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Executive summaryChapter
1: An introduction to LNG
LNG
(Liquefied Natural Gas) is gas cooled to below –161°C, where it
liquefies and can be stored as a boiling liquid in insulated tanks. LNG
carried by specially built ships offers an alternative means of
transportation to pipelines, and may be more economic than pipelines
particularly over long distances. Around 6% of world gas production is
transported as LNG. The
LNG industry developed from experiments in the USA
in 1950s, with the first delivery of LNG to the UK
in 1959 and commercial deliveries of LNG from Algeria
to the UK
and France in 1964 and 1965. The industry then saw major growth with new markets in
Japan
from 1969, supplied from Alaska
and Brunei, and later Indonesia, Malaysia
and Australia. The oil price shock in 1973 encouraged the further development of LNG
as it improved the competitive position of LNG and led to the
development of oil price indexation in LNG supply contracts. First deliveries of Algerian LNG to the USA occurred in 1972, but despite the construction of four US receiving terminals, LNG sales to the US collapsed and remained at a low level through the 1980s and 1990s, returning to their 1979 peak in 2000. During the 1980s and early 1990s further LNG markets developed in Europe and in Korea and Taiwan. The late 1990s and early 2000s have seen rapid growth with expanding LNG markets in the US, Spain, Portugal and Greece and new production facilities in Oman, Qatar, Nigeria and Trinidad. World
LNG trade was approximately 125 mtpa in 2003 with major LNG markets in
the Asia-Pacific region, particularly in Japan, and rapidly growing markets in the Atlantic basin. With capacity
expansions planned at many production and reception facilities and the
first European export project planned, the Snøhvit project near Hammerfest
in the Norwegian Barents Sea, LNG is likely to increase in global reach
and significance. Chapter
2: The LNG chain
Each
LNG project consists of a continuous chain of activities linking the gas
production to the gas user. Links in the LNG supply chain include
upstream (gas production), liquefaction, shipping, regasification, and
distribution (as natural gas) to end-users. Upstream
covers the exploration, development and production of gas. LNG projects
typically require large gas reserves (in excess of 10 Tcf or 280 Bcm),
able to produce gas at a plateau level for at least 20 years. The
quality of the gas is also a key factor in determining whether LNG
projects are economic. Liquefaction
involves the processing and cooling of gas to –161°C. Liquefaction
units are referred to as LNG trains, with most LNG plants operating
between 2 and 8 independent trains. There are two main processes for
liquefying natural gas, the Multi-Component Refrigerant process and the
Phillips Cascade process. These are both described. Liquefaction plant
capital costs may make up over 80% of total liquefaction costs, however,
in recent years these have been significantly reduced through improved
technology and economies of scale. Shipping
forms the vital transportation link in the LNG chain. LNG is carried at
atmospheric pressure in specially built LNG tankers. Most of the 163 LNG
ships in operation today have a capacity of 125,000 m3 to 145,000 m3,
although there are a number of smaller ships still in operation. Most of
the ships on order are in the 135,000 m3 to 153,000 m3 range, although
there are a number of proposals to build larger ships in near future.
Most LNG ships use either the Kvaerner Moss design or one of two
Membrane designs. New LNG ship prices in 2003 were around $175m.
Chapter
3: Project structures
Definition
of commercial structure is a key part of LNG project development. LNG
project structures must meet a range of objectives including, ensuring
stability of operation, sharing risks and rewards equitably, satisfying
the requirements of the host government, and minimising the potential
for conflict and delay. Project structures can be grouped into three
generic models: integrated projects, transfer pricing arrangements, and
throughput arrangements. In an
integrated project there is common ownership of the gas reserves,
liquefaction plant, and in most cases the LNG ships. An integrated
project has the advantages of aligning the partner interests and
avoiding negotiation of transfer prices. There is a case study of the
RasGas trains 1 and 2 integrated project. An
integrated structure may not be possible in many situations because the
owners of the gas reserves differ from the liquefaction plant owners. In
these cases the most common alternative is a transfer pricing
arrangement. The partners in each stage agree a transfer price for sale
of the gas or LNG into the next stage of the process. Transfer pricing
arrangements may lead to conflict, particularly when changing market
conditions shift the risk/reward balance between different partners.
There is a case study of the Malaysia LNG Dua transfer pricing
arrangement. The
third form of project structure is a throughput arrangement where the
upstream partners pay a tolling fee to use the LNG plant and then market
the LNG on their own behalf. Atlantic LNG trains 2 and 3 are in effect a
throughput arrangement. There is a case study of Atlantic LNG trains 4,
which will operate a throughput arrangement from 2006. Chapter
4: Sources of LNG
World LNG production capacity in May 2004 was 143 mtpa, with 55 mtpa of capacity under construction expected to take global capacity to close to 200 mtpa by 2008. There are three major LNG producing regions: Asia-Pacific accounting for 48% of production capacity in 2003, the Atlantic basin 31%, and the Middle East 21%. The
Atlantic basin covers LNG production facilities on both sides of the
Atlantic as well as North African LNG facilities on the Mediterranean. The largest Atlantic basin LNG supplier is Sonatrach in
Algeria, but in 1999 new LNG projects were commissioned in Trinidad (Atlantic
LNG) and Nigeria (Nigeria LNG). Trinidad and Nigeria’s LNG production capacity is being rapidly expanded with several new
trains under construction or proposed. In addition LNG plants are under
construction at Damietta and Idku in Egypt and Snohvit in Norway, Europe’s first LNG export project. There are also proposals for further
expansions or new facilities in Angola, Equatorial Guinea, Venezuela, Russia
and Nigeria. The destruction of three trains at Skikda in Algeria in January 2004 has had only a limited impact on production capacity in
the Atlantic basin. Middle
Eastern LNG production began with the Das Island
plant in Abu Dhabi in 1977. New capacity in Qatar and Oman
developed between 1996 and 2000 and capacity expansions at Das Island
significantly increased LNG production in the Middle East. A third train at RasGas was commissioned in early 2004 and
debottlenecking work at Qatargas, as well as RasGas train 4 and Oman’s third train.
Qatar
has announced its intention to become the world’s largest LNG
exporter, and there are also a number of proposals for further capacity
in Oman, Yemen
and Iran, however, it is unclear if sufficient buyers can be found to justify
these investments. Asia-Pacific
is the largest LNG producing (and consuming) region. By May 2004
capacity had reached 68 mtpa, despite the shut down of two trains
at Arun in Indonesia, due to reserve depletion. Current Asia-Pacific LNG exporters include
Indonesia, Malaysia, Brunei, Australia
and Alaska, with significant additional capacity under construction in Australia
and Russia. Asia-Pacific further proposed capacity includes a number of
developments in Australia, capacity expansions and new facilities in Indonesia
and Brunei, and new developments on the Alaskan North Slope. A key issue in LNG in
Asia-Pacific is the expiry of certain of the older LNG contracts with
Japanese and other buyers. Some, such as with Arun or Alaskan Kenai, may
not be renewed due to limited remaining gas reserves, whereas others may
be renewed or renegotiated over coming years. Although most potential LNG developments are within the existing supply envelopes, there is the possibility that a new supply and consumption region may develop with LNG production on the Pacific coast of South America selling to new receiving terminals in Mexico or California. The major gas sources would be Peru and Bolivia. The
table below summarises world LNG production capacity, highlighting the
large increases in capacity either under construction or proposed,
particularly in the Atlantic basin.
Chapter
5: LNG markets
World LNG demand reached 125 mt in 2003. Of this total 67% was concentrated in the Asia-Pacific region, 24% in Europe, and 9% in the Americas. European LNG imports totalled nearly 30 mt in 2003, with largest importers being Spain and France. LNG provided 7.6% of European gas supply. Significant LNG reception and regasification capacity is under construction including new terminals in UK and Spain, plans for new terminals in Italy and France and capacity expansion in Belgium. Although the USA is the world’s largest gas market, LNG imports forms a comparatively low proportion of gas supply, 10 mt in 2003 representing only 2% of US supply. However, the 2003 level was a record, following a dramatic increase over recent years from the level of 0.5 mt in 1996. These increases are due to surplus LNG cargoes from the Asia-Pacific market, high US gas prices since 2000, and the commissioning of the Atlantic LNG facility in Trinidad, which is much closer to the US East Coast than other LNG plants. Forecasts from the US EIA showing LNG imports increasing to nearly 90 mtpa by 2020. Expansion of the four current US LNG terminals should bring import capacity to at least 40 mtpa by 2008, with around 40 new terminals around North America planned or proposed, although only a small proportion is likely to be built. Puerto Rico and the Dominican Republic have also become LNG importers in 2000 and 2003, respectively, with the Altamira terminal in Mexico due for start-up in 2006 and the Energy Bridge project offshore Gulf of Mexico in 2005.
In
terms of market outlook, LNG demand is expected to grow rapidly over the
next two decades. A base case forecast suggests total demand of 400 mtpa
by 2020, a threefold increase from 2003, at an average annual growth
rate of 7%. The growth rate in the Atlantic basin is expected to be
higher than in the Pacific basin. Meeting base case would require most
prospective projects currently proposed to be developed, with
significant further capacity required to meet high case forecasts. Chapter
6: Contracting for the sale and purchase of LNG
The
common contract form for the LNG business is the LNG Sales and
Purchasing Agreement (SPA). SPAs were originally based on pipeline gas
sales contracts, but have been adjusted to meet the specific needs of
the LNG industry. LNG buyers and sellers may go through a series of
agreements preliminary to signing an SPA, with a greater level of
commitment at each stage. Typical preliminary stages include: Letter of
Indication or Letter of Interest (LOI), Memorandum of Understanding (MOU),
Letter of Intent (LOI), Heads of Agreement (HOA), and Confirmation of
Intent (COI). There are three basic types of LNG, free on board (FOB) where title to the LNG transfers to the buyer at loading and the buyer takes responsibility for shipping; cargo, insurance, freight (CIF) where title transfers during the voyage and the seller is responsible for shipping; and delivered ex-ship (DES) where the seller is responsible for shipping and the title transfers at unloading. Over the last decade there has been a trend away from DES/CIF contracts and towards FOB contracts as buyers have taken greater interest in LNG shipping. Key
contractual terms in a typical LNG SPA include: term of supply (normally
at least 20 years), Annual Contract Quantity (including a minimum
take-or-pay obligation and conditions for flexibility in offtake and
make up provisions), price, responsibility for marine transportation,
scheduling procedures, heating value and main components of the LNG,
measurement and testing, force majeure, destination flexibility (or the
lack of it), and applicable law. These terms are described and their
impact explained. As
short-term LNG trading is developing many LNG players are also adopting
Master Sales Agreements to facilitate and expedite trading. These
agreements provide the framework for trades, but leave details of
volume, price, timing and transportation arrangements to be confirmed
separately for each trade. Chapter
7: LNG prices
There
are different pricing systems in place in the three major market regions
of Asia-Pacific, Europe and the USA. In the Asia-Pacific LNG prices are typically indexed to crude oil
prices, either in Japan or Indonesia, in some cases with an ‘S’
curve to limit the impact of extreme oil price movements. Asia-Pacific
prices tended to be higher than other regions until 2000, since when
there has been greater price convergence. There have also been a number
of new developments in LNG pricing in new markets in Asia since 2000
with China’s Guangdong LNG terminal achieving a lower than average price through
a competitive bidding tender and India’s Petronet achieving the first fixed price LNG contract for over 30
years. In
Europe LNG is competing with pipeline gas and adopts similar formulae
which are typically indexed to crude oil or oil products (gasoil and
fuel oil), although there may also be elements of coal, electricity or
inflation indexation. LNG and gas prices tend to lag crude oil prices by
around six months due to the structure of the oil price indexation
clauses in the contracts. The re-emergence of the UK as an LNG importer
in 2005 will introduce a new set of LNG pricing dynamics in Europe as UK
gas prices are driven by supply and demand fundamentals as in the USA,
and only indirectly by oil prices. In
the USA gas prices are set by gas-to-gas competition, driven by supply and
demand. Two alternative approaches to LNG pricing are in use: netback
pricing where LNG delivered prices to the US market are
typically based on Henry Hub gas prices plus or minus a locational
differential reflecting the basis between the LNG delivery point and the
Henry Hub; and sharing of revenues where the LNG seller
receives an agreed percentage of the Henry Hub price and the remainder
is retained by the buyer. Chapter
8: Shipping
At
the end of May 2004 there were 163 LNG ships in operation, with 78 more
ships due for delivery by the end of 2008. Most existing ships have a
capacity of 120,000 m3 to 145,000 m3, although there are a
number of smaller ships delivering gas to medium-sized gas distributors
in Japan
and to terminals in Spain, France
and Italy that cannot receive large ships. The lifespan of an LNG ship has been
extended from the design expectations of twenty years and there are now
a number of ships of over twenty or even thirty years’ operation.
Total LNG fleet capacity has increased steadily from the first ships in
service in 1962, reaching over 19 mcm by 2004. Prices
of LNG ships have varied considerably over the last two decades, however
in recent years prices have fallen and current price for a standard
135,000 m3 to 140,000 m3 LNG ship is around $175m.
Although LNG ships have been built in shipyards in Japan, Korea, France,
Finland, Spain
and Italy, the market is currently dominated by Korean and Japanese shipyards. In
May 2004 there was a record 78 ships on order for delivery between 2004
and 2008, all but of two of these ships are above 135,000 m3.
Unusually around 30% of ships on order do not appear to be linked to a
particular LNG project and may be developed for speculative reasons. LNG
shipping costs are very much a function of the distance between the
liquefaction plant and the receiving terminal. Shipping costs include
fixed costs (capital charges, crew costs and insurance) and variable
voyage costs (fuel, boil-off gas and port charges), with fixed costs
generally accounting for two-thirds of total transportation costs. An
illustration of typical costs per MMBtu for various distances is
provided. Construction of larger ships of 200,000m3 and above has been possible for some time, but none have yet been built due to limitations on the size (and weight) of ships that can be received by existing LNG terminals. However, Qatargas has invited bids for large ships in early 2004, which could see unit costs reduced by as much as 20%, although the flexibility of these ships to deliver to different markets will be limited by terminal capability. Chapter
9: Short-term trading.
Although
long-term contracts have traditionally underpinned the LNG market, there
has been a low level of short-term or spot LNG trading throughout its
history. In recent years the level of short-term trading has increased,
reaching nearly 11% of total LNG production in 2003. Short-term trading
began as sellers sought to utilise spare liquefaction capacity and some
buyers found that gas demand increased more quickly than forecast. In
the 1980s almost all short-term trading was between suppliers and buyers
that already had a long-term contractual relationship. In the early
1990s this changed somewhat as shut-downs of Algerian production forced
European buyers to seek LNG cargoes from the Middle East and Australia. From 1996 the
US
market also began to buy spot LNG cargoes as Asia-Pacific sellers aimed
to offload excess LNG following the downturn in demand in Japan, Korea
and Taiwan. Since 2000 short-term trading has been further encouraged by high gas
prices in the USA
and extra gas demand in Japan
and Korea in 2003. Short-term
LNG trades may follow a variety of pricing structures, including
indexation to crude oil or oil product prices, or netback from pipeline
gas prices. In the Atlantic basin the proximity between the US and European markets provides sellers and buyers with an opportunity to
arbitrage prices and divert LNG cargoes to attract the highest price.
Analysis of deliveries from the Atlantic LNG plant in Trinidad shows
that when prices in the US
are above European prices deliveries will usually be diverted to the US
from Spain, whereas the situation reverses when European prices are above US
prices. However, this is not always the case, as in early 2003 when US
prices were above European prices, but no cargoes where diverted to the
US, because of additional demand from Japanese and Korean buyers led to
the diversion of Europe-bound Middle Eastern cargoes to Asia-Pacific.
This is the first clear example of increasingly inter-relations between
the three regional LNG markets. The
main factors needed for the expansion of short-term trading are surplus
LNG supply, market demand and receiving capacity, uncommitted ships, and
flexible contracts. In 2002 the main constraints on the further
development of short-term trading were considered to be the shortage of
uncommitted ships and the lack of flexibility in existing contracts.
This had changed significantly by 2004, particularly with increasing
numbers of ships available for short-term charter, but also with
increasing contractual flexibility for buyers. There is also a
reasonable level of surplus production capacity and receiving terminal
capacity, with open access terms in Europe
improving. As a result of these factors, the short-term LNG market is
expected to expand somewhat in the medium-term, however, the large
investments and commitments required for the construction of LNG plants,
ships and terminals, is likely to prevent the short-term market
replacing the current framework of long-term contracts. Chapter
10: The outlook for LNG
LNG
trade has grown significantly in recent years with 2003 demand of 125 mt
nearly 20 mt above the level in 2001. There has been significant growth
in liquefaction and especially shipping capacity. There have been four
new LNG importers since 2000, and four new LNG exporters are poised to
start exports by 2008. Growth forecasts are strong with predictions of
annual trade doubling by 2015 and reaching 400 mtpa by 2020 seeming
increasingly credible. Meeting
these growth forecasts, although not impossible, will be challenging for
the LNG industry, as has been demonstrated by the slippage of schedules
for many of the planned projects, some by a few months, some by several
years. Typically the slippage has occurred before the final investment
decision: following this point long delays are uncommon. Growth in established Asia-Pacific markets has slowed due to slow gas demand growth and uncertainties regarding the future structure of the gas industry. New markets in India and China are now beginning to develop after a number of false starts. As growth has slowed in Asia-Pacific, activity has switched to the Atlantic basin, where a combination of increasing need for gas imports and reducing LNG costs have made LNG an attractive alternative to pipeline gas. uring 1994 to 2004 Atlantic basin LNG demand grew by an average of 10.6%/year compared to 5.2%/year in the Asia-Pacific region. The biggest expansion has been in the USA, where imports grew tenfold over this period. This trend is expected to continue. The last two years have seen the announcement of plans for an unprecedented number of new LNG terminals in North America, with nearly every company active in LNG involved in at least one of the projects. However, it remains very uncertain which projects will go ahead, and a number have already been abandoned due to local opposition. There is also considerable uncertainty as to which of the liquefaction projects targeted at the US market will go ahead, particularly as LNG producers selling in the US market are likely to face increased gas price risk. In Europe LNG market dynamics will change with the re-introduction of LNG imports to the UK and the possibility of gas-to-gas competition changing price structures across Europe. Increasing gas price risk in the Atlantic basin and fierce price competition in Asia-Pacific will place further pressure on LNG costs and may drive the construction of larger ships. The
emergence of a buyers’ market and increased short-term trading is
changing the structure of the LNG market, including increased
flexibility in contracts, and increasing volumes of uncommitted
liquefaction and transportation capacity. Sellers are learning to deal
with new types of buyers, as new players such as IPPs and new entrant
suppliers seek to secure gas supplies in liberalising gas markets. The
development of short-term LNG trading will continue, however, the market
is likely to remain largely dependent on long-term contracts in the
medium to long-term. The
future is likely to owe much to three emergent trends. • Changes in downstream markets and the emergence of new markets that are forcing buyers to seek much more flexible supplies and lower prices than in the past. • Reductions in the costs of LNG to the point where it is already competitive with pipeline gas in a number of growing markets. • The development of short-term LNG trading and the flexibility this gives for LNG players to improve returns on investment and exploit and further develop niche market opportunities. |
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LNG
is unloaded from ships to LNG receiving terminals. These terminals store
and regasify LNG for distribution to end-users. Typically 1 to 3% of gas
is used or lost in the regasification process. Capital costs for
terminals vary significantly between $200m and $1bn depending on
location costs and storage capacity required.
Asia-Pacific
is the largest LNG market, with Japan by far the largest importer. Around 70% of LNG demand in
Japan is from power companies, with gas distributors also purchasing LNG.
Korea
and Taiwan are the other established Asia-Pacific LNG importers. India
became the fourth Asia-Pacific importer in 2004 with China expected to follow in 2006. These new markets have huge growth
potential, with a number of import facilities proposed or planned,
although price remains a significant issue. The Philippines
and Singapore are also considering LNG imports. Development of LNG import terminals on
the West Coast of North America, either in California
or Mexico, could create a trans-Pacific market and potential arbitrage
opportunities.