essentials of lng trading and risk management report
TRANSCRIPT
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: [email protected] 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.
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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".
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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
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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.
6.2.2 Japanese 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.
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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.
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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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Discussions on ship-to-shore compatibility will need to be held well in advance of any negotiation on spot cargo sales.
6.6 Singapore might become the LNG Trading Hub for Asia
A gas trading hub essentially a pricing point for trades of standardised contracts; similar to the Henry hub in Louisiana in the United States.
A trading hub has the ability to affect physical trades. For a successful trading hub to develop there should be significant demand for energy in
neighbouring markets to create the infrastructure facilities required for
trade to take place.
For infrastructure development, a junction of pipelines has to be in place at an optimal geographical location. In some cases, this may require a
strong regulatory system to be present. Both infrastructure development and the necessary regulatory backup help to create sufficient volume and
volatility for paper trades to take place when price discovery and contract flexibility are introduced.
In addition to infrastructure and system requirements, contract flexibility is required to serve different buyers and sellers, and there should be both
short-term and long-term contracts with different volumes and delivery options.
There are growing LNG re-export activities from US terminals with
reloading facilities. Currently, there are healthy levels of commodity trading taking place and significant multi-directional flow of LNG around
the globe compared with the one-directional flow from the Middle East to
North Asia in the past.
Although improvements can be seen in the level of international trade, there is no price convergence and different prices are established globally.
Asia presents a perfect opportunity to further develop LNG trading because the region consumes about 50 percent of the flexible quantities
of LNG traded.
Moving forward, new Asian terminals will further facilitate regional trading
in Asia, especially by 2018 with increasing demand and tightening supply conditions.
The price and texture of regional flows matter to the development of an
LNG trading hub. With the prospect of five to eight new terminals coming up by 2020, there would be sufficient aggregated capacity on the supply
side to create a new and transient Asian market. However, the level of cooperation between Asian buyers has important impact because power
price affordability in developing markets will impact the market size for
flexible quantities traded.
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What is the potential for Singapore to be an Asian hub for LNG trading?
Assuming there is no restriction on growth of supply, demand for LNG is
expected to grow from 3MMTPA to 8-10MMTPA for Singapore. Furthermore, the development of Jurong Island terminal as an open
access and multi-user terminal and the natural fit for terminals in
Singapore further develop our potential for LNG trading.
However, there may be other limiting factors for the development of Singapore as an Asian hub. This includes the inability to effectuate
physical trades, emerging competitors such as Malaysia, and the increasing demand growth in North Asia. Furthermore, the tightening
conditions on the supply side coupled with demand for long-term contracts and the lack of seasonal demand in the domestic market might
further impede market development.
The development of a regional LNG hub will facilitate the process of
greater price discovery. In the longer term, suppliers would also gain sufficient comfort to sanction finance investment decisions with higher
merchant off-take profiles and lenders' blessings.
Regional power producers would be able to sanction more projects because more flexible LNG supply deals are available. To successfully
develop a regional LNG hub, flexibility in addition to pricing are the keys
as contracts need to provide sufficient variations to cater to buyers and sellers. Moving forward, interest in financial trades is expected to increase
as physical trade grows.
6.7 Overview of current Asian Spot Market
A nosedive in natural gas spot prices in Asia in June/ July 2012 marks the end of bullish Japanese buying following the Fukushima disaster and the likely start of
higher supply and lower prices for gas shipped to Europe.
The price of LNG in Asia has fallen 25 percent since June as collapsing demand in the region silences, some say permanently, the world's biggest spot market for
the fuel. That has created an oversupply of about 10 LNG cargos per month with sellers now looking for new buyers outside Asia.
Drilling advances have led to a huge glut of shale gas in the United States leaving Europe as the best alternative to Asia for shipped LNG. The forecast for
July gross LNG imports into Europe is 9 percent higher than the June gross LNG import total. Cargoes that would have headed for Asia have already started
arriving in Europe, ship-tracking data indicates, with two Nigerian cargoes delivered to a new terminal in the Netherlands and the BG Group-led Dragon terminal in the UK set to receive a Nigerian cargo.
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Seaborne deliveries to Europe have slumped sharply for more than a year as tankers were diverted to Asia to take advantage of the biggest price differentials
since 2009.Japan's increased use of LNG to offset closed nuclear sites following the Fukushima nuclear disaster in March 2011 year helped spur the move, which
saw Asian spot prices that were roughly double those in Europe.
But industry officials say Japanese buyers have moved out of the spot market in June/July 2012 , having squared away supply on short- and medium-term
contracts instead.
Atlantic Basin producers wouldn't even consider sending spot cargoes to Asia now. So more cargoes from Algeria, Norway and Nigeria are pushed into Europe, raising the UK gas market as one possible destination. There seems not be any
demand coming out of Asia anymore. It looks like the Japanese are not buying spot supplies anymore because they signed so many medium-term deals.
Unthinkable six months ago, the admission reflects a growing consensus among producers and traders that top importer Japan has had its fill of the fuel on a spot basis.
Spot LNG prices in Asia have been in freefall since June 2012 , hitting $13.80
(8.91 pounds) per mmBtu mid July and slamming shut once lucrative arbitrage opportunities.
The onset of deliveries to Japan under multi-year deals have also stoked fears
that markets in Asia may not recover in 2012.
LNG prices peaked during the summer of 2011 because the Japanese were buying for the winter - but this does not seem to happen in 2012.
Even in China and India, there is no aggressive buying that could be excepted
when prices drop nearly 25 percent in a month.
New supplies from Australia, Nigeria, Norway and Indonesia have contributed to
the price downturn, while packed storage sites are dampening demand even further. This could be the start of Europe seeing more spot cargoes.
It has been a fast fall for traders who saw bumper profits as Asian spot prices in
May 2012 hit highs not seen since mid-2008. From nuclear restarts in Japan to higher LNG spot supply due from new production plants in Australia and Angola, pessimism over the state of the Asian market has triggered a hunt for
alternative buyers.
What's spooking the market right now is Angola - which will start selling cargoes on a spot basis into the market in September. That would mean extra spot
supply coming into the market in a shoulder month, a period of seasonally low demand from Angola's new liquefaction plant, which will provide four to five additional spot cargoes per month, is set for late summer or early autumn 2012.
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Japan's decision to bring back some idled nuclear output is also weighing on LNG price outlooks. Fukushima prompted the shutdown of all 50 of Japan's nuclear
plants, which previously provided about a third of the country's electricity. This is very symbolic and leaves Japanese utilities in a more comfortable position
with the hope that the government will help them," the trader said.
A very tight Asia-Pacific LNG market is expected over the next few years. LNG demand is surging among Asian nations in tandem with rising natural gas
consumption worldwide. Following the start-up of Pluto and Angola LNG later this year, no new supplies of LNG are due to enter the market until late 2014 or 2015. Combined with the large and unexpected increases in demand following
the Fukushima earthquake, this has caused the LNG market to tighten significantly, putting upward pressure on both short and long-term LNG prices,
as well as shipping rates. Possible delays to Australian projects under construction will further exacerbate this period of tightness and sellers with short-term volumes available between 2012 and 2015/16 will be well positioned
to benefit.
Imports of LNG into Asia-Pacific region are projected to increase by an average of 7 per cent a year to reach 217 million tonnes of LNG equivalent in 2017.
China is projected to account for a third of the total increase in the region's LNG imports. Forecast increases in global demand for LNG and the long-term contracts to secure future supplies have underpinned investment in additional
liquefaction capacity.
Between 40 and 50 MTPA of LNG supply from North America is expected to enter global markets by 2025, noting that US and Canadian projects face very
different drivers and constraints than the Australians . North American exports of LNG are expected to make up only about 10 percent of global supply by 2025,
compared to nearly 30 percent from Australia and 20 percent from Qatar.
Following a few years of consolidation of long-term prices into Asia at the
traditional level of 85-90 percent indexation to oil price movements, post-March
2011 there was some uncertainty about whether the events in Japan would lead
to a change in pricing. In fact, price outcomes since March 2011 have seen
further consolidation, and long-term LNG prices for delivery into Asia remain
close to $15/MMBtu when oil is priced at $100 per bbl. A number of recent deals
from greenfield projects include so-called S-curve mechanisms. These provide
relief to the customer in the event of very high oil prices and provide some
protection for the seller against a downside oil price.
Recently reported SPAs between pre-FID US export projects and Korea and India
are priced on the basis of a capacity charge plus a commodity charge linked to the Henry Hub natural gas benchmark. It is expected that buyers will initially
limit their portfolio exposure to Henry Hub and continue to accept oil-linked pricing for Asia Pacific projects. Should Henry Hub remain low for an extended period beyond initial deliveries later in the decade then this could be expected to
only progressively influence Asian pricing formulae through periodic price review mechanisms.
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6.7 Role Japan
Japan cut purchases of spot liquefied-natural-gas cargoes by 27 percent in May 2012 from a month earlier as prices soared to near a record amid the closing of
domestic nuclear power plants.
Supplies for immediate and short-term delivery from the Atlantic Ocean area dropped to 847,624 metric tons in May from 1.16 million tons in April. Prices of
spot LNG climbed to about $920 a ton, or $18.93 per MBTU, 16 percent higher than last year’s average. The fuel reached a record of $25 in 2008.
Japan shut all 50 of its nuclear reactors for safety tests after last year’s
earthquake and tsunami, halting atomic power generation for the first time in more than four decades . As Japan is slowly restarting some of its nuclear facilities, spot cargoes will start to moderate in the second half of 2012 .
The Japan Crude Cocktail, a basket of prices for oil imported into the country used to calculate LNG prices.
6.8 Arbitrage; Flexibility in contracts
With the growth of LNG supply which is increasingly flexible in terms of destination, regional markets are becoming progressively more
connected. A decade ago, when the LNG industry was based exclusively on long-term take-or-pay contracts and the number of market players
was limited, the impact of price signals, if any, was weak. The liquidity of the „flexible‟ LNG market has increased in tandem with the growth in the
number of LNG producing and consuming countries, the appearance of
some uncommitted volumes of LNG and development of arbitrage activity.
Price differentials between the North American, European and Asian markets
have created opportunities for LNG arbitrage to take place.
LNG arbitrage could be defined as follows:
“LNG Arbitrage can be defined as a physical cargo diversion from one market to another, which offers a higher price. The diversion of the cargo can be regarded as arbitrage if the cargo was initially committed
to the first market and to the initial buyer in a commercial contract.”
The two key drivers for arbitrage are:
1. Commercial
2. Operational
The Commercial driver is the ability to take advantage of price differentials between the markets, which arise due to differing pricing structures, variations in the relative balances between supply and demand and market inefficiency.
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Operational reasons for LNG arbitrage include financial loss minimization in case of plant outages, overfull storage tanks or force majeure. Arbitrage for
Operational reasons may also occur for political reasons such as embargoes or conflicts.
Redirection of LNG cargoes can be regarded as arbitrage only if, according to the contract, they were initially contracted to be delivered to another market.
The margin resulting from the arbitrage is usually shared between the seller and the initial buyer. The participants of the deal can be: the seller, the initial
buyer, the end buyer, an independent trader/trading team (intermediary), and so on.
6.7 Recent Developments
There have been noticeable increases in short-term contracts backed by the
recent surge in global LNG production capacity. Profound changes in the market environment have affected significantly the way LNG business is conducted and made Japanese and other Asian players aware of the need to improve the terms
and conditions of their purchases.
It has become more obvious that portfolio players like BG Group, GDFSuez with flexibility in supply volumes and marketing outlets have the upper hand in
negotiations. As 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.
As Asian 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.
6.8 Arbitrage opportunities
The Figure below clearly indicates the arbitrage opportunities that do exist between the US, UK markets and these in Asia like Japan. The spread between the 3 markets is wide enough to make up for the transportation expenses.
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Figure 15: US, UK, Japan Price Benchmarks
6.9 LNG Risk Management
6.9.1 Risks in LNG Markets
Operating in the LNG markets has become increasingly difficult in recent
years. The EU credit crisis and the continuing aftermath of the Fukushima nuclear disaster have significantly increased the challenges faced by
already over-supplied natural gas and LNG markets. Managing the risks of LNG markets means being aware of market, credit, foreign exchange and
systemic risk
6.9.1.1 Risks in physical flows
LNG is about long-haul shipping. Terminal operations requires a certain inventory management dynamic and enterprise resource planning.
Arbitrage opportunities present themselves in destination, forex, and local market prices that are route specific and can be fleeting.
6.9.1.2 Currency risk
The continuing crisis in Europe, combined with the global economic
slowdown, has and will continue to adversely impact the value of the euro against the US Dollar. If volatility rises, forex risk can become very
significant, especially amidst a future round of quantitative easing. Whoever holds the cargo needs to hedge both the asset and the currency.
Matching horizons may be particularly challenging, especially when considering arbitrage opportunities for Atlantic Basin cargoes.
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6.9.1.3 Systemic risk
LNG’s relatively small footprint and sensitivity to global conditions means that managing the optionality in a cargo requires dealing with both
market and currency constraints. The current recession will continue or some time until asset values are rationalised and economies rebalance.
Liquidity and collateral issues will certainly be important in the near term. There are many reasons to monitor systemic risk metrics, collateral and
funding.
6.9.2 Geo Political Risk Management
Next to the common risks available in energy trading like market or price, credit and forex risk, there is a new risk has become relevant that needs the risk
manager’s attention; geopolitical risk
The increasing influence of geopolitical risk on energy markets is forcing risk managers to reassess their risk management strategies around such event-type
risk.
Energy markets are influenced more by geopolitics and macroeconomics than pure supply and demand fundamentals. This has left risk managers needing to
reassess how best to measure and manage geopolitical risk.
The increasing influence of geopolitics is a trend that might continue for the foreseeable future for several reasons such as the scale of unrest in some of the biggest energy-producing countries is at historically high levels. Recent events
have included the Arab spring, the North African revolution and Iraq, and the stand-off between Iran and the West over its nuclear programme.
The financialisation of the market also contributes to the trend of prices reacting
more to headlines than supply and demand. These and other reasons make it more necessary than ever for risk managers to put plans in place for measuring,
managing and even mitigating geopolitical risk.
Geopolitics has long exerted an influence on oil and gas prices due to the fact that physical production is often located in politically unstable countries. But the scale of the instability in recent years has been the key factor in pushing it to the
forefront of risks companies need to address.
On the one hand, there are opportunities in countries with low political risk, such as Canada’s or US shale gas, but where there are great technical
challenges, so you replace political risk with other concerns, or more conventional types of oil and gas, companies are all going into places that are
far more difficult, politically speaking, than they would have gone to before. It’s an industry-wide trend that everybody recognises.
It’s also worth noting that political risk isn’t always confined to countries renowned for political instability. For example, the political will of the US in
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terms of allowing the production of shale gas will have a huge bearing on the gas industry in the future, with natural gas prices likely to soar if the US changes
its stance on shale production.
All this has put an increased focus on improving the management of geopolitical risk. In the past, it has tended to be an inexact science, with it being difficult to
predict or measure the consequences of a low-probability geopolitical event occurring on a wide enough scale to affect a market.
There are two major ways in which companies can address geopolitical risk.
1. By diversifying their physical portfolio so they aren’t overexposed to any
particularly risky country or area. 2. By improving the way they model and measure risk, integrating it into
wider financial risk management in order to get a better geopolitical risk
profile.
The first approach often occurs as part of a company’s investment decision. Geopolitical risk as “event-type risk that people are seeking to incorporate in
particular into their investment decisions. Like many event-type risks, geopolitical risk has challenges in term of the data that could be observed.
By building event models or event descriptions the investment decisions could
be stress tested.
Traditional risk management techniques that address geopolitical risk for
corporates that have physical assets typically involve diversifying one’s portfolio
so that assets are not concentrated solely in one area. Too much concentration
of a portfolio in one country or even in one region should be avoided.
Using local partners or joint ventures could also lower the risk. Having a good local partner could help insulate but also it would help in terms of having the
knowledge of when the situation is bad.
As energy companies often have investments that are long term and physical, they should look at a long time horizon when considering whether to go into a
country or not. As an example, if you look back at Russia over the past 20 years, there have been good times to invest and there have been bad times to invest. You’ve had people pile in because the returns looked good, and then find that
anyone making too much money has some of their business appropriated.
As there have been a number of high-profile cases of this in the energy industry, more companies need to spend more time examining long-term outlooks and not
just present situations. You have to think about whether a country will be stable for the next 10 years and whether the current framework will continue.
As geopolitical issues are increasingly influencing market and price risk, so
companies that do not have a physical presence in these regions can still feel the fallout. As global oil prices remain vulnerable to supply disruption, news coming out of areas such as Nigeria or Iran can be a determining factor in oil price
shocks.
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Markets aren’t great at dealing with these geopolitical risks, partly because they are quite hard to quantify.The risk associated with very low-probability, hard to
define, but potentially huge-impact events, is hard for markets to really price adequately.
Hedging programmes are another way of limiting risk if physical exposure is
inevitable. In the past decade, companies have tried a lot of things. Whether it’s an airline or an industrial or a utility, they’re doing all they can to reduce
exposure from an efficiency and an operational standpoint, but generally there’s not a lot of flexibility for many of these companies in reducing their exposure.
If there is a concern that oil goes to $200 a barrel, they’re not in a position at this point to reduce their usage. They’ve already done that from an operational
standpoint, so the next stage tends to be a strategy in terms of hedging against price spikes. In the end, that goes back to scenario planning and stress testing
for a particular portfolio.
6.9.3 Dealing with Market Risk; Hedging Instruments
Up to 2011 there were no instruments available in the market to hedge the pure
LNG price risk exposure. The only instruments available were oil derivatives to
manage the exposures to the oil price in the long term contracts. However due
to significant growth in LNG spot trade particularly in Asia, some indices were
developed like the Platt’s Japan Korea Marker (JKM) that could be used as
reference to swaps and other financial instruments.
The first ever financially settled LNG swap was executed by Citi and an
undisclosed oil major in January 2011. A swaps market for LNG is set to take off in Asia as players look to hedge the growing volume of physical spot trades in
the region. These contracts could also be used by player sfrom other parts of the world that are active with arbitrage.
Trade platforms and exchanges like ICE and CME are now offering LNG Swaps
The world’s first cleared LNG swap traded on 16 July, 2012. The contract settles on the ICIS East Asia Index (EAX) for physical LNG. The deal was brokered by
Tradition over the CME Direct trading platform and has been cleared by CME Europe.
The deal was done for September at $13.90/MMBtu.
From 16 July the NYMEX also launched the East Asia Index (ICIS Heren) Swap
futures contract for open outcry trading, having received approval from the Commodity Futures Trading Commission (CFTC). The product is to be cleared
through CME ClearPort.
Four ICIS Heren LNG swaps, including the East Asia Index swap, were already available for clearing through CME Clear Europe, from 16 April.
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Up to this point, there has been a very small over-the-counter swaps market for LNG, with a limited pool of counterparties and no clearing services.
ICIS iprovides transparency for physical LNG trade. It publishes five regional
indices and 21 country-specific assessments for spot LNG delivered into the world’s major LNG import terminals. It also publishes FOB assessments for all
major producing regions and FOB reload assessments.
The EAX is an index for the DES price into Japan, South Korea, China and Taiwan. The prices for the four countries are also assessed separately. The price
series has been published daily since June 2010. Relevant bids, offers and deals are also published.
IntercontinentalExchange (ICE), a leading operator of global regulated futures exchanges, clearing houses and over-the-counter (OTC) markets, recently
launched a new LNG cleared swap contract based on the Platt’s daily assessment for the Japan/Korea Marker (JKM).
The Platt’s JKM, introduced in 2009, reflects the daily open-market value of spot
LNG delivered to Japan and South Korea on a daily basis. It has since become a benchmark reference in the industry for calculating price differentials for Asia-
Pacific supply source and destination markets and is increasingly used in outright contract pricing.
CME Group (CME) launched a liquefied natural gas (LNG) swap futures contract that is also based on the Platts JKM.
6.9.4 Case Study: BG's LNG hedging policy
BG has been known for its hedging activities in protecting its cash flow against unpredictable movements in the spread between oil prices and NYMEX Henry Hub natural gas futures.
The company forecast an overhang in the LNG supply market in 2008 and acted
accordingly and it worked. In 2012, BG is again substantially hedged and the opposite is the case in 2013 when the company said it would be "unhedged".
At a meeting with banking analysts, BG CEO Chapman was asked why the UK-based LNG player would not have hedges in place in 2013, and how he thought
the spread would go.
"Very simply on hedging you know the origin of this? We stood up in 2008 and said we'd hedged all this stuff out in 2007. People thought it was a very good
idea. Actually the market went a little shorter a little earlier than expected. We had hedges in place and rather wished they'd come off. On the whole these
hedges have done the trick and given us stability.
"When we've got the hedges in place we're telling you what the performance is going to be. That can go to one side. Now we get to 2013. No hedges in place - we're substantially unhedged.
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Plus the fact is, you're getting more skilled at understanding how we're doing it.
With the data we have given, you will be able to estimate with some accuracy
the picture going forward. So, hedges are in the past."
Asked again to clarify, and given the current environment in the energy industry, Frank was asked again why he wouldn't want to hedge out some of that spread
now. Here is what he said:
"The whole way we've made money in this business over the years, I mean it is true we've shifted where we've taken money and we've taken commercial
positions in different points of the cycle.
"You know we make money out of ships, then we transfer that to making money out of terminals, and then we transfer that into making money out of new supply
and building a customer base in the Atlantic Basin, and a customer base in the Pacific, and then having an equity LNG supply over there, and so and so forth. So the game rolls on.
"We'll take these positions from time to time like we'll take positions on the
quantity of LNG we don't want to sell and which we want to keep liquid.
"And all this overall picture I just put in a box which says 'commercially sensitive.' You know the way we move this business around. The way we mature
it. The way we try to keep ahead of the competition, change the paradigm. I put all that in a box and say I'm not telling you what we're thinking - okay? Sorry. I
think it's good to be a bit secretive every now and then."
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7 Shipping and LNG Trade Flows
7.1 Introduction
Shipping is a key component in the LNG supply chain. As the cost of building an
LNG carrier is many times more than building an ordinary vessel, owners of LNG carriers prefer to support investment decisions with long-term supply or charter commitments. With the development of spot and short-term trade, some players
have designated a small number of LNG carriers for LNG spot cargo trade.
While there were 380 LNG carriers in the world LNG fleet, and another 70 vessels were under construction, there was a shortage of shipping capacity
leading to very high charter rates. The daily chartering rate of LNG tankers has been skyrocketing, indicative of the shortage of spare tanker capacity. Rising
rates were mainly driven by the higher spot LNG demand in Asia after the Fukushima disaster and reached a peak in the first quarter of 2012, with charter rates as high as $150,000 per day.
While the rise in LNG spot prices slowed towards the end of 2011, market
players were eager to secure near-term LNG tanker capacity in preparation for the foreseeable tight freight market in 2012.
7.2 Charter Types
Traditionally transportation of LNG cargoes on time charter terms were favoured. These are usually for lengthy periods, often up to 20 years However, as the industry continues to develop, a growing number of trips are being arranged on
a short-term basis.
Whilst single voyage time charters (“trip” charters) have provided a stop-gap solution, in order to develop a viable spot trade in LNG cargoes a voyage
charter-party form, by which parties can quickly agree a contract for a single voyage to move a single cargo, is clearly desirable.
The industry has seen a rapid growth in spot and short-term trades over the last 10 years, in particular since 2005. These short-term cargoes seem set to
increase in light of the continued interest in arbitrage by major producers and portfolio players.In spite of the burgeoning interest in shorter-term trades, the
LNG shipping arrangements for those trades have evolved slowly.
The International Group of LNG Importers (GIIGNL) recently published a standard form LNG Voyage Charterparty, the first of its kind.
A voyage charterparty is, as a general rule, a more standardised form of
agreement than a time charterparty and is specifically tailored to the requirements of a single voyage. Whilst a time charterparty can be used for a shorter trade, the standard form requires amendment to remove the provisions
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that do not apply, and to add in provisions which are usually missing from time charters (such as demurrage and laytime).
The result is that time can be lost in negotiating contract terms rather than
getting on with the voyage in question. In a spot market where time is of the essence, this can be a significant disadvantage. By contrast, a voyage
charterparty is designed to be negotiated and agreed in the shortest possible time. The focus is on limiting negotiation to the key commercial terms.
To that end, the LNG Voyage Charterparty is separated into two parts. In the
first part the parties will agree commercial aspects such as the freight rate, voyage length, laytime, demurrage and loading/destination ports The second part of the LNG Voyage Charterparty contains the mechanics of the charterparty.
These generally will remain unchanged from voyage to voyage unless a specific revision is required.
Figure 16: LNG Shipping Supply
Shipping oversupply was leading to lower fleet utilization Figure 17: Fleet utilization
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What lead to lower freight rates. Freight rates dropped from above 100,000 dollar per day in the early 2000s to as low as 20’s in 2010
Figure 18: Freight rates
The Shipping demand is trending to increase progressively through 2016. As
LNG demand growth is expected to be strongest over the next few years, driven mainly by Asian consumers. The Asian markets will likely underpin shipping demand as other markets - particularly Latin America – and Europe will boost
demand. As a result long haul arbitrage trade may take a more prominent role. Figure 19: Ship capacity
The growth of LNG fleet supply is expected to moderate over the next six years.
The additional order requirement to satisfy replacement needs and new exports is equivalent to about 25 standard-size ships, by 2016.
Ships available to spot charter is limited. Recent multiple fixtures has reduced
the pool of uncommitted modern, standard-size ships. Some speculatively-
ordered new buildings are available, but other existing modern ships are already
assigned to longer-term business.
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A large number of ships built in the 1970s and early-1980s are coming off long term trades. Best ones will initially trade conventionally for the
medium term given the current high demand. Currently 10 - 30 ships fixed or under consideration for FSRU/FSO projects – leading to a further tightening in
fleet supply and demand. Eventually most will find offshore projects (FSO/FRSU).