Issues
In Focus.
Reassessment of Liquefied Natural Gas Supply Potential
Interest in liquefied natural gas (LNG) as a source
for fuel supply in the United States has been rekindled and strengthened
as a result of sustained high natural gas prices, declining costs
throughout the LNG supply chain (production, liquefaction, transportation,
and regasification), and recent regulatory changes (see Legislation
and Regulations). During the winter of 2000-2001a colder
winter than normalnatural gas prices on the domestic spot
market climbed above $10.00 per thousand cubic feet, and the average
wellhead price increased to $6.82 per thousand cubic feet in January
2001. At that time, plans were announced for the reopening of mothballed
LNG terminals in Maryland (Cove Point) and Georgia (Elba Island),
and plans for the construction of additional new facilities were
being discussed.
By July 2001, wellhead natural gas prices had dropped
below $3.50 per thousand cubic feet, where they remained for most
of 2002. Interest persisted in LNG, which generally was thought
to be economical in the price range of $3.50 to $4.00 per thousand
cubic feet, but momentum slowed as investors waited cautiously to
see whether prices would remain below $3.50. In late 2002, average
wellhead prices again began to rise, to $3.59 per thousand cubic
feet in November and $3.84 in December. They have remained well
above $4.00 per thousand cubic feet since then. Average wellhead
prices for the first half of 2003 ranged from a low of $4.47 per
thousand cubic feet in January to a high of $6.69 in March, contributing
to the belief that there has been a fundamental upward shift in
natural gas prices.
LNG imports are expected to constitute an increasing
proportion of U.S. natural gas supply (Figure 17). Total net imports
are projected to supply 21 percent of total U.S. natural gas consumption
in 2010 (5.5 trillion cubic feet) and 23 percent in 2025 (7.2 trillion
cubic feet), compared with recent historical levels of around 15
percent. Nearly all of the increase in net imports, from 3.5 trillion
cubic feet in 2002, is expected to consist of LNG.
LNG imports already have doubled from 2002 to 2003,
based on preliminary estimates that show LNG gross imports at 540
billion cubic feet in 2003, compared with 228 billion cubic feet
in 2002. Strong growth in LNG is expected to continue throughout
the forecast period, with LNGs share of net imports growing
from less than 5 percent in 2002 to 39 percent (2.2 trillion cubic
feet) in 2010 and 66 percent (4.8 trillion cubic feet) in 2025.
In the AEO2004 forecast, four new LNG terminals
are expected to open on the Atlantic and Gulf Coasts between 2007
and 2010. The first new LNG terminal in more than 20 years is projected
to open on the Gulf Coast in 2007. Although the actual sizes of
the new plants will vary, for projection purposes a generic size
of 1 billion cubic feet per day is used in AEO2004 for new
facilities on the Gulf Coast and 250 to 500 million cubic feet per
day elsewhere. One facility, expected to serve Florida, is planned
for construction in the Bahama Islands, with the gas to be transported
through an underwater pipeline to Florida.
Existing U.S. LNG plants are expected to be at, or
close to, full capacity by 2007, importing 1.4 trillion cubic feet
annually, and new plants are projected to import a total of 812
billion cubic feet in 2010. In addition, a new terminal in Baja
California, Mexico, is expected to start moving gas into Southern
California in 2007, with volumes reaching 180 billion cubic feet
by 2008. Additional capacity in Baja California is expected to be
added in 2012, increasing annual deliveries into Southern California
to 370 billion cubic feet per year from 2014 through 2025. Other
new terminals are expected to be constructed in the Mid-Atlantic
and New England regions by 2016, and significant additional capacity
is expected along the Gulf Coast by 2025, including expansions of
existing terminals and construction of new ones. Imports into new
Gulf Coast terminals are projected to total nearly 2.5 trillion
cubic feet in 2025.
It is considerably more expensive to build LNG regasification
plants at new U.S. sites than to expand capacity at existing sites.
In addition, LNG delivered to new sites can be expected to have
higher production and shipping costs if it is obtained from new,
potentially more distant and expensive supply sources. Delays and
regulatory costs are also expected to add to the price of gas for
new facilities. As a result, trigger prices for the
construction of new LNG plants are estimated currently at $3.62
to $4.58 per million Btu, compared with less than $2.87 to $3.15
per million Btu for expansion at existing plants.
With changing market conditions, most forecasters
now expect LNG to become an increasingly important source of incremental
natural gas supply for the United States. As of August 2002, there
were 16 active proposals to construct new LNG regasification terminals
in North America to serve U.S. markets (or partially serve, as in
the case of three proposed terminals in Baja California, Mexico),
with total annual capacity slightly over 5 trillion cubic feet.
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Project |
Owners |
Location |
Start year
|
Capacity added
|
West Coast |
Terminal
GNL Mar Adentro de B.C. |
ChevronTexaco
|
Baja California,
Mexico (offshore) |
2007
|
750
|
Tijuana
Regional Energy Center |
Marathon/Golar
LNG/Grupo GGS |
Baja California,
Mexico |
2006
|
750
|
Sound
Energy Solutions |
Mitsubishi
|
Long Beach,
California |
2007
|
700
|
Terminal
LNG de Baja California |
Shell
|
Baja California,
Mexico |
2007
|
1,000
|
Energia
Costa Azul LNG |
Sempra
Energy |
Baja California,
Mexico |
2007
|
1,000
|
Crystal
|
Crystal
Energy |
Oxnard,
California (offshore) |
2006
|
600
|
Tractebel
Mexico |
Tractebel
|
Lazaro
Cardenas, Mexico |
2007
|
500
|
Cabrillo
Port LNG |
BHP Billiton
|
Oxnard,
California (offshore) |
2008
|
1,500
|
Florida/Bahamas
|
Ocean
Express LNG |
AES
|
Ocean
Cay, Bahamas |
2006
|
850
|
Freeport
|
El Paso
|
Freeport
Grand Island, Bahamas |
2007
|
500
|
Calypso
|
Tractebel
Bahamas LNG |
Freeport
Grand Cayman, Bahamas |
2007
|
832
|
Gulf
Coast |
ExxonMobil
LNG |
ExxonMobil
|
Quintana
Island, Texas |
2007
|
1,000
|
Sabine
Pass/Cheniere |
Cheniere
|
Sabine
Pass, Texas |
2008
|
2,000
|
Port Pelican
|
ChevronTexaco
|
Louisiana
(offshore) |
2007
|
1,600
|
Cameron
LNG |
Sempra
Energy |
Hackberry,
Louisiana |
2007
|
1,500
|
Altamira
|
Shell
|
Altamira,
Mexico |
2004
|
500
|
Corpus
Christi LNG |
Cheniere
Energy |
Corpus
Christi, Texas |
2008
|
2,000
|
ExxonMobil/Sabine
Pass LNG |
ExxonMobil
|
Sabine
Pass, Texas |
2008
|
1,000
|
Liberty
|
HNG Storage/Conversion
Gas |
Cameron,
Louisiana |
2007
|
3,000
|
Main Pass
Energy Hub |
Freeport-McMoRan
Sulphur |
Gulf of
Mexico (offshore) |
2006
|
1,500
|
Gulf Landing
|
Shell
|
West Cameron,
Louisiana (offshore) |
2008-2009
|
1,000
|
Vermilion
179 |
Conversion
Gas Imports |
Louisiana
|
2008
|
1,000
|
Mobile
Bay LNG |
ExxonMobil
|
Mobile
Bay, Alabama |
2008
|
1,000
|
Freeport
LNG |
Freeport,
Cheniere, Contango |
Freeport,
Texas |
2006
|
1,500
|
Energy
Bridge |
El Paso
|
Floating
Dock (offshore) |
2005
|
500
|
East Coast |
Canaport
|
Irving
Oil/Chevron Texaco |
Canaport,
New Brunswick, Canada |
2006
|
500
|
Weaver's
Cove |
Poten
|
Fall River,
Massachusetts |
2007
|
400
|
Access
Northeast Energy |
Access
Northeast Energy |
Bearhead,
Nova Scotia, Canada |
2008
|
500
|
Fairwinds
LNG |
TransCanada,
ConocoPhillips |
Harpswell,
Maine |
2009
|
500
|
Providence
LNG |
Keyspan,
BG LNG Services |
Providence,
Rhode Island |
2005
|
500
|
Crown
Landing |
BP
|
Logan
Township, New Jersey |
2008
|
1,200
|
Somerset
LNG |
Somerset
LNG |
Somerset,
Massachusetts |
2007
|
430
|
|
As of December 1, 2003, there were 32 active proposals
for new terminals (Table 12): 21 in the United States, 4 in Baja
California, Mexico (to serve both Mexico and U.S. markets), 2 in
Mexico, 3 in the Bahamas (to serve U.S. markets), and 2 in Canada
(to serve Canada and possibly also U.S. markets). The increase in
proposed capacity between August 2002 and October 2003 includes
both additional terminals and increases in capacity for many of
those previously proposed. Proposed projects active during the summer
of 2002 were primarily for terminals with a capacity of 1 billion
cubic feet per day or less, whereas 9 of the current proposals are
for terminals with a capacity of 1 to 2 billion cubic feet per day.
If all the U.S. LNG facilities currently being proposed were completed,
they would add more than 15 trillion cubic feet to annual U.S. import
capacity. In addition, two proposed terminals in Mexico to serve
Southern Mexican markets would have the indirect affect of reducing
U.S. natural gas exports to Mexico.
Three proposals to construct terminals in the onshore
Gulf of Mexico have been filed with the U.S. Federal Energy Regulatory
Commission, and one, Cameron LNG (formerly Hackberry), has received
preliminary approval (see Legislation and Regulations).
Two more proposals for the offshore Gulf of Mexico have been filed
with the U.S. Coast Guard. Despite this strong activity, proposals
for new capacity involve significant risk and uncertainty, and not
all are expected to move forward.
The delivery of new LNG supplies to a new U.S. regasification
facility requires the financing, permitting, and construction of
at least four expensive infrastructure components: gas production
and processing facilities in a source country; an LNG liquefaction
plant and export terminal; LNG transport tankers; and the LNG regasification
and import terminal in the destination country. Additional pipeline
capacityeither to the liquefaction plant or away from the
regasification facilitymight also be needed. If any aspect
of the infrastructure chain is delayed by permitting, financing,
or construction problems, the potential profitability of the endeavor
could be significantly diminished.
Delays in the eventual commissioning of a new LNG
supply chain ending in the United States could occur for a number
of reasons:
- Changing circumstances in the U.S. natural gas market
- Changing political conditions or government policies, either
in the United States or abroad
- Labor strikes or other local opposition (for example, Bolivia
recently decided to end its LNG export program because of political
unrest)
- Delays in financing (for example, Perus Camisea LNG project
has been delayed by problems in arranging financing with the Andean
Development Corporation)
- International competition for LNG supplies.
Global developments are also contributing to the
domestic emphasis on LNG, as new liquefaction facilities proliferate
around the world and potential supply sources expand. Until 1995,
almost all U.S. LNG imports were from Algeria. More recently,
shipments have also been received from Nigeria, the United Arab
Emirates, Oman, Qatar, Malaysia, Australia, and Trinidad and Tobago.
Additional sources of supply exist throughout the world where
liquefaction facilities are either being developed or are in the
planning stages.
Current worldwide liquefaction capacity and LNG
consumption are roughly equivalent at slightly over 6 trillion
cubic feet per year, indicating that supply constraints are contributing
to the current underutilization of U.S. regasification capacity.
The equivalency of capacity and consumption is changing, however,
with an additional annual capacity of 2 trillion cubic feet under
construction and scheduled to come on line by 2006 and an additional
8.5 trillion cubic feet of capacity planned to come on line by
2011. Trinidad and Tobago, with current annual capacity of approximately
300 billion cubic feet, has now surpassed Algeria as the primary
source of supply for U.S. markets. With an additional 157 billion
cubic feet scheduled to come on line by 2006 and 570 billion cubic
feet under consideration for development by 2011, Trinidad and
Tobago (located in relative proximity to the U.S.) is an important
player in the future growth of the U.S. LNG market.
As the global market evolves, LNG is becoming an
increasingly important energy source for many countries. A number
of European and Asian nations already rely heavily on LNG. Japan,
in particular, depends on LNG to meet its power generation needs.
As the world market for LNG continues to expand, natural gas is
expected to become more of a global commodity, and the world natural
gas market is expected to affect the U.S. market [47].
An important aspect of globalization is expansion
of the LNG spot market. Internationally, most LNG currently is traded
under long-term contracts. In recent years, however, the short-term
market has played a more significant role, especially in the United
States (Figure 18). Most of the LNG imported at the Everett
terminal in Massachusetts remains under long-term contract at relatively
stable quantities, but short-term deliveries at Lake Charles, Louisiana,
have risen and fallen dramatically over the past few years, primarily
in response to domestic natural gas prices. In 2002, all cargoes
into Lake Charles were delivered under short-term contracts.
Recent developments in Japan and South Korea illustrate
the potential impact of global developments on the U.S. LNG market.
In Japan, the forced closing of more than a dozen nuclear reactors
in 2001 and 2002 because of reporting discrepancies led to greater
reliance on fossil fuels for electricity generation. The result
was a significant increase in Japans demand for LNG, so that
the majority of world spot cargoes were delivered to the Japanese
market. Japans increased reliance on LNG probably contributed
to the reduction in short-term deliveries of LNG to the United States
during the winter of 2001-2002, although low natural gas prices
also played a role. In South Korea, an unusually cold winter in
2002-2003 led to the diversion of many spot cargoes to that country
to meet unusually high demand for heating. The increase in shipments
to South Korea may in part explain the low level of U.S. LNG imports
during the winter of 2002-2003, when natural gas spot prices were
spiking. These examples suggest that an assessment of future U.S.
LNG consumption patterns cannot be based solely on the economics
of the U.S. natural gas market.
In the United States, an important factor in the future
growth of LNG imports is natural gas market prices. The potential
impact of U.S. natural gas prices on LNG imports is illustrated
by two AEO2004 sensitivity cases, the rapid and slow technology
cases (Figure 19). The rapid and slow technology cases are used
to assess the sensitivity of the projections to changes in assumed
rates of progress for oil and natural gas supply technologies. To
create the cases, reference case parameters for the effects of technological
progress on finding rates, drilling activity, lease equipment and
operating costs, and success rates for conventional oil and natural
gas wells were adjusted by plus or minus 50 percent. Parameters
for a number of key exploration and production technologies for
unconventional gas were also adjusted by plus or minus 50 percent,
and key parameters for Canadian supply were also adjusted to simulate
the assumed impacts of rapid and slow oil and gas technology penetration
on Canadian supply potential.
In the projections for 2010, natural gas wellhead
prices range from $3.25 per thousand cubic feet (2002 dollars) in
the rapid technology case to $3.58 in the slow technology case;
and in the 2025 projections, the prices range from $3.80 in the
rapid technology case to $5.10 in the slow technology case. The
volume of LNG imports across the rapid and slow technology cases
varies from 1.6 trillion cubic feet to 2.3 trillion cubic feet,
respectively, in 2010 and from 3.8 to 5.5 trillion cubic feet in
2025, compared with 0.2 trillion cubic feet in 2002.
Reassessment of Canadian Natural Gas Supply Potential
Until recently, Canada was expected to remain the
primary source of natural gas imports for the United States through
2025, as projected in AEO2003; however, the AEO2004
reference case projects that net imports of LNG will exceed net
imports from Canada by 2015 (Figure 20). The primary reason for
the change in the AEO2004 forecast is a significant downward
reassessment by the Canadian National Energy Board (NEB) of expected
natural gas production in Canada. Both the NEB and the NPC have
revised their earlier estimates of total Canadian natural gas production
[48].
In 1999, NEB estimated total production in Canada
in a range of 8.1 to 9.0 trillion cubic feet in 2015 and 7.7 to
9.9 trillion cubic feet in 2025. In contrast, NEBs 2003
estimates show 5.9 to 7.1 trillion cubic feet in 2015 and 4.3
to 6.1 trillion cubic feet in 2025. NPCs 1999 estimate for
Canadian production in 2015 was 8.2 trillion cubic feet (no estimate
was given for 2025). In 2003, NPC estimated a range of 6.4 to
7.0 trillion cubic feet for 2015 and 5.8 to 6.9 trillion cubic
feet for 2025.
Other reasons are declining natural gas production
in the province of Alberta, which accounts for more than 75 percent
of Canadas natural gas production, and increasing use of
natural gas for oil sands production. In its most recent annual
reserve report, the Alberta Energy and Utilities Board expects
gas production in the province to decline at an average rate of
2 percent per year between 2003 and 2012, while its oil sands
production could triple. Because natural gas is one of the fuels
used in producing oil sands (see below, Natural Gas Consumption
in Canadian Oil Sands Production), such a dramatic increase
could divert significant amounts of gas from the U.S. import market.
Additional factors that could contribute to a decline in Canadian
gas exports include higher projections for domestic natural gas
demand in Canada and recent disappointments in Canadian drilling
results, including smaller discoveries with lower initial production
rates and faster decline rates.
Two recent and significant drilling disappointments occurred
in northeastern British Columbias Ladyfern field and the
Scotian Shelf Deep Panuke field. Production from the Ladyfern
field, heralded as Canadas largest find in 15 years, peaked
at 700 million cubic feet per day in 2002 and is declining rapidly.
Current production is about 300 million cubic feet per day, and
many expect the field to be depleted by the end of 2004. In February
2003, EnCana, initially highly optimistic about the Deep Panuke
field, requested that the regulatory approval process for developing
the field be placed on hold while it reassesses the economics
of development.
The AEO2004 forecast expects the decline
in Canadian imports to be mitigated partially by the construction
of a pipeline to move MacKenzie Delta gas into Alberta. Initial
flows from the pipeline are expected in 2009, with annual throughput
reaching approximately 675 billion cubic feet in 2012 and remaining
at that level through 2025.
.
Notes and Sources
Released: January 2004
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