Order Code RL32445
CRS Report for Congress
Received through the CRS Web
Liquefied Natural Gas (LNG)
Markets in Transition: Implications
for U.S. Supply and Price
June 24, 2004
Robert Pirog
Specialist in Energy Economics and Policy
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress

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Liquefied Natural Gas (LNG) Markets in Transition:
Implications for U.S. Supply and Price
Summary
Natural gas consumption in the United States is expected to increase
substantially over the coming decades primarily because of its usefulness in
generating relatively clean electricity. Domestic supplies are projected to be unable
to meet increasing demand because existing fields are yielding less production and
new drilling efforts are not replicating past success rates. Pipeline imports from
Canada are also projected to decline. Various alternatives exist that might close the
demand and supply gap, with imports of liquefied natural gas (LNG) being touted as
one of the most promising.
As a result of projected supply increases, much of the LNG debate and analysis
has focused on the availability of the physical facilities needed to bring larger
quantities of LNG into the United States. However, other changes in LNG market
structure and practices are also likely to be needed before expanded quantities of
LNG can be supplied at market-based prices.
The traditional LNG market, which developed in the 1970s, and which only
recently has begun to be liberalized, can be characterized as capital intensive, long
term, with restrictive contractual provisions. Risk was managed through the sales
contract, and the whole production chain was committed in advance to ensure
economic viability of the project. Many of the characteristics of this market are
inconsistent with a more competitive market environment.
The LNG market is in the early stages of a transition which incorporates a viable
short term spot market, price discovery through gas-to-gas competition, financial
instruments to manage risk, competitive capital acquisition, open access of various
links in the supply chain to insure efficient resource allocation, and an expanded set
of producers and buyers. Full realization of the potential of LNG to provide a stable
source of supply to U.S. markets, as well as providing a price cap to U.S. natural gas
prices awaits changes in market structure as well as investment in receiving
terminals.
The extent to which the LNG market develops market based characteristics may
determine the extent to which other sources of natural gas supply are needed. The
Alaska Natural Gas Pipeline, drilling on restricted land in the Rockies, and
developing advanced technologies to extract natural gas from unconventional sources
may be considered as substitutes in closing the projected demand and supply gap.
The 108th Congress has considered policy to support the construction of an Alaska
natural gas pipeline (H.R. 6) and the availability of more LNG terminals (H.R. 4413).
This report will not be updated.

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Contents
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Standard LNG Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Competitive LNG Markets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Structural Transformation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Contract Provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Spot Markets and Prices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Shipping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Risk Management. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Other Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10
Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

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Liquefied Natural Gas (LNG)
Markets in Transition: Implications
for U.S. Supply and Price
Introduction
This report analyzes the potential for liquefied natural gas (LNG) to become a
flexible, dependable, source of natural gas supply for the U.S. market, while also
setting a cap on natural gas prices. The potential for increasing U.S. LNG use is
usually framed in terms of expanding the capacity of existing receiving terminals,
and the challenges encountered in siting and constructing new terminals. While
adding the physical capacity to receive more LNG is important, significant changes
in the structure and practices of the LNG market are also likely to be required before
LNG might assume its projected economic role in U.S. energy supply. These
changes center on the structure of LNG markets and transactions, including contract
design, risk sharing, financing, transportation, and the emergence of a competitive
spot market that determines price through a transparent market process. The roles
of these factors in the evolving LNG market are analyzed in this report.
Recent measures introduced before the 108th Congress focus on physical
facilities. The Liquefied Natural Gas Import Terminal Development Act of 2004,
(H.R. 4413) is aimed at reducing regulatory risk and speeding the federal review of
applications to build onshore LNG terminals, as well as assigning authority in this
area to the Federal Energy Regulatory Commission (FERC). Earlier, Federal Reserve
Chairman Alan Greenspan testified before Congress, arguing for more LNG terminal
capacity to mitigate the economic effects of high energy prices.1 Some analysts,
expanding on Mr. Greenspan’s testimony, have pointed to the structure of the LNG
market as a limiting factor in providing supply security and a price cap to U.S.
natural gas prices.2
This report describes the standard LNG market transaction, contrasts it with the
competitive market model, and evaluates the transition currently underway between
standard transactions and competition. Whether the price of LNG serves as a cap or
a floor on U.S. natural gas prices, or whether it follows world oil prices, will have
important implications for U.S. consumers. The characteristics of LNG prices will
largely depend on how the structure of LNG transactions and markets evolve.
1 Greenspan, Alan, Chairman, Federal Reserve Board of Governors. “Natural Gas Supply
and Demand Issues,” Testimony before the House Energy and Commerce Committee, June
10, 2003.
2 Jensen, James T. The LNG Revolution, The Energy Journal, Volume 24, Number 2, 2003,
pp.1-43.

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CRS-2
The evolution of LNG supply will contribute to the debate over the relative
importance of the proposed Alaska natural gas pipeline, expanded use of lands now
off limits to exploration and production, and investments in technology to expand
additional unconventional gas supplies. If secure LNG supplies become available in
quantities consistent with an optimistic view of the market, some, or all, of the other
gas alternatives needed to close the projected gap between U.S. natural gas demand
and traditional North American supply sources in 2025 might not be needed.

Background
The Energy Information Administration (EIA) in the Annual Energy Outlook
2004 (AEO), projects the United States becoming increasingly dependent on
imported natural gas in the coming decades. The AEO reports that in 2002 natural
gas imports of 3.49 trillion cubic feet (Tcf) accounted for 15.3% of the 22.8 Tcf total
of natural gas supplied to the U.S. market. Under the EIA’s base case reference
scenario, the share of imported natural gas is projected to rise to 22.3%, or 6.24 Tcf,
by 2015, and 23%, or 7.24 Tcf, by 2025.3
Not only are the share and volume of imported natural gas projected to rise, but
the sourcing and physical form of the gas are also expected to change as well. In
2002, over 95% of natural gas imported to the United States came from Canada via
pipeline. By 2015, the AEO projects that contribution declining to 48%. Virtually
all of the remaining projected natural gas imports are expected to be in the form of
LNG. In 2002, the United States imported 0.17 Tcf of LNG, which accounted for
less than 5% of U.S. imported natural gas, and less than 1% of the total natural gas
supplied to the market. In 2003, LNG imports rose to 0.5 Tcf. The 2025 import
projection represents over a seven fold increase in LNG supply from overseas
compared to 2003.4
The average wellhead price of natural gas was $1.91 per thousand cubic feet
(Mcf) in the 1990s, the average price in the 2000s is $3.90 per Mcf, over double that
of the previous decade. The wellhead price of natural gas averaged over $5.00 Mcf
from November 2003 through February 2004. Increased prices have put pressure on
residential consumer budgets, raised the cost of electricity, and reduced the
competitiveness of industries that are consumers of natural gas. Higher prices,
coupled with the decreasing cost of LNG, have led to revived interest in supplying
LNG to the U.S. market.
Whether LNG can provide a cap on U.S. natural gas market prices, or a floor
below which prices are unlikely to fall, depends on the way the price formation
process develops in the LNG market. The large quantities of LNG potentially
available on world markets lead some to envisage the U.S. imports of LNG
expanding sharply in response to escalating domestic prices, keeping prices capped,
and competition driving the price of LNG down to its cost of production and
3 Energy Information Administration, Annual Energy Outlook 2004. January 2004, pp.89-91.
4 Ibid. Table 13.

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CRS-3
delivery. Others see LNG providing a high cost, relatively inflexible, incremental
supply to the market that might well be critical in avoiding supply shortages, but at
the same time keeps the price of all gas high enough to justify the cost of LNG. How
prices are formed, and whether they lead or follow the market price, will be important
in defining the role played by LNG in the U.S. natural gas market.
Standard LNG Markets
The LNG market is based on a four link supply chain. The critical links are
field development, which might also include a producing country pipeline, the
liquefaction plant, specialized tankers for delivery to the consuming country, and a
receiving plant to convert the LNG back to a gaseous state. Each link in the chain
is capital intensive, and the system does not produce any revenue until the entire
chain is operational. Investment requires a large initial capital outlay which is offset
by earning from a long term stream of net revenues. If risk concerning projected gas
volumes or price increases, the cost of capital for the project increases, threatening
its economic viability.
The key to facilitating transactions in the LNG market has been the Sale and
Purchase Agreement (SPA), a twenty year or longer, relatively inflexible, contract
between the owners of the upstream portions of the supply chain and the purchaser
of the LNG.5 The length of the contract is determined by the relationship between
the size of the gas field, the capital investment required for the project, and the
consumer’s needs. Since capital expenses are high, fields supplying the feedstock
natural gas must be large volume producers with a long expected life, leading to long
term contracts to supply long term consumption needs.
Risk is a critical factor in the LNG market. The SPA is designed to manage and
reapportion the risk. Most long term contracts include a “take-or-pay” provision.
This provision requires that the buyer guarantee purchase of agreed upon gas
volumes, or pay for non-delivery. By requiring the buyer to take contracted volumes
of gas or pay for non-delivery, the SPA vests the purchaser with the quantity risk of
the contract, virtually assuring the producer of full production levels of output. Full
production is important to the producer because less than full capacity production
usually translates into poor economic performance. Price risk is managed through
a price escalation clause in the SPA. In most existing SPAs, the price escalator is
tied to the price of oil, which traditionally has been the prime competing fuel for
natural gas.6 LNG prices have typically been determined through this negotiated,
administered process of contract negotiation based on an external index price.
Price and volume risk do not exhaust potential risk. Even though the producing
nation’s national oil company is typically a principal, or partner, in the upstream
5 The SPA usually excludes the receiving terminal, which is left to the consuming country
to provide. “Upstream,” then refers to the gas field, the liquefaction plant, and the
specialized tankers that deliver the LNG to the receiving terminal.
6 This is especially true for the Japanese market where a “Japanese Crude Cocktail” serves
as the reference price for LNG.

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CRS-4
investment, country risk with respect to changing tax and business policy remains.
Additionally, political instability has played a role in increasing the risk in LNG
markets.7
Investment costs have been high for LNG projects. As recently as mid-1990s,
the capital investment cost of a liquefaction plant was over $400 per ton of annual
capacity, implying a cost of over $2.5 billion for a plant with an annual capacity of
6.6 million tons.8 Additional costs, of approximately equal magnitude, are also
required for natural gas field development and a possible pipeline from the field to
the liquefaction plant.9 Recently constructed facilities have gained significant cost
reductions. The recently completed Trains 2 and 3 in Trinidad were constructed for
less than $200 per ton of annual capacity.10 Although some of these cost reductions
are related to improved technology, a major factor in cost reduction is economy of
scale. Large plants, now more technically feasible, allow for reduced capital costs
per ton of LNG produced.
Capital costs, scale of the production facility, and risk continue to be related.
As larger scale operations reduce the unit cost of gas, the economics of the project
become more favorable, risk is reduced and project financing and completion
becomes more probable. However, as the size of production capacity increases, the
risk associated with marketing ever larger quantities of LNG grows. As a result of
marketing risk, producers still have a bias toward long term contracts which virtually
ensure favorable economics for the project.
Transportation costs, to include a fleet of specialized, dedicated tankers, have
been significant in LNG projects. No clear ownership pattern exists in LNG tankers;
some are owned by importing companies, some by exporting companies, and some
by shipping companies. Very few LNG tankers are owned by independent shipping
companies and available to handle spot cargoes. The SPA typically includes a
“destination clause” which prevents the buyer from re-selling purchased LNG to a
third party, further discouraging the development of a spot market.
Currently, many tankers are used inefficiently. Since they hold dedicated
cargoes, they follow set point-to-point routes, and are unable to take advantage of
arbitrage possibilities or the re-allocation of shipments through cost reducing cargo
substitution. Many tankers also make return trips empty, further increasing costs.
Competitive incentives are minimal in this part of the market due to the SPA
destination clause as well as the ownership linkages of the LNG supply chain.
7 Guerilla activity in Sumatra, Indonesia in 2001 resulted in the temporary disruption of
production at the Arun liquefaction plant which supplies Japan.
8 Institute for Energy, Law & Enterprise, University of Houston Law Center, Introduction
to LNG, January 2003, p.20.
9 James T. Jensen, The LNG Revolution, The Energy Journal, Vol. 24, No.2, 2003, p.3.
10 Train is a term to describe a liquefaction production facility. Any given plant may include
several trains. The largest trains currently are 5.0 million tons per annum.

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The role of the spot, or short term, purchase market in the traditional LNG
market structure is minor. Although short term purchases are not unknown, as of
April 2004, no LNG facility has been built that is not secured by a SPA. Competitive
spot markets aid in price discovery, but in traditional LNG markets, prices are
negotiated and administered and likely linked to oil prices. Spot, as well as futures
and derivative markets, allow market participants to manage risk, but in the
traditional LNG market, quantities are set in the SPA and the producer’s need to
operate at full capacity to cover financing costs and generate a profit dictates contract
terms. Since most large LNG buyers under the SPA system are electric utilities who
were, until recently, operating as regulated monopolies, there was only limited
impetus for reform.
Competitive LNG Markets
The long term case for an “idealized” competitive market is based on the
premise that price competition between large numbers of buyers and sellers results
in lower costs and better quality service for consumers. To adapt the traditional LNG
world market to this model, much of the existing supply chain would need to be
broken down and re-assembled, based on market principles. The supply chain would
need to be more competitive within each link in the chain, as well as the links
themselves becoming more independent.
The competitive market model would have many countries developing currently
stranded gas resources, and, either independently, or more likely in practice, with the
assistance of international energy companies, producing volumes of LNG for the
open market.11 Partners in LNG projects would market their production shares
independently of other owners, further increasing competition. Consuming countries
would grow in number, and they would shop around the world to find the best
available price among competing sellers. Price would be formed in an international
market through gas-to-gas competition with home market sources, driving down
prices to cost effective levels. Buyers could re-sell purchased gas if economic
incentives indicated that was the profitable strategy. Tankers would be operated by
shipping companies that competed against one another for cargoes, and managed the
available fleet in such a way that shipping costs were minimized. LNG offloading
would take place at receiving facilities that were open to all who brought cargoes to
the facilities and were located in a variety of locations around the consuming market
to minimize the delivery costs to the ultimate consumers. The SPA, if it was
available in a competitive market, would have to offer increased flexibility to
accommodate changing conditions.
Supporting the supply chain would be the availability of financial capital to
develop new projects, fund new tankers, and build new receiving terminals without
the necessary collateral of an SPA. The market would be sufficient in size, depth,
and transparency, to assure investors that demand was stable and deep enough to
justify investment. Although risk would remain a part of the transaction, it could be
11 Stranded gas resources are economically viable to produce, but currently have no
transportation system in place for delivery to market.

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CRS-6
managed through the creation of a financial derivatives strategy based on swaps,
futures contracts, and options, to allow each class of market participant the ability to
transfer risk to those more willing and able to hold it. These derivative markets
would exhibit sufficient financial liquidity so that creating and backing out of
strategic positions could be accomplished at low cost. Purchase contracts would tend
to be of short duration because both buyers and sellers would find it advantageous
to continually search the market for the transaction offering the best economic return.
Structural Transformation
A structural transformation began in international LNG markets in the late
1990s. This transformation was driven by both time and technology. At that time,
contracts signed during the market expansion of the 1970s and 1980s began to expire.
At expiration, LNG buyers faced less regulation in their home markets. Technology
had also improved, allowing for larger, more cost efficient LNG production and
transportation systems. The dual pressures of changing buyer requirements and
lower costs set in motion a market transformation that continues today.

The United States was an early participant in the modern international LNG
market, dating back to the late 1960s with exports from Alaska to Japan.12 In the
1970s and 1980s, Japan, currently the worlds leading importer of LNG, expanded its
imports from Indonesia, Brunei, Abu Dhabi, and other countries. Japan, which has
no domestic sources of natural gas, and no access to pipeline imports, uses natural
gas mostly as a fuel for the electric power industry. As a result of these origins, LNG
prices have been derived from, and determined contractually by, the price of oil. Oil
was the substitute fuel for Japanese utilities at the time. As a result, the LNG price
structure is based on a “net back” to the producer based on the local market natural
gas price, if available, and the reference price of oil, if not. As a result of this pricing
mechanism, LNG investment decisions are made on the basis of the actual and
forecast prices in target markets and what the net back to the project might yield.
There is little evidence to suggest that LNG prices have adjusted to competition in
the market. More common is the result that if prices for natural gas are weak, LNG
supplies tend to exit the market. Four LNG receiving facilities were built in the
United States in the 1970s.13 With the decline of natural gas prices in the 1980s, and
the low prices prevalent for most of the 1990s, these facilities either were closed, or
remained open at very low utilization rates in the latter decade. The high natural gas
prices of the last five years, supported by demand growth for natural gas, coupled
with the declining costs of LNG, have provided economic incentive for these
facilities to re-open and expand.
12 These exports continue, with about 63 billion cubic feet of gas sent to Japan from the
Kenai Peninsula terminal in Alaska in 2003.
13 These facilities are at Cove Point, Maryland, Elba Island, Georgia, Everett, Massachusetts,
and Lake Charles, Louisiana. Their combined peak capacity is about 1.2 tcf, with a baseload
capacity of about 880 bcf. All four have either increased their capacities or plan to complete
an expansion by 2006. Peak capacity of about 1.6 tcf is expected at the four facilities after
expansions are completed.

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CRS-7
Contract Provisions. The LNG market is showing signs of undergoing a
transition. Contracts signed 20 to 25 years ago are expiring. Even in the Asian
market, the regulatory environment for utilities is becoming more open. Before they
enter into new LNG supply agreements, consumers are requesting, and receiving,
liberalized contract terms compared to the typical SPA of the 1980s. Take-or-pay
provisions now typically only apply to a part to the contract volume, giving the
consumer some flexibility to expand or contract purchases as dictated by demand.
Even the destination clause is being liberalized in some cases. On the supply, or
producer, side of the market, more sources of LNG are becoming available to the
market, potentially giving buyers more choice.14
Although liberalized contract terms are generally beneficial for consumers, the
question of whether they are evidence of progress toward an idealized competitive
market remains. To the extent that newly negotiated contracts remain long term, they
may fix the market structure and practices at their current state for the next 10 to 20
years, possibly slowing further liberalization. For example, if new contracts allow
10% of contract volumes to be exempt from take or pay provisions, this could be
interpreted as 10% of contract volumes being available for trade on a short term, or
spot, market, or it could be interpreted as an allowance for the demand volatility that
even long term customers might experience, based on earlier contracts with no
specific relationship to spot market transactions.

Spot Markets and Prices. Whether the increasing number of buyers and
sellers participating in the LNG market means it is becoming more competitive and
flexible depends on whether the price of LNG is the signal that affects the balance
between demand and supply. To the extent that the relationship between buyers and
sellers is still characterized by the SPA, the additional market participants may do
little to change the fundamental nature of the market. If the market follows
traditional practice, if all new supplies of LNG are tied to specific consumers, no net
new gas will be available to secure the operation of a viable spot market. Existing
market relationships will be scaled up to meet the new, larger size of the market, but
the fundamental relationships will remain the same. The existence of a viable spot
market is important because it allows consumers the flexibility to sell off excess
supply to eliminate surpluses, and acquire additional supplies to ameliorate shortages
as well as aiding in price discovery. These activities are central to the market process
and the key to achieving lower prices and driving down costs. Market determined
prices will also help determine future investment decisions in LNG capacity in a
more efficient way.
Recent data suggests that while short term transactions in LNG are becoming
more prevalent, the existence of a viable spot market is still in the future.15 Spot
cargoes in 2003 entered the United States mostly in the summer months when world
14 Energy Information Administration, The Global Liquefied Natural Gas Market: Status
and Outlook, December 2003, pp. 8-16.
15 Definition and classification problems exist in the LNG market. In 2003, the Energy
Information Agency classified 83.2% of U.S. LNG imports as spot cargoes. However,
almost all of the cargoes from Trinidad are U.S. allocated, even though classified as spot
cargoes. Neil, Chris. “LNG in the U.S.–1" Oil and Gas Journal. April 12, 2004. pp. 71-72.

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CRS-8
heating demand was lowest, suggesting that the United States was a residual market
for LNG.16 Other data suggest that the deliveries taken at the four operational U.S.
receiving terminals was adversely affected by world events and competitive price
pressures. Weak U.S. natural gas prices in the winter of 2001-02 resulted in capacity
utilization declining at the U.S. receiving facilities, as available supplies went to
Europe where prices were higher. The same situation occurred later in the year when
nuclear power problems in Japan, and shortages of tanker capacity, again lowered
U.S. capacity utilization rates as cargoes were diverted to Japan.17 This behavior has
led some analysts to characterize LNG supply as unreliable.18
This recent evidence on LNG cargoes and U.S. receiving facility capacity
utilization, in conjunction with the experience of the 1990s, suggests that LNG has
not yet developed the kind of deep, transparent spot market required for economic
efficiency, but is still dominated by fixed contractual relationships. Even though
these cited transactions are short term, they can be interpreted as the servicing of long
term clients on an emergency basis, with little relation to market based spot
transactions. A recent report suggested that although the Asian LNG market is more
sensitive to market fundamentals as contracts are re-negotiated, this does not equate
to the emergence of a global spot market because of infrastructure and logistical
problems, a lack of uncommitted LNG volumes, and few pipeline alternatives.19

The role of LNG as a stable, large volume supplier to the U.S. market is
enhanced by the expectation that expanding supplies can set a price cap on the U.S.
natural gas market. For LNG supply to set a price cap for the U.S. market, producers
would likely have to maintain excess capacity, or have the ability to rapidly expand
production in response to price increases, to allow any upward price pressure to be
set against extra quantities supplied. In addition, the price of LNG should lead the
market, in the sense of competitively being driven down to delivered cost, rather than
following the market and simply netting back returns based on the current market
price for natural gas or a competing reference energy source. Because the costs of
LNG project development are high with significant variability, price will have to be
sufficiently high to cover the costs of the highest cost supplier in the market, or those
high cost producers will be forced to exit the market or seek markets that can meet
the required price. In this sense, increased U.S. LNG use might actually form a price
floor below which natural gas prices cannot fall without risking supply disruption.
Shipping. The LNG tanker fleet is increasing. In October 2003, the LNG
tanker fleet stood at 151 ships with 55 ships in construction. Newer ships tend to be
larger which reduces the unit cost of delivered LNG. Practical limits on the size of
16 Ibid. p.71.
17 James T. Jensen, “The Expanding Role of LNG in North American Gas Supply - A
Challenge to Gas Supply Modeling,” Presentation at the National Energy Modeling System
Annual Energy Outlook Conference, Washington, D.C., March 23, 2004. Figure 2.
18 Neil, Chris. “LNG in the U.S. – 1" Oil and Gas Journal. April 12, 2004. p. 72.
19 “Asian LNG Feels Winds of Change,” Petroleum Intelligence Weekly. Volume XLIII,
Number 23, June 7, 2004. p.5.

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LNG tankers may be related to their ability to berth at existing receiving terminals,
at least in the United States.
Virtually all of the new ships currently under construction are to be dedicated
to delivering the product from specific projects. Recently, some major importing and
exporting companies have ordered LNG tankers not dedicated to a specific project.
This construction may or may not signal the emergence of a merchant fleet. While
these tankers might be used for spot cargoes, it is also possible that they will be used
by these large companies as insurance against the quantity uncertainty associated
with incomplete up and downstream projects in which the companies have invested.
There is still little evidence of the emergence of an independent LNG tanker fleet in
the new construction data. Therefore, the newly constructed tankers are not likely to
change the structure of the market in the direction of more competition; their purpose
may be largely to service the larger scale of the evolving market. The dedicated
structure of the LNG tanker sector suggests that existing practices in shipping will
tend to continue. An available, uncommitted tanker fleet is, for many analysts, a
necessary condition for the existence of a competitive LNG spot market. Until
speculative ships are built in significant number, and shipping companies are willing
to risk the approximately $150 to $160 million for a mid-sized tanker it is unlikely
that significant, continual, spot market transactions can be sustained.20
Tanker costs have declined. A 138,000 cubic meter capacity ship had an
estimated nominal cost of $280 million in the mid-1980s, and an estimated nominal
cost of about $155 million in 2003. Ships are also becoming larger over time,
reducing the per unit transportation cost of LNG. Actual charter rates are harder to
specify because of the non-market use of most of the tankers, but estimates run from
$27,000 to $150,000 per day with an average near $60,000 per day.21 The reduced
cost of LNG tanker construction is largely driven by more shipyards competing to
build the tankers.22
When LNG tankers reach the consuming nation, they must have access to
specialized receiving facilities. With respect to receiving terminal policy in the
United States, policy may have moved the industry away from market based
competition in the interest of certainty of the investment climate. The Federal Energy
Regulatory Commission (FERC) determined that LNG receiving facilities do not
have to provide open access to all who wish to dock LNG cargoes, they can serve the
proprietary interests of their owners, who typically have contracted LNG resources
and require dedicated unloading facilities.23 This decision may have been taken in
20 Energy Information Administration, “The Global Liquefied Natural Gas Market: Status
and Outlook.” December 2003, p.30.
21 Energy Information Administration, The Global Liquefied Natural Gas Market: Status
and Outlook, December 2003, pp.44-45.
22 Teo, Karen. “ExxonMobil Seeking Tankers to Move Qatari Natural Gas,” Oil Daily, May
18, 2004. p.6.
23 The Maritime Transportation Security Act of 2002 (P.L. 107-295) transferred regulatory
control of offshore LNG terminals from FERC to the Coast Guard, as well as assuring
(continued...)

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the interest of enhancing investment feasibility. Given the high costs of LNG
facilities, a fear was thought to exist that little, or no, investment in new receiving
terminals would take place if the owners/investors in the project could not be assured
that their investment would result in their ability to import their own LNG supplies
and achieve an acceptable long term rate of return on their investment. However, the
decision is likely to retard the development of a functioning spot market. If receiving
terminal capacity is largely structured to the sending capacity of an identified LNG
project, it would become more difficult to justify a speculative, non allocated LNG
project.
Risk Management. An important factor restricting the movement toward a
competitive LNG market is the limited ability of market participants to manage risk
through existing institutions. The New York Mercantile Exchange (NYMEX) offers
futures and options contracts on natural gas which can be used to manage some of the
transaction risk. However, these are standardized contracts whose contract gas
quantity levels are small compared to the size of a typical LNG tanker delivery,
making it difficult to establish a contract position.24 The market also thins out as
contracts further than three to six months in the future are considered, again limiting
market participants ability to manage long run risk. Additionally, these contracts
offer no opportunity for the parties to the agreement to negotiate customized terms
which may be required to facilitate large, high value transactions.

The solution to the risk management limitation might lie in an active over-the
-counter derivatives market, but that alternative may not be viable as the major
energy trading companies offering “risk insurance” have withdrawn from the market.
The over-the- counter market, which is designed to account for the specific needs of
traders with respect to contract size, timing, and other characteristics, has been
essentially closed since the bankruptcy of Enron in December 2002. The Enron
bankruptcy caused traders to lose faith in the energy trading process, withdraw from
trading, and led a significant contraction of the over the counter market.
Other Factors. Additional physical and security investments must take place
before LNG import expansion can occur. Many problems and policy concerns exist
surrounding these investments. Terminal siting, pipeline infrastructure, safety and
physical security, and other supply bottlenecks may all require policy responses. The
higher energy content of imported LNG, as well as its suitability for pipeline
transmission also present technical challenges to rapid expansion of LNG usage. For
further information on these topics see CRS Report RL32386.25
23 (...continued)
terminal owners proprietary access. The “Hackberry Decision” gave the same proprietary
access rights to owners of onshore facilities under the regulatory supervision of the FERC.
24 The typical LNG tanker delivery is 650 times the size of a NYMEX contract. See James
T. Jensen, “The LNG Revolution.” The Energy Journal, Volume 24, No. 2, 2003, p.25.
25 For greater detail concerning these issues see CRS Report RL32386: Liquefied Natural
Gas (LNG) in U.S. Energy Policy: Issues and Implications by Paul W. Parfomak. May 17,
2004.

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CRS-11
Conclusions
Growing demand, stagnating domestic production, and the reduced availability
of traditional sources of imported natural gas suggest the possibility of imbalance in
the natural gas market over the AEO forecast period to 2025. Imbalance could show
up as physical shortages, if new sources of production cannot be identified, as well
as volatile, high price levels. LNG has been suggested as a possible solution to this
problem. Large quantities of stranded natural gas reserves exist around the world to
potentially address the quantity problem, while if large quantities of LNG become
available, they might establish a price cap for the market based on the cost of LNG.
The debate thus far concerning U.S. LNG imports has focused on the investment
in receiving terminals, especially siting, to include jurisdictional issues between the
FERC and the states, security, environmental safety, and to a lessor extent the
magnitude of capital investment. CRS analysis suggests that other institutional and
market structure factors might also create impediments to an LNG based scenario,
especially with respect to the competitive nature of LNG price formation.
Since the traditional LNG market structure, largely intact today, is based on
long term contracts designed to ensure business stability, a number of changes would
need to occur if a more competitive market structure is to evolve. Recognizing the
scale of investment required to start LNG production, one of the primary factors is
risk. Without the institutions and financial instruments to supplement or replace the
SPA in risk management it will be difficult for a competitive spot market to develop.
Existing markets offer market participants only a partial ability to manage risk, and
given the size of potential LNG based transactions, they might alter the nature of
trading if they were included in the market.
If a competitive market fails to develop, it is likely that future expansion of LNG
will be through complex long term contract negotiations which might limit the role
of efficient, market based prices. Traditionally, LNG prices have been netted back
to producers based on the price of a substitute commodity, usually oil, or on the price
of natural gas in the local market. Without the pressure of a competitive market it
is unlikely that the long term price of gas will be driven to cost based levels. If the
price determination mechanism for LNG remains there is little reason to assume that
LNG can provide a price cap to domestic natural gas prices. In this case, a possible
scenario would be for LNG to enter the U.S. market when prices are high, and then
exit if prices moderate. While this behavior might moderate extreme price spikes,
it might not provide a stable supply source for domestic natural gas consumers.
Because increasing LNG supplies is only one of a number of ways to close the
projected gap between U.S. natural gas demand and supply over the coming years,
any decisions to encourage or discourage this particular source may have implications
for other potential sources. Optimists point to the large quantities of stranded natural
gas around the world and the plans to develop dozens of receiving terminals in the
United States and might conclude that this source alone might close the demand and
supply gap. If this was the case, the need for an Alaska natural gas pipeline might be
weaker, as would the need for drilling in environmentally sensitive areas and the need

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CRS-12
for expanding technology to develop gas reserves from new sources. If a more
pessimistic view of LNG is taken these other alternatives rise in importance.

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