2013) and research findings by
NEWJEC
With regard to the domestic gas production, many onshore and offshore projects are underway as mentioned
above, although many of them have not specified when production will begin and how much gas they aim to
produce except for certain gas fields.
This study assumes only the production volumes from the Zawtika, Shwe, and M3 gas fields, for which the
MOE is scheduled to launch development projects, as additional domestic gas production volumes. The supply
from domestic gas fields will be 290 BBtud between 2013 and 2014, and then 476 BBtud between 2020 and
2021. If no more new gas fields will be developed thereafter, the supply may drop as production volumes from
existing gas fields decrease (see the chard below).
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Figure3-5: Domestic Gas Supplies in Myanmar
Source: Prepared by Study Team based on information provided by NEWJEC
According to the MOE, how much domestic gas production will be distributed for electricity has not yet been
planned, while 60 to 80 percent of the gas production has always been reserved for electricity purposes. This
study assumed that the 65 percent of to be supplied by the MOE will be distributed to electricity during 2013
and 2014. Besides, although specific LNG supply sources have yet to be determined at this point, the team
envisaged that the calorific value of LNG will be 1,040 Btu/cf.
Given these assumptions, LNG demand for gas-fired power generation is expected to rise to 72 mmscfd
between 2013 and 2014, and then to 354 mmscfd between 2016 and 2017. From 2020 onward, the demand will
depend on trends in the development of new domestic gas fields, while it is expected to be around 350 to 450
mmscfd.
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Figure3-6: Demand for Imported LNG in Myanmar
2.
Identifying and Analyzing Issues before Exploring and Determining Project Details
This section shows what needs to be examined prior to implementation of the project.
a.
Where to install an FSRU
The waters where an FSRU is installed need to be at least 13m deep, so that a regular LNG carrier can make safe
entry and leave. Additionally, as the FSRU and an LNG carrier that comes alongside the FSRU need to berth
safely, it is desirable that the waters do not have much traffic, including fishing boats. For stable regasification
operations, the climate should be calm and the water should have as little floating sludge as possible, so that the
mud will not clog the equipment (e.g., seawater pumps). Also, it would be ideal for the location to be close to an
existing industrial port, and that, considering costs for building a pipeline, it is close to the place where there is a
demand for gas consumption.
b.
Finalizing FSRU specifications
A FSRU’s tank capacity, capability and specifications of regasification equipment, and a cost estimate will be
finalized in accordance with the volume of LNG to be received, and of the regasified LNG to be delivered. The
exact volume have yet to be determined, so the team will need to work closely with our counterparts to set out
more detailed specifications.
c.
Options for holding an FSRU
To opt for a form of holding an FSRU desirable for the counterpart in terms of costs (i.e., cash flow), the
prospective user of the FSRU needs to consider whether they will own the vessel, or charter it from the owner.
Options for holding an FSRU need to be carefully considered in terms of costs. The user of the FSRU has an
option of owing it or chartering it.
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d.
Options for introducing an FSRU
Another economic issue to examine the adoption of an FSRU is whether to have a new FSRU built, or to convert
an old LNG carrier as an FSRU with refurbishment and retrofit of regasification equipment and extra plumbing on
board.
e.
Jetty design
To determine how to moor an FSRU by a jetty, the flexibility, stability, safety and the size of LNG vessel must be
considered, in addition to the conditions of contract for LNG and the marine meteorology.
f.
Pipeline construction route and specifications
The construction route is determined in accordance with where the FSRU is installed, where regasified LNG is
delivered, and geographical and social conditions between the location of the FSRU and the point of delivery. The
pressure applied at the place of delivery, required components and heat value, and whether or not the pipeline will
be shared with the MOGE (i.e., whether it will be used for different purposes) are also factors determining
required facilities and equipment, a construction period and costs. Whether the pipeline route to the place of gas
supplying can be selected, designed, permitted and built at the right time is the major challenge.
g.
Financing pipeline construction
This project estimates USD514 million for adopting the provision of an FSRU, building a jetty and constructing a
pipeline. How to secure the fund needs to be carefully examined. Chapter 9 deals with this issue.
h.
How to obtain LNG
As stated in the section relevant to the project scope, sale and procurement of LNG is outside the scope of this
project. However, since whether or not LNG can be secured has a major impact on the feasibility of this project, it
should be examined.
3.
Examination of the Proposed Project Site: Conclusion
To determine the site of an FSRU installation, the team examined the distance to the pipeline connection point
(i.e., the place for delivering regasified LNG), while exploring the possibility of installing the unit offshore or at
the Yangon estuary. As previously stated, the waters need to be at least 13 m deep for a regular LNG carrier to
safely enter and leave. However, detailed data on the depth of water from recent years is unavailable, so the
team used a nautical chart to pick areas about 15 m deep just to be on the safer side. To determine the location
for installation, one must set out a detailed chart that shows the depth of waters in the proposed site before
detailed designing.
The team have selected the area 80 km off the Yangon estuary as the proposed site (see the figure below), after
examining the required water depth, the pipeline connection point the restrictions on pipeline routes to the point
(details will be provided later), and port facilities in the Yangon area now and in the immediate future. The area
is at the exterior of port area under the jurisdiction of the MPA, and is controlled by the government and the
military.
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Figure3-7: Depth of Water in and off the Yangon Estuary and Site for the FSRU
To supply regasified LNG to the gas-fired power plant in Yangon, the MOGE has requested that the pipeline
route be connected to S. Dagon in the Yangon region’s gas pipeline network that the MOGE plans to develop as
the owner (see the figure below).
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Figure3-8: Flow of Gas Supply in Yangon
Source: Prepared by Study Team based on information provided by the YANGON Electricity Supply Board
(YESB)
The project also needs to be consistent with the future expansion plans for the pipelines that the MOGE owns
and manages. The MOGE currently plans to construct pipelines from S. Dagon to Syrium, and then down to
Thilawa. This project prefers to transport gas via the same route from Thilawa to S. Dagon, the connection point,
so some adjustment will be needed during the planning phase. Currently, there is no pipeline expansion plan
below Thilawa, yet the team needs to check for any plans to build a domestic gas pipeline network associated
with the development project in Dawei, a city in the south of Myanmar.
With regard to pipeline, the team analyzed the three cases, considering location of FSRU, the distance and route
to the land, ensuring that the route between S. Dagon and Thilawa is in line with the Myanmar government’s
expansion plan. The required length of the onshore pipeline on the route will be 50 km (see the figure below).
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Figure3-9: Proposed Site for FSRU and Pipeline Routes
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Figure3-10: Details of Proposed Pipeline Routes
The Myanmar Port Authority (MPA) in charge of the Yangon River requested that the offshore gas pipeline
route bypass the Yangon River (i.e., the pipeline should not run across the riverbed)), if possible.
In addition, with the support by the Japanese government, Myanmar is exploring the possibility of building a
large deep-water port with good water depth just outside of the Yangon estuary4. One of the ideas relevant to a
berthing facilities is to build a jetty 35km off the coast, and to ensure that the water be maintained at least 14m
deep by dredging; the other is to dredge mud to lay a 40km waterway to the area, with the depth of 11m. Both
ideas envisage road construction as transport infrastructure between the large deep-water port and the land, and
set pipeline routes that bypass the road.
With the request from the MPA in mind, the team has adopted the third suggestion as the proposed idea. The
team will need to make adjustments to the onshore pipeline network in accordance with the pipeline network
planned by the MOGE, and to conduct detailed study on the routes below Thilawa considering the progress of
the development of the surrounding areas. With regard to the offshore pipeline, the team examined on the parts
immune from the plan for building the large deep-water port and other plans. If there is any possibility that a
4
Research on the Possibilities of Port-Related Projects in Myanmar, the Ministry of Land, Infrastructure,
Transport and Tourism, February 2013
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new waterway will run across the pipeline, one must consider burying part of the pipeline to a depth that will
not hamper the plan.
4.
How to Source LNG
To carry out this project, the feasibility of importing LNG along with installing LNG supply facilities must be
examined.
a.
Potential LNG Sellers
Given that LNG should be sourced promptly, potential sellers are countries/regions that already serve as major
LNG exporters. Most LNG purchase agreements are long-term ones, which mean that, even if the
country/region exports a large quantity of LNG, Myanmar cannot buy the portions secured for other importers
with long-term contracts. Therefore, the most likely candidates will be countries/regions that will agree a certain
number of short-term and/or spot sale contracts. The figure below shows the countries’ LNG exports, and how
much of the exports were sold in accordance with long-term, short-term, or spot agreements in 2012. As can be
seen, Qatar sold the largest quantity of LNG under short-term and spot agreements, with the amount being
almost triple Nigeria’s that is the second-largest. Myanmar needs 1 to 3 Mtpa25, and Qatar sells up to 21 Mtpa
based on short-term and spot agreements. Besides, Nigeria has 9 Mtpa and Trinidad and Tobago 5 Mtpa
(third-largest) saved for meeting expected demand based on short-term and spot agreements, and these countries
might be able to afford to sell some of the LNG to Myanmar (how to buy the LNG will be examined later in this
document).
The distance over which the tanker transports LNG also influences the procurement cost, although the cost is
not correlated with the final gas price. Of these three likely candidates, Qatar is the prime candidate, with its
geographical proximity to Myanmar and its capability to become the largest supplier.
5
Calculated on the assumption that the operating rate of the FSRU is 70 percent for 150 and 500 mmscfd.
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Figure3-11: LNG Exports by Country in 2012
* A short-term agreement refers to a contract for a period of up to four years.
Source: Prepared by Study Team based on The LNG Industry by GIIGNL
Qatar enters into many short-term and spot agreements for sale of LNG as she made a huge investment in
liquefaction plants to export LNG to the United Kingdom and the United States (see the figure below) until
2011, and today Qatar has to review its plans to sell the gas to the United States, that has begun to produce shale
gas. If Qatar finds another customer who will buy a large quantity of LNG, it may agree on sale that includes
long-term fixed contracts.
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Figure3-12: Capacities of Gas-Liquefying Facilities in Major LNG Exporter Countries
Source: Created by the research team based on The Multi-polarization of the Asia-Pacific LNG Market and the
Evolution of Business Models by Japan Oil, Gas and Metals National Corporation (JOGMEC)
In the mid- and long-term, the capacity of Australia’s liquefying facilities will increase, so LNG imports from
Australia will rise; the import of LNG from the Island of Mozambique in East Africa will also begin; and so will
the export of shale gas from North America to East Asia. If these lead to a situation where there is extra gas
produced in Australia and East Africa, Myanmar may switch over to purchasing gas from these regions.
Nevertheless, in the short-term, it is unlikely that Australia will become a source of imported LNG for Myanmar
because the gas that Australia exports is mostly tied to long-term agreements. Besides, the development of the
liquefying facilities may be delayed, so it is difficult to predict extra gas and sales prices. Hence, if LNG is to be
bought directly from a party with interests in a gas field, Qatar is the prime candidate at the moment.
b.
LNG procurement
There are three major means to buy LNG:
•
Gaining interests in a specific gas field, or establishing a long-term contract with a party that has
interests in the field
•
On the spot deal
•
Purchasing through the source from more than one gas field/region through a portfolio supplier
Gaining interests in a specific gas fields or signing a long-term contract with a party that has interests in the
field is more likely to promise a steady gas supply at a fixed rate than the other options, while it requires that the
volume to purchase be determined several years before the supply begins when the contract is signed. Since
demand may fluctuate as the construction of power plants proceeds during this project, a gap may appear
between LNG supply and demand. Besides, the demand that this project deals with is relatively low, so
investment for gaining interests may not be accepted.
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India and South American countries obtain LNG through spot deals. They often have to buy the energy source
at high prices as LNG demand that tends to increase followed with risk of fluctuated price. Also, depending on
the trend in supply and demand shifts, there may be no bidders and the amount of gas needed may not be
secured. Certain know-how is required to watch shifts in supply of and demand for gas and alternative energy
sources around the world, so that advantageous bids will be received regularly. Given that the government of
Myanmar has never imported LNG, spot bidding is too risky for the government to opt for at this time.
Singapore and other countries source LNG from more than one gas field/region through a portfolio supplier. In
this approach, the business that has interests in the gas fields/regions or liquefaction facilities obtains the
amount of gas needed in accordance with the supply-demand balance and prices at a time. The buyer can hedge
to the portfolio supplier the risks involved in obtaining the amount of gas needed. The buying price may be
higher than that offered through a long-term contract with a specific gas field/country, because this particular
mode of business takes the risks of sourcing LNG, whereas this strategy allows the purchaser to arrange the
volume of purchase more flexibly than they can through a long-term contract, when the buyer is not certain
about his requirement in quantity.
If LNG is sourced through a portfolio supplier, the gas obtained may vary in component and caloric value. This
study foresees that such variation is unlikely to cause operational problems because this project is for providing
gas for gas-fired power plants.
Table3-2: Means of Sourcing LNG by Comparison
“Big Oil” that refers to BP, BG, Shell, and other oil and gas companies in the West are major portfolio suppliers.
For example, BP is capable of providing at least 10 Mtpa. Some leading Japanese electricity and gas enterprises
also have track records as portfolio suppliers.
If LNG is purchased through a portfolio supplier, gas purchased through long-term agreements that the portfolio
supplier has already established, and gas purchased through short-term and spot agreements are consolidated for
sale. Shipping costs do not always correlate with gas prices, depending on individual interests in gas and market
conditions; to hold down shipping costs, each supplier’s interests in gas fields and liquefying facilities, along
with geographical relationships between the fields and/or facilities and Myanmar, are vital. Japanese utility
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companies also have built purchase portfolios that center on the Middle East and Southeast Asia to source LNG
for their Japanese customers, so they have geographical advantages in shipping LNG to Myanmar6.
In this project, the scale of demand is not very substantial. When the supplier purchases gas from a new seller
like Qatar, making a joint purchase of gas to meet demand from somewhere else will also help save the
supplier’s hardship that accompanies buying gas from a new seller, and boosting the capacity of sourcing LNG
will help hold down Myanmar’s LNG procurement costs. These are likely to become major options that will
bring advantages to both parties. In this light, suppliers with customers in Japan, the Middle East, and other
Asian regions are prime candidates.
Bearing all these factors in mind, purchasing gas from the portfolio suppliers’ existing supply sources, and from
Qatar as necessary, to supply it to the counterpart as a one-stop service is a realistic choice for the Myanmar
government that has not imported LNG when required time and effort along with risks involved in purchasing
are considered, even as the particular approach is likely to cost somewhat more than other options. Therefore,
suppliers capable of providing gas from regions geographically close to Myanmar are likely candidate sellers.
5.
Technical Approaches (compared to alternatives)
The team examined technical approaches to adopt the installation of an FSRU. The table below shows the
details and alternatives.
Table3-3: Technical Approaches (Compared to Alternatives)
Item to Examine
Suggestion
Alternative
Advantage of Suggestion
Site for FSRU and
East side of the
West side of the
The pipeline will not run across the Yangon River,
Pipeline Route
estuary
estuary
which the MPA prefers.
Options for FSRU
A newly-built
An old LNG
The specifications are highly flexible; the use of the
Facilities
FSRU
carrier converted
vessel can be ensured for a given period at a certain
to an FSRU
price; opex can be held down, and the vessel is
fuel-efficient.
Design of Jetty
Cross-jetty
Side-by-side
Since the FSRU will be installed off the coast, the
suggested design offers safety when help from tug
boats cannot be received immediately.
Size of Pipeline
24 inches
30 inches
Tailoring the size to demand helps hold down costs.
6
For example, Osaka Gas had bought LNG from Qatar, Oman, Malaysia, Indonesia, Australia, and Papua New
Guinea by 2011.
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a.
Options for using an FSRU
A Converted FSRU, which is an old LNG carrier refurbished and retrofitted as an FSRU will constitute one of the
options. Costs of used and not-so-old LNG carriers in good condition, however, are on the rise as the LNG market
is bullish, and is likely to be on the same trend. Considering the following factors, the cost merit that a converted
FSRU offers is not much greater than that of a newly-built FSRU:
• The engineering work for conversion needs to be customized to the LNG carrier.
•
If the carrier is an old vessel, extensive repairs and life extension work, such as mounting durable
outer panels, will be needed in addition to works for conversion.
•
Additionally, using newly-built FSRUs has become mainstream in recent years, owing to the
following disadvantages of an FSRU converted from an LNG carrier:
•
There are some constraints on the selection of specifications of a converted FSRU.
•
An FSRU converted from an LNG carrier requires higher maintenance and fuel costs than a new
FSRU when operation begins.
•
There will be some restrictions on receiving LNG carriers that have become increasingly larger in
recent years.
The chart below shows the qualitative analyses of new and converted FSRUs:
Table3-4: Features of New and Converted FSRU
Items
New FSRU
Remodeled FSRU
Service Life
Long
Medium
Flexibility of Specifications
Customized
Constrained
Maintenance Cost
Low
High
Capital Expenditure
High/Middle
Middle
Fuel Efficiency
Low
Middle/High
Flexibility of Size of LNG Carrier to Receive
High
Middle/Low
b.
FSRU specifications
The team assumed a newly-built FSRU with the tank capacity of 173,000 m3, which is close to the capacity of
150,000 – 160,000 m3, which represents the most popular case in capacity so far exercised.
As mentioned above, FSRU, having tank capacities of 130,000 to 150,000 m3 have been mostly in use, while the
173,000 m3 capacity tanks have become a standard size that has been ordered frequently in recent years. Also,
given that no engineering work is necessary, that the building time is short, and that costs can be bottom lined,
using a newly-built FSRU can therefore be the most desirable selection (see the table below).
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Launched in
2007
Table3-5: Materialized FSRU Projects
Project
Teesside Gasport (UK)
Tank Capacity
135,000 m3
2008
Northeast Gateway (USA)
2008
Bahia Blanca Gasport (Argentina)
2009
Mina Al-Ahmadi Gasport (Kwait)
2009
Petrobras VT1 (Pecem, Brazil)
151,000 m3
128,000 m3
2009
Petrobras VT2 (Guanabara, Brazil)
138,000 m3
2009-10
Neptune (USA)
145,000 m3
2010
Dubai LNG (UAE)
125,000 m3
2011
GNL Escobar (Argentina)
151,000 m3
2012
West Java (Indonesia)
125,000 m3
145,000 m3
151,000 m3
Table3-6: Ordered FSRU Projects
Year of
Completion
2013
Project Location
Tank Capacity
Italy
138,000 m3
2014
Petrobras VT3 (Guanabara, Brazil)
2014
Puerto Rico
173,000 m3
170,000 m3
2014
Jordan
2014
Lithuania
160,000 m3
170,000 m3
2014
Indonesia
170,000 m3
2014
Chile
170,000 m3
2015
TBD
170,000 m3
2015
TBD
170,000 m3
2015
TBD
170,000 m3
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For your information, the following are examples of FSRU projects.
Figure3-13: FSRU Project 1: “Side-by-Side” Approach (Escobar, Argentina)
Source: Mitsui O.S.K. Lines
Figure3-14: FSRU Project 2: “Cross Jetty” Approach (Pecem, Brazil)
Source: Golar
As for the capability of regasification equipment, team will consider how much gas the equipment can process to
meet the projected demand mentioned above. From the expected demand up to 2025, three pieces of the
regasification equipment in operation should be capable of supplying 360 mmscfd. Besides, since the demand is
projected to increase up to around 440 mmscfd, supplying up to 480 mmscfd should be possible at peak hours
when the fourth piece is put into operation. The regasification equipment on an FSRU is designed on the
3-22
assumption that an extra piece is put on standby to ensure certain operating rates, to fill demand at its provisional
peak, and to keep the regasification process running while maintenance is done for the main equipment. This
project also adopts this assumption for the design of suitable equipment.
An FSRU may or may not have an engine capable of navigation. The FSRU adopted in this project will have an
engine, so that it has a capability to be used as an LNG tanker in the future, if it is desired.
c.
Jetty design
The study team will further need to conduct detailed research on the submarine geology, the hydrographic
conditions, and the weather around the proposed site for FSRU installation. The team has so far learned through
an interview with the meteorological bureau that one or two typhoons hit the waters annually where the site is
located, yet these typhoons pass the continent to the east of the Andaman Sea before they reach the waters, and
thus they are relatively weak and predictable. With this information in mind, the jetty design is carried out on the
assumption that the hydrographic conditions are mild, and the FSRU will be moored by the jetty.
To boost the FSRU’s operating rates, the hydrographic conditions need to be mild. Provision of breakwaters may
have to be considered depending on the hydrographic conditions. If the conditions are harsh, the tower yoke
mooring system will be used instead of jetty mooring,; although the tower yoke system will lift up the cost.
Suitable mooring system will be designed after collecting and examining specific information in relevance.
There are two types of jetty mooring systems. One is called “side-by-side” in which an LNG carrier as a shuttle is
moored alongside the FSRU anchored by the jetty; the other is called “cross-jetty” in which the FSRU and an
LNG carrier as a shuttle are moored on either side of the jetty. The side-by-side system has a clear cost advantage,
while the cross- jetty system offers the following advantages:
• It can receive LNG carriers of any size, regardless of the size of the FSRU.
•
It offers greater stability of moored ships during loading and unloading than the side-by-side system.
•
It allows moored vessels to leave swiftly in an emergency.
3-23
Figure3-15: FSRU Mooring Systems (Top: Side-by-Side; Bottom: Cross-Jetty)
The location of FSRU will be as far away as 80 km from the port, which makes it difficult for tugboats to quickly
come to the rescue should the FSRU has to leave the jetty in an emergency. Therefore, the study team will assume
the design based on the cross-jetty system.
Besides, a piled structure can be considered to build the jetty. The team assumed the loading arms which can stand
against wave heights and tides.
d.
Size of pipelines
As previously stated, the MOGE plans to extend the pipeline from S. Dagon to Thilawa. The right size of the
pipeline that this study assumes depends on whether the team considers only the use of gas regasified from
imported LNG on the FSRU, or the team also considers the use of gas from a different source transported through
the existing pipeline connected to the extension. When the team considers only transporting gas through the
pipeline to S. Dagon, 24 inches can be an option to have a good balance with pressure and boost-up. On the other
hand, the MOGE currently plans to develop a pipeline network along the existing one in Yangon to supply gas to
IPPs newly engaging in gas-fired power generation, and the size of the pipelines for the network is 30 inches. A
larger size means higher operational flexibility and scalability, and greater costs. Despite the MOGE’s choice to
use 30-inch pipelines for the network, the team has adopted 24 inch pipelines because, as supply lines for
3-24
regasified LNG, they do not require much initial cost, and they have an extra transport capacity that can be tapped
into when gas will be carried for different purposes (e.g., consumer use) sometime in the future.
(4) Project Plan Outline
1.
Basic Policies for Determining Project Details
To solve electricity shortages as soon as possible, MOEP is considering LNG import for electric power
generation. As the demand forecast shows, the amount of gas needed is meant to fill the gap between a domestic
gas supply and gas demand based on the capacity of gas-fired power plants in the power source development
plan.
Given this background, MOEP has intention to realize quick start of LNG import. However, further discussion
on the detail including cost needs to be held through an organization with decision-making authority. In this
study, the team determined project details in accordance with the physical and financial restrictions mentioned
previously, and also with the needs of the various Myanmar government organizations which the team had
learned of through interviews.
2.
Conceptual Design and Specifications of Applied Facilities and Equipment
Facilities and equipment that this project uses are broadly classified into the following:
a.
a.
a. FSRU
b.
b. Jetty
c.
c. Pipelines
FSRU
The figure below is the schematic diagram of FSRU processes.
3-25
Figure3-16: Schematic Diagram of FSRU Processes
The table below shows the specifications of the FSRU based on the technical approaches to be adopted:
Table3-7: Main FSRU Specifications
Length Overall
294.5 m
Breadth Molded
46.4 m
Depth Molded
26.5 m
Scantling Draft
12.8 m
Dead Weight
About 83,200 metric tons
Tank Capacity
173,000 m3
Service Speed
18.0 Knots (21% sea margin)
Boil-off Rate
0.15%
Propulsion Engine
DFDE (Dual Fuel Diesel Electric)
Fuel
Boil off gas, HFO, MDO
3-26
Table3-8: Specifications of Regasification System
Regasification Technology
Sea Water heating with shell & tube vaporizer
Regasification Capacity
120 mmscfd x 4 machines
Maximum send-out amount: 480 mmscfd (4 machines
combined)
Regular send-put amount: 360 mmscfd (3 machines, 1 on
standby)
Gas Discharge Pressure
Minimum: 40 barg; Maximum: 100 barg.
LNG Cargo Loading Rate
8,000 m3/ hour
Gas Send-Out Temperature
b.
5.0 degrees celsius
Jetty
The team examined the technical approach and put together the following as summaries of required equipment.
The jetty is designed to receive an LNG tanker from which LNG is transferred to the moored FSRU, so that the
regasification equipment on the FSRU generates gas with the required pressure in accordance with demand at the
time, and the high-pressure loading arm sends out the gas into the pipeline. The following are the pieces of
equipment used in the process:
•
Imported LNG receiving loading arms (LNG: 2 sets; vapor: 1 set; common spare: 1 set)
•
LNG transfer loading arms (LNG: 2 sets; vapor: 1 set; common spare: 1 set)
•
High pressure natural gas send-out loading arm(s) (1 set if can possible to be produce)
•
Valve manifold related to the above
•
Emergency shutdown system
•
Nitrogen connection and piping
•
Loading arm operation system
•
Knock-out drums for vapor
•
Drain pump
•
Electric power distribution panel and system (utilities and power source will be received from the
FSRU)
The following pieces of equipment will be in place as part of the jetty facilities:
• Breasting dolphins
•
Mooring dolphins
•
Navigation aid
•
Radio communications, etc.
3-27
As stated in the section that explores the capacity of an FSRU, the size of the LNG tanker receiver is unidentified
at this point, because the seller from which Myanmar will buy LNG has not been selected. Hence, the team
considered the size that ranges between 125,000 m3 and 160,000 m3 to envisage the structures of the jetty and the
dolphins.
The system flow of the equipment and the schematic diagram are as shown below:
3-28
Figure3-17: System Flow of Jetty Equipment
3-29
c.
Pipelines
The pipelines will be laid offshore (subsea) and onshore.
The onshore pipeline will have a shutdown valve, and a valve station for connecting branched parts in accordance
with the design specifications defined by relevant codes and regulations. The onshore pipeline route that this
project plans crosses the large river at two points, so the pipeline will need to be buried at an adequate depth.
The right size of pipeline may vary depending on the use, so the team will need to discuss it with the MOGE. For
the purpose of examination in this study, the team envisaged that it will be 24 inches, which is the same as the
pipeline circling through the Yangon Region planned by the MOGE. There are pipelines that the MOGE has
already installed in accordance with its specifications. The team will need to keep checking with the MOGE to
ensure that the pipeline that this project builds is consistent with the specifications. At this moment, the team
envisages that the MOGE’s pipelines follow international standards. The figure below is the schematic diagram of
the pipeline.
Figure3-18: FSRU – Pipeline System Schematic Diagram
3.
Proposed Project Details (Site and Investment Cost for the Project)
a.
Project site
An FSRU should be installed80km offshore from the Yangon River, and a gas pipeline route will be laid up to
South Dagon in the existing pipeline network in Yangon. Please see Chapter 4 (3) 3 for details.
3-30
b.
Investment cost
The initial investment cost is approximately US$624 million, and the annual running cost say US$2.57 million.
The project cost does not include the costs for the construction and operation of the onshore pipelines, assuming
that the MOGE will bear these costs. The team also estimated that the initial expenses would be US$66 million if
the project was to be launched in Japan.
Please see Chapter 5 for details.
4.
Issues on Proposed Technologies and System; Solutions
a.
Project site and specifications
The project site and the specifications are set out in accordance with the followings:
• Details stated in the MOEP’s public offering for LNG imports asked in July 2013 and the needs behind
the call
•
Requests from concerned organizations based on the call
•
Technical and system reviewed basing on the physical constraints shown in existing literature
The Myanmar government’s needs may change as the development of domestic gas fields and of power sources
goes on, and detailed research on hydrographic conditions and other physical constraints may locate something
new, which may suggest a better place for installing the FSRU, and/or better technologies to apply. The study
must continue to find out with eye for wider range of subjects. In any case, this study at this junction of time will
serve as a benchmark for future discussions.
Besides, the study further needs detailed information about the water depths, the hydrographic conditions and the
climate in the area for more detailed consideration of the location for installing the FSRU, project expenses, and
running costs. And the team presume that earth and sand from the Yangon River are floating in the stretch of
shallow water. If the FSRU was to be installed in a dredged area with shallow water, the team would need to take
technical measures to prevent the plumbing in the FSRU from becoming clogged with the floating earth and sand.
b.
LNG berthing operation
A large vessel like an LNG shuttle tanker becomes difficult to steer and cannot easily change direction on its own
when it slows down, so tugboats will help LNG carriers to steer and control their speeds as they arrive at, and
leave the jetty. In general, four 3,000 to 4,000 h.p. tugboats will help an LNG carrier as it arrives at, and leaves the
jetty. Through an interview with the Yangon Port Authority, the team discovered that tugboats at Yangon Port,
which is a river port, have only 1,500 horsepower each, that is, the port does not have any tugboats with engines
powerful enough to navigate the ocean. For the new jetty to receive LNG carriers, new tugboats and crews of the
boats must be arranged, and where to anchor the boats and how to operate them around the jetty must be
determined. As the offshore location is fairly far away from land, further study must be done to locate reliable
sources of weather forecasts, and predictions of hydrographic conditions.
3-31
Chapter 4 Evaluation of Environmental and Social Impacts
(1) Analysis of Environmental/ Social Aspects
1.
Project Areas
The Andaman Sea and the Gulf of Martaban where the construction of the FSRU is planned alongside Yangon
and Thilawa Ports are particularly important areas. One of the key characteristics of the Gulf of Martaban is the
significant fluctuation of the sea level. The sea level varies from 4m to 7m at its highest. Tidal range at the time of
spring tide is 6.6 m, and the size of the areas affected is 45,000 km2. Even at the time of the neap tide, the tidal
range is about 3m and the size of the areas affected is 15,000 m2.
The FSRU must be constructed where there is a certain water depth level (15 m), and for areas with shallow-water
such as Yangon Port (9 m) and Thilawa Port (10 m), it will be impossible to construct. The MPA is in charge of a
fixed distance offshore of the Gulf of Martaban. This is a shallow-water area with 1m deep tidal flats at the
estuary of the Yangon River. It will be necessary to identify the appropriate spots from the marine area, which is
under the jurisdiction of the Navy, outside the areas of MPA jurisdiction in order to secure appropriate water
depth for the FSRU. The Gulf of Martaban is a maritime area with shoals, and its water depth is 5 m at 10 km
from the shore and 8 m at 25 km from the shore. It is currently assumed that 15m water depths can be secured 80
km offshore. The Andaman Sea provides good fishing grounds, and fishing and marine product processing
industries have developed in the South of Myanmar, including the Tanintharyi Division and Mon State. It is
assumed that there are rich marine resources and precious marine ecosystems such as coral reefs in the area where
the FSRU will be constructed. It is therefore necessary to further investigate the effect on the natural environment
in the project site, in order to make appropriate arrangements as necessary.
The use of the marine area under the Navy’s jurisdiction is strictly limited. It is necessary to exclusively own the
marine area under the jurisdiction of the navy to construct the FSRU while consulting with the Ministry of
Transport: MOT and the Navy, as it is the case with existing offshore gas fields. The Ministry of Livestock,
Fisheries and Rural Development is in charge of the fisheries industry, and issues three types of licenses for
coastal fishing, inshore and deep-sea fisheries. It is not known yet whether there are fishermen, who operate in the
FSRU construction marine area, but it will be confirmed and the impact on fishermen will be assessed in the
process of creating an Environmental Impact Assessment.
4-1
Figure4-1: Plan of the Constructions of FSRU and Pipelines
Source: Prepared by Study Team based on the materials provided by the MOGE and interviews of the MOGE and
MPA
2.
Future Forecast
The government of Myanmar is conducting early research into construction of a large deep-water port to be built
downstream of the Yangon River, although the concrete plan is yet to be concrete. There is a possibility that the
pipeline that connects FSRU with the existing pipeline network may interfere with the deep-water port project
depending on its location. Currently, the proposed plans include creating it by constructing an artificial island
offshore of the east of the estuary of the Yangon River, and creating it in the area of the Western channel (water
route used by ships to and from the Yangon Port). In case it is created by constructing an artificial island on the
east side, it is assumed that both will be affected, depending on the route of the pipeline.
(2) Environmental Improvement Achieved through Project Implementation
FSRU is one of the fastest methods to achieve LNG imports from overseas. The imported LNG will be used
mainly for power generation. Therefore, it is not expected that in comparison to the current situation, there will be
direct improvements in environmental measures such as emissions of pollutants or greenhouse gases. On the other
hand, if importing LNG is not possible or delayed considerably, it is anticipated that there will be an increase in
the construction of hydropower and coal-fired thermal power plants as alternative options to cover power supply
4-2
shortages. Hydropower has the advantage of reducing emissions of pollutants and greenhouse gases, compared to
thermal power. On the other hand, it will mainly be constructed in the mountainous regions, it is expected that
there will be destruction of the natural environment through development, as well as the eviction of residents from
the region. This has been the case with hydropower plants constructed in the past, where many residents were
forced to relocate.
With coal-fired thermal power plants, it is expected that air pollution and greenhouse gas emissions will be
reduced to some degree, if Advanced Ultra-Supercritical (A-USC) coal fired plants (the use of which is
increasingly supported in Japan) are chosen, and various measures for contamination control are implemented.
However, considering how it tends to be applied in ASEAN countries, contamination control is unlikely to be
sufficient and there is a high possibility that a Supercritical (SC) coal fired plant could be selected as the most
efficient of this type of plant, though it is less efficient compared to A-USC. There will also be an issue of coal
ash disposal with the use of a coal-fired power plant.
If natural gas-fired plants cannot be developed, hydropower and coal-fired thermal plants are likely to be
promoted, and the associated risks of environmental pollution and destruction will be counted for. The
environmental improvement associated with this project will be environmental conservation, where hydropower is
the baseline scenario, and the reduction in emissions of pollutants and greenhouse gas where coal-fired power is
the baseline. In terms of qualifying environmental improvements, taking the increased construction of coal-fired
thermal power plants as the baseline, quantifying the reduction in greenhouse gas emissions by applying CDM is
possible. Below are the methodologies applied to this study:
・ AM0029 Baseline methodology for grid connected electricity generation plants using natural gas
・ AM0087 Construction of a new natural gas power plant supplying electricity to the grid or a single
consumer
(3) Environmental and Social Impacts Associated with the Project
1.
Reviewing Environmental and Social Considerations
In order to assess the environmental and social impact of the project, and clarify the environmental and social
considerations required at the next stage of this research, we have evaluated items following a “List of
Environmental Checklists” of the “JBIC Guidelines for Confirmation of Environmental and Social
Considerations”, and the “JICA Guidelines for Environmental and Social Considerations”. The following tables
are the result of the evaluations.
4-3
Table4-1: Evaluations by “List of Environmental Checklists” for “Other Infrastructure Projects” in the “JICA
Guidelines for Environmental and Social Considerations”
Category
Environmental
Item
(1) EIA and
Environmental
Permits
Confirmation of Environmental
Main Check Items
Considerations
(Reasons, Mitigation Measures)
(a) Have EIA reports been already
(a), (b), (c): An EIA has not been
prepared in official process?
prepared for the project.
(b) Have EIA reports been approved by
(d): Legal systems related to the
authorities of the host country's
environment, including EIAs are
government?
being developed, and it is anticipated
(c) Have EIA reports been
that obtaining permits will become
unconditionally approved? If conditions
necessary.
are imposed on the approval of EIA
reports, are the conditions satisfied?
(d) In addition to the above approvals,
have other required environmental
permits been obtained from the
1 Permits
appropriate regulatory authorities of the
and
host country's government?
Explanati
on
(2) Explanation
to the Local
Stakeholders
(a) Have contents of the project and the
(a), (b): Information disclosure and
potential impacts been adequately
consultation with residents and
explained to the Local stakeholders
stakeholders has not been conducted,
based on appropriate procedures,
as the project is still at the planning
including information disclosure? Is
stage.
understanding obtained from the Local
stakeholders?
(b) Have the comment from the
stakeholders (such as local residents)
been reflected to the project design?
(3)
(a) Have alternative plans of the project
(a): The project is one of several
Examination of
been examined with social and
being planned including onshore LNG
Alternatives
environmental considerations?
construction.
(a) Do air pollutants, (such as sulfur
(a), (b): It is expected that mainly
oxides (SOx), nitrogen oxides (NOx),
natural gas will be used for FSRU
and soot and dust) emitted from the
operation, and emission of polluted
proposed infrastructure facilities and
materials and greenhouse gases are
ancillary facilities comply with the
expected to be limited. The emissions
country's emission standards and
and environmental standards have not
ambient air quality standards? Are any
been established at this stage.
2
Pollution
Control
(1) Air Quality
4-4
mitigating measures taken?
(b) Are electric and heat source at
accommodation used fuel which
emission factor is low?
(2) Water
Quality
(a) Do effluents or leachates from
(a): Cold water emitted from FSRU
various facilities, such as infrastructure
operation could result in lowered
facilities and the ancillary facilities
water temperatures. The degree of
comply with the country's effluent
impact and measures to reduce impact
standards and ambient water quality
will be reviewed in an impact
standards?
evaluation, which will be carried out
through an EIA at a later stage and in
discussion with stakeholders,
including fishermen. The emissions
and environmental standards have not
been established.
(3) Wastes
(4) Soil
Contamination
(a) Are wastes from the infrastructure
(a): The amount of waste materials
facilities and ancillary facilities properly
emitted by FSRU operation will be
treated and disposed of in accordance
minor, and likely to be disposed of
with the country's regulations?
appropriately.
(a) Are adequate measures taken to
(a): Not applicable as FSRU is an
prevent contamination of soil and
offshore facility.
groundwater by the effluents or
leachates from the infrastructure
facilities and the ancillary facilities?
(a) Do noise and vibrations comply
(a): Noise and vibrations are expected
with the country's standards?
to be generated by FSRU operation.
(5) Noise and
The country in question does not have
Vibration
fixed standards. It is assumed that
impact will be relatively small as the
facility is offshore.
(6) Subsidence
(a) In the case of extraction of a large
volume of groundwater, is there a
offshore facility.
possibility that the extraction of
groundwater will cause subsidence?
(a) Are there any odor sources?
(7) Odor
Are (a): Not applicable as no odor is
adequate odor control measures taken?
expected through LNG receipt with
the use of vaporization equipment.
4-5
(a) Is the project site or discharge area
(a): There are no protected areas near
located in protected areas designated by
or within the project areas.
(1) Protected
the country's laws or international
Areas
treaties and conventions? Is there a
possibility that the project will affect the
protected areas?
(a) Does the project site encompass
(a), (b), (c), (d): As FSRU is an
primeval forests, tropical rain forests,
offshore facility, it is possible to
ecologically valuable habitats (e.g., coral construct and operate the facility
reefs, mangroves, or tidal flats)?
while avoiding primeval forests,
(b) Does the project site encompass the
tropical rain forests and ecologically
protected habitats of endangered species
valuable habitats. However, it is
designated by the country's laws or
possible that such areas could be
international treaties and conventions?
affected by construction of the marine
(c) Is there a possibility that changes in
pipeline and land facility. The impact,
localized micro-meteorological
and measures to reduce impact, will
conditions, such as solar radiation,
be clarified in an impact evaluation
temperature, and humidity due to a
which will be carried out through an
Environ
large-scale timber harvesting will affect
EIA at a later stage.
ment
the surrounding vegetation?
3 Natural
(2) Ecosystem
(d) Is there a possibility that the amount
of water (e.g., surface water,
groundwater) used by the project will
adversely affect aquatic environments,
such as rivers?
Are adequate measures
taken to reduce the impacts on aquatic
environments, such as aquatic
organisms?
(3) Hydrology
(a) Is there a possibility that hydrologic
changes due to the project will adversely
offshore facility.
affect surface water and groundwater
flows?
(4) Topography
and Geology
(a) Is there a possibility the project will
cause large-scale alteration of the
offshore facility.
topographic features and geologic
structures in the project site and
surrounding areas?
4-6
(a) Is involuntary resettlement caused by
(a), (b), (c), (d), (e), (f), (g), (h), (i),
project implementation? If involuntary
(j): Not applicable as FSRU is an
resettlement is caused, are efforts made
offshore facility.
to minimize the impacts caused by the
resettlement?
(b) Is adequate explanation on
compensation and resettlement
assistance given to affected people prior
to resettlement?
(c) Is the resettlement plan, including
compensation with full replacement
costs, restoration of livelihoods and
living standards developed based on
socioeconomic studies on resettlement?
(d) Is the compensations going to be
4 Social
Environ
ment
paid prior to the resettlement?
(1)
(e) Is the compensation policies
Resettlement
prepared in document?
(f) Does the resettlement plan pay
particular attention to vulnerable groups
or people, including women, children,
the elderly, people below the poverty
line, ethnic minorities, and indigenous
peoples?
(g) Are agreements with the affected
people obtained prior to resettlement?
(h) Is the organizational framework
established to properly implement
resettlement? Are the capacity and
budget secured to implement the plan?
(i) Are any plans developed to monitor
the impacts of resettlement?
(j) Is the grievance redress mechanism
established?
4 Social
Environ
ment
(2) Living and
Livelihood
(a) Is there a possibility that the project
(a): As FSRU is an offshore LNG
will adversely affect the living
receiving facility, it could have an
conditions of inhabitants? Are adequate
impact on fishermen operating in the
measures considered to reduce the
area, by causing changes to fish
impacts, if necessary?
catches. It is possible to reduce the
4-7
negative impact by clarifying the
causes of the impact on fish catches,
such as lowered water temperatures
from cold water emissions, and
putting forward measures to reduce
such impacts.
(3) Heritage
(a): Detailed research has not yet been
will damage the local archeological,
conducted as the project is still at the
historical, cultural, and religious
planning stage.
heritage? Are adequate measures
considered to protect these sites in
accordance with the country's laws?
(4) Landscape
(a), (b): FSRU will be constructed in a
will adversely affect the local
relatively distant offshore area, and
landscape? Are necessary measures
the effect on the local landscape is
taken?
considered to be minor.
(b) Is there a possibility that landscape is
spoiled by construction of high-rise
buildings such as huge hotels?
(5) Ethnic
Minorities and
Indigenous
Peoples
(a) Are considerations given to reduce
(a), (b): There are no ethnic minorities
impacts on the culture and lifestyle of
or indigenous peoples nearby, or in
ethnic minorities and indigenous
the subject project areas.
peoples?
(b) Are all of the rights of ethnic
minorities and indigenous peoples in
relation to land and resources respected?
(6) Working
Conditions
(a) Is the project proponent not violating
(a), (b), (c), (d): Working conditions,
any laws and ordinances associated with
safety considerations and safety and
the working conditions of the country
health training will be clarified in an
which the project proponent should
impact evaluation that will be
observe in the project?
conducted through an EIA at a later
(b) Are tangible safety considerations in
stage.
place for individuals involved in the
project, such as the installation of safety
equipment which prevents industrial
accidents, and management of hazardous
materials?
(c) Are intangible measures being
planned and implemented for
4-8
individuals involved in the project, such
as the establishment of a safety and
health program, and safety training
(including traffic safety and public
health) for workers etc.?
(d) Are appropriate measures taken to
ensure that security guards involved in
the project not to violate safety of other
individuals involved, or local residents?
(a) Are adequate measures considered to
(a), (b), (c): The impact during the
reduce impacts during construction (e.g.,
construction period will be clarified in
noise, vibrations, turbid water, dust,
an impact evaluation which will be
exhaust gases, and wastes)?(b) If
(1) Impacts
construction activities adversely affect
stage.
during
the natural environment (ecosystem), are
Construction
adequate measures considered to reduce
impacts?(c) If construction activities
adversely affect the social environment,
are adequate measures considered to
reduce impacts?
5 Others
(a) Does the proponent develop and
(a), (b), (c): An EIA has not been
implement monitoring program for the
conducted for this project.
environmental items that are considered
(d): There are no legally binding rules
to have potential impacts?
on the methods and frequency of
(b) What are the items, methods and
reporting monitoring results.
frequencies of the monitoring program?
(c) Does the proponent establish an
(2) Monitoring
adequate monitoring framework
(organization, personnel, equipment, and
adequate budget to sustain the
monitoring framework)?
(d) Are any regulatory requirements
pertaining to the monitoring report
system identified, such as the format and
frequency of reports from the proponent
to the regulatory authorities?
4-9
(a) Where necessary, pertinent items
(a), (b): Not applicable
described in the Roads, Railways and
Bridges checklist should also be checked
(e.g., projects including access roads to
Reference to
Checklist of
Other Sectors
the infrastructure facilities).
(b) For projects, such as installation of
telecommunication cables, power line
towers, and submarine cables, where
necessary, pertinent items described in
the Power Transmission and
6 Note
Distribution Lines checklists should also
be checked.
(a) If necessary, the impacts to
(a): Not applicable
transboundary or global issues should be
Note on Using
confirmed (e.g., the project includes
Environmental
factors that may cause problems, such as
Checklist
transboundary waste treatment, acid
rain, destruction of the ozone layer, or
global warming).
Sources: “List of Environmental Checklists” for “Other Infrastructure Projects” in the “JICA Guidelines for
Environmental and Social Considerations” with added comments by Study Team
4-10
Table4-2: Evaluation by “List of Environmental Checklists” for Other Infrastructure Projects in the “JBIC
Guidelines for Confirmation of Environmental and Social Considerations”
Category
Environmental
Main Check Items
Item
Confirmation of Environmental
Considerations
(i) Have EIA reports been officially
completed?
(ii) Have EIA reports been approved
by authorities of the host country’s
government?
(iii) Have EIA reports been
(1) EIA and
Environmental
Permits
unconditionally approved? If
conditions are imposed on the
approval of EIA reports, are the
conditions satisfied?
(iv) In addition to the above
approvals, have other required
1 Permits
(i), (ii), (iii) An EIA has not been
prepared for the project.
(iv): Legal systems related to the
environment, including EIAs are
being developed, and it is anticipated
that obtaining permits will become
necessary.
environmental permits been
and
obtained from the appropriate
Explanation
regulatory authorities of the host
country’s government?
(i) Are contents of the project and
the potential impacts adequately
explained to the public based on
appropriate procedures, including
(2) Explanation
information disclosure? Is
to the Public
understanding obtained from the
public?
(ii) Are proper responses made to
(i), (ii): Information disclosure and
consultation with the residents and
stakeholders has not been conducted,
as the project is still at the planning
stage.
comments from the public and
regulatory authorities?
(i) Do air pollutants, (such as sulfur
oxides (SOx), nitrogen oxides
(NOx), and soot and dust) emitted
2 Mitigation
Measures
(1) Air Quality
from the proposed infrastructure
facilities and ancillary facilities
comply with the country’s emission
standards and ambient air quality
standards?
4-11
(i): It is planned that mainly natural
gas will be used for FSRU operation,
with emissions of polluted materials
and greenhouse gases expected to be
limited. The emissions and
environmental standards have not yet
been established.
(i): Cold water emitted from FSRU
operation could result in lowered
water temperatures. The degree of
(i) Do effluents or leachates from
impact and measures to reduce these
various facilities, such as
impacts will be reviewed in an
(2) Water
infrastructure facilities and the
impact evaluation which will be
Quality
ancillary facilities comply with the
carried out through an EIA at a later
country’s effluent standards and
stage, and in discussion with
ambient water quality standards?
stakeholders, including fishermen.
The emissions and environmental
standards have not yet been
established.
(i) Are wastes from the
infrastructure facilities and ancillary
(3) Wastes
facilities properly treated and
disposed of in accordance with the
country’s standards?
(i): The amount of waste materials
emitted by FSRU operation will be
minor and likely to be disposed of
appropriately.
(i) Are adequate measures taken to
(4) Soil
Contamination
prevent contamination of soil and
groundwater by the effluents or
leachates from the infrastructure
(i): Not applicable as FSRU is an
offshore facility.
facilities and the ancillary facilities?
(i): Noise and vibrations are expected
to be generated by FSRU operation.
(5) Noise and
(i) Do noise and vibrations comply
The country in question doesn’t have
Vibration
with the country’s standards?
fixed standards. It is assumed that
impact will be relatively small as the
facility is offshore.
(i) In the case of extraction of a
large volume of groundwater, is
(6) Subsidence
there a possibility that the extraction
of groundwater will cause
offshore facility.
subsidence?
(7) Odor
3 Natural
Environmen
t
(1) Protected
Areas
(i) Are there any odor sources?
(i): Not applicable as no odor is
Are adequate odor control measures
expected with LNG receipt and with
taken?
the use of vaporization equipment.
(i) Is the project site located in
protected areas designated by the
country’s laws or international
4-12
(i): There are no protected areas
within or near the project areas.
treaties and conventions? Is there a
possibility that the project will
affect the protected areas?
(i) Does the project site encompass
primeval forests, tropical rain
forests, ecologically valuable
habitats (e.g., coral reefs,
mangroves, or tidal flats)?
(ii) Does the project site encompass
the protected habitats of endangered
species designated by the country’s
laws or international treaties and
conventions?
(2) Ecosystem
and biota
(iii) If significant ecological impacts
are anticipated, are adequate
protection measures taken to reduce
the impacts on the ecosystem?
(iv) Is there a possibility that the
3 Natural
amount of water (e.g., surface water,
Environmen
groundwater) used by the project
t
will adversely affect aquatic
(i), (ii), (iii), (iv): As FSRU is an
offshore facility, it is possible to
construct and operate the facility
while avoiding primeval forests,
tropical rain forests and ecologically
valuable habitats. However, such
areas could be included in the land
facility. The impact, and measures to
reduce impact, will be clarified in an
impact evaluation which will be
carried out through an EIA at a later
stage.
environments, such as rivers? Are
adequate measures taken to reduce
the impacts on aquatic
environments, such as aquatic
organisms?
(i) Is there a possibility that
(3) Hydrology
hydrologic changes due to the
project will adversely affect surface
offshore facility.
water and groundwater flows?
(i) Is there a possibility the project
(4) Topography
and Geology
will cause large-scale alteration of
the topographic features and
geologic structures in the project
site and surrounding areas?
4-13
offshore facility
(i) Is involuntary resettlement
caused by project implementation?
If involuntary resettlement is
caused, are efforts made to
minimize the impacts caused by the
resettlement?
(ii) Is adequate explanation on
relocation and compensation given
to affected persons prior to
resettlement?
(iii) Is the resettlement plan,
including proper compensation,
restoration of livelihoods and living
standards developed based on
socioeconomic studies on
(1) Resettlement
resettlement?
(iv) Does the resettlement plan pay
particular attention to vulnerable
4 Social
groups or persons, including
Environmen
women, children, the elderly, people
t
below the poverty line, ethnic
(i), (ii), (iii), (iv), (v), (vi), (vii): Not
applicable as FSRU is an offshore
facility.
minorities, and indigenous peoples?
(v) Are agreements with the affected
persons obtained prior to
resettlement?
(vi) Is the organizational framework
established to properly implement
resettlement?
Are the capacity and
budget secured to implement the
plan?
(vii) Is a plan developed to monitor
the impacts of resettlement?
(i): As FSRU is an offshore LNG
(2) Living and
Livelihood
(i) Is there a possibility that the
receiving facility, it could have an
project will adversely affect the
impact on fishermen operating in the
living conditions of inhabitants?
area by causing changes to fish
Are adequate measures considered
catches. It is possible to reduce these
to reduce the impacts, if necessary?
possible negative impacts by
clarifying the causes of the impact on
4-14
fish catches, such as lowered water
temperatures from cold water
emissions, and putting forward
measures to reduce such impacts.
project will damage the local
(3) Heritage
archeological, historical, cultural,
(i): Detailed research has not yet been
and religious heritage sites? Are
conducted as the project is still at the
adequate measures considered to
planning stage.
protect these sites in accordance
with the country’s laws?
(4) Landscape
(i): FSRU will be constructed in a
project will adversely affect the
relatively distant offshore area, and
local landscape? Are necessary
the effect on the local landscape is
measures taken?
considered to be minor.
(i) Does the project comply with the
(5) Ethnic
Minorities and
Indigenous
Peoples
country’s laws for rights of ethnic
minorities and indigenous peoples?
(i), (ii): There are no ethnic
(ii) Are considerations given to
minorities or indigenous peoples
reduce the impacts on culture and
nearby or in the subject project areas.
lifestyle of ethnic minorities and
indigenous peoples?
(i) Is the project proponent not
violating any laws and ordinances
associated with the working
conditions of the country which the
4 Social
project proponent should observe in
Environmen
the project?
t
(ii) Are tangible safety
(6) Working
conditions
considerations in place for
individuals involved in the project,
such as the installation of safety
equipment which prevents industrial
accidents, and management of
hazardous materials?
(iii) Are intangible measures being
planned and implemented for
individuals involved in the project,
such as the establishment of a safety
4-15
(i), (ii), (iii), (iv): Working
conditions, safety considerations and
safety and health training will be
clarified in an impact evaluation that
will be conducted through an EIA at
a later stage.
and health program, and safety
training (including traffic safety and
public sanitation) for workers etc.?
(iv) Are appropriate measures being
taken to ensure that security guards
involved in the project do not
violate safety of other individuals
involved, or local residents?
(i) Are adequate measures
considered to reduce impacts during
construction (e.g., noise, vibrations,
turbid water, dust, exhaust gases,
and wastes)?
(1) Impacts
during
Construction
(ii) If construction activities
adversely affect the natural
environment (ecosystem), are
adequate measures considered to
reduce impacts?
(i), (ii), (iii): Impact during the
construction period will be clarified
in an impact evaluation which will be
stage.
(iii) If construction activities
adversely affect the social
environment, are adequate measures
considered to reduce impacts?
(i) Does the proponent develop and
5 Others
implement monitoring program for
the environmental items that are
considered to have potential
impacts?
(ii) Are the items, methods and
(2) Monitoring
frequencies included in the
(i), (ii), (iii): An EIA has not been
monitoring program judged to be
conducted for this project.
appropriate?
(iv): There are no legally binding
(iii) Does the proponent establish an
rules on the methods and frequency
adequate monitoring framework
of reporting monitoring results.
(organization, personnel, equipment,
and adequate budget to sustain the
monitoring framework)?
(iv) Are any regulatory requirements
pertaining to the monitoring report
system identified, such as the format
4-16
and frequency of reports from the
proponent to the regulatory
authorities?
(i) Where necessary, pertinent items
described in the Roads, Railways
and Bridges checklist should also be
checked (e.g., projects including
access roads to the infrastructure
Reference to
Checklist of
Other Sectors
facilities).
(ii) For projects, such as installation
of telecommunication cables, power
(i), (ii): Not applicable
line towers, and submarine cables,
where necessary, pertinent items
described in the Power
6 Note
Transmission and Distribution
Lines, and Pipelines checklists
should also be checked.
(i) If necessary, the impacts to
transboundary or global issues
Note on Using
Environmental
Checklist
should be confirmed (e.g., the
project includes factors that may
cause problems, such as
(i): Not applicable
transboundary waste treatment, acid
rain, destruction of the ozone layer,
or global warming).
Sources: “List of Environmental Checklists” for “Other Infrastructure Projects” in the “JBIC Guidelines for
Confirmation of Environmental and Social Considerations” with added comments by Study Team
4-17
2.
The Environmental Impacts of the Alternative Proposals
We have presented three proposals in Chapter 3 as alternatives to LNG import using FSRU: buying back exported
gas; building onshore facilities for receiving LNG; adopting a Shuttle Regasification Vessel (SRV). Below are the
expected possible environmental impacts of each proposal.
Table4-3: The Environmental Impacts of the Alternative Proposals
Alternative Proposals
Possible Environmental Impacts
Buying back exported gas
Currently, the only gas pipeline available is used for export purposes, and it would
be necessary to lay a long distance gas pipeline from the gas field to Yangon. It is
possible that constructing the pipeline could cause mid to long term impact on the
environment through causing a disturbance to the ocean bed, depending on the
pipeline route.
Building onshore facilities
Environmental impacts could include an impact on the landscape, involuntary
for receiving LNG
relocation of the residents and groundwater pumping, all caused by the construction
of major facilities on the ground.
Adopting SRV
It is necessary to construct a Turret Buoy regasification facility in the marine area at
depths of more than 100m to use a SRV, which will have to be constructed 100km
offshore in the case of the Andaman sea marine area. It is technically and
financially difficult to send natural gas from turret buoy facilities and even if
possible, a long distance gas pipeline would have to be laid -possibly causing mid to
long term environmental impacts, through construction disturbances to the ocean
bed.
It is necessary to carry out a detailed investigation of each alternative plan through concrete research. Given the
conditions of the marine area of the Yangon River and the Andaman Sea, it is anticipated that the facilities will
have to be constructed farther away from the area where the FSRU is expected to be constructed, and also from
Yangon, whichever alternative plan were to be realized. In this case, it could be the case that the environmental
impact will be larger compared to the construction of the FSRU.
3.
Result of Information Collected on Environmental and Social Impacts
According to an interview with the Myanmar Environmental Conservation and Forestry Ministry (MECF) which
is responsible for environmental administration in Myanmar, projects that are expected to conduct an EIA
(Environmental Impact Assessment) are those that exceed a project size, determined according to types of projects.
Those projects smaller than a certain size, are expected to be followed with an IEE only (Initial Environmental
Examination). It is anticipated that even for those operations taking place on the shore, the same EIA process of
MECF will be applied. Below are the details of the types and sizes of projects, accordingly.
・ For gas-fired power generation, an IEE is required for 5-50 MW plants, and an EIA is required for those
over 50 MW.
・ For gas pipelines, an IEE for under 10km and an EIA for over 10 km.
4-18
With regard to FSRU, there is no criterion at present. Like for instance, for an oil storage facility, the IEE process
is required for sizes from 100,000 to 1,000,000 liters, and the EIA process is required for sizes over 1,000,000
liters.
The MECF will review and make decisions as to whether the EIA process is required, or not, on currently running
projects. This project consists of 3 components that are, FSRU, underwater gas pipelines and above ground
pipelines, and MECF’s view is that these can be addressed together in one EIA report.
Apart from MECF’s regulations, MIC (Myanmar Investment Commission) Law and MIC regulations require
submission of a report during the business approval process of large scale operations, such as oil and gas
businesses, hydropower generation business and electricity transmission business. Therefore, an EIA has already
been partly applied in certain businesses. Currently, EIA consultants who conduct EIA internationally, and are
registered with EIA consultants agencies etc. are asked to submit reports to the government, though MECF does
not have registered EIA consultants. For example, the offshore gas production business which is already in
operation in Yadana has submitted an EIA report. MECF uses the report of this business operation as a good
example. As for examples of projects cancelled due to rejected EIAs, one project was cancelled, as there was a
possible risk of destruction of national cultural heritage by its hydropower generation business.
4-19
(4) Overview of the Country’s Environmental and Social Related
Regulations and Necessary Measures
1.
Overview of Regulations and Schemes Related to the Environment
MECF, which is responsible for administration of environmental matters, was established in 2011. The
Environmental Conservation Law was established in 2012 in order to deliver sustainable development and
conservation of the environment. The Government of Myanmar has shown a proactive approach, partially revising
the law after its introduction.
Myanmar’s environmental conservation rules are currently under development and the EIA process is being
reviewed during this process. The EIA process is being drawn up with support from JICA and ADB, referring to
international regulations laid by the ADB and the IFC.
2.
EIA Related Matters
It is likely that the EIA process will need to be checked by third party environment consultants who have been
approved and registered by MECF. However, the criteria for approval of environmental consultants are currently
being discussed and the detailed list of consultants is yet to be compiled.
Since no standard has currently been issued related to EIA by MECF, each business operator selects its own
standard when submitting EIA reports to MIC. Therefore, some business operators use IFC standard to compile
EIA reports or use their countries’ standards when submitting EIA reports.
The EIA process will be the same regardless of the types of owners of businesses, whether it’s governmental
organizations or private businesses. However, specific operations such as nuclear power generation are an
exception and the parliament will make the decision on approval.
It is assumed that the EIA admission process will be completed within 90 days of MECF receiving EIA reports.
The 90 days include public hearing process. It is assumed that IEE admission process will be completed within 60
days.
4-20
(5) Requirements to Deliver Projects in This Country (by Implementing
Organizations and Related Organizations)
To construct FSRU and start the receiving of LNG in Myanmar, it is necessary to get permission and
authorization from the related ministries including MIC, which requires submission of EIA reports. Also, although
the EIA-related process and liability are yet to be confirmed, it is currently under discussion and it is assumed that
the legal system will be developed in a few years. Below is the list of items that are the necessary course of
actions to be taken by the Myanmar side as to the execution of the project, from an environmental and social point
of view.
・ Development of EIA and IEE, as well as other emission standards and environmental standards
・ Registration and training of EIA consultants
・ Implementation of EIA and IEE (based on the above legal development)
・ Collaboration and promotion of agreement with project related groups (energy related organizations and
managers of harbors), local governments.
・ Provide thorough explanations and occasions to discuss for stakeholders such as fishermen.
4-21
Chapter 5 Financial and Economic Evaluation
(1) Estimated Project Costs
1.
Cost Estimate Breakdown
The costs of project include the following cost elements:
a.
Production and Construction Costs
1) Equipment costs
Equipment costs include design/production/material purchases/inspection and transport. The main cost
components of costs includes FSRU, jetty and sea pipelines. See Chapter 3 (4) for detailed specifications of
equipment.
2) Construction work costs
Construction work costs for the above equipment and buildings
b.
Consulting services and fee
c.
Operating costs
This cost includes the operational costs of the FSRU, jetty and pipeline including labor, utilities, repair, insurance
and general management costs.
d.
Other costs and expenses (interest and taxes)
Taxes and financial levies, such as interest, corporation, and commercial taxes, as well as custom duties have been
included. Inflation has also been factored in. However, such costs should be verified during an upcoming
examination, as they may be subject to further taxation.
2.
Project Costs
a.
Production and construction costs
Illustrated below is the brief breakdown of the project cost assuming that each equipment/construction project
includes construction at site for a certain period of time, the cost is partly shown in the local currency. The costs
below include a contingency. Costs for constructing and operating land pipelines are not included in the
operational costs by assuming they will be paid by MOGE. However, just in case that our side has to assume these
costs, the initial cost was estimated at US$ 66 million.
5-1
Table5-1:Plan of the Constructions of FSRU and Pipelines
Cost
Foreign
(converted
Currency
USD$1 million)
(USD$1 million)
Expense Items
Construction/Equipment Cost Total
Local Currency
514
460
52,503
FSRU
278
264
13,622
Jetty
82
57
23,936
154
138
14,945
Pipeline (offshore)
1USD =973MMK
b.
Consulting services costs/fee
Mentioned below is the consulting service cost/ fee.
Table5-2: Consulting Cost
Cost
Expense Items
(converted USD$1
million)
Consulting Cost/fee
Foreign Currency
Local Currency
(USD$1 million)
15
12
3,748
in total
1USD =973MMK
Sources: Prepared by Study Team
c.
Operating costs
The cost given hereunder below includes those cost elements needed for a trial operation period, during which
time, a trial will be conducted on the condition that one regasification facility runs for a month including spare
facilities. The cost below is based on operating three regasification facilities after the operation has started. Utility
costs include the cost of fuel for FSRU operation, and are subject to change according to the number of
regasification facilities in operation.
5-2
Table5-3: Operational Costs
Trial Operation Period
Operating Period
(USD$1 million)
(USD$1 million/year)
Labor Costs
0.6
6.8
Utility Costs
0.3
10.8
Repair Costs
0.3
3.6
General Management
0.2
2.2
0.1
0.7
Costs/Expenses
Insurance Premium
1USD =973MMK
Table5-4: Utility Costs according to the Number of Regasification Facilities in Operation
Number of regasification facilities in
Regasification Capacity
Utility Cost
operation (per plant)
(mmscfd)
(USD$1
million/year)
1
120
7.3
2
240
9.0
360
10.8
3
1USD =973MMK, Fuel price assumption: LNG Price at $14/mmbtu
The above operating costs are subject to the LNG purchase contract, and are based on the assumption that the
contract is to purchase LNG at the CIF price, and does not include costs related to the handling of jetty
docking/undocking of LNG tankers (tug boats chartering costs, etc.). The Myanmar Port Authority does not own
enough tug boats to handle LNG tankers, and the cost of purchasing 4 tug boats is presumed to be around 32.0
MMUSD in total, in the case that a new business operator makes the purchase.
d.
Taxes and financial levies
•
Borrowing rate
Set the beginning rate at 13% (including ECAs guarantee charge and banking establishment handling fee),
•
and 3% during the loan period.
Corporate tax
Set at 25% on assumption that a corporation will be set up under the foreign investment law.
•
Commercial tax (value-added tax)
The tax rate differs according to the items. While daily commodities are non-taxable, tax for items for
personal consumption (cigarettes) is 8-100%. It is assumed that the project falls under other items, and the
•
assumed tax rate is 5%.
Custom duties
5-3
All imported goods are subject to custom duties. A rate of 0.5% of the import price, which is the basic rate of
•
assessment for imported goods, has been applied.
Inflation rate
The team have applied the average 2011, 2012 figure of 2.8% from the IMF statistics.
3.
Disbursing Plan of Project Costs
Below is the plan of the costs disbursement until the commencement of the project.
Table5-5: Project Cost Contribution Plan
Unit：MMUSD
Business year
-5
-4
-3
-2
-1
Construction/Equipment costs
0.0
0.0
205.4
154.1
154.1
Consulting fees
4.6
4.6
3.1
1.5
1.5
Commercial taxes
0.2
0.2
9.3
7.0
7.0
Custom duties
0.0
0.0
0.9
0.4
0.4
Handling Fee of Interest
0.0
0.0
39.7
0.0
0.0
Interest during construction
0.0
0.0
6
10
14
5
5
264
173
177
Total
1USD =973MMK
5-4
(2) Summary of the Result of Preliminary Financial/ Economic Analysis
1.
Financial Analysis
The feasibility of the business under the project, which is to construct and operate the FSRU/pipeline and
transport the supplied LNG to the spots designated by the consumers, has been identified. The cash flow was
developed under certain preconditions to work out the NPV, B/C and FIRR.
a.
Preconditions of financial analysis
Table5-6: Financial Analysis Preconditions
Project period
25 years
5 years
Operating period
20 years
360 mmscfd
Profit
approx. $14/mmbtu)：$135 million/year
Initial cost
624 MMUSD
Operating cost
24.0 MMUSD /year
Capital ration
25%
Depreciation period
FSRU, jetty：20 years, Pipeline: 10 years
Corporate tax rate
25%
Commercial tax
5%
Custom duties
0.5%
Hurdle rate of FIRR
Case1: The location of the FSRU is 100 km offshore (80 km for the base
case)
5-5
b.
Result of evaluation
Table5-7: Result of Calculation of Performance Indicators
132MMUSD
165%
IRR
11.5
Case1:IRR_offshore100km
10.5%
Case2:IRR_operation period is 10
6.9%
years
This study has revealed that the project has good viability in terms of financial aspect even if a chartering cost per
year is USD 165 million and even if the FSRU is installed 100km offshore, reaching the level of the long-term
interest of 10% in Myanmar. If the duration of operations is cut by 50% to 10 years with the chartering cost
unchanged, IRR will remain at 6.9%. If the chartering cost is changed to USD 200 million per year, the IRR will
be 10.0%. (Refer to the table below.)
Table5-8: IRR Analysis for Several Chartering Cost（Case2: The Operational Period is 10 years）
chartering cost
(USD$1 million)
IRR
135
6.9%
145
8.3%
155
9.6%
160
10.3%
5-6
The tables below show the project cash flow.
Table5-9: FIRR Calculation Cash Flow (Base case)
-4
2014
Sales Amount
Operation M anagement M aintenance Cost
Depreciation cost
Income
Repayment of Interest
Profit for the Quarter before Tax
Corporation Tax
Profit for the Quarter after Tax
Cash Inflow
Cash Outflow
DSCR
IRR
Sales Amount
Depreciation cost
Income
Corporation Tax
Cash Inflow
Cash Outflow
DSCR
Fixed Property
-2
2016
-1
2017
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
%
Fixed Property
-3
2015
0
2018
11
1
0
10
0
10
0
10
1
2019
135
58
33
77
-14
63
16
47
2
2020
135
58
33
77
-13
64
16
48
3
2021
135
58
33
77
-12
64
16
48
4
2022
135
59
33
76
-11
65
16
49
5
2023
135
59
33
76
-10
66
16
49
6
2024
135
59
33
76
-10
66
17
50
7
2025
135
59
33
76
-9
67
17
50
8
2026
135
60
33
75
-8
68
17
51
81
32
2.06
480
81
32
2.10
447
82
32
2.14
414
82
32
2.17
380
83
32
2.21
347
83
32
2.25
313
84
32
2.29
280
84
32
2.34
247
0
0
67
41
10
49
0
11.5%
0
205
360
514
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
9
2027
135
60
33
75
-7
68
17
51
10
2028
135
60
33
75
-6
69
17
52
11
2029
135
45
18
90
-5
85
21
64
12
2030
135
46
18
89
-4
86
21
64
13
2031
135
46
18
89
-3
86
22
65
14
2032
135
46
18
89
-2
87
22
65
15
2033
135
47
18
88
-1
87
22
66
16
2034
135
47
18
88
0
88
22
66
17
2035
135
47
18
88
0
88
22
66
18
2036
135
48
18
87
0
87
22
65
19
2037
135
48
18
87
0
87
22
65
20
2038
135
48
18
87
0
87
22
65
MMUSD
MMUSD
MMUSD
85
32
2.38
213
85
32
2.43
180
82
32
2.37
162
82
32
2.42
144
83
32
2.48
126
83
32
2.53
108
84
32
2.59
90
84
0
84
0
83
0
83
0
83
0
72
54
36
18
-0
Table5-10: FIRR Calculation Cash Flow (Case1: The Location of the FSRU is 100 km)
-4
2014
Sales Amount
Depreciation cost
Income
Corporation Tax
Cash Inflow
Cash Outflow
DSCR
Fixed Property
IRR
Sales Amount
Depreciation cost
Income
Corporation Tax
Cash Inflow
Cash Outflow
DSCR
Fixed Property
-3
2015
-2
2016
-1
2017
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
%
0
2018
11
1
0
10
0
10
0
10
1
2019
135
62
37
73
-15
57
14
43
2
2020
135
62
37
73
-14
58
15
44
3
2021
135
62
37
73
-13
59
15
44
4
2022
135
63
37
72
-12
60
15
45
5
2023
135
63
37
72
-11
61
15
45
6
2024
135
63
37
72
-10
61
15
46
7
2025
135
64
37
71
-9
62
16
47
8
2026
135
64
37
71
-8
63
16
47
80
34
1.92
515
81
34
1.95
478
82
34
1.99
440
82
34
2.02
403
83
34
2.06
366
83
34
2.09
329
84
34
2.13
292
84
34
2.17
254
0
0
73
44
10
53
0
10.5%
0
221
386
552
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
9
2027
135
64
37
71
-7
64
16
48
10
2028
135
65
37
70
-6
64
16
48
11
2029
135
46
18
89
-5
84
21
63
12
2030
135
46
18
89
-4
85
21
64
13
2031
135
46
18
89
-3
85
21
64
14
2032
135
47
18
88
-2
86
22
65
15
2033
135
47
18
88
-1
87
22
65
16
2034
135
48
18
87
0
87
22
66
17
2035
135
48
18
87
0
87
22
65
18
2036
135
48
18
87
0
87
22
65
19
2037
135
49
18
86
0
86
22
65
20
2038
135
49
18
86
0
86
21
64
MMUSD
MMUSD
MMUSD
85
34
2.21
217
85
34
2.26
180
81
34
2.18
162
82
34
2.23
144
82
34
2.27
126
83
34
2.32
108
83
34
2.38
90
84
0
83
0
83
0
83
0
82
0
72
54
36
18
0
5-7
Table5-11: FIRR Calculation Cash Flow (Case2: The Operational Period is 10 years)
-4
2014
Sales Amount
Depreciation cost
Income
Corporation Tax
Cash Inflow
Cash Outflow
DSCR
Fixed Property
IRR
-3
2015
-2
2016
-1
2017
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
%
0
2018
11
1
0
10
0
10
0
10
1
2019
135
58
33
77
-14
63
16
47
2
2020
135
58
33
77
-13
64
16
48
3
2021
135
58
33
77
-11
66
16
49
4
2022
135
59
33
76
-10
67
17
50
5
2023
135
59
33
76
-8
68
17
51
6
2024
135
59
33
76
-7
69
17
52
7
2025
135
59
33
76
-6
70
17
52
8
2026
135
60
33
75
-4
71
18
53
9
2027
135
60
33
75
-3
72
18
54
10
2028
135
60
33
75
-1
73
18
55
81
47
1.56
480
82
47
1.59
447
83
47
1.62
414
83
47
1.65
380
84
47
1.68
347
85
47
1.71
313
86
47
1.75
280
87
47
87
47
88
47
247
213
180
0
0
65
41
10
48
0
6.9%
0
205
360
514
2.
Economic Analysis
a.
Potential profit generated by the project
benefit delivered through increased electricity supply and avoidance of power outage. To calculate the economic
effect, it is necessary to evaluate the difference by comparing the effect of the project taking place by setting the
case that the project does not happen as a baseline case. This study made rather conservative assumption that in
the case where the project did not materialize, the hydropower generation plants would be developed strongly,
generating the equivalent amount of electricity per year. However, as described in Chapter 1, Myanmar has a dry
season for 3 months, and therefore it was also presumed that there will be rolling power cuts caused by electricity
shortages, deriving from the inability of hydropower generation especially in the last half of the dry season. The
difference in economic effect between the baseline case and the case the project is implemented can be the
difference created by avoiding power failures during the dry season, as well as the difference between the
construction and operational costs of hydropower plants and the operational costs of gas-fired power plants.
not by the project.
b.
On the basis of the above, the preconditions for economic analysis are set as below.
5-8
Table5-12: Preconditions for Economic Analysis
Project period
25 years
5 years
Operation period
20 years
360 mmscfd
Profit
months) (Power shortage amount in the dry season 1,555
GWh×$1/kWh7)-（New land gas pipeline costs + operational costs of
gas-fired power plant – construction/operational costs of a
hydropower plant）
Initial cost
624 MMUSD
Operating cost
24.0 MMUSD /year
Hurdle rate of FIRR
base case)
(ii) transmission (21%)1.
The operating cost of a gas-fired power plant (excluding fuel costs), construction/operating costs of hydropower
plant are adapted from the average operating cost in China (gas fired: USD10.88/kWh, hydropower: USD
36/kWh) in the “Projected Costs of Generating Electricity 2010 Edition” by the OECD. For the fuel cost of a
gas-fired power plant, this study team used the price deducing USD 0.5/mmbtu (=equivalent of the transport cost
described in the “New Policies Scenario” in the IEA’s “World Energy Outlook 2012”. The price varies at USD
14/mmbtu during the operational period.
c.
Evaluation results
The profitability of the project is as given below.
7Source:
FY 2011 Infrastructure System Export Promotion Investigations (Project formation of yen loan/ private
8
5-9
Table5-13: Result of Calculation of Performance Indicator
632 MMUSD
503 %
IRR
28.0 %
Case1:IRR_100 km
26.2 %
offshore
Case2:IRR_operational
26.6%
period is 10 years
As shown in the above table, the result exceeds the above 12% opportunity cost under the both cases where we
assume FSRU is located 100km offshore and project period of 10 years. However, the calculation of the above
performance indicators are mostly based on various assumptions, as including matters and elements outside the
scope of the study and therefore contains some uncertain elements in its result. It is necessary to conduct further
detailed study in the future.
The cash flow of the project is shown as below.
Table5-14: EIRR Calculation Cash Flow (Base Case)
-4
2014
Profit from Avoidance of Power Failure
Profit from Ggas-fired Power Generation
Cost of Ggas-fired Power Generation
Cost of gas
Cost of Hydropower Generation
Profit from Hydropower Generation
Benefit Total
Initial Investment Cost
Operational Cost
EIRR
Cost of gas
Benefit Total
Operational Cost
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
%
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
-3
2015
5
0
28.0%
-2
2016
5
0
-1
2017
291
0
0
2018
193
0
1
2019
1,555
632
1,844
1,538
498
553
287
2
2020
1,555
632
1,829
1,523
498
553
302
3
2021
1,555
632
1,834
1,527
498
553
298
4
2022
1,555
632
1,838
1,532
498
553
293
5
2023
1,555
632
1,842
1,536
498
553
289
6
2024
1,555
632
1,847
1,541
498
553
284
7
2025
1,555
632
1,851
1,545
498
553
280
8
2026
1,555
632
1,856
1,550
498
553
276
24
24
24
25
25
25
25
26
187
1
9
2027
1,555
632
1,860
1,554
498
553
271
10
2028
1,555
632
1,865
1,558
498
553
267
11
2029
1,555
632
1,869
1,563
498
553
262
12
2030
1,555
632
1,874
1,567
498
553
258
13
2031
1,555
632
1,876
1,570
498
553
255
14
2032
1,555
632
1,878
1,572
498
553
253
15
2033
1,555
632
1,880
1,574
498
553
251
16
2034
1,555
632
1,883
1,576
498
553
249
17
2035
1,555
632
1,885
1,579
498
553
246
18
2036
1,555
632
1,885
1,579
498
553
246
19
2037
1,555
632
1,885
1,579
498
553
246
20
2038
1,555
632
1,885
1,579
498
553
246
26
26
27
27
27
28
28
28
29
29
29
30
5-10
Table5-15: EIRR Calculation Cash Flow (Case1: The Location of the FSRU is 100 km)
-4
2014
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
%
Cost of gas
Benefit Total
Operational Cost
EIRR
Cost of gas
Benefit Total
Operational Cost
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
-3
2015
6
0
26.2%
-2
2016
6
0
-1
2017
313
0
0
2018
206
0
1
2019
1,555
632
1,844
1,538
498
553
287
2
2020
1,555
632
1,829
1,523
498
553
302
3
2021
1,555
632
1,834
1,527
498
553
298
4
2022
1,555
632
1,838
1,532
498
553
293
5
2023
1,555
632
1,842
1,536
498
553
289
6
2024
1,555
632
1,847
1,541
498
553
284
7
2025
1,555
632
1,851
1,545
498
553
280
8
2026
1,555
632
1,856
1,550
498
553
276
24
24
25
25
25
26
26
26
201
1
9
2027
1,555
632
1,860
1,554
498
553
271
10
2028
1,555
632
1,865
1,558
498
553
267
11
2029
1,555
632
1,869
1,563
498
553
262
12
2030
1,555
632
1,874
1,567
498
553
258
13
2031
1,555
632
1,876
1,570
498
553
255
14
2032
1,555
632
1,878
1,572
498
553
253
15
2033
1,555
632
1,880
1,574
498
553
251
16
2034
1,555
632
1,883
1,576
498
553
249
17
2035
1,555
632
1,885
1,579
498
553
246
18
2036
1,555
632
1,885
1,579
498
553
246
19
2037
1,555
632
1,885
1,579
498
553
246
20
2038
1,555
632
1,885
1,579
498
553
246
26
27
27
27
28
28
28
29
29
29
30
30
Table5-16: EIRR Calculation Cash Flow (Case2: The operational period is 10 years)
-4
2014
Cost of gas
Benefit Total
Operational Cost
EIRR
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
%
5
0
26.6%
-3
2015
-2
2016
5
0
281
0
-1
2017
192
0
0
2018
1
2019
1,555
632
1,844
1,538
498
553
287
2
2020
1,555
632
1,829
1,523
498
553
302
3
2021
1,555
632
1,834
1,527
498
553
298
4
2022
1,555
632
1,838
1,532
498
553
293
5
2023
1,555
632
1,842
1,536
498
553
289
6
2024
1,555
632
1,847
1,541
498
553
284
7
2025
1,555
632
1,851
1,545
498
553
280
8
2026
1,555
632
1,856
1,550
498
553
276
9
2027
1,555
632
1,860
1,554
498
553
271
10
2028
1,555
632
1,865
1,558
498
553
267
24
24
24
25
25
25
25
26
26
26
187
1
5-11
Chapter 6 Planned Project Schedule
(6) Project Implementation Schedule
1.
Preconditions for Project Implementation
For the successful completion of the project, the following preconditions need to be decided by the relevant
companies/entities or by the discussion among them.
The determination of these preconditions will expedite the project.
•
Appointment for the responsible entity of the project, and the main body of the counterpart governments for
charter ship contract
•
Decisions of basic conditions of fuel gas procurement (quantity/gas components etc.)
•
Decision of gas delivery point

Change of the gas delivery point influences on the whole project design of gas pipeline including project
schedule, etc.
•
Policy on fund sourcing

Affected by developing situation trends of appropriate financing plan related FSRU/pipeline
introduction, the LNG purchase
•
Schedule of legislation for EIA

2.
Affected by preparation of the EIA process and progress of parliamentary approval
Project Schedule(Proposed)
From basic development plan to gas delivery, the project is composed of three stages:
1. From making basic development plan to final investment decision (FID)
2. From FID to installation of FSRU, jetty facilities and pipelines
3. Connecting the facilities to the existing gas pipeline network
The schedule in this study is made based on the assumptions that the above preconditions have been appropriately
satisfied at each stage, and that the schedule of one stage does not influence on that of other stages each other.
It is assumed that after the completion of this study, while firming up the basic conditions with counterpart
organizations, it will take less than 18 months for the final investment decision. The required tasks are the
development of the basic project design, EIA approval, and so on. This will, then, be followed by the confirmation
of implementation, namely the project will be ready for commencement. In parallel, after order placement of EPC
of FSRU, jetty facilities and offshore pipeline, it will take about 33 months for the commencement of FSRU
operation after the construction begins. It is now assumed that pipelines for the project will be connected to the
existing pipeline network at the S. Dagon Station owned by the MOGE. As described above, if the receiving
facility is made ready through this process, after the installation of FSRU, jetty facilities and pipelines, it will
require additional two months to be connected to the network. Overall, the period from the launch of the basic
plan to the completion of the gas supply system is about 53 months in total.
6-1
In addition, climate at the project site and hydrographic and geological conditions will influence on the project
development schedule. Additional study will be required in this respect.
If the favorable research results are obtained, it will potentially contribute to shorten the project development
period.
The project development period can be shortened by several factors
1. If it is counted from the start of the basic development plan until its implementation, given the necessary
information or agreement related to providing information for the design, 6months
2. If the existing FSRU design, which is previously made by other project, is ready-to-use, 2 months9
It is possible to shorten the process by 8 months overall, and to achieve gas delivery within 45 months from the
basic development plan implementation.
Figure6-1: Detailed Schedule for Project Implementation
LINE DESCRIPTION
1
Main Milestone
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
35
36
37
38
39
40
41
42
42
43
2
3
4
5
6
7
8
9
Basic
planning
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 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Complete
of basic
design
Start of the
Project
Start of the
Construction
LNG
Receiving
Basic planning
Basic plan
Basic design
Comfirmation of project base
Collect additional data and survey marine data
Write EIA report
Environmental approval received work
Inquiry plan
Inquiry・Select sub-constructor
Detailed design
Final Investment Decision
Order sub-constructor
Lower side of jetty
Contract
Detailed design・Construction design
Site work
ipper side of jetty
Offshore Pipeline
Detailed design
Equipment purchase
Equipment carried
Installation and piping, electrical
and instrumentation work
Contract
Material purchase /on-site installation
FSRU
Contract
basic design
detailed design
Production design
Construction and manufacturing
Transport and installation to the site
Preparation for operation
Whole system inspection
Ready　For　LNG　Receiving
Followings are the estimated duration of the main tasks:
• Basic Plan: 3 months
•
9
Basic Design/Ministries approval: 12 months
However, possibility that the existing FSRU design is ready-to-use is not high. It is more probably to need to
redesign.
6-2
•
Detailed Design: 6 months (part of this work can begin earlier)
•
FSRU: LNG reception can begin 33 months after order placement
•
Jetty Facilities: complete in 31 months after order placement, in 23 months after the start of construction
•
Setting up of Pipeline and Valve Station: complete in 30 months after order placement
6-3
Chapter 7 Implementing Organization
(1)
Relevant Ministries Agencies and Their Roles
The entity mainly controlling the energy sector in Myanmar is the Ministry of Energy (hereinafter, MOE). The
MOE has four organizations, namely the Energy Planning Department (hereinafter, EPD), Myanmar Oil and Gas
Enterprise (hereinafter, MOGE), Myanmar Petrochemical Enterprise (hereinafter, MPE) and Myanmar Petroleum
Products Enterprise (hereinafter, MPPE). Relevant Ministries/Agencies for this project are the MOE, which is in a
position to supervise the entire energy sector including natural gas, the MOGE that constructs and operates the
pipeline to transport gas and the MPE that could be the major LNG consumer in the future.
Electric Power generation and transmission/distributions are supervised by the Ministry of Electric Power
(hereinafter, MOEP), which owns two enterprises, that is, Hydropower Generation Enterprise (hereinafter, HPGE)
which is in charge of hydraulic and coal-fired power generation, and the Myanmar Electric Power Enterprise
(hereinafter, MEPE), responsible for development and operation of gas-fired power plants and supply of gas to
IPPs. The transmission part is undertaken exclusively by the MEPE, which also supplies electricity to the Yangon
City Electricity Supply Board (hereinafter, YESB) that manages the power distribution network in the Yangon
Region and the Electricity Supply Enterprise (hereinafter, ESE), an electric distribution public corporation that
manages the power distribution outside Yangon. The YESB is in charge of a public offering process of the LNG
import described before.
Figure7-1: MOE Organization Chart and Major Roles of Each Division
Ministry of Energy
(MOE)
Energy Planning
Department
(EPD)
• Regulation
• Adjustment of plans
• Gas production and
distribution
management
Myanmar Oil and Gas
Enterprise
(MOGE)
• Gas development
and production
• Pipeline
construction and
operation
• CNG production
Myanmar
Petrochemical
Enterprise
(MPE)
• Petroleum refinery
• Production of
fertilizer, LPG,
CO2 and methane
Myanmar Petroleum
Products Enterprise
(MPPE)
• Marketing and sale
of petroleum
products
Source: Prepared by Study Team based on MOE materials
7-1
Figure7-2: MOEP’s Structure
Public corporations under the umbrella of MOEP
Electricity generation
HPGE
MEPE
(Hydraulic and coal-fired)
(Gas/oil thermal)
Electricity transmission
IPPs
MEPE
Electricity distribution
YESB
ESE
(Yangon)
(Outside Yangon)
Consumers
Source: Prepared by Study Team based on MOEP materials
(2)
Required Capabilities for the Project Implementation
Myanmar does not have experience in the LNG import yet. However, each of the related ministries and agencies
would partly have the capabilities of supporting this project.
The MOE/MOGE has several experiences to develop offshore gas fields such as Yadana, and build and operate
gas supply infrastructure for export to Thailand etc. These experiences will be able to contribute to this project
and LNG import. Specifically, the MOGE has designed and built the on-shore gas pipeline by itself, thus it would
be technically not so difficult for it to construct the onshore pipeline of this project, though the size of the pipeline
would be bigger than that of MOGE has experienced before.
In addition, the MEPE is also experienced entity to procure natural gas from the MOE and receive gas through the
pipeline owned and operated by the MOGE for gas-fired power business. This experience would be able to assist
LNG import using FSRU as well.
This study suggests project implementation formation, considering to the roles and capabilities of the related
ministries and agencies.
Firstly, of course, it is suggested that the MOEP/MEPE/YESB and the MOE/MOGE need to collaborate each
other.
However, based on the fact that the MOEP requires immediate import of LNG to overcome the domestic energy
shortages mainly due to the rapid increase of electricity consumption, it would be beneficial to unify the business
7-2
contact window of the government, to promote this project quickly. Currently, since the LNG import is mainly for
gas-fired power plant, it is suggested MOEP should be the primal contact window for project
participants/stakeholders.
Although the MOEP has appointed the YESB as the managing body of a public bidding for LNG import, it would
be very challenging for YESB because it is an unprecedented project in Myanmar, thus YESB does not have any
past experiences. This may become one of the obstacles for companies to enter into this market. In addition,
inadequacy of transmission and the distribution network also will be an obstacle in electricity supply, which
generates another risk to newcomers. Therefore, to enhance the feasibility of the project, well-organized
development plan and project management for not only power generation plants but also transmission/distribution
grid expansion are critical.
Considering the abovementioned aspects, new organization under MOEP would be required, whose missions are
to become the supervisory agency for firepower sector and LNG import, to manage this project and relevant
agencies such as the transmission sector of the MEPE and YESB. MEPE is an organization with an
implementation capability and robust operating competency for the plan. Furthermore the firepower sector of the
MEPE has signed a memorandum of understanding about the gas-fired power generation plan with South Korean
and Chinese companies, so it would be suitable for MEPE supervisees the IPP players’ power plant developing
plans. So, MOEP can control the power generation plan by supervising the MEPE to the implementation of the
IPP business as planned.
This research suggests that the MEPE should be the purchaser of the LNG, which has the contract directly with
LNG supplier because of the two main reasons. First, MEPE is already the purchaser for domestically produced
natural gas to fuel gas-fired power plants. Therefore, MEPE would be able to play the role in adjusting domestic
demand and supply gap for the consumption of gas-fired power plants. Second, sole entity to purchase the natural
gas from overseas can be expected to have a bargaining power to acquire the lower LNG price, contributing to
supply cheaper electricity price to consumers.
About the chartered ship to the FSRU and also the pipeline transportation service, the MEPE would favorably be a
contract entity, in terms of consistency of the contract, as well as the unification of the business access posts.
Furthermore, capacity developing would be necessary for the MOEP/MEPE, to manage and supervise IPP players,
realize the electric power development as planned, and enable the operators to carry on business in a stable
manner because the delay of the construction and/or the critical problems of the operation would adversely affect
the FSRU project as well.
In addition, for the success of the power plant development, financial assistance would be vital. Especially, it is
necessary to complement the revenue shortages for purchasing gas, in order to make it cover costs. Financial
enhancement by the government guarantee, secured by the MOF, is needed.
7-3
Lastly, to involvement of the MOE/MOGE, would be important because of their expertise of the development,
and provision of on-shore pipeline to support the MOEP/MEPE. Though this project assumes that the imported
LNG is utilized only for gas-fired power plant, LNG would be supplied to other consumers such as petrochemical
industry in the future. Considering this, MOE/MOGE should be involved at the early stage of this project to
understand the logistics of imported gas and to get the know-how to handle the gas, because the role of these
entities will be very important to distribute natural gas to such different users in the future.
Based on the above, the chart below shows the suggestion of role sharing in the LNG import & transport project
(refer to Chapter 8 for a SPC’s detail role).
Figure7-3: The Suggestion of Role Sharing in the LNG Import & Transport Project
7-4
Chapter 8 Technical Advantages of Japanese Company
(1) Assumable Forms of Participation by Japanese Enterprises
Japan’s enterprise will participate in the following fields:
• Procurement of major plant equipment
•
Design and construction of plants
•
Launch, operation and maintenance of plants
•
Technology transfer to local workers
•
Fund securing
There will be two ways for how to cover the costs: possessing the FSRU and the pipeline on its own, chartering a
ship from the owner of the FSRU and requesting wheeling through the pipeline.
The advantage of the owning FSRU is that the possessor can fully customize and upgrade the specifications
during the period of operation as per the requirement of the terminal. This allows for the configuration flexibility
with respect to regasification capacity, layout, shore integration and any future enhancements. While this case has
the disadvantage in increased work burden including higher initial investment, and all ship management tasks to
be conducted by the possessor, such as the arrangement and administration of crew (refer to the following table).
Table8-1: Comparison Result by Type of FSRU/PL Possession
Items
Owned FSRU
Chartered FSRU
Customization
High
Middle/low
Amount of Initial Investment
High
Low
Work Burden
High
Middle/low
Based on the above study, this project adopts the charter model, which holds down initial investment for the
counterpart in the case of FSRU, and has low work burden to the counterpart when initially installing FSRU.
On the other hand, as to the land pipeline as mentioned in Chapter 7, it will be effective to construct a state-run
grid because in most cases, grids are not built by private companies for their inherent purposes, but are built as
national common-use infrastructure in nature, when building pipelines in terms of responding to wide-ranging gas
demand not only for this electricity generating purposes, but also for commercial use except electricity generation
in the medium and long run.
In addition, it will be desirable for private operators and the entire economy in Myanmar for MOGE with a track
record of construction and operation to own a pipeline for constructing and operating it, though the initial costs
are higher, considering that the compulsory purchase of land will become an issue for private operators in building
8-1
pipelines. MOGE will be incentivized with increased profit through wheeling and an increase in the utility value
of the entired related infrastructure, with the extended pipeline networks and capacity.
Regarding offshore pipelines, which are different from land pipelines in nature, it is difficult to plan their
diversification and development except their main purpose, and exiting sea pipelines were commissioned to
foreign private companies. Considering that MOGE has no experience of constructing them, it will be desirable
for the counterpart to use wheeling in view of the work and initial investment burdens, as in the case of FSRU.
An unit of SPC in which Japanese companies invest is considered to have a possession and operation of the FSRU
and offshore pipeline. The SPC receives LNG from tankers, does regasification of the LNG and transports gas to
such points of delivery as designated by users.
Furthermore, concerning the scheme of the FSRU chartering contract between SPC and the counterpart, there will
be two scheme: merchant and tolling agreements. Merchant agreement is a scheme for providing gas procurement
and sales, combined with chartering FSRUs. It is a one-stop solution for the counterpart to realize LNG
importation. This scheme is adopted by land re-gasification facilities and equipment. However, there are a limited
number of business operators (or consortiums) that can carry out LNG procurement, FSRU procurement and
operation at the same time. Further, no FSRU chartering business has adopted this scheme to our knowledge,
which may increase the risk in financing arrangements or become costly business.
On the other hand, tolling agreement consists of chartering FSRUs, re-gasifying the LNG that the counterpart
procured, and supplying the gas to the counterpart. This scheme has been often taken up by FSRU projects in
other countries. It will realize the business in tandem with LNG procurement from an LNG portfolio supplier that
has a low procurement risk.
Please note the buyer of gas from an LNG portfolio supplier will be MEPE, which has operated gas-fired power
plants, in addition to procuring gas domestically. (Refer to Chapter 7 for details)
Based on the above, the table below shows a plan of introduced equipment and player make-up, assumed by this
study team.
8-2
Figure8-1: Introduced Equipment and Player Make-up (Planned)
Regarding financing, it is necessary for FSRUs, the pipeline and the SPC to secure funds as the initial investment
for the project. The SPC is assumed to raise funds from Japanese financial institutions, including Export Credit
Agencies and commercial banks, as well as investment from Japanese and foreign companies.
In addition, it is assumed that MEPE as the off-taker or its upper organization MOEP will supply equity in the
SPC because such financing may help enhance the prospect for realizing this business from the viewpoints of
easing the investment burden and risk that foreign companies may face, as well as lowering the risk bar for the off
taker arising out of cancelation of the project. However, in general, under this arrangement, conflict may occur
about how to handle the assets for liquidation after the project is over, or the realistic and best structure in terms of
tax cannot be made because of government involvement. (For instance, there may be restrictions which do not
allow establishment of an SPC in low-tax countries like Singapore, making the requirement that it must be a
Myanmar’s corporation possible.) Also, quick decision-making can be compromised by governmental influence
over operating the SPC. The above can be disadvantageous to this arrangement. As after all, this is only one
option of schemes. Therefore, it is necessary first to judge whether MOEP intends to invest in this project or not,
from the viewpoint of acquiring technology/know-how for similar projects in the future. If so, it will be necessary
to investigate the ratio of ownership, roles, rights, obligations, etc., of each partiers. If MOEP invests in the SPC,
utilizing the back finance of the funds by ODA to secure financing, will be useful bringing down the initial costs
of the Myanmar side, and in reducing the risk of investors (a risk of investment shortage).
Furthermore, it is necessary to study how to procure LNG and finance FSRU chartering. As mentioned in Chapter
7, it will be desirable to enter a contract with MEPE in consideration of integrating the contacts for actual work of
procuring LNG, chartering FSRU, and pipeline wheeling.
MEPE will be able to reduce the initial investment in equipment and facilities related to receiving LNG, by
chartering FSRUs under the scheme that was proposed by this study. Also, as the imported LNG through this
project will be eventually used for generating electricity, fees for use of FSRU and the pipeline should be paid
8-3
basically by government subsidies. However, given that it is not easy to raise electricity rates due to objection
among the population, and that government finances are tight, there is a possibility that this project cannot secure
enough profits to be viable only with additional funds from the Myanmar side (a possible gap between costs and
profits). Viability gap funding, as a measure to help fill the gaps, the back financing of this fund by ODAs can be
utilized.
With the above issues sorted out, the table below shows a project scheme
Figure8-2: Project Scheme (Planned)
8-4
(2) Superiority of Japanese Enterprises in Implementing this Project
(Technologically and Economically)
Japanese enterprises have the following superiority:
a.
Provision of highly reliable long-term operation services for the FSRU
Since the contract period of providing ship chartering and operation services persists over a long period of time,
ranging from a few years to 20 years, stability and reliability in every aspects of business are required to
continuously provide services during the contract period.
As the world’s largest LNG carrier, Mitsui O.S.K. Lines has top-level know-how of NG transport, handling
technologies and vessel management know-how all essential for the operation of the FSRU.
While there are currently only a few companies that enjoy a track record of offering operation services of
regasification through FSRU on a global basis, Mitsui O.S.K. Lines has accumulated unique know-how on FSRU
since participating jointly in the shipboard LNG regasification project on the east coast of North America
(“Neptune project”) with a partner shipping company in Norway from 2006, and independently signed a
long-term charter party for FSRU with GDF Suez S.A., a French company, in October 2013, to make a full-scale
entry into the FSRU business. Among FSRU operators, Mitsui O.S.K. Lines has more stable financial grounds
compared with other providers, and high reliability in provision of extended services.
b.
Support in fund securing
To implement the project, fund arrangement of finance costs of the project is necessary, and more importantly,
such funds can be invested to the SPC.
SMBC, a Japanese financial institution, has a strong track record in LNG-related project finance including FSRU,
and may possibly take part in this project as a financial advisory, or in form of lending.
Having a record of participation in the investment in two LNG ships with shipboard regasifiers (FSRU)
(investment ratio: 48.5%) in the Neptune project described above, Mitsui O.S.K. Lines may have a possibility of
investment in this project as well.
In addition, as an advantage to Japanese enterprises consideration of using ODA by the Japanese government and
Japanese Export Credit Agencies as a fund source for the SPC in terms of businesses that benefit Japan..
Such experience enables to offer services to solve operational issues for the entire LNG supply chain, including
financing.
8-5
(3) Measures Necessary to Help Japanese Enterprises Win Contracts
As mentioned in Chapter 7, it is necessary to establish a system for managing the procurement of LNG in all
stages to plan electricity generation for enhancing the feasibility of realizing this business. Japan’s proactive
support to the counterpart through enterprises that are technologically, economically versed in operations from
LNG procurement, to electricity generation planning will lead to swiftly and properly assess and identify the
entire project, matching with the request to promptly introduce LNG imports. Specifically, such support includes
assistance in collaboration among ministries and agencies on cross-sectional examination issues, building relevant
bidding processes and a study of the evaluation items and criteria.
This support will lead Japanese companies to secure contract by incorporating their superior specifications and
scope of works into bid documents and conditions to reasonable extent that can eventually demonstrate a greater
advantages and competitiveness.
8-6
Chapter 9: Potential Funding Source for the Project
(1) Reviewing Fund Sources and Financing Plans
In implementing this project, funds for investment for FSRU and construction of pipelines as well as for operation
and maintenance of such equipment are required. However, a specific funding source and financing plan have not
so far been confirmed through interviews with governmental agencies of Myanmar. As for the bids for the import
of LNG, invited by YESB, the study team learned that no concrete proposal on financing source has been made.
Because substantial amount of costs will be incurred for introduction of the project and purchase of LNG in the
early stages and during the operation period, securing appropriate funding sources is a highly crutial factor to
materialize the import of LNG.
Given that FSRU and associated equipment in this project are necessary for natural gas used for gas-fired power
generation, costs and expenses related to the project are assumed to be covered primarily by (1) increase in
electric tariff and (2) an increase in government subsidies. However, in light of the fact that a hike in electricity
rates announced in October 2013 was temporarily suspended due to protests from the people, it is not considered
easy to increase electric tariff. Furthermore, it would be also difficult to significantly raise government subsidies
in view of the fiscal status of Myanmar.
Therefore, utilization of loans and investments from foreign governments and companies is expected to play an
important role in fund-raising. Specifically, three means can be deemed as potential sources: A. Official
Development Assistance (ODA) by foreign governments, B. investments and loans from foreign companies, and
C. finance utilizing investments and loans and guarantees from export credit agencies and international
organizations such as the World Bank.
A. ODA by foreign governments
Myanmar government has received ODA from multiple foreign governments, and such assistances
contribute to a wide range of sectors including infrastructure development and education. The Japanese
government has also provided ODA totaling of approximately 600 billion yen in the form of past yen loans
and free financial aids. In addition, the Japanese government takes a positive attitude about ODA for
Myanmar, as the government confirmed a commitment to the provision of ODA totaling 91 billion yen by
the end of fiscal year 2013 in the Japan-Myanmar summit in May 2013.
B. Investments from foreign companies
As Myanmar and its neighboring countries utilize business scheme called IPP, in certain infrastructure
projects, private sector owns/operates infrastructure using their investment funds without a government
doing business by itself nor holding assets. In many cases, foreign companies establish special purpose
companies and invest in these companies to set up and operate projects over a given period of time.
9-1
C. Loans and guarantees from export credit agencies and international organizations
Governments provide funds through direct finance and/or guarantees to loans from private financial
institutions through export credit agencies and international organizations.
(2) Feasibility of Fund-Raising
Although it seems that a financing plan for this project has not been decided as described above, the following
shows possibilities and challenges of fund-securing by the Japanese government/organizations/companies in terms
of the fund sources presented in Section (1).
This section is based on the assumption that Japanese companies execute projects related to FSRU and associated
equipment, assuming the figure of business scheme in Chapter 8.
1.
ODA by the Japanese Government
The following two structures can be assumed as a fund-raising mechanism utilizing ODA by the Japanese
government.
a.
Equity back financing
When MOEP intends to make investment into a SPC, the investment funds would be required as initial investment
cost. ODA loans can be utilized as back finance for these investment funds.
Detailed schemes including setting of the borrower are yet to be studied. For example, as a possible scheme,
Ministry of Finance and Revenue (“MOF”) can be the borrower of loans from the Japanese government and
on-lends the funds to MOEP (or a government-run company including MEPE) (the same shall apply to the
following “Viability Gap Fund” explained below).
Figure 9-1: Equity Back Financing Scheme
Source: Prepared by the Study Team
9-2
b.
Back finance of Viability Gap Funding (VGF)
Generally, VGF is a subsidy provided by government to make an unprofitable project commercially viable. This
scheme is to provide back finance for such VGF through ODA loans.
Since LNG imported under the project is eventually used to generate electricity, expenses for using FSRU and
pipelines should be primarily covered by an increase in electricity rates and government subsidies. However, it
may be possible that the sustainable level of revenue cannot be obtained (there will be a gap between costs and
income) because of difficulty of an increase in electric tariff and restriction in Myanmar government’s fiscal
budget. This scheme can be used to fill part or full of the gap.
Although a specific lending scheme needs to be further studied, a mechanism with certain realities to provide
finance for the part of the cost increase due to the introduction of this project, which cannot be passed on to
electricity price or subsidy, in the form of covering the price of electricity. Nevertheless, in the case where the
loan is made available to fill such gap, it will be necessary to establish a system in MOEP and/ or MEPE to
precisely recognize the gap between costs and income by taking into account the cost with relation to the project
as a part of electric-generating cost.
This also needs to be studied in the light of the Japanese government’s applicable criteria in implementing ODA.
In addition, it should be considered whether the finance can be linked to payment of ship charter and usage fees.
Even if it were possible, it would be necessary to implement a transparent structure which can secure clear linkage
(e.g., by use of an account used exclusively for loans for this project and payment of the costs and expenses from
the account).
Figure 9-2: VGF Scheme
In either scheme, there will be two merits from the viewpoint of Myanmar government.
9-3
First, the cost of loan interest can be minimal since interest rates of ODA loans are usually set at a low level. For
ODA loans extended by the Japanese government for which the agreement was signed with Myanmar government
in January 2013, the lending rate is extremely low at 0.01%.
Second, cash requirement in a short run will be reduced by setting a grace period in the repayment schedule to
ease the immediate cash requirement on Myanmar’s government and defer the financing burden on repayment of
the loans to the future. The above-mentioned ODA extends the grace period of 10 years and the repayment period
of 40 years. Some comments by Myanmar government in the interview under this study indicate that this feature
would be effective for Myanmar.
The selection of the scheme needs to be considered in light of the intention of the MOEP to invest in an SPC, a
level of gap between an increase in costs with relation to LNG import and increase of electricity tariff. Yet, back
finance of VGF seems to be the more advantageous option because (a) in equity back financing, the use is limited
to certain portion of investment by Myanmar’s government (If MOEP makes a 25% investment in the SPC on the
assumption described in (3) below, the amount is approximately 50 million U.S. dollars at most.) and (b) in VGF,
conditions which would be acceptable for investors in terms of payment of ship charter and usage fees for pipeline
during the entire term can possibly be established, which can make the project feasible and bankable to investors
and loan providers for the entire project period. However, further analysis is required after clarifying the roles of
ministries and agencies in Myanmar government to see whether the government can establish a scheme that can
meet VGF’s applicable requirements as stated above.
Moreover, since ODA is a form of financing provided to help developing countries grow their society and
economy and improve their welfare, it will be important to formulate a highly feasible implementation plan of the
entire value chain including import of LNG through generation and transmission of electricity, so that the
realization of this project does contribute to improvement of the nation’s economy and welfare of the population.
2.
Investments by Japanese Companies
Japanese enterprises will set up special purpose companies, to own, maintain, operate FSRU and associated
equipment, and lease the FSRU and the pipeline to MEPE. The cash required for Myanmar government on initial
capital expenditure can be reduced by inviting investments from Japanese companies.
9-4
Figure 9-3: Investments by Japanese Companies
In order for foreign companies including Japanese companies to make investments, the following requirements
need to be satisfied.
a.
Development of a framework for charter contract that meets international standards.
In order for Japanese companies to carry out investments, a framework with Myanmar’s government needs to be
built in terms of appropriate risk sharing in charter contract that meets international standards.
b.
Credit enhancement by Myanmar government including MOF
If a state owned entity is an off-taker, credit enhancement may be required to attract foreign financial institutions,
including guarantees provided by the MOF for performance of contractual obligations of such state owned entity.
c.
Appropriate level of investment income
In order for Japanese companies to carry out investments, it is required to set charter fees and pipeline usage fees
that ensure appropriate returns on investments taking the country risk of Myanmar into account.
3.
Loans/ Guarantees from Japanese Export Credit Agencies
Loans and guarantees by Japanese export credit agencies (Japan Bank for International Cooperation/Nippon
Export and Investment Insurance) enables investors to secure funding required to implement the project and an
improvement in the rate of return on investments for investors described in B. above. From Myanmar’s point of
view, initial cash required to implement the project can be reduced.
9-5
Figure 9-4: Loans/ Guarantees from Export Credit Agencies
It is expected that credit enhancement by MOF and other agencies of the Myanmar government as described in B
above may be required in order for Japanese export credit agencies to provide loan and/or guarantee. However,
according to Myanmar’s MOF, Myanmar has not yet offered a guarantee which covers contractual obligations of
state owned entities or a debt guarantee.
In view that such mechanism can be extended to other infrastructure development in the future, it is also desirable
to establish an appropriate framework. In addition, it will be necessary to build an appropriate legal framework
including enforceability of security.
The above issues are related to raising funds necessary for FSRU and associated equipment. It is important to also
consider financing for purchase of LNG, which requires a larger amount of funds than those funds.
(3) Cash Flow Analysis
1.
Financial Analysis
The feasibility of the business under the project, which is to construct and operate the FSRU/pipeline and
transport the supplied LNG to the spots designated by the consumers, has been identified. The cash flow was
developed under certain preconditions to work out the NPV, B/C and FIRR.
a.
Preconditions of Financial Analysis
9-6
Table 9-1: Financial Analysis Preconditions
Project period
25 years
5 years
Operating period
20 years
360 mmscfd
Profit
approx. $14/mmbtu)：$135 million/year
Initial cost
624 MMUSD
Operating cost
24.0 MMUSD /year
Capital ration
25%
Depreciation period
FSRU, jetty：20 years, Pipeline: 10 years
Corporate tax rate
25%
Commercial tax
5%
Custom duties
0.5%
Hurdle rate of FIRR
Case1:The location of the FSRU is 100 km offshore (80 km for the base
case)
Case2:The operational period is 10 years.
b.
Result of evaluation
Table 9-2: Result of Calculation of Performance Indicators
132MMUSD
165%
IRR
11.5
Case1:IRR_offshore100km
10.5%
Case2:IRR_operation period is 10
6.9%
years
9-7
This study has revealed that the project has good viability in terms of financial aspect even if a chartering cost per
year is USD 165 million and even if the FSRU is installed 100km offshore, reaching the level of the long-term
interest of 10% in Myanmar. If the duration of operations is cut by 50% to 10 years with the chartering cost
unchanged, IRR will remain at 6.9%. If the chartering cost is changed to USD 200 million per year, the IRR will
be 10.0%. (Refer to the table below.)
Table 9-3: IRR Analysis for Several Chartering Cost (Case2: The Operational Period is 10 years）
chartering cost
(USD$1 million)
IRR
135
6.9%
145
8.3%
155
9.6%
160
10.3%
The tables below show the project cash flow.
Table 9-4: FIRR Calculation Cash Flow (Base Case)
-4
2014
Sales Amount
Depreciation cost
Income
Corporation Tax
Cash Inflow
Cash Outflow
DSCR
Fixed Property
IRR
Sales Amount
Depreciation cost
Income
Corporation Tax
Cash Inflow
Cash Outflow
DSCR
Fixed Property
-3
2015
-2
2016
-1
2017
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
%
0
2018
11
1
0
10
0
10
0
10
1
2019
135
58
33
77
-14
63
16
47
2
2020
135
58
33
77
-13
64
16
48
3
2021
135
58
33
77
-12
64
16
48
4
2022
135
59
33
76
-11
65
16
49
5
2023
135
59
33
76
-10
66
16
49
6
2024
135
59
33
76
-10
66
17
50
7
2025
135
59
33
76
-9
67
17
50
8
2026
135
60
33
75
-8
68
17
51
81
32
2.06
480
81
32
2.10
447
82
32
2.14
414
82
32
2.17
380
83
32
2.21
347
83
32
2.25
313
84
32
2.29
280
84
32
2.34
247
0
0
67
41
10
49
0
11.5%
0
205
360
514
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
9
2027
135
60
33
75
-7
68
17
51
10
2028
135
60
33
75
-6
69
17
52
11
2029
135
45
18
90
-5
85
21
64
12
2030
135
46
18
89
-4
86
21
64
13
2031
135
46
18
89
-3
86
22
65
14
2032
135
46
18
89
-2
87
22
65
15
2033
135
47
18
88
-1
87
22
66
16
2034
135
47
18
88
0
88
22
66
17
2035
135
47
18
88
0
88
22
66
18
2036
135
48
18
87
0
87
22
65
19
2037
135
48
18
87
0
87
22
65
20
2038
135
48
18
87
0
87
22
65
MMUSD
MMUSD
MMUSD
85
32
2.38
213
85
32
2.43
180
82
32
2.37
162
82
32
2.42
144
83
32
2.48
126
83
32
2.53
108
84
32
2.59
90
84
0
84
0
83
0
83
0
83
0
72
54
36
18
-0
9-8
Table 9-5: FIRR Calculation Cash Flow (Case1: The Location of the FSRU is 100 km)
-4
2014
Sales Amount
Depreciation cost
Income
Corporation Tax
Cash Inflow
Cash Outflow
DSCR
IRR
-2
2016
-1
2017
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
%
Fixed Property
-3
2015
Sales Amount
Depreciation cost
Income
Corporation Tax
Cash Inflow
Cash Outflow
DSCR
Fixed Property
0
2018
11
1
0
10
0
10
0
10
1
2019
135
62
37
73
-15
57
14
43
2
2020
135
62
37
73
-14
58
15
44
3
2021
135
62
37
73
-13
59
15
44
4
2022
135
63
37
72
-12
60
15
45
5
2023
135
63
37
72
-11
61
15
45
6
2024
135
63
37
72
-10
61
15
46
7
2025
135
64
37
71
-9
62
16
47
8
2026
135
64
37
71
-8
63
16
47
80
34
1.92
515
81
34
1.95
478
82
34
1.99
440
82
34
2.02
403
83
34
2.06
366
83
34
2.09
329
84
34
2.13
292
84
34
2.17
254
0
0
73
44
10
53
0
10.5%
0
221
386
552
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
9
2027
135
64
37
71
-7
64
16
48
10
2028
135
65
37
70
-6
64
16
48
11
2029
135
46
18
89
-5
84
21
63
12
2030
135
46
18
89
-4
85
21
64
13
2031
135
46
18
89
-3
85
21
64
14
2032
135
47
18
88
-2
86
22
65
15
2033
135
47
18
88
-1
87
22
65
16
2034
135
48
18
87
0
87
22
66
17
2035
135
48
18
87
0
87
22
65
18
2036
135
48
18
87
0
87
22
65
19
2037
135
49
18
86
0
86
22
65
20
2038
135
49
18
86
0
86
21
64
MMUSD
MMUSD
MMUSD
85
34
2.21
217
85
34
2.26
180
81
34
2.18
162
82
34
2.23
144
82
34
2.27
126
83
34
2.32
108
83
34
2.38
90
84
0
83
0
83
0
83
0
82
0
72
54
36
18
0
Table 9-6: FIRR Calculation Cash Flow (Case2: The Operational Period is 10 years)
-4
2014
Sales Amount
Depreciation cost
Income
Corporation Tax
Cash Inflow
Cash Outflow
DSCR
Fixed Property
IRR
-3
2015
-2
2016
-1
2017
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
%
0
2018
11
1
0
10
0
10
0
10
1
2019
135
58
33
77
-14
63
16
47
2
2020
135
58
33
77
-13
64
16
48
3
2021
135
58
33
77
-11
66
16
49
4
2022
135
59
33
76
-10
67
17
50
5
2023
135
59
33
76
-8
68
17
51
6
2024
135
59
33
76
-7
69
17
52
7
2025
135
59
33
76
-6
70
17
52
8
2026
135
60
33
75
-4
71
18
53
9
2027
135
60
33
75
-3
72
18
54
10
2028
135
60
33
75
-1
73
18
55
81
47
1.56
480
82
47
1.59
447
83
47
1.62
414
83
47
1.65
380
84
47
1.68
347
85
47
1.71
313
86
47
1.75
280
87
47
87
47
88
47
247
213
180
0
0
65
41
10
48
0
6.9%
0
205
360
514
2.
Economic Analysis
a.
Potential profit generated by the project
benefit generated through increased electricity supply and avoidance of power outage. To calculate the economic
benefit, it is necessary to evaluate the difference by comparing the effect of the project taking place by setting the
case that the project does not happen as a baseline case. This study made rather conservative assumption that in
the case where the project did not materialize, there will be emphasis on the promotion for additional provision of
hydropower generation plants, generating the equivalent amount of electricity per year. However, as described in
Chapter 1, Myanmar has a dry season for 3 months, and therefore it was also presumed that there will be rolling
power cuts caused by electricity shortages, deriving from the inability of hydropower generation especially in the
9-9
last half of the dry season. The difference in economic effect between the baseline case and the case the project is
implemented can be the difference created by avoiding power failures during the dry season, as well as the
difference between the construction and operational costs of hydropower plants and the operational costs of
gas-fired power plants.
not by the project.
b.
On the basis of the above, the preconditions for economic analysis are set as below.
Table 9-7: Preconditions for Economic Analysis
Project period
25 years
5 years
Operation period
20 years
360 mmscfd
Profit
months) (Power shortage amount in the dry season 1,555
GWh×$1/kWh10)-（New land gas pipeline costs + operating costs of
gas-fired power plant – construction/operating costs of a hydropower
plant）
Initial cost
624 MMUSD
Operating cost
24.0 MMUSD /year
Hurdle rate of FIRR
base case)
(ii) transmission (21%)1.
10Source:
FY 2011 Infrastructure System Export Promotion Investigations (Project formation of yen loan/private
11
9-10
The operating cost of a gas-fired power plant (excluding fuel costs), construction/operating costs of hydropower
plant are adapted from the average operating cost in China (gas fired: USD10.88/kWh, hydropower: USD
36/kWh) in the “Projected Costs of Generating Electricity 2010 Edition” by the OECD. For the fuel cost of a
gas-fired power plant, this study team used the price deducing USD 0.5/mmbtu (=equivalent of the transport cost
described in the “New Policies Scenario” in the IEA’s “World Energy Outlook 2012”. The price varies at USD
14/mmbtu during the operational period.
c.
Evaluation results
The profitability of the project is as given below.
Table 9-8: Result of Calculation of Performance Indicator
632 MMUSD
503 %
IRR
28.0 %
Case1:IRR_100 km
26.2 %
offshore
Case2:IRR_operational
26.6%
period is 10 years
As shown in the above table, the result exceeds the above 12% opportunity cost under the both cases where we
assume FSRU is located 100km offshore and project period of 10 years. However, the calculation of the above
performance indicators are mostly based on various assumptions, as including matters and elements outside the
scope of the study and therefore contains some uncertain elements in its result. It is necessary to conduct further
detailed study in the future.
The cash flow of the project is shown as below.
9-11
Table 9-9: EIRR Calculation Cash Flow (Base Case)
-4
2014
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
%
Cost of gas
Benefit Total
Operational Cost
EIRR
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
Cost of gas
Benefit Total
Operational Cost
-3
2015
5
0
28.0%
-2
2016
5
0
-1
2017
291
0
0
2018
193
0
1
2019
1,555
632
1,844
1,538
498
553
287
2
2020
1,555
632
1,829
1,523
498
553
302
3
2021
1,555
632
1,834
1,527
498
553
298
4
2022
1,555
632
1,838
1,532
498
553
293
5
2023
1,555
632
1,842
1,536
498
553
289
6
2024
1,555
632
1,847
1,541
498
553
284
7
2025
1,555
632
1,851
1,545
498
553
280
8
2026
1,555
632
1,856
1,550
498
553
276
24
24
24
25
25
25
25
26
187
1
9
2027
1,555
632
1,860
1,554
498
553
271
10
2028
1,555
632
1,865
1,558
498
553
267
11
2029
1,555
632
1,869
1,563
498
553
262
12
2030
1,555
632
1,874
1,567
498
553
258
13
2031
1,555
632
1,876
1,570
498
553
255
14
2032
1,555
632
1,878
1,572
498
553
253
15
2033
1,555
632
1,880
1,574
498
553
251
16
2034
1,555
632
1,883
1,576
498
553
249
17
2035
1,555
632
1,885
1,579
498
553
246
18
2036
1,555
632
1,885
1,579
498
553
246
19
2037
1,555
632
1,885
1,579
498
553
246
20
2038
1,555
632
1,885
1,579
498
553
246
26
26
27
27
27
28
28
28
29
29
29
30
Table 9-10: EIRR Calculation Cash Flow (Case1: The Location of the FSRU is 100 km )
-4
2014
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
%
Cost of gas
Benefit Total
Operational Cost
EIRR
Cost of gas
Benefit Total
Operational Cost
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
-3
2015
6
0
26.2%
-2
2016
6
0
-1
2017
313
0
0
2018
206
0
1
2019
1,555
632
1,844
1,538
498
553
287
2
2020
1,555
632
1,829
1,523
498
553
302
3
2021
1,555
632
1,834
1,527
498
553
298
4
2022
1,555
632
1,838
1,532
498
553
293
5
2023
1,555
632
1,842
1,536
498
553
289
6
2024
1,555
632
1,847
1,541
498
553
284
7
2025
1,555
632
1,851
1,545
498
553
280
8
2026
1,555
632
1,856
1,550
498
553
276
24
24
25
25
25
26
26
26
201
1
9
2027
1,555
632
1,860
1,554
498
553
271
10
2028
1,555
632
1,865
1,558
498
553
267
11
2029
1,555
632
1,869
1,563
498
553
262
12
2030
1,555
632
1,874
1,567
498
553
258
13
2031
1,555
632
1,876
1,570
498
553
255
14
2032
1,555
632
1,878
1,572
498
553
253
15
2033
1,555
632
1,880
1,574
498
553
251
16
2034
1,555
632
1,883
1,576
498
553
249
17
2035
1,555
632
1,885
1,579
498
553
246
18
2036
1,555
632
1,885
1,579
498
553
246
19
2037
1,555
632
1,885
1,579
498
553
246
20
2038
1,555
632
1,885
1,579
498
553
246
26
27
27
27
28
28
28
29
29
29
30
30
Table 9-11: EIRR Calculation Cash Flow (Case2: The Operational Period is 10 years)
-4
2014
Cost of gas
Benefit Total
Operational Cost
EIRR
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
MMUSD
%
5
0
26.6%
-3
2015
-2
2016
5
0
281
0
-1
2017
192
0
0
2018
1
2019
1,555
632
1,844
1,538
498
553
287
2
2020
1,555
632
1,829
1,523
498
553
302
3
2021
1,555
632
1,834
1,527
498
553
298
4
2022
1,555
632
1,838
1,532
498
553
293
5
2023
1,555
632
1,842
1,536
498
553
289
6
2024
1,555
632
1,847
1,541
498
553
284
7
2025
1,555
632
1,851
1,545
498
553
280
8
2026
1,555
632
1,856
1,550
498
553
276
9
2027
1,555
632
1,860
1,554
498
553
271
10
2028
1,555
632
1,865
1,558
498
553
267
24
24
24
25
25
25
25
26
26
26
187
1
9-12

Feasibility Study for Introduction of LNG Receiving Facilities in

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