International LNG Trade
The Emergence of a Short-Term Market
by
Panagiotis G. Athanasopoulos
M. Sc. Marine and Ocean Technology and Science
National Technical University of Athens, 2004
Dipl. Naval Architecture and Marine Engineering
National Technical University of Athens, 2001
SUBMITTED TO THE DEPARTMENT OF MECHANICAL ENGINEERING IN
PARTIAL FULFILLMENT OF THE REQUIREMENTS FOR THE DEGREE OF
MASTER OF SCIENCE IN OCEAN SYSTEMS MANAGEMENT
AT THE
MASSACHUSETTS INSTITUTE OF TECHNOLOGY
JUNE 2006
C Panagiotis G. Athanasopoulos, MMVI. All rights reserved
The author hereby grants to MIT permission to reproduce and to distribute publicly paper
and electronic copies of this thesis document in whole or in part in any medium now
known or hereafter created.
Signature of the author....................
...................................
DepartiieiifiTMeehanical Engineering
May 12, 2006
A
C ertified by ...................................
Dr. Henry
Accepted by...........................
MASSACHUSETTS INSITIfITE.
..........-:......... 9. . . .. .... . .. . .. - N ..........................
Dr. Lallit Anand, Professor of Mechanical Engineering
Chairman, Department Committee in Graduate Student
OF TECHNOLOGY
JUL 14 2006
LIBRARIES
.............. .
....................
Marcus, Professor of Marine Systems
Thesis Supervisor
ARCHIVES
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2
International LNG Trade
The Emergence of a Short-Term Market
by
Panagiotis G. Athanasopoulos
Submitted to the Department of Mechanical Engineering on May 12, 2006 in Partial
Fulfillment of the Requirements for the Degree of
Master of Science in Ocean Systems Management
ABSTRACT
Natural gas is estimated to be the fastest growing component of world primary energy
consumption. Liquefied natural gas (LNG) supply chain is a way of transporting natural
gas over seas, by following a procedure of gas liquefaction, transportation in specialized
tankers and regasification. During the last decade the LNG market changed substantial
with the emergence of a short-term market. Analysis was performed examining the needs,
the conditions and the risks of this change. The implications of the short-term market were
investigated and an assessment was made regarding the future of a global LNG market.
Certain risk management approaches were introduced and the implications of cost
reduction in the LNG supply chain were examined. A computer model was created to
investigate the profitability, on behalf of the shipowner, of three short-term trading routes.
The future liquefaction and regasification capacity were presented, along with the future
growth of the LNG fleet. Finally, a forecast for the future level of the LNG short-term
trade was conducted.
Thesis Supervisor: Dr. Henry S. Marcus
Title: Professor of Marine Systems
3
AKNOWLEDGEMENTS
I am indebted and very grateful to my Thesis Supervisor, Dr. Henry S. Marcus, for his
support and guidance not only during the preparation of this study, but also during the
whole time that I have spent in MIT.
Furthermore, I would like to thank my friends Takis, Nikos, Despoina, Sofia,
Michalis, Dimitris, George and Christina, Charis and Stavroula for their care and support
during the whole course.
Dora has a very special place in my heart and I thank her for her love and support.
Being there for me each time I needed her gave me the strength to carry on.
Last, but definitely not least, I would like to thank my family, George, Amalia,
Chrysoula and Charilaos for providing me the opportunity of studying in MIT and helping
me, in numerous ways, on the completion of my studies.
I dedicate this Thesis to my grandmother Maria whose words still vividly sound in my
ears: "Bpe KepX! Ba~t(dipe! Tdiar poo
U\V TOV iXa VY60,
Paoti;
Oa toD Etqa.........'
4
va yivrtg! Na To iub? 9a to
it6!
MOpt
TABLE OF CONTENTS
ABSTRACT ..........................................................................................................................
3
AKNOWLEDGEMENTS ...............................................................................................
4
TABLE OF CONTENTS .................................................................................................
5
LIST OF FIGURES ..........................................................................................................
9
LIST OF TABLES ..........................................................................................................
12
NOMENCLATURE AND ACRONYMS ......................................................................
13
CHAPTER 1 - INTRODUCTION.....................................1
B AC K GR OU N D ...................................................................................................................
15
P URPO SE ...........................................................................................................................
17
PR O CEDU RE ......................................................................................................................
18
CHAPTER 2 - INTERNATIONAL LNG TRADE........................................................19
GLOBAL NATURAL GAS CONSUMPTION.........................................................................19
EVOLUTION OF LNG TRADE ..........................................................................................
22
LNG EXPORTING COUNTRIES-LIQUEFACTION PLANTS ..................................................
26
LNG IMPORTING COUNTRIES-REGASIFICATION PLANTS .............................................
28
CURRENT LNG FLEET....................................................................................................31
CHAPTER 3 - FINANCING LNG PROJECTS............................................................34
TRADITIONAL LONG -TERM CONTRACTUAL FRAMEWORK ............................................
5
34
SALES AND PURCHASE AGREEMENT ..............................................................................
36
S P A R IGID ITIE S ................................................................................................................
40
EVOLUTION OF LONG-TERM CONTRACTS ....................................................................
42
EMERGENCE OF SHORT-TERM
LNG MARKET ...............................................................
45
LNG MARKET ..................................................
48
LNG MARKET............................................
52
TRANSPORTATION CONDITIONS OF SHORT-TERM LNG MARKET ................................
54
NATURAL CONDITIONS OF SHORT-TERM
ECONOMIC CONDITIONS OF SHORT-TERM
INSTITUTIONAL CONDITIONS OF SHORT-TERM
LNG MARKET......................................57
RISKS IN LNG PROJECTS................................................................................................59
POLITICA L R ISK ................................................................................................................
60
T ECH N ICAL R ISK ...............................................................................................................
64
FINANCIAL R ISK ................................................................................................................
66
RISK MANAGEMENT TECHNIQUES IN
LNG PROJECTS...................................................69
DOWNSTREAM AND MIDSTREAM INTEGRATION...........................................................
71
UPSTREAM AND MIDSTREAM INTEGRATION ................................................................
76
PRICING DEVELOPMENTS IN LNG CONTRACTS.............................................................78
POTENTIAL OF RISK HEDGING BY USING FINANCIAL DERIVATIVES..................................80
CHAPTER 4 - COST REDUCTION IN LNG SUPPLY CHAIN.............................84
COST REDUCTION IN
LNG SUPPLY CHAIN.....................................................................84
COST REDUCTION IN GAS PRODUCTION .........................................................................
COST REDUCTION IN LIQUEFACTION.............................................................................86
COST REDUCTION IN SHIPPING......................................................................................88
6
85
COST REDUCTION IN REGASIFICATION...........................................................................91
COST REDUCTION AND LNG ECONOMIC FEASIBILITY .................................................
92
CHAPTER 5 - PRICE ARBITRAGE BETWEEN LNG MARKETS ....................
95
PRICE ARBITRAGE IN LNG TRADE ....................................................................................
95
PRICE ARBITRAGE IN THE ATLANTIC BASIN.................................................................
98
PRICE ARBITRAGE IN THE PACIFIC BASIN .......................................................................
102
CHAPTER 6 - FINANCIAL FEASIBILITY OF SHORT-TERM LNG TRADING IN
THREE ROUTES............................................................................................................105
A NNUAL PROFITABILITY .................................................................................................
105
CHAPTER 7 - FUTURE INTERNATIONAL LNG TRADE.....................................110
FUTURE
LN G DEM AND ...................................................................................................
LNG REGASIFICATION TERMINALS CONSTRUCTED UNTIL 2011 ....................................
FUTURE
LNG PRODUCTION ............................................................................................
110
116
118
LNG LIQUEFACTION TERMINALS CONSTRUCTED UNTIL 2011 .......................................
124
FUTURE LN G FLEET .......................................................................................................
125
FORECAST OF LNG SHORT-TERM TRADE .......................................................................
131
CHAPTER 8 - CONCLUSIONS....................................................................................135
WORKS CITED...............................................................................................................138
WORKS CONSULTED ..................................................................................................
141
APPENDIX I ....................................................................................................................
144
7
APPENDIX 11 .............................................................................
8
147
LIST OF FIGURES
Figure 1: World marketed energy use by fuel type, 1970-2025. .....................................
15
Figure 2: Fuel share of world electricity generation, 2002-2025.....................................16
Figure 3: (a) World natural gas consumption and (b) consumption by end user, 1980-2025.
......................................................................................................................................
19
Figure 4: (a) Natural gas consumption by region and (b) increases in consumption by
co u n try g ro u p ...............................................................................................................
21
Figure 5: Natural gas consumption in mature market economies by source, 2002-2025....21
Figure 6: World gas reserves as of January 1, 2006 .......................................................
22
Figure 7: The L NG chain .................................................................................................
23
Figure 8: Expansion of LNG markets under medium and long-term contracts........24
Figure 9: Natural gas and LNG trade, 1970-2004............................................................25
Figure 10: Natural gas and LNG contractual flows in 2004 ............................................
26
Figure 11: LN G im ports, 1970-2004 ..............................................................................
29
Figure 12: Methane Pioneer, the first LNG carrier..........................................................31
Figure 13: Total LNG fleet and orderbook, 1970-2005...................................................32
Figure 14: Representation of the gas contract arrangement............................................35
Figure 15: Long-term and short-term LNG markets............................................................46
Figure 16: Evolution of short-term LNG trade, 1993-2004..................47
Figure 17: Conditions and dynamic structure of the short-term LNG market.........48
Figure 18: LNG exports compared with liquefaction capacity.......................................49
Figure 19: Source of short-term exports by region .............................................................
9
50
Figure 20: Destination of short-term imports by country ................................................
51
Figure 21: Cumulative incremental growth of the world's capacity and trade................53
Figure 22: Cumulative growth of new and de-bottlenecked capacity..............................54
Figure 23: LNG tanker capacity and tanker demand, 1978-2002....................................56
59
Figure 24: Risks encountered in LNG projects..............................................................
Figure 25: Sourcing of global LNG traded volumes.......................................................61
Figure 26: Risk management in LNG projects. ..................................
70
Figure 27: A regionally diversified portfolio greenfield LNG projects compared to the
upstream capital budgets of selected companies.....................................................75
Figure 28: Long-term LNG price formula for the European market ...............................
79
Figure 29: Costs in the LNG supply chain, 1980s-2004................................................85
Figure 30 : Total transportation cost per MBtu for a 145,000 m2 LNG vessel................89
Figure 31: LNG newbuilding prices, 1980 to 2005 .......................................................
90
Figure 32 : Long-term LNG shipping rates ....................................................................
91
Figure 33 : Netback analysis for the Bonny project in 1998 and in 2004.......................93
Figure 34 : Regional distribution of uncommitted volumes of the 2010 firm and probable
LN G p rojects ................................................................................................................
96
Figure 35 : Movement of Trinidad's LNG volumes between USA and Spain, 1999 to 2003.
......................................................................................................................................
99
Figure 36 : Netbacks to Trinidad, Nigeria and Qatar from shipping to Spain, USA and
Japan, Decem ber 2000. ..............................................................................................
10
100
Figure 37 : Netbacks to Trinidad, Nigeria and Qatar from shipping to Spain, USA and
1
Japan, Septem ber 200 1...............................................................................................10
Figure 38 : Netbacks to Trinidad, Nigeria and Qatar from shipping to Spain, USA and
Japan , N ovem ber 2002 ...............................................................................................
10 1
Figure 39 : Illustrative netbacks for selected Atlantic arbitrage patterns...........................102
Figure 40 : Illustrative netback calculations for Qatar from the US Golf Coast, Spanish
and Jap anese m arket...................................................................................................103
Figure 41: Annual profit calculations for the route Dohra to Spain. ................................
107
Figure 42 : Annual profit calculations for the route Dohra to Boston. .............................. 108
Figure 43 : Annual profit calculations for the route Dohra to Japan. ................................
109
Figure 44: Global LNG demand forecast, 2010-2020 ......................................................
110
Figure 45 : LN G dem and forecast for A sia........................................................................111
Figure 46 : LNG dem and forecast for Europe ...................................................................
114
Figure 47 : LNG demand forecast for North America.......................................................115
Figure 48 : Global liquefaction outlook in 2005................................................................119
Figure 49 : Global existing and future liquefaction capacity as of 2005 ........................... 120
Figure 50 : Delivery dates of the LNG vessels in order until April 2006..........................129
Figure 51: LNG trade flows in 2002 and expected further flows by 2012.......................131
Figure 52 : Forecast analysis of the LNG short-term trade percentage. ............................ 133
11
LIST OF TABLES
Table 1: LNG liquefaction plants as of April 2005 .........................................................
27
Table 2: LNG regasification plants as of April, 2005.....................................................
30
Table 3: Expansion of upstream companies to the midstream and downstream sectors ..... 73
Table 4: Expansion of downstream companies to the midstream and upstream sectors ..... 77
T able 5 : Ship's characteristics and costs...........................................................................105
Table 6 Distance and travel time for the three trading routes..........................................106
Table 7 Planned LNG regasification terminals................................................................117
Table 8 : Liquefaction plants with signed SPA/HOA ........................................................
124
Table 9 : World LNG orderbook as of April 21st 2006......................................................126
Table 10 : Estimated number of required LNG vessels until 2011....................................130
Table 11 : Forecast analysis...............................................................................................145
Table 12 : Annual profit results for the route Dohra to Spain ...........................................
148
Table 13 : Annual profit results for the route Dohra to Boston .........................................
149
Table 14 : Annual profit results for the route Dohra to Japan ...........................................
150
12
NOMENCLATURE AND ACRONYMS
Bcf - Billion cubic feet
Bcm - Billion cubic meters
BTU - British Thermal Unit
c.i.f - cost, insurance and freight
CCGT - Combined Cycle Gas Turbine
CNOOC - Chinese Offshore Oil Company
CRE - Comision Regulatora de Energia
d.e.s. - delivered ex ship
DFDE - Duel Fuel Diesel Electric
EPC - Engineering, procurement and construction
f.o.b - free on board
FERC - Federal Energy Regulatory Committee
GTI - Gas Technology Institute
IOC - International Oil Companies
IPE - Intrnational Petroleum Excange
JCC - Japanese Crude Cocktail
Kogas - Korea Gas Company
LNG - Liquefied Natural Gas
Mtpa - Million tons per annum
NBP - National Balancing Point
13
NIGEC - National Iranian Gas Export Policy
NPC - National Petroleum Council
NWS - Australian North West Shelf
NYMEX - New York Merchantile Exchange
OECD - Organization for Economic Co-operation and Development
OTC - Over The Counter
RasGas - Ras Laffan Natural Liquified Gas Corporation
SPA - Sales and Purchase Agreement
STS - Ship To Ship
TAGP - Trans ASEAN Gas Pipeline
TaP - Take and Pay
TEPCO - Tokyo Eelectric Power Company
ToP - Take or Pay
14
CHAPTER 1 - INTRODUCTION
BACKGROUND
The development of the global natural gas industry over the past 30 years has been
remarkable by any measure. In volume terms the reserve base has roughly doubled, and
annual usage has grown by more than 100% as presented in Figure 1.
Quladrl-on Btu
Projections
250History
200
150
100 -coal
Renewables
1 raI Gas
50
__________________Nuclear
1970
1980
2002
1990
2015
2025
Figure 1: World marketed energy use by fuel type, 1970-2025. (EIA, 2005)
Prior to the energy crises in 1970s, and the oil and energy price increases that
followed, natural gas was very much a poor relation in the energy business. Oil was cheap,
the costs of developing and transporting gas to market were high for the developer, and the
economic returns to the host government from such developments was significantly less
than for oil. Apart from the events in the 1970s, the environmental movements which
followed highlighted the advantages of natural gas as a fuel compared with oil products
and coal when levels of polluting emissions were considered. However, the attribute which
15
opened up a new demand sector for the natural gas, was the high efficiency of gas-toelectricity conversion through the use of gas in combined cycle gas turbines
(CCGT).(ECSSR, 2001)
Natural gas is expected to be a favored choice for new electricity generation capacity
built over the next two decades. The natural gas share of total energy used to generate
electricity worldwide will increase, according to the EIA forecast, from 18% in 2002 to
24% in 2025, (Figure 2), with other energy sources showing small losses in market share.
(EIA, 2005)
-ercen of' Total
10c
8C
*~tural -0as
6C
*Nuclear
MRenewal es
40
ECoal
MOU
20
C
2002 2010 2015 2020 2025
Figure 2: Fuel share of world electricity generation, 2002-2025. (EIA, 2005)
Where local supplies of natural gas are not available in adequate quantities, the trend
has been to acquire gas from foreign suppliers either as pipeline gas or as liquefied natural
gas (LNG). Historically, the LNG industry started in 1959 when the vessel Methane
Pioneer transported the first LNG shipment from Louisiana to the UK's Canvey Island.
The following years more countries, like Japan, Italy, Spain, France and Taiwan
commenced importing LNG and currently plans are at an advanced stage for India and
16
China. According to statistical data the percentage of natural gas traded as LNG increased
from 24.7% in 1993, to 26.2% in 2004. (BP, 2005)
Liquefied natural gas is expected to play an increasingly important role in the natural
gas industry and global energy markets in the next several years. The combination of:
i.
Higher natural gas prices
ii.
Lower LNG costs
iii. Riding gas import demand, with a new demand wave triggered by gas to power
iv. Traditional gas exporting countries, like Australia, Canada and Norway, now
becoming import dependent and
v.
The desire of gas producers to monetize their gas reserves
is setting the stage for increased global LNG trade. (EIA, 2003)
PURPOSE
The purpose of this thesis is, apart from providing a brief overview of the international
liquefied natural gas market, to concentrate on the evolving contractual framework of the
LNG chain. Specifically, this research will focus on the emergence of short-term trading; a
practice increasingly used in recent years in order to cover part of peak gas demand. Effort
will be given to identify the changes of the LNG trade and the linkage between different
gas markets, which is the result of shifting gas volumes between regions based on
differences in their supply and demand balance. The conditions and implications of the
emergence of the short-term LNG market will be analyzed and a financial evaluation of
three trading routes will be examined. Finally, the future of the international LNG supply
chain will be assessed.
17
PROCEDURE
First the issue of international LNG trade will be addressed by presenting the global
gas consumption and the main LNG import and export countries. Also, the most updated
data regarding the current LNG fleet will be provided.
Then the financing of LNG projects will be introduced. The traditional long-term
contracts will be reviewed and their revolution during the last years. Most importantly, this
section will focus on the emerging short-trade market and the risks associated with the
greenfield projects. The methods of risk migration for the stakeholders of the industry will
be presented along with the overview of the potential usage of financial derivatives.
After the contractual framework overview the issue of cost reduction in the LNG
supply chain will be discussed. Cost reduction in liquefaction, regasification and
transportation of natural gas will be addressed and special attention will be drawn over the
influence of LNG transportation cost to match supply and demand.
The presence of price arbitrage in the Atlantic basin will be addressed next as a
driving force behind the growth of the short-term LNG trade. The possibility of a price
arbitrage in the Pacific basin will be also overviewed.
An examination of the profitability of three short-term trading routes will then be
conducted on behalf of the shipowner. The minimum number of round trips and the
minimum value of spot-rate will be calculated for a newbuild 150,000 m3 LNG vessel.
Finally, there will be a look into the future growth of the international LNG trade, by
presenting the forecasted future gas demand and the LNG production and imports. The
new terminals planned or under construction will be discussed along with the future LNG
ships fleet. Then the expected growth of the short-term market will be estimated.
18
CHAPTER 2- INTERNATIONAL LNG TRADE
GLOBAL NATURAL GAS CONSUMPTION
According to the Energy Information Administration natural gas is projected to be the
component
fastest growing
of world primary energy
consumption.(EIA,
2005)
Consumption of natural gas worldwide will increase by an average of 2.3% annually from
2002 to 2025, compared with projected annual growth rates of 1.9% for oil consumption
and 2.0% for coal consumption. As presented in Figure 3a, from 2002 to 2025,
consumption of natural gas is projected to increase by almost 70%, from 92 trillion cubic
feet to 156 trillion cubic feet, and its share of total energy consumption on a Btu basis is
projected to grow from 23% to 25%. Gas use for power generation has become the driver
for the recent wave of gas demand. Based on the analysis of EIA, the electric power sector
will account for 51% of the total incremental growth in worldwide natural gas demand
over the next 15 years (Figure 3b).
Tr
ICi
iocu
eeri
H3scory
2
E-
Projection S
e
':' F VErI
1Transportation
industnal
142
-
128
111
-
Residea
92
2
142
111
120
73
(a)
92
(b)
Figure 3: (a) World natural gas consumption and (b) consumption by end user, 1980-2025. (EIA,
2005)
19
By analyzing the forecasts a very interesting conclusion is reached regarding the
future growth of the LNG trade. A close look at the forecasted consumption, Figures 4 and
5, leads to two conclusions. First, the consumption in the emerging economies of Asia will
almost triple and the reason for that is the rapid expansion of natural gas industry in India
and China. The Chinese government is committed to a rapid increase in the share of natural
gas in the country's energy mix. India is also stepping into the international LNG trade
scene with the power and fertilizer sectors being forecasted as the main consumers. The
second conclusion is that in the mature market economies, where natural gas markets are
more established, consumption of natural gas is projected to increase by an annual average
of 1.6% from 2002 to 2025. It should be noted that according to the forecasts the largest
incremental growth in the mature market economies is projected for North America, at 11
trillion cubic feet.
However, this increase in the consumption is not followed by a relevant increase of the
production. This disparity between the increase projected for natural gas consumption in
the mature market economies and the much smaller increase projected for their gas
production points to an increasing dependence on the transitional and emerging market
economies for gas supplies, as presented in Figure 5. In 2002, the mature market
economies accounted for 42% of the world's total natural gas production and 50% of the
world's natural gas consumption; in 2025, they are projected to account for only 29% of
production and 43% of consumption. As a result, the mature market economies are
expected to rely on imports of natural gas from other parts of the world to meet almost
one-third of their natural gas consumption in 2025, up from 15 percent in 2002.
20
Trillion Cubic Feet
100
History
Prjechons
*Mature Market Econorries
ETransibonal Economies
MEr erging Economies
80-
EE/FSU
Ergrci#g Asi3
North Amnca
60-
40k
0
1980
1990
2002
I1
2010
2015
2020
Mid le East
Westem Europe
&ent-a d r
~-tAnle rica
Antca
Mature Market Asia
I
6
2025
1'0
1
Trilion Cubic Feet
(a)
(b)
Figure 4: (a) Natural gas consumption by region and (b) increases in consumption by country
group. (EIA, 2005)
100-
Trillion Cubic Feet
80-
MErl rg ng Economies Imports
MEE/FSU Imports
*(kmnesic Production
604020-
'
0
2002
2010
2015
2020
2025
Figure 5: Natural gas consumption in mature market economies by source, 2002-2025. (EIA,
2005)
The importance and potential of LNG trade is revealed when the regional reserves are
examined. In Figure 6 the world reserves of natural gas as of
[St
of January 2006 are
plotted. Leaving aside Russia, which may account for 27.5% of the total world reserves,
but does not have until now a clear market framework and LNG export strategy and uses
21
20
pipelines for the transportation of its resources, the majority of the world's reserves are
concentrated in Middle East. The share of the Middle East countries, 38.1% of the world
reserves, is not only impressive but also indicative of the demand for LNG transportation
from the Middle East region to the mature markets of North America and Western Europe,
and the emerging economies of Asia.
184-7
Nigeria
United States
UAE
2
Saudi Arabia
Qatar
,:0.2
Iran
Russia
12-1
Total World
0
1000
2000
3000
4000
5000
6000
7000
Natural Gas Reserves (Trillion Cubic Feet)
Figure 6: World gas reserves as of January 1, 2006. Source (Oil & Gas Journal, 2005)
EVOLUTION OF LNG TRADE
An LNG project represents a chain of investments whose ultimate success is at risk to
the possible failure of its weakest link. As it is illustrated in Figure 7 the chain consists of
five links: field development and production, where the natural gas is extracted;
liquefaction, at this stage natural gas is liquefied in a liquefaction plant known as train;
shipping in special tankers with heavily insulated tanks; regasification where the LNG is
gasified and finally distribution to the marketers.
22
Production
Liquefaction
Transportation
4
Distribution
Regasification
Figure 7: The LNG chain. (Buoncristian, 2005)
Prior to the development of the LNG chain described above, the transportation of
natural gas was limited to movements that could be served by pipeline. Gas was unable to
utilize the mainstay of international oil trade, namely marine transportation. The scene
changed in 1960 with the construction of the first base-load liquefaction plant at Arzew,
Algeria to process natural gas form the giant Hassi R' Mel field. (Greenwald, 1998) The
latter was part of the so called CAMEL project which was the first commercial LNG trade
to deliver Algerian gas to the UK and France. By 1969, three more trades had started from
Algeria to France, Italy and Spain, and one from the Cook Inlet of Alaska to Japan, the
first Pacific project. While the first deliveries from Algeria were comparatively short hauls
23
to Europe, the USA entered the market first in 1973 when deliveries started for the small
Distrigas (Cabot) project at Everett, MA.
The development of the early US projects took place during a period of unprecedented
change in international energy markets. This included the two oil price shocks, the
widespread nationalization of the international oil companies' concession areas within
OPEC, and the restructuring of the North American gas industry. While LNG imports into
Europe continued to increase, the North American trade nearly collapsed, thereby blunting
what was expected to be a substantial growth in Atlantic Basin trade. With the substantial
slowdown in interest in LNG in the Atlantic, the balance of interest shifted to the Pacific as
Korea and Taiwan joined Japan as importers.(Jensen, 2004) In Figure 8 the expansion of
the LNG market under medium and long term contracts is presented.
196A9
krr BIm
DateDae
Exqft~pwt AkIE
DT1970-1979
ekr limp
1971 1-
UY
QAItaly
ibya
US
Itl 161Algeria
Brunei
St
969Indonesia
Abu Dhabi
Japan
1973 I2
1973
1977
1
E
3
Al gria
!
USA
1990-199
18
Dake
i 192
Km1MFrance
197
19
1991
K9orea
20
199f
Nigeapnn98Italy 1999 As&Kra2004
Turkc 1999
Taiwan 1990
ur
MaasaKorea 1991
Indonesia Taiwan 1990
1998
Ja
Korea
1999
Figure 8: Expansion of LNG markets under medium and long-term contracts. Source (Odawara,
2004)
The rate of increase of LNG trade followed the rate of increase of the natural gas until
1994. From 1994 to 2004, LNG showed a remarkable growth and revealed as one of the
fastest growing sectors of the international energy industry. During that period LNG trade
grew on average 7.4% per year surpassing the growth rate of natural gas as presented in
24
Figure 9. The total amount of LNG traded in 2004, on a contractual basis, was equal to
.
177.95 billion in 3
Billion m 3
210
3,000
2,500
175
2
2,000
140
F
1,500e
105
1,000-
70
500-
35
0
0
70
72
74
76
78
80
82
84
86
88
Natural Gas (left axis) -
90
92
94
96
98
00
02
04
LNG (right axis)
Figure 9: Natural gas and LNG trade, 1970-2004. (Gardiner, October 25th, 2005)
The flows of international LNG trade in 2004 are illustrated in Figure 10. It should be
mentioned that the values in the table of Figure 10 are based on a contractual basis and
may not correspond accurately to physical flows. In order to have a more precise view of
the LNG flows the regasification and liquefaction capacities of the plants should also be
taken under consideration. By examining the historical evolution of the LNG flows, it is
clear that during the last two years certain notable changes in the LNG trade occurred.
These changes originated from movements of gas exporting countries in Middle East, like
Qatar, which are making active efforts to expand to markets of new LNG importing
countries, like India and China, which have not been among the traditional players in the
LNG market of the Asian-Pacific region. (Odawara, 2004)
25
Major trade movements
Trade flows worldwide fbillion cubic metros)
AN.22
62.
0
2.25
3.41
11.04
13.13
-00
10.75
7.11
USA
Canada
Mexico
7.20
S. & Cent. America
Eurasia
Europe
&
Middle
East
Africa
Asia
4 Natural gas
Pacific
LNG
,Trade movements 2004 - liquefied natural gas (LNG)
To
I
From
LISA
&
Tego
Dominican Republic
Puerto Rico
Italy
Portugal
Span
Turkey
Asia Pacific
India
Japan
South Korea
Taiwan
-
-
0.57
-
-
-
-
-
-
-
Nigena
Australia
-
3.41
-
0.33
0.42
-
-
-
-
-
-
-
2.85
-
-
-
1.20
3.91
0.20
0.63
-
-
-
6.58
3.24
-
2.63
9.22
7.96
7.10
0.08
-
-
0.30
-
-
-
-
0.27
0.34
-
IJA
13.13
-
0.18
-
-
-
1.68
-
-
-
1,48
6.00
-
-
-
0.68
Europe
Belgium
France
Greece
Malysa
Lka
Gatr
-
S. & Cent. America
Indon+sta
Algeria
Oman
North America
USA
I
-
Billion cubic metres
0.0
-
6.72
0.55
2.10
-
-
-
-
0,83
-
3.8
1.31
4.81
1.063
Bn~E
-
0.18
-
-
-
-
-
-
0.16
0.24
11.20
0.55
8.29
1.21
21.19
7.30
16.63
6.25
4.05
0.06
-
-
5.00
knpo s
18.471
0.11
0.68
2.85
7.63
0.55
5.90
1.31
17.51
4.27
2.63
76.95
29.89
9.13
Figure 10: Natural gas and LNG contractual flows in 2004. (BP, 2005)
LNG EXPORTING COUNTRIES-LIQUEFACTION PLANTS
Since the 1960s the number of exporting countries rose from 2 to 13. Up until April
2005 the world LNG production capacity was equal to 158.6 billion m 3 per year with 72
production trains as illustrated in Table 1. Three countries Nigeria, Malaysia and Qatar
hold 38.5% of the total LNG production.
26
Table 1: LNG liquefaction plants as of April 2005. Source (Suzuki & Morikawa, 2005) and
cornpanies sites
47.6
30
RAfrica
Algeria
Arzew GL4Z
Arzew GLlZ
Arzew GL2Z
Skikda GLlK
Skikda GL2K
3
6
6
3
3
7.8
8
2.8
3
Damietta LNG
Egyptian LNG
1
2
5.5
7.2
UFG, EGAS, EGPC
BG, Petronas, EGAS, EGPC
Spain
Italy, France, USA
Mara el Brega
Nigeria
3
2.6
Serte Oil
Spain
Nigeria LNG
3
9.6
NNPC, Shell, Total, ENI
1.1
Europe, America
Sonatrach
Egypt
Libya
Italy, France,
32.5
13
Middle East
Abu Dhabi
Sai
ADGAS
3
5.4
ADNOC, Mitsui, BP, Total
Japa, Spain
Oman LNG
2
6.6
Shell, Total, Mitsui, Patrex, Itochu, Mitsubishi,
Oman
Japa, South Korea, Spain
Qatargas
3
9.2
Total, Mitsui, ExxonMobil, Marubeni, Qatar
Petroleum
Japan Spain
RasGas
2
6.6
Total, Mitsui, ExxonMobil, Marubeni, Qatar
Petroleum, Kogas, LNG Japan, Itochu
South Korea
RasGas
3
4.7
Qatar Petroleum, ExxonMobil
India
2
1.1
ConocoPhillips, Marathon
Japan
3
9.6
BP, BG, Repsol
USA, Spain
5
7.2
Brunei, Shell, Mitsubishi
Japan, South Korea
5
2
1
3
1
13.2
6
3.1
4.5
2
3
8.1
Oman
Qatar
North America
USA
Kenai
Trinidad Tobago
Atlantic LNG
Asia Pacific
10.7
5
28
70.4
Brunei
Brunei LNG
Indonesia
Bontang I, II, IV
Bontang III, VI
Bontang V
Arun I, II
Arun I
Malaysia
Malaysia LNG I
PT Badak NGL
PT Arun NGL
Japan
Taiwan
South Korea
Japan
South Korea
Petronas, Mitsubishi, Sarawak
Japan
Malaysia LNG 11
2
7.8
Petronas, Mitsubishi, Sarawak, Shell
Japan, South Korea,
Malaysia LNG III
Australia
NWS
76
World Total
2
6.8
Petronas, Mitsubishi, Sarawak, Shell, Nippon Oil
Japan, South Korea
11.7
Woodside, Shell, Chevron, BP, MMI
Japan
4
161.2
27
Africa, Algeria and Nigeria are the major production countries. In Algeria specifically,
Sonatrach, the Algerian national oil company, has the world's largest equity share in LNG
plants. Nigeria's LNG activities are set to increase rapidly during the next decade with
plans for additional LNG facilities being developed at the West Niger Delta.
Asia is a very important exporting region, with almost half of the world's exporting
capacity and liquefaction plants. Malaysia is the world's largest exporter with 22.7 billion
m3 production per year. Indonesia is second but with important plants under construction,
like the Tangguh project which is dedicated to supplying LNG to China.
Middle East has recently emerged as a major LNG exporting region with plants in
UAE, Oman and Qatar. However, what will be interesting the following years is the
attitude of Iran towards gas exportation. Iran, the holder of the world's second largest gas
reserves, is developing an LNG export policy under National Iranian Gas Export Policy
(NIGEP) which advances with a slow rate.
In America Trinidad and Tobago are the major exporting countries, but in the future
several other countries, mainly from South America, are planning to construct and operate
liquefaction plants.
LNG IMPORTING COUNTRIES-REGASIFICATION PLANTS
Asian markets, mostly Japan and Korea, currently dominate the LNG trade. Japan was
the first Asian country to import LNG and is currently the world's biggest importer with
76.97 billion m 3 contractual imports in 2004, as it is presented in Figure 11. South Korea
started to import LNG in 1986 and is now the world's second largest importer with 29.89
28
billion m3 . India is also emerging as an LNG importer with the first LNG shipment
delivered to the Indian company Petronet from Qatar's RasGas at the beginning of 2004.
LNG imports in Europe are expected to grow from the current level of 9%, to 25% in 10
years. The USA will be the key for LNG market growth, from 2002 to 2003 LNG imports
doubled to 14.6 billion m3 , while in 2004 imports increased by 26.5% to 18.47 billion i 3
200
180
160
140
120
100
806040
20
II IL
0.
70
72
74
76
MJapan
78
80
82
84
86
ES.Korea
88
90
0 Europe
92
94
96
98
00
'02
'04
MOther
Figure 11: LNG imports, 1970-2004. (Gardiner, October 25th, 2005)
In Table 2 the world's total regasification plants are presented as of April, 2005. Japan
has 24 regasification plants with a total capacity of 60.47 billion m3 . USA is second with 4
regasification plants and a capacity of 24.4 billion m3 . Continuing increases in demand and
the reforms of European gas market are leading to new opportunities for LNG, especially
for the Mediterranean countries which account for 21.6% of the world's regasification
capacity.
29
Table 2: LNG re asification lants as of A ril, 2005. Suzuki & Morikawa, 2005 and companies sites
1322
26.1
North America
USA
5.4
155
285
373
189
Tractebel LNG
Trunkline LNG
Dominion
Southern LNG
Excelerate (This is an offshore receiving terminal
and not a regasification plant)
160
EcoElectrica
160
AES
Tobata
Fukuoka
Nagasaki
Kagoshima
0.15
0.4
7
9.5
6
1.5
3.5
0.34
1.4
3.1
0.8
3
0.3
4
8.5
2.6
2.6
0.2
1.3
2.6
1.3
0.2
0.1
0.08
80
720
860
2660
540
600
1180
177
300
640
200
200
160
480
180
740
520
85
480
460
480
70
35
36
Sendai City Gas
Nikhokan LNG
Tokyo Electric
Tokyo Electric
Tokyo Electric
Tokyo Gas
Tokyo Gas
Shimizu LNG
Chubu Electric
Chita LNG
Toho Gas
Chubu Electric
Toho Gas
Chubu Electric
Osaka Gas
Osaka Gas
Kansai Electric
Hiroshima Gas
Chugoku Electric
Oita LNG
Kitagamishu LNG
Saibu LNG
Saibu LNG
Nihon Gas
Yung An
7.44
690
CPC
Daheii
5
320
Petronet
Pyeongtack
Inchon
Tongyoung
7.2
7.2
3
1000
1680
420
Kogas
Everett
Lake Charles
Cove Point
Elba Island
7.7
7.7
3.4
Gulf Gateway Deepwater Port 500 mcfday
Puerto Rico
1.3
Penualas
Dominic Reb.
Andres
0.6
4146
90.31
Asia
Japan
Sendai
Higashi Niigata
Futtsu
Sodegama
Higashi Ogishima
Ogishima
Negishi
Sodeshi
Chita Kyodo
Chita
Chita Midorihama
Yokkaichi LNG
Yokkaichi
Kawagoe
Senboku
Himeji
Himeji LNG
Hatsukaichi
Yanai
Oita
Taiwan
India
South Korea
43.1
Europe
Belgium
510
Zeebrugge
4.8
261
Fluxys
Fos-sur-Mer
Montoir de Bretagne
5.8
8.2
150
360
Gaz do France
Panigalia
2.6
100
Nam
Barcelona
Cartagena
Huelva
Bilbao
6.2
0.9
2.7
2
240
55
165
160
Enagas
Sines
3.8
120
Transgas
Revythoussa
1.5
130
DEPA
255
Botas
France
Italy
Spain
Portugal
Greece
Turkey
Marmara Ereglisi
World Total
4.6
159.51
5978
30
CURRENT LNG FLEET
More than 50 years ago in 1954, active studies started in four countries, Norway,
France, United Kingdom and USA, for ship designs to transport LNG. After five years
Continental Oil Co. and Union Stockyards joined to convert a dry cargo vessel into an
LNG carrier. The resulting Methane Pioneer, presented in Figure 12, transported the first
LNG shipment in the world. (Greenwald, 1998)
Figure 12: Methane Pioneer, the first LNG carrier. (Heath, 2005)
From 1959 until 1984 there was a steady but slow increase in the number of LNG
vessels with a total fleet in 1984 just below 80. From 1985 to 1993 there was stagnation in
the LNG orders with no interest from the shipowner community in ordering new vessels.
This image started to change after 1994 with an almost exponentially increasing interest
for LNG tankers and new orders reaching the level of 113 vessels in 2004 and 136 vessels
until April 2006. (Hine, 2006a) The two types of tank design are the spherical tank or
31
Moss and the membrane tank design. In Figure 13 the LNG fleet and the world's
orderbook are illustrated from 1970 to 2005.
Number of vessels
200
180
160
140
120
100
80
60
*~iIII
40
.
i I
2:
1970
1975
1980
1990
1985
1995
2000
2005
U Orderbook
E Total Fleet
Figure 13: Total LNG fleet and orderbook, 1970-2005. (Gardiner, October 25th, 2005)
Until July, 2005 the total LNG fleet was equal to 177 vessels with a total deadweight
of 11,461,384 tons. The average deadweight of the fleet was 64,753.58 tons, while the
average age was equal to 14.35 years. (Lloyd's Register, 2006) However, with more ships
delivered, up until April 21" 2006 the total number of LNG ships was equal to 197
according to LNG Shipping Solutions.(TradeWinds, 2006a)
The standard cargo tank size in the 1970s and 1980s was 125,000m3, and in the 1990s
135,000m 3 . In the last three or four years, the standard size has increased to 145,000m 3 and
155,000m 3 . Specifically, in the Qatar expansion project, which is the largest LNG project
in terms of required capital, it was decided to use vessels with a cargo tank size of over
210,000m3.
The LNG vessels can be categorized according to their size in five classes:
32
i.
Med-max of 75,000 m3 tank volume
ii.
Conventional of 135,000-160,000 m 3 tank volume
iii. 'Atlantic-max' of 175,000 m3 tank volume
iv. Q-flex of 210,000 m3 tank volume
v.
Q-max of 250,000 m 3 and above tank volume. (Powell-Kite, 2005)
On March 2006 Qatar Ship Acquisition Team signed with Samsung shipyard a
shipbuilding contract for three 266,000 cbm ships for delivery in 2008, as part of its 70
LNG ships plan. When complete, they will be the largest LNG vessels in the world.(Hine,
2006b) Driving the increasing trend is the market's demand for increased efficiencies and
transportation cost reductions. In the Qatar project, the importer's main receiving terminal
is on the Gulf Coast in North America, making the line one of the longest distance trade
lines in the world. It takes more than 45 days for the round trip, making efficient
transportation critical for the success of the project. (Hashimoto, 2005)
Passing to the propulsion systems of the LNG vessels it is clear that the need for
reliable steam turbine engine is ever increasing, with much skepticism in the shipowning
cycles at the innovative French companies of Gaz de France and Chantiers de I' Atlantique
for building dual fuelled diesel electric (DFDE) vessels. However, BP and AP Moller
followed the example of Gaz de France and ordered 4 and 2 DFDE ships respectively in
2004. Also, Qatar aided by ExxonMobil, allocated 8 new 200,000 m3 vessels with slowspeed diesel engines equipped with re-liquefaction plants.(BRS, 2005)
33
CHAPTER 3 - FINANCING LNG PROJECTS
TRADITIONAL LONG -TERM CONTRACTUAL FRAMEWORK
In the gas industry long-term contractual relationships have been used successfully for
many years to deal with the long-term nature and the high specificity of investment in all
parts of the gas chain from exploration and production to the final customer. The rationale
behind this is the nature of gas as a natural resource coming from reservoirs whose size can
vary from small fields of 1 bcm to giant fields with over 10,000 bcm of gas, the high
specificity and costs of the investment to transport end distribute gas, as well as the
substantial investment that bids consumers to gas once they have made an investment
decision. Each of the elements along the chain, from production to the final customer, has
to be linked and aligned in a way that allows all participants to hedge their long-term risks
of gas supply and earn an adequate return in investment or compensation for a finite
resource.(IEA, 2004)
In Figure 14 the manner in which the various contracts bind the respective participants
in an LNG project is presented. The upstream gas producer must make a contract with the
hosting government which will give him the rights, in respect of a specific area, to explore,
produce, transport, process and sell natural gas. Then usually the gas producer forms a
joint venture with other companies with one of the group appointed as operator. The effect
of this structure is that the companies have operated as if they were shareholders in a
corporation, rather than as independent and competitive corporate entities. The producer
must also come to an agreement through the engineering, procurement and construction
34
Production
Liquefaction
Shipping
Regasification
Figure 14: Representation of the gas contract arrangement.
35
Distribution
contracts (EPC) with subcontractors because he may not have the ability to build the
required infrastructure, like for example offshore facilities. An upstream gas producer
capable of building the plant will nonetheless have to turn to major subcontractors for the
provision of specialty items.
Then the transportation of the LNG is done with tankers dedicated to that specific
trade to ensure continuity of supply. There are times that the gas producer has his own
fleet, but when this is not the case, producers and purchasers turn to third party vessel
owners and/or operators who provide the necessary carriage through long term charters or
other transportation arrangements. Moving down the supply chain, the downstream gas
purchaser makes certain EPC contracts for the construction of the regasification plants and
the required infrastructure, for the transportation of the LNG to the plant and then to the
pipeline grid. Lastly, the gas purchaser comes to agreement with the gas end users through
certain sale contracts.
However, above and before all the contracts and agreements of the traditional long
term gas contractual framework lays the LNG Sale and Purchase Agreement (SPA)
between the upstream gas producer and the downstream gas purchaser, which will be
discussed in the following section.
SALES AND PURCHASE AGREEMENT
The traditional LNG project of the previous years featured a carefully structured
system of risk sharing among the participants. Central to the project was the long-term
import contract between buyer and seller for LNG, known as the Sale and Purchase
36
Agreement or SPA. (Jensen, 2004) The SPA agreement is the sine qua non for proceeding
to the development of the LNG chain. For a greenfield development identification of a
suitable buyer and negotiation of the sales terms from the developer's marketing team will
have taken years of concentrated effort, begun long before the development decision is
taken and the search for an EPC contractor has begun. An accurate example of the latter is
the QatarGas project. Incorporated n 1984, serious project planning began only in 1992,
after QatarGas secured a long-term SPA with Chubu Electric of Japan for the supply of 4
million tons of LNG per year, with option of an additional 2 million tons which was
exercised later.
The risk sharing logic of the SPA contract was embodied in the phrase 'the buyer
takes the volume risk and the seller takes the price risk'. Hence most contracts featured
Take-or-Pay (ToP) clauses to assure buyer purchase of some minimum level and a price
escalation clause to transfer responsibility for energy price fluctuations to the seller. De
facto the buyer commits a certain share of his market. The minimum pay obligation puts an
implicit limit on how much other gas the buyer can buy, unless he develops more demand.
The obligation to grant a competitive price will implicitly restrict the seller from selling
into the same market via another channel. Long-term contracts thereby divide the risks
associated with large gas projects, like commitment of large reserves and of substantial
capital, between producers and importers. They typically put the price risk on the seller,
and the risk related to marketing the gas on the buyer (IEA, 2004)
ToP clauses have been a hallmark of LNG sale and purchase arrangements since their
inception. Essentially, they try to ensure that the buyer does not fail to undertake its
37
contractually required quantities, thereby depriving seller of the constant flow of revenues
needed to cover its costs and to realize a return on its investment. The buyer may argue that
the seller has not really lost anything when a cargo is not lifted, since the seller still has the
LNG can dispose it in some other fashion. In this case, however, if the buyer does not take
its full contract quantities during a given period, it was problematic whether and when the
seller would still have an opportunity to recover the resulting lost revenues. The quantities
for which a buyer must pay, even if not taken, is the difference by which the quantities
actually taken by the buyer during a given period are less than the quantities the buyer was
contractually obligated to take during that period. Normally LNG contract quantities are
measured in terms of British thermal units (Btu) rather by volume, since it is the heating
value of the commodity in its delivered stage that is of primary interest to the buyer when
considering its energy requirements and comparing LNG's cost to other energy
sources.(Greenwald, 1998)
Early long-term import contracts were typically for twenty years duration, although
longer contracts were common. The contract term was, and still is, measured from the time
sales reach their 'plateau', or even annual delivery rate, following an initial 'rump-up'
period during which sales levels increase in steps up to the plateau. Once the liquefaction
facilities are up and running, the rate at which they are operated can be increased rather
rapidly up to their design capacity. For this reason, and because a seller's cash flow will be
at its lower levels during the initial years, the seller prefer to minimize the duration of the
'rump-up' period and maximize the volumes taken during that period. Buyers on the other
hand, may maintain that they need to phase in the volumes under the new purchase
38
arrangements, since their taking of additional quantities may have to be harmonized with
the tapering off of purchases from other suppliers or with a gradual build-up of demand.
The point of delivery might be either free-on-board (f.o.b.) or delivered ex ship
(d.e.s.), depending on which party assumed the tanker transportation responsibility, but in
either case the operation of the receipt and regasification terminal was downstream of the
point of delivery and thus outside the scope of the contract. Tankers might be owned by
buyer, seller or independent shipowners, but, as we mentioned at the earlier section,
traditionally were dedicated to the specific trade, usually for the life of the contract.
The early contracts viewed oil, not gas, as the competitive target and thus price risk in
the indexation clauses was principally defined in oil terms, a pattern that persists in some
markets to this day. Since the main substitute for gas were fuel oils, in some cases crude
oils, the gas price was pegged to the prices of the next best substitute of gas, gasoil for
small customers and for process use, and heavy oil for large industrial use. The base price
allowed the importer to recover the cost for the infrastructure from the import point to the
consumer. Over time substitutes came up, such as coal and electricity. In that way LNG
price structure in each region was linked to a favored combination of crude oils or
reference energy sources, with each seller and buyer having its own preferred indices for
escalation. However, in the following section it will be showed that for some countries this
price structure changed as gas-to-gas competition emerged.(IEA, 2004)
In the original pattern of LNG project development, nearly all buyers were either
government monopoly or franchised utility companies from OECD countries. Sellers were
typically either major oil companies or national oil companies of producing countries.
39
Hence, financial creditworthiness for the project was usually not an issue. This enabled
LNG projects to obtain favorable financing, giving them a debt-equity ratio and cost of
capital more nearly resembling utility financing than that of corporate equity. Since most
of the purchasers were regulated utilities or government monopoly companies, they were
effectively able to lay off some of the market risk to their end use customers.(Jensen, 2004)
SPA RIGIDITIES
Over the last decades the dynamics of the LNG trade evolved and greater flexibility
between the sellers and the buyers became of growing importance. The SPA imposed
certain rigidities preventing the compliance of the contractual framework with the market
needs. Specifically, the SPA envisioned a system in which particular trades were
essentially self-contained, involving a specified liquefaction facility as the source of the
LNG and dedicated tankers to shuttle between the specific plant and its destination. The
bilateral nature of the trades made it unnecessary to build in design flexibility for the
tankers to serve other ports, and questions of interchangeable gas quality were largely
ignored. Even today some terminals cannot accept cargoes from some liquefaction plants
because they fail to meet the quality specifications of the new terminal. This is a major
issue in both the USA and UK, where special nitrogen ballasting may be required to
accommodate some of the cargoes in order to change the cargo's heating value, namely the
.
amount of Btus per million m3
The volume obligation in the long-term contract was embodied in the Take-or-Pay
clause, and commonly obligated the buyer to take a minimum of 90% of his annual
40
contract quantity. The contract was designed to ensure that the debt service on the
financing could be met and thus, ideally, would provide for level cash flow over the
contract period. But real markets seldom behave ideally. Most markets grow so that a
volume that is keyed to current demand will be inadequate to meet future requirements
several years in the future. In order to face this problem the features of 'plateau' volume
and 'ramp-up' period, which were mentioned in the previous section, were introduced
providing the buyer a way to grow into his volume commitment. Even with these features
the SPA still could not address successfully the distinct seasonal swings of some markets
with large proportion of temperature-sensitive load or the market uncertainties surrounding
economic cycles. The need to adapt the rigid contract structures to the realities of a
somewhat uncertain market led the LNG buyers and sellers to use mutual agreements to
adjust over and under commitments among themselves. In the following sections it will be
shown that these bilateral agreements, better described as short-term sales, were the
predecessors of the short-term trading market.
Another rigidity of the traditional contract was that the LNG tankers were dedicated
to a specific trade. This had several effects. Even though some surplus tanker capacity
could occur at times when buyers were taking their contractual minimums, it was difficult
to reschedule the surplus vessels since they were technically committed to the buyer's
trade at his discretion. And the fact that newbuild tankers were commonly ordered to
service a new LNG contract, left some existing tankers that had become surplus for one
reason or another to remain in lay-up. A number of tankers originally ordered for the
Algeria/US trades and the PacIndonesia project from Indonesia to the US West Coast in
41
the 1970s remained in lay-up for fifteen years or more when those trades were abandoned.
(Jensen, 2004)
Finally, one of the major constraining features of most SPA contracts was the
'Destination Restriction' clause. This limited the ability of the buyer to resell any surpluses
that he might experience to his own account to a third party outside the national borders,
thereby preserving any margin on the resale for the account of the seller.
EVOLUTION OF LONG-TERM CONTRACTS
The traditional long-term contracts as described before have been changing under the
pressure of new market dynamics. Although long-term contracts are not likely to
disappear, LNG importing companies are seeking increased flexibility and better contract
terms. A reason for the latter is that during the last years, interest in LNG has spread to
smaller buyers, such as independent power projects, who differ significantly from their
traditional predecessors, and whose creditworthiness may be in question. Hence the
financial risks of the newer projects are often inferior to those that marked the early days of
the industry and they may be less able to obtain favorable financial terms. Government
backing may either be unavailable or of relatively little value in securing the cash flows
and assurances that lenders to projects may require. (Greenwald, 1998)
However, the evolution of long-term contracts can be mainly attributed to the
restructuring of the gas and electricity industry. The theoretical model for the restructuring
of the gas industry represents a substantial challenge to this highly-structured, risk-averse
form of business relationships.
42
Gas industry restructure was predicated on the assumption that the traditional form of
government monopoly or regulated public utility operation of electricity and gas is
inefficient and that a system that introduces market competition inherently provides lower
prices and more desirable service options for consumers. It envisioned free market
competition among buyers and sellers to set commodity prices for gas leading to a 'gas-togas competition'. (Jensen, 2004)
The restructuring process in USA and UK in the 1980s, facilitated by oversupply,
lower gas demand than expected and falling fuel oil prices, led to the collapse of the longterm ToP contracts. In the following years many parties settled their contracts by including
additional price flexibility and dropping ToP obligations. Significant changes in the
structure and pricing were observed mainly in the volume and pricing clauses. These
changes were the following:
*
Shorter terms for new contracts, namely between 8 and 15 years in Europe and
15 and 20 in Asia instead of the traditional 20-25 years
*
Smaller volumes ranging from 0.5 to 3 bcm per year for new contracts or
renewals of LNG contracts. These were favored by the increasing share of gas
in power generation and the multiplication of regasification plants
*
Greater flexibility in reviewed contractual terms with more flexibility in swing.
Swing is a contractual commitment allowing a buyer to vary up to specified
limits the amount of gas it can take at the wellhead, beach or border
43
"
Reduction in the ToP minimums or the inclusion of optional cargoes at the
buyer's discretion
"
New price indices with electricity pool prices and spot gas prices. With the
removal of the European ban on the use of gas in large power plants, gas-to-gas
competition developing in the UK and with pipeline-to-pipeline competition in
Germany, more gas was sold to the power plants. In German contracts the
import price formulas were adjusted by pegging a share of the price to the price
of imported coal; in UK the import price were pegged to the spot prices in
National Balancing Point (NBP)
"
Drop of destination clauses. These clauses were not in line with European
competition law as they restrict the resale and flow of gas between countries.
Nigeria LNG in December 2002 was the first external supplier to remove
destination clauses from existing future contracts with European customers.
(IEA, 2004)
An example, where the above mentioned changes are clearly presented, is the renewal
contracts of the Japanese utilities. When Japanese utilities renewed an expiring 20-year,
360 Bcf per year (7.4 million tons per year) contract for Malaysian LNG, they reportedly
obtained a 5-percent price reduction, a two-tier contract arrangement whereby 58 Bcf (1.2
million tons per year) is sold for 4 years and the rest for 15 years, and an agreement that
about one-fourth of the volumes will be sold f.o.b., which will increase shipping flexibility
44
and reduce freight costs for the buyers. The contract also covers short-term purchases.
(EIA, 2003)
EMERGENCE OF SHORT-TERM LNG MARKET
One very significant result of the changing environment described in the previous
sections has been the emergence of a short-term LNG market. The short-term LNG market
includes all cargos not traded under long-term agreements and has two separate but
coherent parts, the paper part and the physical part. The paper side of this market is
represented by the future contracts, whose duration varies from 1 to 12 months and are
traded in International Petroleum Exchange in London (IPE) and in New York Mercantile
Exchange (NYMEX).
The physical side of trading LNG in the short term is represented by the spot trading
with spot deliveries varying from I to 30 days, trading in major interconnections of the
natural gas pipelines grid like Henry Hub and Zeebrugee. Since it is very common with
many agencies, like the International Energy Agency and the US Energy Information
Administration, to use the term spot-trading for labeling all short-term trading, the terms
spot-trading and short-term LNG trading will be used interchangeably. In Figure 15 the
current two LNG markets are presented.
45
Figure 15: Long-term and short-term LNG markets.
The first short-term trading LNG cargoes can be traced at the start of the 1990s. As
presented in Figure 16 the size of the LNG short-term trade in 1993 was almost negligible;
namely, the percentage of short-term trade was equal to 1.66% of the global LNG trade.
After a short period of marginal increase, short term trade reached a minimum value of
0.75% in 1998. That year marked the beginning of a favorable period for the short-term
LNG market. In less than a decade, from 1998 to 2004, the share of short-term trade
increased five times reaching the level of 10.1% in 2004. It should be noted that even
though in 2001 many stakeholders of the LNG industry feared that the bankruptcy of
Enron, one of the biggest natural gas trading companies, would influence negatively the
short-term trade, the volumes traded under sort-term contracts continued to grow.
46
Total trade
Short term trade
(million tons)
200
(% total)
12%
1
*%
10%
150
8%
6%
100
4%
50
2%
0
1993
1994 1995 1996
1997 1998
1999 2000
2001
-0%
2002
2003
2004
Figure 16: Evolution of short-term LNG trade, 1993-2004.
The emergence and growth of the short-term market was based on two factors. The
first factor was the existence of certain conditions which fostered the birth of spot trading.
These conditions can be categorized in four groups: natural, economic, transportation and
institutional. (Mazighi Hachemi, E. A., 2003) The second factor was the existence of a
reinforcing loop, inherent in the structure of this market illustrated in Figure 17. The
existence of an organized market for the short-term transactions increased the flexibility
and innovation of the trade, with the usage of several financial derivatives and flexible
clauses in the short-term contracts. The latter increased the willingness of producers to sell
in a short-term, non-contracted basis, which in turn augmented the liquidity of the market.
High liquidity in the market led to an increasing need for organization and structuring in
order to increase its effectiveness. This reinforcing loop operates until a limit is reached
regarding the quantity of LNG that the stakeholders are willing to trade on a short-term
47
basis. In the following sections each one of the required conditions, which led to the
emergence of the short-term market, is examined.
Figure 17: Conditions and dynamic structure of the short-term LNG market.
NATURAL CONDITIONS OF SHORT-TERM LNG MARKET
Natural conditions refer first to the existence of surpluses and deficits in gas supply, in
other words an increase of the liquefaction capacity of the exporting countries and a
decrease of the domestic production of the importing countries, and second to sudden
augmentations in gas demand, which must be accompanied by an increase of the
regasification capacity. The previous parameters combined increase the number of buyers
and sellers leading to an increased liquidity of the gas market. Historically, the first time
that this phenomenon occured was during the 1980s when substantial surpluses of LNG
48
capacity relative to demand existed as a result of pricing disputes between Algeria and its
customers. (Jensen, 2004)
BCMI
200
150
-
r
Earlv Surpkues ;42c(
in 191' Largely
Later 5urpluses 22. In 1999
Largely Attributabke tc
Expansicon in the Face of r
--
E
Lagging Pa-ific Demand/
AttributaleI- t- th-
Algerian Political
Dispute and Clsing
U.S. Terrnnal
of
100
50
1975
1995
1985
Figure 18: LNG exports compared with liquefaction capacity. (Jensen, 2004)
The early appearance of capacity surpluses east of Suez in the early 1990s seems to
be a chaotic coincidence and not the result of a well designed plan. It was the result of over
8 million tons of de-bottlenecking capacity additions in Southeast Asia during a period
when both Indonesia and Malaysia were adding expansion trains. It was sustained later by
the 1997-1998 Asian financial crises and by the emergence of new export capacity from
Qatar and Oman in the Gulf. But by 1999, further Middle East expansions, as well as the
startup of Trinidad and Nigeria in the Atlantic Basin, institutionalized the surpluses and by
now some of the excess capacity appears to have been created deliberately to enable
companies to participate in spot and short-term trading opportunities. It should be noted
that the RasGas project, in 1999, and the Oman LNG project, in 2000, were both
commercially innovative, since they were the first projects starting construction without
49
long-term commitments for the total capacity (Marie-Francoise Chabrelie, 2003) In Figure
17 of the previous page the LNG liquefaction capacity and the actual trade are compared.
In Figure 18 it is clear that the Pacific Basin provided much of the earlier short-term
volume, but the active trading market that has developed in the Atlantic Basin has provided
an opportunity for Atlantic and Middle East sources to grow rapidly.
BCMI
SMiddle
East
oAtlantic
But Now the Atlantic Basin and the
Middle East Dominate Short Term
10.01
Basin
Pacific
Basin
Exports
The Pacific Bas in Was Important Earlier
2.5
0.0
1992
2000
1995
2002
Figure 19: Source of short-term exports by region. (Jensen, 2004)
The destinations for this trading activity have been remarkably concentrated. Since
1996, four countries, namely USA, Spain, Japan and Korea, have accounted for more than
80% of the short-term volumes as illustrated in Figure 19. The dynamics of this highly
targeted concentration are easily explained.
Starting with the USA the obvious reason for the increase in sport trade was the
reemergence of the LNG market due to the high level of prices in 2000-2001, which led to
spot cargoes being redirected from Europe to the US, in addition to the direct LNG spot
50
purchases. About 4 bcm per year was imported to the USA under spot or short-term
contracts during the period 2000 to 2002. Again in 2003, Figure 19, sustained high level of
prices in the USA led to a surge in spot purchases and the rerouting of LNG cargoes
initially destined for Europe to the US market.(IEA, 2004)
BCM
All
OOther
Q
10.0
Spain, Japan and Korea - Have
Accounted for
Korea
Ja n
Since 1996, Four Countries -the US.
Q
80% or More of Short Term
Purchases
-
7.5
1p1
us
2.5
0.0
-
5.0
1992
1995
2000
2002
Figure 20: Destination of short-term imports by country. (Jensen, 2004)
Spain and Korea had their role in the increase of the LNG cargo deviations since they
relied heavily in spot-term trading. The two countries adopted a strategy to meet peak
winter demand, by relying on spot cargoes to cover their seasonal demand. Spain imported
4 bcm of LNG under spot basis in 2002. Kogas bought 43 spot cargoes, total volume 3
bcm, during the winter of 2002-2003.
Lastly, Japan greatly affected spot trading especially after 2003. During the end of
2002 and the beginning of 2003 Japan decided to shut-down 17 nuclear power plants
which led Japanese utilities to resort to power generation by gas fired power based on
LNG, resulting in increased spot sales or swaps with other Asian buyers. Hence, Tokyo
51
Electric Power Company (TEPCO) bought around 30 cargoes in the six months ending
September
3 0 th,
2003 and TEPCO and Kogas swapped 12 LNG cargoes in 2003. Japanese
LNG imports increased to 80 bcm in 2003 with the TEPCO nuclear shut-down structurally
added 3 mtpa of demand and caused a short-term spot supply squeeze. (IEA, 2004)
ECONOMIC CONDITIONS OF SHORT-TERM LNG MARKET
The second condition is the increasing willingness of producers to sell more LNG on a
short-term basis. The decreasing cost of liquefaction during the last years, as it will be
examined in latter section, certainly reduces the capital at risk in LNG plants and enable
producers to sell more on a short-term basis.
Apart from the decreasing liquefaction cost the root of the economic conditions lays
under the softening of the rigidities of the old style long-term ToP contracts, which enabled
extra volumes to trade on a short-term basis. These flexible volumes originate from the
mismatch between customer market growth and the early availability of full capacity to
cover the plateau period of the contract. The volumes of the 'ramp-up' period of the longterm contracts are increasingly being utilized to feed the short-term market. 'Ramp-up'
volumes have existed for many years but their availability for short-term transactions is
more recent. Because they become available when projects start up, they can be quickly
put on the market without waiting for complex negotiations between buyer and seller.
Actual ramp-up capacity potentially available for short-term markets is comparatively
large relative to their actual utilization for short-term market sales. This is illustrated in
52
Figure 20, which shows the incremental growth of capacity, contract exports and shortterm sales since 1992. (Jensen, 2004)
BCM
100
-
Surplus
capacity
Short Term
Exports
Cont ract
Exports
25
0
1993
1995
2000
1997
2002
Note: Capacity Figures Are as of the End of Year and Thus May Overstate Annual Surplus in
an Expansion Year
Figure 21: Cumulative incremental growth of the world's capacity and trade.(Jensen, 2004)
In addition, as the industry ages, more and more gas is coming to the end of the
original contract period, enabling the sellers to renew the original agreement or to take
back the volumes for more flexible sales. This de-bottlenecking of existing facilities
creates capacity that has already been financed by the original contract. With increased
competition among projects for the market, companies seem more willing to commit to a
project with some portion of the output 'uncovered'. And since the seller's greatest
concern is debt service while the loan obligation is still outstanding, it may increasingly be
possible to tailor the contract length to the shorter period of loan payout, giving the seller
greater flexibility to put volumes on the short-term market. In Figure 21 the growth in new
and de-bottlenecked capacity are compared since 1990. De-bottlenecking effectively added
about one sixth of the incremental volume since that time.
53
75
Debottlenecking of Old Capacity Accounts
for AboLut One Sixth of the Increase This
E
.
BCM
E Capacity
Past Decade
50
25
1991
1992
1993 1994 1995 1998 1997 1998 1999 200
21001
2002
Figure 22: Cumulative growth of new and de-bottlenecked capacity. (Jensen, 2004)
TRANSPORTATION CONDITIONS OF SHORT-TERM LNG MARKET
The emergence and the increase of the short-term LNG trade inherently require
uncommitted shipping. The absence of available and uncommitted LNG vessels a priori
stops any initiative of short-term trading as it was proved in the period when traditional
long-term was the common practice.
Under the traditional long-term contracts, LNG tankers were dedicated to specific
trades with rigid obligations to deliver the maximum contract quantity at the buyer's
discretion. This had as a result an unavailability of transporting other cargoes even when
the LNG buyer was taking his minimum contracted volumes. New long-term contracts
required newbuildings, a practice which led eventually to a relatively inflexible tanker
fleet. If a LNG vessel were to be idled for any reason, it was very difficult to find another
charter for it and it was likely to be laid up. This is exactly what happened the late 1970s
54
and early 1980s, when several trades, for which tankers had been ordered, either failed to
materialize or collapsed after a brief period of operation. These included the failed
PacIndonesia trade from Indonesia to California and the Algeria - US trades to Cove Point,
Elba Island and Lake Charles, which shut down after less than two years. In addition, two
tankers that had been built on speculation never got contracts. All in all, fifteen tankers
were laid up by these events. Although six of these were subsequently scrapped, the
remaining nine remained idle, several for more than twenty years, before being refitted for
a newer, more flexible tanker market. (Jensen, 2004)
The contract clauses also tended to prevent the scheduling of tankers to cover cross
shipping. Cross shipping is a method which is based on exchange agreements and
minimizes transportation costs by effectively crossing the sailing course of dedicated
tankers. To illustrate, ConocoPhillips was considering at one point the possibility of
bringing its Bayu Undan gas in the Timor Sea, via an Australian liquefaction plant, into a
possible Baja California terminal. It also is an owner of the Cook Inlet, Alaska LNG plant
that is dedicated to the Japanese market. Had this venture gone ahead under the old
dedicated tanker ground rules, the combined cross trade of Alaska-Japan and Bayu UndanMexico would have had a combined shipping distance of 10,547 nautical miles; 3,250
nautical miles form Alaska to Japan and 7,287 from Darwin to Baja. However had it been
possible to make a flexible exchange deal of Alaska to Baja and Darwin to Japan, the
combined shipping distance would have been more than halved; 2,191 for Alaska-Baja and
2,864 for the Australian shipment or 5,055 nautical miles total. Cross shipping is now a
55
major issue with the growing geographic dispersion of supply sources and markets and it is
likely to be more important in the future.(Jensen, 2004)
Thciusands of BCM Nattical Miles
700
700
600
500 -
Contracted
Capacity Factor 9 in18
Contracted
Capacity Factor
72% in 1%3
-
Net Surpus
Contracted
Capacity Factor
83% in 2001
O Capacityp
ld [11
ECapacity
Short Te rm
*Utilization
o nact
400-
200
MilM
0
1980
1985
1990
1995
[11 Fifteen vessels built for collapsed trades or on speculation
2000
Figure 23: LNG tanker capacity and tanker demand, 1978-2002. (Jens en, 2004)
The tanker inflexibility began to give way in the early 1990s as it is illustrated in
Figure 23 where tanker capacity, expressed in thousands of bcm nautical miles, compared
with contract transportation utilization is presented. One of the first changes was the
renewal of the Alaska - Japan contract in 1994. The contract renewal coincided with a debottlenecking of the plant and a decision to use somewhat larger newbuild LNG vessels for
the renewed contract. This idled the two vessels used in the original contract, which were
then purchased by BG and placed in other service. The latter favored the change of the
dominant perception of limited effective life of LNG vessels. The stakeholders started to
recognize that LNG tankers may have a useful life of more than 30 years and need not to
be replaced when a contract extension has been negotiated. As a result a new class of
56
secondhand tankers began to appear in the market. This pattern accelerated with the
replacement of five Gotaas Larsen ships that were chartered to the original Abu DhabiJapan contract when an expanded trade was initiated in 1995-1997. An illustrative example
of the previous arguments is the fix by Gas de France of Galeomma, a 125,000 cbm, 28
years old LNG vessel controlled by Shell, for a short term contract of six months which
happened on April 2006. (TradeWinds, 2006b)
INSTITUTIONAL CONDITIONS OF SHORT-TERM LNG MARKET
If we look at the historical experience of the internationalization of oil trade flows, the
creation of a short-term market for natural gas trade required the emergence of organized
markets for both the trading of gas molecules and their shipping. Organized markets take
shape under certain institutional conditions, among other things. These institutional
conditions, which facilitated the emergence of the short-term market, derived from the
restructuring process of the gas industries in the USA and UK.
The main goal of the restructure was to make gas industry more competitive and
focused on essential elements. The first was regulatory intervention in existing contractual
relationships between buyer and sellers, freeing sellers to ship for the lowest gas among
suppliers. The second element was the requirement the transportation systems be open to
third party access to enable producers and consumers to negotiate directly with one
another, without the monopoly control of a merchant transporter. The restructuring model
foresaw the LNG chain reconstructed efficiently through independent competitive
offerings of each of the relevant links, which are free to operate independently of one
57
another. And since many market decisions involve time lags between buyers' and sellers'
revenue objectives with volatile price behavior in the meantime, it also provides a system
of risk management through the use of various types of financial derivatives like futures
contracts, options and swaps.
In USA the Federal Energy Regulatory Committee (FERC) issued the 436 Order
which granted third-party access to pipelines to producers and consumers. Taking
advantage of the supply surplus, this access boosted the development of a short-trade
market, spot and future contracts, which decreased the price level of gas. Pipeline
companies faced severe financial difficulties as a result of the ToP provisions, as they were
no longer able to take delivery of the contract quantities. To alleviate the obligations of the
pipelines, FERC intervened with Order 500 which granted ToP credits to pipelines if they
granted third party access (TPA) to their creditors.
In UK regulatory reforms, along with oversupply, led to complete restructuring of
long-term ToP contracts and the development of spot sales. Contract obligations were very
costly to change for the companies involved as there were no re-opener clauses. It cost
British Gas 2.5 billion to renegotiate its contracts with North Sea producers when gas
prices dropped to 9 per thm, while the cost to British Gas for buying it averaged 19 per
thm.(IEA, 2004) Following UK's example the European Union made obligatory third party
access to all the greenfields and old regasification terminals. (Mazighi Hachemi, E. A.,
2003)
58
RISKS IN LNG PROJECTS
Risk is inherent in every major international construction and trading project. LNG
trade by its nature is vulnerable to a number of risks, which the traditional LNG trading
model tried to minimize through contractual intervention. The emergence of the short-term
market has actually shifted the balance of risks among the parties in ways that made
necessary the introduction of new risk management tools and risk allocation techniques,
not previously utilized in the traditional, risk-averse model of LNG trade. The three main
categories of risk encountered in the LNG projects are political, technical and financial risk
and are illustrated in Figure 24.
olitical instabil
ationalization
erritorialdis
overnment bre
enfield develo
technology
onstruction cost
erruns and del
ice risk
olume risk
erest rate
Figure 24: Risks encountered in LNG projects.
In the following sections we will overview these three risk categories and focus on the
influence of the short-term LNG market to the financial risk and the risk management tools
utilized by the stakeholders.
59
POLITICAL RISK
The emergence of the short-term LNG market created more opportunities but also new
challenges for both buyers and sellers. One challenge of great importance is how the
security of supply is affected by geopolitical dynamics of the countries possessing the gas
reserves. On one hand, the flexibility created by competitive markets, enables more LNG
suppliers to access more markets and mobilize gas resources in a shorter period of time.
Looking on the buyers it allows access to more and more flexible supplies playing a
critical role in the balancing of gas supply and demand between different regions, by
allowing arbitrage and purchasing cost optimization. On the other hand the LNG market
flexibility raises several issues, linked with the location of LNG resources.
According to OECD, by 2030 LNG trade is expected to account for about 50% of total
trade and 16% of global gas consumption. As shown in Figure 25, most of the projects to
be developed over the next 30 years are located in non-OECD countries, the exceptions
being Australia, Norway and Alaska. OPEC countries hold a little more than half of global
gas reserves and their exports counted for 37.6% of the global LNG trade in 2004. By
2030, the last figure is expected to grow to more than 60% of global LNG trade. If exports
from other non-OECD countries are added, that means that 90% of global LNG would
come from non-OECD countries. The geopolitical implications of this trade pattern are
similar to that of the oil trade and give rise to the same concerns. The development of LNG
trade could lead to similar geopolitical complications as were experienced for oil in the
past. LNG suppliers from non-OECD countries could possibly try to influence LNG prices
by trying to withhold capacity from the market, as is the case for OPEC and oil. (IEA,
2004)
60
600
-
300
200
-
'00
100
-
-4
-
500
-
700
-
800
0
-
OPEC
2030
2020
2010
2002
E3 Non-OECD
U OECD
Figure 25: Sourcing of global LNG traded volumes.(IEA, 2004)
The traditional politic risks in greenfield and brownfield LNG projects include
nationalization, government breach of contract, political instability and territorial dispute.
In some countries there may be no sound basis for these concerns, for example the UK
remains one of the most unstable investment environments due to fiscal risk; however,
LNG projects in developing countries may require support from export credit agencies
because of augmented political risk. The latter leads to significant complications regarding
the project finance process. (Martin, 2005)
The risk of nationalization is realized when the government of the host country
decides to nationalize the assets of a project or the shares of a project company in
discriminatory or arbitrary manner without the payment of a fair compensation to the
project company. The nationalization risk is of particular relevance in the case of emerging
market projects like LNG projects, where the existence of the blooming of nationalist
policies may tempt government to nationalize these projects. A breach of contract by the
61
government occurs when an authority of the host country does not recognize its obligations
in relation to any substantial part of the project company's rights under a project contract.
Typically these two kinds of political risk are addressed by appropriate risk reduction and
distribution mechanisms, such as political risk insurance coverage, government guarantees
and assurances or credit support from the sponsors and other participants in the project.
(Buljevich & Park, 1999)
Political instability is main issue of the LNG trade since the concentration of the
majority of gas resources in a few countries who do not have solid political foundations
increases the risk of supply disruption. A recent example is Indonesia. Indonesia is
currently the world's largest LNG exporter. Unrest in the separatist Aceh region created a
major supply cut in 2001 when ExxonMobil had to shutdown three of the four fields
supplying the Arun liquefaction LNG plant after repeated attacks on its workers from
separatist rebels. This forced Pertamina, the state Indonesian oil and gas company, to
declare a state of force majeure at the plant, which was closed for seven months. This
resulted in changes in the way LNG was traded, with more flexibility requested by buyers
and more cooperation developing between suppliers. After the disruption in 2001,
Indonesia, Malaysia and Brunei pledged to work closely together to cover possible supply
problems. There are still violent conflicts in Aceh and separatist sentiment is also growing
in Irian Jaya.
Territorial dispute is of major importance especially for the countries of Middle East.
The case of Iran is a very clear example. Iran, the holder of the world's second largest gas
reserves, is developing an LNG export policy under NIGEC (National Iranian Gas Export
62
Policy) with four LNG projects planned. However, these projects have been stalled, faced
with the current development in the United Nations Security Council. A last vivid example
is the delay of the LNG projects between Australia and Indonesia from the joint shelf
between East Timor and Australia, as East Timor entered into a treaty originally signed
between Australia and Indonesia, before East Timor's independence. The Sunrise project,
which also lies on the shelf between East Timor and Australia, is still facing an agreement
over the landing and liquefaction site and the split of royalties.(IEA, 2004)
On a general perspective, until now LNG producers have maintained good
relationships with their individual customers. Otherwise, they would risk not only losing
their export revenues, but also jeopardizing their reputation in the case of a breach of
delivery contract. The current LNG business is also characterized as a buyers' market.
There are many LNG projects and a number of gas fields waiting for development and for
customers. Fields also tend to be developed on a joint venture basis, which creates
considerable competition on the supply side and often commits government-owned
companies. In the following years the trend is towards a more global market and increasing
LNG supplies from only a few OPEC member countries: Qatar, Indonesia, Nigeria and
Algeria. Therefore, although gas resources are abundant and LNG projects numerous, there
is no room for complacency, and diversification policies should continue. The growing
diversity of supply sources may help buyers to mitigate the political risks. Similarly, major
companies with investments in affected countries can only spread the risks by investing in
a portfolio of supply sources.(IEA, 2004)
63
TECHNICAL RISK
Technical risk refers to the losses of a probable temporal or permanent disruption of
the LNG project during its construction, start-up, operation or maintenance. The main
elements of technical risk are associated with greenfield development, new technology in
regasification, liquefaction and transportation, construction delay and cost overrun and
EPC contracts risk.
As far as greenfield development is concerned, for the last 40 years the LNG industry
enjoyed a virtually unblemished safety record in the development and operation of new
projects. A recent study conducted by the International Gas Union on the safety record of
the LNG industry concluded that there have been no reports worldwide of offsite damage
resulting from an incident at an LNG facility. (IGU, 2003)
LNG liquefaction terminals have technologically evolved and grown in number since
the first plant to be operated on a commercial basis was established at Arzew in Algeria in
1964. The early plants were built more or less according to refinery standards while later
generations of plants have benefited from the development of LNG's own standards and
practices, similar to the lean designs that are now customary in the gas industry. Lessons
are taken from past incidents, mainly through the evolution of the design of the plants,
which have become safer and more reliable, and also in the accumulated experience of
operating companies. The number of incidents in LNG plants is similar to, or lower than
those in refineries. For many years, the LNG industry has implemented Safety and
Management Systems and Environmental Management Systems in the day-to-day
operation of LNG plants, either in response to compulsory regulatory requirements, or on a
voluntary basis. (IEA, 2004)
64
Based on the available data the transportation risk of LNG is limited. Over the past 40
years, there have been more than 40,000 LNG ship voyages, covering more than 60 million
miles without any major incidents involving a major release of LNG in port or in sea. It
must be noted that unlike oil tankers double containment has been the standard in LNG
vessels from the start. The LNG fleet has an absolute safety and reliability record since the
high asset value and safety levels demanded the ships tend to be very well maintained and
operated.
Regasification terminals also carry a limited technical risk having an excellent security
record. Not one accident has been reported since the beginning of commercial LNG trade.
However, local opposition and environmental considerations have often delayed or even
blocked the building of new terminals. The local population is more demanding than in the
past insisting that industrial sites are based further away from residential areas.
Construction cost overruns occur when the actual construction and start up costs of an
LNG project are higher than the figures estimated in the financial plan. If the projected
construction costs are exceeded, additional funds will be required for the completion of the
LNG project. Additionally, if construction cost overruns are not distributed to a
creditworthy third party, such additional funds need be financed by the sponsors through
additional equity contributions or subordinated shareholders loans or otherwise by new
debt financing not contemplated in the financial plan. Construction delays can present a
series of difficult problems for the LNG project's success, namely the increase in the
interest burden of the LNG project during the construction phase, which in turn leads to
financial cot overruns not contemplated in the financial plan. Also, the delay in
65
commencement of the operating phase leads to a delay in the commencement of the LNG
project revenue stream. In LNG projects construction delays result from supplies and
materials shortfalls, and delays, mainly for the regasification plants, in obtaining the
necessary permits and authorizations. (Buljevich & Park, 1999)
The experience, reputation and creditworthiness of each of the subcontractors in a
LNG project to whom projects risks are allocated are essential for the success of a project.
Engineering, procurement and construction contracts between the joint venture of the
companies developing the project and the subcontractors are based on the experience and
credit standing of the subcontractors and are of utmost importance to avoid or at least
minimize the technical risk. (Buljevich & Park, 1999)
One of the main risk mitigation mechanisms used for the technical risk are cash
completion agreements, performance bonds and corporate guarantees. Another risk
reduction tool is contingent credit facilities granted by the lenders or other project
participants for purposes of making available additional financing to cover potential cost
overruns.
Closing, a risk spreading technique gaining ground the last years, is the
diversification of the traditional parties' business activities by expanding in all the areas of
the LNG supply chain. In a following section this trend will be examined in detail.
FINANCIAL RISK
Financial risk is probably the key challenge in financing LNG projects. The reliability
of expected cash flows is essential for the financial feasibility of the project and lenders
66
typically require a level of certainty as to the future volume demand, and sale prices of the
gas to be produced from a certain project.
The level of future demand is associated with the so called volume risk. Volume risk
refers to the loss from the probable disequilibrium between the volume that the buyer is
contracted to buy and the demand in the market in which the gas is sold. In the long-term
ToP contracts the buyer was obliged to take a minimum level of gas volume having the
risk if the demand escalated, there would not be enough gas supply to match it. The
rigidity imposed from these contracts forced the sellers and buyers to bilateral transactions
in order to adjust to commitments among themselves. The emergence of a short-term LNG
market implies that a certain quantity of gas will flow with priority to markets with high
prices. One consequence of the latter is that markets with low prices will need stocks of
gas in order to meet their demand, whereas the satisfaction of this demand was provided
before through the ToP contracts. In other words the reduction of the volume risk for the
importer will need a certain amount of commercial stock building. (Mazighi Hachemi, E.
A., 2004)
Apart from the volume risk the financial risk central to the LNG projects financing
structure is the price risk. Price risk is actually the loss from the probable fluctuation of the
gas price from the level agreed between the LNG buyer and seller. A minimum price was
contracted in the SPA of the long-term contracts in order to transfer responsibility energy
price fluctuations to the seller. Simply stated the minimum price approach establishes a
benchmark price level, usually determined by reference to the historical LNG prices
applicable over a base period in the relevant buyer's market, and subject to escalation to
67
maintain the level of the minimum price in real terms over time. The minimum price
concept, as originally devised, was meant to address two important considerations
especially applicable to greenfield projects. The first issue was project viability, namely the
need to convince the project's stakeholders that the project has an acceptable rate of return
on investment, even if there was a significant drop in energy prices. The second issue was
project financing. Developers' concerns about massive debt appearing on their balance
sheets led to the development of new financing methods. Limited resource project
financing is less concerned with the developer's financial standing than it is with having a
secure access to LNG sales revenues that are assured to provide sufficient returns to cover
the borrower's debt service obligations. (Greenwald, 1998)
Another risk that should be noted in this section is the interest rate risk. Financial
projections must include realistic rate assumptions and the projected cash flows of the
project must accommodate statistically reasonable increase in interest rates without
jeopardizing the LNG project's feasibility. Interest rate protection agreements can be
designed to transfer or mitigate such risk generally or in certain specific contingencies. In
LNG projects the most common derivative instrument used for mitigating interest rate risk
is the coupon swap, where the project company swaps its floating rate interest payment
obligations into a fixed rate.
Finally the risk of currency devaluation is present in every international project which
has a portion of its costs denominated in one or more foreign currencies, since it is exposed
to the risk of fluctuations in the exchange rate between such foreign currencies and the
local currency in which the project is generating its revenues. In most of the LNG projects
68
this risk appears to be of relatively minor concern as all revenues and costs accrue in $ US.
However, by the very nature of the off-take agreements the LNG buyer still poses a very
subtle and indirect currency risk. If the buyer generates its revenue in a local currency an
adverse currency movement might imperil his ability to honor the SPA.
An illustrative example of what was discussed before is the case of Ras Laffan Natural
Liquified Gas Corporation project (RasGas), which process and sells gas from a field
offshore of Qatar to Korea Gas Company (Kogas), for resale to the Korea Electric Power
Company (Kepco). Kogas generates all its revenue in Korean Won. During the Asian
financial crisis Korean Won depreciated against the $ US and the effective cost of LNG
doubled in local currency terms. Hence, exchange rate risk when borne by the buyer has a
tendency to transform itself into a credit risk. (Dailami & Hauswald, 2000)
RISK MANAGEMENT TECHNIQUES IN LNG PROJECTS
Risk management techniques in LNG projects consist of a combination of five
different but interrelated steps as presented in Figure 26.
The first step is to identify the risks. In the previous sections it was presented that for
the LNG projects the inherent risks are political, technical and financial. Their
quantification and assessment is usually accomplished with the usage of probabilistic
models which determine their magnitude and its epistemic uncertainty.
At the third step risk reduction techniques are applied to reduce the overall risk facing
the LNG project participants to the lowest possible level. In the following sections three
risk reduction tools, namely downstream and midstream integration, upstream and
69
midstream integration and efficient pricing mechanisms, which were developed or
modified after the emergence of the short-term LNG market will be examined.
Figure 26: Risk management in LNG projects.
At the fourth step the risks are distributed among the various project participants in a
way that is mutually acceptable. In long-term term contracts this was done with the ToP
contracts, but as mentioned before current contracts are more flexible and are structured
more like a Take-and-Pay (TaP) contract where the buyer is not unconditionally obligated
to pay for a minimum volume of gas.
The last step is essentially a means for each participant to individually further reduce
its allocated risks through hedging, which is the usage of financial derivatives as an
70
additional risk spreading mechanism, and political or commercial insurance. In the
following sections the underlined risk management tools of Figure 26 will be presented
DOWNSTREAM AND MIDSTREAM INTEGRATION
According to the business segmentation of traditional LNG projects the upstream,
midstream and downstream sectors refer to the gas well development and liquefaction
plant operation sector, LNG transportation sector, and LNG reception, regasification and
marketing sector respectively.
The developments in the LNG trade the last decade has led the traditional LNG market
players to diversified business activities, as an answer to the change in the balance of risks
and rewards produced by the clash between the two structural models of the international
LNG industry. Specifically, one of the reasons that the international oil companies (IOC)
are advancing into the downstream market is to monetize their upstream assets, leverage
their gas reserves and allow for faster launch of upstream projects by securing gas
outlets.(Dubois, 2004)
Another reason for the downstream and midstream integration is that in the liberalized
markets, like USA, UK and now Japan, LNG importers, such as power and gas companies,
need various flexibilities in their contracts which are limited by the ability of the sellers to
provide the required gas volumes. International oil companies and trading houses see the
latter as a new business opportunity to offer volume risk hedging options. In liquid markets
such as the US and the UK, exporters are exposed to relatively higher price risk, but
volume risk is relatively low. Therefore, IOC and trading houses can sell their LNG
71
relatively easily if price volatility is not considered. It should be noted that a possible
future outcome of this trend might be that the LNG will be delivered from multiple
liquefaction facilities to multiple destinations, within the range set by the SPA, in order to
&
maximize profit. As a result, the liquidity of the LNG market will be increased. (Suzuki
Morikawa, 2005)
In Table 3 recent cases in which traditional players in the upstream sector, of the
natural gas industry, made active efforts to expand into the midstream and downstream
sector are presented. These cases can be categorized in four categories depending on their
content.
The first category includes cases in which the players that hold interests in the
upstream sector order hold and operate LNG tankers. This measure can be regarded as part
of a business strategy aiming to increase the cost-efficiency of the LNG chain as a whole,
while securing flexibility by transporting to the downstream sector the company's assets,
which are located in different locations, in the upstream sector. As forms of LNG trade are
expected to be further diversified in the future, these companies are working toward
achieving centralized control of LNG marketing and LNG tanker operation with a view of
establishing a system that will be able to respond immediately to market demand. The
latter will eventually decrease the financial risk associated with the volume demand.
The second category includes cases in which traditional upstream companies
participate in projects for constructing LNG receiving terminals in natural gas consuming
countries. Among others, noteworthy cases are the movements toward:
72
Table 3: Expansion of upstream companies to the midstream and downstream sectors. (Odawara, 2004)
Integration to Midstream
Ordered construction of LNG tankers for
organizing its own fleet
Participation in LNG receiving termina
construction
Joint construction, with Sempra, of LNG
receiving terminal in Costa Azul
Rights' acquisition for LNG storage and
regasification capacity usage
Acquisition of subsidiaries and affiliated companies
that engage in LNG trade
Obtained right to use capacity Cove Point LNG
receiving terminal
Started construction of a LNG receiving
terminal in Altamira, Mexico.
Acquired 26.7% of interests in GDFs Fos
Cavaou LNG receiving terminal in
Southern France
Acquired the right to use the capacity of the Bilbao
LNG receiving terminal
Organized a fleet of LNG tankers under its
.curd2%o
ntrssi h N
Acquired jointly with Sonatrach the rights to use the Acquired 30% of interests in the company holding the
own control
Acurd2%o neet nteLG
capacity of the Grain LNG receiving terminal in UK Guangdong LNG receiving terminal
reception project in Kirishna Putnam, India
Acquired 35% of interests in SK Power that was
constructing a gas-fired power plant in Gwangyang
Jointly construction with Qatar Petroleum
(QP) of the South Hook LNG receiving
terminal in UK
Acquired jointly with QP the right to use the
capacity of the Zeebrugge LNG receiving terminal
owned by Fluxy
Acquired approval for constructing the Port
Perican offshore LNG receiving terminal
Acquired 20% of interests in the South
Pars LNG terminal in Iran
Acquired 30% of interests in the Dragon
Acquired the right to use 50% of the capacity of the
LNG receiving terminal in Milford Haven, ADragon terminal.
UK
Acquired the right to use the capacity of the Cove
Point terminal jointly with BP and Shell
Organized a fleet under its own control
mainly targeting the Atlantic market
Started construction of the Brindisi LNG
receiving terminal
Acquired the rights to use the capacity of the Elba
terminal in US
Acquired 60% of interests in Freeport LNG
the constructor of LNG terminal in US
Acquired the right to use the capacity of the Elba
LNG receiving terminal
73
Acquired, jointly with QP 45% interests in the North
Adriatic LNG import project
"
Global cooperation between oil majors, which have already established their
position in the world as interest holders in the natural gas upstream sector, and
state owned oil companies, like the cooperation between ExxonMobil and Qatar
Petroleum
" Cooperation between oil majors and gas companies, which have established
their position in the downstream sector, like the cooperation between Shell and
Sempra.
The third category includes cases in which traditional players acquire the right to
regulate use of LNG storage and regasification capacity of LNG receiving terminals. This
is also called capacity trade. This measure is taken by interest holders in the natural gas
upstream sector to rent, for a certain period, LNG storage and regasification capacity from
companies operating LNG receiving terminals. Particularly after 2000, capacity trade has
become popular in the European and North American markets windows and regulations
have been improved along with the progress of market liberalization. (Odawara, 2004)
The fourth category includes cases in which interest holders in the natural gas
upstream sector establish or acquire subsidiaries and affiliated companies that engage in
LNG purchase and sale or in the power-gas industry, thereby launching and stabilizing
LNG export projects in which they are involved. This measure also seems to actually
contribute to demonstrating such players' supply capacity in the market, and in particular,
it is obviously regarded as part of the movement toward vertical integration in the LNG
chain led by oil majors. (Odawara, 2004)
74
Before closing it should be noted that integration is not without cost and the price tag
for the highest degree of diversity is so large that few companies can afford it. Figure 27
illustrates a 'greenfield entry fee' for what might be described as a fully diversified LNG
portfolio involving supplies in the Pacific Basin, Middle East and Atlantic Basin and
matching terminal capacity in Asia, Europe and North America. The $15 billion price tag
is compared to the 2002 capital expenditures of the five super majors, the 'five sisters',
together with the smaller ConocoPhillips. BG is also a major player but, as a gas company,
difficult to compare with the upstream oil producers. Figure 27 assumes that 25% of total
upstream capital budgets are available for LNG, taking 60% of the budget for the world
outside North America and Europe and 40% of that is targeted on gas. It is apparent that
the entry fee remains large compared to available investment dollars for these very large
companies.
CAPEX - $BILLION
$1
$15.5
Bn for a Set of Three
25% of IUprrsfen
CAPEX
Potential
LNG Budgets
Plus Middle EastvUS
Plus NigeriaSpain
$10 ..
an
U
-;-
egasIrmaon
ni TaiDW
Trasport
IndonesiaJapan
LNG
$10i
Liquefaction
$5
Assumptions: Two 33 MMT Trains. $3.86 Field Investment per Annual Mcf. Cornpany Upstream
Budgets @C 25% Based on GD% Invested Outside North America & Europe and 40% Invested in Gas
Figure 27: A regionally diversified portfolio greenfield LNG projects compared to the upstream
capital budgets of selected companies. (Jensen, 2004)
75
UPSTREAM AND MIDSTREAM INTEGRATION
The other face of integration in the LNG industry is that of downstream companies
integrating to the midstream and upstream sectors. For the LNG buyers who still exert
some control over their own markets, the possibility of acquiring an upstream position in
production, usually expected to be the most profitable link in the chain, offers a method of
upstream integration. The main reason behind that is the need to cover risks by securing a
diversified portfolio of LNG supplies and carrier capacity. Essentially upstream and
midstream integration is a method for doing risk-hedging and adding value along the LNG
chain. In Table 4 recent cases of traditional players in the downstream expanding into the
upstream and midstream sectors such as production, transportation and importation are
presented.
The cases of Table 4 are divided in two categories. The first category includes the case
in which the traditional LNG buyers construct and hold their own tankers. This measure is
not intended only to reduce transportation cost by securing the f.o.b. option in LNG import
contracts. Rather, the specific companies seem to take this measure with the objective of
securing opportunities to actively adjust themselves to the changes in the market
environment, not only acting as LNG importers but also shifting their position to act as
LNG sellers. (Odawara, 2004)
The second category of Table 4 includes cases in which the LNG importing companies
participate and acquire interest in the gas development field and liquefaction plant
operation sectors of LNG exporters. In the cases of this category measures are being taken
in line with national policy in addition to the projects led by private businesses, such as
formations of corporate consortiums led by state owned companies. Kogas in Korea was
76
Table 4: Expansion of downstream companies to the midstream and upstream sectors. (Odawara,
2004), (IEA, 2004)
Ist~aio t MidsreamAcquliitin of interests in
gps fiM dvlpetand
Acquired interests in SEGAS that manages the ELNG Damietta
LNG export terminal in Egypt, and 6(r% of the right to use the
liquefaction capacity of the terminal for 20 years
Holding 8% of interests in Qalhat LNG in
Oman
Announce 4 year investment plan targeting projects for
conistructing LNG receiving terminals in USA, via a joint
venture established with Repsol
Constructing and holding its
own
ships
Akuired
Holding
10% in Greater Sunrise gas field and Evans Shoal gas
10% of interests in the first train of Atlantic LNG
of interests in the Bayu-Undang
gas field in
Constructing and holding its own ships
Acquired 3.36%/
Constructing and holding its own ships
Acquired 6.72% of interests in the Bayu-Undang gas field in
Damwn LNG export project
Darwin LNG export project
Oman LNG respectively
of the ROK LNG consortium
Acquired 5% of interests in RasGas and
through the formation
Holding
10% of interests in Block Al
gas field in Myanmar
Acquired 17% of interests in Indonesia's Tangguh, 25% in
Australia's NWS and 12.5% in Gorgon joint venture
Joint venture with Nissho Iwai Corp and Sumitomo Corp with a
6.%iIdosi'Tngu
Ordered 4 LNG tankers for transporting
RasGas LNG to the Taizhong LNG receiving
stk
Holding 5 ships of its own
Holding 5% of interests in ELNG
Holding 12% of interests in the Snohvit LNG export project
one of the first buyers to acquire an upstream stake by obtaining an interest in Qatar's
Rasgas project. It has also been the path of the. Chinese Offshore Oil Company (CNOOC)
in acquiring an equity interest in the Australian North West Shelf project as a part of the
Guangdong purchase contract. This has also been the route that Tokyo Electric and Tokyo
Gas have followed in acquiring an equity interest in the Bayu Undan project in the Timor
Sea. (IEA, 2004)
77
PRICING DEVELOPMENTS IN LNG CONTRACTS
Over the long-term horizon of LNG contracts one of the key elements of risk
management is the determination of the right price formula and the most efficient price
review mechanism. These two will implement the most appropriate risk reduction strategy
with regards to the LNG contract price. (Dubois, 2004)
Traditionally the long-term LNG contract prices have been indexed in oil prices.
However the emergence of the short-term LNG market has paved the way to a wider and
more flexible approach of pricing in the LNG industry. Suppliers are adopting different
pricing policies according to the buyers' market For instance, Qatar, which sells on the
three main LNG markets, has pegged its LNG sales to crude oil prices in Japan, to Henry
Hub spot prices in the US, to NBP spot prices in the UK and to fuel oil prices in
continental Europe.
In Japan, c.i.f LNG prices are based on a basket of crude oils imported into the
country, known as the Japanese Crude Cocktail (JCC), which are adjusted on a monthly
basis. In the past, this "cocktail" was a convenient basis for gas pricing because the main
competitor of gas was light crude oils, whose prices are reflected in the JCC. However, as
gas in electricity generation, which is the major user of gas in Japan, is no longer
competing with crude oil, Japanese buyers require more flexibility in volume and pricing.
Moreover, the contract signed by Australian North West Shelf (NWS) with Chinese
buyers has set a new benchmark for LNG pricing in Asia. The price formula is reported to
be similar to that used for the NWS Japanese contracts; namely an S-curve formula based
on the average price of a cocktail of imported crude oils, designed to protect the parties
against sharp swings in oil prices. However, based on a reference barrel of $18, NWS
78
partners have lowered the c.i.f. price to China to around $3/mBtu, or about 15% below the
current Japanese price. Moreover, the slope of the S-curve is not as steep as under the
Japanese formula. This means that for a price of $25/b, China would pay 25% less than
Japanese buyers. This price cut will greatly affect renegotiation of the Asian contracts of
about 25 mtpa, including Japanese contracts with NWS partners, which come up for
renewal before the end of the decade. (IEA, 2004)
European LNG contracts have predominantly been linked to the evolution of gasoil
and heavy fuel oil prices, with a reference period usually of six months to one year.
However, the recent developments associated with the short-term LNG market have led to
the introduction of alternative indices into the structure of the price formula. In some
contracts other indices, such as electricity pool prices, inflation level, NBP prices for UK
and emerging gas hubs prices like Zeebrugge Hub in Belgium, have now been included to
reflect the new dynamic of the LNG market. A vivid example of the latter is the
introduction of electricity pool prices in the formula negotiated between Trinidad and
Tobago and Spain's Gas Natural. In Figure 28 an example of a long-term LNG price
formula for the European market is presented.
Figure 28: Long-term LNG price formula for the European market. (Dubois, 2004)
79
In the US market, LNG prices are generally linked to the Henry Hub prices. Ex-ship
prices tend to represent 80% to 90% of the futures prices at Henry Hub, as they are
adjusted for the location of the LNG terminal. LNG supply will seek highest differential
compared with Henry Hub spot prices first: Everett; Cove Point; Elba Island and then Lake
Charles. However, the arrival of sudden large LNG supplies flowing directly into the US
gas grid has an impact on the basis to Henry Hub prices and sometimes completely
annihilates it. (IEA, 2004)
POTENTIAL OF RISK HEDGING BY USING FINANCIAL DERIVATIVES
The conditions which recently fostered the emergence of the LNG short-term market
have also given birth to the idea of risk hedging by using financial derivatives.
Specifically, the concept was the usage of financial derivatives, for long-term as well as
short-term risk management, in order to exempt the seller from relying on long-term
contracts for his future cash flow and utilize the longer-term derivatives market in order to
lock in prices. Under this concept financial derivatives in LNG market could be used to
hedge multi-billion dollar LNG investments, thereby replacing the long-term contract in
managing project risk.
The predominant market for natural gas derivatives is the New York Mercantile
Exchange (NYMEX), which is a for-profit corporation organized under the laws of the
state of Delaware and has been in continuous operation as a commodity exchange for more
than 130 years. NYMEX is the largest exchange in the world for the trading of futures and
option contracts based on physical commodities. NYMEX futures market has proved to be
80
highly successful and serves as a potential model for gas risk management in USA and
other countries. It has provided a very liquid vehicle for hedging short-term USA gas
market transactions and enabled companies to stabilize revenues and profitability when
market volatility would otherwise cause them to fluctuate unacceptably. The three common
hedging techniques used by gas buyers and sellers in NYMEX are the following:
" Buying or selling futures. A future is an agreement to buy or sell a specific
amount of gas at a specific location at a specified date and price. All futures are
traded through NYMEX that also guarantees performance of the counterparties.
Currently, gas futures are offered at Henry Hub in Louisiana. Most futures
positions are not closed out by actual delivery but simply through buying or
selling at a later date through the exchange. Because of the integrated pipeline
network in the USA, futures are commonly used to hedge risk across the USA
and Canada.(Shively & Ferrare, 2003)
" Buying or selling options. An option is a right, but not an obligation, to
purchase or sell a future at a specific price within a specific time frame. Options
have a lower cost than futures and are used to create price ceilings and floors
rather than an absolute price guarantee. There are two types of options. A call
option grants the buyer the right to purchase a future at a specific price while a
put option grants the right to sell a future at a specific price. The cost of this
right is called the option premium. For the buyer, the risk of the option is
limited to the option premium since if the option price is not supported by the
81
market, the buyer will simply allow the option to expire. The seller however has
&
an unlimited risk unless he has hedged the risk in some other way.(Shively
Ferrare, 2003)
*
Over the counter (OTC) derivatives. Since the standard provisions of the
futures and options markets often do not fit with a specific customer's needs,
financial service companies and large marketers offer OTC derivatives that
mimic many of the features of the futures/options markets but at different
locations and under different terms. In NYMEX exchange of futures for swaps
(EFS) transactions are provided as an additional instrument to add flexibility to
participants trading and risk management portfolios. The parties to EFS are
allowed to privately negotiate the execution of an OTC swap and related futures
)
transaction on their own pricing terms. (NYMEX,
Natural gas derivatives have enabled buyers and sellers to lock in current market
pricing conditions for physical transactions that will not take place until some time in the
future. Applied to LNG, it would enable the parties to offset the sometimes irregular
delivery of LNG cargoes. For example a transaction for Middle East LNG for the USA
East Coast can be locked in to the current market price despite the fact that it might take
three weeks for the vessel to deliver the cargo. The futures quotations on the NYMEX
exchange are available for 72 months into the future, while for longer-term risk
management, the EFS transactions extend the hedging period years into the future.
However, the liquidity of the NYMEX market drops off significantly for later transactions,
82
making it increasingly difficult to move large volumes without affecting the market. There
are no published figures for swaps activity, but its liquidity is also very poor for longerterm transactions.(Jensen, 2004)
All financial derivatives depend on counter parties to offset the positions of those who
want to hedge prices. For example, if a gas seller uses a futures contract to hedge against a
price decline, someone in the market must be prepared to take a matching contrary position
to balance the transaction. For near months, market speculators contribute significantly to
that role, but as contracts lengthen, speculative activity tends to decline. For longer-term
positions, the market has relied more and more on the specialist market trading companies
and the investment banks as the counter parties. Enron, for example, was a major specialist
in long-term gas swaps. One of the principal consequences of its bankruptcy proceeding
has been to default on some of its longer-term commitments, adversely affecting the
profitability of those who relied on it for hedges. (Jensen, 2004)
The near collapse of the trading companies has markedly changed the outlook for
long-term risk management in LNG. Since some of the affected companies were leaders in
the effort to develop the long-term derivatives market, their problems, and in some cases
complete withdrawal from trading activities, have sharply reduced the number of players
who are prepared to accept that risk. If the idea that a financial derivatives contract could
be used to hedge multi-billion dollar LNG investments was questionable before, it is now
almost completely discredited. (Jensen, 2004)
83
CHAPTER 4 - COST REDUCTION IN LNG SUPPLY CHAIN
COST REDUCTION IN LNG SUPPLY CHAIN
In the last 20 years costs in the LNG supply chain have been declining steadily. LNG
projects are considered among the most expensive energy projects in the world and
accurate data on LNG plant costs are difficult to pinpoint since costs vary widely
depending on location and whether a project is greenfield or brownfield.
The four main price components of an LNG project from the gas field to the receiving
terminal are:
" Gas production cost, which refers to the associated cost for bringing the gas
from the reservoir to the LNG plant
" Liquefaction cost, which includes all the costs relevant to gas treating,
liquefaction, LPG and condensate recovery, LNG loading and storage
*
Shipping cost, which encloses the cost for obtaining the LNG tankers and
transporting the LNG
" Regasification cost, which includes all the costs relevant to unloading, storage,
and regasification of the gas
In Figure 29 the total cost of the LNG supply chain is illustrated for two time periods,
namely the 1980s and 2004. During this 20 years period the total cost of the LNG supply
84
chain decreased by 31.7%, from 4.1 to 2.8 $/MBtu. In the following sections a brief
examination for each cost segment will be presented.
US$/MBtu
5Total Cost = 4.1
-
4
0.8
Total Cost = 2.80
31.4
0.75
-
2
0
2004
1980s
0 Regasification B Shipping 0 Liquefaction EJ Gas Production
Figure 29 : Costs in the LNG supply chain, 1980s-2004.(Gardiner, October 25th, 2005), (lEA,
2004)
COST REDUCTION IN GAS PRODUCTION
The gas production cost is the segment of the LNG supply chain with the smallest
reduction during the last 20 years. In the middle of 1980s the mean production cost was
equal to 0.8 $/MBtu, while in 2004 that was slightly decreased to 0.75 $/MBtu. Even
though the technologies used today enable the big international oil companies to extract
more efficiently larger volume of gas, the cost of current infrastructure is much higher than
it was 20 years ago mainly increasing substantially the cost per MBtu.
85
The driving force of the gas production sector during the last two decades has been the
technological developments in gas reserves detection and extraction. More precise and
efficient acoustic and seismic methods, along with the usage of underwater vehicles,
reduced the required time for detecting gas reserves both onshore and offshore but at a
greater cost. At the same time new drilling techniques enabling horizontal along with
vertical drilling paved the way for shorter and more efficient drilling period, but the
required engineering infrastructure for these kinds of drilling techniques is much more
expensive than the one used 20 years ago. The advance of fiber optics gave the ability,
especially at the offshore platforms, to perform a wide variety of tasks in greater depths
while new designed platforms are able to extract gas from a depth of 6,000 feet below the
sea level. A reduction in the production cost was experienced, because these new
technologies gave access to more gas reserves without having to repeat the traditional steps
of drilling and extracting for each reserve, but since the same technologies are associated
with a higher cost, the cost reduction in the gas production segment of the LNG supply
chain has been small.
COST REDUCTION IN LIQUEFACTION
The largest cost component in the LNG value chain is the liquefaction plant, which
consists of one or more trains, or production units. LNG plant costs are typically high
relative to comparable energy projects for a number of reasons, including remote locations,
strict design and safety standards, large amounts of cryogenic material required, and a
historic tendency to overdesign to ensure supply security.
86
Liquefaction plants typically consist of one or two processing trains. The standard
economic size of each train is now about 4.0 mtpa. Adding a second train once a plant is
built can reduce the unit cost of a liquefaction train by 20-30%. According to Gas
Technology Institute (GTI), construction of a liquefaction plant that annually produces 8.2
mtpa of LNG could cost $1.5 to $2.0 billion depending on land costs, environmental and
safety regulations, labor costs and other local market conditions. Roughly half of that
amount is for construction and related costs, 30% is for equipment, and 20% is for bulk
materials. The liquefaction trains account for approximately half the costs of operating an
LNG plant, storage and loading facilities for 24%, utilities 16%, and other facilities
account for the final 1 1%.(EIA, 2003)
The cost of liquefaction dropped in the last 20 years from 1.4 $/MBtu in 1980s to 1
$/MBtu in 2004. The main factors driving costs downward include:
" Reduction of over-design margins
" Larger and fewer storage tanks
*
Improved technology like gas turbines, larger axial compressors, multiple
compressors, turbines on a single shaft
* Improved engineering techniques
*
Competitive lump-sum bidding.
The cost of adding trains to existing projects is significantly lower than building a new
greenfield plant, since many of the facility components are already in place. Major
87
economies of scale have been achieved by increasing the size of liquefaction trains,
therefore requiring fewer trains to achieve the same output. In the early days of the
industry, trains with annual capacities of 1.0 to 2.0 mtpa were the norm; today, the
Damietta LNG in Egypt is the train with the largest capacity in the world, namely 5.5
mtpa, while a 7.8 mtpa train is planned for Qatar.(EIA, 2003)
Technological progress over the past four decades has led to a sharp decrease in
investment and operating costs of liquefaction plants. The average unit investment for a
liquefaction plant dropped from some $550 a ton per year of capacity in the 1960s in
Algeria, to approximately $433 in 1983 in Malaysia, to $396 in 1996 for QatarGas, to $273
in 2000 for Oman LNG. Further reduction through expansion of the size of trains will be
achieved when QatarGas 2 will start operating. According to EIA the liquefaction cost will
decrease to 200 $ a ton per year capacity by 2010 and to $150 by 2030.(Odawara, 2004)
COST REDUCTION IN SHIPPING
Focusing on the percentage of shipping cost in the LNG supply chain it can be seen
from Figure 29 that in the 20 years period that we examine, shipping cost decreased by
46.2%, from 1.3 $/MBtu to 0.7 $/MBtu. The main factors behind this decrease are
examined further down.
Most LNG vessels are dedicated to particular LNG projects and are owned by LNG
importing and exporting companies or shipping companies. Independent shipping
companies own only a small percentage of the LNG tanker fleet. LNG shipping costs are
determined by the daily charter rate, which is a function of the price of the ship, the cost of
88
financing, and operating costs. In Figure 30 the total transportation cost per MBtu for a
145,000 m2 LNG vessel is presented depending on the distance between the regasification
and liquefaction plant.
145,000 Cu.M Vessel
1.61.4
1.2
0.8
0.60.4
0.2
0
2,000
4,000
6,000
8,000
10,000
12,000
20,000
25,000
Miles -R/Trip
N Capital
D Operating
0Voyage
Figure 30 : Total transportation cost per MBtu for a 145,000 m2 LNG vessel.(Gardiner, October
25th, 2005)
Substantial reductions in cost have been achieved over recent decades thanks to
economies of scale. Tanker sizes have increased from some 40,000 m 2 for the first
generation to more than 200,000 m 2 nowadays. As far as the newbuilding prices are
concerned in Figure 31 the history of LNG vessels newbuilding prices is illustrated for the
time period from 1980 to 2005. After 1997 costs for LNG tankers dropped significantly in
the wake of the Asian crisis and because of an increase in the number of shipyards entering
the market of LNG tankers. The latter enhanced competition and drove the prices to lower
levels. However, after 2002 the prices for LNG newbuildings have been rising steadily
mainly because of an increased demand and a lack of slots in the shipyards.
89
An interesting conclusion that can be extracted from Figure 31 is that even though the
prices for LNG vessels followed quite closely the general trend in newbuilding prices of
other ship types, their volatility is much greater. A possible explanation could be the
limited shipbuilding capability for LNG vessels of the previous years, which permitted the
shipyards to monetize greatly any increase in the demand for LNG vessels.
30025020015010050
80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05
-
VLCC (Right) -
LNG Carrier (150,000 cu.m.) -
CapeSize (Right)
Figure 31 : LNG newbuilding prices, 1980 to 2005.(Gardiner, October 25th, 2005)
As far as LNG freight rates are concerned, there is no set market for LNG tanker rates,
as there is for crude oil tanker rates. Long term rates have eased in the last couple of years
as ship supply has increased. The rates for the recently emerged short-term trade have
followed the long-term rates with a delay, as it will be presented in a later section. The
price arbitrage between the Pacific and Atlantic gas markets is the main driving force
behind the changes in the short-term rates.
90
US$/Day
75,000
-
70,000
-
65,000
-
60,000
-
55,000
-
50,000
-
45,000
40,000
2000
Figure 32
2001
2002
2003
2004
2005
Long-term LNG shipping rates. (Gardiner, October 25th, 2005)
COST REDUCTION IN REGASIFICATION
Regasification plant costs depend on throughput capacity, land development and
labour costs, which vary considerably according to location, and storage capacity. The
reduction in the regasification cost over the last 20 years was equal to 41.6%, from 6
$/MBtu to 3.5 $/MBtu. Currently, regasification cost is the smallest segment of the total
cost for the LNG supply chain, which makes more difficult any further reduction in this
sector.
Regarding the cost of the terminals GTI estimates that it can range from $100 million
for a small terminal, to $2 billion or higher for a state-of-the-art Japanese facility. In the
United States, most new terminals are estimated to cost $200 to $300 million for an output
capacity from 3.8 to 7.7 mtpa of natural gas.(EIA, 2003)
91
By far the most expensive items in a terminal are the storage tanks, which can account
for one-third to one-half of the entire cost, depending on the kind of tank. The tank type, in
turn, is dictated largely by location and local regulatory requirements. Therefore efforts
have been made to reduce cost through economies of scale. The storage capacity of a LNG
tank expanded from 40,000 m 3 in the early days to 100,000-140,000 m 3 in the 1990s and
160,000-200,000 m 3 thereafter. ExxonMobil has recently obtained a patent for LNG
storage tank technology called modular tank which will enable further significant reduction
in construction cost and time. (Odawara, 2004)
Marine facilities are another major cost item, especially if significant dredging of the
ship channel is needed, which could add as much as $100 million to the cost of the
terminal. Based on the current data the probability of increased future dredging activities in
the mature LNG markets is positively correlated with the size of the LNG vessels.
COST REDUCTION AND LNG ECONOMIc FEASIBILITY
The cost reduction in the LNG supply along with the optimistic projections of global
gas demand had certain implications for the LNG industry. The most remarkable was the
effect on the economic feasibility of LNG greenfield projects. Nigeria provides an
excellent illustration of LNG economics evolution. In the mid-1990s, after thirty years of
off-and-on industry discussions of an LNG project, a consortium of Shell, AGIP, Elf and
Nigerian National Petroleum Company, started negotiations on what has become the
Bonny LNG project in that country. Initially the sponsors could not demonstrate economic
feasibility for a project destined for Italian and US markets. But by acquiring very low-cost
92
options on seven laid up LNG tankers, at a time when the price of new builds was at an alltime high, and taking advantage of the technological driven cost reductions in the LNG
chain, they succeeded in reducing the project costs enough to make it economic.
Base
Netback [1] -
f$0.211
A Mid-1990s Perspective
5% of the
Update Tanker Costs -
$0.28
Update Plant Costs -
$0.31
Netback
Improvement
is Driven by a
Change in Price
Expectations
2-3.76 MMT Trains Price @ EIA 2004
$0.17
-0.88
($0.50
*
$0.00
I
$0.50
.
$MMBTU
1
$1.00
.
1
$1.50
.
Improved Netback -$41
$2,00
[1] Assuming EFIA's 2001
Price Forecast for 2010, 3-2.5 MMT Trains, 11 135,00 CuM Tankers, Fant
and Tankers Prk-ed @ Pr-Tdinidad Levels
Figure 33 Netback analysis for the Bonny project in 1998 and in 2004.(Jensen, 2004)
The first value of Figure 33 illustrates the economics that a new Nigerian greenfield
project destined for the US Gulf Coast might have faced in 1998, given the designs, costs
and market price expectations of the period. As is evident, the project was a non-starter
since the initial netback from the expected Gulf Coast market price to the inlet of the
liquefaction plant was negative (-$0.21). For clarification purposes we will remind that
netback calculation is the measure of the value of any given LNG sale. This calculation
takes the price of gas in the marketplace and subtracts the transportation cost plus
gathering and processing costs, if applicable, thereby netting a price in the supply basin.
93
LNG producers with market alternatives will calculate the netback from various markets to
determine which market is most lucrative.
Also in Figure 33 the improvements in netback, as a result of using current cost
estimates for the original design, as well as the design improvements in plant economics
from increasing plant sizes, two 3.75 mtpa trains instead of three 2.5 mtpa trains, are
presented. The common mid 1990s view of relatively low prices for 2010 has been
changing and the 2004 price projection was 32% higher for 2010. The results of these
improvements were impressive and the netback from -$0.21, increased to $1.04 making the
project economic feasible.(Jensen, 2004)
94
CHAPTER 5 - PRICE ARBITRAGE BETWEEN
LNG MARKETS
PRICE ARBITRAGE IN LNG TRADE
An important part of the new short-term LNG trading pattern is the emergence of
arbitrage between the LNG markets. The emergence of price arbitrage has as a result a
shift in the LNG cargoes to whichever market will offer the highest netback. Namely, the
magnitude of the profit margin, calculated by the LNG cost and the LNG price at each
market, determines the final destination point for the LNG cargo. Price arbitrage is mostly
developed within the Atlantic Basin, primarily involving supplies from Trinidad and
Nigeria and markets in the United States and Europe, primarily in Spain. The active role of
Middle East during the last decade in the supply of LNG has facilitated the development of
another pattern of arbitrage between Northeast Asian markets and Atlantic Basin markets
via shipments from the Middle East. Middle East suppliers, principally Qatar, are in a
position to ship either to Asia or to the Atlantic Basin as markets dictate.
Figure 34 illustrates the distribution of the uncommitted volumes of the firm and
probable LNG projects scheduled to start operation in 2010. It can be seen that the
majority of the uncommitted volumes is located in the Atlantic Basin, where arbitrage has
been the most active. The uncommitted volumes include self-contracting where the seller
contracts with his own marketing affiliate in order to achieve downstream integration. If
these system sales are intended to serve previously-determined integrated markets, they
may be less flexible than their appearance as uncommitted volumes would suggest. For
example, several of the companies that have self-contracted have acquired regasification
95
terminal capacity in several markets, clearly intending to move LNG through their own
integrated systems much as they might earlier have done with third-party contracting.
(Jensen, 2004)
BCM INCREASE OVER 2002
140
120 -
Uncommitted or
"System"
The Middle East
Has Been Much
More Oriented
100 -
Volumes are
Towards Third
Large in the
Atlantic Basin
Party Contracts
80
Probable
Co ntract
Fir c
Co nract
Contract
60
40
Probable
Uncommitted
Firm
Uncommitted
Expirations Loom
Important
in the
Pacific Basin
as
-Issues
-
20
0
-20
Atlantic Basin
Middle East
Pacific Basin
[11 Includes both uncommitted and self-contracted volumes
Figure 34: Regional distribution of uncommitted volumes of the 2010 firm and probable LNG
projects.(Jensen, 2004)
It was mentioned earlier that arbitrage enables the trading company to divert cargoes
to those markets that provide the highest netbacks. However, the capability to arbitrage
requires sufficient excess capacity in tankers and receipt terminals to take advantage of
market opportunities when they occur. Some of the excess capacity is the result of the
normal imbalances between supply and demand which can be utilized when available to
seek out the best netbacks. The surplus receipt capacity in the terminals in the USA was in
part a lingering result of the collapse of the Algeria-US trade in the 1980s. But companies
can elect to create excess tanker and terminal capacity in order to take advantage of
arbitrage trading. However, the deliberate creation of excess capacity is not without a cost.
96
In order to create an annual surplus capacity in receipt terminals of 25% a 10% increase in
the costs of regasification is required. The creation of excess tanker capacity through
purchases of newbuild tankers is somewhat more costly. A 25% spare capacity may cause
about a 21% increase in tanker costs. However, the short-term tanker trading has tended to
concentrate on used tankers that are no longer in their original service. For such vessels the
costs can be considerably reduced below newbuild excess capacity levels. (Jensen, 2004)
Closing, we will mention some of the companies with presence in LNG projects on
both sides of the Atlantic optimizing the use of their assets by using arbitrage
opportunities. One of them is Tractebel, which owns US Cabot LNG, now Tractebel LNG
North America, and Belgian Distrigas LNG assets. Its Everett terminal has a prime
location, close to customers and downstream from historic pipeline bottlenecks to transport
gas from the Gulf of Mexico to the North-East. Tractebel is also partner of the Trinidad
Atlantic LNG project and is developing a regasification terminal in the Bahamas, Bahamas
LNG at Freeport.
BG, another Atlantic arbitrager, has also acquired producing LNG assets in the
Atlantic basin: in Egypt, Nigeria, Equatorial Guinea and Trinidad, owns the Lake Charles
terminal in the US, and has recently acquired rights in Elba Island. It is also involved in the
Italian regasification terminal at Brindisi and is developing a new terminal project in the
US, Keyspan LNG, Providence, RI.
The Spanish company Repsol has also developed an LNG strategy based on synergies
in the Atlantic Basin. The company is an equity partner in the Trinidad & Tobago project
and a shareholder of Spain's Gas Natural. This has allowed the company to develop swap
97
agreements involving exchanges of Trinidad and Algerian LNG. Gaz de France and Statoil
are the two other companies developing Atlantic arbitrager positions. Gaz de France rerouted 12 Algerian LNG cargoes to the US in 2003 through its joint-venture with
Sonatrach Med LNG & Gas to benefit from price differentials between the US and
European markets. Statoil, which is developing the LNG Snohvit project with customers
on both sides of the Atlantic, has bought a long-term one-third entry capacity at the Cove
Point terminal in the US.(IEA, 2004)
PRICE ARBITRAGE IN THE ATLANTIC BASIN
Much of the interregional arbitrage that has occurred to date has been in the Atlantic
Basin primarily involving Trinidad and Nigeria as suppliers and the USA and Europe
primarily Spain as market destinations. Figure 35 provides an example of how the
arbitrage between USA and Spain during the time period 1999 to 2003 influenced the flow
of Trinidad's LNG exporting volume. It should be noted that the prices in the US Gulf
Coast are derived from Henry Hub market prices by allowing for a $0.35 regasification
charge and a $0.10 basis differential from the terminal to Henry Hub. Spanish prices are
LNG import prices as liquid. Since Spanish imports include a substantial quantity of
contract volumes with their formula prices, the two price series are not completely
comparable. The Spanish import prices are inherently more stable than US market prices.
The values of Figure 35 show that from October 1999 until April 2000 the prices of
LNG in the USA gas market fell below the prices in Spain and the green line in the Figure
which represents the price differential took negative values. The latter resulted to a shift of
98
the LNG flow towards the Spanish market. The following fall and winter United States
first experienced its gas price shock, and it appeared that anyone with access to a US
terminal could make substantial profits by buying in the surplus LNG market and selling
into the high-priced shortage market in the USA. Many of the proposed new North
American terminal proposals appeared during this period and frequently involved US
marketing companies without upstream LNG assets. Trinidad after November 2000
stopped shipping to Spain and supplied all its LNG volume to the USA.
1,000,000 and
5.0
+I
900,00 1
800,00
3.0
700,00
Volume
US Spain
600,00
m2 LNG 500,00
$/MMBtu
1.0
400,00300,00-..
l ..
.....
-
-
- -
-
- 0.0
200,00100,00
'AMJ JAS
1999
JFMAMJ JASONJFMAMJ JAS
2000
2001
JFMMJ JASON JFMAMJJAS
2002
2003
Henry Hub - Spain Price
-
Figure 35: Movement of Trinidad's LNG volumes between USA and Spain, 1999 to 2003. (Ball,
2004)
However, the during the spring of 2001 gas prices collapsed as market surpluses
developed and access to US terminal capacity no longer appeared so attractive. During
2001, the Atlantic Basin arbitrage worked in favor of Europe where prices remained
99
stronger. Then in late 2002, Tokyo Electric ran into difficulty with its nuclear facilities and
shut down seventeen plants. This upset LNG markets and tanker availability again
affecting the market arbitrage in the Atlantic Basin.
In order to capture the broader picture of price arbitrage in the Atlantic market in
Figures 36, 37 and 38 the netbacks are illustrated from three selected markets, Trinidad,
Nigeria and Qatar, to three suppliers, Spain, Japan and USA, during the same three
periods, 2000, 2002 and 2002, as examined before for the Trinidad's LNG exports. In
December 2000, when US prices were very strong, Trinidad, Nigeria and Qatar all could
achieve higher netbacks from the USA, assuming they had access to terminal capacity,
than they could achieve by shipping to Spain or in Qatar's case to Japan. But by the
following September, US prices had collapsed and both Trinidad and Nigeria preferred
shipments to Spain while Qatar preferred Japan.
F.O.2
Loading Port
Trinidad/Spain
Transport
Trinidad-LakeChades
NigeriaSpain
Nigeria-LakeCharles
-
For Shippers
With Access to
U.S. Terminal
Capacity, the
U.S. Market i.
Preferred
4
Qatar:Spain
;!1:@Y
QatarLakeCharles
9
Qatar/Japan
U
1
4
2
0
0
S.MMBtu
Figure 36 : Netbacks to Trinidad, Nigeria and Qatar from shipping to Spain, USA and Japan,
December 2000. (Jensen, 2004)
100
F.O.B
Loading Port
Trinidad..Spain
]
Trinidad-LakeCharies
NigeriaSpain
5555
Transport
Tnnidad and
Nigeria Prefer
~
Spain
NigerialakeCharles
Qatar Prefers
Japan
Qatar:Spain
Qstar/LakeCharles
QatariJapan
a
a~a
I
I
I
2
3
4
IIIa
,
I
1
0
5
S.MMBtu
Figure 37 : Netbacks to Trinidad, Nigeria and Qatar from shipping to Spain, USA and Japan,
September 2001. (Jensen, 2004)
The strengthening of the Asian markets following Tokyo Electric's nuclear shutdown
in 2002 caused each shipper to prefer a different market; namely Trinidad to the USA
Nigeria to Spain, and Qatar to Japan.
S
Trinidad'Spain
FO.B
Loading Port
~.
]
Trinidad-LakeCharies
Nigeria-Spain
5.,.~
NigerialakeChades
55
Transport
Trinidad Prefers
the U.S.,
Nigeria refers
Spain
~
-55
Qatar Prefers
Japan
Qatar:Spain
Qatar/LakeCharles
QatariJapan
0
1
2
3
$.MMBtu
4
5
6
Figure 38: Netbacks to Trinidad, Nigeria and Qatar from shipping to Spain, USA and Japan,
November 2002. (Jensen, 2004)
101
In Figure 39 the netback performance from actual prices in the previous selected
markets from 2000 through 2003 is illustrated. The time series captures the changing
trends in netback advantage that have been illustrated for the selected months of the
Figures 36, 37, and 38. It is clear that the prices have fluctuated substantially on both sides
of the Atlantic, providing ample opportunity for arbitrage.
SiMMBtu
10
Lake Charles
---
Trinidad and Nigeria Have Similar
Netback. From Spain
Ni ri
Lae Charles
/
9
Trndad/
8
But Trinidad Does Better Against
the U.S. Gulf Coast
7
Trindad or
Nigera/Spain
6
4
3
2
1.0
Jul 00
Jul 02
Jul 01
Jul 03
[11 US Prices are Market Prices; Spanish Prices are Import Prices and Inc4ude Irnports with
Relatively Stable Contract Terns
Figure 39 : Illustrative netbacks for selected Atlantic arbitrage patterns. (Jensen, 2004)
PRICE ARBITRAGE IN THE PACiFIC BASIN
In the Pacific basin, an arbitrage pattern is not possible as long as no regasification
capacity is available on the US west coast or Mexico. Even when such capacity becomes
available, transportation distances may be a limiting factor for the development of
arbitrage possibilities. Such a development would involve much larger differences in
shipping distances than in the Atlantic basin. For example, it would take three times more
102
ships to deliver an equivalent amount of LNG from Indonesia's Bontang to California as it
now does to Japan. However, as the LNG market evolves, the Middle East is going to act
as a swing supplier. The Atlantic basin market will be connected to the Pacific basin via
Middle East producers, which may export to both markets. This is illustrated in Figure 40,
which shows the potential netbacks for Qatar from the US Gulf Coast, Spain and Japan.
$/MMBtu
8
US Gulf Coast is an Attractive Market When
US Prices
Strong
are
7
Lake
hre
Lk Charles
Japan Usually Gives Better Netbacks
Than Spain But is Much Lees Active m
Short Term Markets
6
Spain
Japn
4
2
0
Jul 00
Jul 02
Jul 01
Jul 03
[1] US Priosa are Market Prices; Spanish and Japanese Prices are Import Prices
and Include
Imports with Relatively Stable Contract Tens
Figure 40 : Illustrative netback calculations for Qatar from the US Golf Coast, Spanish and
Japanese market. (Jensen, 2004)
The Japanese price data, like the Spanish price data, are for all LNG imports and thus
include the stabilizing effect of contractual volumes. When US prices have been strong,
they have provided the best netbacks to the Middle East. Japan usually provides better
netbacks than does Spain, but the fact that Japan has a much more limited short-term
market tends to focus the Middle East trading volumes on Europe. Japanese prices based
on the traditional crude oil linkage formulas that have been utilized in that country, have
103
tended to be among the world's highest. The expiration of a significant number of
Australian and Indonesian contracts toward the end decade has the potential to weaken
Asian prices and to change the relative shape of the curves of Figure 40.
104
CHAPTER 6 - FINANCIAL FEASIBILITY OF SHORT-TERM
IN THREE ROUTES
LNG TRADING
ANNUAL VESSEL'S PROFITABILITY
In order to investigate the financial feasibility of short-term LNG trading an analysis
was performed aiming to calculate the profits of a shipowner trading his ship, under shortterm contracts, in three different routes.
The characteristics of the ship along with the values for the relevant costs are
presented in Table 5.
Table 5 : Ship's characteristics and costs.
Ship Characterisics
Annua _Opraing TkMe (
Mr)
8,400
Capital Expenses
CAPEX ($/d;!y)
$ 39,389
Qpratinq Exp!nses
1nsuanWJ~t$
Repars (c~j$
Stores
;
2,900.00
900.00
$ 500.00
$ 500.00
$ 5,200.00
OPEX
$10,000
VoyIge Expenses
Voyage Cost ($/day)
$ 19,000
105
The LNG vessel is newbuild with cargo carrying capacity 150,000 m 3 and purchase
cost $220 million. $20 million are financed by equity and the rest of the $200 million is
financed by debt. The interest of the loan was assumed equal to 6% and the payback period
was determined to 30 years. The loading and unloading time for the cargo was set to 24
hours and the assumption was made that the vessel will be operational for 350 days per
year.
The selected liquefaction plant from where the cargo will be loaded is the RasGas
plant situated in Qatar. The reason for choosing Qatar as the cargo loading point is its
strategic position, which enables shipping both to the East Coast of North America and to
the West part of the Pacific Basin. The three cargo destinations chosen are the South coast
of Spain, the East coast of USA, specifically Boston, and Japan. The travel time for the
round trips from Dohra to the three destinations, along with the maximum number of round
trips that the vessel can complete in one year, are illustrated in Table 6.
Table 6 : Distance and travel time for the three trading routes.
Dohra to
Dohra to
Dohra to
Spain
Boston
Japan
5,700
23.75
25.75
13.6
9,600
40.00
42.00
8.3
7,300
30.42
32.42
10.8
The objective of this analysis is to estimate the annual profit of the shipowner based
on two parameters, the freight rate expressed in $/MBtu and the number of round trips per
year. A range was selected for these two parameters and the annual profit was calculated
106
for all the possible combinations of the two parameters. The equations used and the results
of the calculations are presented in Appendix II.
For the first trading route, Qatar to Spain, the results of the annual profit are presented
in the three-dimensional graph of Figure 41. The main conclusion that can be stated is that
for all the values of the selected price range, if the vessel makes three or less round trips
per year the shipowner will make losses. As the number of round trips increases, the
required rate for closing the year with a profit decreases, as it was logically expected. The
minimum value of the rate for this trading route is equal to 0.65 $/MBtu. For lower values
than this, short-term trading in this route is not profitable, no matter how many trips the
vessel will do during the year.
Profit calculation for an 150,000 m3 LNG vessel trading in the short-term market
between Dohra and Spain
Profit ($1,000)
$60,0G
$45,000
$15,0
-
$30,
-$15,000-
-$30,00
0
0.15
0.3
0.45
0.6
0.75
0.9 1.05 1.2
Rate ($/MBtu)
1.35
1.5
1.65
1.8
1.95
1
U -30000-15000 U -15000-0 00-15000 015000-30000 E30000-45000 045000-60000
Figure 41 : Annual profit calculations for the route Dohra to Spain.
107
Number of
Round
Trips
The second trading route, namely from Dohra to Boston, has the longest traveling
distance, which means that the increased voyage cost will require a higher rate than the
other two routes in order to be profitable. Indeed by looking the results it is clear that the
minimum value of the rate is equal to 0.95 $/MBtu. The latter value is 46.2% higher than
the one of the Dohra-Spain route and we estimate that an increase in the rates of this route
will be driven by an increase of the USA gas demand combined with a shortage of LNG
from the Atlantic Basin suppliers. The minimum number of round trips is equal to three
which is the same with the previous examined route. The results of the profit calculations
are presented in Figure 42.
Profit calculation for an 150,000 m3 LNG vessel trading in the short-term market
between Dohra and US East Coast (Boston)
Proft ($1,000)
$30,
$20,000
$10,000-
$0-$10,000-
-$30,OOD-
0
0.15 0.3
0.45 0.6
0.75
0.9 1.05 1.2
Rate ($JMBtu)
1.35
1.5
1.65
1.8
1.95
7
$
-$20,000-
Number of
Round
Trips
1-30000-20000 0-20000-10000 03-10000-0 00-10000 010000-20000 820000-30000
Figure 42 : Annual profit calculations for the route Dohra to Boston.
Finally, the profitability of the last route, from Dohra to Japan, is the profitabilites of
the previous two routes. The minimum number of the return trips is again three, which
108
shows that for the selected range of rates the total number of the return trips the vessel will
make, independently of the combination of the trading routes, must be more than three in
order to have a profit. The minimum rate is equal to 0.75 $/MBtu which is 15.4% higher
than the one of the route Dohra to Spain. The minimum profit is equal to $199,000 and is
achieved with 6 return trips at a rate of 1.15 $/MBtu. The results of the calculations are
illustrated in Figure 43.
Profit calculation for an 150,000 m3 LNG vessel trading in the short-term market
between Dohra and Japan
Profit ($1,000)
$50,000
$40,000$30,00
$20,000-
$10,000
-$10,000
-$20,000-
0
-$30,000-
0
0.15
0.3
045
06
075 0.9
1.05
1.2
Rate ($/MBtu)
1.35
1.5
1.65
1.8
1.95
1
4
Number
of Round
Trips
B-30000-20000 U-20000-10000 0 -10000-0 00-10000 E10000-20000 020000-30000 E30000-40000 040000-50000
Figure 43 : Annual profit calculations for the route Dohra to Japan.
109
CHAPTER 7 - FUTURE INTERNATIONAL LNG TRADE
FUTURE LNG DEMAND
In the following years natural gas will capture an increasingly greater share of the
world's energy use. As we mentioned in Chapter 1 natural gas is currently the fastest
growing primary energy source. The annual increase of natural gas consumption
worldwide until 2020 is projected to be equal to 2.3%. LNG in the years to come will
enforce its role in the international natural gas trade mainly because of a regional
imbalance between the natural gas supply countries. The combination of increased natural
gas demand and reduction of gas reserves in USA and Europe, excluding Russia, also
contributes to the augmentation of LNG trade.
Global LNG demand forecast according to Cedlgaz and Gas Strategies
450
400
350300-
250-
o South America
O North America
200-
KEurope
MAsia
150
100-
50-
2003 LNG
demand
edigaz Low I Gedigaz High
Gas
I Strategies
2010 LNG demand forecast
I
Gedigaz
Low
Cedigaz High
Gas
Strategies
2020 LNG demand forecast
Figure 44: Global LNG demand forecast, 2010-2020. Sources (Marie-Francoise Chabrelie, 2003;
Suzuki & Morikawa, 2005)
110
In Figure 41 of the previous page the forecast of Cedigaz and Gas Strategies regarding
the global LNG demand for the years of 2010 and 2020 is presented. In 2010 Cedigaz
predicts that the mean value of LNG demand will be equal to 217 mtpa, with the low
demand scenario forecasting 201 mtpa and the high demand 234 mtpa, while Gas
Strategies believes that it will be greater and equal to 320 mtpa. For 2020 Cedigaz predicts
a 320 mtpa for the world's LNG demand according to the low demand scenario and 380
mtpa according to the high demand. Gas Strategies is more optimistic forecasting a global
LNG demand equal to 393 mtpa.
In the Figures 42, 43 and 44 the regional forecast regarding LNG demand are
presented for the same time period of Figure 41. Cedigaz believes that LNG demand in the
LNG demand forecast in Asia according to Cedigaz and Gas Strategies
-
20
180-
160 -4
140120-
E Other
U China
mtpa 100
Oindia
OTaiwan
South Korea
6W0 -
E Japan
4020-
0-2003 LNG
Cedigaz Lo
Cedigaz High
demand
2010 LNG demand
Gas
Strategies
Cedigaz Low Cedigaz
forecast
High
Gas
Strategies
2020 LNG demand forecast
&
Figure 45: LNG demand forecast for Asia. Sources (Marie-Francoise Chabrelie, 2003; Suzuki
Morikawa, 2005)
111
Asian market for the year 2010 will increase by 29.7%, low demand scenario, or by 39.3%,
high demand scenario, from the level of 2003 LNG demand. For 2020 the percentage of
increase is 75% and 95.2% respectively. The forecast of Gas Strategies provides a 46.4%
increase for 2010 and a 119% increase for 2020.
LNG in Asia market is and will continue to be the basic type of natural gas supply
mainly because of geopolitical reasons. Currently no international natural gas pipeline
exists in the Asia-Pacific region, excluding some areas in Southeast Asia where the
Dolphin project is carried out between Qatar, Oman and UAE. The two main pipeline
projects which have drawn the attention of the gas industry the last two years are the Trans
ASEAN Gas Pipeline (TAGP), extending from East Siberia to China and ROK; and the
project for pipeline extending from gas producing countries such as Iran, Turkmenistan
and Myanmar to India. The latter was abandoned when the political tension, between the
countries in which the pipeline is to pass through, were brought into surface. The former
faces an uncertain future since an agreement between the concerning countries has not yet
been reached. The emergence of Qatar as a major supply country, the uncertain political
future of Iran and the pressure from certain members of OECD towards Russia points to
the conclusion that the only way in the near future of exporting natural gas from the Asian
countries will be by LNG.
In the European market while natural gas demand is expected to increase due to the
movement trending away from the use of nuclear energy, the interregional sufficiency will
decline. As both Norwegian and Algerian reserves are constrained, by 2020, most of the
incremental gas supply would have to come by pipeline from transition economies, mostly
112
Russia and the Caspian Sea, and in the form of LNG from the Middle East, West Africa
and Latin America. By that time, European supplies will be dominated by Russian/ FSU
gas supplies and LNG imported from countries from Africa and the Middle East area.
However, the unit cost of getting European gas to market is expected to rise as more
remote and costly sources are tapped. Piped gas from North Africa and the Nadym-Pur-Taz
region in Russia are the lowest cost options, but supplies from these sources will not be
sufficient to meet projected demand after 2010. Pipeline projects based on fields in the
Yamal Peninsula and the Shtokmanov field in the Barents Sea in Russia are among the
most expensive longer-term options. That leaves LNG as the most efficient solution for the
supply of gas to the European market.
LNG traded both under long-term contracts and on spot markets, will play a much
more important role in supplying the European gas market if supply costs continue to fall.
LNG imports will become especially important if Russian gas sector reforms lag and
investments in Russian fields fall short of expectations. This could happen, if investment in
new Russian fields is insufficient to compensate for the decline in production from existing
fields. In any event, the distances over which LNG imports from new sources need to be
shipped may well drive costs and prices up.
In Figure 42 the forecast of LNG demand in the European market is presented. The
forecast of Cedigaz for 2010 shows a 86.7% increase for the low demand scenario and a
126.7% increase for the high demand. Gas Strategies' forecast for the same year a 296.7%
increase. For 2020 Cedigaz predicts a 190% and a 266.7% increase for the two scenarios,
while Gas Strategies believes that an increase of 276.7% is more probable.
113
LNG demand forecast in Europe according to Cedigaz and Gas Strategies
140-
120-
100-
SmOthers
* UK
80-
ETurkey
E
U Spain
* Portugal
0 Italy
O Greece
E France
* Belgium
mtpa
60
-
40
LNG
demand
S-2003
C-edigaz
Lo.
Cedigaz Hig
Gas
Strategies
Cedigaz Low
2010 LNG demand forecast
Cedigaz High
SGasi
Strategies
2020 LNG demand forecast
Figure 46 LNG demand forecast for Europe. Sources (Marie-Francoise Chabrelie, 2003; Suzuki
& Morikawa, 2005)
In North America the gas market essentially consists of two countries USA and
Canada with the possible entrance of Mexico in the next years. According to the forecasts
of Cedigaz in 2010 the LNG demand will be greater than the one of 2003 by 219%, low
demand scenario, or 318%, high demand scenario. Gas Strategies is very optimistic about
the future role of Mexico and predicts an increase of 600%. As for 2020 the increasing role
of LNG imports in the USA leads Cedigaz to a prediction of a 645% and 872.2%
respectively for the two scenarios. Gas Strategies concludes that the LNG demand will be
equal to 91 mbta, which represents a 727.7% increase from 2003. The above mentioned
data are illustrated in Figure 44.
For years the USA market has been dominated by a surplus of supply and low gas
prices giving little opportunity for LNG. Starting in 2000 tight supply capacities led to a
114
sharp rise in prices which peaked at $ 10/MBtu in January 2001 before dropping again.
There is no doubt that LNG imports are going to expand quickly and contribute to a
growing share of USA gas supply. A report by the Unites States National Petroleum
Council (NPC) titled "Balancing Natural Gas Policy" indicates that the USA natural gas
market is facing a fundamental change, which is the increasing dependence on imports
from outside the region due to the decline in self-dependence and reduction in Canada's
export capacity. Considering such change the report mentions that in order to lower the
natural gas price and reduce price volatility it is necessary to develop new supply sources,
promote infrastructural improvement and expand LNG imports with a view to reduce a
potential gap between supply and demand.
LNG demand forecast In North America according to Cedigaz and Gas Strategies
120-
76
80 --
-
-
-
100-
o Others
mtpa
Mexico
-0
0 Canada
40-
2003 LN
demnand
Cedigaz Low
0
Cedigaz High
2010 LNG demand
Gas
Strategies
forecast
USA
Cedigaz Low Cedigaz High
Gas
I
Strategies
2020 LNG demnand forecast
Figure 47: LNG demand forecast for North America. Sources (Marie-Francoise Chabrelie, 2003;
Suzuki & Morikawa, 2005)
115
In Mexico while efforts have been made to increase self-sufficiency by shifting the
emphasis on the development policy from oil to natural gas, the Comision Regulatora de
Energia (CRE) expects that domestic demand, mainly for power generation, will exceed
domestic production. Considering the necessity to import LNG from a medium and longterm perspective, projects for constructing LNG receiving terminals are being carried out
on the coast of the Gulf of Mexico.
Canada currently is self sufficient for natural gas but by 2020 the cost to extract gas
from the remaining gas reserves will increase significantly making LNG imports a more
economical solution to satisfy gas demand. Currently in Canada with a view to achieve self
sufficiency and LNG export to the USA, several projects in constructing LNG receiving
&
terminals are being promoted in the Atlantic Coast and the Pacific Coast. (Suzuki
Morikawa, 2005)
In South America the role of LNG will be of minor importance for the following years
since the official energy policies of the South American countries are mainly focused
towards oil. Currently LNG imports are minimal and the potential future interest of Brazil
and Chile is uncertain for the time being.
LNG REGASIFICATION TERMINALS CONSTRUCTED UNTIL 2011
An urge for constructing LNG regasification plants is apparent in several countries
both traditional players and new entries in the LNG market. In Table 5 a collection of the
most probable projects be constructed is presented according to their current status. It
116
anesis
&Morikawa, 2005), cor
7Suzuki LNieaflcaIes
Plane
laned L G r asfiction terminals.
TableSouc7:Tabl
sites
132.62
North America
Canada
Point Tupper
7.67
2007
Bear Head LNG-Anadarko
Port Pelican (Offshore), LA
Freeport, TX
Sabine, LA
Fall River, MA
Corpus Cristi, TX
Corpus Cristi, TX
Corpus Cristi, TX
Sabine, TX
12.26
11.5
19.93
6.13
19.93
7.67
7.67
7.67
2007
2007
Chevron
Cheniere Energy, ConocoPhillips
Chenier Energy
Hess LNG
Cheniere Energy
ExxonMobil
Ingleside Energy
ExxonMobil
Cost Azul
Coronado Island
Puerto Libertad
Penualas
7.67
10.73
9.96
3.83
2007
2007
2008
2008
Shell, Sempra
Chevron
DKRW Energy
Tractebel
6.44
0.4
2007
2009
AES Ocean Express
ENAP
Putian, Fujian
Qingdao, Shangdong
Shanghai
Ningbo, Zhejiang
Rudong, Jiangsu
Darlian, Liaoning
Tiangjing
Zhuhai, Guangdong
Swatou, Guangdong
Guangxi
Hong Kong
2.6 -5.0
3.0
3.0
2007
2008
2008
2008
2008
2008
2010
2010
2010
2010
2011
CNOOC, Fujian Investment
Sinopec
Tokyo Electric
Tokyo Electric
Tokyo Electric
Tokyo Gas
Tokyo Gas
Shimizu LNG
Chubu Electric
Chita LNG
Toho Gas
Cilegon
3
2007
PLN
Korean
1.5
2008
LG-Caltex Oil
Kochi
Ennore
2.5
2.5-3.0
2007
2008
IOC, Petronas
Taichung
4.5
2008
CPC
TBD
3.0-5.0
2010
PTT
0.9-1.08
2011
Contact Energy, Genesis Energy
Fos-sur-Mer 2
6
2007
Gaz de France, Total
Brindisi
Syracuse
Rovigo
6
5.84
3.7
2008
2010
2008
BG, Enel
Shell, ERG
ExxonMobil, Edison
Reganosa
2.1
2007
Milford Haven
22.76
2007
USA
2007
2007
2008
Mexico
6.84
Central America
Bahama
Chile
49-65.08
Asia
China
3.0-5.0
3.0-6.0
3.0-6.0
3.04.0
2.0-4.0
3.0
3.0
2.5
Indonesia
South Korea
India
Petronet
Taiwan
Thailand
New Zealand
TBD
46.4
Europe
France
Italy
Spain
Endesa, Union Fenosa, Sonatrach
UK
World Total
234.86-243.76
117
Petroplus, BG, Petronas, ExxonMobil, Qatar
Petroleum
should be mentioned that for the USA only the projects approved by FERC, MARAD and
the Coast Guard are included in Table 5.
At this point two notes should be made. First, the Rovigo LNG terminal presented in
Table 5 will be located offshore the coast of Italy in the North Adriatic Sea and will be the
largest terminal of its kind in the world. The shipyard which will construct it is Aker
Kvaerner. Second, in recent months there has been an increased interest for constructing
LNGRV vessels. LNGRV are LNG vessels equipped with regasification equipment in
order to regasify the LNG on ship and transfer it through a pipeline to the shore. Their
main advantage is that they do not require a permanent regasification terminal onshore,
which reduces dramatically the total cost of an LNG project and makes it ideal, from a
public point of view, for delivering gas in regions with high environmental constraints.
However, these kinds of vessels are approximately $50 million more expensive than
ordinary LNGs, and even though their technology has been proven onshore, their
efficiency in the marine environment will be proved with time. Currently, Excelerate
Energy owns two of these ships with capacity 138,000 m3 , while seven more have been
ordered; 3 for Excelerate Energy paired with Exmar, two solely for Exmar and two for
Hoegh and MOL.
FUTURE LNG PRODUCTION
LNG production capacity is set to expand rapidly the following years with expansion
plans in brownfield projects and greenfield projects in new supply countries. Even when
allowances are made for delays to project start ups, the impact on LNG trade and ship
118
demand will be pronounced. In Figures 45 and 46 the existing and future global
liquefaction capacity is presented. Specifically in Figure 45 the global liquefaction capacity
from 1970 until 2005 is illustrated along with the projects that have signed SPA or MOU
contracts. It is shown that, according to current data, the liquefaction capacity in 2014 will
be equal to 237.9 mtpa, almost 47.5% greater than the capacity in 2005.
Global Liquefaction Outlook
mtpa
3-
280
-
E
Capaclty
Under Production
Awarded
260
240
220
200
180
160
140
120
7% Average Annual
100
Growth Rate
80
60
40
20 70 72 74 76 78 80 82 84 86 88 90 92 94 96 98 W 02 04 06 08 10
16
Figure 48: Global liquefaction outlook in 2005. (Buoncristian, 2005)
The distribution of the liquefaction capacity in four categories is illustrated in Figure
45. According to their status liquefaction plants are categorized in existing, under
construction, planned and speculative. The sum of existing and under construction
categories is the one shown in Figure 45 for the year 2014. It is quite impressive that
40.4% of the planned liquefaction capacity, namely 43.7 mtpa, is allocated in the Middle
East region highlighting the importance of this region to the future of the LNG trade.
119
Global Liquefaction Capacity
North America
[
Europe
Existing
161.2
Under Construction
Planned
76.7
225.8
Latin America
"
Africa SOMEONE
Middle East
AsialPacific
0
20
E Existing
40
80
60
E Under Construction
100
U Planned
120
140
160 mtpa
0 Speculative
Figure 49: Global existing and future liquefaction capacity as of 2005. (Gardiner, October 25th,
2005)
Future LNG production will be greatly influenced by the future role of five major
supply countries, namely Iran and Qatar from Middle East, Russia from Europe, and
Nigeria, Angola and Equatorial Guinea from West Africa. In the following paragraphs a
brief overview of the countries mentioned above will be presented.
The LNG industry is now focusing with great interest on the plethora of upcoming
projects in West Africa. So far the region has only one LNG producer Nigeria LNG
(NLNG) but another four, Equatorial Guinea, Brass LNG, Angola LNG and Olokola LNG,
are scheduled to begin the next five years. The NLNG project started after several years
delay but since the first cargo was shipped in 1999 it has expanded quickly. NLNG's
fourth and fifth liquefaction trains came onstream in 2006 and production is set to rise to
22 mtpa once train six starts to operate in 2007. Unofficial information proclaims that
120
NLNG has already signed an MOU agreement selling all the production from train seven
to the USA. A final investment decision on the train is due in December 2006.(Hine,
2006d) Brass LNG is the second greenfield project launched in Nigeria and recently it was
announced that 6 mtpa of its planned 10 mtpa production has been sold with BP, BG and
Suez buying 2 mtpa each. However, the project is expected to face a delay since on
February 2006 Chevron, a major stakeholder, pulled out from the project and a
replacement procedure was launched. Energy major Total, Centica from UK and various
Japanese companies have been mentioned as possible replacements. Closing, Olokola
LNG (OKLNG) is the last and biggest LNG project in Nigeria. OKLNG will be composed
by four trains of 5.5 mtpa each. Start-up date is scheduled for late 2010 and the total cost is
estimated at $6 billions. Nigeria is expected to play a predominant role especially in the
LNG short-term trade because of its proximity to the European and North American
market compared to the Middle East suppliers.(Hine, 2006d) Political stability will be an
essential factor for the future of the Nigerian projects; the Nigerian oil workers strike in
2003 showed that energy supplies could be disrupted by local social actions.
Angola and Equatorial Guinea are moving towards their first LNG projects. In
Angola the announced project will be of 6 mtpa capacity with Sonangol, Chevron, BP,
ExxonMobil and Total as stakeholders. The Equatorial LNG project near Malabo will have
one train with capacity 3.4 mtpa and BG as the main investor.
Russia holds the largest amounts of natural gas in the world, 27.5% of the global
natural gas reserves, and is certain that it will significantly affect the future LNG trade.
Since the break-up of the Soviet Union the Russian economy has been fuelled by the
121
energy sector, which accounted for almost 25% of the GDP. Russia's state controlled
natural gas company Gazprom holds about 65% of the country's reserves, produces nearly
90% of Russian gas and operates the national natural gas pipeline grid.
One of the main goals for Gazprom is to become the world's leader in the LNG
&
market and is focused mainly on the USA market. According to the Gazprom Marketing
Trading LNG department, Russia could be exporting 65 mtpa of LNG by 2015. Shtokman
field located 348 miles north of Russia's Arctic coastline in Barents Sea is the main project
that Gazprom is focused on. The project will be realized in three phases and upon
completion it will be the largest liquefaction project in the world with total capacity of 45
mtpa. The importing markets will be the USA Gulf Coast and the eastern or north-eastern
coast of Canada. On a much smaller scale, but more immediately realizable, is the Baltic
LNG project in which Gazprom plans to convert gas it already exports via pipeline into
LNG and ship it out through a new 5 mtpa terminal from Primorsk or Ust-Luga near St.
Petersburg. It should be noted though that since Russian business remains highly
politicized, LNG exports may face unexpected delays and commence after the planned
start-up date of 2010.
In the meanwhile Gazprom made its first step in the LNG short-term trade on April of
2006. The Greek owned LNG vessel 'Maran Gas Asclepius' delivered the first spot-trade
csargo of Gazprom in the UK market. The cargo originated from Egypt and its original
destination was the Spanish market. However, price arbitrage between UK and Spain
denoted that the cargo should be diverted to Spain.
122
Qatar had a big effect on the world LNG dynamics the past two years. The current
Emir of Qatar envisioned his country to become the world's biggest supplier in the
following years. However, because of Qatar's geographical position, situated between the
world's current largest consumers, Japan and Korea and the USA, the greenfield projects
had to take full advantage of the economies of scale. Currently Qatar is the fourth largest
LNG exporter after Indonesia, Malaysia and Algeria, with 20.5 mtpa and has SPA/MOU
signed for an additional 55.9 mtpa. If production capacity proceeds according to plan,
Qatar will have nearly 76 mtpa of production capacity by 2012, and it will become the
world's largest LNG exporter.
Finally, Iran is the second country after Russia with the biggest natural gas reserves in
the world, but the political instability that is presently facing reduces the probabilities of
developing an LNG export industry in the immediate future. As it was mentioned in an
earlier chapter, Iran was developing an LNG export policy under NIGEC (National Iranian
Gas Export Policy). Four LNG projects were planned, each with some 9-10 mtpa, although
with no startup date or investment decision taken so far. For the time being, no one project
is likely to move ahead, and the negotiations between NIGEC and BG and ENEL, who are
primarily interested in securing LNG at competitive prices, have stopped. In general unless
the political situation in the Middle East is settled, LNG coming from this region will not
necessarily be considered as secure supplies. This is reflected in the rather low credit-rating
of Iran and other countries in the Gulf region.
123
LNG LIQUEFACTION TERMINALS CONSTRUCTED UNTIL 2011
The plans for the construction of LNG liquefaction plants worldwide are numerous but
only a part of them will finally be realized. In Figure 6 the liquefaction plants with signed
SPA/HOA worldwide are illustrated.
Table 8: Liquefaction plants with signed SPA/HOA. Source (Suzuki & Morikawa, 2005), (Hine,
2006c)
52.5
Africa
Angola
5 Sonagol, Chevron, BP, Total, ExxonMobil, Norsk
Hydro
Angola LNG
2010
EquatoralGuinea
Equatoral Guinea LNG
2007
3.4
Marathon, Mitsui, Marubeni, Sonagas
Olokola LNG
Brass LNG
Nigeria LNG (train 7)
2010
2010
2010
22
10
8
NNPC, Chevron, BG, Shell
NNPC, ConocoPhillips, Agip
NNPC, Shell, Total, ENI
USA
Nigeria LNG (train 6)
2010
4.1
NNPC, Shell, Total, ENI
USA, Europe, Mexico
2006
3.7
Oman LNG, Omani government, Union Fenosa
Europe, Asia
Qatargas II (train 4,5)
2007
15.6
Qatar Petroleum, ExxonMobil, Total
UK, France, USA
RasGas II (train 5)
2007
4.7
Ras Laffan LNG Company Limited
Europe
RasGas III (train 6,7)
QatarGas III
QatarGas IV
Yemen
Yemen LNG (train 1,2)
2008
2008
2010
15.6
7.5
7.8
Ras Laffan LNG Company Limited
Qatar Petroleum, ConocoPhillips
Qatar Petroleum, Shell
USA
USA
Europe
2008
6.7
Total, Yemen Gas, SK
Asia, Europe
4.2
Petro, Statoil, Total, RWE, Amerada Hess
USA, Europe
2007
9.6
Mitsui, Shell, Mitsubishi
Asia
2008
7.6
BP, MI Berau, CNOOC, Nisseki Berau, LNG
Japan, KG Berau Wiriagar
Asia, Japan
3.5
Eni, Santos, Inpex, Tokyo Gas, Tokyo Electric
Asia
Nigeria
61.6
Middle East
Oman
Qalhat LNG (train 3)
Qatar
Europe
Norway
4.2
Snohvit LNG
Asia Pacific
Russia
Sakhalin II (train 1,2)
Indonesia
Tangguh (train 1,2)
2007
20.7
Australia
Darwin LNG
World Total
2006
139
124
The total liquefaction capacity is equal to 139 mtpa with the majority of the potential
capacity, 61.6 mtpa, concentrated in Middle East and specifically Qatar. Attention should
also be paid to the trend of enlarging the liquefaction capacity in order to achieve
economies of scale and reduce the cost.
FUTURE LNG FLEET
LNG shipping has become one of last years most active sectors in shipping with
unparalleled new orders and a forecast growth expected to continue. Another unique future
is the occurrence of speculative orders and an increase in the size of the vessels along with
a possible demise of the steam turbine. Since the emergence of LNG shipping the
conservatism regarding new technical developments was center of the owners' philosophy.
That had as a result almost no new developments in the last 40 years. However, the last 4
years the shipping worlds has experienced a sharp size increase from 145,000 cbm in 2002
to more than 200,000 cbm in the next years. Apart from the size increase, the choice of
Gaz de France for using dual fuelled diesel electric propulsion was another innovation that
surprised many stakeholders. Shell is currently investigating new gas turbines designs
while direct drive slow speed diesel engine propulsion with a reliquefaction plant, as the
means to dispose of the boil-off gas, will become increasingly common in the following
years.
The world LNG orderbook as of April 210 2006 is illustrated in Table 7. For each
shipyard the ordered vessels are categorized according to their owner, size their scheduled
delivery date.
125
Table 9: World LNG orderbook as of April 21" 2006.(Hine, 2006a)
Mo ier (z Y emen)
Chevron
Oman
MISC
BG
Teekay (Qatar)
OSG (Qatar)
Petronet
NYK (Nigeria LNG)
K Line (Tangguh)
QGTC (Qatar)
Hoegh LNG
U
AF
2
1
4
7
4
2
1
2
3
3
2
IM I
Golar
140,UUU/I14,UUU
154,000
145,000
145,000
145,000
216,200
216,200
154,800
149,600
153,000
266,000
145,000
mar uL-uec uv
Jul 08-May 09
Jul-06
Nov 06-08
Apr 06-Feb 08
Feb-Jun 08
Oct 07/Jan 08
Sep-06
Jun 07/Aug 07
Nov 08-Jan 09
Aug 08-Nov 09
2009
14, 1UU/1 bb,UUU
Jun ubiu1u
May 06/Jan 07
Mar 06-Jun 08
Dec-06
Oct-06
Aug 06/May 07
Dec 06/Mar 07
Mar 08/Sep 09
Dec-06
Mar/Nov 08
Feb-Aug 08
Nov 07-Feb 08
2009
145,000
2
5
2
1
2
156,100
138,000
145,700
3
151,700
2
5
2
5
4
3
148,000
138,000/150,900
145,000
210,100
209,000
264,000
Dynacom
3
149,700
NYK
Tsakos
BP
JS (Qatar)
3
149,700
1
3
150,000
155,000
3
216,200
NLNG
OSG (Qatar)
1
141,000
2
216,200
3
1
1
1
155,000
150,000
155,000
155.000
Bergesen (NLNG)
BWGas (Yemen)
Knutsen
Maran Gas (Qatar)
Teekay (Qatar)
Sovcomflot/NYK (Tangguh)
Exmar/Excelerate
Korea Line (Kogas)
JS (Qatar)
Pronav (Qatar)
QGTC (Qatar)
148,300
&
Huyndai Heavy Industries
Huvndai Samhn
Teekay (Tangguh)
HMM (Kogas)
MOL
BP
126
May 07-Mar 08
Oct 07-Dec 07
Mar-06
Jun 07-Jan 08
Aug-Sep 08
Mar-06
Oct 07/Jan 08
2008
Mar-08
Sep-06
2008
Hanjin Heavy Industries
2 ships
IsiA vanucean (yemen)
1
Kogas
I
150,00
150,01
Tepco
NYK/Sovcom flot
Hoegh/MOL (Snohvit)
MISC
Oman
3
2
1
5
1
138,000/145,400
147,200
147,208
145,000/157,000
145 500
MUL (I
OKYO uas)
140,UUU
Tokyo Gas
K Line (Snohvit)
K Line (Cheniere)
Lino Kaium
NYK/Osaka Gas
NYK/Osaka Gas (Oman)
Hiroshima Gas
2
Jaoanese Owners
2
Imabari shipbuildir
145,000
140,000
145,000
145,000
145,000/153,000
153,000
19,500
2,500
Nov-U0
2009
Mar 06-Mar 09
Dec 07/Feb 08
Apr-06
Mar 07-Dec 08
Jun-06
uec-uu
Mar-06
Jun-06
Dec-07
Dec-08
Sep 06/Nov 08
Dec-08
Sep-07
4 shiDs
154,200
Nov 07/08
154,200
Nov-09
1
154.200
Nov-10
1
21
145,000
2,500
Dec-06
2
-
1
I
147,200
Mav-08
I
2
1
MOL
Line(Yemen)
K
IMOL
3 nh
C
|Gaz
de France
Gaz de France
Gaz de France
&
Mitsui Engineerng
Shinbuildina
rim orsk (Sakhalin)
127
I
The total number of vessels in order is 136 with the majority of them constructed in
Korean shipyards. Actually, in 2006 over half of the turnover of two of Korea's largest
shipyards, Daewoo shipbuilding & Marine Engineering and Samsung Heavy Industries,
will derive from LNG carriers, which clearly shows the huge influence that the rapid
expansion of the world's LNG fleet has had on the shipbuilding sector.
Daewoo Shipbuilding & Marine Engineering, which was the first shipyard to target
the LNG sector aggressively along with Samsung Heavy Industries have been vying for the
total number of vessels on order over the past year. Japanese shipyards have still a major
role in LNG shipbuilding although to a lesser extent then their Korean competitors. In
2005 STX Shipbuilding in Korea and Japan's Imabari Shipbuilding Co has joined the
previous mentioned shipyards in LNG construction while the Chinese shipyards are
expected to make a massive move behind the new entrant Hudong
Zhonghua
Shipbuilding.(Hine, 2006a) By examining the history of LNG shipbuilding during the last
128
three decades it becomes clear that LNG shipbuilding has gravitated from Europe to Japan
and then to South Korea. Over the next two decades it is expected to see Chinese shipyards
figure more prominently in the LNG shipbuilding sector. The delivery schedule of the
LNG vessels presented in Table 7 is illustrated in Figure 47.
Delivery dates of the LNG vessels of the April 2006 orderbook
8
87
7-
6
.6
6
oz
> 5- -
-
-
5
5
-
-J
0
z
4
3
2
12 22
2
2
2
2
2
2
Delivery Date
U Number
of delivered
LNG vessels
Figure 50 : Delivery dates of the LNG vessels in order until April 2006.
One shipbuilding agreement that should be noted is the one between Qatar's LNG
producers and three largest shipyards in Korea, Hyundai, Samsung and Daewoo. Under
this agreement which was officially concluded in early 2005, around 95 berth slots have
been set aside for the vessels of the Qatargas and RasGas projects. According to the
agreement the berths extend into the third quarter of 2012 in case new LNG production
129
deals are firmed up. (Hine, 2006a) It is estimated that based on the requirements of the
current scheduled LNG projects in Qatar a total of 70 will be required until 2010.
In Table 8 an estimation of the required LNG ships over the next five years is
presented based on the requirements of the planned LNG projects. According to the
estimations of the LNG producers 119 LNG vessels will be required in addition to the
number of the vessels listed in the orderbook. The latter will be the main driving force
behind the expansion of several shipyards into LNG construction the following years.
Table 10 Estimated number of reuired LNG vessels until 2011. Hine, 2006a)
Gassi Touil, Algeria
Skikda replacement, Algeria
Danietta train 2, Egypt
4
4.5
5
3
1
3
Equatorial Guinea train 2
Camisea LNG, Peru
Trinidad train 5
Angola LNG
Gorgon Australia
Pluto, Australia
Pars LNG, Iran
OK LNG trains 1,2, Nigeria
Nigeria LNG train 7
Baltic LNG, Russia
NIOC LNG, Iran
Brass LNG, Nigeria
OK LNG trains 3, 4, Nigeria
Shtokman, Russia
3.8
4
5.2
5
10
7
10
10
4.1
5
8
10
10
15
5
4
3
7
6
6
8
13
8
6
6
10
13
17
119
Total
Closing, an apparent change that is worth noting is the introduction of new types of
organizations becoming involved in owning LNG vessels as it is illustrates in the owners
category of Table 7. While the previous decades LNG vessels were mainly owned or
leased by a joint venture formed between the developer and the production company, this
130
has been changing during the last years. Independent shipowners as well as end LNG
exporters, like Oman, Qatar and NLNG, and importers, like Tokyo Gas and Osaka Gas,
have been ordering new LNG vessels.
FORECAST OF LNG SHORT-TERM TRADE
LNG short-term trade as a percentage of total LNG trade has been increasing steadily
during the last 6 years as it was illustrated in Figure 16 of Chapter 3. The future growth of
LNG short-term trade will be dictated by the interaction of global gas dynamics and local
specifics in the importing and exporting countries. LNG trade flows are expected to bridge
the Pacific and Atlantic basin markets, as presented in Figure 47, and short-term trading
will be one of the main driving forces behind that. At the same time the price arbitrage for
the Asian gas exporters, between Europe and the American East Coast will create a linkage
between these three regions. (Mazighi Hachemi, E. A., 2003)
LNG markets
LNG supply
-
9
LNG flows in 2002
Expected further flows by 2012
Figure 51 : LNG trade flows in 2002 and expected further flows by 2012. (Wit, 2004)
131
Global integration of the LNG industry and trade along with the resulting expansion of
open markets in an international scale will provide the appropriate conditions for the future
growth of short-term trading. However, limitations are posed to the participants in the
industry, as they seek to balance the rewards of a more open and competitive market with
the investment risks inherent in this capital-intensive business. The more enthusiastic
advocates of the fully-competitive market model see the growth of short-term trading in
LNG as the wave of the future, and one that signals the demise of the traditional LNG
long-term trading. Certainly, the surplus of LNG offerings in the past several years has
appeared to create a buyers' market in LNG, and short-term trading is steadily increasing.
This suggests that it might be possible in the relatively near future for buyers to
contemplate the possibility of relying totally on short-term or spot purchases, with reliance
on financial derivatives for risk management, as the free market model would suggest.
There is little evidence, however, that sellers are ready for such a radical change. Both
Mobil in Qatar and Shell in Oman in 1996 supposedly considered the option of justifying
new LNG trains on the basis of large spot volumes, but rejected it as too risky.
Based on the current global energy status no country during the last years has placed
as much as 30% of its exports in any one year in short-term trading, and all expansions,
like the financing of the earlier trains, have been based on underlying long-term contracts.
Since no supplier has yet undertaken to build a new facility on a purely speculative basis
without strong indications that it will have the contracts in hand for much of the volume, it
would seem that the long-term LNG trading pattern holds a predominant position.
132
However, it is clear that companies are willing to take greater speculative risks that
they can convert active negotiations into contracts than they might have done in an earlier
period. The Asia Pacific market has proved to be the most competitive and the initial
decision to move forward on Sakhalin II appears to have been taken with only 58% heads
of agreement coverage, 29% coverage of the two train project, of the first train to Japanese
customers.
In order to estimate the growth trend of the LNG short-term trade a forecast analysis
was performed using a polynomial equation and the Verhulst equation. The results are
illustrated in Figure 48, while the assumptions and the details of the analysis are presented
in Appendix I.
40
-
Forecast analysis of the LNG short-term trade percentage
35
30
0
:29.3%
il421.4%~
M
0
15
C
0T
0
1990
1995
2000
2005
2010
2015
2020
Year
a
* Historic LNG short-term trade percentage
Verhuist equation
-
Polynomial Regression
Figure 52 : Forecast analysis of the LNG short-term trade percentage.
133
2025
The analysis reveals that until 2010 the percentage of short-term LNG trade will be in
the range of 21-29% of the total LNG trade. The forecast using the polynomial equation
predicts a 29.3%, while the Verhulst equation forecasts a percentage equal to 21.4%. Less
optimistic forecasts, like the one made by EIA in 2003, estimate the short-term trading
percentage to reach 15 to 20% of the LNG trade until 2012. (EIA, 2003) At the same time
LNG shipping companies like Excelerate Energy estimate a value of 30% for the year
2010. Heuristically, since the range of our forecast analysis lies between the two
estimations, it can be assumed that the mean value of our forecast, namely 25%, might be a
safe estimation of the future LNG short-term trade percentage for the year 2010.
134
CHAPTER 8 - CONCLUSIONS
Taken under consideration all the information and data presented in this study it
becomes clear that the static and conservative pattern of the traditional LNG trade has
entered a new dynamic era. One of the products of this era has been the emergence of the
short-term LNG trade market as described and analyzed herein.
It can be easily derived is that the LNG trade will increase drastically exceeding a total
trade volume of 220 billion m3 at the end of this decade. North America will emerge as the
largest LNG importer, mainly because of the combination of growing gas demand for
power generation and the deterioration of the traditional North American supplies; namely
the Canadian gas supply because of an increasing Canadian gas demand and a reduction of
gas reserves. Europe will continue to relay on its surplus from the North Sea reserves but
unless Russia's Gamproz materializes its expansion projects, LNG imports are expected to
rise steeply the next years. The emergence of the previous mentioned markets shifts the
balance of the LNG growth to the Atlantic basin with the traditional markets of the Pacific
basin becoming less important than before.
The supply side of LNG is reshaping with the entrance of Middle East and West
Africa countries in the LNG supply group. Qatar has entered aggressively in the LNG
scene with the ambition to become the world's largest LNG supplier. Abu Dhabi and
Oman will play an important role in the future, while the LNG potential of Iran is very
large but its future is unclear at the moment. Nigeria and Algeria are already major players
135
while Egypt is poised to join them. Angola and Equatorial Guinea will be the future
entrants from the African region.
During the last ten years traditional long-term contracts with ToP clauses became
much more flexible and a new short-term market emerged as result of capacity surpluses,
low utilization of the LNG fleet and regulatory reformations. We forecast that the shortterm market will increase steadily the following years and achieve a percentage of 25% of
the total LNG trade at year 2010. However, since the LNG projects are capital intensive
with substantial financial risk, we estimate that new projects will still perceive a percentage
of long-term financial coverage of more than 50%. Also, the potential usage of financial
derivatives, as a tool to hedge financial risk in the multi-billion dollars LNG investments,
appears highly unlikely after the financial bankruptcy of the major energy merchant
traders, like Enron.
The declining costs of the LNG supply chain, along with the growing diversity of the
supply sources and the loosening of the traditional rigid industry structure have created an
interconnected system which can transmit price signals between previously isolated
regional gas markets. After 1999 the signs of an active arbitrage market in the Atlantic
basin are apparent with shipments form Trinidad or Nigeria diverted either to USA or
Spain depending on the local market price. The role of Qatar, along with the other Middle
East countries exporting LNG, as suppliers to both the traditional markets in Northeast
Asia and the emerging markets on the Atlantic basin verifies that price signals are also
transmitted between Asia and the Atlantic basin.
136
Currently the LNG fleet consists of 197 vessels with 136 more scheduled to be
delivered until 2010. The percentage of the orderbook over the existing fleet is quite high
and equal to 69%. If the LNG projects under planning get to be realized, an additional
number of 119 LNG vessels will be required in the following 5 years. Although the size of
the orderbook is quite high, the possibility of a surplus of LNG vessels is quite low since
the percentage of speculative orders is small, in 2004 it was equal to 2%. The vessels are
ordered for specific projects so if gas demand continues as projected, the risk is shifted to
the completion and operation of the liquefaction plant. With projects like the ones of Qatar
which require a fleet of 70 ships, any geopolitical instability would greatly influence the
utilization of the LNG fleet. The trend of ordering LNGRV is expected to increase with
more companies like Hoegh LNG following the steps of Excelerate Energy. Currently,
seven LNGRV are scheduled for delivery until 2010 but the possibility of ship-to-ship
(STS) gas transfers might be a good incentive for more orders of this kind.
The current picture of the LNG market does not lead to the conclusion that it will
achieve the flexibility of the world oil market. The LNG transportation cost prevents the
physical movement of the commodity over long distances in the way that oil is transported.
However, we can conclude closing this study, that if the size of the short-term LNG trade
continues to grow within the limits of our forecast and more volumes are traded under
short-term contracts, then the resulting shifts in LNG sources and destinations will
reinforce the international price arbitration and will influence greatly the relationships
between supply, demand and LNG price in the gas market regions.
137
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143
APPENDIX I
The forecast analysis for the percentage of short-term LNG trade was based on the
available historic data from 1993 to 2004 and on the usage of two forecast equations. The
first one is a polynomial equation calculated by the trendline analysis of Excel software,
presented in Equation (1), where x is the number of years with 1993 being year 1.
P = 0.1417x 2 -1.1115x+3.3949
with R 2=0.944
(1)
For the second equation we choose the Verhulst equation presented in Equation (2).
P=
KPoe"l
K(2)
K+PO (er t -1)
where K is the maximum percentage that the short-term trade can achieve, Po is the initial
percentage and r is the growth rate. The selection of the Verhulst equation was based on
the assumption that the short-term trade is part of dynamic system enhanced in the LNG
trade with several factors forming reinforcing and balancing loops affecting the maximum
percentage that short-term LNG trade can achieve. We assumed that the growth trend will
follow an S-curve with z\a steep increase in the growth rate during the first period and then
a gradually softening until a maximum percentage is achieved.
For the value of Po we selected the value of the short-term trade percentage for 1993,
while for the growth rate r the average growth rate from 1993 to 2004 was calculated and
used. The initial value of K was set to 10% and an optimization procedure commenced by
144
of the
using the Solver module of Excel program. The goal was to minimize the value
mean square error MSE for the values from 1993 to 2004 by changing the values of K and
r. The values of K and r which were in a logical range and minimized MSE, were finally
chosen for the forecast. The data of the analysis are presented in Table 9.
1993
1 66
1994
1.78
1I
0.933
0.072
2
0.466
3
1.336
1.476
1.134
-0.281
-0.635
-2.136
-1.277
-1.821
0.432
-0.297
0.977
0.577
1.175
2.61
1996
1.57
-0.398
4
1.216
1.851
1997
1 68
0 070
5
1998
1999
2000
2001
2002
2003
2004
0.75
2.30
2.60
5.85
6.31
8.95
10.11
-0.996
2.075
0.128
1.254
0.077
0.419
0.130
Average
Rate=0.299
6
7
8
9
10
11
12
1.380
1.827
2.558
3.572
4.869
6.450
8.314
10.462
2.315
2.885
3.579
4.418
5.421
6.602
7.973
9.533
13
14
15
12.893
15.607
18.605
11.274
16
17
21.886
25.451
17.267
19.361
18
29.299
21.410
2006
2007
2008
2009
2010
,
,
1995
2005
15.184
19
33.430
23.359
37.845
42.543
25.165
26.800
22
23
24
47.525
52.790
58.338
28.247
29.504
30.576
2017
25
64.170
31.479
2018
2019
2020
26
27
28
70.285
76.684
83.366
32.230
32.847
33.351
2013
2014
2015
2016
R
II.9~4
145
4.562
1.631
3.317
0.187
0.088
0.954
0.332
1.534
13.170
20
21
2011
2012
0.727
0.605
2.425
1.739
0.3538
0.0074
0.2374
It should be noted that for the calculation of MSE the values of the years 1995 and
1998 was discarded because it was considered that they would bias the final result.
146
APPENDIX 11
The annual profit calculations presented in Chapter 6 was based on Equation (3) which
calculates the revenue from the specific number of trips and subtracts the annual operating
and capital expenses, and the voyages expense for the steaming period of the vessel.
P = RT(Rate x ECC) - RT x TD x (OPEX + CAPEX + VC) -(365 - TD) x (OPEX + CAPEX)
(3)
" RT=Number of return trips
" Rate= The rate in $/MBtu
*
ECC=Energy carrying capacity which is equal to
150,000(m3 )*600*35.5(ft 3/m3 )* 1,000(Btu/ft 3)/1,000,000=3,177,000 MBtu
*
TD=The duration of the round trip in days
" OPEX=Operating expenses per day in $/day
*
CAPEX=Capital expenses per day deriving from the amortized payment of the loan per
day in $/day
*
VC=Voyage cost per day of steaming in $/day
The annual profits were calculated for a range of the rates from 0 to 2 $/MBtu with a
step of 0.05 $/MBtu, for all the possible number of return trips per year. The results are
presented in the following tables.
147
Table 12 ! Animl nrnfit re'ninlte fhr thi rmiiti ThI
0.65
416,451
5
0.7
0.75
-$18,292
3
0.8
415,974
-$15,818
415,857
415,498
415,339
415,180
415,021
2
414,863
3
1
3
-$8,534
-8,057
47,581
44,099
5
47,104
86,628
46,151
45,875
-$3,463
-2,828
42,193
-$1,557
$922
-$286
$349
$984
$1,620
$2,255
$2,891
$3,528
$4,161
$4,797
$5,432
1
1.05
1.1
1.15
1.2
1.25
1.3
1.35
1.4
1.45
1.5
1.55
1.6
1.65
1.7
1.75
1.8
1.85
1.9
1.95
2
-$14,704
-$14,545
-$14,386
414,227
414,068
-$13,909
-$13,751
-$13,592
-$13,433
$13274
-$13,115
-$12,956
412,797
412639
-$12,480
412,321
412,162
I
I
t
5
-
0.9
0.95
416,133
-
0.85
417,086
)
49,487
49,010
45,198
-4,722
44245
43,768
3,292
-$2,815
42,339
-$1,862
41,386
-$909
-$433
44,734
-4
-4
-4
4
4
-4
B
.
3
1
I
5
3
D
7
4
148
a
422,430
421,000
419,571
418,141
416,711
415,282
413,852
411,774
410,993
-$9,563
47,962
48,559
-$7,765
-,971
46,177
-$5,382
-$4,588
-$3,794
-$3,000
42,205.
41,411
4N17
$177
$972
$1,766
$2,560
$3,354
$4,149
$4,943
$5,737
$6,531
$7,326
$8,120
$8,914
$9,708
$10,503
$11,297
0
421,941
420,670
419,399
418,128
416,88
415,587
414,318
413,045
410,504
49,233
-
416,928
418,789
-$18,610
I
2
-
417,404
417,245
-4
-4
$
0.35
0.4
0.45
0.5
0.55
0.6
-417,112
416,635
418,159
415,682
415,208
414,729
414,253
-$13,776
-$13,299
-$12,823
-412,346
411,870
411,393
-410,917
-410,440
49,964
$
417,563
418,078
417,442
418,807
416,171
415,536
-14,901
414,265
413,830
-$12,994
-$12,359
411,724
-$11,088
410,453
49,817
49,182
48,547
47,911
-$7,278
4",640
46,005
-$5,370
$
0.3
417,588
$
0.2
0.25
2
5
-4
-1
1
-4
-4
$
418,713
418,198
418,040
417,881
417,722
0.15
-$20,473
419,879
418,885
418,090
-$17,296
416,502
415,708
414,913
-14,119
413,325
-$12,531
411,736
410,942
410,148
49,354
$
-$19,984
-$19,348
-
418,357
-$19,495
419,018
418,541
418,085
$
5
-
0.1
181
$
0
0.05
$4,123
$5,235
$6,347
$7,459
$8,571
$9,683
$10,795
$11,907
$13,019
$14,131
$15,243
$16,355
$17,467
$18,579
$19,691
$20,803
$21,914
$23,026
-46,891
-$5,420
44,150
-$2,879
41,608
-$337
$934
$2,204
$3,475
$4,746
$6,017
$7,288
$8,558
$9,829
$11,100
$12,371
$13,642
$14,912
$16,183
$17,454
$18,725
$19,996
$21,266
$22,537
$23,808
$25,079
$26,350
$27,620
$28,891
412,423
48,134
-$6,704
45,274
43,845
42,415
-985
$444
$1,874
$3,304
$4,733
$6,163
$7,593
$9,022
$10,452
$11,882
$13,311
$14,741
$16,170
$17,600
$19,030
$20,459
$21,889
$23,319
$24,748
$26,178
$27,608
$29,037
$30,467
$31,897
$33,328
$34,756
9
;1
-2
4
S
7
a
0
1
F-
423,409
421,6861
-$19,914
418,167
-$18,419
414,672
412,924
-$11,177
-$9,430
47,682
I
-$5,935
3
44,188
-42,440
-4893
$1,05
$7,262
$8,851
$10,439
$12,028
$13,816
$15,205
$18,793
$18,382
$19,970
$21,559
$23,147
$24,738
$26,324
$27,913
$29,501
$31,090
$32,678
$34,267
$35,855
$37,444
$39,032
$40,621
$2,802
$4,549
$6,296
$8,044
$9,791
$11,538
$13,286
$15,033
$16,780
$18,528
$20,275
$22,023
$23,770
$25,517
$27,265
$29,012
$30,759
$32,507
$34,254
$36,001
$37,749
$39,496
$41,243
$42,991
$44,738
$46,485
Tah'- 13 ! Annimal nrnfit r
$19,623
419,305
418,987
418,670
-$18,352
-$18,034
-$17,717
-$17,399
0.1
0.15
0.2
0.4
-$17,554
-$17,081
0.45
0.5
0.55
-$17,395
417,236
0.6
-$16,919
0.65
0.7
0.75
416,760
-$16,764
416,446
416,128
415,810
-$15,493
0.8
0.85
0.9
0.95
1
1.05
1.1
1.15
1.2
1.25
1.3
1.35
1.4
1.45
1.5
1.55
1.6
417,077
416,601
416,442
-$16,283
416,124
-$15,175
4$15,966
4$13,904
414,857
-$14,540
-$14,222
-$15,807
-$13,587
-$15,648
4$15,489
-$13,269
-$15,330
415,171
415,012
-$14,854
-$14,695
414,536
-$14,377
-$14,218
414,059
-$13,900
-$13,742
1.65
-$13,583
1.7
1.75
1.8
1.85
1.9
1.95
2
-$13,424
-$13,265
-$13,106
412,947
-$12,789
-$12,630
-$12,471
-$12,951
412,633
-$12,316
411,998
-$11,680
-$11,363
-$11,045
-$10,727
410,410
-$10,092
-9,774
-$9,456
-$9,139
-$8,821
-$8,503
-$8,186
47,868
-$7,550
-$7,233
-$6,915
1
4
41
8
41
1
4$ 5
41
8
-$1
2
-$1
5
-$1
8
41
2
41
5
41 , I 9
-$1
2
-$l
6
9
3
41
41
6
-$1
9
3
41
-1
8
-$
0
-$i
3
41
$
0.25
0.3
0.35
-$18,666
418,507
-$18,348
$18,189
418,031
417,872
417,713
-$
-$
-$
"$
.$
$
418,825
-4
$
0
0.05
-$
-$
S
)
t
1
-$4,698
1
r
-$4,063
-$3,428
-$2,792
-$2,157
-$1,521
-$886
-$251
$385
$1,020
$1,656
$2,291
$2,926
$3,562
$4,197
I
t
3
-$ ,,, I
-$
5
-$
-$
-$
-$
-$
-$
-$
-$21,219
-$20,583
-$19,948
-$19,313
-$18,677
-$18,042
-$17,406
-$16,771
-$16,136
-$15,500
-$14,865
-$14,229
-$13,594
-$12,959
-$12,323
-$11,688
-$11,052
-$10,417
-$9,782
-$9,146
-$8,511
-$7,875
-$7,240
-$6,605
-$5,969
-$5,334
5
5
1
rM I
-$22,017
-$21,223
-$20,428
-$19,634
-$18,840
418,046
-$17,251
-$16,457
-$15,663
-$14,869
-$14,074
-$13,280
-$12,486
411,692
-$10,897
-$10,103
-$9,309
-$8,515
-$7,720
-$6,926
-$6,132
-$5,338
-$4,540
-$3,749
-$2,956
-$2,161
-$1,366
-$572
$222
$1,016
$1,811
$2,605
$3,399
$4,193
$4,988
$5,782
$6,576
$7,370
$8,165
$8,959
$9,753
149
-$22,815
-$21,862
-$20,909
-$19,956
-$19,002
418,049
417,096
-$16,143
415,190
-$14,237
-$13,284
-$12,331
-$11,378
-$10,425
-$9,471
-$8,518
-$7,565
-$6,612
-$5,659
-$4,706
-$3,753
-$2,800
-$1,847
-$4
$604
$1,013
$1,966
$2,919
$3,872
$4,825
$5,778
$6,731
$7,684
$8,637
$9,591
$10,544
$11,497
$12,450
$13,403
$14,356
$15,309
1
-$23,613
-$22,501
-$21,389
-$20,277
-$19,165
-$18,053
-$16,941
-$15,829
-$14,717
-$13,605
-$12,493
-$11,381
-$10,269
-$9,157
-$8,046
-$6,934
45,822
-$4,710
-$3,598
-$2,486
-$1,374
-$262
$850
$1,962
$3,074
$4,186
$5,298
$6,410
$7,522
$8,634
$9,746
$10,858
$11,970
$13,082
$14,193
$15,305
$16,417
$17,529
$18,641
$19,753
$20,865
-$24,411
-$23,140
-$21,869
-$20,598
-$19,328
418,057
-$16,786
-$15,515
-$14,244
-$12,974
-$11,703
-$10,432
-$9,161
-$7,890
-$6,620
-$5,349
-$4,078
-$2,807
-$1,536
-$24,650
-$23,332
-$22,013
-$20,695
-$19,376
-$18,058
-$16,739
-$15,421
-$14,103
-$12,784
411,466
-$10,147
-$8,829
-$7,510
-$6,192
-$4,873
-$3,555
-$2,236
-$918
-$266
$400
$1,005
$2,276
$3,547
$4,818
$6,088
$7,359
$8,630
$9,901
$11,172
$12,442
$13,713
$14,984
$16,255
$17,526
$18,796
$20,067
$21,338
$22,609
$23,880
$25,150
$26,421
$1,719
$3,037
$4,356
$5,674
$6,993
$8,311
$9,630
$10,948
$12,267
$13,585
$14,903
$16,222
$17,540
$18,859
$20,177
$21,496
$22,814
$24,133
$25,451
$26,770
$28,088
Table 14 : Annual profit results for the route Dohra to Japan
-
I
I
I
-
I
I
I
S
-$15,307
-$15,148
414,989
-$14,830
-$14,671
-$14,513
-
-$15,466
-
$15,625
I
-$12,86
-$12,23C
4$11,5911
-
_
4$14,13E
4$13,501
-$10,951
-$10,3249
-$9,689
4$9,053
-$8,418
4$7,782
-$7,147
-$6,512
-$5,876
-$5,241
-$4,605
-$3,970
1.35
-$14,54
4$3,335
1.4
1.45
1.5
1.55
1.6
1.65
1.7
1.75
1.8
1.85
1.9
1.95
2
-$14,195
-$14,036
-$13,877
-$13,718
-$13,560
-$13,401
-$13,242
-$13,083
-$12,924
-$12,765
412,606
-$12,448
-$12,289
-$2,699
-$2,064
-$1,428
-$793
-$158
$478
$1,113
$1,749
$2,384
$3,019
$3,655
$4,290
$4,926
I
-|
,575
1,781
987
193
398
604
810
016
221
427
633
839
044
4
-$
4
4
4
44,985
4$3,555
4
-1
I
-1
4
-1
$2,164
Ii
.1~
4
6
250
156
38
133
927
721
515
$4,310
$5,104
$5,898
$6,692
$7,487
$8,281
$9,075
$9,869
$10,664
150
42,125
-$696
$734
,058
4 ,011
4 ,964
4 ,918
4 ,871
4 .824
$8,777
$9,730
$10,683
$11,636
$12,589
$13,542
$14,495
$15,449
$16,402
$1,013
$2,125
.$3,237
$4,349
$6,461
$6,572
$7,684
$8,796
$9,908
$11,020
$12,132
$13,244
$14,356
$15,468
$16,580
$17,692
$18,804
$19,916
$21,028
$22,140
$3,733
$5,003
$6,274
$7,545
$8,816
$10,087
$11,357
$12,828
$13,899
$15,170
$16,441
$17,711
$18,982
$20,253
$21,524
$22,795
$24,065
$25,336
$26,607
$27,878
$3,593
$5,023
$6,453
$7,882
$9,312
$10,742
$12,171
$13,601
$15,030
$16,460
$17,890
$19,319
$20,749
$22,179
$23,608
$25,038
$26,468
$27,897
$29,327
$30,757
$32,186
$33,616
.
4
4
4
$
-4
-4
-4
-4
-4
-I
-4
-4
-4
-$23,570
-$22,140
-$20,711
I
-$19,281
S$17,851
-$16,422
I
-$14,992
I
-$13,5683
S
I
-$12,133
-$10,703
-$9,274
S
-$7,844
-$6,414
4
-
I
I
I
1
-$
-
-
-$15,407
-$14,7729
-
418,04
-
-
-$17,31 :
-$18,878
,106
,312
,518
,724
,929
.135
,341
,547
.,752
.958
,164
:,370
$
-
I
-
416,419
416,260
418,101
_$15,942_
415,783
I
-
-$18325
-$18,166
-$18,007 _
-$17,848
-$17,890
-$17,531
417,372
-$17,213
-$17,054
-$16,895
-$16,737
$18,578
-
0.9
0.95
1
1.05
1.1
1.15
1.2
1.25
1.3
418,484
-
-I
S-4
-4
S-4
-4
I
0.05
0.1
0.15
.2
0.25
0.3
0.35
0.4
0.45
0.5
0.55
0.6
0.65
0.7
0.75
0.8
0.85
-$9,889
48,301
-$6,712
-$5,124
-$3,535
-$1,947
-$358 7
1,230
$2,819
$4,407
$5,996
$7,584
$9,173
$10,761
$12,350
$13,938
$15,527
$17,115
$18,704
$20,292
$21,881
$23,469
$25,058
$26,648
$28,235
$29,823
$31,412
$33,000
$34,589
$36,177
$37,766
$39,354
-$9,239
-$7,523
-$5,807
44,092
-$2,376
-$881
$1,055
$2,771
$4,486
$6,202
$7,917
$9,633
$11,348
$13,064
$14,780
$16,495
$18,211
$19,926
$21,642
$23,358
$25,073
$26,789
$28,504
$30,220
$31,935
$33,651
$35,367
$37,082
$38,798
$40,513
$42,229
$43,944