Order Code RL32386
CRS Report for Congress
Received through the CRS Web
Liquefied Natural Gas (LNG)
in U.S. Energy Policy:
Infrastructure and Market Issues
Updated February 18, 2005
Paul W. Parfomak
Specialist in Science and Technology
Resources, Science, and Industry Division
Congressional Research Service ˜ The Library of Congress

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Liquefied Natural Gas (LNG) in U.S. Energy Policy:
Infrastructure and Market Issues
Summary
Liquefied natural gas (LNG) imports to the United States are increasing to
supplement domestic gas production. Government officials such as the Federal
Reserve Chairman and the Secretary of Energy have spoken in favor of LNG imports
to mitigate high energy prices. Through regulatory and administrative actions,
federal agencies are trying to attract private capital for LNG infrastructure, streamline
the LNG terminal approval process, and promote LNG trade. Were these policies to
continue and gas demand to grow, LNG might account for as much as 21% of U.S.
gas supply by 2025, up from 3% in 2004. Congress is examining the infrastructure
and market implications of greater U.S. LNG demand.
There are concerns about how LNG capacity additions would be integrated into
the nation’s gas infrastructure. Meeting projected U.S. LNG demand would require
six to ten new import terminals in addition to expansion of four existing terminals.
Five new terminals in the Gulf of Mexico are approved, but public opposition has
blocked near-to-market terminals which might save billions of dollars in gas
transportation costs. New LNG terminals can also require more regional pipeline
capacity to transport their supply, although this capacity may not be available in key
markets. Securing LNG infrastructure against accidents and terrorist attacks may
also be a challenge to public agencies. Since import terminals process large volumes
of LNG, a breakdown at any facility has the potential to bottleneck supply.
LNG’s effectiveness in moderating U.S. gas prices will be determined by global
LNG supply, the development of a “spot” market, potential market concentration, and
evolving trading relationships. There appears to be sufficient interest among LNG
exporters to meet global demand projections, although it remains to be seen which
new export projects will be built. An LNG spot market, which may help U.S.
companies import LNG cost-effectively, also appears to be growing. Although some
industry analysts believe the future LNG market may be influenced by a natural gas
cartel, the potential effectiveness of a such a cartel is unclear. Whether exporters
cooperate or not, an integrated global LNG market may change trading and political
relationships. In a global market, individual country energy polices may affect LNG
price and availability worldwide. Trade with LNG exporters perceived as politically
unstable or inhospitable to U.S. interests may raise concerns about supply reliability.
Recent measures before Congress (H.R. 4413 in the 109th Congress, S. 2095 in
the 108th Congress, and P.L. 108-199) would affect LNG imports by encouraging
domestic gas production and new LNG terminal construction, although Congress has
not been explicit about the desirability of imported LNG overall. As Congress
debates U.S. natural gas policy, three questions emerge: (1) Is expanding LNG
imports the best option for meeting natural gas demand in the United States? (2)
What role, if any, should the federal government play in facilitating the development
of LNG infrastructure domestically and abroad? (3) How might Congress mitigate
the risks of the global LNG trade within the context of national energy policy?
This report will be updated as events warrant.

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Contents
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
What Is LNG? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
U.S. LNG Import Experience and Projections . . . . . . . . . . . . . . . . . . . . . . . . 4
Global LNG Market Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
LNG Safety and Security . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
LNG Policy Activities of U.S. Federal Agencies . . . . . . . . . . . . . . . . . . . . . . 7
FERC Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Offshore Terminal Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
DOE LNG Summit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Key Issues in U.S. LNG Import Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Physical Infrastructure Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Terminal Siting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Pipeline Infrastructure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Interchangeability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Safety and Physical Security . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Supply Bottlenecks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Global LNG Market Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Global LNG Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
Spot Market Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Market Concentration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Global Trade and Politics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Appendix: Existing and Proposed LNG Import Terminals in North America . . 23
List of Figures
Figure 1: LNG Supply Chain . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Figure 2: U.S. Natural Gas Wellhead Price ($/Mcf) . . . . . . . . . . . . . . . . . . . . . . . 4
Figure 3: Projected U.S. Natural Gas Production and Imports (Tcf) . . . . . . . . . . . 5
Figure 4: U.S. Natural Gas Pipeline Flows and Proposed LNG Terminals . . . . . 11
Figure 5: Global LNG Import Market Shares Projected for 2015 . . . . . . . . . . . . 20
List of Tables
Table 1: Global Natural Gas Reserves and LNG Production Capacity . . . . . . . . 17

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Liquefied Natural Gas (LNG) in U.S. Energy
Policy: Infrastructure and Market Issues
Introduction
The United States is considering fundamental changes in its natural gas supply
policy. Faced with rising natural gas demand and perceived limitations in North
American gas production, many in government and industry are encouraging greater
U.S. imports of liquefied natural gas (LNG). Recent activities by the Federal Energy
Regulatory Commission, the Department of Energy, and other federal agencies to
promote greater LNG supplies have included changing regulations, clarifying
regulatory authorities, and streamlining the approval process for new LNG import
terminals. While forecasts vary, many analysts expect LNG to account for 12% to
21% of total U.S. gas supply by 2025, up from approximately 3% in 2004. If these
forecasts are correct, U.S. natural gas consumers will become increasingly dependent
upon LNG imports to supplement North American pipeline gas supplies.
Recent measures before Congress have sought to encourage both new LNG
terminal construction and domestic gas production. The Liquefied Natural Gas
Import Terminal Development Act (H.R. 359) was introduced on January 25, 2005.
Among other provisions, H.R. 359 would clarify that the federal government has the
primary authority to approve LNG terminal siting (Sec. 2d); would clarify that the
Federal Energy Regulatory Commission (FERC) is the lead agency for onshore LNG
terminal environmental review and permitting (Sec. 2g); would codify FERC’s prior
rulings exempting LNG terminals from certain rate regulations and open access
requirements (Sec. 2d); and would streamline the onshore terminal siting review
process, requiring FERC to issue siting decisions within one year of receiving an
application (Sec. 2e).
In the 108th Congress, the Energy Policy Act of 2003 (S. 2095) included various
incentives for domestic natural gas producers (Subtitle B), provided loan guarantees
and other incentives for an Alaska gas pipeline (Subtitle D), and clarified federal
approval authority for LNG terminal expansions (Sec. 320).1 The Consolidated
Appropriations Act of 2004 (P.L. 108-199) sought to amend the Energy Policy Act,
should it have been enacted, to create a financial incentive for constructing an LNG
terminal in Alaska for shipments to the lower 48 states (Sec. 146).
1 The House version of the Energy Policy Act of 2003 (H.R. 6, 108th Cong. (2003); as
reported (H.Rept. 108-375 (2003)). That version also includes domestic gas production
incentives (Title IIIB), and Alaska gas pipeline incentives (Title IIID).

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While an increase in LNG imports is already underway, federal officials and
Members of Congress have been debating the merits and risks of U.S. LNG
dependency. In 2003 congressional testimony, for example, Federal Reserve
Chairman Alan Greenspan called for “a major expansion of LNG terminal import
capacity” as essential to alleviate the harmful economic effects of high energy prices.2
In April, 2004, Department of Energy Secretary Spencer Abraham testified before
Congress that “increasing U.S. access to [LNG] imports...will help produce the fuels
we need in the 21st Century.”3 In a July, 2004 election campaign interview,
President Bush reportedly stated “I strongly support developing new LNG capacity
in the United States.”4 Some in Congress question the implications of such a policy,
however, drawing analogies to the consequences of U.S. dependency on foreign oil.5
Other observers express concern about LNG safety and vulnerability to terrorism.6
Specific questions are emerging about the implications of greater LNG imports
to the United States. LNG has substantial physical infrastructure requirements and
there are uncertainties about how this infrastructure would be integrated into North
America’s existing gas network. The potential effects of larger LNG imports on U.S.
natural gas prices will be driven by the global LNG market structure, although that
market structure is still evolving. Political relationships among countries in the LNG
trade may also change as LNG becomes increasingly important to their economies.
This report will review the status of U.S. LNG imports, including projections
of future U.S. LNG demand within the growing international LNG market. The
report will summarize recent policy activities related to LNG among U.S. federal
agencies, as well as private sector plans for LNG infrastructure development. The
report also will introduce key policy considerations in LNG infrastructure and market
structure, highlighting current market information and key uncertainties. Finally, the
report will identify key questions in LNG import policy development.
Background
Natural gas is widely used in the United States for heating, electricity
generation, industrial processes, and other applications. In 2003, U.S. natural gas
consumption was 22 trillion cubic feet (Tcf), accounting for 2% of total U.S. energy
2 Greenspan, A., Chairman, U.S. Federal Reserve Board. “Natural Gas Supply and Demand
Issues.” Testimony before the House Energy and Commerce Committee. June 10, 2003.
3 Abraham, Spencer, U.S. Energy Secretary. Testimony to the House Committee on Energy
and Commerce Hearing on Department of Energy FY 2005 Budget Priorities. Apr. 1, 2004.
4 American Gas Association (AGA). “President George W. Bush on Supply, Demand and
His Energy Plan.” American Gas. Washington, DC. July, 2004. p3.
5 Hon. Peter Domenici. “U.S. Must Build LNG Ports to Avoid Spiraling Natural Gas Prices,
Sen. Domenici Says.” Press release. Feb. 15, 2005.
6 Hebert, H.J. “Potential of Catastrophic Fire from Terrorist Attack Worries LNG
Opponents.” Associated Press. Jan. 22, 2005.

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consumption.7 Until recently, nearly all U.S. natural gas was supplied from North
American wells and transported through the continent’s vast pipeline network to
regional markets. In 2003, however, due to constraints in North American natural
gas production, the United States sharply increased imports of natural gas from
overseas in the form of liquefied natural gas (LNG). While absolute levels remain
limited today, growth in LNG imports to the United States is expected by many
analysts to accelerate over the next 20 years, reflecting growing domestic demand
and expectations for a global expansion in LNG trade.
What Is LNG?
When natural gas is cooled to temperatures below minus 260°F it condenses
into liquefied natural gas, or “LNG.” As a liquid, natural gas occupies only 1/600th
the volume of its gaseous state, so it is stored more effectively in a limited space and
is more readily transported by tanker ship. A typical tanker, for example, can carry
138,000 cubic meters of LNG — enough to supply the daily energy needs of over 10
million homes.8 When LNG is warmed, it “regasifies” and can be used for the same
purposes as conventional natural gas.
The physical infrastructure of LNG includes several interconnected elements as
illustrated in Figure 1. In producing countries, natural gas is extracted from gas
fields and transported by pipeline to central liquefaction plants where it is converted
to LNG and stored. Liquefaction plants are built at marine terminals so the LNG can
be loaded onto special tanker ships for transport overseas. Tankers deliver their LNG
cargo to import terminals in other countries where the LNG can again be stored or
regasified and injected into pipeline systems for delivery to end users.
This LNG infrastructure requires large capital investments. In addition to gas
field development costs, a new liquefaction plant costs approximately $2-$3 billion,
and an import terminal costs $500 million to $1 billion. Each LNG tanker costs
$150-$200 million.9
Due to the high capital costs of LNG infrastructure, LNG trade has traditionally
relied upon long-term fuel purchase agreements in order to secure project financing
for the entire supply chain. Of over 160 major LNG supply contracts in force around
the world as of March, 2004, well over 90% had a contract term of 15 years or
longer.10 While these contracts have increasingly incorporated some flexibility by
accommodating extra LNG deliveries, for example, or allowing shipments to be
7 Energy Information Administration (EIA). Annual Energy Outlook 2005.
DOE/EIA-0383(2005). Feb. 2005. Table A13. p159.
8 Energy Information Administration (EIA). The Global Liquefied Natural Gas Market:
Status & Outlook. DOE/EIA-0637. Dec. 2003. p30.
9 Clark, Judy. “CERA: Natural Gas Poised to Overtake Oil Use by 2025.” Oil & Gas
Journal. Mar. 1, 2004. p22.
10 “LNG Contracts.” LNG OneWorld website. [http://www.lngoneworld.com] Drewry
Shipping Consultants. London, England. Mar. 9, 2004.

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diverted, they have only allowed for a limited supply-demand response compared to
other global commodities markets.
Figure 1: LNG Supply Chain
Source: Oil & Gas Journal. Nov. 10, 2003. p64.
U.S. LNG Import Experience and Projections
The United States has used LNG commercially since the1940s. Initially, LNG
facilities stored domestically produced natural gas to supplement pipeline supplies
during times of high gas demand. In the 1970’s LNG imports began to supplement
domestic gas production. Between 1971 and 1981, developers built four U.S. import
terminals: in Massachusetts, Maryland, Georgia, and Louisiana.11 Due primarily to
a drop in domestic gas prices, however, two of these terminals quickly closed.
Imports to the other two terminals remained small for the next 30 years. In 2002,
U.S. LNG imports were only 0.17 Tcf, less than 1% of U.S. natural gas supply.12
Figure 2: U.S. Natural Gas Wellhead Price ($/Mcf)
$7.00
$6.00
$5.00
$4.00
$3.00
$2.00
$1.00
$0.00
1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005
Source: Energy Information Administration. Natural Gas Weekly Update. Feb. 3, 2005.
United States demand for LNG has been increasing dramatically since 2002.
This growth in LNG demand has been occurring in part because North American
natural gas production appears to have plateaued, so it has not been able to keep pace
with growth in demand. As a result, U.S. natural gas prices have become higher and
more volatile. As Figure 2 shows, gas prices at the wellhead have risen from
between $1.50 and $2.50/Mcf through most of the 1990s to an average above
11 An LNG terminal was also built at Kenai, Alaska in 1969 for exports to Japan.
12 EIA. DOE/EIA-0383(2005). Feb. 2005. Table A13. p159. Tcf = trillion cubic feet.

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CRS-5
$5.00/Mcf and a peak above $6.00/Mcf in 2004.13 At the same time, international
prices for LNG have fallen because of increased supplies and lower production and
transportation costs, making LNG more competitive with domestic natural gas.14
While cost estimation is speculative, some industry analysts believe that LNG can be
economically delivered to U.S. pipelines for approximately $2.50 to $3.50/Mcf.15
Forecasts by the Energy Information Administration (EIA), National Petroleum
Council, and other groups project expansion in U.S. LNG imports over the next 20
years. Specific LNG forecasts vary based on methodology and market assumptions,
but most expect LNG to account for 12% to 21% of U.S. natural gas supplies by
2025.16 EIA’s reference forecast projects U.S. LNG imports to reach 6.4 Tcf in 2025,
which equates to approximately 21% of total U.S. gas supply for that year, up
substantially from the 2004 market share of about 3%.17 Figure 3 details projected
U.S. LNG imports relative to other natural gas production and pipeline imports in
EIA’s forecast.
Figure 3: Projected U.S. Natural Gas Production and Imports (Tcf)
Source: Energy Information Administration. Annual Energy Outlook 2005. Feb. 2005. pp159-160.
Global LNG Market Development
Projections of accelerated growth in U.S. LNG demand reflect a general
expansion in the global natural gas market. According to the EIA’s most recent
international forecast “natural gas is expected to be the fastest growing component
13 Mcf = thousand cubic feet
14 Sen. Colleen Taylor. “LNG Poised to Consolidate its Place in Global Trade.” Oil & Gas
Journal. Jun. 23, 2003. p73.
15 Hughes, Peter. “Outlook for Global Gas Natural Markets.” BP, Gas Power & Renewables
Division. Presentation to the World Bank Energy Week 2004 Conference. Mar. 8, 2004.
16 For a comparison of major forecasts see EIA. Annual Energy Outlook 2005.
DOE/EIA-0383(2005). Feb. 2005. Table 36. p118.
17 EIA. DOE/EIA-0383(2005). Feb. 2005. Table A13. p159.

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of world primary energy consumption.”18 EIA projects global natural gas demand to
rise by an average 2.2 percent annually for the next 20 years, with “the most robust
growth... among the nations of the developing world,” much of it to fuel electricity
generation.19 A significant part of this global gas demand growth is expected to be
met by new supplies of LNG. Long-term projections of global LNG growth vary, but
most major energy companies and industry analysts expect global LNG demand to
roughly triple by 2020, from 6 Tcf in 2003, to 18 Tcf or more in 2020.20 According
to EIA projections, 18 Tcf would account for approximately 12% of global natural
gas consumption in 2020.21
LNG Safety and Security
Natural gas is combustible, so an uncontrolled release of LNG poses a hazard
of fire or, in confined spaces, explosion. LNG also poses hazards because it is so
cold. Because LNG tankers and terminals are highly visible and easily identified,
they may also be vulnerable to terrorist attack. Assessing the potential risk from
LNG releases is controversial. A 1944 accident at one of the nation’s first LNG
facilities, for example, killed 128 people and initiated public fears about LNG
hazards which persist today.22 But technology improvements and standards since the
1940’s appear to have made LNG facilities safer. Between 1944 and 2004, LNG
terminals experienced approximately 13 serious accidents, with two fatalities,
directly caused by LNG.23 Since international LNG shipping began in 1959, tankers
have carried 40,000 LNG cargoes without a serious accident at sea or in port.24 In
January 2004, however, a fire at an LNG processing facility in Algeria killed an
estimated 27 workers and injured 74 others.25 The Algeria accident raised new
questions about LNG facility safety and security.
18 Energy Information Administration (EIA). International Energy Outlook 2004.
DOE/EIA-0484(2004). Apr. 2004. p47.
19 DOE/EIA-0484(2004). Apr. 2004. p47.
20 See, for example, Nauman, S.A. ExxonMobil. “The Outlook For Energy: A 2030 View.”
Irving, TX. Slide presentation. Jan. 25, 2005.; Deutshce Bank Securities, Inc. “Global LNG:
Exploding the Myths.” July 22, 2004. p.2.; Brinded, M., Royal Dutch/Shell. “Shared Trust -
The Key to Secure LNG Supplies.” Speech to the U.S. LNG Summit. Washington, DC, Dec.
17, 2003.
21 DOE/EIA-0484(2004). Apr. 2004. p47.
22 Bureau of Mines (BOM). Report on the Investigation of the Fire at the Liquefaction,
Storage, and Regasification Plant of the East Ohio Gas Co., Cleveland, Ohio, October 20,
1944. February, 1946.
23 CH-IV International. Safety History of International LNG Operations, Revision 2. TD-
02109. Millersville, MD. November, 2002. p6-12.
24 Verberg, G. “The Role of IGU in the Promotion of LNG.” Presentation to the Groupe
International des Importateurs de Gaz Natural Liquefie. Korea. Oct. 17, 2004.
25 Junnola, Jill et al. “Fatal Explosion Rocks Algeria’s Skikda LNG Complex.” Oil Daily.
Jan. 21, 2004. p6.

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A number of technical studies since the terror attacks of September 11, 2001,
have been commissioned to reevaluate the safety hazards of LNG terminals and
associated shipping. These studies have caused controversy because, due to
differences in analytic assumptions, some have reached inconsistent conclusions
about the potential public hazard of LNG terminal accidents or terror attacks. In an
effort to resolve these inconsistencies, the Department of Energy commissioned a
comprehensive LNG hazard study from Sandia National Laboratories. The Sandia
report, released in December 2004, determined that a worst-case, “credible” LNG
tanker fire could emit harmful thermal radiation up 2,118 meters (1.3 miles) away.26
Although, the report concluded that “risks from accidental LNG spills ... are small
and manageable,” it also concluded that “the consequences from an intentional
[tanker] breach can be more severe than those from accidental breaches.”27 Both
proponents and opponents of new LNG terminals have cited the Sandia findings to
support their positions. The controversy continues.
LNG Policy Activities of U.S. Federal Agencies
The Federal Energy Regulatory Commission and the Department of Energy
have been actively promoting increased LNG imports. Through regulatory and
administrative actions, these agencies have tried to foster LNG capital investment,
streamline the LNG terminal approval process, and promote global LNG trade.
FERC Regulations. The Federal Energy Regulatory Commission (FERC)
grants federal approval for the siting of new onshore LNG facilities and interstate gas
pipelines, and also regulates prices for interstate gas transmission.28 In December,
2002, the FERC exempted LNG import terminals from rate regulation and open
access requirements. This regulatory action allowed import terminal owners to set
market-based rates for terminal services, and allowed terminal developers to secure
proprietary terminal access for corporate affiliates with investments in LNG supply.29
These regulatory changes greatly reduced investment uncertainty for potential LNG
developers, and assured access to their own terminals.30 In February 2004, FERC
streamlined the LNG siting approval process through an agreement with the Coast
Guard (USCG) and the Department of Transportation (DOT) to coordinate review
of LNG terminal safety and security. The agreement “stipulates that the agencies
26 Sandia National Laboratories (SNL). Guidance on Risk Analysis and Safety Implications
of a Large Liquefied Natural Gas (LNG) Spill Over Water. SAND2004-6258. Albuquerque,
NM. Dec. 2004. p51.
27 SNL. Dec. 2004. p14.
28 Natural Gas Act of 1938 (NGA), June 21, 1938, ch. 556, 52 Stat. 812, (codified as
amended at 15 U.S.C. §§ 717 et seq).
29 Under open access, terminal owners were required to offer terminal services on a first
come, first served basis, and could not discriminate against service requests to protect their
own market activities.
30 Vallee, James E. “FERC Hackberry Decision Will Spur More U.S. LNG Terminal
Development.” Oil & Gas Journal. Nov. 10, 2003. p64.

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identify issues early and quickly resolve them.”31 FERC also announced a new
branch devoted to LNG within its Office of Energy Projects.32
Between 1999 and 2005, FERC approved the reactivation of the two idled U.S.
LNG terminals, and subsequently approved the expansion of the four existing import
terminals in the continental United States. In September, 2003, FERC approved the
Cameron LNG project in Hackberry, LA, the first new LNG import terminal to be
sited in the continental United States in over 25 years.33 In 2004, FERC also
approved LNG terminals in Freeport, TX and Sabine Pass, LA.34 These approvals
could increase total U.S. LNG import capacity to approximately 3.8 Tcf per year. In
2004, FERC also approved the construction of two new gas pipelines connecting
Florida to proposed LNG import terminals in the Bahamas.35
Offshore Terminal Regulations. In November, 2002, Congress passed the
Maritime Transportation Security Act of 2002 (P.L. 107-295), which transferred
jurisdiction for offshore LNG terminal siting approval from the FERC to the
Maritime Administration (MARAD) and the U.S. Coast Guard (USCG). According
to the Department of Energy (DOE), the act
... streamlined the permitting process and relaxed regulatory requirements.
Owners of offshore LNG terminals are allowed proprietary access to their own
terminal capacity, removing what had once been a major stumbling block for
potential developers of new LNG facilities.... The streamlined application
process ... promises a decision within 365 days....36
The proprietary access provisions for offshore terminals are similar to those set
by FERC for onshore terminals to ensure equal treatment for both kinds of facilities.
In November, 2003, the MARAD and USCG approved the Port Pelican project, the
first offshore LNG terminal ever to be sited in U.S. waters. The agencies have
subsequently approved Energy Bridge (January, 2004) and Gulf Landing (February,
2005), two additional offshore LNG projects. All three terminals would be located
in the Gulf of Mexico. Their combined annual capacity would be approximately 1.2
Tcf. As of February, 2005, the agencies were reviewing six additional offshore
terminal applications, two off the California coast, four in the Gulf of Mexico, and
one off the coast of Massachusetts..
31 Federal Energy Regulatory Commission (FERC). Press release. R-04-3. Feb.11, 2004.
32 Lorenzetti, M. “LNG Rules.” Oil & Gas Journal. Apr.5, 2004. p32.
33 Eckert, Toby. “Sempra Gets Final OK for Louisiana Gas Import Facility.” Copley News
Service. Sep. 10, 2003.
34 Federal Energy Regulatory Commission (FERC). “Existing, Proposed and Potential North
American LNG Terminals” Office of Energy Projects. Washington, DC. Jan. 6, 2005.
[http://www.ferc.gov/industries/gas/gen-info/horizon-lng.pdf].
35 “Cheyenne Plains, Tractebel’s Calypso Pipelines Get Green Light.” Natural Gas
Intelligence. Mar. 24, 2004.
36 EIA. DOE/EIA-0383(2004). Jan. 2004. p15.

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DOE LNG Summit. In December 2003, the Department of Energy (DOE)
hosted an LNG Summit attended by energy ministers from 24 countries as well as
senior executives from multinational energy and infrastructure companies.
According to the welcome address by Secretary Spencer Abraham, the conference
was intended as a call “to get new [LNG] terminals up and running, to develop new
[gas] fields around the globe, and to come together in partnership on mutually
beneficial, long-term agreements.”37 The Secretary also asked federal agencies to
“speed up the siting and permitting process for regasification and related facilities.”38
Key Issues in U.S. LNG Import Policy
Federal actions have been facilitating greater U.S. LNG imports, and the private
sector is responding with plans for new LNG facilities. Nonetheless, concerns are
emerging about the infrastructure needs of LNG, the future structure of global LNG
trade, and the relationship between the United States and other LNG market
participants.
Physical Infrastructure Requirements
To meet U.S. LNG imports of 6.4 Tcf in 2025 as projected by the EIA would
require significant additions to North American import terminal capacity. Along
with planned expansions at the four existing terminals, six to ten new import
terminals would be needed. LNG developers have proposed over 70 new terminals
with a combined annual import capacity exceeding 12 Tcf — far more capacity than
would likely be needed the meet the projections (Appendix).39 These developers
include major multi-national corporations with both the financial resources and the
project experience to develop such facilities. At issue is where these terminals would
be constructed, how they would be integrated into the nation’s existing gas
infrastructure, and how they might be secured against accident or terrorist attack.
Terminal Siting. Choosing acceptable sites for new LNG terminals has
proven controversial. As noted earlier in this report, federal agencies have approved
the siting of five new terminals in the Gulf of Mexico as well as two new Florida
pipelines for proposed terminals in the Bahamas. But many developers have sought
to build terminals nearer to major consuming markets in California and the Northeast
(Figure 4). Near-to-market terminal proposals have struggled for approval due to
community concerns about LNG safety, effects on local commerce, and other
potential negative impacts. LNG terminal opposition is not unlike that experienced
by some other types of industrial and utility facilities. Due to local community
opposition, LNG developers have already withdrawn terminal projects recently
proposed in California, Maine, North Carolina, Florida, and Mexico. Other terminal
37 Abraham, Spencer. U.S. Secretary of Energy. Welcoming remarks at the LNG Ministerial
Summit. Mayflower Hotel. Washington, DC. Dec. 17, 2003.
38 Abraham, Spencer. U.S. Secretary of Energy. Keynote address at the LNG Ministerial
Summit. Mayflower Hotel. Washington, DC. Dec. 18, 2003.
39 This figure Includes several proposed terminals in Canada, Mexico and the Bahamas.

---

CRS-10
proposals in Rhode Island, New York, New Jersey and Canada are facing stiff
community opposition. In Alabama, a state assumed by many to be friendly to LNG
development, community groups have effectively blocked two onshore terminal
proposals and have called for LNG import terminals to be built only offshore.40
In some cases state and local agencies are at odds with federal agencies over
LNG terminal siting approval. For example, the California Public Utilities
Commission (CPUC) has rejected FERC’s assertion of sole jurisdiction over the
siting of an LNG terminal in Long Beach. The CPUC has opened an investigation
into the terminal proposal, has ordered the developer to apply for a separate siting
approval from the state, and is challenging FERC’s assertion that it can preempt state
jurisdiction over the proposal.41 In June, 2004, FERC reasserted its earlier
jurisdictional ruling, prompting a federal court appeal by California regulators. In
December, 2004 Congress included language in H.Rept. 108-792 accompanying P.L.
108-477 affirming FERC’s authority to pre-empt states on LNG terminal siting and
permitting (page 963).42 Eighteen members of Congress have since filed an amicus
brief with the federal court hearing the CPUC case in support of the CPUC’s
position.43 Litigation continues.
40 Editorial. “Move ExxonMobil’s LNG Plant Offshore.” Mobile Register. Nov. 30, 2003.
41 Schmollinger, C. “Aggressive FERC Tangles With States on Jurisdiction Issues.” Natural
Gas Week. May 7, 2004.
42 This language can be found in the joint explanatory statement accompanying the
Consolidated Appropriations Act, 2005. See 150 Cong. Rec. H10,560 (daily ed.Nov. 19,
2004) (Joint Explanatory Statement on H.Rept. 108-792, 108th Cong. 2nd Sess. (2004)).
43 Hon. Barney Frank. “Lawmakers File Brief Opposing LNG Preemption Language.” Press
release. Jan. 1, 2005.

---

CRS-11
Figure 4: U.S. Natural Gas Pipeline Flows and Proposed LNG Terminals
60
61
58
42
63
59
56
41 33
62
32
57
27
49 43
48
54
1
13
25
50
47 30
37 21
38
29
22
51
4
15
17 31
55
16
# Existin
Ex
g
72
71
# Approved
ov
3
67
# Propo
r
se
s d
e
68
46
#
68
69
Ca
C nc
a
ell
nc
e
ell d
e
40 36
26
19 45
2
73
7
73
39
12 10 11 24
20 9 34
18
52
8
6
14
35
14 23
53
23
28
64
44
66
44
65
70
5
Note: Terminal numbers refer to tables in the Appendix.
Sources: Energy Information Administration, FERC, Trade Press

---

CRS-12
In a similar dispute, Delaware’s environmental secretary has blocked the
development of an LNG terminal on the Delaware-New Jersey border ruling that part
of the planned terminal would violate Delaware’s Coastal Zone Act.44 The ruling is
under appeal. In 2004, a Rhode Island state representative (unsuccessfully)
introduced legislation that would have banned LNG tankers from passing through the
Sakonnet River, preventing them from serving proposed LNG terminals at Fall River
and Somerset, MA.45 Also in 2004, the Governor of Alabama helped to block the
development of an onshore LNG terminal in Mobile Bay by calling for “an adequate
independent, individualized, site specific safety study” apart from safety studies
required by FERC under federal siting regulation.46
Developers have proposed terminals near consuming markets to avoid pipeline
bottlenecks and to minimize transportation costs. In 2003, soon after LNG deliveries
to the Cove Point resumed, natural gas for the local Maryland market was priced well
below conventional gas supplies transported by pipeline from the Gulf of Mexico.47
If new terminals are built far from key consumer markets, delivered gas might cost
more than if LNG terminals were built locally.
Local opposition for LNG terminals has been strong in the Northeast, which has
a constrained gas transmission infrastructure. Northeast gas prices are higher than
in other parts of the country. In Maine, for example, the monthly average wholesale
price of gas delivered between October, 2003 and October, 2004 was $8.85/Mcf,
compared to $6.09/Mcf in Louisiana.48 Were the same price differential to hold in
the future, Maine consumers would have to pay $2.76/Mcf, or 45 percent, more for
LNG delivered to Louisiana rather than the Maine coast. Many factors like weather
and pipeline tariffs could significantly change relative prices. Nonetheless, if recent
regional pricing patterns persist, displacing a handful of proposed LNG terminals
from consumer markets to the Gulf of Mexico could cost regional gas consumers
billions of dollars in extra pipeline transportation charges. On the other hand, siting
new terminals in more receptive locations could help bring them into service more
quickly, and could still exert downward pressure on gas prices while alleviating
community safety concerns.
Pipeline Infrastructure. LNG supplies to the United States have been such
a small share of the total market that they have had little discernible influence on the
development of North America’s gas pipeline network. If projections of U.S. LNG
growth prove correct, however, LNG terminals may have more impact on pipeline
infrastructure in the future. As additional LNG import capacity is approved, how
44 Fifield, A. “Del. Hands BP a Setback on Pier.” Philadelphia Enquirer. Feb. 4, 2005.
45 O’Driscoll, M. “LNG: Safety Debate Intensifies, R.I. Law Could Block Mass. Shipments.”
Greenwire. Mar. 29, 2004.
46 Raines, B. “Gov. Riley Demands Studies Before LNG.” Mobile Register. Jan. 15, 2004.
47 Jowdy, M. and Haywood, T. “LNG Imports Undermine Premiums Near US Terminals.”
World Gas Intelligence. Nov. 25, 2003.
48 Energy Information Administration (EIA). “Natural Gas City Gate Price.” website data
series. [http://tonto.eia.doe.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm]. Feb. 8, 2005.

---

CRS-13
new terminals will be physically integrated into the existing pipeline network
becomes a consideration.
LNG terminals may affect pipeline infrastructure in two ways. First, new
terminals and terminal expansions must be connected to the interstate pipeline
network through sufficient “takeaway” pipeline capacity to handle the large volumes
of imported natural gas. Depending upon the size, location and proximity of a new
terminal to existing pipelines, ensuring adequate takeaway capacity may require new
pipeline construction. For example, the owner of the Lake Charles, LA terminal
intends to build a 23-mile pipeline to transport additional gas volume from the
terminal’s planned expansion.49 The owner of the Everett, MA terminal has
predicted that, without significant new pipeline investments, the terminal’s
production capacity could exceed takeaway capacity by 10 times or more in the next
decade due to pipeline demand growth in New England.50 The availability of
pipeline capacity directly affects pipeline transportation costs, so it is an important
consideration in evaluating the economics of LNG versus traditional pipeline
supplies in specific markets.
Second, if gas imported as LNG cannot move freely through interstate pipeline
systems, consumers may not realize the lower prices that result from additional gas
availability. One industry observer remarked, “without more infrastructure, gas may
face the kind of glut plaguing the electric utility industry, with too much generating
capacity and too few connections.”51 For this reason, some LNG developers advocate
building LNG terminals in traditional gas producing regions, where pipeline nodes
are located. According to one industry executive, “it doesn’t make a lot of sense to
build a terminal and then have to build a huge pipeline.”52 Others argue that the most
costly constraints in the gas pipeline network are at the ends of the pipelines, not the
beginnings. Gas is expensive in Boston, for example, because there are few pipelines
supplying the region — a transportation constraint that would not be alleviated by
pumping more gas into pipelines in the Gulf of Mexico. As one senior FERC official
recently remarked, “we can site all the LNG we want in the Gulf but it won’t help
people in New England.”53 It is not clear, therefore, whether adding LNG supplies
to traditional producing regions would be less costly for consumers than building in-
market terminals and adding to regional pipeline capacity.
In addition to requiring sufficient takeaway capacity, LNG terminals likely will
influence pipeline network flows. As Figure 4 shows, major U.S. pipeline systems
49 “FERC gives OK to Second Expansion of Trunkline LNG’s Louisiana Terminal.” Inside
F.E.R.C.’s Gas Market Report. Sept. 24, 2004. p3.
50 “LNG Expansion Requires Adequate Takeaway Capacity and Market Integration.” Foster
Natural Gas Report. Feb. 5, 2004. p15.
51 Foster Natural Gas Report. Feb. 5, 2004. p15
52 “For Sponsors, Stake in Supply is Key to Getting LNG Terminals Built, says ExxonMobil
Head.” Inside F.E.R.C. Feb. 16, 2004. p20.
53 Robinson, M. Federal Energy Regulatory Commission (FERC), Office of Energy Projects.
Remarks at the Senate Energy Committee Natural Gas Conference. Washington, DC. Jan.
24, 2004.

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CRS-14
were designed primarily to move gas from traditional producing regions (e.g., Gulf
Coast, Appalachia, Western Canada) to consuming regions (e.g, Northeast, Midwest).
If most new LNG capacity is built in the Gulf of Mexico, then traditional gas flows
would be maintained. If a number of new terminals are built in consuming regions,
however, they may change historical gas transportation patterns, potentially
displacing traditional production and changing infrastructure constraints. Among
other potential impacts, some analysts have suggested that new LNG terminals will
result in “less market leverage and probably lower cash flows” for some existing
pipelines because new LNG supplies may be able to reach consumer markets by
alternate routes.54 Predicting the overall effects of long term changes in gas flows is
a complex problem, although such changes may have important implications for
current pipeline utilization and for future pipeline investments.
Interchangeability. LNG consists primarily of methane, but it may also
contain significant quantities of other hydrocarbon fuels, such as ethane, propane and
butane. The quantity of these other fuels in LNG affects the overall heat content in
the LNG and varies depending upon its source. In markets outside the United States,
LNG contains more non-methane fuels and, therefore, has a higher heat content than
traditional U.S. natural gas supplies. LNG with a high heat content can cause
problems when imported into the United States because it may damage pipelines and
natural gas-fired equipment (e.g., electric power turbines) which are designed for a
lower heat content. There are a number of potential technical solutions to LNG
interchangeability problems, such as stripping out the non-methane fuels, blending
the LNG with domestic natural gas, and “diluting” the LNG with nitrogen.55 These
solutions may involve significant added expense to LNG processing, however, which
could be reflected in higher natural gas prices. The FERC has been working with
natural gas trade associations to establish appropriate national policies for natural gas
interchangeability and quality, possibly including national standards for LNG
composition.56
Safety and Physical Security. To protect the public from an LNG accident
or terrorist attack, the federal government imposes numerous safety and security
requirements on LNG infrastructure. The nature and level of risk associated with
LNG is the subject of ongoing debate among industry, government agencies,
researchers and local communities.57 Whatever the specific risk levels are
determined to be, they could multiply as the number of LNG terminals and associated
tanker shipments grows. Likewise, the costs associated with mitigating these risks
are also likely to increase. To the extent these costs are not borne by the LNG
54 “Consultant: LNG Will Cut Transportation Values, Put Downward Pressure on Prices.”
Natural Gas Intelligence. Dec. 29, 2003.
55 Rogers, D. “Gas ‘Interchangeability’ and Its Effects On U.S. Import Plans.” Pipeline &
Gas Journal. Aug. 2003. pp21-24.
56 Jura, M. “Industry Still Struggling with Gas Interchangeability Issues.” Natural Gas Week.
Sept. 20, 2004.
57 For further discussion see CRS Report RL32205: Liquefied Natural Gas (LNG) Import
Terminals: Siting, Safety, and Regulation by Paul W. Parfomak and Aaron Flynn. Jan. 28,
2005.

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CRS-15
industry, they may represent an ongoing burden to public agencies such as the Coast
Guard, law enforcement, and emergency response agencies.
Securing tanker shipments against terrorist attacks may be the most significant
public expense associated with LNG. CRS has estimated the public cost of security
for an LNG delivery to the Everett terminal to be on the order of $80,000, excluding
costs incurred by the terminal owner.58 Marine security costs at other LNG terminals
could be lower than for Everett because they are farther from dense populations and
may face fewer vulnerabilities, but could still be on the order of $20,000 to $40,000
per shipment. If LNG imports increase as projected, the number of vessels calling
at LNG terminals serving the United States would increase from 99 (0.17 Tcf) in
2002 to over 3700 (6.40 Tcf) in 2025.59 At current levels of protection, marine
security costs would then be in the range of $74 million to $148 million annually.60
Few, if any, interested parties have suggested that current levels of maritime LNG
security ought to be reduced, at least in the short term. Furthermore, the public costs
of LNG security may decline as federally mandated security systems and plans are
implemented. Nonetheless, the potential increase in security costs from growing U.S.
LNG imports, and the corresponding diversion of Coast Guard and safety agency
resources from other activities have been a concern to policy makers.61 Whether the
costs of security should be assumed by industry may become an issue.
Supply Bottlenecks. Because U.S. LNG terminals process large volumes
of LNG, the potential for one facility to bottleneck supply might not be recognized.
A disruption at a U.S. import terminal (or at an associated supplier’s export terminal)
could effect regional gas availability.
In March, 2004, striking workers at an export terminal in Trinidad stopped all
LNG operations — interrupting shipments from the largest U.S. supplier and the sole
supplier to the Everett terminal. Although the strike ended quickly and U.S. gas
demand at the time was moderate, one gas trader stated that if the strike had occurred
during the heart of winter it might have exacerbated already high Northeast gas
prices.62 Similarly, when LNG shipments to the Everett LNG terminal were
suspended after the terror attacks of September 11, 2001, markets analysts feared
58 CRS Report RL32073. Liquefied Natural Gas (LNG) Infrastructure Security: Background
and Issues for Congress by Paul W. Parfomak. Feb. 2, 2004. p18.
59 Increasing tanker size may reduce the actual number of future shipments, but are assumed
not to reduce associated security costs since the hazard associated with each ship and time
in port would increase proportionately.
60 Note that security costs associated with LNG terminals in Canada, Mexico and the
Bahamas (built primarily to serve U.S. markets) would not be a direct U.S. responsibility,
although such costs might still priced into LNG supplied from those terminals.
61 See, for example: Government Accountability Office (GAO). COAST GUARD: Station
Readiness Improving, but Resource Challenges and Management Concerns Remain.
GAO-05-161. Jan. 2005; Representative Edward Markey at the House Select Committee
on Homeland Security hearing on the FY2005 Department of Homeland Security budget
request. Feb. 12, 2004.
62 Reuters News Service. “U.S. Gas Traders Shrug Off Trinidad LNG Strike.” Mar. 9, 2004.

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CRS-16
shortages of gas for heating and curtailments of gas deliveries to regional power
plants in New England.63
Some industry analysts view the Trinidad and September 11, 2001 events as
new supply risks the United States could face as LNG becomes a larger share of gas
supply. Others view these kinds of events as ordinary supply uncertainties readily
managed in other fuel markets. As one consultant stated,
they are not problems that should make the industry shy away from developing
LNG trade ... they are just problems that should make you consider how you are
going to structure long-term LNG contracts and estimate what kind of premiums
you are going to pay over indigenous pipeline supply.64
The future sensitivity of U.S. natural gas markets to LNG terminal disruptions is
difficult to forecast and will be driven by factors such as supply diversity and pipeline
development. Nonetheless, the concentration of incremental gas supplies among
perhaps a dozen major import facilities may raise new concerns about the security of
U.S. natural gas supply.
Global LNG Market Structure
In his 2003 congressional testimony, Federal Reserve Chairman Alan Greenspan
asserted that increasing LNG import capacity would create “a price-pressure safety
valve” for North American natural gas markets which would be “likely to notably
damp the levels and volatility of American natural gas prices.”65 Basic market
economics suggest that increasing marginal gas supplies from any source would tend
to lower gas prices. But the long-term effectiveness of LNG in moderating gas prices
will be significantly influenced by global LNG supply, the development of an LNG
spot market, and potential market concentration.
Global LNG Supply. The belief that LNG can serve as a “price-pressure
safety valve” by setting a price ceiling on natural gas assumes that sufficient LNG
would be available at that price to satisfy all incremental gas demand. Otherwise,
gas prices would be capped by potentially more costly North American production
alternatives. The question, then, is whether there will be sufficient LNG production
abroad to supply incremental U.S. demand and sufficient global infrastructure to
distribute it. Table 1 summarizes basic characteristics of existing or potential LNG
exporters. As the table shows, 2004 global LNG production capacity currently
operating totaled approximately 6.7 Tcf per year. Table 1 also shows an additional
16.4 Tcf of global capacity proposed for service by 2015, with more proposals likely
in the future. If all these proposed facilities were constructed, total global production
capacity could exceed 23 Tcf annually, exceeding EIA’s projected global LNG
demand of 18 Tcf in 2020.
63 “LNG Ban Could Spell Higher Power Prices.” Gas Daily. Oct. 5, 2001. p5.
64 “Trinidad Strike Settled in Two Days, But Raises Red Flags.” Natural Gas Intelligence.
Mar. 15, 2004. p1.
65 Greenspan, A., Chairman, U.S. Federal Reserve Board. “Natural Gas Supply and Demand
Issues.” Testimony before the House Energy and Commerce Committee. Jun. 10, 2003.

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CRS-17
Global tanker capacity also appears to be keeping up with LNG demand growth.
Current tanker orders will add 111 ships to the current operating fleet of 158,
increasing overall LNG shipping capacity 70% by 2007.66 Based on these figures,
there appears to be sufficient interest among existing and potential exporters to meet
both short-term and long-term global LNG demand projections. It remains to be seen
which of these export projects will be constructed and how they will be integrated
into the global LNG trade.
Table 1: Global Natural Gas Reserves and
LNG Production Capacity
Share of
LNG Production
2004 Gas
World Gas
Capacity (Bcf/yr)
OPEC
Country
Reserves
Reserves
Member?
(Tcf)
Estimated
Projected
(%)
2004
2015
Russia
1,660
26.7
0
3,145
No
Iran
942
15.2
0
1,753
Yes
Qatar
910
14.7
920
2,843
Yes
Saudi Arabia
236
3.8
0
0
Yes
U.A.E.
214
3.4
263
268
Yes
United States
185
3.0
63
409
No
Nigeria
176
2.8
672
3,209
Yes
Algeria
160
2.6
949
1,383
Yes
Venezuela
147
2.4
0
390
Yes
Iraq
110
1.8
0
0
Yes
Indonesia
90
1.5
1,212
2,147
Yes
Australia
90
1.5
443
1767
No
Norway
87
1.4
0
204
No
Malaysia
85
1.4
969
1,105
No
Egypt
62
1.0
0
1,052
No
Libya
46
0.7
29
24
Yes
Oman
33
0.5
356
487
No
Bolivia
29
0.5
0
390
No
Trinidad
26
0.4
487
935
No
Yemen
17
0.3
0
316
No
Brunei
12
0.2
341
321
No
Peru
9
0.1
0
195
No
Angola
2
<0.1
0
390
No
Eq. Guinea
1
<0.1
0
195
No
Others
875
12.9
0
0
No
OPEC Total
3,031
48.9
4,045
12,017
World Total
6,205
100.0
6,704
23,074
Sources: Deutsche Bank, July 22, 2004; Energy Information Administration; BP; Trade press.
66 “LNG Fleet.” LNG OneWorld website. [http://www.lngoneworld.com] Drewry Shipping
Consultants. London, England. Feb. 9, 2005.

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CRS-18
Spot Market Growth. Some gas market analysts believe that a robust short-
term or “spot” market for LNG is essential for U.S. importers to manage price and
supply risk, and to do business cost-effectively. An LNG spot market could allow
for short-term balancing of physical supply and demand. It could also offer greater
LNG price discovery and transparency, benefitting companies negotiating long-term
LNG contracts and potentially serving as a more relevant index for LNG contract
price escalators than traditional petroleum indexes.67 A spot market might also
support financial trading and derivatives, important tools for managing price risk,
especially during periods of volatile prices.68
In recent years, the global LNG market has seen limited, but increasing short-
term trade. Short-term contracts accounted for between 8% and 9% of global LNG
transactions in 2004, up from less than 2% in 1998, and have already enabled some
physical market balancing. In 2003-2004, for example, South Korea purchased 36
spot cargoes of LNG to meet extra residential heating demand during winter.69 In
December, 2003, Indonesia sought four LNG cargoes from rival producers to meet
delivery contracts following production problems at its Bontang plant.70
Unlike petroleum markets where all prices are essentially short-term, analysts
believe LNG trade will stabilize with some mix of long and short-term contracts
since infrastructure costs are so high. No new LNG liquefaction project yet has been
launched without a long term contract. The likely size of an LNG spot market is
difficult to predict, however at least one major exporter expects 30% of global LNG
capacity will ultimately trade on the spot market.71 Coupled with projections of
overall LNG demand growth, a 30% spot market share implies a ten-fold increase in
spot market volumes by 2020. It is an open question, however, whether this volume
of spot trade in LNG will materialize and if it will offer the full range of benefits
realized in comparable commodity markets.
A concern related to LNG spot market development is the potential role of
market intermediaries. In the late 1990’s, independent marketers like Enron and
Dynegy emerged to participate in trading of natural gas, electricity, and other energy
commodities. These market participants increased market liquidity, selling risk
management services to both producers and consumers. Many marketers fell into
bankruptcy, however, following the California electricity crisis in 2001 and
subsequent scandals. It is unclear which entities might step into LNG markets to help
provide the capabilities needed for a fully functioning market.
67 For an alternative view see J.T. Jensen, “The LNG Revolution,” The Energy Journal, vol.
24, no. 2 (2003), p. 14.
68 J. Roeber, “The Development of the UK Natural Gas Spot Market,” The Energy Journal,
vol. 17, no. 2 (996), p. 2.
69 “Asia Lures Natural Gas Cargoes From Trinidad, Nigeria, Boosts Prices,” Africa News,
Oct. 19, 2004.
70 Mike Hurle, “Indonesia Seeks LNG Cargoes to Cover Bontang Shortfall,” World Markets
Analysis, Dec. 23, 2003.
71 Hand, Marcus. “Petronas Head Says 30% of LNG Trade Will be Spot Deals.” Lloyd’s List
Feb. 5, 2004. p2.

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CRS-19
Market Concentration. Some industry analysts believe the future LNG
market may be susceptible to concentration-related inefficiencies. They note that
only a limited number of buyers and sellers can effectively participate in LNG trade
because the capital requirements are so great.72 Many analysts also believe that a
relatively small number of exporting countries are likely to account for the majority
of LNG trade in the foreseeable future.
Based on LNG’s similarity to the world oil trade, some observers are concerned
about the possible emergence of a natural gas export cartel analogous to the
Organization of Petroleum Exporting Countries (OPEC). One analyst remarked:
Might a few countries come to dominate the supply of LNG and adopt policies
harking back to the confrontational OPEC of the 1970’s? An association of some
kind among LNG exporters is likely. Many of them are also oil exporters, and
the desire to compare fiscal terms will be irresistible.73
In March, 2004, at the Fourth Annual Gas Exporting Countries Forum, 15 major
natural gas exporters established an “executive bureau” to develop common policies
and joint initiatives regarding natural gas exports. According to press accounts, some
forum members viewed the bureau as “a major step toward creating an OPEC-like
organization to regulate gas production.”74 Some analysts have also pointed to
apparent efforts by Russian gas company, Gazprom, “to sketch out the basic terms
for broad cooperation in the gas sector between Russia and Iran” the two countries
controlling the largest natural gas reserves in the world.75
The ability of a cartel to play a similar role in gas as OPEC does in oil is
debatable. OPEC member countries currently control over 75% of the world’s
proven oil reserves and approximately 40% of global oil supply.76 By comparison,
OPEC members control approximately 50% of proven world gas reserves and
approximately 52% of global LNG production capacity projected for 2015 (Table 1).
When non-LNG sources are accounted for, however, OPEC countries’ share of
global gas supply would be approximately 5% in 2015. Based on these figures alone,
it is difficult to draw conclusions about the potential market power of an association
of LNG exporters. It is possible, however, that the diversity of LNG suppliers, and
the competitive relationship between LNG and traditional pipeline gas could make
the world LNG market somewhat different than that of oil.
Global Trade and Politics. Continued growth of United States demand in
an integrated global LNG market may affect trading and political relationships with
72 J.T. Jensen, 2003, p. 25. For example, the natural unit of trade, an LNG tanker cargo, is
several hundred times the size of a commodity contract for pipeline natural gas.
73 Daniel Yergin and Stoppard Michael, “The Next Prize,” Foreign Affairs, Nov./Dec. 2003.
74 M. Schmidt, “Former DOE Policy Chief: U.S. Focusing on Importing LNG from Nearest
Locales,” Inside Energy, Apr. 5, 2004, p. 10.
75 “Gazprom’s Iran Strategy,” World Gas Intelligence, Feb. 2, 2005.
76 Organization of Petroleum Exporting Countries (OPEC), “About OPEC,” at
[http://www.opec.org], visited Feb. 10, 2005.

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CRS-20
key market participants. According to one estimate, by 2015 the United States may
be the world’s largest LNG importer, accounting for 22% of global volumes (Figure
5). South Korea, Spain, and the UK will also be importing large quantities of LNG,
and may be joined by developing nations including India and China, seeking greater
imports for rapidly growing economies.
Figure 5: Global LNG Import Market Shares Projected for 2015
Others (8%)
China (3%)
USA (22%)
Taiwan (4%)
France (4%)
Mexico (4%)
India (4%)
UK (7%)
Japan (20%)
Spain (9%)
S. Korea (13%)
Source: Deutsche Bank Securities, Inc. “Global LNG: Exploding the Myths.” July 22. 2004. p2.
In an integrated global LNG market, individual country energy polices may
significantly affect LNG price and availability worldwide. In 2001 and 2002, for
example, after the Japanese government forced Tokyo Electric Power to shut down
over a dozen nuclear plants for safety reasons, Japanese utilities relied more heavily
on fossil fuels for electricity generation. According to the EIA:
the result was a significant increase in Japan’s demand for LNG, so that the
majority of world spot cargoes were delivered to the Japanese market. Japan’s
increased reliance on LNG probably contributed to the reduction in short-term
deliveries of LNG to the United States... 77
Japan’s nuclear energy policies also affected South Korea, which depends on flexible
spot LNG supplies to meet winter heating demand. With LNG supplies in Asia
suddenly scarce, South Korea had to pay a substantial premium to attract spot cargoes
originally destined for Spain.78 In 2004-2005, Spain attracted several LNG spot
77 Energy Information Administration (EIA), International Energy Outlook 2004,
DOE/EIA-0484(2004), Apr. 2004, p. 53.
78 “LNG Supply Shock Would Hit Asia Hard,” Petroleum Intelligence Weekly, Mar.12,
2003.

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CRS-21
cargoes “at the expense of the US” in response to record cold weather and inadequate
hydroelectric power supplies.79
Trade with LNG exporters such as Indonesia, Iran and Nigeria may also raise
geopolitical concerns. According to one analyst, “question remains on the merits of
increasing reliance on imported energy ... if supply sources are from a region
perceived as politically unstable or inhospitable to U.S. interests.”80 In part to
mitigate such risks, the DOE has been encouraging the development of LNG supplies
in South America and West Africa rather than the Middle East. According to the
former DOE Assistant Secretary for Policy and International Affairs, “DOE is trying
to make countries like Equatorial Guinea as attractive as possible to investors while
aiming to limit the countries’ potential political instability through contract and
regulatory reform.”81
LNG trade may also be linked to broader trading and political relationships
among key LNG partners. For example, in the fall of 2004, China’s interest in
securing LNG supplies from Iran “put it in direct conflict with U.S. efforts to force
Iran to renounce its ambitions to become a nuclear weapons state.”82 In an April,
2004 meeting with U.S. Energy Secretary Spencer Abraham, the Prime Minister of
Trinidad reportedly used his country’s status as the largest U.S. LNG supplier to seek
most favored nation status for Trinidad’s energy exports, duty free U.S. access for all
Trinidadian-packaged products, and U.S. aid to offset gas exploration costs.83
It is difficult to predict the nature of trading and political relationships either
among LNG importers, or between specific LNG importing and exporting countries
over a 20-year time frame. Nonetheless, experience suggests that global LNG trade
may introduce new risks and opportunities among trading countries that warrant
consideration in LNG policy debate.
79 M. Jura, “Spiking Spanish Demand Diverts LNG Cargoes Away from US,” The Oil Daily,
Feb. 3, 2005.
80 Frank A. Verrastro, LNG the Growing Alternative, Center for Strategic and International
Studies, Qatar Embassy Policy Series, Washington, DC, Mar. 16, 2004.
81 M. Schmidt, “Former DOE Policy Chief: U.S. Focusing on Importing LNG from Nearest
Locales,” Inside Energy, Apr. 5, 2004, p. 10.
82 I. Bremmer, “Are the U.S. and China on a Collision Course?,” Fortune, Jan. 25, 2005, p.
50.
83 Lucy Hornby, “Trinidad to Expand Role as Top Supplier of US LNG.” Oil Daily, Apr.
21, 2004, p. 4.

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CRS-22
Conclusions
As long as domestic demand outpaces North American natural gas production,
the option of developing LNG import capacity appears economically attractive.
Currently, LNG supplies 3% of U.S. natural gas, but both industry and government
project this figure to rise to as much as 21% by 2025. Such an increase would pose
a number of practical, immediate challenges, such as ensuring adequate production
and import capacity, integrating LNG efficiently into the existing natural gas supply
network, and securing LNG infrastructure against accident or terrorist attack. Public
opposition to LNG-related facilities and new trading relationships in an increasingly
integrated global gas market will also bear upon the expansion of the industry.
As the practical challenges to LNG import expansion are addressed, the policy
discussion turns to the long-term implications of increased LNG imports in the
nation’s energy supply. Intentionally or not, the United States may be starting down
a path of dependency on LNG imports similar to its current dependency on foreign
oil. Such a dependency would represent a major shift in the nation’s energy policy,
and may have far-reaching economic impact. Because U.S. natural gas markets are
regional, major consuming areas such as California and the Northeast might be
particularly affected.
Some energy analysts believe that U.S. dependency on imported LNG is
inevitable; the only uncertainty is how quickly it will occur. Others disagree,
promoting instead familiar alternatives such as greater domestic gas production,
switching to oil or other energy sources, and conservation. Recent measures before
Congress affect LNG imports by providing incentives for domestic gas production
and for new LNG terminal construction. If Congress considers the relative merits of
LNG and other energy supply alternatives, three overarching policy questions may
emerge.
! Is expanding LNG imports the best option for meeting long-term
natural gas demand in the United States?
! What role, if any, should the federal government play in facilitating
the ongoing development of LNG infrastructure in the United States
and abroad?
! How might Congress mitigate the risks of the global LNG trade
within the context of national energy policy?
The answers to these questions may flow from enhanced understanding of the
infrastructure and market structure issues discussed in this report. With incomplete
information and limited policy analysis, LNG imports may look unrealistically
attractive to some, but unreasonably risky to others. The reality probably lies
somewhere in between. It may not be possible to predict the LNG future 20 years
from now, but choices made now can substantially affect that future.

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CRS-23
Appendix: Existing and Proposed LNG Import Terminals in North America
Capacity
Map No.
Location
Name
Developer(s)
Type
Permit Status
(Bcfd)a
1
Everett, MA
Distrigas
Tractebel
Onshore
0.70
Operating
2
Lake Charles, LA
Lake Charles
CMS Energy
Onshore
1.80
Operating
3
Elba Island, GA
Savannah
El Paso
Onshore
0.80
Operating
4
Cove Point, MD
Cove Point
Dominion
Onshore
1.80
Operating
5
Peñuelas, PRb
Peñuelas
EcoElectrica
Onshore
0.19
Operating
6
Gulf of Mexico, LA
Energy Bridge
Excelerate Energy
Offshore
0.50
Under Construction
7
Hackberry, LA
Cameron LNG
Sempra
Onshore
1.50
Approved 9/03
8
Gulf of Mexico, LA
Port Pelican
ChevronTexaco
Offshore
1.60
Approved 11/03
9
Freeport, TX
Freeport
Cheniere Energy
Onshore
1.50
Approved 6/04
10
Sabine Pass, LA
Sabine Pass
Cheniere Energy
Onshore
2.00
Approved 11/04
11
Gulf of Mexico, LA
Gulf Landing
Shell
Offshore
1.00
Approved 2/05
12
Sabine Pass, TX
Golden Pass
Exxon Mobil
Onshore
1.00
Applied 11/03
13
Fall River, MA
Weaver’s Cove
Poten & Partners
Onshore
0.40
Applied 12/03
14
Corpus Christi, TX
Corpus Christi
Cheniere Energy
Onshore
2.00
Applied 12/03
15
Oxnard, CA
Clearwater Port
Crystal / Woodside
Offshore
0.80
Applied 1/04
16
Long Beach, CA
Long Beach
Mitsubishi / Conoco
Onshore
0.70
Applied 1/04
17
Oxnard, CA
Cabrillo Port
BHP Billiton
Offshore
0.80
Applied 1/04
18
Gulf of Mexico, LA
Main Pass
McMoran
Offshore
1.00
Applied 2/04
19
Mobile, AL
Compass Port
ConocoPhillips
Offshore
1.00
Applied 3/04
20
Ingleside, TX
Vista Del Sol
Exxon Mobil
Onshore
1.00
Applied 9/04
21
Providence, RI
Fields Point
KeySpan
Onshore
0.40
Applied 5/04
22
Logan Twp., NJ
Crown Landing
BP
Onshore
1.20
Applied 9/04
23
Ingleside, TX
Corpus Christi
Occidental Petrol.
Onshore
1.00
Applied 11/04
24
Gulf of Mexico, LA
Beacon Port
ConocoPhillips
Offshore
1.50
Applied 2/05
25
Gloucester, MA
Neptune
Distrigas
Offshore
0.4
Applied 2/05

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CRS-24
Capacity
Map No.
Location
Name
Developer(s)
Type
Permit Status
(Bcfd)a
26
Port Arthur, TX
Port Arthur
Sempra
Onshore
1.50
Feasibility study
27
Point Pleasant, ME
Quoddy Bay
Quoddy Bay, LLC
Onshore
TBD
Feasibility study
28
Gulf of Mexico, LA
Vermillion 179
HNG Stor./ CGI
Offshore
1.00
Feasibility study
29
Belmar, NJ
Energy Bridge
Excelerate Energy
Offshore
0.50
Feasibility study
30
Gloucester, MA
TBD
Excelerate Energy
Offshore
0.50
Feasibility study
31
Camp Pendleton, CA
TBD
ChevronTexaco
Onshore
TBD
Feasibility study
32
Coos Bay, OR
Jordan Cove
Energy Projects
Onshore
0.15
Feasibility study
33
St. Helens, OR
Port Westward
Port West. LNG
Onshore
0.70
Feasibility study
34
Galveston, TX
Pelican Island
BP
Onshore
1.50
Feasibility study
35
Port Lavaca, TX
Calhoun LNG
Gulf Coast LNG
Onshore
1.00
Feasibility study
36
Pascagoula, MS
Bayou Casotte
Gulf LNG Energy
Onshore
1.30
Feasibility study
37
Long Is. Sound, NY
Broadwater
TransCanada / Shell
Offshore
1.00
Feasibility study
38
Philadelphia, PA
Port Richmond
Philadelphia Gas
Onshore
0.60
Feasibility study
39
Pascagoula, MS
TBD
ChevronTexaco
Onshore
1.30
Feasibility study
40
Cameron Parish, LA
Creole Trail
Cheniere Energy
Onshore
2.60
Feasibility study
41
Astoria, OR
Skipanon LNG
Calpine
Onshore
1.00
Feasibility study
42
Cherry Point, WA
Cherry Point
Cherry Pt. Energy
Onshore
0.45
Suspended
43
Sears Island, ME
Sears Island
Not disclosed
Onshore
TBD
Suspended
44
Brownsville, TX
Brownsville
Cheniere Energy
Onshore
TBD
Suspended
45
Mobile, AL
Mobile Bay
Exxon Mobil
Onshore
1.00
Suspended
46
Mobile, AL
Pinto Island
Cheniere Energy
Onshore
1.00
Suspended
47
Somerset, MA
Somerset
Somerset LNG
Onshore
0.43
Suspended
48
Gouldsboro, ME
TBD
Cianbro
Onshore
TBD
Cancelled
49
Sears Island, ME
Sears Island
Not disclosed
Onshore
TBD
Cancelled
50
Eureka, CA
Humboldt Bay
Calpine
Onshore
1.00
Cancelled
51
Vallejo, CA
Mare Island
Bechtel / Shell
Onshore
1.30
Cancelled
52
Tampa, FL
Tampa Bay
BP
Onshore
0.55
Cancelled

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CRS-25
Capacity
Map No.
Location
Name
Developer(s)
Type
Permit Status
(Bcfd)a
53
Gulf of Mex., LA
Liberty
HNG Stor./ CGI
Offshore
1.50
Cancelled
54
Harpswell, ME
Fairwinds
Conoco / TCPL
Onshore
0.50
Cancelled
55
Radio Island, NC
Radio Island
El Paso
Onshore
0.25
Cancelled
56
Canada (NS)
Bear Head
Anadarko
Onshore
0.75
Under construction
57
Canada (NB)
Canaport
Irving Oil / Repsol
Onshore
0.55
Approved 8/04
58
Canada (PQ)
Rabaska
Gaz Metro
Onshore
0.65
Feasibility study
59
Canada (PQ)
Gros Cacouna
TransCanada / P-C
Onshore
0.50
Feasibility study
60
Canada (BC)
Kitimat
Galveston LNG
Onshore
0.34
Feasibility study
61
Canada (BC)
TBD
WestPac
Onshore
0.30
Feasibility study
62
Canada (NS)
TBD
Keltic Petrochem.
Onshore
1.00
Feasibility study
63
Canada (NS)
TBD
Statia Terminals
Onshore
TBD
Feasibility study
64
Bahamas
Ocean Express
AES
Onshore
0.84
Pipeline approved
65
Bahamas
Calypso
Tractebel
Onshore
0.83
Pipeline approved
66
Bahamas
Seafarer
El Paso
Onshore
0.75
Applied 2003
67
Mexico (Baja CA)
Costa Azul
Sempra / Shell
Onshore
1.00
Approved 10/04
68
Mexico (Baja CA)
Puerto Coronado
ChevronTexaco
Offshore
0.70
Approved 1/05
69
Mexico (Sonora)
Puerto Libertad
Sonora Pacific LNG
Onshore
TBD
Feasibility Study
70
Mexico (Gulf)
TBD
Tidelands O&G
Offshore
TBD
Feasibility Study
71
Mexico (Baja CA)
Rosarito
TAMMSA / Moss
Offshore
TBD
Feasibility Study
72
Mexico (Baja CA)
Tijuana
Marathon
Onshore
0.75
Cancelled
73
Mexico (Baja, CA)
Rosarito
El Paso / Phillips
Onshore
0.68
Cancelled
Source: Trade press; Company websites
a. May indicate baseload or peak delivery capacity. Includes planned expansions.
b. Terminal supplies dedicated to a gas-fired electric power plant.

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