Morten Frisch Gasex 2010 Paper 14 November 2010

Version 2, updated 14 November 2010

GAS MARKET DYNAMICS
AND THE FUTURE PRICING OF SPOT LNG

To be presented at
Plenary – Panel Discussion I: Energy Supply Security

GASEX 2010 CONFERENCE
Taipei, Taiwan
Wednesday, 24 November 2010

Morten Frisch
Senior Partner
Morten Frisch Consulting

Morten Frisch Consulting
6 Holmwood Close
East Horsley
Surrey KT24 6SS
United Kingdom

Tel: +44-1483-284248
Fax: +44-1483-285099
Email: office@mfcgas.com
Web: www.mfcgas.com

Morten Frisch Consulting accepts no liability for commercial decisions based on the content of this paper. Although the paper is copyright of
Morten Frisch Consulting, quotes from the paper are permitted, provided full references to the paper and Morten Frisch Consulting are made.
Onward transmission or copying of the paper is allowed in its original form only.

Gas Market Dynamics And The Future Pricing Of Spot LNG, Morten Frisch, GASEX 2010

Contents
About the Author .................................................................................................................................... 3
Abbreviations .......................................................................................................................................... 4
Executive Summary................................................................................................................................. 5
Causes of the LNG Surplus....................................................................................................................... 6
a) Unconventional Gas a Challenge for LNG .................................................................................. 6
b) World-wide Liquefaction Capacity Developments ....................................................................... 7
c) Uncontracted LNG Availability .................................................................................................. 8
d) Recession Impact on Gas Demand ........................................................................................... 9
LNG Spot and Short-term Trading ...........................................................................................................10
Commercial Model for Spot and Short-term Trading .................................................................................15

Tables
Table 1: Projected Incremental LNG Availability ........................................................................................ 7
Table 2: Flexible LNG Sales as Percentage of Total LNG Exports ................................................................ 8
Table 3: Asia LNG Demand Q1-Q3 2010 ..................................................................................................10

Figures
Figure 1: Spot and Short-Term LNG Exports ............................................................................................. 8
Figure 2: Interrelations of LNG Markets ...................................................................................................11
Figure 3: Relationship Between Henry Hub and NBP Prices .......................................................................11
Figure 4: Price Relationship between HH, NBP, BAFA and Japan LNG Import Prices....................................13
Figure 5: Current LNG Spot Price Dynamics (schematic) ...........................................................................13
Figure 6: Japanese DES Spot Prices Potential Range ................................................................................14

Keywords: 1. Gas Markets. 2. LNG Markets. 3. LNG Supply. 4. LNG Pricing. 5. Spot LNG. 6. LNG Trading.
7. LNG Price Benchmarks. 8. LNG Short-term Sales. 9. Platform-based LNG Trading. 10. Market-based LNG
Price Discovery. 11. US LNG Imports. 12. European Gas Market. 13. LNG Trade Routes. 14. Shale Gas.
15. Unconventional Gas.

© 2010 Morten Frisch Consulting
2


About the Author

Morten Frisch, Senior Partner, Morten Frisch Consulting (MFC)
Morten Frisch’s career developed in parallel with the gas industry in his home country of Norway. He has
more than 35 years of hands-on experience addressing strategic, commercial and operational issues along
the entire value chain for LNG and pipeline gas. This experience stems from work for the Norwegian
Government, multinational oil companies and as a consultant since 1990.
The first time Morten Frisch led a gas sale negotiation was in 1976, the year his first dealings with LNG
receiving terminals (Everett and Cove Point terminals, USA) also took place. His first LNG marketing work
was conducted in 1980 (for the then Phillips Petroleum’s Bonny LNG project in Nigeria).
In 1977 as part of gas price indexation formulae design work, Morten Frisch was instrumental in the
development and drafting of the Norwegian and Swiss law Price Review and Price Re-opener clauses, now
universally used in long - term gas sales and purchase contracts for the supply of gas to Continental Europe.
In 1993 together with Freshfields solicitors in London he converted this language to English and New York
law. The resulting Price Review and Price Re-opener clauses are now commonly used in long term Atlantic
Basin LNG supply agreements.
Since 1990 Morten Frisch has conducted extensive work related to natural gas in the Middle East, Iran,
Russia, and Central and Western Europe. He has also provided consulting services to clients or projects in
North and West Africa, Japan, Australia and New Zealand. He is familiar with gas developments in North
America and has monitored and analysed unconventional gas developments for more than ten years.
Morten Frisch and MFC’s consulting practice deals with a variety of gas issues, with a high number of
assignments addressing gas pricing issues, commercial optimisation, risk mitigation strategies and methods
for operations in rapidly changing gas market environments. He has been called upon as an expert witness
in arbitrations and court cases dealing with gas contract related issues, particularly in disputes involving price
review/price re-opener clauses.
Morten Frisch has acted as a lead negotiator in gas sales and purchase negotiations for clients. In the past
he has also advised governments on international gas issues. He also advises clients on the organisational
structure and staffing of gas-related projects, and he has acted as a mentor for their novice commercial gas
staff. He is an established professional in the field of gas training.
Since 2007 Morten Frisch has been supporting clients in the development of a more transparent and reliable
way to establish gas market-based pricing of spot and short-term LNG sales.
Morten Frisch is a chartered engineer (Sivil Ingeniør) in his home country of Norway and an economist
(degrees from University of Newcastle upon Tyne, UK and Massachusetts Institute of Technology (MIT),
Mass., USA). He is a member of the Society of Petroleum Engineers (SPE) (since 1975), the International
Association of Energy Economics (IAEE), the British Institute of Energy Economics (BIEE) and a founding
member of the Norwegian Petroleum Society (NPF). He has published a number of articles addressing
strategic and commercial gas issues. He is frequently invited to give presentations at major international gas
and energy conferences and appears regularly as a guest on major TV stations’ business programmes.

3


Abbreviations

BAFA = Bundesamt für Wirtschaft und Ausfuhrkontrolle is the name for the German Federal Office of
Economics and Export Control. Monthly average unit cost of imported natural gas across all border points is
published by this Federal Office on a monthly basis in €/TJ.
Bcm = Billion cubic meters (106).
CEGH = the Central European Gas Hub at Baumgarten, established by OMV Gas & Power GmbH. OMV and
Gazprom have recently signed a Cooperation Agreement to jointly develop the hub with the aim of it
becoming the largest trading platform in Continental Europe (Press Release of 25 January 2010)
DES = Delivered Ex Ship.
GASPOOL = joint company which operates the market area cooperation of DONG Energy Pipelines GmbH,
Gasunie Deutschland Transport Services GmbH, ONTRAS – VNG Gastransport GmbH and WINGAS
TRANSPORT GmbH & Co. KG.
Henry Hub (HH) = Henry Hub is the pricing point for natural gas futures contracts traded on the New York
Mercantile Exchange (NYMEX). It is also a physical point on the natural gas pipeline system in Erath,
Louisiana.
Mmbtu = Million British Thermal Units
Mtpa = million tonnes per annum.
NBP = the virtual National Balancing Point in the United Kingdom’s network of pipelines forming the national
gas transmission system and the hub in Europe with the largest trade volumes and the greatest trading
depth.
NCG/EGT = a joint company which operates the market area cooperation of Bayernets GmbH, Eni Gas
Transport Deutschland S.p.A., E.ON Gastransport GmbH, GRTgaz Deutschland GmbH, GVS Netz GmbH.
After its most recent expansion, it is now referred to as simply NCG (Net Connect Germany). In 2010 it
became the largest trading hub after TTF in Continental Europe.
PEG-Nord = the virtual trading point in the North of France, created in 2009 when the three zones (PEG
OUEST, PEG EST, PEG NORD) merged into one.
PSV = Punto di Scambio Virtuale, is the name of the Italian Virtual Trading Point established by Snam Rete
Gas.
Sm3 = a cubic meter of pipeline-quality gas at standard conditions with gross calorific value of 39 MJ.
TTF = the Title Transfer Facility, the virtual national balancing point in the Dutch pipeline network and in
2010 the largest trading hub in Continental Europe.
ZEE Hub = Physical gas trading hub at Zeebrugge which was the first major gas trading hub in Continental
Europe.

4


Executive Summary

A world wide LNG surplus started developing in late 2008. This paper examines the causes of the surplus
and the changes the international LNG industry should adopt to address it.
The advent of unconventional gas and shale gas in particular has changed the North American gas scene
beyond recognition. Neither the USA nor Canada needs to import LNG on a regular basis and both countries
could before 2020 become exporters of domestically produced gas in the form of LNG from new liquefaction
facilities planned for the US Gulf coast and the west coast of Canada. The Lower 48 States of the USA
already re-export LNG by ocean going tankers from two Gulf Coast terminals. North American shale gas
exploration trends and developments are now being transferred to countries in other parts of the world.
A number of new liquefaction plants currently under construction will come on stream in the period to 2015.
Although some major players in the LNG liquefaction industry are suffering from serious feedgas problems
which will limit product availability from a number of existing plants, the industry’s liquefaction capacity is
likely to see more than a 50 per cent addition of operational production capacity before the end of 2014. A
large part of the additional liquefaction capacity which was originally destined for the US and Canadian
markets is now no longer required to supply these markets. The quantities of LNG sold in the flexible spot
and short term markets are predicted to increase substantially over the next 3 to 4 years as a result. They
could be more than double the 2009 observed levels.
Gas demand in US and Canada as well as Europe although improving, is still weak after the recession. Both
market regions are currently more than adequately supplied and as a result experience depressed gas prices.
The Asian LNG market on the other hand has come out of recession much faster and is now showing strong
demand growth and firming spot and short term prices.
International LNG trade routes have been changed as a result of the North American gas supply situation.
The UK National Balancing Point (NBP) has become the dominant trading hub for the pricing of spot and
flexible LNG supplies, since Henry Hub and the North American gas market have price-wise become isolated
from gas markets in Asia, Europe and South America. Russia’s Gazprom which has lost market share in
Europe due to inflexible oil-indexed gas pricing could be the international LNG industry’s wildcard. Should
the company start discounting gas prices towards the lower European hub prices, then this is likely to reduce
Europe’s attractiveness to LNG suppliers. If the current balance between LNG supply and demand is
disturbed in such a way that North American gas prices are no longer isolated from prices in other
international gas markets, then such a development would likely also have a major impact on the
international pricing of LNG.
The Asian market in general and the traditional markets of Japan, South Korea and Taiwan in particular, are
likely to remain the highest priced LNG markets also in the future and should be in a position over the next
five years, and likely beyond, to attract sufficient LNG supplies for their needs.
The current gas market environment has demonstrated how the traditionally used model for commercial LNG
operations can no longer deliver optimum utilisation of available product. This situation is now being
magnified as a result of a high number of new industry participants. Energy industry publishing houses and
major commodity brokers have recognised that the LNG industry needs better market and pricing
transparency as well as the development of screen-based LNG market data systems and trading tools which
should lead to proper market-based pricing of spot LNG and improved optimisation of LNG chain activities.

5


Causes of the LNG Surplus

a) Unconventional Gas a Challenge for LNG
Unconventional gas, meaning tight gas, shale gas and coal bed methane, has during the last 10 years played
a large and increasing role in the supply of gas to the Lower 48 States of the USA in particular, but also in
Canada. This development has been accelerated by advances in drilling and production techniques of shale
gas, advances that started becoming significant around 2006. Shale gas production has since this year
developed from being a relatively small source of gas to one that has changed US gas supply in a substantial
way. The “shale gas revolution”, now spreading throughout the North American continent, has led to a
situation where the region already today can be perceived to be self-sufficient in natural gas on an average
annual basis. Domestic production together with underground gas storage should also provide sufficient
capacity to meet peak gas demand during most periods of the year.
Unconventional gas, shale gas in particular, has not yet reached its full potential in North America.
Technological advances in shale production are now made on a continuous basis improving shale gas
economics in a substantial way. For example, after only a year of experimentation with flowing well
pressure modifications, it has been possible to increase expected ultimate recovery (EUR) of gas per well by
some 30 per cent in some of the major shale gas plays.
Moreover, many of the new shale gas producing areas still lack the necessary gas gathering, processing and
transmission infrastructure required for large scale commercial production and transportation of sales gas to
markets. These needs for infrastructure have been made more acute by the fact that many of the shale
plays in addition to dry gas also produce substantial quantities of natural gas liquids (NGLs) in particular and
also light crude oils. New producing areas such as the Marcellus Basin in the North East USA and Eagle Ford
in South West Texas should by 2015 have the necessary infrastructure in place to change gas flow patterns
and, therefore, change gas pricing along the Atlantic seaboard of the USA and Canada. All US and Canadian
LNG import terminals are located on this coast.
The prolific Marcellus Basin producing area in addition to serving the currently high-priced gas markets of
New England, will also supply gas to Canada further north and to markets bordering the Gulf of Mexico.
Marcellus gas will be flowing from the North East USA towards Henry Hub in Louisiana, the world’s largest
gas trading hub, likely resulting in excess gas supplies and in keeping Henry Hub gas prices low. This
development has already lead to soft gas price signals throughout the international gas industry.
With unconventional gas flowing into the domestic market, traditional price signals in the US can no longer
on their own reflect the economic potential of new reserves and their likely production growth. In fact,
despite soft Henry Hub prices currently rendering in many areas gas resources uneconomic, wells keep being
drilled and production from these is brought to the market. The significant margin producers receive from
the extraction of NGL and light oils means the gas coming out of these wells is becoming a by-product of the
liquids production. Moreover, in many cases, producers, bound by the strict terms of expensive acreage
lease agreements, are forced to drill for gas and complete wells for production, irrespective of market price
signals. As a result, a sustainably strong gas supply keeps market prices low, a situation exacerbated by the
absence of a counter-balancing strong demand. With total gas demand weak in the US for some time, small
increases mainly from the power generation fuel market have been unable to reverse the downward trend of
gas market price signals. Based on the latest gas demand forecast from the US Department of Energy’s
Energy Information Administration, US gas demand will remain relatively stable in the short to medium term
and unable to fully absorb all new sales gas production made available to the market.
Allegedly the practice of drilling long horizontal wells and the hydraulic fracturing of these in order to obtain
maximum gas production from shale deposits have resulted in environmental concerns, particularly related to
water management issues including claims of water table contaminations. It is not known that the latter has
been proved.
However, international oil and gas companies with proved “green” credentials, good technology and people
are now becoming increasingly involved in North American shale gas exploration and production operations.
These large and resourceful companies should be able to operate to new and more environmentally friendly
standards regarding drilling and hydraulic fracturing of wells, a situation which should correct perceived
mistakes made in the past by pioneering small independent companies.

6


The advent of unconventional gas and shale gas in particular has changed gas demand planning in North
America beyond recognition. As an example, as late as 2007 US Authorities projected an LNG import
requirement of some 55 mtpa (80 bcm of pipeline quality gas) to balance its gas markets in 2015 and a
further increase in imported LNG requirements was predicted in 2020. Only a small part if any of this LNG
import volume will now be required in the US and a similar situation is developing in Canada. As a result of
developing gas surpluses both the Lower 48 States of the USA and Canada could become exporters of LNG
produced from domestic feedgas before 2020. The US State of Alaska is currently a net exporter of LNG.
North American shale gas exploration trends and developments are being now transferred to countries like
Australia, China and India. In the future this will also be the case in Indonesia, South Africa, Jordan and
even Russia. These countries will likely all have substantial shale gas production in ten years time. Although
shale gas exploration has also started within European Union countries, the future shale gas production
levels in Western and Central Europe are likely to be more uncertain.

b) World-wide Liquefaction Capacity Developments
In parallel with unconventional gas developments in North America, substantial new projects for LNG
liquefaction have been developed and are in the process of being brought to the market around the world.
The most recent major projects are located in Qatar, Sakhalin in Russia, Tangguh in Indonesia, Equatorial
Guinea, Yemen, Peru, Western Australia, Angola and Algeria. A large part of the capacity of these LNG
liquefaction projects was meant to supply the US, in particular, and also Canada. Now, the operators of
these projects have to re-direct supply towards Asian and European markets in particular, but also to new
“counter-seasonal” markets in South America and in the Arabian Gulf area.
Table 1 entitled “Projected Incremental LNG Availability” shows a projection of total anticipated new LNG
liquefaction capacity coming on stream between the beginning of 2008 and end 2014.

Table 1: Projected Incremental LNG Availability

LNG expressed as bcm of pipeline quality gas per year 2008 2009 2010 2011 2012 2013 2014

Total anticipated additional LNG capacity [1] 11.5 33.9 80.0 114.6 134.7 144.4 146.7
Reduction in LNG production due to feedgas problems [2] 0.0 40.5 37.7 43.5 48.8 52.8 54.4

Anticipated incremental LNG availability [3] 11.5 -6.7 42.3 71.1 85.9 91.6 92.2

Source: MFC estimates, updated 14 November 2010
[3]=[1]-[2]

A number of traditional LNG suppliers, notably Indonesia, Nigeria, Algeria, Egypt, Oman and Malaysia, to
mention the most important, have over the recent years experienced problems in securing adequate feedgas
supplies for their LNG liquefaction plants. Some of these feedgas problems are the result of competition for
gas supplies between domestic market requirements and export projects. This is an increasing problem in
many LNG producing countries. The inadequate feedgas supply in total represented a reduction in LNG
production of some 28 mtpa (40.5 bcm) in 2009 when compared to nameplate capacity. As shown in Table
1 these reductions have been projected to increase to some 37.5 mtpa (54.4 bcm) in 2014.
Among the existing liquefaction plants Nigeria LNG presents a major uncertainty due to disruptions to
feedgas supplies caused by insurrection in the gas producing area. In 2008 the company produced at only
65% of nameplate capacity, a number which fell to 51% in 2009. The company also experienced substantial
reductions in deliveries during the first half of 2010, a situation that appears to have been corrected for the
last months of the year. In Table 1 it has been assumed that Nigeria in future years will be able to produce
at 85 per cent of nameplate capacity, a normal annual operating level for the industry.
In 2009 the combined effect of delayed start-up of new liquefaction capacity and the reduction in LNG
production due to feedgas problems resulted in a reduction in LNG availability of 4.6 mtpa (6.7 bcm) when
compared to previously anticipated LNG availability based on nameplate capacities. However, overall
worldwide LNG production did increase by 9.6 mtpa (13.9 bcm) or 5.66 per cent to 179.1 mtpa (259.7 bcm)
in 2009 when compared to 2008.

7


Anticipated incremental LNG availability when using end 2007 capacity as a base and adjusting for reduction
in LNG production due to feedgas problems is forecasted to increase from 29.2 mtpa (42.3 bcm) in 2010 to
63.6 mtpa (92.2 bcm) in 2014.

c) Uncontracted LNG Availability
Uncontracted LNG availability is product sold under spot and short-term sales arrangements. Spot and
short-term LNG exports or sales are understood to be sales of duration of up to 4 years. Such spot and
short-term sales are also referred to as “flexible” sales in the text below.

Figure 1: Spot and Short-Term LNG Exports

35

30 Middle East/Africa/Europe
Americas
25 Australasia
Others
20
Mtpa

Total

15

10

5

0
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009

Source: GIIGNL

Figure 1 entitled “Spot and Short-term LNG Exports” shows the development of flexible LNG sales since
1999. There has been a marked increase in such sales since 2005. The major source of such sales have
been the Middle East, Africa and Europe, the latter being cargoes diverted from European destinations such
as Spain and France to the USA in 2005/06 and mainly to Asian markets thereafter. Since 2008 flexible sales
from the Americas (Trinidad and Tobago) and Australasia (mainly Sakhalin in Russia and Tangguh in
Indonesia) have increased due to diversion of cargoes originally destined for the USA.
Table 2 entitled “Flexible LNG Sales as Percentage of Total LNG Exports” shows that flexible LNG sales
peaked at 21 per cent of total exports in 2007. The comparable figure for 2009 was some 16 per cent or
29.3 mtpa (42.5 bcm) out of the 179.1 mtpa (259.7 bcm) total LNG production in the year. This figure is
expected to increase to above 20 per cent again in the time period 2010 – 2014 when a number of new
liquefaction projects which were originally meant to supply the US and Canadian markets come on stream.

Table 2: Flexible LNG Sales as Percentage of Total LNG Exports

LNG spot and short-term sales
Assessment of total exports

2005 15%
2006 17%
2007 21%
2008 19%
2009 16%

Source: MFC estimates.

8


Arabian Peninsula-based LNG sellers are likely to provide large quantities of product for flexible sales by the
end of 2011, when all plants being constructed at Ras Laffan in Qatar should have reached full production.
In addition to the availability of flexible LNG product, there is another industry development which may act
as a catalyst for LNG producers to sell into the flexible markets. This is the emergence of a high number of
energy and commodity trading houses as active players in the LNG market. These companies appear to be
in a position to offer higher prices for product than traditional buyers. However, new entrants to the LNG
market that do not have equity production or long-term supply contracts which include arrangements for
LNG tanker transportation, face a serious industry bottleneck. Shipping availability is an important hurdle.
About 80 per cent of the current LNG fleet is assigned to production projects. Of the remaining LNG tankers
some 80 per cent are controlled by the international oil and gas companies leaving only some 4 per cent of
the current fleet available for independent charter on a regular basis1. It has been observed that traders and
commodity trading houses have failed to secure cargoes due to the lack of acceptable LNG tankers.
An interesting case of a company which for some time directed all of its uncontracted LNG supply to the LNG
spot and short-term market is Algeria’s Sonatrach. Algeria’s marketing decisions during the period 2006-
2008 were based on the assumption that spot sales were sustainably more attractive than long-term contract
sales. During this period LNG volumes that had previously been delivered to Belgium and Spain under long-
term contracts, were released to the spot market by purposely not renewing the expiring contracts. During
the same period Sonatrach decided to construct the Skikda rebuild and Arzew 3/Gassi Touil plants without
long-term sales agreements. These two plants are expected to bring up to 9.2 mtpa of additional product to
the market when they both have reached full production capacity after a gradual build up during the period
2012 to 2015.
However, Sonatrach’s strategy ultimately proved to be unsustainable as the recession changed the
international LNG markets from the late 2008. Amidst softening prices and the absence of long-term
contracts for their under construction plants Sonatrach senior management started to realise that the
marketing decisions of the past were no longer viable. Such realisation is reflected in a statement of the then
Algerian Energy Minister, Dr. Chakib Khelil at the Gas Exporting Countries Forum (GECF) in April 2010. Dr.
Khelil urged member countries to reduce spot selling in order to boost gas prices2. His statement likely
heralded Algeria’s future selling strategy. In fact, the sharp reduction observed in Algerian LNG sales over
the past six months of 2010 could possibly, at least in part, be a conscious effort to boost price levels by
holding back product from the market.

d) Recession Impact on Gas Demand
Under a) above we discussed the soft gas demand in the USA. Both Canada and the USA are still suffering
from the effect of the recession with reduced industrial and commercial activity. Persistent high levels of
unemployment are also likely to exert a downward pressure on domestic gas demand in North America.
Key European gas markets such as Germany experienced reduced gas demand due to demand destruction
already in 2007. Starting in the fourth quarter 2008, this development was magnified on a Europe-wide
basis by the onset of the recession. In 2009 the 25 European Union countries that consume natural gas
experienced a fall in consumption of 6.4 per cent compared to the level in 2008. This was the case despite
the fact the winter of 2009/10 was in many countries the coldest in 30 years. Industrial and feedstock
sectors saw in 2009 particularly large reductions in gas demand. Although these energy demand sectors
have experienced some improvements, their 2010 gas demand is expected to remain below historical levels.
In the case of the German gas market utilities are expecting total gas demand in 2010 to return to 2008
levels of some 85 bcm against a total demand of 92.8 bcm in 2006.
In spite of the negative market development in 2009 and part of 2010, LNG producers have managed to
make substantial inroads in European markets with new or expanded LNG terminal facilities such as in the
UK, Belgium and Italy. This has been at the expense of the traditional pipeline suppliers, Russia’s Gazprom
and Algeria’s Sonatrach, which to a large extent have failed to adapt to Continental Europe’s new two-tier

1
New LNG Trading Players to challenge Old Guard, by Edward McAllister, Reuters, 12 August 2010.
2
GECF Falls Short of Spot Sales Deal, article in the World Gas Intelligence, 21 April 2010, p.1

9


price system3. These two suppliers have as a result seen sharp declines in their gas exports to European
Union countries, while Qatar in particular but also Norway have increased their market shares.
In contrast to North American and European gas demand, gas consumption in the main Asian LNG importing
countries has increased very noticeably during the first six months of 2010 compared to the same period in
2009. This development has continued in third quarter 2010 as a result of increased industrial activity and
unusual warm weather in some of the key markets. Table 3 below entitled “Asia LNG Demand Q1-Q3 2010”
presents LNG import developments for Japan, South Korea, Taiwan, China and India. In the case of India
LNG imports have fallen in 2010 due to the start up of new domestic gas production.
Based on current trends in economic development with the shift in activity from North America and Europe
to Asian economies, energy demand including LNG is likely to continue showing healthy growth in Asia with
the possible exception of Japan. This will in turn create additional demand for flexible LNG supplies as well
as new long term LNG supply arrangements.
Table 3: Asia LNG Demand Q1-Q3 2010

2010 2009 Volume
('000 tons) Jan-Sep Jan-Sep change % change

Japan 52,712 48,027 4,685 9.75%
South Korea 23,039 17,388 5,651 32.50%
Taiwan 8,478 6,695 1,783 26.62%
China 6,708 3,959 2,748 69.42%
India 6,589 7,285 - 696 -9.55%
Total 97,526 83,356 14,171 17.00%

Source:Customs data.

LNG Spot and Short-term Trading

The LNG industry is increasingly becoming a global business. The three traditional main LNG consuming
markets have been interlinked through LNG trade as shown in Figure 2 entitled “Interrelations of LNG
Markets”. In this diagram the North American market is represented by Henry Hub, the main price-setting
gas trading hub on the continent. Europe has been split between Spain and Portugal, which together have
historically been the largest LNG importers in Europe, and the other European countries further north, mainly
due to inadequate gas pipeline connections between Spain and France. Of the European gas trading hubs
shown, the UK’s National Balancing Point or NBP is normally the price-setter in North West Europe.

3
Current European Gas Pricing Problems: Solutions Based on Price-Review and Price-Re-opener Provisions, Morten
Frisch, Centre for Energy, Petroleum and Mineral Law and Policy, Dundee University, Working Research Paper Series
2010/03.

10


Figure 2: Interrelations of LNG Markets

The price relationship between Henry Hub in the USA and NBP in the UK for the period from July 2009 is
shown in Figure 3 entitled “Relationship between Henry Hub and NBP Prices”. In the past these two price
curves have normally moved in parallel during periods of Atlantic Basin LNG supply surpluses. This
relationship appears to have come to an end at least temporarily starting in the spring of 2010. The likely
explanation for this is that the Atlantic Basin LNG price link has been broken with US imports staying low,
and mainly coming from Trinidad and Tobago under long-term contracts, while the UK has seen rapidly
increasing LNG import volumes. By far the largest supplier of LNG to the UK in 2009 and 2010 has been
Qatar. Qatar with its large LNG exports also to East Asian markets therefore connects the LNG markets of
Asia and Europe.

Figure 3: Relationship Between Henry Hub and NBP Prices
8

7
HH MA NBP MA
$/mmbtu

6

5

4

3
Jul-09 Sep-09 Nov-09 Jan-10 Mar-10 May-10 Jul-10 Sep-10 Nov-10

11


The view that the LNG based Henry Hub and NBP price link has been broken, is supported by the fact that
LNG spot prices delivered to North West European and Mediterranean destinations have been priced in
relation to NBP. The same has reportedly been the case for spot sales of LNG into East Asian markets4.
Although Henry Hub is no longer used as a benchmark for LNG sales into European and Asian markets,
Mexican Caribbean coast imports still use Henry Hub-based pricing. It is also understood that product out of
Peru LNG has been priced and sold on the basis of Henry Hub.

Referring back to Figure 3 above an important question for the international gas industry is: How stable is
the current LNG market situation in which the North American market in effect is isolated from gas markets
in Asia, Europe and South America? The market forces controlling this situation are dictated by a) the total
amount of spot or flexible LNG product available in the market in relation to global LNG demand, b) the
availability of receiving terminal capacity in North American markets and c) the availability of shipping to
serve North American demand, should the need re-emerge.

North America has under-utilised LNG receiving capacity due to a large and increasing unconventional gas
production together with a flat gas demand as discussed under section a). The LNG shipping fleet has been
developed to serve the North American gas market and a number of vessels in this fleet are today either idle
or being used partly loaded. Supply-demand dynamics in the global LNG market is the determining factor.
As outlined under section b) above the LNG producing industry will in the period to 2014 be in a position to
supply increasing volumes of flexible or spot LNG to the market, if it so wishes.

When Dr. Khelil requested that GECF member countries should refrain from spot selling of gas in April 2010,
it looked as if his request had fallen on deaf ears. The developments on the part of LNG producers since this
date might indicate that this may not have been the case. The future availability of flexible or spot LNG
could easily change the current relationship between Henry Hub and NBP gas prices and, therefore, the
pricing of LNG on a global basis5.

Figure 4 entitled “Price Relationship between HH, NBP, BAFA (Germany) and Japan LNG Import Prices”
shows the link between Henry Hub, NBP, BAFA representing average German gas import prices and the
average Japanese LNG import price. The Japanese LNG import price, which is the highest of the four prices
shown, is mainly priced off the Japanese Customs Cleared average crude oil price (JCC), although Japanese
prices based on other crudes such as Brent and Indonesian blends also exist. Until the end of 2008 the
German BAFA price reflected mainly the price under long-term oil-indexed gas import contracts. However,
after the emergence of a two-tier gas price system in Continental Europe, which resulted in the import of
increased volumes of hub priced gas, together with subsequent price renegotiations of long-term contracts,
the BAFA reported price has now been increasingly reflecting European hub prices linked to NBP. European
oil-indexed gas prices that have not yet been modified were in August 2010 some US$1.6/mmbtu above the
reported BAFA- average German gas import price for the same month.
In today’s North West European gas market environment it can be assumed that Continental European hub
prices will be at a level between NBP and BAFA reported prices provided that the pipeline systems linking the
UK and Continental European markets are fully operational. LNG landing in the UK would normally have a
DES price of NBP less terminal costs and UK gas transmission systems entry costs. During the third quarter
of 2010 typically this represented a price obtained by applying a discount of some 5 per cent to the NBP
price. This pricing system will under normal operating conditions make the UK DES LNG spot based price the
lowest DES LNG price in North West Europe. During the third quarter 2010 Mediterranean6 DES spot LNG
prices have also been at a premium to NBP.

4
Heren Global LNG Markets, 17 September 2010
5
The linkage of prices in the US and UK gas markets was addressed in a paper entitled “Price linkage between US and
UK Gas markets. The role of LNG. Can the Markets be de-linked again?” presented by Bjorn Brochmann of Point Carbon
at the 11th European IAEE conference in Vilnius, 25-28 of August, 2010 and published in the Conference Proceedings at
www.IAEE.org.
6
By Mediterranean is meant Turkey, Greece, Italy, French Med terminals, Spain and Portugal.

12


Figure 4: Price Relationship between HH, NBP, BAFA and Japan LNG Import Prices

18

16

14

12
$/mmbtu

10

8

6
Henry Hub Month Ahead
4
NBP Month Ahead
BAFA (German) Import
2
Japan LNG Import
0
Feb-08 Jun-08 Oct-08 Feb-09 Jun-09 Oct-09 Feb-10 Jun-10 Oct-10

This relationship is demonstrated in Figure 5 entitled “Current LNG Spot Price Dynamics (schematic)”. East
Asian DES spot LNG prices are today reportedly referenced to NBP. This is because the Japanese mainly
JCC-benchmarked price is at a level allowing shipping differentials to be absorbed by Japanese buyers. The
same applies to spot LNG cargoes delivered on a DES basis to South Korea and Taiwanese buyers. China
and India have in the past also purchased cargoes based on such pricing.

Figure 5: Current LNG Spot Price Dynamics (schematic)

In the LNG Spot and Short-term Trading section it was discussed that North American gas markets are today
effectively isolated, price-wise, from gas markets in other parts of the world. Should available LNG product
increase to such a level that North American gas markets stop being isolated from gas markets in Asia,

13


Europe and South America, then such an LNG supply situation would likely lead to rapid gas price
developments in most international markets. The answer to how the available LNG product would increase
to such a critical level could very well lie in Gazprom’s future marketing strategy for Europe and its desire to
regain market share for its pipeline gas supplies.

Both Russia and Algeria, as mentioned under section d) above, have seen their sales of gas to European
Union countries decline as a result of inflexible pricing in an oversupplied gas market. Both countries have
lost market share in Europe. Russia in 2009 exported 142 bcm of pipeline gas to European countries and
had planned to increase such exports to 160 bcm in 2010. However, based on the latest gas export data
coming out of Moscow, the country will most likely export only some 140 bcm in 20107, even a decrease
compared to 2009. Reportedly, a number of Gazprom’s main gas customers claim they are still facing
serious difficulties with the pricing of Russian gas supplies and have demanded additional unscheduled price
renegotiations. Should Gazprom start discounting gas sales prices under long-term gas sales contracts, it is
thought this could have serious implications first of all for European LNG imports. As stated above, Russia in
the short term would like to export an additional 20 bcm of pipeline gas, equivalent to some 13.8 mtpa of
LNG product.

If Russian prices were to be lowered sufficiently to reflect Continental European hub prices, then Russian
supplies would increase sharply and potentially achieve the above pipeline gas export ambition. This would
have an immediate impact on LNG import levels in Italy, France and Turkey with secondary effects on
Belgium, the Netherlands, Germany and Austria. This would in turn result in increased imports of pipeline
gas to the UK and hence impact on NBP pricing. Such a development would be reflected in the value of
LNG imported into the UK. The value of NBP pricing used as a benchmark for East Asian spot DES sales
would be lowered under this scenario at the same time as LNG volumes directed towards East Asian markets
would increase and lower the price range for spot LNG deliveries to this region. In the current European gas
market environment Gazprom could, therefore, well be the wild card for the pricing of spot LNG sales first of
all to Europe and then to East Asian markets.

Figure 6: Japanese DES Spot Prices Potential Range

18

Japan LNG Import Price
16 NBP MA Spot
Japan LNG Import Forward
NBP Forward Curve
14 NBP + 1.50 $/mmbtu
NBP + 2.00 $/mmbtu

12
$/mmbtu

10

8

6

4

2

0
Feb-08 May-08 Aug-08 Nov-08 Feb-09 May-09 Aug-09 Nov-09 Feb-10 May-10 Aug-10 Nov-10 Feb-11 May-11

7
Netherlands, Denmark ask for more gas from Gazprom, article in RIA Novosti, 29 October 2010

14


Furthermore, under such a scenario where a) Europe becomes less attractive to LNG producers, b) additional
volume of LNG is directed to Asian Buyers and c) new seasonal markets in South America and the Arabian
Gulf area are unable to absorb all the volumes otherwise destined for Europe, there seems to be only one
other market for the surplus LNG product, should this continue to be produced: All surplus LNG, which could
not be absorbed in Asian, European and South American markets, would then find its way to the US and
Canada, with North America becoming the market of last resort. If this should happen, it would lead to a
downward pressure on prices for spot LNG in international markets potentially forcing LNG spot prices to
spiral down to levels again set by Henry Hub as benchmark. Russia could well hold the large international
gas price wild card.

Of course, on the other hand, should there be a combination of increased Asian LNG demand and a
persistent reduced availability of installed LNG liquefaction capacity, there could in the short to medium term
be a shortage of LNG in Asian markets. Under this scenario it appears that the traditional Japanese, South
Korean and Taiwanese buyers can outbid their European counterparts without much difficulty. Based on
market information these buyers in September appeared to be prepared to pay at least US$2.5/mmbtu more
than the highest long-term contract prices currently serving the German market, a contract price level
European gas importers today have great difficulties in passing on to their end consumers. In tight LNG
supply situations Japanese buyers have in the past been observed to pay DES prices well in excess of
US$20/mmbtu.

Figure 7 entitled “Japanese DES Spot Prices Potential Range” presents a comparison of the NBP month
ahead price with the Japanese average reported import price from Qatar for corresponding delivery months.
Based on forward curves for crude oils, the forward curve of the average Qatari price has been estimated.
This estimate is shown together with the forward relationship between the NBP month ahead price curve and
Japanese DES LNG spot price ranges and such price ranges relationship with the NBP curve, all observed
during the early part of November 2010. Figure 6 confirms the strength of Japan’s LNG purchasing power in
relation to that of European gas buyers both historically and during the first half of 2011.

Commercial Model for Spot and Short-term Trading

The 29.3 mtpa (42.5 bcm) of spot and short-term LNG trade recorded in 2009 was at a substantially lower
level than what the industry had expected. Section b) above discussed anticipated incremental LNG
availability, using end 2007 capacity as a base, which was projected to be 29.2 mtpa (42.3 bcm) in 2010
increasing to 63.6 mtpa (92.2 bcm) in 2014. A large proportion, probably more than half, of these
quantities, if they are produced, are likely to be sold in the spot and short term markets, increasing flexible
sales from the current level of some 30 mtpa (43.5 bcm) to in excess of 60 mtpa (87 bcm) by the end of
2014. This quantity of LNG represents a gas demand which exceeds the total demand of most national
markets. Furthermore, it will be sourced from an increasing number of liquefaction trains and producers
around the world at the same time as the number of LNG regasification terminals, both permanent
installations and ship-based units, is growing rapidly.
In addition to an increasing number of market players with access to LNG production and receiving
infrastructure, there are in November 2010 at least ten energy traders and commodity houses actively
participating in the commercial LNG market8. With increased availability of flexible LNG quantities it can be
assumed that the number of independent LNG traders in the near term will increase further. Even some of
the very conservative Japanese Utilities are now moving into LNG trading in order to optimise their fuel
supply portfolios.
The industry which supplies energy trading activities and energy market operators with data has understood
the increasing need for transparency and improved market data. A number of industry newsletters are now
publishing indicative DES spot prices for major LNG market areas such as; South East Asia normally
represented by Japan; North West Europe represented by the UK; and the Mediterranean represented by
Spain.

8
Factbox – New Trading Players in the LNG Market, Reuters, 10 August 2010

15


The maturing of the LNG spot market is also evident by the increasing acceptance of LNG brokers in cargo
transactions. Tullett Prebon, an inter-dealer brokering house was the first to launch an LNG brokering desk
at the end of 2007, and is now operating from London and Singapore, signalling business is growing. UK
commodity house, Spectron has since followed suit. Tullett Prebon LNG brokered its first cargo within a year
of being set up and has since been involved in over 10 LNG cargo deals including options and deals for
regasified LNG.
The company launched in early 2010 the first online screen for advertising LNG cargoes and buying interest.
They state that this LNG screen-based service has been designed for fast communication of spot trade
interests among their clients and to meet a growing need for greater price transparency. Advocating market
transparency and to help its clients get the best possible understanding of LNG trade movements, Tullett
Prebon LNG has also launched vessel tracking data services, both on its own and in collaboration with Lloyd’s
List Intelligence.
The amount of detail and the accuracy of the Tullett Prebon screen-based LNG service are unverified,
however it is understood that over 100 market participants now have access to these services.
The Spectron Group in its turn launched in September 2010 a screen-based LNG Indices service used to
record indicative price levels for spot LNG cargoes to be delivered to East Asia, Mediterranean and North
West Europe in 30 and 60 days from the data of the entry date. The recorded LNG price data should,
therefore, correspond to the front month (M+1) and the front second month (M+2) in the forward gas
market.
The Spectron LNG Indices service, just like the publishing houses now also providing indicative LNG spot
prices, is based on assessments and reported data that has not necessarily been confirmed by trades.
It is hoped that these latest LNG market activities will develop into an Over-The-Counter physical market
(OTC market) for LNG and that such a move will ultimately result in deals for string cargoes being recorded
and a physical forward price curve starting to develop.
One thing can be certain of these analyses and screen-based developments: The traditionally used
commercial model for LNG is no longer adequate for an optimum operation of the LNG industry. Electronic
trading platforms have long been used to set up commodity exchanges for flexible products such as crude
oil, oil products and coal. Financial products developed from the electronic trading of crude oil and oil
products are today frequently used by LNG buyers and sellers to hedge their market positions. The LNG
industry is as a result becoming increasingly familiar with electronic trading operations and the benefits they
can provide. Thus while a credible LNG Index and swap market has yet to establish itself, this would be a
natural evolution of the market.
The development of electronic market tools for LNG would be very welcome to an increasing number of
buyers and sellers of LNG on an international scale. It can be expected that traders in addition to brokers
will take the lead in developing such tools as the LNG spot and short term market becomes more liquid in
the period to 2015. It is observed that the latest market developments already have increased LNG traders’
appetite for physical risk. In addition to sourcing LNG and trading cargoes of product on board LNG tankers
they are also entering into spot and long term LNG tanker charters and contracts for firm capacity at LNG
receiving and regasification terminals. Traders are today increasingly operating along the entire LNG chain:
hence the need for more sophisticated tools to control and minimise risk.
The development and use of transparent and reliable online trading services will lead to proper market-based
price discovery for spot or flexible LNG, meaning the discovery of an optimum price for LNG in the various
geographic regions in which the product is used on a regular basis. This price will be the direct result of
market trading and not based on the cost of fuel alternatives which are used as price benchmarks. It will be
primarily dependent upon the demand and supply forces of the underlying fuel with the addition of a
shipping differential and any other destination-specific costs. This price will be an accurate reflection of a
single market’s activity and/or the interrelations of activities in systems of markets, as demonstrated by the
currently observed link between NBP gas prices and the DES price for spot LNG in East Asia.
Price discovery tools will have positive consequences not only for buyers and sellers in the LNG industry but
also for participants in LNG - dependent industries such as shipping. By monitoring LNG tanker traffic
through the Suez Canal during the month of July 2010, it was observed that a total of 36 laden LNG carriers
made the voyage through the Canal; 32 sailed from East to West while 4 travelled from West to East. Most
of the west-bound cargoes came from Qatar while it is believed that up to 3 of 4 laden eastward transits

16


may have been delivered to Kuwait and, therefore, sailed past Ras Laffan where the Qatari tankers sailing in
the opposite direction had been loaded9. A market-based price discovery process for spot LNG will surely
lead over time to a reduction of all such non-optimal shipping flows and shipping routes. One thing that
could potentially hamper this development is the fact the LNG shipping fleet does not have the same
flexibility as the ocean going fleets for crude oil, petroleum products and dry bulk commodities.
It can not be disputed that market based pricing and price discovery will lead to the optimisation of
commercial operations and portfolio flows of both LNG suppliers and consumers. On a trading level, if
applied to LNG, market based pricing and price discovery would allow for direct, non-benchmark based use
of all pricing and hedging possibilities available to traders of other commodities in today’s increasingly
sophisticated markets.
Looking at history, both gas markets in the USA and UK were modernised and saw the introduction of
transparent gas trading systems based on which financial products could be developed, as a result of gas
oversupply caused by structural market changes. The combination of the recession, the large increase in
LNG supply and further regulatory changes are now driving a similar development in Continental Europe.
Only time will tell to what extent the influx of LNG, which is forecast to become available before 2015
without long-term contracts, will cause a similar development in the international LNG industry.

Morten Frisch Consulting accepts no liability for commercial decisions based on the content of this paper. Although the paper is
copyright of Morten Frisch Consulting, quotes from the paper are permitted, provided full references to the paper and Morten Frisch
Consulting are made. Onward transmission or copying of the paper is allowed in its original form only.

9
Suez Canal LNG Traffic Surges in July, LNG World News, 23 August 2010

17

Morten Frisch Gasex 2010 Paper 14 November 2010

Recomendados

Recomendados

Mais conteúdo relacionado

Semelhante a Morten Frisch Gasex 2010 Paper 14 November 2010

Semelhante a Morten Frisch Gasex 2010 Paper 14 November 2010 (20)

Último

Último (20)

Morten Frisch Gasex 2010 Paper 14 November 2010