2006-2009 triennium work report programme committee d:...
TRANSCRIPT
1
2006-2009 Triennium Work Report
October 2009
PROGRAMME COMMITTEE D: LNG
Chair: Seiichi Uchino
Japan
STUDY GROUP 2
Group Leader : Dr. Boyoung Kim Korea Gas Corporation
Republic of Korea
2
Summary
The topic for 2006~2009 research was “LNG contract clauses for more flexible global LNG market” and this
topic is in line with the previous topic that was undertaken during 2003~2006 Triennium “LNG spot market”.
The goal of our study is to demonstrate that modifications in the terms of current contract clauses can
contribute to establishing a more flexible global LNG market and that this could provide a win-win strategy for
both buyers and sellers. .
In order to achieve such objectives we have selected 5 key topics for our study. These key topics are: 1)
price formulae and indexation mechanisms ; 2) duration, terms and extension ; 3) volume flexibility ; 4)
Incoterms clauses ; and 5) destination and diversion clauses.
However, it should be made clear that since our study group has participants from both sellers and buyers,
the inputs reflects the different opinions from our members and the outcomes will be depend on how the
interests of countries and corporations can be harmonized. Indeed a few suggestions to minimize the
perceived gaps are reflected on the report. We hope that readers of this report enjoy the adventure of finding
those clues listed in the text.
Résumé
Faisant suite au thème retenu pour le triennat t 2003-2006 “Le marché spot du GNL”, le sujet d’étude du
triennat 2006-2009 a été “Clauses contractuelles pour un marché du GNL plus flexible”. L’objectif est de
montrer que l’établissement d’un marché global du GNL plus flexible via la modification des clauses
contractuelles peut constituer une stratégie gagnant-gagnant pour l’acheteur et le vendeur.
A cette fin nous avons sélectionné 5 sujets majeurs sur lesquels nous avons ciblé notre analyse : 1) les
formules et mécanismes de prix ; 2) la durée des contrats et les possibilités d’extension ; 3) les souplesses
sur les volumes ; 4) les clauses Incoterm ; et 5) les clauses de destination et de détournement.
Je souhaite souligner que du fait de la composition de notre groupe de travail, auquel ont participé à la fois
des représentants des vendeurs et des acheteurs, des opinions différentes ont été exprimées, en fonction
des intérêts propres des pays et des compagnies. Le rapport contient toutefois diverses suggestions
susceptibles d’aider à combler ces différences. Nous espérons que les lecteurs de ce rapport apprécieront
de les retrouver au fil de leur lecture.
3
Index Summary
Chapter 1. Introduction ....................................................................................................................... 5
Chapter 2 Perspectives of World LNG Market ................................................................................... 6 A. Asia Pacific Basin . ................................................................................................................. 6 B. Atlantic Basin . ...................................................................................................................... 14 C. Global LNG Market, New Hubs . .......................................................................................... 29
Chapter 3. LNG Contracts ................................................................................................................. 36 A. Factors to Make LNG Trading More Flexible ......... ............................................................. 36 B. Price Formula and Mechanisms . ......................................................................................... 37 C-1. Duration / Terms / Extention . ............................................................................................... 42 C-2. Duration / Terms / Extention . ............................................................................................... 44 D. Volume Flexibility . ................................................................................................................ 45 E. Incoterms . ............................................................................................................................ 48 F. Destination clauses / Diversion ............................................................................................ 54
Chapter 4. Conclusion .............................................................................................................. 60
4
Chapter 1: Introduction For the Triennium 2003~2006, the research topic selected by our group was “LNG spot market”. In 2003,
when we first started the research, the spot volume of LNG was about 5%. However, the spot trading volume
share showed a significant increase to 20% by 2008. With that mentioned, we are proud that our report in
WGC 2006, Amsterdam, about the importance of the LNG spot market, was rather insightful. To be in line
with such view on the market, we have chosen “LNG contracts clauses for more flexible global LNG market”
as our research topic for 2006~2009. The topic was suggested taking into account that the current LNG
market, in which 80% of the trades are based heavily on 20-year plus long term contracts cannot secure its
position in the global market without reforming the current contract terms. With that in mind, we questioned
ourselves “Would there be a solution that can generate a win-win strategy for both buyer and seller?” and we
decided to spend the past 3 years analyzing the subject to find such solution.
However, there was a strong conflict between buyer’s and seller’s interests which arose from our first
meeting, held in Yokohama in September, 2006. As shown in the report, each of the items (� price formulae
and mechanisms � duration, term, extension � volume flexibility � Incoterms � destination clauses,
diversion) in chapter 4 ‘LNG contracts’ are described with parallel views from the buyer and the seller as they
could not be agreed by mutual understanding. Furthermore, different views were observed within a group of
sellers and also within a group of buyers representing various countries’ and corporation’s interests. For that
reason, we have decided to put all those ideas in the report rather than deriving a single understanding.
Readers might be confused with various ideas but that is the reality we are facing today.
A great achievement of our study group was that we were able to bring together both buyers and sellers to
share each other’s point of view on several sensitive matters of the LNG contracts during this 3-year period..
Although the members of the research group are not directly in charge of making deals, they were able to
share their ideas and indirectly benefit from it since they have clear understanding of their country’s and
corporation’s interests. Regretfully, we were only able to get together once or twice a year and such time
restriction has given us little opportunity to dedicate ourselves in melting various ideas into one mutual
understanding. However, further discussion and research are expected to be performed by the next research
group for the 2009~2012 Triennium in order to generate more conclusive results.
5
Chapter 2: Perspectives of World LNG Market
A. Report for Asia Pacific Basin
Mr. Ahmad Marzuki Haji Ahmad, Petronas 1. Introduction
• Natural Gas In 2007, natural gas accounted for about 23.8% of the world’s primary energy consumption, with the Asia
Pacific region attributing to about 15.3% of the natural gas share of the primary energy consumption.
During the same year, about 70.6% of the world’ total natural gas consumption was met by domestic gas
with the remaining balance through imported pipeline gas and as LNG. LNG accounted for about 29.2% of
the total natural gas traded during the same year.
• Liquefied Natural Gas The Asia Pacific region continues to dominate LNG imports with traditional buyers namely, Japan, South
Korea and Taiwan together accounting for more than half of the total LNG imports year on year to date,
averaging at about 61% over the last four years since India received its first LNG cargo in 2004. The
emergence of India and China is expected to sustain the Asia Pacific region as the major LNG demand
centre. BY 2010 and 2015, the Asia Pacific region is projected to account for about 58.1% and 53.1% of the
world’s total LNG demand respectively.
On the supply side, the Asia Pacific region (the Middle East excluded) accounted for slightly more than one
third (~37.5%) of world’s total LNG supply of about 174 million tonnes in 2008, with supplies mostly
originating from Malaysia, Indonesia, Australia, Brunei and the US (Alaska). Russia via their Sakhalin II LNG
project has just emerged to become the latest Asia Pacific-based supplier this year. Located on the eastern
Sakhalin Province north of Japan’s Hokkaido Island, the project represents the Russian first foray into the
LNG exportation business industry, having been till now a dominant pipeline gas supplier to Europe. The
two-train Sakhalin II LNG project will add another 9.6 million tonnes to the current global LNG supply, raising
the current global production capacity to 185.9 million tonnes.
Asia Pacific is projected to account for about one third of the world’s total supply of 269.8 million tonnes in
2010 and 284.9 million tonnes in 2015 respectively, mainly to satisfy the energy hungry Asia Pacific
consuming countries and, the Pacific Rim (North and Central America) region in future.
LNG demand in the Asia Pacific region in 2007 reached 118.6 million tonnes, an increase of 6% over 2007.
Between 2000 and 2008, the average annual growth rate in LNG demand for the Asia Pacific region has
averaged around 6%. While Japan continues to dominate the global LNG importation scene, emerging
demands from India and China and other gas consuming countries like the United States (West Coast),
Mexico, Argentina, Indonesia and Thailand to name a few are expected to sustain the Asia Pacific position
as an important LNG demand centre. In 2008, both India and China accounted for about 18% of the region’s
total LNG imports, an increase from 9% recorded in 2007.. Of significant importance is the recent spot cargo
movement to India and China, that gave indication of these new emerging markets’ growing willingness to
accept global market-related LNG prices.
6
2. New Markets
• INDIA
Natural Gas Demand Natural gas accounts for approximately 9% of India’s total primary energy mix. Its share is projected to
increase to 12.4% by 2020. In addition, natural gas consumption is forecasted to grow at annual rate of
16.2% through 2010, 7.1% annually between 2010 and 2015, and at a relatively slower rate of 3.5% annually
between 2015 and 2020. Total natural gas consumption in India is projected to reach 12.2 bscf/d by 2020.
Electricity generation currently accounts for the largest share of India’s natural gas consumption. In 2008,
electricity generation share of natural gas consumption was 32%. India’s overall electricity demand is
projected to grow at an average rate of 5% annually through 2015. Demand for natural gas in the power
generation sector is projected to grow from 1.7 billion standard cubic feet per day (bscf/d) in 2008 to 3.5
bscf/d by 2020, at a rate of 3.2% annually through 2015 and, 2.2% annually between 2015 and 2020.
Domestic gas primarily from offshore basins on the east coast will likely be used for power generation.
The fertilizer sector is the second-largest consumer of natural gas in India, accounting for 26% of the total
natural gas consumption in 2008. Gas is primarily consumed as a feedstock for urea production. Growth in
the fertilizer sector will be on account of new gas-based urea plants, as well as conversion of naphtha-based
plants to gas. Gas consumption in the fertilizer sector is projected to grow by 6% annually between 2008 and
2020.
Other consumers of natural gas in India include industrial users such as steel, petrochemical, glass and
ceramic industries, and electronic device manufacturers. Overall gas consumption in the industrial sector is
projected to grow from 1 bscf/d in 2008 to 2.9 bscf/d by 2020, and at a rate of 12% annually through 2015
and 5% annually between 2015 and 2020.
With developments in gas infrastructure, demand for natural gas in the city gas sector is expected to
increase from 0.2 bscf/d in 2008 to 1.2 bscf/d by 2020 and, at a rate of 15% annually until 2015 and 6% until
2020.
LNG Import Projects India’s foray into LNG importation began in 2004 with the commencement of operations of the Petronet
LNG’s Dahej LNG terminal, located in the north western coastal state of Gujarat. The Dahej LNG terminal
has a capacity 5 million tons per annum, and it has been recently expanded to 10 million tons per annum to
meet the increasing demand for gas around that region.
Gujarat is also host to the India’s second LNG import project. Located south of Dahej, the Hazira LNG
terminal was commissioned in 2005 with an initial capacity of 2.5 million tonnes per annum. With marginal
incremental investments in equipment, the terminal’s capacity can be enhanced to 5.0 million tonnes per
annum. Jointly owned by Shell and TOTAL, the Hazira terminal operates on a merchant basis, hence has no
long-term LNG supply arrangements.
In 2008, India imported about 8.6 million tonnes of LNG, an increase of about 11% over 2007, driven by
strong demand in the industrial and residential sectors and substitution for naphtha in fertilizer production. In
2007 alone, India purchased 46 cargoes on the spot market primarily from Qatar, Nigeria, and Algeria. LNG
demand in India is projected to almost double to 11.9 million tonnes per annum by 2015 and almost tripled to
20.7 million tonnes per annum by 2020.
7
• CHINA Natural Gas Demand China plays a major role in shaping Asia Pacific’s primary energy consumption, and its energy consumption
has been primarily dominated by coal due to large coal reserves available in China.
In 2008, China’s primary energy consumption grew by 6.7%, dominated 70% by coal, followed by oil (19%),
hydroelectric (5%), natural gas (3%) and the rest to nuclear. China’s primary energy consumption is
expected to continue to grow at an average annual growth rate (AAGR) of 9.5% between 2008 and 2020.
Although coal and oil are expected to remain as the largest contributors to China’s energy mix, natural gas is
expected to emerge as one of the new major contributors to the growth in China’s energy consumption in the
years to come, amidst the increasing concern for the environment.
Gas demand in China has traditionally been constrained by domestic production levels and the fragmented
nature of the existing gas pipeline infrastructure. Most of China’s indigenous gas production is consumed
locally at a regional level, but the completion of the West-East pipeline has facilitated growth and enabled
indigenous production to be transported to demand centres in eastern China. Nevertheless, additional
imported volumes will be required to keep pace with the anticipated demand growth in China’s gas market.
LNG imports began in 2006 and are expected to continue to increase until 2020, filling the gap between
indigenous supply and demand.
Higher gas demand for power and residential and commercial sectors, as well as improved gas infrastructure
have supported the rise of China’s natural gas share of the primary energy mix from 2.2% in 1990 to 3.3% in
2008. It is also worth mentioning that China’s natural gas use has increased significantly by 42% from 2006
to 2008. Industrial sector currently tops the usage of natural gas in China with 36% share, followed by 31%
from residential and commercial and 16% from power generation. Although the industrial use of gas is
largest at present due to a wide usage of natural gas as feed for fertilizer plants, the growth in power and
residential and commercial sectors are expected to outpace demand growth in the industrial sector by 2020.
An AAGR of 13% and 9% are forecasted in the power and residential and commercial sectors respectively
by 2020. LNG Import Projects With Guangdong LNG and Fujian LNG terminals in operation, China’s available total LNG it add another 3.0
MTPA, followed by another 6.5 million tonnes when both the Dalian and Rudong LNG import projects is
completed by 2011 and 2012 respectively. New capacity is expected to be added via expansion of the
existing LNG terminals as well as development of new ones.
Supply-wise, China has secured several long term LNG supply agreements for their LNG regasification
terminals namely, from Australian North West Shelf LNG for Guangdong LNG, Indonesian Tangguh LNG for
Fujian LNG, Malaysian MLNG Tiga for Shanghai LNG and Qatargas 4 for Dalian LNG. The supply of LNG to
Guangdong, Fujian and Shanghai is in line with China’s plan to use gas for specific gas-fired power stations
in operations and being developed to reduce its dependency on oil in the power generation sector.
The above are two of the significant demand markets that have emerged in the new millennium. Let us now
look at the new players that have also emerged in the regions and that are expected to significantly
contribute to the regional LNG supply/demand scenario.
8
SINGAPORE Natural Gas Demand
Singapore’s current natural gas demand is relatively small at less than 800 mmcfd. Demand for natural gas
is expected to grow as more power plants switch feedstock from fuel oil to natural gas. Overall natural gas
demand is expected to be driven by the power generation and industrial sectors.
With no indigenous natural gas supplies, Singapore relies on natural gas imported via pipelines from
Malaysia and Indonesia.
LNG Import Projects In 2006, the Singaporean Government decided to proceed with plans to import LNG, as a means of
enhancing energy security by diversifying natural gas supply sources. The project is being developed by
Singapore’s gas and power regulator, the Energy Market Authority (EMA). Pursuant to the signing of an LNG
Terminal Agreement in April 2008, the EMA announced that PowerGas, a subsidiary of the Singapore Power
Group, will develop the LNG regasification facility.
The proposed 3.0 MTPA facility will be located on Jurang Island and is expected to commence operations in
2012. Initially, the terminal will accept between 0.8-1.2 MTPA of LNG, and will ramp up to 3 MTPA by 2018.
Capacity may be expanded to 6 MTPA in the future. Powergas has selected the newly-merged GDF SUEZ
as its joint venture partner to build and operate the terminal, whereby GDF SUEZ will hold a 30-percent
share in the project.
On the marketing front, the EMA has appointed BG Group as aggregator of the Singaporean LNG market.
BG will be responsible for sourcing and supplying LNG to the terminal for 20 years.
THAILAND
Natural Gas Demand Current natural gas consumption in Thailand is approximately 4,000 mmcfd. Indigenous supplies from the
Gulf of Thailand account for the majority of Thailand’s natural gas supplies, while imports via pipelines from
Myanmar account for 25%. Natural gas is used to produce 80% of the country’s electricity. The power
generation sector is forecasted to drive natural gas demand in Thailand.
LNG Import Projects In a move to diversify the country’s natural gas supply portfolio and reduce dependency on neighbouring
countries, the Thai government has announced their intention to import LNG. Construction of Thailand’s first
LNG regasification terminal began in February 2008. The 5.0 MTPA import project is located within the Map
Ta Phut industrial port in Rayong Province. The facility, to be operated by PTT LNG Company (a subsidiary
of PTT), is expected to commence commercial operations in 2011.
The majority of the LNG imported into the terminal is intended to serve a dedicated new power generation
facility to supply electricity to the Map Ta Phut industrial complex whilst the remaining gas will be sent to the
PTT gas pipeline network.
Plans are in place to expand the LNG regasification facility in two additional phases. The expansion would
double the capacity to 10.0 MTPA. However any future expansion of the facility is subject to approval and
also dependant on the success of the first phase.
9
PAKISTAN Natural Gas Demand In 2008 Pakistan natural gas demand reached nearly 4 bcfd. Power generation and industries account for
75% of the country’s demand while a large residential and commercial consumer base, circa 5 million
residential and commercial consumers account for 17% of the gas demand. Demand for natural gas has
been growing around 7% per annum and is expected to reach 7 bcfd by 2025, but it is currently constrained
by lack of supply. A growing number of power plants are currently running on fuel oil. Information from
Pakistan’s Ministry of Oil suggests an existing gap of 700 mmcfd which may increase to 2.2 bcfd by 2015
even taking into account new anticipated domestic supply. The Government has announced plans to import
gas from Iran via pipeline and has launched an LNG import scheme, the Mashal LNG project.
LNG Import Projects In 2006, the Government of Pakistan nominated SSGC (Sui Southern Gas Company) as the facilitator for
the establishment of a 3.5 million mtpa LNG import and regasification project to be located in the vicinity of
Karachi, the Mashal LNG project. To date SSGC have evaluated proposals from several bidders and have
issued a letter of Support to one of the potential project developers to progress formal project award. Due to
time constraints the project will initially be developed as a floating regas facility which can upgraded in the
future to a land based terminal. The proposed facility is expected to be commissioned by 2011-2012.
3. New Suppliers
• RUSSIA Russia plays a significant role in the world natural gas trade. Russia holds the positions as the world’s largest
proved natural gas reserves at 1529 TCF (23.4% share), the world’s largest natural gas producer at 58.1
TCF (19.6% share), as well as the world’s largest natural gas exporter at 5.4 TCF (26.3% share) by end of
2008.
In 2007, Russia’s primary energy consumption grew by a nominal 0.6% with natural gas contribution to the
growth at 57.1%, oil at 18.2%, coal at 13.7% coal, hydroelectric at 5.9%, and the rest is nuclear. Due to low
domestic tariffs, Russia’s natural gas demand is largely driven by gas-fired power plants, and power
generation is likely to remain as an important contributor to the growth of natural gas demand.
Russia’s natural gas industry remains dominated by Gazprom, although the company’s share of total
Russian gas production has declined steadily from 94% of Russia’s total gas output in 1998 to 85% in 2007.
Historically, Gazprom has focused on massive low cost resources gas fields, all combined accounted for
approximately 52% of Gazprom’s production in 2005. As productions from these fields are expected to
decline by 30% by 2010 and 65% by 2020, Gazprom has taken steps to move towards higher cost and more
complex upstream projects to boost its production.
Independent gas producers such as Novatek, Rospan, ArcticGaz, and Northgaz are also likely to play a
growing role in meeting Russia’s export targets. It is projected that most of Russia’s natural gas production
growth between 2008 and 2030 will be contributed by independent gas producers.
Aside from concerns that Russia may use its position as an energy supplier for political purposes, there is
also mounting concern about Russia’s ability to meet, or to a greater extent, expand its current export
10
commitments. Despite Russia’s potential as an energy supplier, Russian natural gas production has been
affected by the slow pace of project development and further delays in new investments.
The experience regarding Russian production has raised concerns among European policy makers that
future Russian production may not allow Gazprom to meet its contractual commitments. Growth in Russia’s
domestic gas demand could also threaten the stability of export supplies to Europe. If new gas fields are not
brought on line after 2010, there are concerns about supply shortage during the winter season.
Although domestic price reform would reduce domestic demand growth, declining production coupled with
even modest growth could make it more difficult for Gazprom to meet its contractual obligations with its
current developed gas projects. Hence, Russia has made bold moves in bidding to secure whole gas exports
from Libya and Azerbaijan to address their supply ability over contractual commitments.
• IRAN Iran has the world’s second largest oil and gas reserves in the world, with 137.6 billion barrels of oil and 1046
trillion cubic feet of gas in proven reserves by end of 2008. As one of the leading members of the
Organisation of Petroleum Exporting Countries (OPEC), progress in monetizing its resources as a major oil
and gas producer has been dampened by internal and external challenges.
Iran’s natural gas is being monetized as pipeline gas and proposed LNG projects. While several contracts for
pipeline gas supply to neighbouring countries located around the Caspian region are in service and
concluded, a few others negotiations are being suspended due to disagreements on a variety of commercial
terms of supply.
Three LNG exportation projects are being promoted and pursued with various international investors
comprising national and international oil companies. Each project comprising two trains of 5.0 to 8.0 million
tonnes per annum of liquefaction capacity is at various stages of project reality. Gas supply for these projects
will be sourced from the South Pars gas field. This gas field is part of a single huge non-associated gas field
that straddles between two countries - the South Pars gas field (~463 TCF) on Iran’s side of the border and
the North Dome gas field (~900 TCF) on Qatar’ side.
1) Iran LNG (2 x 5 MTPA):
• NIGEC (49%), the Pension Fund Organization (50%), and the Pension Fund Investment
Organization (1%);
• Signed MOU with OMV (Austria) for a 10% share in the liquefaction plant;
• Start-up: ~ 2015.
2) Pars LNG (2 x 5 MTPA):
o NIOC (50%), TOTAL (40%), and PETRONAS (10%);
o FID is expected in 2009;
o TOTAL and PETRONAS underwrites LNG off-take from Train 1, with India, Thailand, and
China as possible markets for Train 2;
3) Persian LNG (2 x 8.1MTPA)
• NIOC (50%), Shell (25%), and Repsol YPF (25%).
• FID targeted for 2009/2010.
• Shell and Repsol to purchase output from Train 1.
Despite the huge gas reserves and signing several LNG supply commitments with a number of LNG buyers
these proposed projects have been experiencing continuous postponement mostly due to financing of
11
projects and technology constraints. These are attributable to the prevailing geo-political scenario that is
limiting project promoter access to the essential technologies to support their projects whilst forcing some
potential partners to inevitably review their investment policies.
Amidst the period of project cost escalation, the geo-political situation is also hindering Iran’s efforts to attract
and secure foreign direct investments as many reputable international financial institutions had reviewed
their investment strategy.
• PERU The Peru LNG - a joint venture LNG export project being developed by Hunt Oil (USA), Repsol YPF (Spain),
SK Energy (South Korea) and Marubeni Corporation (Japan) - is anticipated to commence operations in the
first half of 2010. Launched in January 2007, the project is considered as one of the most important
resources of the country’s future energy strategy. It also represents the government largest industrial
projects ever to be undertaken in the country.
The project is being developed as a single train facility with a production capacity of 4.4 million tonnes per
annum, which will be fed by natural gas transported from the Camisea gas fields in Chinquintirca in the
mountains around Ayacucho in central Peru to the LNG Plant at Pampa Melchorita on the coast. The 408 km
natural gas transportation pipeline will cross 22 districts before reaching the plant site.
LNG produced from this project has been purchased by Spanish Repsol YPF under an 18 years sale and
purchase agreement.
AUSTRALIA
Since it joined the club of LNG exporting countries as the sixth LNG exporter vis-à-vis the North West Shelf
LNG project in 1989, Australia has remained one of the key LNG suppliers for the region.
Located on the Burrup Peninsula in northwest Australia, the NWS LNG project commenced operations with a
three-train 7.5 MTPA total production capacity. The project has since increased its production capacity to
16.3 MTPA with the recent commencement of production of its Train 5 module last September 2008, which
was completed ahead of schedule.
The Darwin LNG project is the second of the many LNG exportation projects being promoted and pursued
for development in Australia. The 3.2 MTPA Darwin LNG commenced production in 2006 and boosted
Australian supply position to 19.5 MTPA, with most of the volume produced form these two projects destined
for Asia Pacific.
The third project expected to elevate Australia as one of the region’s leading LNG suppliers is the
Woodside’s Pluto LNG Project. Kansai Electric and Tokyo Gas have each purchased a 5% share, with
Woodside retaining the remaining equity shareholding in the project. To be constructed adjacent to the
existing North West Shelf LNG project, the 4.3 MTPA Pluto LNG project will further raised Australia’s LNG
export capacity to 23.8 MTPA by end 2010.
In addition to the abovementioned projects, a few other conventional-based LNG projects are being
promoted and pursued along the northern half of the Australian coast namely, Gorgon LNG, Ichthys LNG,
Browse LNG, Scarborough LNG, Greater Sunrise LNG, and Wheatstone LNG. If some of these projects
come to reality, it will eventually transform Australia, not only as the leading LNG player in this region, but
also a significant global LNG exporter over next decade or so.
12
The sedate coal industry has since been excited with the recent flurry of joint venture partnerships pursuing
the development of non-conventional LNG projects that is, the monetization of coal seam gas (or coal bed
methane) into LNG. Five separate joint ventures have been established namely, the Santos-PETRONAS
Gladstone LNG (GLNG), Queensland Gas Co.-BG Queensland Curtis LNG, Arrow-Shell Gladstone LNG,
Sunshine Gas Limited-Sojitz Corporation Sun LNG, LNG Impel Southern Cross LNG, all located within the
Australian eastern seaboard province of Gladstone.
These projects together could potentially add about 10.0 MTPA of LNG supply to the regional market during
their initial phase of the project. There are also plans to increase the production capacity for some of the
projects, subject to viable project economics.
Australia has since been the third largest of the region’s four LNG suppliers after Indonesia, Malaysia, and
Brunei. The reality of projects as mentioned above could easily catapult Australia as the region’s major LNG
supplier, easily contributing about 30.0 MTPA minimum of LNG to the market.
LNG Storage Facilities/Hubs Since its establishment, the global LNG industry business landscape has evolved and become more
complex, diverse, and competitive. An expanding feature of the industry is the "Brand LNG" business that
began in the 1990s. Essentially, Brand LNG is LNG that is produced anywhere and sold anywhere this
business is the key driver of the LNG spot trade.
The Brand LNG business has been promoted by many of the well known LNG industry players namely Shell,
BP, BG, ExxonMobil, Total, ENI and Gazprom. Others include Japanese trading companies such as Mitsui
Co. and Mitsubishi Corp and utility companies like Gaz de France, Snam of Italy as well as Osaka Gas. With
some flexibility or no restrictions on the sources and/or the destinations, this business leverages on the
ability of the company involved to source from its portfolio as well as to market and deliver the LNG. The
introduction of diversion clauses in LNG contracts further enhanced the Brand LNG business model.
The Brand LNG business also inspired the development of a new LNG hub located in the Middle East. The
Dubai LNG storage hub (DLSH), a project promoted by the Canadian LNG Impel and the Dubai Multi
Commodities Centre joint venture, intends to create a physical settlement point for LNG trading, making it the
third spot gas trading point, in addition to Henry Hub and NBP. To be completed in three phases between
2011 and 2013 the DHSL will provide numerous services namely LNG storage and LNG loan services, LNG
blending to meet Btu requirements as well as services to aid in force majeure situations.
The Asia Pacific region is also expected to be equally serviced by a similar project. Singapore has recently
embarked on a plan to initially develop and construct an LNG importation terminal project on Jurong Island
with plans to increase the terminal storage capacity.
In view of the expanding LNG business and trade dynamics especially the spot LNG trade, these facilities
are expected to serve as strategic LNG storage hubs to serve the increasing demand for LNG. Targeted
mainly for buyers, especially those with long term contracts, these facilities provide these buyers a
marketplace to procure cargoes at competitive prices, hence allowing them the opportunity to maximize
purchases during the cheaper months and store what they need for later.
The effectiveness of these facilities to accommodate the increasing regional need for readily available LNG cargoes will depend on how well the region’s traditional LNG suppliers are able to manage and ensure sufficient supply to meet their basic contractual LNG supply obligations and beyond.
13
B. Reprot for Atlantic Basin
Mr. Gregorio Morales, Stream Abstract
The LNG market has evolved from being one in which few players dominated both supply and demand, to one
in which technology and energy diversification has enabled new countries and companies to get into the game.
New liquefaction and regasification projects and terminals can be seen on both sides of the Atlantic,
contributing to price liquidity in LNG and natural gas markets.
How will the massive new liquefaction capacity coming on stream in the next months get along with the
demand downturn?
Will the current financial crunch curb the LNG market, scare investors? We face several months if not years of
uncertainty, and we need to be able to predict as close as possible to reality, how will the Atlantic Basin
situation evolve.
1. Where we come from – 2004 Situation
1.1. Liquefaction and Regas Capacity in the Atlantic Basin
From the figure below (Figure 1), we can observe that up to 2004 the Atlantic Basin market was
very focused on the European market and especially on Spain, with only 4 terminals working in the
US under an interruptible regime (no downstream commitment, except for Everett).
On the liquefaction side there were only 4 producers in the Atlantic Basin dominated by Algeria.
Also, volumes from Middle East (Qatar, Oman) were supplying LNG to Europe. Pacific Basin
volumes arrived rarely to the Atlantic on a spot basis.
14
Source: Stream. Figure 1: “Liquefaction and Regas Capacity in the Atlantic Basin, by end 2004”
1.2. Gas Prices
During the period 2000-2004 the main driver for prices was Henry Hub (HH) since the US market was
flexible enough to absorb volumes on a spot basis if price-differentials (Figure2) were attractive
enough for European and Asiatic players.
Source: Stream. Figure 2: “Brent and Gas indexes evolution, 2000-2004”.
Regas Capacity
Liquefaction Capacity
T&T
0
10
20
30
40
50
60
0
2
4
6
8
10
12
dic - 99 jun - 00 jan - 01 jul - 01 feb-02 sep-02 mar-03 oct-03 apr - 04 nov- 04
$/Bbl
$/MMBtu
Brent and Gas Indexes Evolution 2000 - 2004
NBP Nymex Brent
15
2. Starting Point – Today‘s Situation
2.1. Liquefaction and Regas Capacity in the Atlantic Basin:
From the figure below (Figure 3), we can observe that the Atlantic Basin market has grown
significantly mainly in the American continent and in the UK.
On the liquefaction side 3 new producers entered the market in the Atlantic Basin, and Algeria lost
their dominant position in favor of a more diversified portfolio of suppliers.
The Atlantic Basin and the Middle East Producers (Qatar, Oman) have provided the Pacific Basin
during the 2004-2008 period with the needed flexibility to cover shortages of LNG and the Atlantic
Basin is now providing the needed flexibility to place excess volumes from the DQT’s and demand
downturn.
Regas Capacity
Liquefaction Capacity
T&T
Equatorial Guinea
Source: Stream.
Figure 3: “Liquefaction and Regas Capacity in the Atlantic Basin, by end 2008”.
16
2.2. LNG Demand in the Atlantic Basin (mtpa, 2004-2008)
0,0
10,0
20,0
30,0
40,0
50,0
60,0
70,0
2004 2005 2006 2007 2008
mmtpa
North America
Latin America
Europe
Source: WoodMackenzie – Feb’09. Figure 4: “LNG demand for Europe, Latin America and North America, 2004-2008”.
0,0 10,0 20,0 30,0
40,0 50,0 60,0 70,0 80,0 90,0
100,0 110,0 120,0 130,0 140,0
150,0 160,0 170,0 180,0 190,0
2004 2005 2006 2007 2008
mmtpa
World Total
Atlatic Basin Total
Source: WoodMackenzie – Feb’09. Figure 5: “LNG demand. Atlantic Basin vs. World Total, 2004-2008”.
17
2.3. Effective Liquefaction Capacity (mtpa, 2004-2008)
Source: WoodMackenzie – Feb’09. Figure 6: “Effective Liquefaction Capacity, Atlantic Basin vs. World Total, 2004-2008”.
Source: WoodMackenzie – Feb’09. Figure 7: “Atlantic Basin suppliers’ Effective Liquefaction Capacity, 2004-2008”.
0,0
10,0
20,0
30,0
40,0
50,0
60,0
70,0
2004 2005 2006 2007 2008
mmtpa
Trinidad
Norway
Nigeria
Equatorial Guinea
Angola
Egypt
Libya
Algeria
0,0 10,0 20,0 30,0 40,0 50,0 60,0 70,0 80,0 90,0 100,0 110,0 120,0 130,0 140,0 150,0 160,0 170,0 180,0 190,0 200,0
2004 2005 2006 2007 2008
mmtpa
World Total
Atlatic Basin Total
18
2.4. Prices
During the period 2005-2008 HH has not been the only price driver for the LNG market. Since the
European markets have gained liquidity thanks to rising number of participants and transparency,
through the liberalization processes, European price indexes have evolved to being a new price
driver equivalent or even more referenced than Henry Hub.
The unbalanced supply/demand scenario in the Asian market has introduced a new marginal price
based on the “Asian anxiety”. New supplies to the US have provided an enormous flexibility to satisfy
the Asian needs.
Source: Stream.
Figure 8: “Brent and Gas indexes evolution, 2005-2008”.
3. Where are we heading to?
3.1. Word Economic Outlook – IMF – January 28, 2009
[…] The world economy is facing a deep downturn. Global growth in 2009 is expected to fall to ½ percent
when measured in terms of purchasing power parity and to turn negative when measured in terms of market
0
20
40
60
80
100
120
140
160
0
2
4
6
8
10
12
14
16
18
nov -04 may -05 dec-05 jul-06 jan -07 aug-07 feb-08 sep-08
$/Bbl
$/MMBtu
Brent and Gas Indexes Evolution 2005- 2008
NBP Nymex Brent
19
exchange rates. Helped by continued efforts to ease credit strains as well as expansionary fiscal and
monetary policies, the global economy is projected to experience a gradual recovery in 2010, with growth
picking up to 3 percent. However, the outlook is highly uncertain, and the timing and pace of the recovery
depend critically on strong policy actions. […]
Figure 9: “Percentage change on GDP growth since 1970”.
Financial markets remain under stress. Financial market conditions remain extremely difficult for a longer
period than envisaged by the IMF in the November 2008, despite wide-ranging policy measures to provide
additional capital and reduce credit risks. As economic prospects have deteriorated, equity markets in both
advanced and emerging economies have made little or no gains. Currency markets have been volatile.
Financial markets are expected to remain strained during 2009. […]
Figure 10: “Growth in Global Industrial Production and Merchandise Trade since 1997”.
20
Global output and trade plummeted in the final months of 2008. The continuation of the financial crisis,
as policies failed to dispel uncertainty, has caused asset values to fall sharply across advanced and
emerging economies, decreasing household wealth and thereby putting downward pressure on consumer
demand. In addition, the associated high level of uncertainty has prompted households and businesses to
postpone expenditures, reducing demand for consumer and capital goods. At the same time, widespread
disruptions in credit are constraining household spending and curtailing production and trade. […] Anemic global growth has reversed the commodity price boom. The slump in global demand has led to
a collapse in commodity prices (Figure 4). Despite production cutbacks and geopolitical tensions, oil prices
have declined by over 60 percent since their peak in July 2008, although they remain higher in real terms
than during the 1990s. The IMF’s baseline petroleum price projection has been revised down to $50 a barrel
for 2009 and $60 a barrel for 2010 (from $68 and $78, respectively, in the November WEO Update), and
risks to this projection are on the downside. Metals and food prices have also been marked down in line with
recent developments. These price declines have dampened growth prospects for a number of commodity-
exporting economies. […]
Figure 11: “Real Commodity Prices since 1980”.
3.2. New Liquefaction and Regas Capacity in the Atlantic Basin, by end 2012
The floating regasification technology will have an important role on the Atlantic Basin LNG demand
projects. 4 new floating terminals are expected to come on stream in the next few years, boosting
the regasification capacity in the Atlantic Basin. This will enable to satisfy the demand of areas like
South America, which is gaining importance on the global picture, as we can see on figure 13.
Europe terminals are gaining importance, with the hope of local governments of diversifying their
energy portfolio.
21
On figure 12 we can observe how new liquefaction players are entering the market. None of the new
liquefaction projects are under construction (only Angola), and only some of them have FID taken
(the last FID to be published was Angola’s project).
Source: Stream. Figure 12: “Liquefaction and Regas Capacity in the Atlantic Basin, by end 2012”.
3.3. LNG Demand (mtpa, 2008-2012)
0,0
10,0
20,0
30,0
40,0
50,0
60,0
70,0
80,0
90,0
100,0
110,0
120,0
2008 2009 2010 2011 2012 2013
mmtpa
North America
Latin America
Europe
Source: WoodMackenzie – Feb’09.
Figure 13: “LNG demand for Europe, Latin America and North America, 2008-2013”.
New Regas Capacity
New Liquefaction Capacity
Freeport, Sabine & Cameron
South Africa?
Kuwait
Reloading Terminals
Zeebrugge
Croatia
Croatia
Netherlands
22
0,0 10,0 20,0 30,0 40,0 50,0 60,0 70,0 80,0 90,0 100,0 110,0 120,0 130,0 140,0 150,0 160,0 170,0 180,0 190,0 200,0 210,0 220,0 230,0 240,0 250,0 260,0 270,0 280,0 290,0
2008 2009 2010 2011 2012 2013
mmtpa
World Total
Atlatic Basin Total
Source: WoodMackenzie – Feb’09. Figure 14: “LNG demand. Atlantic Basin vs. World Total, 2008-2013”.
3.4. Effective Liquefaction Capacity in the Atlantic Basin (mtpa, 2008-2012)
Source: WoodMackenzie – Feb’09. Figure 16: “Atlantic Basin suppliers’ Effective Liquefaction Capacity, 2008-2013”.
0,0
10,0
20,0
30,0
40,0
50,0
60,0
70,0
80,0
90,0
100,0
2008 2009 2010 2011 2012 2013
mmtpa
Trinidad
Norway
Nigeria
Equatorial Guinea
Angola
Egypt
Libya
Algeria
23
0,0 10,0 20,0 30,0 40,0 50,0 60,0 70,0 80,0 90,0 100,0 110,0 120,0 130,0 140,0 150,0 160,0 170,0 180,0 190,0 200,0 210,0 220,0 230,0 240,0 250,0 260,0 270,0 280,0 290,0 300,0
2008 2009 2010 2011 2012 2013
mmtpa
World Total
Atlatic Basin Total
Source: WoodMackenzie – Feb’09.
Figure 16: “Effective Liquefaction Capacity, Atlantic Basin vs. World Total, 2008-2013”.
3.5. Relevant issues - Demand
The current economic and financial crisis will be one of the mayor drivers of the LNG market in the coming
years. It will affect both, supply and demand, leading the market to a dramatic slowdown, and flooding the
Atlantic Basin with LNG. Some of the following issues could help us to understand the near and long term
prospects shaping the future energy scenarios:
• When analyzing former crisis, we can see how demand was significantly affected in OECD countries,
while emergent countries never had negative demand growth. During the 1980 crisis, the OECD
countries had negative demand growth for six years. On the other hand, during the 1990s Asian
crisis, import levels were back to pre-crisis level in less than two years, but few expect such a quickly
recovery nowadays, as the main economies have been severely shattered. The 3 main LNG
importing countries are members of OECD. As an example, Japan LNG imports fell 9.6% from 3Q08
to 4Q08.
Figure 17: “OECD members as of 2009”.
24
• The global recession has sparked industrial closures worldwide, some will not be able to be back on
track in the short run. Plunge in LNG demand for both, industrial use and power generation, the main
LNG destinations, shows how LNG demand is more elastic than oil as it is only marginally employed
for transportation.
Source: WoodMackenzie – Feb’09.
Figure 18: “US’ Gas demand by sector since 1990”.
Source: WoodMackenzie – Feb’09. Figure 19: “Spain’s Gas demand by sector since 1990”.
Source: WoodMackenzie – Feb’09. Figure 20: “UK’s Gas demand by sector since 1990”.
25
• LNG use for power generation is directly affected by substitute fuels prices. LNG can be replaced by
cheaper alternative fuels, like coal or even nuclear in the long run. Oil end use different to natural
gas!
• CO2 emission costs: certain fuels, like coal, become more attractive as the CO2 emission costs
diminish. Countries under Kyoto protocol would encounter restrictions when switching to higher
polluting fuels.
Figure 21: “Merit order of generation volumes across Europe, assuming CO2 trades at 20 €/tonne”.
Figure 22: “Merit order of generation volumes across Europe, assuming CO2 trades at 7.5 €/tonne”.
• US domestic gas production has rocketed thanks to the development of unconventional gas reserves
(shale, tight, etc.). Unless the US becomes the last resource or best paying market, higher cost of
unconventional gas, could increase prices. Breakeven value of shale gas is expected to be around
26
5-6 $/MMbtu. President Barack Obama is promoting domestic supply of energy, and diversification
of energy sources.
Figure 23: “Gas domestic consumption and supply in the US since 1990, and projections”.
• LNG demand will be leveraged by the environmental and technical pros of power generation through
CCGTs. President Barack Obama’s energy plan focuses, among others, on creating a cap-and-trade
system to reduce carbon emissions 80% by 2050, and reducing energy use and costs increasing
energy efficiency.
• Record temperatures have been recorded these past years, making LNG less needed during the
winter periods. According to several studies, we are immersed in a global warming situation. Impact
of weather on demand will depend on weather severity compared to former and future years. LNG
demand will also be impacted by excess hydro supply in countries like Brazil or Spain.
• Long term contracts linked to oil indexes are becoming less competitive than spot LNG, in the
current price scenario. Asian offtakers have applied DQT (Downward Quantity Tolerance) and
European buyers are applying DFT (Downward Flexibility Tolerance), or even nearing the Take or
Pay clauses.
3.6. Relevant issues – Influence of Pacific Basin
• In first three quarters of 2008, no Asia-Pacific (Indonesia, Brunei, Malaysia and Australia) region
cargo moved west of Suez. In 2Q09, already several spot Australian cargoes will be landing in NWE.
• Only one Middle Eastern cargo unloaded in North America, in first three quarters of 2008. This will
swift to a large number of cargoes being destined to North America, with more LNG projects coming
on stream, and USA becoming the last resource market.
Consumption
Domestic supply
Net Imports
AEO2008 reference case
16%14%
AEO2009 reference case
3%
10
15
20
25
30
1990 1995 2000 2005 2010 2015 2020 2025 2030
Source: EIA Annual Energy Outlook 2009 Reference Case Presentation
History Projections
27
• Far Eastern companies are currently reviewing downwards their demand scenarios, because of the
global recession, and not knowing what to expect.
• Some of the new LNG supply coming on stream is based on non conventional gas, like coal bed
methane which is quality wise difficult to accept by Far Eastern countries.
3.7. Relevant issues – Supply
• Over 82 mmtpa of new LNG supply will come on stream during the next three years (more than 50%
of it in Qatar).
• It takes around four to five years from FID for a liquefaction facility to start commercial operations.
Those projects with no finance secured may be cancelled or postponed indefinitely, as current
lenders are more risk-averse. The financial market turbulence has caused the biggest shift to safety
since II WW. If no FID is taken, when demand comes back on track, no incremental supply will be
there. Brass LNG, OK LNG and NLNG T7 are just some of the projects facing further delays in FID.
• In some of the producing countries, NOCs are the main contributors to GDP. There is not enough
investment capacity, and NOCs might need help from IOCs, to keep the business running, as well as
for new project developments.
• The downturn of LNG demand is also a challenge for producers:
o Long Term LNG contracts with increased destination flexibility will be able to redirect
cargoes to premium markets, now located in the Atlantic Basin.
o In the same way that LNG importers will struggle to meet Take or Pay obligations,
producers will have to do their best to avoid production cuts in their liquefaction facilities
(lender requirements, LPG’s).
• Construction and labor costs will plummet, because no new projects will be started, and construction
capacity will be idle.
• Securing gas supply for new projects has been increasingly difficult over the last few years. NOCs
are starting to demand a bigger portion of the cake, as gas to be retained for domestic consumption.
• Demand contraction in Europe will have strong consequences for LNG exports to these countries.
• China’s and India’s new regas capacity have the potential to create new demand hubs for diversions
as they have a huge latent demand for power and fertilizer.
28
C. Global LNG Markets
Mr. Yves Cerf-Mayer, Total Trading Global LNG Markets – New Hubs – Update July 2009
1. LNG Global Trends Global LNG: Short Term Concerns
2008 Situation
After 8 years of strong growth (2000 – 2007), there has been for the first time since 1981, a stagnation of
the LNG Trade with 173.6 Mtpa delivered in 2008 compared to 174.5 Mtpa in 2007 (0.5% reduction).
4 causes can be identified to explain this situation:
− Shortage of gas supplies (Nigeria, Indonesia , Oman , Egypt)
− Force Majeure (Nigeria, Algeria)
− Technical problems (Norway , Australia)
− Start-up delays (Qatargas II, Tangguh , Sakhalin II).
Nevertheless, Asian LNG imports in 2008 (118.64 Mt) surged by + 5.4% on year-to-year basis.
Additional purchases from the Middle East (Qatar & Oman) and from Atlantic producers compensated for
lower supplies from Asia – Pacific.
In 2008, the volumes diverted from Atlantic into Asia were twice the volumes diverted in 2007: 15 Mt /
247 cargoes versus 7.6 Mt / 131 cargoes.
Short Term 2009-2011
The economic crisis impacts gas demand on all markets, particularly the industrial sector
LNG Supply capacities build up significantly (+ 95 Mtpa), almost +50% more supply capacities above
2008 world trade level
Unconventional gas to LNG competition in the US affects LNG growth on this market.
Although the new capacities are already committed, it is possible that there could be insufficient demand
in 2009-2010 to absorb the entire LNG supply on offer. Besides in 2009-2010, there would be hardly any
need for the Asian Buyers to call LNG volumes from the Atlantic Basin.
There will be a downward pressure on spot – short term gas prices during this period
As at mid 2009, the global LNG demand is falling by an estimated 7 to 9 % as recession takes
effect, whereas supply availability will increase by almost 8% over 2009-2011
But there are also long term supply question marks
29
Long Term - 2012 / 2013 onward The current disconnect between costs and commodity prices is an added hurdle for new projects: a
shortage of project sanctions today means limited supply growth tomorrow.
Demand for LNG will recover based on solid fundamentals:
− Growth of global energy demand and competitiveness of Natural Gas (versus Coal and Oil)
− LNG specifics : Security of Supply and diversity of supply.
But the LNG market, particularly in Asia-Pacific, will be then again constrained by supply limitations
As at mid 2008, almost all LNG market experts had great expectations that the growth of spot/short term
LNG trade, particularly in Asia, would continue to rise steadily from 2009 towards the forthcoming
decade.
Almost a year ago, the main issue that the LNG Industry had to address was to secure enough LNG
volumes & cargoes to meet a steadily growing demand.
Today, after a 180º downturn, the urgent issue to be solved is to find sufficient outlets to dispose of a
substantial part of the LNG supplies from existing productions and from new facilities coming on stream
in 2009-2011. No one would be fool enough to try to predict how the LNG markets will react within the
forthcoming 6 to18 months if the global recession continues to contribute to further shrink the energy
demand.
However, Flexibility, whether contractual, operational or commercial, will be an essential asset for the
resilient players who have set in their business models flexibility features such as diversion clauses and
Master Trading Agreements to mitigate, defend and optimise their positions.
2. LNG Hubs & Flexibility
Worldwide LNG production (Mtpa)
Existing + decided projects
Probable projects
Barents
0
50
2005 2010 2015 2020
North Africa
0
50
2005 2010 2015 2020
Latin America
0
50
2005 2010 2015 2020 West Africa
0
50
100
2005 2010 2015 2020Middle East
0
50
100
150
200
2005 2010 2015 2020
Asia - Pacific
0
50
100
150
200
2005 2010 2015 2020
30
Global LNG projects: emergence of the Middle East
Global LNG – « Hubs » (1) Mature Markets (up till 2007) Mature Producers (up till 2007)
Asia Pacific Asia Pacific
− Japan - Alaska
− Korea - Indonesia
− Taiwan - Malaysia Europe - Brunei
− France - Australia (1)
− Spain
− Belgium Middle East
− Italy - Abu Dhabi
− Greece - Qatar
− Turkey - Oman
− Portugal North America Africa / Atlantic
− USA - Algeria
− Mexico - Lybia
− Puerto Rico - Nigeria
− Dominican Republic - Egypt - Trinidad
Global LNG – « Hubs » (2)
Production Hubs/ Trends (2008- 2009)
Mediterranean Zone Algeria upward Lybia upward
Egypt upward
Europe Norway stable
Russia / Artic upward
Africa
Nigeria upward
Equatorial Guinea upward
Angola upward
Latin America / Caribbean
Trinidad stable
31
Middle East
Abu Dhabi stable
Qatar upward Oman stable Yemen stable
Asia Pacific
Alaska decline
Indonesia decline Malaysia stable
Brunei stable
Australia upward Russia / Far East upward
Global LNG – « Hubs » (3) New and Future Markets (from 2009 onwards)
Asia Pacific
− India
− China
− Singapore
− Thailand
− Philippines
− Hong-Kong
− New Zealand
− West Coast Mexico
− California
Middle East
− Kuwait
− UAE
Europe
− Germany
− Poland
− Cyprus
− The Netherlands
− Croatia
Africa
32
− South Africa
Latin America
− Brazil
− Chile
− Argentina
Global LNG – « Hubs » (4) New and Future Producers (post 2009)
Asia Pacific
− Russia / Eastern Siberia
− Australia (2)
− Papua New Guinea
− East Timor
− Peru
Europe
− Norway
− Russia / Artic Middle East
− Qatar Expansions
− Yemen
− Iran
Africa
− Equatorial Guinea
− Angola
− Algeria (2)
− Lybia (2)
− Nigeria (2)
Latin America
− Venezuela
− Brazil
Flexibility: LNG Market Status
The 2 main LNG markets, Atlantic- Europe and Asia- Pacific, are now in full communication. However they
remain different from each other.
33
The first one, Atlantic-Europe, is an almost fully liquid gas market, with gas to gas competition, with plenty of
pipeline gas resources and infrastructures, with a robust LNG regasification capacity on both sides of the
Atlantic Ocean and interconnected regional gas markets in Europe and a gigantic pipeline network in North
America.
It is characterized by almost transparent gas market prices based on few public indexes and a huge
capability to swap and trade commodities
The second one, Asia-Pacific, is not a liquid market but a physical one.
It will remain made of segregated gas provinces for a long while and because of the lack of inter-regional
pipeline infrastructures in Asia, LNG imports constitute the only major source of supply to bring gas to the
national markets. Market prices in Asia are still often based on long term features, inherited of “1 to
1“historical negotiations.
Most of the LNG Btu’s imported and traded in this market must in the end be delivered to the wholesales
buyers (utilities) and swaps and trading capabilities remain limited on this market.
What means nowadays « Flexibility »? In the past years from 1970 till 2000, Flexibility was mainly volume oriented but remained subject to very
limiting factors within the limits of the LNG trades.
Defined in the long term SPA’s, Flexibility affected directly the value of the trade, i.e. a downward flexibility
exercise would reduce the NPV of the contract if not made-good and had to be limited (few cargoes per year)
and compensated rapidly.
Nowadays, new conditions in the LNG Industry worldwide have created new opportunities.
There are more regasification capacities than supply, representing a 2 to 1 factor versus production.
Also very significant shipping capacities have been added to the world LNG fleet since 2000.
There are now new types of SPA’s provisions, particularly in the form of multiple destinations and diversion
clauses which tend to become common features in all contracts. Whereas in the past years, it was more
Force Majeure situations which justified diversion rights.
Diversion - Flexibility - Security of Supply
Diversion capability has become since 2000 one of the main factors behind increased flexibility in the world
LNG trade.
Diversions currently and for long will remain triggered mainly by price differentials between markets (i.e.
typical « arbitrage situation » based on short term actions), short term supply imbalances and
synchronization issues around matching LT supply to LT demand (often in the case of early or late start-up of
new facilities).
However, for mature major markets in Asia, namely Japan, Korea and Taiwan, flexibility should not impair
security of supply which is of paramount importance for these gas consuming markets dominated by LNG.
34
On the long term, market forces are the key factors which will limit flexibility to a reasonable degree. Too high
gas prices compared to other conventional fuel sources (fuel oil and coal) will trigger re-adjustments of the
fuel mix of the Buyers: either switching to other fuels or reducing demand growth especially for industrial
sectors, until the gas market prices are readjusted downward to regain competitiveness in those markets.
35
Chapter 3: LNG Contracts A. Factors to make LNG trading more flexible
Flexibility of LNG – A Misperception ?
Mr. Eberhard Lange, E.On
To make LNG trade more flexible requires fulfilment of many preconditions. The early days of LNG did not
know flexibility other than volume flexibility, when security of supply underpinned by long term take or pay
obligations was of paramount importance. Supply chains were restricted to bespoke flows from A to B.
Increasing LNG volumes supplying growing markets, which in turn required more seasonal and annual
flexibility, called for instruments to match volatile demand and rigid LNG imports. Most LNG importing
countries reacted by building more LNG storage capacity, partly to build up a strategic national reserve,
partly to cover seasonal swing.
A true change in LNG trade occurred, when first swaps were arranged to save transportation cost and when
peak demand in the leading LNG import countries attracted single cargoes at attractive prices away from
their long term trades. Buyers and producers enjoyed extra margins. On the other side, surplus volumes
found their way into terminals in US, acting as a sink of a global LNG market.
The share of short term or spot trade increased slightly but steadily, and it was only until last year that the
majors were convinced, that spot share would not increase beyond the 15 % mark. What started as the last
resort or first aid in times of shortage in suffering markets, developed into an arbitrage driven traders’ market.
This flexible trade was made possible through the availability of
• volumes in excess of firm supply commitments from operating liquefaction plants and start ups
• contractual volume flexibility, or downward adjustment rights
• spare shipping capacity to cover the extra needs due to the longer distances
• ships acceptable for the respective harbours
• willing sellers and buyers
• the right price
• free capacity in receiving terminals
• compatible LNG quality
• a liquid import market.
The flexible supply pattern is supported by some producers’ strategy to sell ever more volumes with
diversion rights. Possibly not the most economic way, albeit potentially the more profitable way for
producers.
36
Thus, LNG can flexibly contribute to closing any gaps that may arise on the energy markets by creating
greater diversification for the supply and demand countries as well as improve supply security. As a
consequence of the current economic turmoil and the demand reduction, more spot cargoes will be moving
around globally, with the North American LNG market possibly acting as a sink for residual supply, if not
needed elsewhere.
To summarize: An increasing globalisation of LNG flows is likely due to companies’ strategic positioning, the
development of flexible LNG portfolios and pricing arbitrages. The spot market will gain in significance and
may surpass its current 15 % share of the market. Arbitrage as well as spot possibilities will increase as a
consequence, even if these approaches are vulnerable to physical restrictions such as shipping distance,
gas quality and market access.
Yet, sellers and buyers will benefit from a flexible LNG market.
B. Pricing Formula and Mechanism
Mr. Angelo Ferrari, Eni
Mr. Yves Cerf-Mayer, Total
The world LNG market has become increasingly global and therefore the different regional LNG markets are
now fully interrelated.
According to different typologies and peculiarities, one can divide the consuming markets in two main zones:
• USA and Europe (the “Atlantic Basin”)
• Pacific Rim, North-East and South-East Asia (the “Asia Pacific Zone”).
While for the Asia Pacific Zone LNG has been and remains for the moment the only practical way to develop
gas markets, Europe and USA can choose their supply sources between LNG and piped gas, both domestic
or imported, depending not only on the differentials between the gas prices, but also on other key factors
such as volume flexibility.
With regard to price indexation, trading of LNG can be divided in three well defined areas:
• Continental Europe: where the LNG prices are indexed to Brent and other oil product indices (such
as for instance Fuel Oil or gas Oil prices);
• USA and UK: where LNG price is indexed to specific liquid points where a reference price of the gas
mainly based on domestic productions is established (Henry Hub in USA and NBP in UK);
• Asia Pacific Zone: where the LNG prices are linked to the JCC .
Even if the difference of prices among the three areas can vary remarkably, the interconnection between the
three main markets brought by the development of the worldwide LNG trade is now a reality. One major
consequence is that factors affecting the price of LNG in a certain market are able to influence price on other
37
market with different specific patterns for the only reason of the flexibility associated to the possibility of
diverting cargoes from one to the other market.
LNG arbitrage between gas markets is made primarily through price signals, almost in the same way as the
commodity market operates.
The adjustment of the supply-demand equation on the non liquid gas markets, i.e. mainly in the traditional
Asia LNG markets where there is no substitute, such as piped gas, is now partly solved through the price
issue and competition for the LNG resource in the form of bidding for spot or short term cargoes to a limited
number of producers or International Oil Companies holding the spare/excess volumes.
LNG markets – Basic trends
In a medium/long term horizon the global demand of LNG is predicted to grow significantly not only in the
traditional LNG consumers countries (Japan Korea, Europe, USA and Taiwan) but even in new emerging
markets such as China, India, Pakistan, Thailand and Singapore that have limited domestic resources but
the need to face the internal growing demand with a friendly and clean energy. The volume of LNG trade in
the global hydrocarbons market may be relatively small but it increases year on year, almost regularly and
faster than the other energy products. The reasons of the growing importance of LNG in the world gas
market are peculiar for each area: while in the Asia Pacific region LNG is almost the only gas source
available, in Europe and USA the decision to turn more and more towards LNG results from the combination
of three main factors:
-the gradual reduction of the domestic production,
-the growing distance from the production to the consuming areas,
-the willingness to increase energy supply security by diversifying supply sources.
LNG, unlike piped gas that has fixed inlet/outlet points, can be transported with ships and therefore delivered
where it is most needed. This peculiarity led in the past years to a significant growth of the spot market
driven by many external factors such as seasonality of the demand, weather related events, earthquakes
and natural disasters, shortage of other supply sources, etc, thus creating a tension on demand and affecting
the prices not only for the spot cargoes but also for short term.
The recent growing demand of LNG also affected the price requested by Sellers for new long term contracts
that are to remain the vast majority of deals to be entered into.
LNG price evolution (Alternance of Sellers’ and Buyers’ markets)
When the LNG trade started (1969-1974), prices were fixed in “money of the day” terms and there were
premiums up to 70% over the crude oil prices.
The first oil shock of 1973 led to a change in the gas price policy and between 1974 and 1986 prices were
linked directly to crude oil.
In 1986, following the oil price crash, the producers, with the aim to maintain their profits decided to fix an ad
hoc pricing mechanism established on monthly or quarterly basis.
The further recovery of oil prices led to a new era: the Buyer’s market period (1988-2003). LNG prices,
linked to 85% of the value of crude oil, were settled in new formulas introducing a constant element resulting
38
in a 10 to 15% premium over crude oil. Besides in some contracts was introduced a “S” curve mechanism,
which was progressively adopted in all the new contracts and even in order to open new markets, the
reference crude oil prices in the new formulas were capped when they reached 25-30$/bbl.
The oil shock subsequent to the Gulf War led again to a tension of the oil prices and the LNG market has
become again a “Seller’s” period (2005-2008). The price review discussions between Sellers and Buyers
have become progressively more and more difficult and for certain existing Long Term contracts, very large
LNG price adjustments are still outstanding after several years of discussions.
The growth of the demand for LNG in mature markets, the emergence of new players such as India and
China, the delays in the realization of new liquefaction plants, and a strong competition among the various
players to have access to spot cargoes from the excess capacity of existing plants have been key factors
contributing to giving some advantage to Sellers in the global LNG trade.
However, starting from the last quarter of 2008, the entire world has been hit by a very severe financial and
industrial crisis and even if from the second half of 2008 crude oil prices fell down from 150 to around 60
$/bbl nowadays, the effect of the crisis on the LNG Industry has been a downfall of the energy demand
against an oversupply situation due to the exercise of Downward Quantity Tolerances by the Buyers on all
the Long Term contracts.
It is probable that the stagnation of the consumption which could last for at least a couple of years and the
massive LNG supply capacities build up (+95 Mtpa within 2012) will create a significant downward pressure
on spot-short term gas prices, within a general lower oil price environment than in 2008.
Will there be a new era for LNG prices? Signals are showing that the “pendulum” is moving again
(towards//backwards) to a more uncertain (less clear-cut) type of market characterized by a relative LNG
demand stagnation against temporary regasification and shipping overcapacity (2009-2012), and then again
towards a foreseeable shortage of new liquefaction and supply capacities by 2015.
What could be the impact on LNG prices under such market conditions is difficult to predict. Most likely LNG
prices will settle down slightly below 100% crude oil parity prices for a certain period but there will remain the
risk of tension due to the possible shortage of supply on the long run.
As it happened in the past, Sellers and Buyers should be prepared to work again towards improving
traditional LNG pricing terms and conditions to enable both parties to reach an equitable sharing of risks and
benefits.
In an ideal world, the alternance between LNG Sellers’ and Buyers’ market periods would progressively
disappear reaching a true commodity price situation.
The future impact on the gas prices
The world energy demand is predicted to grow again in the coming years mainly driven by the Power
Sector and the role of natural gas is expected to assume a leading role within the basket of fuels. Generally,
it was anticipated that the price of the gas to final customers should be lower than the price of the alternative
fuels. This statement was the rule in those previous years when natural gas competed on the final markets
with alternative fuels oil derivates. The recent significant increase of LNG price and indexation could lead
some industrialized countries to reconsider the possibility to turn to nuclear or even to coal or to renewable
39
sources and many developing countries to turn to any available form of energy without considering the long
term environmental impacts.
With the aim to boost on the use of gas, producers and consumers have to understand the constraints and
the needs of each counterpart and have to work together to meet a common goal, being convinced that it is
a game where there cannot be losers or winners.
Global LNG trade growth has encouraged the launching of several new potential liquefaction projects even if
only a few of them have been or are going to be sanctioned in the short term. In reality, most of them have
been delayed or cancelled due to the increase of material, engineering and construction costs, because of
strong competition among the few available EPC contractors, and last but not least the decision of many
producing countries to use most of the gas produced for domestic consumption and internal gas industry
growth.
The unavailability of LNG could also aggravate the gap between demand and supply thus creating a
competition among the buyers and resulting in a relative distortion and artificial growth of the LNG prices,
giving to the Sellers the possibility to maximise returns for the supply of LNG.
In a context of high oil price environment, Sellers are tempted to impose pricing formulas directly linked to oil
prices (Brent or JCC) with slopes set to grant high sensitivities to oil price movements. Often, such type of
formulas are also inserted in a contractual framework that implies 100% Take or Pay clauses with no
flexibility in the definition of the Annual Delivery Program, where cargoes have to be rateably distributed
along the contract year.
These formulas and contractual frameworks of course give some protection to the Sellers who have to face
enormous investments related to new projects’ development but not always a reflection of the way in which
natural gas is effectively sold on the final markets.
It is nevertheless worth highlighting that a Buyer, selling LNG to specific markets has generally to deal with
the following:
1) Demand seasonality and peak requirements
2) Different type of formulas and indexations
3) Competition with pipeline gas (at least in US and European markets)
4) Competition with alternative fuels (i.e. other oil products, coal, nuclear etc...)
5) Competition with specific market price indexes (electricity and gas indexes),
and often has to bear the risk of the misalignment without being able to transfer back some share of the risks
to the producers.
How to get flexibility without impacting on LNG price
Buyers on the one hand are seeking higher flexibility from their LNG deliveries to better meet the needs of
their market, thus reducing the necessity of over sized gas storage capacity and to be able to compete with
alternative energy sources, for instance with hydroelectricity during the rainy season.
40
Sellers, on the other hand, have to try to optimize their investment costs in designing plant facilities
producing LNG as regularly as possible, thus avoiding to over size the LNG storage tanks and the number of
LNG carriers. It appears quite evident that the requirement for flexibility leads to higher costs along the entire
LNG chain.
What could be the solutions to match both Buyers and Sellers requirements without impacting on the
economics of the selling prices?
This is not a simple task but some areas could be explored.
An interesting way could be for instance to try to elaborate contracts which could be both FOB and DES at
distinct periods within the contract term. With such a type of contract, Buyers could elect from time to time to
choose where to dispatch the LNG that they are obliged to off-take on a steady basis and not in position to
consume on the original contractual market to a range of downloading ports offering the possibility to divert
cargoes. Of course these solutions imply that the Buyers have in place pre-arranged agreements with other
customers or have access to regassification capacities in more than one country whose markets are
speculative in term of seasonality demand. For sake of clarity one has to underline that, in case of DES
Long Term Contracts, Buyers has the right to ask for diversions and Sellers will agree on diverting cargoes in
case the diversions can be managed without interfering with its shipping capacity, In case the diversions
could not be arranged within Seller’s shipping capacity Buyer would have to provide shipping capacity. In
addition to justify the destination flexibility it could be helpful that Sellers and Buyers agree at an early stage
on pricing for each destination. To protect Sellers against risks of sudden revenues changes, the quantities
capable of being diverted from/to a given destination could be restricted within a given range. Alternatively
the Buyer’s role could evolve from a single Buyer to an aggregator, looking for customers in marginal
markets, where to download part of a cargo or to deliver cargoes on spot basis.
Both the solutions evoked above would require great efforts from the buyers to invest in their own fleet and to
find out markets and customers willing to accept such arrangements and in the meantime would protect the
Sellers both in term of return on capital invested, and guarantee regular production profiles for the
liquefaction plants. The agreement between Buyer and Seller should also be structured to avoid an incorrect
use of the diversion right and a profit sharing mechanism when demonstrated that the diversion is a
consequence of the flexibility needs.
Summary of Expectations
It is quite obvious that LNG Sellers and Buyers have different expectations in term of gas pricing:
Sellers’ position
• Pricing formulas directly linked to oil prices with slopes granting high sensitivities to oil price
movement.
• Low flexibility in the definition of the Annual Delivery Program.
• High protection versus the enormous investments related to projects’ development.
Buyers’ position
41
• Pricing formulas both envisaging an indexation linked not only to oil or oil related products but also to
gas and electricity indexes to better reflect market characteristics and an equitable price to protect
Sellers and Buyers in situation of extreme oil price scenario (“s” curve).
• Price revision mechanism to protect Sellers and Buyers in respect of changes in the energy market
that affect the value of the gas.
• Higher availability from the Seller to settle a mechanism that allows Buyers to manage the flexibility
of supply without impacting the selling price.
However it is also quite clear that Sellers and Buyers have still to reach out solid compromises in order to
guarantee the sustainability of their own businesses.
C-1. Duration / Term / Extension
Mr. Hajime Nakamura, Tokyo Gas
1. Long-term Contract Since LNG was first delivered in 1964, long-term contracts have been a majority in LNG trades.
Developments of LNG business are so capital-intensive that long-term commitments before making final
investment decisions by both LNG sellers and buyers are very critical.
The duration of long-term contracts depends on various factors. For instance, pay back period is important
for both sellers to recover Capex of gas producing facilities and liquefaction plants, and buyers to recover
costs related to regasification terminal and transport pipeline. For that reason, the term of ten (10) years is
generally thought to be the minimum term in LNG business. However, longer contract term is more
preferable in most of the LNG projects, especially for investors and financiers from a viewpoint of
stabilizing cash flow. Therefore reserves at an initial stage would be the most crucial factor to determine
the duration in each LNG project. Many LNG projects have long-term contracts of twenty (20) years and
more. In some cases, the duration can be extended by exercising an option of either a seller or a buyer if
additional reserves are proven up after the sales and purchase agreement is signed and effective.
The characteristic of LNG business has made both sellers and buyers to provide limited opportunities to
trade LNG in the market, historically. As a result, LNG has not been a very liquid commodity as petroleum.
2. Short-term and spot contract In the last decade, numbers of LNG cargoes were traded on spot and short-term basis. Especially, in
2008, remarkable numbers of LNG cargoes were diverted from the Atlantic basin to the Asia pacific region
due to demand increase and supply shortfall in the Asian countries. On the contrary, some cargoes are
traded from east to west in early 2009 due to the demand plunge in the East Asia triggered by global
financial turmoil. These are typical examples of spot and short-term trading.
42
Following are some of the reasons why spot and short-term trading have been popular in the LNG
business. Apparently, there have been changes to the marketing structure of LNG between sellers and
buyers as LNG market has been growing, that have contributed to a more liquid LNG market.
Some LNG projects made final investment decisions without 100% off take commitment by
buyers, and such uncommitted quantities could be available for spot and short-term trading.
In the Atlantic region, “Equity LNG” and “Branded LNG” were created under long-term contracts.
Equity LNG is such a concept that LNG produced in a project is lifted by its investors according to
its shares for their own marketing. Branded LNG means non-consuming buyers purchase LNG
from various LNG projects and sell LNG to buyers under their names from their supply portfolio
without specifying a single supply source.
The new spot LNG was coming from a buyer’s receiving terminal. The cargo is originally sold by
a seller, unloaded, and stored in an LNG tank of a buyer’s receiving terminal for a while, and then
re-loaded and shipped to the second buyer.
Small numbers of traditional long-term contracts, especially in the Asia Pacific region, include destination
flexibility. Spot and short-term trading have been and will be useful to cope with seasonal and/or
unexpected demand fluctuation, but long-term contracts will definitely continue to be the base for LNG
procurement.
Most of green field LNG projects are recently anticipated to be delayed in start-up due to more complex
processes and increased number of construction equipments; in some region due to shortage of labors,
and difficulties in environmental approval for plant constructions. Some conventional LNG sellers are not
so confident of extending their contractual commitments because of uncertainties in gas reservoir and
brisk demand for natural gas in their countries. Worrying about such slippage of green field LNG projects
and feasibility of conventional LNG projects, buyers have to rely on short and middle-term contracts. For
years to come, the number of short and middle-term contacts will increase.
3. Downscaling of LNG liquefaction project For many years, only large gas fields have been developed for LNG mainly due to economical reasons.
LNG liquefaction capacity has been larger to pursue scale economics. However, there is a new challenge
that small-middle gas fields will be developed for LNG. In order to materialize them, cheap prefabricated
liquefaction plant of simple process has been developed. Development for small scale offshore gas fields
using floating LNG vessels is also considered, while it is not realized yet at this moment. It is said that one
of the benefit of floating LNG concept is that it can improve the economics if, after the first gas field is
depleted, it is redeployed and used in the next field.
These small LNG projects seem to have more difficulties in development than traditional large LNG
projects. But they will become economically viable in the future by technology improvement. Considering a
number of potential gas fields will be popular in the future, once such technology is successfully developed
43
and matured. Due to shorter lifetime of these projects by nature, average duration of LNG contracts will be
shortened accordingly.
4. Conclusion Longer contractual duration of off take has been essential for many years in LNG business. It is still one of
the key components in development of LNG in many green field projects. However, LNG contracts have
recently been diversified to combination of long-term, middle to short-term, and a spot basis, owing to the
development of new marketing, maturity of LNG technology, increased shipping capacity and technology
innovation. Such trend toward increase of shorter term contracts will continue to the future as LNG market
grows.
C-2. Duration / Term / Extension
Mr. Abdulla Ahmad Al-Hussaini, Qatargas Operating
The term of a LNG sales and purchase agreement should be clearly specified.
The term can be tied to a specific start date or an event, usually referred to as Commencement Date.
The term of an agreement should not extend beyond the period that a seller or buyer can meet their
contractual obligations; Examples would be the expiration date of a license, ship charter required to deliver
LNG, terminal capacity agreements required to receive LNG or other rights to ensure LNG can be delivered
to the point of sale.
The Commencement Date may be later than the Effective date of an agreement and can be determined as
follows:
• Agreement of a specific date by the buyer and seller for the start of LNG deliveries
• In the case of a seller, tied to the start-up of a new LNG production train or expansion
• In the case of a buyer, the start-up or expansion of a terminal or other buyer’s facility where the LNG is
to be received or used
The procedure for establishing the Commencement Date should be clearly specified in any agreement. Any
option period should be clearly specified and the ending period be clearly specified so there is clarity about
the start of take-or-pay obligations or an obligation to deliver. Ambiguous language related to the completion
of buyer’s or seller’s facilities should be avoided.
Industry practice is evolving with respect to the duration of LNG contracts and generally falls into three
categories:
• Long-term – 20-25 years
• Medium-term – 3-5 years
44
• Short-term – 1 cargo to 2 years
Rights which may have accrued during the term of an agreement should survive the termination of an
agreement.
Contract extensions can be included in an agreement and generally fall into three categories:
• Mutual agreement by buyer and seller
• Seller’s option to extend
• Buyer’s option to extend
Price considerations or price reopeners might be included as part of an extension clause.
D. Volume flexibility
Mr. Haksoo Park, Korea Gas Since the recent global financial economy crisis spread out all over the world, we are forecasting that the
world LNG demand will decrease more than the volume we expected in 2008. According to the data of Wood
Mackenzie, the total volume of world LNG demand in 2015 would be 387mtpa (million tones per annum)
which was forecasted in October 2006. But it was decreased from 387mtpa to 311mtpa in their forecast in
November 2008.
However many energy experts have a perspective that it is also difficult for sellers to meet the demand
because of several reasons which are the increase of supply cost, postponement of production, facilities
deterioration, and higher risks in a huge project. In other words, not only the buyer side but also the seller
side will need volume flexibilities more and more in the future.
45
1. What is flexibility?
Flexibility in a contract is defined as the difference between the availability and the offtake/minimum-pay
obligation within a given time span. Flexibility is a concept of the cost. In other words, flexibility costs money;
• Buyer’s side: the flexibility is related with the opportunity cost of fuel switching.
• Seller’s side: Enhancing flexibility can be considered that it needs an extra investment. It means that this
needs adding cost.
The cost of flexibility can be identified as a separate item so that flexibility can be sold on its own. A decision
can then be taken as to whether it is more economic to provide flexibility upstream or downstream as well as
on the cost of transporting the flexibility from the delivery point to the place of consumption.
* Flexibility in gas contracts
•Buyer’s side - Flexibility required by the buyer has cost implication; because gas can not be stored easily,
requirements for flexibility of supply and acceptance must be decided before the capacity of the gas chain is
finally fixed. This determines investment and revenue created in the chain is a function of the utilization rate
of this capacity.
•Seller’s side - On the contrary, producer can consider creating flexibility as an extra investment (main
investment is the upward/downward flexibility in the LNG contracts) or as lower utilization of the investment
guaranteed by the buyer.
• Terminologies
- Downward flexibility: option to ask for 10% less than ACQ
- Upward flexibility: option to ask for 10% more than ACQ
- ACQ=Annual Contract Quantity
Therefore we must consider the flexibility on both the buyer and the seller. Nevertheless it costs, cost of
flexibility is more reasonable than the cost that buyer or seller should pay for LNG spot on unexpected
period.
2. Contract as flexible as a safety pin
* Contract quantities
Seller provides daily production estimates for project life of 20 years. Daily quantities are given under these
conditions;
• Build-up period - 40% within 6 months and 60% by the first year
• Plateau period - Builds up to peak and flattens to plateau
• Decline period - after plateau period, production continues to decline until abandonment.
* Seasonal demand
46
Specific methods to cope with seasonal variations linked to the power system may be cheaper than the cost
of providing any extra capacity in the gas system.
On the buyer’s side, instrumentalities are needed to cope with long-term developments such as market
growth. These may take the form of investment in additional capacity.
Instrumentalities are also needed to cope with fluctuation in demand on an annual or daily basis. In such
cases, the capacity must already be available, or customers would have to be cut off (that is interruptible
one).
3. Risk mitigation and Risk sharing * Buyer’s Risk : Volume risk (take or pay)
- Mitigation : No take or pay during debt repayment, Cargo diversion(if buyer is unable to take)
- Seller’s countermeasure : Revenue uncertainty, Indifferent to diversion if resale is not in seller’s current
market
* Seller’s risk : Seller’s supply failure due to non Force Majeure causes (Shortfall penalty)
- Mitigation : Work out the failure probability and build in the financial consequences in the price, try to
avoid default liability
- Buyer’s countermeasure : Requesting the cargo flexibility during supply year
* Buyer’s side: delay in market opening
- Buyer can not import LNG from overseas because buyer’s country has some trouble to start the gas
market system.
* Seller’s side: delay to start LNG project
- Seller can not export LNG to buyer because seller’s country has some trouble to start to supply it.
* Compensation
- Failure to fulfill the gas volume obligation (to take or to supply) raises the question of compensation.
- This would involve a minimum payment for the buyer and default rebate for the seller if commitments are
not fulfilled. In both cases, the sum would depend on the extent to which contractual obligations were not
fulfilled.
4. New trend in LNG contracts
* The change of circumstances
- Seller may require change in the production profile; the seller may ask for possibilities to change the
plateau rate, length or both as a function of the performance of the reservoir.
- Buyer may require change in the rate with market; the buyer’s interest will be a long and stable plateau
possibly with the option to change the plateau rate to adapt it to changes in the market.
47
* Case study of Sakhalin 2
- It will be delayed for Sakhalin 2 to supply the gas from the original schedule on the end of 2008 to April
2009. This will result in a shortfall of 5mtpa (Japan) and 1.5mtpa (Korea) out of 9.6mtpa Sakhalin production
• But secondary market of LNG is on very poor circumstances. Therefore it is almost difficult to copy
with such a condition only by LNG spot supply.
• Therefore it is important not the penalty but how to satisfy the demand of buyer’s country. In case of
Korea, it is not easy to substitute other fuels for LNG because of market specification. If then, the
problem of flexibility may spread it out to the energy security.
* New trend in LNG contracts
- There is a competition among buyers; China, India, Japan, Korea and Spain etc.. At the same time, Coast
Azul terminal in Mexico which is newly opened will put demand on Asia-Pacific LNG.
- Buyers are seeking more flexible supply terms; shorter term or mixed term SPAs. Buyers are also
negotiating greater flexibility in build up period, make up and carry forward right.
• Terminologies
- Carry forward: carry forward is a credit to be set off against TOP but up to a limit 25% of MQ (Minimum
Quantity)
- Recently, a contract (combined 680,000tons per year) was signed between three Japanese companies
(Tokyo Gas, Osaka Gas, Toho Gas) and MLNG (TIGA). This provides 40% volume flexibility instead of
5~10% in conventional contract.
- BP signed a 3 year contract with Adgas for flexible volume varying between 300,000 and 750,000 tons per
year.
E. Incoterms
Mr. Jean-Noël Mesnard, GdF Suez
The Incoterms (“International Commercial Terms”) are a set of international rules established by the
International Chamber of Commerce (ICC) for the interpretation of the most commonly used terms in
international sales with respect to the delivery of goods.
The first Incoterms were published in 1936, they were then regularly updated or amended to remain in line
with international trade practices ; the most recent version was issued by ICC in 2000.
ICC has grouped the different terms (13 different terms have been defined so far for global trading of goods)
in 4 different categories, depending on the conditions according to which the goods are delivered by seller to
buyer.
48
Incoterms define the reciprocal obligations of seller and buyer under an international contract of sale and
purchase and specify the respective responsibilities of the parties, but do not specify the point at which title is
transferred (to be decided by the parties). Incoterms set out how the associated costs and risks are
apportioned.
In the LNG industry the most commonly used Incoterms are FOB (free on board) and DES (delivered ex-
ship). Very few transactions are based on CIF (cost, insurance and freight) term.
• LNG Sales FOB
In a FOB sale, the seller delivers and transfers risks (and generally associated title) of the LNG to the buyer
at the exit point of the liquefaction plant in the loading port ; from that point the buyer has to arrange and pay
for sea transportation and to bear all costs and risks of loss of or damages to the LNG. The buyer also
provides for unloading and regasification or arranges the sale of the LNG cargo to another party at the exit
point of the liquefaction or at any point further.
source : GIIGNL
• LNG Sales DES
In a DES sale, the seller delivers and transfers risks (and generally associated title) of the LNG to the buyer
at the inlet point of the regasification plant in the unloading port. The seller has to arrange and pay for
liquefaction and sea transportation and to bear all costs and risks of loss of or damages to the LNG until this
point. Buyer has to provide for regasification or arrange the sale of the LNG cargo to another party at the
inlet point of the regasification terminal.
49
source : GIIGNL
It has to be noted that the new version of the HNS1 convention, currently under ratification, may seriously
affect the existing balance between DES sellers and buyers of LNG regarding the impact of financial
contributions to the HNS compensation fund: in the near future the LNG “receivers” (i.e. the buyers) will have
to bear the main part of the burden, whatever is the Incoterm chosen in the relevant contract. This new
liability may make more complex LNG sale and purchase contracts negotiations.
• Incoterms’ use in the LNG industry
The following is a compilation of the long term LNG sale and purchase contracts in operation within the 1980
– 2020 time period2.
Historically the DES contracts have always represented an average of 60% of all LNG contracts, in terms of
number of contracts as well as in terms of annual contract quantity.
1 HNS Convention is an international treaty dealing with parties’ liabilities in case of accident involving sea transportation of Hazardous and Noxious Substances. 2 Sources : GIIGNL/Cedigas/Poten & Partners/GDF SUEZ.
DISTRIBUTION OF CONTRACTS IN OPERATION (Number of contracts)
0
20
40
60
80
100
120
140
1980
1983
1986
1989
1992
1995
1998
2001
2004
2007
2010
2013
2016
2019nu
mbe
r of
con
tract
s in
ope
ratio
n
DES contractsFOB contracts
50
A more detailed look on the allocation of FOB and DES contracts depending on the production area shows
that :
- Asia-Pacific producers started with DES contracts with Japanese buyers (LNG from Brunei, USA-
Kenai, Indonesia-Bontang and Abu-Dhabi) until the mid-eighties when these buyers started to buy
FOB at Bontang. The FOB share then increased slowly. DES now represents and should continue
to represent approximately 60% of the contracted quantities in the area.
- On the other hand Atlantic basin producers started in the sixties with FOB contracts only and this
situation remained the same for almost thirty years until 1994 and the start up of the Algerian
deliveries to Turkey, followed by first sales of Nigerian LNG. The DES share in the Atlantic basin is
still increasing and should reach 60% by 2015.
- Notwithstanding a completely opposed use of Incoterms at the very beginning of their respective
LNG production story, Asia Pacific region and Atlantic region have progressively converged and
seem now to stabilize at a “balance point” of 60% DES and 40% FOB.
DISTRIBUTION OF CONTRACTS IN OPERATION (Pacific Basin)
0%10%20%30%40%50%60%70%80%90%
100%
1980
1983
1986
1989
1992
1995
1998
2001
2004
2007
2010
2013
2016
2019
% o
f tot
al c
ontr
acte
d qu
antit
y
FOB quantitiesDES quantities
DISTRIBUTION OF CONTRACTS IN OPERATION (Quantity)
0%
20%
40%60%
80%
100%
1980
1983
1986
1989
1992
1995
1998
2001
2004
2007
2010
2013
2016
2019
% o
f tot
al c
ontr
acte
d qu
antit
yFOB quantities
DES quantities
51
DISTRIBUTION OF CONTRACTS IN OPERATION (Atlantic Basin)
0%10%20%30%40%50%60%70%80%90%
100%
1980
1983
1986
1989
1992
1995
1998
2001
2004
2007
2010
2013
2016
2019
% o
f tot
al c
ontr
acte
d qu
antit
y
FOB quantitiesDES quantities
• Choice of Incoterms for a new LNG trade
Factors influencing the choice of the LNG projects developers regarding Incoterms of their long term
contracts are various :
- The LNG industry is one of the most capital intensive sectors in the energy field ; in the whole LNG
chain, from the gas fields to the exit point of the regasification plant, the sea transportation can
represent between 10% and 25% of the total cost ; even if shipping can be made through long term
chartering of LNG vessels, selling on FOB basis can be a way for a producer to reduce its financial
needs or commitments.
- FOB sale can also be chosen to mitigate the industrial risk of developing a new chain, in particular
when the project developer is a new actor in the LNG industry. Selling FOB gives him the opportunity
to focus resources and efforts on the upstream part of the chain (gas production, treatment and
liquefaction).
- On the other hand, an FOB purchase is a way for the customer to be more strongly involved in the
development of the project, by bearing a bigger part of the financial burden and of the industrial risks
of the new LNG chain.
- Strong producers, either because they are already present in the LNG industry or because their
partnership includes major companies, have decided to go downstream in the LNG chain and to
develop and use their own fleet with the objective of better monitoring the marketing of their LNG :
naturally they chose to sell on a DES basis.
52
- Furthermore the choice depends on the business models of the seller and of the buyer and on the
kind of flexibilities they are looking for.
• Incoterms and flexibility
Trying to establish a relation between the elected Incoterms (FOB or DES) and the flexibility (on volumes
and on unloading destinations) of a given LNG sale and purchase agreement is challenging because
flexibility broadly depends on other contractual provisions such as downward or upward quantity rights,
management of the excess quantities, available shipping capacity, destination restrictions, price and price
adjustment according to the destination, LNG quality….
The following can however be underlined :
- Some buyers need to secure LNG for the supply of their downstream markets located in well
identified countries and supplied through stable chains : they need more volume flexibility than
destination flexibility and should then be indifferent to the Incoterms. This is the case of Far East
utilities.
- Some buyers have their business model based on continuous maximum valuation of their LNG
portfolio : to achieve this goal they need as much flexibility as possible on final destination and
therefore have preference for FOB purchase. This is indeed challenging, and one could argue that
purchasing DES does not necessary prevent a buyer to organise diversions, it only necessitates to
do them through a cooperation with the seller, and on the contrary, purchasing FOB does not allow
all diversions, since destination restrictions may prevent some of them. Whatever the Incoterms,
FOB or DES, an agreement with the seller is often needed, but in the case of FOB, it can be limited
to a consent, on the basis of economic considerations, whereas in the case of DES, it is a real
cooperation, on the basis of economical considerations and feasibility requirements (availability of
ships, compatibility, vetting issues, etc…). In this regard, the FOB purchase allows the buyer,
through the control of its own fleet, to organise and schedule its trades much more easily that the
DES purchase.
- In the middle some buyers have diversified supplies, combining pipe gas and LNG, a diversified set
of downstream markets, with their own flexibilities and the ability to optimize their integrated portfolio.
They are able to accept either FOB or DES Incoterms.
- Some producers have a business model based on permanent value optimization of at least a part of
their LNG portfolio for which they are willing to be directly involved in downstream marketing,
sometimes with booking of regasification and transportation capacity in liquid markets and
development of marketing activities in such markets ; this requires monitoring destination of the LNG
cargoes which is easier to achieve with control of the fleet and through implementation of DES sales.
53
In conclusion, there is no evident link between the Incoterms used in a given LNG sale and purchase
contract and the “flexibility” of such contract ; such flexibility results more of a combination of other
contractual conditions and from the cooperation that seller and buyer are able to develop over the duration of
their partnership, in order to continually adapt their commercial relation to the changes of their business
environment.
F. Destination Clauses / Diversion
Mr. Lowell A. Bezanis, Cheniere Energy
Mr. Ahmad Marzuki Haji Ahmad, Petronas
1. Introduction
Since the first commercial long term LNG supply between the Alaskan Kenai LNG and its Japanese
buyers (Tokyo Electric and Tokyo Gas), the global LNG industry has evolved into an industry that was
once very rigid in every aspects of the business and trade to one that is dynamic involving a myriad of
players in every corner of the world.
To date, the industry has undergone two waves of evolution spanning a total period of 42 years and is
presently in the third wave of evolution – or is it the fourth?
The FIRST WAVE of industry evolution was represented by a long thirty-three (33) years period
between 1964 and 1996 while the SECOND WAVE period was substantially shorter - a period of nine
(9) years period between 1997 and 2005.
At present we are in the THIRD WAVE of its evolution. Shorter than the preceding ones, it is expected
to last up to the end of the decade or even slightly longer to 2012 resulting from the prevailing
financial crisis affecting the world - or is the crisis a feature of the FOURTH WAVE?
Each of these waves represent a specific period in the evolution of the LNG industry during which
certain events and factors helped or forced the shaping of industry trends and influencing trade
practices and contractual norms.
2. The LNG Industry, Business and Trade
This paper focuses on the impact of the evolution of the industry on one of the key clauses stipulated
in the LNG sales and purchase agreement (SPA) - the Destination Clause.
However, before we proceed to discuss issues and concerns relating to these clauses, perhaps it
would be prudent to reflect on the evolution of the LNG business and trade that has a bearing on the
applicability of these clauses in today’s LNG business and trade.
54
The evolution of any industries will generally results in the establishment of numerous understandings
and agreements that helps to facilitate and regulate the industry in relation to its business and trade.
For the LNG industry, capital investments required to develop the relevant components along its entire
value chain was and remains very high. It requires significant financial commitments from each
interested parties involved in order to realise relevant projects related to each component in the value
chain. The subject of this paper is substantially relevant and related to the the midstream component
of the value chain (liquefaction, transportation and regasification) that involve a major portion of the
total investment cost.
The midstream component requires the availability of a cryogenic-based system to liquefy the natural
gas and maintains it in liquefied form for delivery as LNG from the supply point to the delivery point.
And it is this component of the value chain that necessitates the inclusion of certain key clauses in the
LNG sales and purchase agreement (SPA), and amongst them, is the Destination Clause.
Destination clauses are clauses in supply contracts that have the effect of forbidding buyers from re-
selling the product outside the pre-destined market stipulated in the SPA, thereby guaranteeing the
seller a reasonable level of revenue stream, primarily to service loans taken to develop a particular
LNG exportation project. The clause also represents an effective mechanism to maintain price
differentials across different export markets.
3. Applicability of Destination Clause in the SPA
1. The FIRST WAVE (1964-1996, 33 years)
The first long term commercial LNG trade was established in 1969, when Japan took delivery of
its first LNG cargo from the Alaskan Kenai LNG project.
LNG trade during this period was limited to a small group of sellers and buyers linked by long-
term LNG supply contracts (usually 20-25 years). Commercial terms and conditions of supply
included the take-or-pay clause in lieu of security of supply. LNG was generally delivered on an
ex-ship basis and transported using dedicated specially-built LNG Tankers.
While security of supply was of paramount importance to the LNG buyers, namely the Japanese,
South Korean and Taiwan, whose country has limited indigenous energy resources to feed their
respective country energy requirements, the ability to secure the necessary financial packaging
from lenders to support the development and construction of the relevant LNG exportation
infrastructure were crucial to the project owners alike.
The introduction of the destination clause in the LNG SPA will ensure seller’s sales are protected
vis-à-vis the ability to maintain price differential between different exporting markets that is
fundamental to any project viability. Such will ensure the expected revenue generation streams,
hence allowing the project owners to timely pay their lenders as per agreed terms and conditions
55
of the financial package given. For the buyers, it guarateed them specific uninterruptible LNG
supply over the period of the contract duration.
The destination clause is explicitly applicable to mitigate operational problems. For example, if
the buyer’s LNG receiving facility is having some technical problems that renders it not being
able to receive the LNG cargo delivered or there’s a change in gas demand pattern affecting the
intended LNG delivery, then a buyer can approach and request from the seller for the cargo to
be diverted to a different destination other than that explicitly stated in the SPA. On this note,
any request by a buyer to divert a particular cargo, if any, must be negotitated with and agreed
by seller, before a cargo can be diverted to an agreed destination, different from the originally
agreed and intended one.
2. The SECOND WAVE (1997-2005, 9 years)
The SECOND WAVE saw the entry of new suppliers and buyers into the global LNG trade
arena. The economics of LNG as a competitive energy source called for larger liquefaction trains,
bigger ships and more flexible contracts – with the intent to reduce unit production and
transportation costs.
It was during this period too, that the industry saw the emergence of two new middle-eastern
LNG export projects - Qatar and Oman; providing buyers with a wider source of LNG supply in
an already competitive market. Heightened competition amongst existing players and the
pressure of industry deregulation and liberalisation in importing countries resulted in the
introduction of more flexible terms and conditions of SPAs as negotiated by both Buyers and
Sellers.
The demand side saw the emergence of new LNG buyers representing two huge gas demand
markets - India and China. In order not to lose market share, remain competitive and capture
potential upside values, LNG suppliers required increased flexibility in the commercial terms
extended by sellers to potential LNG buyers, amongst them the introduction of Diversion Clause in some SPA.
During this period, the natural interest of sellers continues to be the need to retain destination
clauses, while embracing marginal controlled change, such as profit-sharing diversion
mechanisms. Buyers on the other hand, have sought to eliminate or relax destination clauses.
While the former emphasized themes such as stability/security of supply and reasonable returns
on investment, the latter concerns were stressed upon their need to manage domestic demand,
enhance market efficiency and so forth. Hence, these two distinct aspirations are expected to be
concerns emphasized by both parties at the negotiation table as the global LNG industry
business and trade dynamically expand and converge.
56
Since the European Union (EU) gas directive came into force in early 2000, effrots have been
pursued to omit the destination clause in supply contracts in line with EU Anti-Competition Law.
Subsequent to investigations initiated by the European Union (EU) Commission in April 2001,
especially on the Destination Clause, for Europe in terms of EU Anti-Competition Law, Nigeria
agreed to omit the destination clause in their sales contract concluded with ENEL of Italy in
October 2002. Norway and Nigeria agreed to repeal the clause. In October 2003, Russia agreed
with Italy’s ENI to abolish the clause whilst Algeria agreed to delete this from all contracts
affecting EU buyers in early 2005. Russia is moving to eliminate the clause for pipeline gas
exports, but no agreement has been made between Russia and buyers other than ENI.
3. The THIRD WAVE (2006-2010/12, 5-7 years)
The THIRD WAVE saw a mix of events that spiraled down the global oil and gas industry from
its greatest heights to prevailing lows.
Attrition of skilled manpower and resource constraints affected the operations of existing LNG
projects that inevitably shifted the start up further up the timescale for some and deferred or
shelved indefinitely for a few others. These factors, combined with changing domestic gas
policies, some abrupt, to mitigate increasing domestic gas consumption in some gas consuming
countries, resulted in a tight LNG supply situation amidst increasing global demand for LNG.
The increasing upward trend in oil prices underpinned the increase in gas and LNG prices
creating greater and wider arbitrage opportunity play, not only between Europe and the US east
coast, but also between the west and east of Suez markets. This can be seen in the increasing
sales and deliveries of spot cargoes (including short term) into the Far East market due to the
attractive price opportunities.
The omission of the destination clause in SPAs vis-à-vis the EU Anti-Competition Law was also
a factor that resulted in the greater flow of Atlantic-based spot cargoes into the Far East. This
was predominant over the recent few years of increasingly tight supply scenario coupled with the
higher price affordability of the east of Suez markets.
For a dynamic and matured market of Europe and the US, the omission of the destination clause
may work effectively to ensure a healthy and competitive LNG trade. However, the same cannot
be said for the other major demand centre i.e., the Asia Pacific market. If the destination clause
is omitted in the region’s LNG supply contracts, the eventuall loser could well be the LNG buyers,
originating from countries with limited energy resources. Hence, security of supply remains
paramount. The destination clause is a pre-requisite for suppliers, considering the huge capital
investment involved, to ensure buyers are guaranteed their reliable and uninterruptible LNG
supplies.
The indiscrimate application of the destination clause could result in LNG suppliers from being
guaranteed the expected return on investemt that is fundamental in realising an LNG project.
57
This in turn could lead to project owners not being able to service their loans effectively that
could inevitably affect the smooth operations and maintenace of the LNG facilities and
subsequently affecting LNG production, supply and delivery.
4. Moving Forward
The global LNG industry is expected to continue and evolve. An industry that was once facing a
supply crunch due to factors mentioned earlier in this paper is now on the reverse into an over-
supply scenario. Gas consuming countries that were frantically scrambling for any excess LNG
volume they can get hold on whatever the price may be, have now approached and requested their
respective sellers for a reduction in their offtakes. Such has inevitably put suppliers in a very
awkward positon with excess volume on their hands to deal with. The scenario is providing an
opportunity for the domestic gas market to enahnce their efforts to grab this emerging gas supply
opportuntiy for their own needs. Such a situation could well be an unsightly scenario for the LNG
industry in general.
In light of the current supply scenario and economic turmoil, perhaps the next wave in the continued
evolution of the LNG business and trade could focus on the security of market, an exact reversal of
the earlier years ? The prominence of domestic gas demands, consequential political pressures and
nationalism that had emerged in the recent months could perhaps catapult the LNG business and
trades into the next wave ?
5. CONCLUSION
For a region that exist markets that predominatly depends on imported resouses, in this instance
LNG, the destination clause provides these markets the added security for them to have a reliable
and uninterruptible LNG supplies.
Diversion of cargoes is possible to mitigate operational problems faced by buyers. The spirit of the
SPA provides opportunity for both buyers to seek and negotiate for the diversion of cargoes, subject
to mutually agreed terms and conditions of supply and delivery of the affected cargo.
58
Chapter 4: Conclusion For A More Flexible LNG Market Dr. Boyoung Kim, Korea Gas
The group’s goal of finding a win-win solution to satisfy both buyer and seller in the LNG contract was, as
expected in the very beginning of the study, difficult to find.
On top of that, the financial crisis stormed the global economy around the time we were finalizing the
research. The financial crisis caused industrial stagnancy and brought a huge change in the demand outlook
of the LNG market. In other words, the financial crisis ignited from the U.S in late 2008 and spreading world
wide has caused the global economic downturn which in turn, relayed into a decline in the short term and
probably medium term(~2015) demand of natural gas. During 2008 to 2009, Asian LNG buyers
simultaneously exercised the Downward Quantity Tolerance on their Annual Contracted Quantity leaving
excess quantity of LNG in the market that pulled down the price for the spot trades. This trend generated
rather arbitrary demand in the U.S and Europe where spot market takes a significant portion of the LNG
trades to benefit from unusual market situation of low LNG spot price. If markets in the U.S and Europe were
not in structure to digest such spot quantities, the excess supply would have caused a significant damage
both physically and economically to suppliers.
In separate account, there are diversified opinions in the outlook on LNG demand with different forecasts on
when and how fast the market would spring back from current suppressed situation. We believe that the
outlook on future demand of LNG is dependent on the inter-related activities between the following two key
factors.
One is the forecast on when the current economy would recuperate back to its former status. In the short
term, the demand will be suppressed but in the long run the demand for natural gas shall inevitably return to
its status quo. The only question remains is when such inevitability would be realized. The other factor is the
reinstatement of gas development plans which were halted due to various reasons. Recently, most of gas
field developments had to be delayed due to the rise of the EPC raw material cost, labor cost and overall
investment requirement. Furthermore, dramatic fall of the oil price surrounded the investor with fear of low or
even no return on their investments. However, the question is not whether the demand and the supply would
find a new equilibrium point but when would that equilibrium is reached.
The changes mentioned above are something that we, the research group, did not foresee during 2006 to
2007 and also in the first half of 2008. So far, the research was focused on how to modify the terms of a
contract under seller’s market condition to satisfy the buyer’s need and to empower the LNG trades.
However, the time seems to be just around the corner for sellers to modify the contract terms to benefit from
more flexible LNG trade.
For such mutual benefit, there exists not only the need for LNG consuming nations to establish the proper
user market but also the need for LNG exporting countries to build a flexible sales frame. Asian buyers in
59
particular, where LNG takes a significant portion of aggregate national energy consumption, must equip
themselves with adequate storage facility and competitive price level to compete with other energy sources.
The reason behind such requirement is that although the market will self-adjust as the portion of spot market
increases from current 20% level (Until a couple of years ago, the majors were convinced that spot share
would not increase beyond the 15% mark), sellers will soon be able to rectify the institutional restrictions by
introducing various marketable products and sales terms.
As LNG spot market increases its territory in the LNG trade and buyers and sellers adapt more relaxed
contractual terms, main bodies of the economy are forced to deal with the unexpected massive fluctuation in
supply and demand. Therefore finding the right balance between flexibility to cope with market volatilities and
stability of the demand and supply should yield a win-win strategy for both buyers and sellers.