Essentials of LNG Trading and Risk Management Report

Commodity Markets Intelligence Series
Essentials of LNG Trading and Risk Management
September, 2012 Sponsored by:

About Maycroft and the Author
Maycroft is a boutique consulting firm that provides strategic advice about
(energy) commodity trading and risk management. Among Maycroft’s wide client
base are government agencies such as the European Commission, investment
banks, major utilities and commodity trading companies and various exchanges
in Europe, CEE countries, North America and Asia.
Kasper Walet has more than 25 years of experience in the commodity trading
and risk management industry. With his company Maycroft he has advised
energy companies, banks, trading houses, exchanges and
clearing houses and large industrial companies from all over the world. For
writing this report I have tapped on my experiences of the many years that I
have walked around in the energy commodity industry and my expert
knowledge that I have gathered by doing LNG Trading training courses in
Europe and Asia as well as conducting projects for (LNG) energy companies
and banks.
LNG Training Courses
If you are interested to learn more about the opportunities to organize an (in-
house) workshop about LNG Markets, Trading and Risk Management you could
either:
 Visit our website; www.maycroft.com
 Or Contact us at:
Email: walet@maycroft.com
Tel: + 31 (20) 5160618
Mob: +31 653818191

About the sponsor:
www.lngjournal.com

Introduction
As there is so much dynamics in the global market place, the short-term LNG
market and trading are developing very fast. How to keep up with these
developments, this report will support you with that.
The main drivers of the LNG markets supply and demand are relatively easy
to predict for the short and midterm. How is it then possible that the LNG
market has changed so dramatically over the past few years? Who could
have forecasted the impact of the shale gas revolution due to new technology
to extract gas from shale economically? Who could have forecasted that as a
result of the Fukushima earthquake not only Japan would have to change its
energy mix and rely more on more on LNG imports, but also that Germany
would phase out its nuclear plants? These changes have had an impact on
supply and demand, and have affected gas pricing differently in various parts
of the world.
There are so many issues that could influence the way the LNG trading
markets will develop. It is therefore crucial for you and your company to
understand the current and future drivers of the trading markets.
In this report we will give you an overview of the essential drivers of the
trading markets and you will get close being a real LNG trader. We will
discuss all the relevant information, market outlook, expectations, forecasts,
available derivative instruments etc. that a trader will use to determine his or
her strategy.
We will answer questions like how does the future of LNG trading looks like
until the end of this decade? What will be the main drivers and possible game
changers to look out for ? What will be the impact of new LNG output from
Australia and the US coming on stream in the years to come? Will there be
enough shipping capacity available or is that going to become the main
constraint? What will happen to demand in Asia, will it really surge as
predicted? What will be the impact of the demand for LNG in the Middle East
for the European players?
All that uncertainty would also increase the need for risk management
and hedging instruments like JKM Swaps. By using practical examples we will
discuss the strategies that you could apply.
This is a highly practical and essential report for everyone who would like to
understand what is driving the LNG trading markets.
Enjoy your reading
Kasper Walet

Table of Contents
1. OVERVIEW OF LNG MARKETS ...................................................1
1.1 The LNG Market from regional to global....................................................1
1.2 Australian liquefaction capacity ................................................................2
1.3 US exports ................................................................................................2
1.4 Fukushima fallout .....................................................................................2
1.5 Chinese LNG demand ................................................................................2
1.6 Global growth ...........................................................................................3
1.7 Impact Unconventional Gas on the LNG Industry.....................................3
1.8 Impact US shale gas revolution on LNG trade flows and prices................4
1.9 Growth in unconventional gas production outside North America............9
1.10 Future Global Outlook .............................................................................10
2 SUPPLY AND DEMAND ............................................................12
2.1 Supply Fundamentals ..............................................................................12
2.2 Demand Fundamentals ...........................................................................14
2.3 Impact new LNG importers on the global market....................................16
2.4 Implications of significant growth in regasification capacity .................17
3 MAIN PRODUCERS LNG; CURRENT STATUS AND FUTURE
DEVELOPMENTS...........................................................................18
3.1 The influence of new supply....................................................................18
3.2 Qatar and other Middle Eastern Producing countries ..............................19
3.3 Australia .................................................................................................21
3.4 North America.........................................................................................23
3.4.1 Canada.................................................................................................. 23
3.5 Russia .....................................................................................................24
3.6 Indonesia and Malaysia...........................................................................25

4 MAIN BUYERS AND THEIR SEARCH FOR SUPPLIERS...............26
4.1 Japan ......................................................................................................26
4.2 China.......................................................................................................28
4.3 Korea ......................................................................................................30
4.4 India .......................................................................................................31
4.5 Malaysia and Indonesia...........................................................................32
5 LNG CONTRACTING STRUCTURES AND PRICING MECHANISMS
33
5.1 Introduction............................................................................................33
5.2 The Standard Contract ............................................................................33
5.3 MSAs for spot cargoes.............................................................................34
6 LNG TRADING AND TRADING MARKETS..................................37
6.1 Introduction............................................................................................37
6. 2 Main Players ...........................................................................................38
6.2.1 Portfolio players...................................................................................... 38
6.2.2 Japanese players .................................................................................... 38
6. 3 Long term vs. Short term LNG Markets ...................................................39
6. 4 Factors driving the LNG spot cargo trade ................................................40
6.5 Trends and challenges ............................................................................40
6.6 Singapore might become the LNG Trading Hub for Asia ..........................41
6.7 Overview of current Asian Spot Market...................................................42
6.7 Role Japan ..............................................................................................45
6.8 Arbitrage; Flexibility in contracts ...........................................................45
6.7 Recent Developments .............................................................................46
6.8 Arbitrage opportunities...........................................................................46
6.9 LNG Risk Management ............................................................................47
6.9.1 Risks in LNG Markets............................................................................... 47
6.9.2 Geo Political Risk Management ................................................................. 48
6.9.3 Dealing with Market Risk; Hedging Instruments .......................................... 50

6.9.4 Case Study: BG's LNG hedging policy.................................................... 51
7 SHIPPING AND LNG TRADE FLOWS ........................................53
7.1 Introduction ...............................................................................................53
7.2 Charter Types..........................................................................................53

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1. Overview of LNG Markets
1.1 The LNG Market from regional to global
The global LNG market is still in a stage of relative infancy. Only a small portion
of global gas consumption is currently satisfied by LNG (around 9%). Only a
portion of those LNG cargoes have the contractual flexibility for diversion in
response to price dynamics, although these flexible cargoes can have a
disproportionate influence on global gas prices given their influence on marginal
pricing. This lack of global LNG cargo flexibility is currently reflected in the
regional price divergence across Asia (tight market post Fukushima), Europe
(broadly tracking oil-indexed contract supply) and the US (flooded with domestic
shale gas).
Figure 1: A geographical summary of the global gas market
The end result of this period of rapid evolution in the LNG market should be price
convergence across regional hubs towards transport differentials. New LNG
infrastructure will drive an increasingly dynamic market in traded cargoes and a
strengthening of global gas price influence on regional markets. But there is
considerable uncertainty around the path of evolution that the LNG market will
follow over the next decade.

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The possible main drivers for the global trend are described in the following
paragraphs:
1.2 Australian liquefaction capacity
Around 70% of liquefaction capacity currently under development is located in
Australia. If this capacity is brought to market as planned then Australia is set
to overtake Qatar as the world’s largest exporter of LNG by the end of this
decade. Australia has an abundance of gas resource, but its weakness is high
project costs. Gas is relatively expensive to produce and transport to the
liquefaction terminal, not helped by high labour costs and unprecedented
strength of the Australian dollar. Australia projects are currently satisfying
incremental demand growth from a gas hungry Asia. But there are two key
threats to project development: exports of cheaper gas from the US and a
slowdown in Asian demand growth.
1.3 US exports
The US is currently awash with relatively low cost gas, however, uncertainty
remains as to whether the government will approve large volumes of US exports
and the sustainability of the US shale gas revolution. The extent to which
exporters are granted approval and whether the industry can overcome shale
gas environmental concerns and grow or even maintain production levels will be
key factors influencing re-convergence of global prices.
1.4 Fukushima fallout
Most of Japan’s 50 nuclear reactors that were closed after the Fukushima
disaster are currently not in operation. Given Japan is the world’s largest LNG
importer, nuclear closures have been a huge factor driving tightness in the Asian
market. While the increase in Japanese demand has been dramatic, it is a one-
off factor whose impact will diminish over time. The Japanese economy, already
suffering from decades of stagnation, is being crippled by the strength of the yen
and the cost of imported energy. The pace of return of the reactors, a subject of
intense political debate in Japan, will be a key driver of Asian demand over the
next few years.
1.5 Chinese LNG demand
If the penetration of gas increased by just 1% in China’s primary energy
consumption (from 4 to 5%) it would mean an increase of approximately
27bcma of gas demand. If that volume were to be met by LNG alone, it would
mean an increase in imports of 20MT per year. However while the headline
numbers are startling, there is considerable uncertainty over the rate of China’s
policy driven switching from coal to gas fired generation, particularly as the
economy slows.

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There are also a range of alternative sources of gas to satisfy Chinese demand,
specifically pipeline imports from neighbouring countries (Turkmenistan,
Kazakhstan, Burma and Russia) and domestic shale gas resource.
1.6 Global growth
Another global recession looks increasingly likely as a result of a slowdown in the
rate of Asian growth and political deadlock over European debt crisis resolution.
While this is a key source of uncertainty impacting all energy markets, the LNG
market is particularly exposed. A sharp fall in Asian growth would have a
disproportionate impact on global LNG demand given that Asia is the key driver
of incremental demand growth. At the same time LNG supply development is
vulnerable to tightening capital constraints from a deterioration of the financial
crisis, given that liquefaction projects are very capital intensive.
1.7 Impact Unconventional Gas on the LNG Industry
The rapid transformation of the US gas market following the shale gas boom has
already had an impact on the global LNG industry, but this impact could grow if
the US exports shale gas as LNG or if unconventional gas can have the same
transformative impact on other markets.
The shale gas boom in the US and its dampening impact on the country’s LNG
demand has amplified the supply and demand balance in the market in recent
years. Yet the absence of the US as a significant LNG importer merely pushes
back the time at which the LNG market tightens by a couple of years. The
bigger question is whether other countries will be able to replicate the success of
the US?
The growth in the US gas production has been driven chiefly by the ability to
produce unconventional resources at ever cheaper rates. Unconventional gas
includes shale, coal bed methane and tight gas which are all characterised by
low natural permeability in the reservoir (commercial gas volumes do not “flow”
naturally). Using horizontal drilling and hydraulic fracturing, combined with
tighter well spacing and a higher rate of drilling versus conventional gas fields,
companies have been able to create sufficient permeability to extract ever
increasing commercial volumes from these reservoirs.

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Figure2: US Situation
US Natural Gas Production Share of Shale Gas in US Production
This growth in shale gas production has emerged as a shock to the LNG system
for two reasons: first, it has made clear that the US will not import significant
volumes of LNG over the next decade (at least), and furthermore has already
altered the dynamics of both the Canadian and Mexican gas markets as well;
and second, there is growing uncertainty over whether other countries will be
able to replicate the experience of the US and hence, reduce their own needs for
imports. Together, these two prospects could reshape the LNG industry.
1.8 Impact US shale gas revolution on LNG trade flows and
prices
Perhaps the most important global implication of this “shale gas revolution” is
that the US no longer needs as much LNG as previously forecasted. One useful
way to think about the importance of US LNG is to re-examine the forecasts
done by the Energy Information Administration (EIA) at the US Department of
Energy. In its 2005 Annual Energy Outlook (AEO 2005), the EIA was forecasting
that US would need to import as much as 70 bcm in 2010 to meet demand and
offset the drop in indigenous production. Given actual LNG production in 2010,
this would have amounted to a global market share of 23%, making the US the
world’s second largest LNG market after Japan. To meet this projected rise in
imports, there was a boom in US regasification capacity, which increased
sevenfold between 2002 and 2011.
As the production growth story proved to be sustainable, those expectations
shifted: by 2008, the EIA thought that by 2010, the US would only need 34
bcm. However, even those numbers turned out to optimistic. In 2011 the EIA
significantly downgraded its LNG import expectations, and in 2012 it has gone
even further, projecting that the US will become a net LNG exporter by 2016,
after start up of Cheniere Energy’s Sabine Pass liquefaction project, the first
train of which is announced to come on-stream in 2015.

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In addition to Sabine Pass, there are now eight other proposed liquefaction
projects in the continental (excluding Alaska). However, Sabine Pass is the only
one to have secured contracts for any of its proposed capacity. Three other
projects have announced start-up dates: Cove Point LNG in 2016, Freeport LNG
in 2016, and Corpus Christi LNG in 2017.
Figure 3: Status LNG Exporting Terminals US
There is little prospect of all these projects going ahead and as such there will be
significant first mover advantage. The challenge for the developers will be to
successfully navigate their way through the complex approval and permitting
processes. There are effectively three elements:
 Federal Energy Regulatory Commission (FERC) has authority under the
Natural Gas Act to approve the location of and health and safety related
aspects of LNG facilities
 Department of Energy (DOE) grants approval to export natural gas to
both free trade and non-free trade countries. The DoE assessment is
based on a broad assessment of the economic impact of the proposal
 There are also a series of approvals required at a state level which
effectively allow a state veto over proposals
After each approval is granted, opposition groups have various avenues open to
them to get the project delayed or even cancelled. To date the DOE has only
granted one approval (2.2 bcf from Cheniere Energy’s Sabine Pass facility) to
export LNG to countries with which the US has a Free Trade Agreements (FTA) in
place. Very few LNG importing countries currently have a FTA in place with the
US which provides a key sticking point for the prospects for LNG exports.
If the DoE insists on restricting exports to FTA countries, the status of the
various FTA negotiations could exert a significant influence over the global gas
market. The UK and Germany have recently made comments supporting a
proposed FTA between the European Union and the US. This could have the
effect of creating a partial fragmentation of the global gas market with the US
supplying significant volumes to Europe whilst other LNG producing countries
focus their efforts on selling into the Asian market. The approval process for
Canadian projects is likely to be less onerous as they are less likely to meet such
vocal opposition to those in the US.

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Opposition to the export projects is centred around the prospect of the US losing
its natural gas self sufficiency and the associated risk and cost to the wider
economy. This will manifest itself through the change to domestic gas pricing
dynamics. US gas prices have been relatively low and stable since the US
stopped importing significant volumes of LNG. The logical outcome of any
significant volume of LNG exports is price convergence, less processing and
transportation costs, with destination markets. Under this scenario, US gas
prices will rise and potentially become more volatile as the domestic market is
directly influenced by global events (e.g. via the changing economics of LNG
flows in response to changes across the Asian, European and American LNG
markets). In fact, the EIA recently suggested that LNG exports may increase
domestic gas bills by up to 9% by 2035. One of the key challenges for
opponents in the US is that project developers can point to the fact that DoE
currently allows gas to be exported to Canada and Mexico where it could be
liquefied and exported, thereby neatly side stepping the need for approval in the
US.
Figure 4: US LNG Situation
Forecasts EIA US LNG Imports US Regasification capacity vs.
Imports
This means that not only a significant source of demand for global LNG supplies
has disappeared, but in fact the US is likely to add to global LNG supply by the
middle of the current decade. This will have a significant impact on LNG
markets over the next decade, but it has already transformed regional dynamics
in North America. In particular, US net imports from Canada have declined
steadily since 2007, while net exports to Mexico have grown. Lower demand for
Canadian gas in the US has coincided with declining Canadian conventional gas
production, but an important implication of lower demand for Canadian gas in
the US is that new shale gas being developed in western Canada is now more
likely to be exported as LNG. There are several projects proposed, and these
are likely to add to LNG supply in the Pacific Basin over the next decade,
including Kitimat LNG, BC LNG, LNG Canada and the PETRONAS/Progress LNG
project in Canada’s Pacific Northwest. In Mexico, greater availability of pipeline
gas from the US has already led to lower LNG imports in 2011, and this trend is
likely to continue.

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Given that LNG investments have a long-lead time, there has been a significant
amount of LNG capacity that has come on-stream between 2009 and 2012 that
was constructed based on the market expectations of 2005, whereby the US
would become a major import market. This LNG had to find a new place to go –
and in 2010 , it found a home mostly in Europe as well as in emerging markets
(Middle East and Latin America). In 2011, following the Fukushima disaster,
Japan absorbed most of the incremental LNG as its nuclear reactors were taken
offline. Thus, while the lack of more imports needed from the US produced a glut
in gas supplies, new supply has been effectively absorbed by the market,
minimising any downward pressure on prices outside of North America.
Specifically, this has two implications for gas pricing:
First, the US market has become effectively disconnected from the broader
global market, and remained so even as prices elsewhere moved towards
convergence in 2011. While Henry Hub has never correlated perfectly with prices
in either Europe or Asia, the disparity between Henry Hub and prices elsewhere
has been magnified since 2008. In 2011, US gas prices were more than 68%
lower than prices in Japan, while they also traded at a growing discount to UK
gas prices (-33% in 2010,and -55% in 2011). As a result of this disparity,
several companies that own regasification terminals which are idle have
proposed to start exporting LNG from North America.
Figure 5: Global Gas Prices
Gas Prices in Selected Markets European Prices; oil linked vs. spot
Second, increased supply into Europe put temporary pressure on the linkage
between oil-linked and spot prices there. In 2009, the average oil-linked
contract price exceeded the spot price at NBP by about $3.5/mmBtu. However,
by the end of 2010 the gap had disappeared as buyers were in some cases able
to renegotiate terms with sellers. Buyers succeeded in linking some of the
volumes they purchase to spot prices rather than oil; they also achieved a
relaxation of take-or-pay (TOP) provisions. In 2011, however, this trend proved
temporary: NBP fell slightly as the UK absorbed a greatly increased volume of
LNG from Qatar, while rising oil prices pulled oil linked prices higher.

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Figure 6: Spot vs. Long Term Prices
Thinking about the importance of US shale gas from a more structural
perspective, there are three questions to consider:
1. Is the US shale gas revolution sustainable, and at what price is shale gas
viable? And what risks are associated with its production? In 2011, the
answers to these questions became somewhat clearer. First, the shale gas
revolution is looking increasingly robust, as persistent low prices, and a
massive shift in drilling to target oil rather than gas has yet to slow rising
gas production in the US. While there are cyclical factors contributing to
this, such as portfolio high grading (companies drilling only on their best
acreage), and JVs in which the operator’s drilling costs are carried by its
partners for a set time period, it nonetheless appears that structural
trends support sustainability. That is, the cost of producing shale gas has
been driven down to a level at which production can be sustained long
term even in a relatively low price environment, though eventually growth
is likely to slow or even temporarily reverse as the cyclical trends cited
above play out. And though restrictions on hydraulic fracturing due to its
perceived or real environmental impacts could have a material impact on
production potential in some areas, the actual impact remains highly
uncertain. Current policy trends mostly support continued expansion of
drilling, but this could change over time if environmental impacts prove
significant.
2. Has the absence of US LNG import demand produced a short or long-term
glut in supplies. From a global perspective, the glut seen in 2009-2010
has proven short-lived, though much of that has been driven by increased
Japanese demand post-Fukushima, and this could change depending on
the evolution of nuclear power policy there. In the near-term, very little
incremental LNG capacity is set to come on-stream, meaning markets are
likely to remain tight so long as Japanese demand remains high.

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As the next wave of LNG capacity is added over the coming decade,
demand growth in China, India and other emerging markets now appears
likely to prevent another major glut, but this could change if economic
trends reverse. Over the long term, the most significant question remains
whether other countries will be able to replicate the boom in shale gas
seen in the US.
3. What is the potential impact of US LNG exports on global markets? The
total amount of proposed LNG capacity in the US is now over 100 MTPA
(137 bcm), but much of this capacity is highly speculative and very
unlikely to move forward. Sabine Pass LNG, the project with the greatest
momentum and a relatively high likelihood of being built, has a total of 18
MTPA (four 4.5 MTPA trains) proposed. While it now appears likely that
some LNG export capacity will be built in the US, there remains great
uncertainty over how much is possible, and thus the impact on LNG
markets is likewise uncertain. At the low end, 18 MTPA represents about
6% of current global capacity, not insignificant but also not likely to
transform global trade patterns or market dynamics.
1.9 Growth in unconventional gas production outside North
America
The success of the US in boosting shale gas has generated interest in
unconventional gas around the world. In Asia, Europe, Latin America and Africa,
companies want to apply the knowledge and expertise gained in North America
to other reservoirs globally. Interest is growing rapidly, but to-date,
development is still at a very early stage. At this point, several observations can
be made:
The global resource base is thought to be significant – estimated by the US EIA
in 2011 to be as high as 6,623 tcf (188 tcm) – but this is a geological estimate
of resources in place that could possibly be produced, and does not reflect
economic or other considerations that will prevent much of this gas from ever
being produced. There is much more activity needed before we know exactly
how much unconventional gas exists and, more importantly, how much can be
produced economically. .
The shale gas revolution in North America was the result of a number of factors
coming together: a prime resource base, large service sector capacity,
favourable pricing, easy to market gas, clear property rights, a supportive
government, etc. These conditions are largely absent in most other places – and
even when some conditions are present (for example, high prices), others are
not (availability of rigs, people, services or easy access to pipelines or clear sub-
surface mineral rights, etc.).
Every play is different. Even in the US, productivity (and hence profitability) is
highly variable with good wells being as much as 30-40 times better than the
worst wells. There are also enormous productivity gains over time as companies
learn how to produce optimally from specific reservoirs.

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In that sense, the industry’s challenge is to “adapt” not merely “adopt” the best
practices from America.
There is an industry consensus that the production outlook for unconventional
gas is very uncertain. Most likely, unconventional gas production may grow in
certain niche markets such as Australia, China and a few others in Europe and
Latin America. To date, a limited number of horizontal wells with hydraulic
fracturing have been drilled with mixed results in Argentina, Poland, China and
Australia. Of these, the most promising in terms of reported production rates
have been in China and Australia. In China, with activity dominated by the
incumbent NOCs, who have brought in IOC majors as partners, it may be
several more years before activity builds to a level where material shale gas
production is seen, and many uncertainties remain over the quality of plays and
whether they will be economic to drill. In Australia, activity has been somewhat
more widespread, but commercial production likewise remains at least several
years away.
Therefore, while there is certainly the potential for unconventional gas to
transform the global market in the same way that it transformed the North
American market, it is clear that the level of activity globally is not at that point
yet. In some countries such as Australia and China there are early indicators
that look promising; other countries such as Argentina and Poland are also
moving quickly. But in several others – for example, France and South Africa,
the political constraints are already delaying drilling for shale gas. Development
will be thus slow and uneven around the world.
1.10 Future Global Outlook
 Will Japan’s nuclear outage continue to affect global LNG demand? The
future of nuclear power continues with uncertainty after the accident in
Japan in 2011. While it is still too early to tell how much LNG demand will
be impacted by the shut in of nuclear plants and an overall policy shift
away from nuclear in select countries, the potential upside for gas is
significant.
 How high will the tally of countries turning to LNG imports to meet
domestic needs rise? Just as the Middle Eastern, South American, and
Southeast Asian countries began importing LNG in the last five years,
more countries in these regions, and potentially Africa, have plans to
begin importing LNG in the next few years. How significant will the
additional demand impact on the market?
 How long will the shale gas boom in the United States affect LNG prices?
The LNG market tightened as a result of robust demand growth in 2011
and the demand shock from Japan in the aftermath of the Fukushima
Daiichi tragedy. In that market environment, the overhang generated by
shale gas in the United States is slated to last less than many market
analysts had anticipated.
 Is the pace of growth in liquefaction capacity set to continue? Incremental
LNG supply into the market is expected to slow in 2012-2014 as all of
Qatar’s trains have come on-stream and Australia’s liquefaction capacity is
not expected on-stream until later in the decade. Only three liquefaction
plants are scheduled to come on-stream in 2012: the Skikda-GL1K

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Rebuild project in Algeria, Angola LNG T1 in Angola and Pluto LNG in
Australia. Arzew-GL3Z (Gassi Touil) is announced to come on-stream in
2013.
 Will all the announced liquefaction capacity come online as scheduled? 84
MTPA in liquefaction capacity is under construction, though another 92.1
MTPA has been announced to come on-stream by 2016, bringing global
liquefaction capacity to 454 MTPA in that year, as opposed to 278.7 MTPA
in 2011. Still, some of these plants may not come on-stream on schedule
and decommissioning of older plants is expected to offset a minor share of
this growth.
 What nations will drive future growth in liquefaction capacity? Though
Qatar has been the source of much of the world’s new liquefaction
capacity over the last decade, the country has completed its last currently
planned train – the 7.8 MTPA Qatargas IV. Australia is projected to
surpass Qatar as the largest LNG exporter by the end of the decade, given
its 61 MTPA of capacity currently under construction.
 Will global LNG receiving capacity continue on a strong growth trajectory?
Roughly 94 MTPA of regasification capacity is currently under construction
and announced to be on-stream by the end of 2016. Once completed,
global regasification capacity will stand at about 709 MTPA.
Commissioning of new floating regasification vessels (which have shorter
development lead times) could further increase LNG receiving capacity
within this time frame.
 Will the LNG shipping market continue to tighten in 2012? LNG shipping
will be driven by three main factors: first, a slowdown in new vessel
deliveries; second, Qatar has chartered a number of smaller vessels to
increase the flexibility of its fleet; and third, an increase in players looking
to do long-haul trade (including re-exporting from the United States)
adding to miles travelled even though volumes may not grow. Together,
these three factors have helped push up spot charter rates in 2011 and
led to a dramatic number of LNG ship orders, with 55 ships ordered
between March and December 2011.

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2 Supply and Demand
2.1 Supply Fundamentals
Liquefaction capacity worldwide is projected to increase at an average annual
rate of 5 per cent, to reach 366 million tonnes per annum by the end of 2017.
Australia will be one of them main beneficiaries. Its LNG export earnings are
projected to increase by an average of 20 per cent per annum to total $30 billion
(in 2011–12 dollars) in 2016–17. The growth will be underpinned by higher
export volumes supported by the start-up of 66 MTPA of additional LNG
production capacity.
Figure 7: LNG Trade Movements 2011
Over this decade, global gas consumption is increasing. The International Energy
Agency forecasts world natural gas consumption to reach 3.8 trillion cubic
metres by 2016. Gas-fired power is an attractive option especially in the Asia-
Pacific because it is characterised by low capital expenditure, short construction
times, flexibility in meeting peak demand, and low carbon emissions relative to
other fossil fuels. The majority of incremental gas consumption is projected to
occur in emerging economies, where gas-fired energy is projected to support
strong economic growth.
However, the majority of the world's natural gas production is still confined to a
few regions including the former Soviet Union and North America. LNG
production from the US and Russia is ready to hit the market before the end of
the decade, even sooner in the case of the US. These two areas will provide
some competition for Australia LNG.
In the minds of some Australian LNG players, there is the vision of cheap US
LNG from the shale-gas boom squeezing through the expanded Panama Canal
into the Asia-Pacific market, and backed by flows of volumes from the Pacific
Coast of Canada headed for Japan, China and Korea,.

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LNG carrier transportation costs will be reduced in 2014 when a $5Bln expansion
project for the Panama Canal is due to be completed. The project will increase
the width of the canal, allowing it to accommodate LNG vessels transporting LNG
from the Atlantic market to the Asia-Pacific market. The expansion is likely to
reduce transport costs and travel time.
The established LNG markets of Japan, South Korea and Taiwan are the bedrock
of Asian LNG. Their LNG demand is driven by the power generation sector and
they continue to seek security of supply and diversification.
The second group of buyers are the growing energy markets of China and India.
Australia has already cracked the China market, while Russia's Gazprom is
hoping to do more LNG business with India.
However, the slow pace of Russian LNG developments is turning the Russia-
India supply chain into a cargo marketing exercise out of Singapore. The
Russians continue with sea trial, however, to deliver LNG to Asia by the eastern
Sea Route through Arctic waters for the Yamal and Shtokman LNG projects.
Russia's Asia-Pacific LNG volumes are likely to be boosted sooner by the
Vladivostok LNG project and an expansion of the Sakhalin LNG plant.
A third group of countries are the emerging regional markets for LNG, including
Singapore, Thailand, Vietnam and the Philippines, along with traditional LNG
suppliers, Indonesia and Malaysia.
The Australian LNG competition debate has now shifted from if North American
LNG exports head for Asia to - how much?
Two US Gulf coast LNG export projects, Cheniere's Sabine Pass and Sempra
Energy's Cameron LNG have so far tied up a combined 24 MTPA of output for
delivery to Asia.
Cheniere's Henry Hub US price-linked agreements with Korea Gas Corp. and
India's Gail and Sempra's agreements with Mitsubishi and Mitsui of Japan for
Cameron LNG exports represent significant developments.
The Canadian LNG export projects have been slower off the mark, but are
unlikely to account for more than 16 MTPA of cargoes into Asia in the early
years.
Already that's 40 MTPA of additional North American LNG headed for Asia after
2016, which given the growing Asia-Pacific demand is unlikely to have a series
impact on Australian contract income.
Given the oil-price link to LNG originating in the Asia-Pacific, the US pricing of
North American LNG will offer price diversification and a certain hedging for
Asian buyers, though only in limited quantities, analysts said.
Australian natural gas resources are abundant and exploration programmes are
headed for success in the coming years to feed the Asian LNG market.

14
Despite this imminent competition from North America, Japanese LNG customers
in particular are keen to sign Australian LNG contracts and extensions to existing
agreements.
In April 2012, Japan's Chubu Electric signed up for 1 MTPA of output for 20 years
from the Chevron-operated Wheatstone LNG project, while Kyushu Electric
Power Co. extended a supply contract to 2023 with the North West Shelf plant at
Karratha, Australia's first LNG plant and which has now been in operation for 23
years.
The Japanese utilities have a long history as foundation customers in Australia.
NWS, whose shareholder include the developers of the new LNG projects,
companies such as Woodside Petroleum, Shell and Chevron, has supply
contracts with 10 Japanese utilities.That's why Japanese demand will underpin
Australian development and production, rather than the new economies of China
and India whose LNG and natural gas infrastructure couldn't absorb imminent
high volumes of Australian LNG.
However, more natural gas transport capacity is also being prepared for the
Australian surge in the form of LNG carriers, additional pipelines and the
construction of more regasification terminals in the Asia-Pacific region.
2.2 Demand Fundamentals
In all the regional economies, LNG imports are increasingly used to supplement
insufficient domestic gas supplies to meet growing demand.
Demand for natural gas is estimated to surge by more than 50% by 2035,
provided that vast global resources of unconventional gas can be tapped in a
profitable and environmentally friendly manner, the International Energy Agency
(IEA) said in a special report.
The U.S. is experiencing a boom in shale gas production, with gas prices on
record lows and power producers switching from coal to comparatively cheap
and less carbon-intensive gas. By 2035, gas-fired power plants could have 25%
share of the global energy mix, outperforming the contribution of coal-fired
plants which might be downgraded to become the second largest primary energy
source after oil, according to the IEA's most optimistic scenario for
unconventional gas.
In the U.S., new gas-fired power plant projects are mushrooming as an
attractive spark spread [the profit margin of generating electricity from natural
gas] is prompting power producers to retrofit ageing coal-fired plants to run on
natural gas.
The share of unconventional gas in current total gas production is forecast to
rise from 14% to 32% by 2035. The IEA said the lion's share of the increase is
set to materialise after 2020, "reflecting the time needed for new producing
countries to establish a commercial industry".

15
Production volumes of unconventional gas - mainly shale gas—are expected to
more than triples to 1.6 trillion cubic meters by 2035, accounting for nearly two-
thirds of incremental gas supply in the U.S between now and then.
In Japan, increases in LNG imports have now been underpinned by greater gas-
fired electricity generation following the March 2011 earthquakes and tsunami
and the subsequent closure of most of its nuclear facilities.
Asia-Pacific imports of LNG are forecast to increase by 11 per cent in 2012 to
reach 162 million tonnes.
A second Australian LNG surge is not out of the question after 2020, as new
resources are discovered and existing projects mature or expand and
engineering capacity is more widely available. Asian demand will also continue to
demand at a rate in line with economic expansion in China and India, whose
infrastructure networks are playing catch-up.
From 2014 to 2017, Asia-Pacific imports of LNG are projected to increase at an
average of 6 per cent a year to reach 217 MT, reflecting the increasing
importance of natural gas in power generation, and for direct consumption in the
residential and industrial sector.
Japan's LNG needs will guide the future of the Asia-Pacific supplies and price in
the medium-term. A surge in Japanese LNG consumption followed the March
2011 earthquakes and tsunami that ultimately led to the closure of most of
Japan's nuclear reactors for stress tests.
Figure 8: LNG import forecasts for the main Asia-Pacific LNG buyers
through 2017

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2.3 Impact new LNG importers on the global market
There will be over 30 LNG importing countries by 2015, double the number ten
years earlier. New regions have emerged to challenge the traditional markets of
Asia, Europe and North America. Greater geographic diversity and volume of
import capacity is substantially increasing the range of factors that can exert an
influence over the global gas market.
Latin America, Argentina, Brazil, Chile and Mexico have developed regasification
terminals while in the Middle East, Dubai and Kuwait have emerged as big LNG
importers. In Asia, countries such as Malaysia and Indonesia which had been
exporters of LNG, have recently become importers as their own domestic gas
reserves have declined. But the most significant development impacting global
LNG demand, has been the emergence of global growth powerhouses China and
India as LNG buyers.
Figure 9: Development of LNG import terminals and importing
countries
The key drivers behind the projected growth in demand for LNG imports are :
1. Energy intensive economic growth in developing economies and an
increasing preference for gas as the fuel of choice for power generation.
2. The global shift towards gas for power generation has primarily been the
result of an environmental policy driven switch away from coal fired
generation, to address carbon emissions in the developed world and local
pollution issues in the developing world. This is despite the fact that coal
fired generation is currently significantly cheaper than gas on a marginal
cost basis in many regions. The extent to which the closure of nuclear
capacity results in the development of new gas fired capacity will also be a
factor.

17
3. LNG import growth has been facilitated by a rapid expansion in global
regasification capacity. In many cases this has been justified on the
grounds of security of supply, with supply source diversification increasing
a country’s ability to manage geopolitical risks and flexibility to manage
supply chain shocks.
4. Another driver behind the rapid growth of regasification capacity is the
relatively low barriers to entry. Regasification capital costs are typically
only a fraction (approx 10%) of the cost of liquefaction capacity, so
developing import terminals creates a (relatively) “cheap option” to import
LNG. The development of the Excelerate floating LNG storage and
regasification units ( FSGUs) and dockside regasification terminals have
also lowered the costs and lead times for developing import
infrastructure. Excelerate currently has nine FSGUs (which can also act as
conventional LNG tankers) serving terminals in Argentina, US, UK, Kuwait
and Brazil.
2.4 Implications of significant growth in regasification
capacity
The growth in global regasification capacity has substantially increased the depth
of the LNG demand side, both in terms of geographical diversity and volume.
The development of regasification capacity represents an option to import
LNG. But the actual level of imports into a regasification terminal will be driven
by local gas market dynamics, particularly the marginal value placed on
increasing volumes of imports. This adds to the complexity of global LNG
demand dynamics.
The level of influence of any one country on the global market will clearly be
constrained by the size of its import capacity. Inter-regional market price
dynamics will drive global LNG flows and trade. In turn, regasification capacity
utilisation will largely be driven by changes in regional price differentials and
relative transportation costs, as has been witnessed recently with large volumes
of European cargoes diverted to Asia.

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3 Main producers LNG; current status and future
developments
3.1 The influence of new supply
Several LNG export projects currently under construction will come online over
the next two to three years . Australia is set to become one of the globe’s largest
LNG exporters which will significantly reduce the geopolitical risk of global LNG
supplies, although there is still considerable uncertainty around the timing of
some large projects.
New liquefaction facilities are also being constructed in Papua New Guinea,
Indonesia and Algeria, with a combined capacity of about 20 MTPA.
Global gas consumption is forecast to rise at an average annual rate of 3 per
cent through 2020, underpinned by increasing use of natural gas in electricity
generation in China, India and elsewhere in the Asia-Pacific region.
Figure 10: LNG Export Projects Under Construction
At the other end of the geo-political risk spectrum it is unclear when Iran’s LNG
export facility (currently under construction) will be commissioned given the
sanctions imposed by the internationally community over its nuclear program.
The degree to which these new projects ease the tightness in the global LNG
market will be driven by the strength of demand growth from emerging
markets (especially China and India) and the extent to which demand holds up
in developed markets facing an economic slowdown.
The level of price convergence across the global markets will be largely driven
by this dynamic.
80 percent of the new LNG output coming on stream from now until 2017 is
already under long-term contract, while short shipping capacity is the main
constraint in the LNG value chain.

19
3.2 Qatar and other Middle Eastern Producing countries
Since the beginning of 2012 Qatar has been actively signing LNG contracts with
a number of Asian countries, such as South Korea, Taiwan and Pakistan. This is
not surprising given the challenging market conditions in Europe, and the self
sufficiency of US markets on the back of shale gas.
Qatar have arrangements to supply LNG to the UK, Belgium and Italy through
either direct investment in LNG receiving terminals or long-term contract sales.
Qatar is utilizing much of its expanded LNG production capacity, originally
earmarked for the Atlantic Basin, to supply incremental LNG into Asia, including
Japan.
While Qatar has used separate LNG pricing policies depending on market
regions, its future direction of geographical distribution of sales and
accompanying pricing policies are drawing attention in the industry. As fiercer
competition is expected from the next generation of LNG supply sources in
Australia and other countries after 2014-2015, Qatari marketers are gearing up
marketing campaigns to secure long-term deals.
Preliminary sales deals were agreed with Argentina for 5 MTPA from 2014 and
with Malaysia for 1.5 MTPA from 2013. However, these deals may take time to
be finalized as the two countries have historically had lower domestic natural gas
prices than internationally-traded LNG.
In June 2012, Qatargas signed a contract to deliver 1mn tonnes of LNG a year,
under a long-term contract with Tokyo Electric Power Company (Tepco). This is
the first long-term bilateral agreement between both companies. Qatargas
supplies a total of 200,000 tonnes of LNG a year to Tepco and seven other firms
until December 2021.
As Qatar ramps up its exports of LNG, Qatar Gas Transport Company (Nakilat)
has built one of the largest LNG fleets in the world. Nakilat (‘carrier’ in Arabic)
currently owns 16 percent of global LNG shipping tonnage. Its LNG fleet includes
nine conventional vessels (146,000–154,000 m3), 31 Q-Flex carriers (210,000–
216,000 m3) and 14 Q-Max ships (263,000–266,000 m3).
Qatar’s massive investment in LNG facilities is the driving force behind the
state’s phenomenal economic growth. In recent years, some of the world’s most
advanced energy projects have been undertaken by Qatar Petroleum, RasGas,
its sister company Qatargas and their joint venture partners.
Investing in the Qatari-based marine infrastructure to support this global
economic supply line has been a key project. Formed in 2007 by a partnership
between Nakilat and Singapore-based shipbuilder, Keppel Offshore and
Marine, Nakilat-Keppel Offshore & Marine (N-KOM) at Ras Laffan Port is one of
the world’s leading yards for LNG repairs.
Middle East LNG gas producers, the biggest suppliers of the fuel to Europe, are
set to cut exports for the first time in 20 years amid rising local demand for
power generation.

20
Qatar, Oman, Yemen and Abu Dhabi, which supply 40 percent of the world’s
LNG, exported at 96 percent of capacity in 2011. That will probably fall to about
94 percent in 2012.
This fall is caused by a combination of reduced supply and rising demand in the
Middle East, as countries build import terminals to meet their power needs. ,
may accelerate the diversion of supplies from Europe to more lucrative The four
Middle East LNG producers exported 95.6 million metric tons in 2011. They have
a combined liquefaction capacity of 100 million tons.
Yemen LNG’s plant halted for over seven weeks from March 31 after the pipeline
feeding was sabotaged, cutting 1 million tons of supply. One million tons of LNG
is about 1.2 billion cubic meters of gas, equivalent to Sweden’s annual
consumption.
Qatar and Oman will reduce output by a combined 5 million tons in 2012, the
estimates show. Qatar has increased exports every year since 1996 and started
its 14th liquefaction plant in 2011. It plans no more. Oman’s exports fell 13
percent from 2007 to 2010 as gas was diverted for domestic use.
Middle East electricity demand grew 20 percent from 2006 to 2009, almost four
times faster than the world average. The region’s gas use may rise to 428 billion
cubic meters by 2015 and 470 billion cubic meters by 2020, from 335 billion
cubic meters in 2008. The Middle East’s rate of growth in imports is second only
to China.
Kuwait started the Middle East’s first LNG import terminal in 2009, with Dubai
following a year later. They shipped in 3.7 million tons on 2011. last Bahrain,
the United Arab Emirates, Jordan, Kuwait, Israel and Lebanon have announced
terminals as they seek to meet rising demand. Saudi Arabia is exploring for gas
to use in power plants to cut its dependence on oil-export income.
While exports from the region’s current producers decline, Israel and Iraq are on
course to meet the shortfall. Israel may ship as much as 10 million tons a year
of LNG by 2020, after Noble Energy Inc. develops the Leviathan and Tamar
fields that hold about 30 trillion cubic feet of gas. Iraq may export 4.5 million
tons a year from the south of the country by the end of this decade as well as by
pipeline through Turkey.
Unrest in the region also limits supply. Attacks on a pipeline in Yemen have shut
the country’s LNG plant three times in the past year. The nation, bordering
Saudi Arabia and Oman at the southern tip of the Arabian Peninsula, is battling
Al-Qaeda-affiliated militants in the province of Abyan.

21
Jordan and Israel have suffered disruption to gas supplies after repeated
sabotage on a pipeline from Egypt. State-owned Israel Natural Gas Lines Ltd.
signed a deal with Italy’s Micoperi Srl to build an offshore re-gasification terminal
that may be completed in 2012.
Jordan plans to offer a tender to build an offshore terminal in the Red Sea port
of Aqaba by June. Qatar and Jordan set up a technical committee that will study
shipping fuel from the emirate.
Bahrain, which previously explored importing gas from Iran by pipeline, wants to
award an LNG terminal contract by the end of 2012 and is in talks to source the
LNG supply. The terminal is to be finished by 2014 or 2015.
3.3 Australia
Australia is set to overtake Qatar as the world's largest producer and while the
Gulf state is unlikely to expand output, Australia has untapped natural gas
resources for even more projects to be developed in the years ahead.
That won't be for a while though, as Australian engineering, construction and
labour capacity, not to mention its offshore expertise and potential infrastructure
provision, has reached a scale where no extra capacity could be handled in a
safe and timely fashion.
The Australian LNG build-up has spanned the country from west to east and to
the north, with liquefaction facilities offshore and onshore and including subsea
hydrocarbons and coal-seam gas.In addition, the next wave of Australian
development and production will come from floating LNG plants located offshore
northwest Australia, from Prelude FLNG and Bonaparte FLNG, to other projects
which may emerge from the planning rooms of the energy majors.
In total about 70 per cent of the world's LNG capacity currently under
construction is located in Australia, and according to the Bureau of Resource and
Energy Economics in Australia, the discovered extensive gas reserves are
capable of supporting 40 to 50 years of LNG production.
The Australian LNG industry's addition of 60 million tonnes of production in the
next seven years represents faster growth than the World No. 1 LNG producer
Qatar when it built its six mega-Trains.
More than US$200 billion in investment has already been committed to the eight
approved LNG projects and another $150billion of investment is planned for
plant expansions and the new projects already announced. In 2012–13,
Australian exports are forecast to increase by 19 per cent to total 23 million
tonnes, as production at the Pluto facility is scaled up towards capacity.

22
Figure 11: Australia’s LNG Capacity
Out of the 14 liquefaction projects committed or under construction around the
world, eight are located in Australia. Australia LNG liquefaction capacity is
projected to increase four-fold to total 85 million tonnes in 2017. Most of this
additional capacity is scheduled to come online after 2014.
Between 2014 and 2015, three coal-seam-gas-LNG projects, with a combined
capacity of 25 million tonnes, are scheduled to start up: the Australia Pacific LNG
project, the Queensland Curtis LNG project and the Gladstone LNG project.
The three CSG-to-LNG projects are located next to each other at the port of
Gladstone and have secured lucrative contracts from Asian buyers.
The remaining LNG projects scheduled for completion include Gorgon (15 MT in
2015), Wheatstone (8.9 MT in 2016), Prelude FLNG (3.6 MT in 2016/17) and
Ichthys LNG (8.4 million tonnes in 2016).
Figure 12: Australian LNG Plants; operating, under construction, planned

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3.4 North America
In the Introduction chapter we have already delat in depth with the
developments in the US gas markets. But maybe even more important to the
new supply situation is Canada as it is well positioned both geographically and
regulation wise.
3.4.1 Canada
Canadian LNG export projects involving local and global energy players are
slowly gathering momentum for exports to Asian markets to begin by 2016 or
later, though the first project off the blocks has delayed its final investment
decision.
Mitsubishi Corp. of Japan, meanwhile, is building up its equity positions in
potential Canadian LNG exports. The Japanese company recently made an
investment in EnCana Corp.'s Cutback Ridge gas play in northern British
Columbia. It is also busy carrying out feasibility studies as it's already involved
with Royal Dutch Shell in another Canadian LNG project.
The first LNG export venture to come on stream was expected to be the Kitimat
LNG project, known as KM LNG, originally developed as an import venture and
now owned by Apache Corp., EOG Resources and Canada's EnCana Corp.
KM LNG was expected to take a final investment decision in 2011 and has now
pushed the FID back to the third quarter of 2012. KM LNG is being delayed
because the partners wish to review the size of equity they would be willing to
offer buyers.
As regards the other projects, the National Energy Board recently awarded an
export licence to privately-held, Houston, Texas-based BC LNG after previously
giving a permit to KM LNG. The BC LNG venture will be based near Kitimat.
Shell and partners Korea Gas Corp, Mitsubishi and China National Petroleum
Corp. have bought land for their potential LNG export terminal, also near
Kitimat. The choice of Kitimat as an export port is underpinned by acceptance
from First Nation land-rights holders in that area and planned pipeline links from
the gas fields to the West Coast.
Progress Energy Resources Corp. is another company with LNG export
ambitions. It has set up a joint venture with Petronas of Malaysia.
The slow-track approach in Canada is all the more surprising as it doesn't have
the political opposition being experienced by LNG export developers in the US.
Indeed, the potential LNG export business for Canada is receiving a wave of
political support in the areas of the permitting process and promised tax breaks.
The stakes for Canadian LNG export plans centred on BC are now higher than
ever. Much of the natural gas produced in BC is already exported by cross-
border pipeline to the low-priced US market.

24
Because of the current price levels for Canadian natural gas pipeline exports,
there is no big opposition lobby citing adverse impacts on domestic prices if the
gas surplus is liquefied and exported to Asia.
Of the 3 billion cubic feet per day of gas currently produced in BC, 16 per cent is
consumed locally, 41 per cent is exported to the US through two pipeline
systems and 43 per cent is delivered to other regions of Canada by pipeline.
The development of shale gas in BC is not new and began back in 2005. It has
rapidly evolved. With shale gas now in play, it is conservatively estimated that
BC has at least 100 trillion cubic feet of recoverable gas. This compares with
total production of 22.5 Tcf in the province between 1954 and 2010.
"This has changed the natural gas industry for ever, making natural gas an
abundant resource.
The government has drawn up a strategy that will make BC one of the most
attractive areas in the world for LNG investment. BC will for instance invest in
critical infrastructure to power future LNG facilities in balance with the need to
keep electricity rates affordable for the people of the province.
This would boost exploration and production spending and allow LNG project
developers better to estimate the economics of their ventures.
The province will provide more evaluations of the geological and hydrological
context for surface, sub-surface, and deep saline water resources in Northeast
BC as water is used in shale-gas production.
3.5 Russia
Gazprom is aiming to become a dominant player in the liquefied natural gas
market by targeting booming demand in Asia. "In the near future, Gazprom will
become a major player on the LNG market according to Gazprom’s CEO Alexei
Miller. In 2011, Gazprom, the state-run firm produced 10.67 million tons of LNG
at its only current plant off Sakhalin Island in Russia's Far East, saying this
figure should grow markedly with a firmer focus on Asian sales.
Miller said that in addition to the growth in traditional markets such as Japan,
Korea and Taiwan, there is great potential in large new consumers such as India
and China. Energy demand is also growing in Singapore, Pakistan, the
Philippines, Thailand and Bangladesh.
Mr .Miller saying Gazprom expected to launch a new LNG plant in the Russian
Pacific port city of Vladivostok by 2017. Gazprom plans to build the plant with a
Japanese consortium led by trading house Itochu with a reported price tag of
about 1.0 trillion yen ($12.45 billion). The facility will receive natural gas from
other parts of Russia and convert it to LNG before shipping it to countries in the
Asia-Pacific.

25
3.6 Indonesia and Malaysia
Indonesia and Malaysia have regularly vied for the world No.2 and No. 3 spots in
the LNG producer league behind Qatar.
However, both will soon be overtaken by Australia and even the US could take
fourth spot in the export league after 2020.
Indonesia currently exports some 65 percent of its total gas production, and this
may not be sustainable in the future amid the rising domestic demand, which is
competing for the same supply sources.“Failure to attract new investments to
develop the gas production capacity will increase Indonesia’s reliance on gas
imports in the future, repeating the pattern that has led the country to become a
net importer of oil,” the IGU warned.
Malaysia’s natural gas demand challenges stem from the fact that 70 percent of
its gas reserves are located in East Malaysia, whereas the primary demand
centres are in West Malaysia. Gas reserves in Sarawak are dedicated for the
export market, where Malaysia is currently the third-largest exporter of LNG in
the world. However, rising gas demand in the Peninsula, particularly at the
power sector, requires gas imports from Indonesia and Joint Development Areas
to supplement the production from offshore Terengganu.
To mitigate declining production and secure additional reserves, Petronas is
leading other players to invest in the upstream sector, particularly in deepwater
areas and marginal field developments.
In view of the financial burden and growing gas demand, the government
decided to gradually reduce gas subsidies that have been in place since 1997.
“The progressive move towards market-based pricing in Malaysia will further
enhance the competitiveness of the country’s gas industry and attract new
investments into this sector,” the IGU said.
Although Indonesian LNG export capacity is expected to grow with an eventual
third Tangguh Train, the Donggi-Senoro plant and the Inpex-led Abadi FLNG
project, total exports are expected to fall, with a shift to domestic gas use. More
LNG FSRUs are in an advanced stage of planning in Indonesia and will be built
and deployed in the near future.
Indonesia also plans to export more spot cargoes from the Tangguh LNG plant in
West Papua from the LNG allocations formerly controlled by Sempra Energy of
the US. BP of the UK, operator of the Tangguh LNG plant, earlier this year
reached a deal with San Diego, California-based Sempra that allows Indonesia to
divert 54 out of the 60 cargoes originally committed to the US company on an
annual basis from the Tangguh facility.

26
4 Main buyers and their search for suppliers
4.1 Japan
With its scarce domestic energy resources, Japan is the world's fourth largest
energy consumer. Japan purchases 100 per cent of consumed natural gas in the
form of LNG and is the world's largest LNG importer.
Japanese electric power and gas companies have been criticised for buying
allegedly the most expensive LNG in the world, especially after increases in
imports in 2011 and increased public awareness of less expensive gas available
in other regions of the world, especially North America. The Japanese LNG
buyers are often frustrated by the huge gaps between oil-linked long-term
contract prices and hub-based spot prices in the Atlantic Basin. Japanese long-
term contracts are based on a percentage, usually around 12-13 percent, of
Japan’s oil import price, commonly known as the Japanese Crude Cocktail (JCC),
plus a premium, usually $1 to $2. So if JCC is $100/barrel, then the LNG prices
will be $13-15 per MMBtu.
Japanese LNG buyers are increasingly required to devise ways of procuring LNG
at more competitive prices - for example through active participation in the
whole value chain of the LNG business.
While Japanese electric power and gas companies buy the majority of their LNG
under long-term contracts, the companies have increased short-term contract
and spot purchases to meet incremental gas demand through 2012, as well as
tradition contract cargo deliveries. Japanese buyers were not that willing, or did
not see that much of a need, to purchase LNG linked to Henry Hub or European
hub prices, but that was a long time ago. Right now, they are more willing and
placing importance and emphasis on hub-linked prices.
In particular, there have been noticeable increases in short-term contracts
backed by the recent surge in global LNG production capacity.
As Japanese buyers introduce more cargoes from the Atlantic Basin - where gas
prices have plummeted, especially in North America - into the oil-linked Pacific
Basin, the price gap between the global regions has become more apparent.
Transactions have often fallen through because of a lack of available LNG
carriers, even if there is spare LNG production capacity. A value-chain flow from
LNG production to electricity supply cannot stand if there is any missing link in
the capacity of thermal power plants, LNG storage tanks or marine facilities.
Japan's LNG imports in 2012 have sometimes been running at more than 8
million tonnes per month after growing by 12 percent in 2011.
As well as the increased volumes, higher prices have further inflated amounts
paid for the imports. Japan paid 4.8 trillion yen ($60 billion) for its LNG imports
in 2011, an eye-popping 38 percent jump from the 3.5 trillion yen paid the
previous year. Hence, it is quite likely that the total amount for LNG purchases
surpassed 1 percent of the nation's gross domestic product for the first time.

27
The largest proportion of incremental LNG volumes delivered to Japan come
from Qatar, which supplied nearly 12 million tonnes last year, an increase of
more than 4 million tonnes year-on-year. Supply from the Atlantic region
exporters, including West Africa, also increased significantly to 4.7 million tonnes
from 3 million tonnes the previous year.
LNG prices for Japan as a whole have followed three tracks in the past year:
long-term contract prices; slightly less expensive medium-term and short-term
contract prices; and even lower or fluctuating spot prices.
There is now sufficient LNG supply capacity to meet the incremental demand not
only in the short term but also in the medium term. Until 2014-2015, when
another new wave of LNG supplies start flowing, diversions from the Atlantic
region, short-term and medium-term contracts and spot cargo deliveries are
expected to continue bridging gaps of supply and demand in the Asia-Pacific
market.
It will be more important for Japanese players to procure more competitive LNG
supply in the future through proactive involvement in the value chain as a
whole, including the upstream, liquefaction and transportation segments.
Cooperation and alliances with players in the region and around the world to
optimise business and LNG supplies will be more crucial for Japan in the future.
In 2011 Gazprom together with the Agency for Natural Resources and Energy as
well as with Japanese consortium Japan Far East Gas Company conducted a
preliminary feasibility study on the project of a LNG plant construction near
Vladivostok. In March 2012 the Gazprom Management Committee resolved to
prepare the Investment Rationale for the LNG plant construction near
Vladivostok. Preparation for the Investment Rationale is to be completed in late
2012. Significant new supplies of LNG from projects yet to take a final
investment decision will be required to meet demand, and long-term SPAs with
pricing linked to oil will continue to be used to support project economics,
especially in the Asia-Pacific Basin.
The influence on Asian pricing will ultimately be dependent on the proportion of
Asian sales captured by US LNG and the extent to which US supplies become
and remain the marginal supply choice for the region.
At the start of the second quarter of 2012, only two Japanese reactors with a
combined capacity of 2,227 megawatts were operating in Japan. The remaining
49 reactors were inoperative either as the result of government imposed stress
tests or because of planned maintenance. The two online generators were also
due to close for inspection and maintenance in the first half of 2012. Assuming
the authorities allow the restart of around 15 nuclear power stations that have
passed stress tests in the second half of 2012, Japan's imports of LNG would
decline.

28
That is thought unlikely. Projections of Japan's LNG imports over the medium-
term are now largely dependent on government policies that will dictate if and
when nuclear capacity is restarted.
4.2 China
China's LNG usage has only just overtaken Taiwan's and Chinese infrastructure
is being developed at a slower pace than expected, while rising pipeline gas
supplies from former Soviet states is meeting some demand.
China's gas consumption is projected to rise from 112 billion cubic metres to
reach 260 Bcm by 2015.
China will need up to 60 new liquefied natural gas carriers worth in the region of
$12bn between now and 2020 to meet energy goals set out in the Twelfth Five-
Year plan. There will be a minimum of four Chinese shipyards building these high
spec vessels in the coming years, up from the current one in Hudong-Zhonghua.
The number of terminals in China will jump to 14 from the current five in
operation at the moment with a further 10 due for consideration after 2016
depending on demand. With the global LNG fleet also set to spike the face of
LNG shipping will change dramatically with a flourishing spot market for the first
time.
It is not expected that LNG imports in China will account for much greater than
20% of overall gas demand. At present, China satisfies around 13% of its gas
demand through LNG imports and most of these volumes are consumed in close
proximity to receiving terminals. The vast majority of LNG, some 90%, is sold as
direct sales to consumers in the power and industrial sectors, with only around
10% being sold through LDCs. The ratio of regas to power generation as
opposed to regas for industrial use differs in Japan, South Korea and China.
Power generation dominates gas use in Japan, accounting for approximately
60% of overall demand. In South Korea this figure is around 50% and in China
this figure is around 50-60% at present
While Chinese state-owned energy companies are focusing on developing
domestic natural gas supply to meet rising demand, the IEA projects that
China's gas production will equate to around half of the growth in domestic
consumption. The remaining component of demand is likely to be met by
increasing imports of pipeline gas and LNG. Indeed, pipelines are the most cost-
effective means of importing natural gas into China in the northern and western
provinces. .But in China's northern and western provinces, the long distances to
gas-consuming centres via pipeline make LNG imports more economic.
The slower than forecast development of LNG regasification capacity in China is
expected to constrain increases in its LNG imports. In 2012, China's LNG imports
are forecast to increase 30 per cent to total 16 MT, reflecting additional capacity
at the new Zhejiang Ningbo and Dalian import facilities.In 2013, Chinese LNG
imports are forecast to grow by an additional 13 per cent to total 19 million
tonnes.

29
Increases in LNG imports are forecast to be supported by the expected
commissioning of the Zhuhai Jinwan and Tangshan facilities, but will be
moderated by the completion of the Myanmar-China pipeline. Between 2014 and
2017, several additional LNG projects are scheduled to start up underpinning
China's LNG imports over medium term. Combined, these projects are expected
to support more than 37 million tonnes of LNG imports into China in 2017.
China's energy giants are slowing their purchases of overseas unconventional
gas assets following two years of aggressive investment, leaving the door open
for Asian rivals to step up their game in regions including the Americas.
Sinopec Group, PetroChina and CNOOC Ltd have been leading Asia's gas
acquisitions, with a bulk of the deals involving the transferring of Western
technology on unconventional energy to China, believed to hold the world's
biggest deposits of gas in shale rock.
As they focus on learning the expertise and gathering experience in running
those projects -- most of which are early-stage operations requiring massive
capital spending -- Chinese purchases of overseas energy assets fell to $16.3
billion in 2011 from $23.4 billion in 2010. Deals totaled $5.1 billion so far in
2012.
The Chinese bid is definitely not there for a lot of the unconventional assets as
the main buyers are the Japanese and some Southeast Asian players. As
Chinese buyers take a breather, companies in Japan, South Korea, India and
Malaysia are swooping in to pick up assets. Japanese trading houses have been
acquiring overseas gas assets to replace lost nuclear power capacity after the
Fukushima crisis and to secure supplies before long-term liquefied natural gas
contracts expire. A strong yen has also provided them with the ammunition they
need in overseas takeovers, bankers say.
Mitsubishi Corp) agreed to buy a 40 percent stake in Encana Corp's British
Columbia gas assets in a C$2.9 billion ($2.9 billion) deal. In contrast, PetroChina
walked away from a C$5.4 billion joint-venture with Encana last year because of
differences over terms.
State-run Korea Gas Corp (KOGAS), expecting to invest $2.5 billion to develop
oil and gas projects this year, is scouring the world for opportunities. There are
no limits —- wherever there is gas, we will go, saidPresident and Chief Executive
Kangsoo Choo. GAIL (India) Ltd has around $1 billion to spend on shale gas
assets in Canada and the United States.
Oil and Natural Gas Corp, India's biggest state-owned energy explorer, is
considering bidding for some Canadian oil sands holdings being auctioned by
ConocoPhillips for around $5 billion.
Indian state energy and mining companies have made few overseas acquisitions
in recent years, lacking the financial independence that other national oil
companies enjoy. Slow decision-making has also been cited by analysts as a
factor.

30
Asian companies have announced outbound oil and gas acquisition deals worth
$13 billion so far this year, compared with $28 billion for the whole of 2011 and
$44 billion the previous year.
Conventional oil and gas assets in Africa held by Swedish oil group Svenska
Petroleum Exploration, currently on the block to raise an estimated $2 billion,
may also attract Asian companies.
For now, an oversupply of natural gas in the United States and increasingly
tough environmental rules on shale production have discouraged China's energy
producers from aggressively entering into more shale deals. There seems to be 2
reasons for this: One is they have already got projects to get on with. And
secondly gas price is very low in the U.S
PetroChina was recently approached by Chesapeake Energy Corp ,which
previously sold stakes in shale gas fields to CNOOC, but the Hong Kong-listed
unit of China's largest energy company did not express any interest because it
was wary about natural gas prices and regulatory risks.
PetroChina's $3 billion-plus Australian coal-seam gas joint venture with Royal
Dutch Shell Plc is also facing cost pressures because of the need to comply with
increasingly stringent local environmental rules, rising labour expenses and a
stronger Australian dollar. Total investment in the joint venture may surge to
$34 billion-to-$36 billion from $24 billion-to-$26 billion initially estimated by
PetroChina.
Bringing in experienced foreign partners to develop China's unconventional
energy reserves may be cheaper.Early 20120, PetroChina awarded the country's
first shale gas production sharing contract to Shell, which under the contract will
transfer its shale gas technology.
4.3 Korea
Korea, the other main LNG consumer in East Asia, has increased its imports in
line with demand in recent years. In 2011, Korean imports increased by 12 per
cent to total 33 million tonnes, underpinned by a rise in gas use for electricity
generation.
In 2013, Korean LNG imports are forecast to increase by 7 per cent to total 38
MT. Increasing imports reflect an expectation that natural gas will continue to
play a critical role in Korean peak-load electricity generation and expansion of
the gas distribution network.

31
4.4 India
As far as India is concerned, between 2013 and 2017, imports of LNG are
projected to increase at an average annual rate of 5 per cent to reach 16 MT in
2017. This trend is set to continue for the foreseeable future.
Reliance Industries, ONGC and GAIL want to buy shares in LNG terminals on the
east coast of the US for shipping gas to India at about $9.5 per mmBTU, which
will be over 50% cheaper than current imports.
Indian companies with shale gas assets are interested in acquiring an operating
interest in terminals to ship gas to India at less than $10.. India is already the
world's eighth-largest importer of LNG. Those imports could rise five-fold in the
next decade as domestic gas output falls and demand surges.
Currently, seven LNG terminals are planned in the US to export gas. Indian
companies want to ship from the US east coast just as Chinese counterparts
focus on the west coast for shipment to ensure energy security.
This is significant as shipments from US could become more viable than gas
flowing through the Trans-Afghanistan-Pakistan-India (TAPI) pipeline from
Turkmenistan in the future. The landing cost of this is estimated at $13 per
mmBtu, besides the geopolitical risks.
RIL has made $3.8 billion investments in US shale exploration and production
assets, and is now exploring opportunities to buy stakes in LNG terminals on the
east coast to ship the gas to India. RIL plans to invest another $1-1.5 billion
over five years.
GAIL India last year bought a 20% stake in one of Carrizo Oil & Gas's shale gas
assets for $300 million. The gas transporter is planning to buy a stake in an LNG
export terminal and has been in talks with Macquarie Energy, which has a share
in the US-based Freeport LNG project.
ONGC was pursuing a stake buy in LNG terminals in the US. This month, ONGC
and Japan's Mitsui agreed to work together in the gas and LNG businesses. They
signed an MoU to pursue opportunities in the entire value chain of sourcing LNG
to setting up a re-gasification terminal. Under the agreement both partners
would make efforts to source LNG from international suppliers on spot, short-
and long-term contract basis.
The seven planned LNG terminals will allow exports to nations that have signed
free-trade agreements (FTAs) with the US. With India not on this list, The
external affairs ministry has been asked to intervene for allowing gas imports
from US.
The gas shipments from US will be costlier than current domestic gas prices at
$4.2 per mmBtu, which is subject to revision in 2014. RIL, for instance, is
seeking price approval from the government to sell its coal bed methane gas at
$12 per mmBtu.

32
4.5 Malaysia and Indonesia
As discussed before in the producing countries section as well as Indonesia as
Malaysia are both among the leading producing countries, but are also becoming
important buyers in the market. This is the result of their LNG production being
locked up ion ling term supply contracts and an strong increase in gas utilisation
in their domestic markets.
The first Malaysian LNG import and regasification terminal has been completed
at Sungai Udang in Malacca and will take cargoes from Malaysia's own
liquefaction plants and from overseas.
Malaysia will now join Indonesia as an LNG producer also importing cargoes.
Both Asian nations, still in the top four of global producers, are building up a
network of regasification facilities as their domestic natural gas demand
increases.
Petronas Gas Berhad ,the natural gas unit of state energy company Petronas,
will operate the facility and it is scheduled to begin commercial operations in
August 2012. The capacity of the Malacca terminal is 3.8 million tonnes per
annum of LNG and comprises an offshore jetty of unique design.
The facility is on an island jetty. It consists of two floating storage units and a
new three-kilometres subsea pipeline connecting to a new 30km onshore
pipeline that links to PGB's existing Peninsular Malaysia Gas Utlization pipeline
network. The independent regasification facility is on the jetty itself, unlike other
similar facilities elsewhere. PGB has also expressed its willingness to share the
facility with a third party in line with its open-access policy in terms of gas
supply and distribution.
The LNG for the terminal will be imported from various supply sources globally,
and from the Petronas Bintulu LNG production complex in Sarawak.

33
5 LNG contracting structures and pricing mechanisms
5.1 Introduction
Players in the LNG spot market have understood the benefits of putting in place
master spot cargo trading contracts with prospective trading partners. It is
preferable to negotiate a master agreement rather than spend a similar time on
a one-off sale and purchase contract. A typical form of LNG spot cargo trading
contract comprises two essential parts:
• Master LNG sale and purchase agreement (“Master Agreement”)
• Confirmation notice/memorandum (“Confirmation Notice”).
The Master Agreement consists of all the standard terms and conditions of LNG
trading but with no firm obligation on the seller to sell or on the buyer to buy.
The Confirmation Notice, a form of which is usually attached to the Master
Agreement, sets out the actual purchase and sale of one or more LNG spot
cargoes including details about price, quantity, LNG ship, demurrage, arrival
window, laytime, loading and discharging ports, LNG heel, specifications and
other requirements specific to a particular transaction.
Once signed, the Confirmation Notice constitutes, together with the Master
Agreement, a valid and binding contract.
An LNG spot cargo contract could be either a one-way contract where it is clear
from the Master Agreement which party is the seller and which party is the
buyer; or a two-way contract where a party could be the seller in one
transaction and the buyer in another.
Either form of contract can be further divided into the following: Master
Agreement for free on board (FOB) delivery, Master Agreement for delivery ex-
ship (DES), Master Agreement for delivery at terminal (DAT) or Master
Agreement for both FOB and DES/DAT deliveries. We may see fewer DES
contracts in the coming years because DES has been removed from Incorterms
2010, which took effective on 1 January 2011.
5.2 The Standard Contract
LNG Sales and Purchase Agreements are bilateral confidential arrangements
which typically provide for periodic price discussions over the term of the
contract. Meaning that LNG volumes will be subject to some form of price
renegotiation. The impact of price reviews and “Price Out of Range” negotiations
is to recalibrate contract pricing to reflect market trends.
In today’s tight markets and the robust outlook for short, mid-term and long-
term pricing this would lead this process is expected to generate incremental
value for the producers.

34
As part of their pricing strategy, LNG producers will continue to build protection
against a downside oil price into a significant portion of their r LNG portfolio
through the use of a combination of price floors, S-curves and other mechanisms
as can be negotiated.
80 percent of new LNG output coming on stream from now until 2017 is already
under long-term contract, while short shipping capacity is the main constraint in
the LNG value chain. Quite a few new LNG contracts were agreed in 2011,
particularly for the Australia projects. LNG production in Algeria is now not tied
by "any long-term contracts and is likely to be looking for the high-priced
markets, to the extent that shipping capacity allows it.
5.3 MSAs for spot cargoes
An LNG sale agreement is a fairly lengthy and complex contract. In fact, if one
compares the sale of one cargo to a long-term sale of LNG over 10 years or
more, the main differences relate to terms which are not sale-specific (for
example conditions precedent, annual volume and take or pay, which are all
project-specific rather than sale-specific).
A contract will be on average 50 to 100 pages long and it would be inefficient to
negotiate a long document for each spot sale.
An MSA is a bilateral agreement between two parties to buy and sell LNG
(usually one party will be the buyer and the other the seller but in some cases
the roles can be interchangeable within the same MSA).The MSA will set out the
general terms under which two parties will buy and sell should they choose to do
so.
The parties will need to conclude an ancillary agreement (usually named a
confirmation notice) to buy and sell one or more cargoes. The confirmation
notice will incorporate the terms of the MSA by reference and will contain deal-
specific terms such as price, quantity, delivery point and delivery period (and
also any term that departs from the original MSA). The legal tool of choice for
buying and selling LNG in the short term remains the combination of an MSA and
confirmation notices. MSA terms have evolved over time and a convergence of
terms can be observed.
Industry bodies sought to develop model MSAs for the benefit of the industry.
The Association of International Petroleum Negotiators (AIPN), the European
Federation of Energy Traders (EFET) and the International Group of Liquefied
Natural Gas Importers (GIIGNL) have each prepared a model MSA.
Each model has specific features and all are very high-quality and useful models.
They provide a good model to draft an MSA but also a good precedent to
compare with a draft prepared by a counter-party Unfortunately, no model
seems to have emerged as the industry standard.
While each MSA is different , a lot of similarities do exist.

35
One reason is that before the AIPN/EFET/GIIGNL models were available, a few
existing precedents have inspired several industry players (for example, the
language used in early precedents prepared by BG, BP and Shell have had an
influence on the market). Another reason is that some terms are widely
accepted across the industry. Overall, despite language discrepancy, the
conceptual solutions seem to vary little.
As the short-term market has grown, the relations between the industry players
have become complex. These relations were essentially bilateral in the beginning
(and the bilateral nature of the MSA reflects that). As the market has matured,
they have become multi-dimensional.
The short-term market started small with a limited number of buyers and sellers
and limited LNG sources. The growth of the market was initially driven by buyers
and sellers who were predominantly producers and end-users. Trading may also
involve parties who buy and sell back to back. The result is not only a
multiplication of the parties but also an increasing complexity of the relations
between the parties.
This means that instead of having certain buyers entering into MSAs with certain
sellers, there is pressure for all buyers to enter into MSAs with all sellers and all
traders to enter into MSAs with all buyers and all sellers. More and more MSAs
are being signed and they all differ slightly from each other. How do the parties
manage discrepancy between the terms of their contracts?
An additional factor of complexity is the origin of the LNG bought and sold. Initial
volumes came from producers who had additional capacity. To these volumes,
we can now add diverted cargoes from long-term LNG sales and cargoes bought,
stored and resold. Each type of cargo is transacted under different terms and
from the perspective of legal risk management, the risk of discrepancy between
MSA terms and the terms under which a cargo is bought can only become more
likely. Typically a seller has to deal with more constraints than a buyer. A cargo
sold needs first to be produced and stored. The extraction, treatment,
liquefaction and storage of a cargo may present specific constraints which the
seller needs to manage each time.
From the seller's perspective, the risk profile of its portfolio needs to be
managed legally and it will often appear more desirable to trade on its own
terms and conditions.
In this respect, using a model MSA rather than the seller's in-house MSA may
not improve its risk profile. On the other hand, as the portfolio becomes more
complex, a single MSA with each buyer is less and less likely to contain all
desirable safeguards.
However, when a seller is trading from a portfolio, it is not realistic to enter into
a different MSA for each LNG source. In addition, it would not be commercial to
revisit some of the most negotiated MSA terms when concluding a confirmation
notice. As a result, a seller must ensure that its existing MSAs can be
reconciliated broadly with the terms under which the LNG is available.

36
A bilateral instrument like an MSA was not designed for complex multilateral
contractual relations. Each MSA is concluded under slightly different terms and
the differences between the MSAs may relate to risk areas such as shortfall, LNG
quality and the limitation of liability.

37
6 LNG trading and trading markets
6.1 Introduction
LNG trade routes have been diversifying, a growing number of under-utilized
LNG import terminals in the United States and Europe are re-exporting LNG
cargoes.
Natural gas consumption grew at an annual average rate of about 3 percent
from the 1970s when its large-scale commercial use started spreading around
the world. While LNG trading has grown at a much faster pace, at more than 6
percent since the 1990s, LNG's share in the global natural gas market is still only
around 10 percent.
Thus, LNG is expected to expand its share of gas trades further in the future.
Because of the Qatar mega-Trains, 48 percent of LNG trades in the world
originated from the Middle East and North Africa in 2011. Qatar's additional LNG
production since 2009 has translated into Northwest Europe's increase in LNG
imports.
Figure 13: LNG and Pipeline Trade flows 2011

38
6. 2 Main Players
6.2.1 Portfolio players
Portfolio players what are companies with multiple options in both the supply
and downstream segments - including international oil and gas companies and
midstream players with portfolios of supply and outlets - have been leading the
global LNG trading business.
Having portfolios of both upstream and liquefaction and regasification and
downstream sales at multiple points gives them the upper hand in negotiations
and consequently further expands business opportunities and options. The ups
and downs of the LNG market and the remarkable rise of newly emerging
markets has highlighted the strong positions of these portfolio players.
The UK's BG Group has been a leading player in this field as a front-runner in
several aspects of the LNG business: long-term capacity commitment at a US
LNG terminal; securing portfolio LNG supply with destination flexibility; and
secondary marketing of LNG the company purchases and sells on to different
LNG buyers.
France's GDF-Suez and the Spanish alliance of Gas Natural Fenosa and Repsol
have similar operations.
In addition to these players with a focus on midstream business, super-majors
and other international oil and gas companies have been expanding LNG
upstream and market positions in recent years. They have also invested in North
American unconventional gas plays to boost business portfolios.
6.2.2Japanese players
Japan is expected to remain the largest market for LNG in the world and the
country's developments are expected to have significant impacts on the global
market, even though the country and its LNG importing companies have a lot of
challenges to overcome concerning energy and nuclear policies.
Since the inception of the LNG business in the 1960s, some Japanese trading
houses have brokered LNG import deals for the nation's gas and electric power
companies, participating in the LNG upstream and liquefaction sectors as
minority partners, and facilitating project funding by utilizing Japan's commercial
banks and government-backed financing.
They have evolved their role as an essential element in the global LNG business
according to changing market environments and requirements, by coordinating
short-term and long-term deals between various regions, and not necessarily
limited to Japan.
Future Japanese LNG procurement and business development strategies will be
more important because of the nation's energy security requirements.

39
6. 3 Long term vs. Short term LNG Markets
A short-term LNG market started developing at the beginning of the 1990s. It
grew from less than 2 percent of LNG trade in 1993 to more than 20 percent
today. The total volume of LNG traded globally reached 223.8 million tonnes per
annum. Short-term LNG trade volumes are projected to increase at an average
rate of 11 per cent per annum for the period up to 2015. This growth rate is
higher than the total growth rate for the LNG market, which BP estimates will be
7 per cent per annum; thus the proportion of short-term LNG trades is set to
grow.
Figure 14: The World Wide Short Term LNG Market
The purchase of spot cargoes in the last couple of years was mostly by
Northwest Europe (in particular, the UK) and Asian countries such as Japan,
Korea, Taiwan and China. Japan has been scooping up large quantities of LNG
since March 2011 for power generation, after the Fukushima earthquake
paralyzed several of its nuclear power plants. Korea, requiring cargoes mainly
for heating during winter months, has been a major participant in the short-term
and spot market. Taiwan and China are catching up. Although China’s activities
in the spot cargo trade have been noticeable in recent years, further growth is
likely to be limited due to restrictions in access to terminal and pipeline facilities
in China, its inability to pass on the market price to the heavily regulated
domestic gas market, and recent hikes in shipping costs.
In terms of LNG suppliers, in addition to the traditional resource-back suppliers
such as Qatar, Australia, Indonesia, Trinidad and Nigeria, increasing numbers of
multi-national oil companies, national oil companies and investment banks are
setting up trading houses in major trading hubs such as London, Houston and
Singapore to service LNG spot cargo customers from Europe and Asia.
The prospect of East Africa (Mozambique and Tanzania) becoming LNG exporting
nations has attracted attention in the market. The rise of East Africa as LNG
exporting nations will in no doubt present a welcome alternative for LNG buyers.

40
6. 4 Factors driving the LNG spot cargo trade
Traditionally, the LNG market was dominated by long-term off-take contracts.
Without such arrangements it would not have been possible to make the
significant capital investments in extraction, transportation, storage and re-
gasification that are all necessary to build the LNG supply chain. Such
arrangements offer very limited rights to upward and downward quantity
adjustments and little, if any, cargo diversions. As the demand and supply of gas
is influenced by factors including weather conditions, seasonal gas consumption
peaks, delay in or disruption of gas domestic production or power supplies, price
and availability competing fuels, and growing demand for cleaner and safer
energy fuel, the spot and short-term LNG trade offers the flexibility to fill in the
gaps caused by the supply shortages and to arbitrage prices between alternative
LNG markets.
The increase in the use of cargo swaps to reduce shipping distance and the
continuing investment in new build or converted floating re-gasification and
storage units to provide alternative shipping and terminal capacity will add
further a dimension to the spot cargo trade.
6.5 Trends and challenges
So far, the LNG spot cargo trade has exhibited a healthy growth. In The market
there are of trading models used, including open tenders for multiple and single
cargo sales, brokered trades, cargoes sold in chains, and speculative trading
positions taken up by non-traditional participants including investment banks.
Although the LNG market is traditionally divided into two distinct markets, the
Atlantic Basin and Asia Pacific markets, with minimal trade between the two, the
increasing trend is that LNG cargoes will be traded between the two due to the
high LNG price premium in Asia and surplus supply and subdued gas
consumption in the Atlantic Basin.
From 2009 to 2010, China was a popular destination for LNG spot cargoes.
However, the recent earthquake in Japan has changed the rules of the game
substantially in the region. Japan has now become the largest LNG spot cargo
purchaser in the region and has driven the price of LNG spot cargoes to a level
where China and other developing countries such as Thailand, Vietnam and the
Philippines are under pressure to revalue their plans on expanding LNG spot
cargo imports. It is not clear when the situation in Japan will improve so that
other players in the region can resume their roles in the market.
There are challenges ahead for further growth. As mentioned above, the
majority of LNG carriers in service today are designed and built to provide
services under a specific long-term contract. With little standardization between
LNG projects around the world, sourcing or constructing an LNG carrier which is
compatible with most, if not all, existing terminals can be challenging.

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