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OCR for page 49
4
Meeting U.S. Natural Gas Demand
America's appetite for natural gas is growing. As discussed in
Chapter 2, current estimates suggest average growth in U.S. do-
mestic demand of 2 percent per annum, approaching 30 Tcf/year
by the middle of the next decade (EIA, 2003a). Given recent examples of
extreme price and storage volume volatility, the workshop discussion fo-
cused on how the United States could secure stable supplies of natural
gas to meet domestic demand. The committee and workshop participants
discussed the role of and interplay among access, technology, and com-
petitive market issues in securing new supplies of natural gas through
both internal and external sources. U.S. energy policies and world market
price fluctuations will drive the relative mix of internal and external sup-
plies to meet demand.
U.S. PRODUCTION AND STORAGE TRENDS
The committee and workshop participants discussed U.S. natural gas
production trends, storage trends, and storage variability. These discus-
sions are summarized below.
In the past decade, daily natural gas production in the United States
grew from about 40 Bcf/day in the early 1990s to about 48 Bcf/day in
1997 (see Figure 4.1~. Production trends from 1997 through 2002 re-
mained relatively flat despite a doubling in the gas rig count from 1999
to 2001 (Naresh Kumar, Growth Oil and Gas, personal communication,
2003~.
Peak production rates for individual gas wells increased by more than
49
OCR for page 50
50
40
30
m
2n
U.S. NATURAL GAS DEMAND, SUPPLY, AND TECHNOLOGY
60
50
Gas Rigs ~ ~ i
Pr ojection@?
800 Rigs
O' . .. . . .. . . . .
90 91 92 93 94 95 96 97 98 99 00 01
...~c
... 1
. , , O
02 03 04 05 06
~2006 ~2002 1~11998 ~1994 ~ 1990
~ 2005 ~ 2001 ~1 1997 113 1993 I2l <1990
1~12004 ~ 2000 1~1 1996 ~ 1992
~ 2003 1~ 1999 1~1 1995 [11 1991
-1100
-1000
. ~ 900
~ 800
700
600
~ 500 an
~ 400
300
~ 200
-100
FIGURE 4.1 U.S. daily wet natural gas production from gas wells by year of
production start for the period 1990 to 2006. SOURCE: Compiled by Anadarko
Petroleum Corporation, 2003. Data are from IHS Energy (2003) and EIA (2003a).
1 ,400
1 ,200
1 ,000
800
600
400
200
o
_ Peak Production
~ |Decline 1 2 Mo |
— ~~r[_<
Estimate
~0
1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001
Year of Production Start
70%
65%
60%
55%
50%
45% 'A
_.
40% ~0
35%
30%
25%
20%
FIGURE 4.2 Average peak total U.S. natural gas production and first-year decline
per well by year of production start for the period 1991 to 2001. SOURCE: Anadarko
Petroleum Corporation, 2003. Data are from IHS Energy (2003) and EIA (2003a).
OCR for page 51
MEETING U.S. NATURAL GAS DEMAND
51
50 percent from 1991 to 1997 (see Figure 4.2), largely as a result of im-
proved drilling and completion practices. Since 1997, average initial pro-
duction rates leveled off and even showed signs of decline in 2001 and
2002. From 1991 to 2001, first-year decline rates for gas wells dramatically
increased from about 25 percent to over 50 percent, while per-well re-
serves, other than for coalbed methane wells in the Powder River Basin,
remained relatively flat (see Figure 4.3~.
Ever-increasing decline rates are apparent in a recent Texas study of
all gas completions in a 53-county area (Malt Simmons, Simmons and
Company International, personal communication, 2003~. In that study,
gas wells completed in 2002 comprised 32 percent of the total 7.8 Bcf/day
production for lanuary 2003, while all 2001 vintage wells combined ac-
counted for a mere 5 percent of total production (having already declined
by 68 percent).
The Gulf of Mexico offshore area currently contributes 5+ Tcf/year,
or about 25 percent of the total U.S. domestic natural gas production
(Richie Baud, Minerals Management Service, personal communication,
2003~. Deepwater and deep-shelf gas exploration activities are expected
to bring new production volumes on-stream in the coming years (up to 1
Tcf/year). However, the Minerals Management Service projects flat over-
all production through 2006 from the Gulf of Mexico offshore area due to
offsetting steep decline rates on the base shelf production.
Overall, near-term projections for U.S. gas production indicate that,
even with a healthy rig count of about 800 rigs, production is expected to
gradually decline through 2006 (see Figure 4.1~. The EIA shows a more
optimistic long-term production growth profile through 2025 (see Figure
2.6), though real growth is indicated only from onshore unconventional
sources (see Figure 4.4) (Mary Hutzler, EIA, personal communication,
2003~.
In any case, current U.S. production trends appear to be relatively
stable. However, the seasonal cyclicity of demand was clearly demon-
strated in the past 6 months when record-high storage volumes in Octo-
ber 2002 (over 3 Tcf) were drawn down to record lows (less than 700 Bcf)
by March 2003 (see Figure 4.5~. This extreme storage volatility can be at-
tributed to an imbalance in supply and demand and to the interplay be-
tween factors such as wellhead price, weather, imports, domestic rig ac-
tivity, deliverability of new wells, and availability and cost of external
supplies (i.e., pipeline and LNG-sourced). These dynamics further em-
phasize the need to secure reliable future supplies of natural gas, not only
to satisfy projected average U.S. demand growth (2 percent per annum)
but also to fill short-term "gaps" during extreme demand cycles. Reliable
supplies will require improved transportation networks and improved
storage capacity (Colleen Sen, Gas Technology Institute, personal com-
munication, 2003~.
OCR for page 52
52
in
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OCR for page 53
MEETING U.S. NATURAL GAS DEMAND
12
8
53
History
a
. _
c'
o
In
cot
~ ~ 6
go
2
Projection
10
§~ ~m (= ?= S~ $= §~ c~ Im 9
>~ I~ §~ i~ &~ $~ {~ (~ 8~ )~ i~ 9~ 8~ ;~ $~ 8~ ;~ >
O- 1 1 —
1990 1995 2000 2005 2010 2015 2020 2025
Year
Onshore Unconventional ~ <~ ~~ Alaska
Nonassociated
Onshore Conventional
Nonassociated
Offshore
----- Associated/Dissolved
FIGURE 4.4 U.S. dry natural gas production in trillion cubic feet for the period
1990 to 2025. SOURCE: EIA (2003a, p. 76~.
U.S. SOURCES OF NATURAL GAS
The committee and workshop participants discussed several critical
factors that influence projected supplies of natural gas from U.S. sources:
· access to remaining resource areas and the regulatory environment
in "leasable" areas:
· technological innovations enabling recognition of new resources
and/or making new resources economically recoverable, including re-
search and development funding;
· available workforce, including graduate degree trends; and
· economic incentives designed to accelerate investment in domestic
natural gas projects.
OCR for page 54
54
~C'
m
U.S. NATURAL GAS DEMAND, SUPPLY, AND TECHNOLOGY
3500 -
3000 -
2500 -
2000 -
1 500 -
1 000
500
o
.~\~3 Dog
FIGURE 4.5 U.S. natural gas storage capacity for the period January 2001 to
March 2003. SOURCE: Greg Stringham, Canadian Association of Petroleum Pro-
ducers, personal communication, 2003.
Access and Regulatory Issues
As discussed at the workshop, access to remaining resource areas rich
in natural gas in the United States is currently constrained by areas wholly
or partially off-limits to leasing, including the offshore East Coast, off-
shore West Coast, portions of the offshore eastern Gulf of Mexico (includ-
ing offshore Florida), portions of the onshore Rocky Mountains and west-
ern states, and portions of offshore and onshore Alaska (including the
Alaska National Wildlife Refuge and portions of the National Petroleum
Reserve Alaska). Some workshop participants believe that these areas con-
tain significant remaining oil and gas resources that could be explored
and developed using modern technologies. For the lower 48 federal outer
continental shelf alone, the Minerals Management Service estimates the
remaining conventionally recoverable natural gas resource at about 63
Tcf for the East Coast, West Coast and eastern Gulf of Mexico areas com-
bined (see Figure 4.6~. This resource estimate equates to about a 3-year
supply of total U.S. natural gas consumption, at current annual rates.
Workshop participants also discussed the impact of operational and
regulatory restrictions on the timing and economics of natural gas re-
sources in "leasable" areas. In the Rocky Mountains, full-cycle explora-
tion to first production on federal leases can take 7 years or more because
of the time required to obtain permits, seasonal and wildlife restrictions
OCR for page 55
MEETING U.S. NATURAL GAS DEMAND
55
182
OF
101
CF
28
TCF
.- ......
14
TCF
FIGURE 4.6 Remaining economic gas resources at 53.52/Mcf in the federal outer
continental shelf (includes discovered remaining reserves and mean undiscov-
ered economically recoverable resources). SOURCE: Richie Baud, Minerals Man-
agement Service, personal communication, 2003. Data are from Lore et al. (2001),
Sherwood and Craig (2001), and Sorensen et al. (2000~.
(e.g., operating "windows" of 2 to 4 months/year), and ensuing environ-
mental impact studies and regulatory approvals (see Figure 4.7~. The Na-
tional Petroleum Council (2001) estimates that 137 Tcf, or about 40 per-
cent of the remaining gas resource in the Rocky Mountains, is on federal
lands currently closed to exploration or under restrictive provisions. Simi-
lar operational and regulatory challenges exist in Canada, where federal
and provincial reforms are under way to create a more efficient regula-
tory "road map" (Greg Stringham, Canadian Association of Petroleum
Producers, personal communication, 2003~.
Technology
Technology is another critical factor discussed at the workshop that
influences projected supplies of natural gas from U.S. sources. Technol-
ogy has consistently had a significant positive influence on both techni-
cally and economically recoverable resource estimates. An historic com-
pilation of natural gas resource estimates for the lower 48 states indicates
that both public- and private-sector estimates ramped up considerably in
the l990s (see Figure 4.8~. This three- to four-fold increase is largely attrib-
utable to previously underestimated resources from unconventional res-
ervoirs, such as tight sands, basin-centered gas, shale gas, and coalbed
OCR for page 56
56
U.S. NATURAL GAS DEMAND, SUPPLY, AND TECHNOLOGY
FIGURE 4.7 Natural gas resource development timeline for the Rocky Moun-
tains. SOURCE: James Emme, Anadarko Petroleum Corporation, personal com-
munication, 2003.
2200 -
2000 -
1 800 -
1 600 -
1400 -
u) -
`~ 1200-
't 1 000 -
z 800-
600 -
400 -
200 -
o
~ USGS
GRI {a 7
E'
Estimates adjusted for production since
date of estimate
USGS
~ HEFNER
PACK ~ PGC
PGC. PGC ~ PGC
· EIA {I
GRI ~ _
~ GROW
AAP~ ~ ENRON JO ~ {1~ DOI
~ NRC, ~ NPC
Gal ~ IRON ~ PGC
TREND LINE DOE. '~ PGC~ PGC
\ ~ENRON
PGC ~~. PGC
PGC a$'D icy;
~ USGS_
MOB L NRC EXXON SHELL
HUBBERT~ ~ SHELL ~ H UBBERT ~
SMITH &
Ll DSKY
1975 1980 1985
Year
1990 1995 2000
FIGURE 4.S Estimates of remaining natural gas reserves in the lower 48 states in
trillion cubic feet for the period 1970 to 2000. SOURCE: Kumar (2001~.
OCR for page 57
MEETING U.S. NATURAL GAS DEMAND
15-
12-
9-
O.
57
~ n
..........................................
l
...............................
' ~
B..........................................
l .
2001-2020 2001-2025
Slow oil and gas technology
2001-2020 2001-2025
2001-2020 2001-2025
Reference Rapid oil and gas technology
~ Alaska
[IIII1 LNG
~ Mexico and Canada
Nonassociated Unconventional
Other
FIGURE 4.9 Major sources of incremental natural gas supply in three cases, 2001
to 2020 and 2001 to 2025. The first case is slow oil and gas technology growth. The
second case is the reference case. The third case is rapid oil and gas technology
growth. Volume is in trillion cubic feet. SOURCE: Mary Hutzler, EIA, personal
communication, 2003. Data are from EIA (2003a).
methane. The timing of these increased estimates coincides with wide-
spread development of unconventional reservoirs using new or improved
drilling and completion technologies necessary for economic recoveries.
The EIA has modeled three scenarios of a combination of supply
sources to meet future U.S. natural gas demand over the next 17 to 22 years
(see Figure 4.9~. By 2025 low- versus high-technology tracks could influence
annual gas demand by 1.8 Tcf and wellhead price by $0.84/Mcf (EIA, 2003a)
(see Figure 2.10~. Rapid technological innovations favor the growth of un-
conventional sources at the expense of pipeline or LNG imports.
Technological improvements impact all facets of exploration and pro-
duction activities, including but not limited to seismic acquisition, pro-
cessing and interpretation, drilling and completion techniques, reservoir
characterization, and basin modeling. Advances in computer power due
to parallel processing have resulted in dramatically increased resolution
OCR for page 58
58
U.S. NATURAL GAS DEMAND, SUPPLY, AND TECHNOLOGY
of three-dimensional seismic data acquisition (i.e., fold and frequency con-
tent), processing (e.g., wave equation migration algorithms), and imaging
and interpretation software (lames Emme, Anadarko Petroleum Corpora-
tion, personal communication, 2003~. Improved predrill seismic data ob-
tained at ever-decreasing costs will continue to impact exploration effi-
ciency, especially in difficult-to-image plays (e.g., the Gulf of Mexico
subsalt).
Workshop participants noted that recent examples of important drill-
~ng and completion technology breakthroughs exist in virtually all U.S.
Operational areas, including onshore (unconventional reservoirs), offshore
deepwater, deep-shelf, and subsalt settings and in the Arctic. A few of
these are presented below.
Bossier Sands, Onshore East Texas and North Louisiana
Since 1996, significant new gas reserves have been discovered in the
East Texas and North Louisiana salt basins. furassic-aged Bossier sands
are tight, overpressured unconventional reservoirs that, prior to 1996,
were considered a drilling hazard en route to deeper objectives and as
such were rarely completed (lames Emme, Anadarko Petroleum Corpo-
ration, personal communication, 2003~. Lower costs and higher well
productivities were subsequently achieved through a combination of (1)
25 to 40 percent improved drilling efficiencies (e.g., using top-drive rigs,
poly-diamond carbon bits, mud motors); (2) lower-cost and higher-pro-
ductivity fracture stimulations (e.g., staged, high-pressure, limited-entry
fracture stimulations and use of coiled tubing); and (3) improved cycle
time and decreased down time (e.g., use of remote monitoring) (lames
Emme, Anadarko Petroleum Corporation, personal communication,
2003~. Future improvements are anticipated with the application of new,
deep, and hostile environment drilling technologies as well as expand-
able liners (e.g., slim-hole concepts).
Current industry estimates of economically recoverable discovered
reserves for the Bossier are at least 4 to 5 Tcf, and current production rates
from Bossier sands exceed 600 Mcf/day (lames Emme, Anadarko Petro-
leum Corporation, personal communication, 2003~. USGS resource esti-
mates for 1995 did not recognize Bossier sands in the assessment.
Nakika and Canyon Express Developments, Offshore Eastern
Gulf of Mexico
The Nakika and Canyon Express developments in the eastern Gulf of
Mexico illustrate how improved deepwater subsea technologies have
linked relatively small discoveries to economically viable projects. The
OCR for page 59
MEETING U.S. NATURAL GAS DEMAND
59
Nakika development links five independent oil and gas fields in water
depths of 5,800 to 7,000 feet. Subsea completions will tie back to a central,
permanently moored floating production facility scheduled for start-up
by the end of 2003 (with peak rate capacity of 425 Mcf/day and 110 thou-
sand barrels of oil per day). A sixth field, Coloumb, in water depths of
approximately 7,600 feet, will be tied back 22 miles to the host facility by
about mid-2004. Ultimate recoverable reserves for the six-field complex
are over 300 million barrels of oil equivalent (or 300 Bcf equivalent per
field) (Luyties, 2003~.
North of Nakika in the Mississippi and Desoto Canyon areas, the Can-
yon Express pipeline system is currently the world's deepest producing
development (500 million cubic feet per day [MMcf/d] capacity, on line
since September 2002), linking three separate gas fields totaling 900 Bcf
equivalent recoverable (300 Bcf equivalent per field) (see http://
www.gomr.mms.gov/homepg/offshore/canyon/). One of the fields, Aconcagua,
holds the world's water depth production record at 7,210 feet and was on
line just 40 months after the initial discovery well was drilled in April
1999.
Enabling technologies for these projects include subsea SMART well
completions with commingled multiple reservoirs, use of multiphase flow
meters and flow assurance systems (e.g., pipe-in-pipe, methanol cycling
for hydrate inhibition), and modern floating production facilities. En-
hanced capabilities, lower costs, and improved cycle times now allow
fields as small as 250 Bcf to 300 Bcf to be economically developed. Mini-
mum reserve thresholds will likely continue to drop over time, signifi-
cantly increasing estimates of economically recoverable deepwater re-
sources (lames Emme, Anadarko Petroleum Corporation, personal
communication, 2003~.
Alpine Field and Arctic Platform, North Slope of Alaska
The Alpine field, located on the Colville Delta on the North Slope of
Alaska, is the largest onshore discovery in more than a decade (430 mil-
lion barrels of recoverable oil). Using modern long-reach horizontal drill-
ing (up to 3+ miles), the field is currently producing about 100 million
barrels of oil per day from surface facilities totaling only about 100 acres
(even though the areal extent of the field in the subsurface is about 40,000
acres). Effective utilization of horizontal drilling techniques illustrates
how acceptable low-impact development schemes can work for future oil
and gas developments in sensitive arctic environments (lames Emme,
Anadarko Petroleum Corporation, personal communication, 2003~.
Separately, on the North Slope during the winter of 2002 to 2003, a
new drilling concept called the Arctic Platform was utilized as part of a
OCR for page 66
66
=
=
o ~ ~ ~ ~ ~ ~ ~
. . . . . . . .
_ o o o o o o o
(PO°a) Coda ON]
_
^
1 1 1 _
W _ o
_ _ _
~ o
<
. ~ I
I
~ :
I
I
1
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1
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~ ~ 1
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w
o
(Pang) sandal GU0Gd!8 1GN
. .
U
o
.S
.1
.~
OCR for page 67
MEETING U.S. NATURAL GAS DEMAND
14
12
10 -
8
67
Growth in Alaskan Production
Growth in Net LNG Imports
Growth in Net PiDeline ImDorts
6_
4_
2
18%
16%
Growth in L48 Conventional
Production*
10%
2000 2005 2010 2015 2020 2025
* Includes supplemental supplies
Year
FIGURE 4.17 Sources of incremental natural gas supply for the period 2000 to
2025 in trillion cubic feet. The data include supplemental supplies. SOURCE: Mary
Hutzler, EIA, personal communication, 2003. Data are from EIA (2003a).
The EIA (2003a) projects that by 2025 net LNG and pipeline imports
(including Alaska) will account for more than 6 Tcf/year, or 53 percent, of
new incremental gas supplies above the current base (4 Tcf/year) (see
Figure 4.17~. The same study indicates that Mexico will be a net gas im-
porter from the United States until 2020, while relatively steady U.S. im-
port growth will occur from LNG and Canadian pipeline sources through-
out the period (see Figure 4.18~.
Canada
Canada's ability to grow its domestic natural gas production will
drive its role in supplying U.S. demand. Canada's pipeline network is
well positioned to supply U.S. markets through various northern routes
(see Figure 4.19~. Canada's immediate production potential is tied to per-
formance in the Western Canada Sedimentary Basin. Future natural gas
production growth depends on accessing unconventional reservoirs, such
as coalbed methane, in the Western Canada Sedimentary Basin and con-
ventional resources in the Mackenzie Delta and offshore East Coast (Greg
Stringham, Canadian Association of Petroleum Producers, personal com-
munication, 2003~.
In the past decade, Canada has grown Western Canada Sedimentary
OCR for page 68
68
5
3
6 -
A _
2 -
O -
U.S. NATURAL GAS DEMAND, SUPPLY, AND TECHNOLOGY
History
/
/ Further
Planned expansion at
Projection
Canada
Flows from MacKenzie Delta begin
Flows from new facilities begin
expansion at existing facilities begins
. existing facilities
.
Liquefied
Natural Gas
3 Flows from Baja LNG begin Mexico
...........
1C
90 1995 2000
Year
2015 2020 2025
FIGURE 4.18 Net U.S. natural gas imports for the period 1990 to 2025 in trillion
cubic feet per year. SOURCE: Mary Hutzler, EIA, personal communication, 2003.
Data are from EIA (2003a).
Basin natural gas production from 10 to 12 Bcf/day to more than 17 Bcf/
day (see Figure 4.20~. Improving netback (the net price to producers after
treatment and transport charges), gas prices, and infrastructure (e.g., Alli-
ance pipeline) were key to this growth. Since 2001, however, Canadian
natural gas production has been flat despite significant new discoveries
(e.g., Ladyfern Field) (Greg Stringham, Canadian Association of Petro-
leum Producers, personal communication, 2003~.
The Canadian National Energy Board estimates of Canada's total re-
maining natural gas resource range from 235 to 462 Tcf, with significant
contributions from the Western Canada Sedimentary Basin, coalbed meth-
ane, Mackenzie Delta and the East Coast (see Figure 3.8~. USGS estimates
for the Western Canada Sedimentary Basin (16 Tcf) are an order of magni-
tude less than National Energy Board estimates (176 Tcf), suggesting huge
disparities in the methodologies used (see Figure 3.19) (USGS, 2000~. The
USGS's estimates for the basin would imply an undiscovered reserve vol-
ume equivalent to only about a 2.5-year supply based on current produc-
tion rates.
Future natural gas production from all Canadian sources is expected to
grow incrementally about 1 Tcf/year by 2010 and then, depending on tech-
nology and environmental drivers, either decline or grow more gradually
until 2020 to 1.5 Tcf/year above the current base (see Figures 4.21 and 4.22~.
Rapid technological advances and environmental preferences for natural
gas might favor development of eastern Canada offshore resources and
coalbed methane growth. Alternatively, slower technology (the supply
OCR for page 69
MEETING U.S. NATURAL GAS DEMAND
69
. ~
Algonquin
Noncontinental
FIGURE 4.19 Canadian and U.S. natural gas pipelines. SOURCE: Greg Stringham,
Canadian Association of Petroleum Producers, personal communication, 2003.
18 -
16
14
12
10-
~c'
m 8-
6
4-
2-
O, , r , I I I , , r
5~ 5~ 5~ 5~ 5~ 5~' 5~' 5~' ~~' ~~' As, En,
Year
· 2001
2000
1999
1998
1997
1996
~ 1995
ED 1994
13 1993
1~ 1992
m 1991
1990
m pre90
~ Solution
FIGURE 4.20 Western Canada Sedimentary Basin marketable gas production
grouped by connection year for the period January 1990 to January 2001. SOURCE:
Greg Stringham, Canadian Association of Petroleum Producers, personal com-
munication, 2003. Data are from Canadian National Energy Board (2002~.
OCR for page 70
70
24000,
20000-
1 6000-
1 2000-
8000-
4000 -
U.S. NATURAL GAS DEMAND, SUPPLY, AND TECHNOLOGY
O-
2001 2004 2007 2010 2013 2016 2019 2022 2025
FIGURE 4.21 Canada's deliverable supply outlook by resource category for the
supply push scenario. SOURCE: Greg Stringham, Canadian Association of Petro-
leum Producers, personal communication, 2003. Data are from the Canadian Na-
tional Energy Board (2003~.
24000-
20000~
1 60004
1 2000g
80004
40004
~ - - ..............
Eastern Canada
O ~
2001 2004 2007 2010 2013 2016 2019 2022 2025
FIGURE 4.22 Canada's deliverable supply outlook by resource category for the
rapid technological advances scenario. SOURCE: Greg Stringham, Canadian As-
sociation of Petroleum Producers, personal communication, 2003. Data are from
the Canadian National Energy Board (2003~.
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MEETING U.S. NATURAL GAS DEMAND
71
push scenario) would favor early development of the MacKenzie Delta gas
pipeline. The EIA's 2003 estimates of U.S. imports from Canada indicate
incremental growth of 1.5 Tcf/year by 2025 (see Figure 4.17), which re-
quires virtually all of the new (incremental) volumes in the Canadian As-
sociation of Petroleum Producers' most optimistic scenario.
The Canadian Association of Petroleum Producers' estimates of the
first year of production for the Mackenzie Delta pipeline range from 2008
to 2011 (Greg Stringham, Canadian Association of Petroleum Producers,
personal communication, 2003), while the EIA (2003a) indicates start-up
by 2016. In either case, about half of the anticipated production of about 1
bcf/day could be consumed internally to fuel Canada's expanding heavy
oil development (see Chapter 2~.
As in the United States, Canada's challenges to grow its natural gas
production will depend on access to resource, regulatory, and fiscal re-
gimes and the pace of technological improvements.
Alaska Pipeline
The timing of a natural gas pipeline from the North Slope of Alaska
linking the Canadian infrastructure with that of the lower 48 states will
have a significant impact on North American markets. Thirty-five trillion
cubic feet of discovered resource exists, largely in the Prudhoe Bay gas
cap and Pt. Thompson Field (USGS, 1998~. The USGS estimates that an-
other 63 Tcf of remaining undiscovered resource exists in the onshore
North Slope (excluding the Alaska National Wildlife Refuge, which would
add an estimated 4 Tcf).
A North Slope gas pipeline capable of moving 4 Bcf/day (expandable
to 6+ Bcf/day) to Alberta would require an initial nominal capital invest-
ment of $10 billion to $12 billion (National Petroleum Council, 2001~. Esti-
mates of the first year production range from as early as 2010 to as late as
2020+ (EIA, 2003a).
The National Petroleum Council (2001) suggests that stable U.S. natu-
ral gas prices of $3.50/Mcf for 3 years or more will be required to eco-
nomically justify pipeline construction. Stakeholders in Prudhoe Bay's gas
reserves are currently seeking federal loan guarantees for up to 80 percent
of the pipeline's costs as well as a wellhead tax credit of up to $0.52/Mcf,
depending on netback prices (which guarantees minimum returns of
$1.82/Mcf at the wellhead). Earlier legislative discussions included a pos-
sible $3.25/Mcf gas floor price guarantee to ensure economic returns for
the producer group James Emme, Anadarko Petroleum Corporation, per-
sonal communication, 2003~.
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72
U.S. NATURAL GAS DEMAND, SUPPLY, AND TECHNOLOGY
Liquefied Natural Gas
LNG could potentially satisfy U.S. demand not met by other sources
of North American supply. Immense volumes of proven natural gas re-
serves exist worldwide, on the order of 5,501 Tcf (See, 2003~. Much of this
gas is "stranded" without current access to LNG export facilities (e.g.,
Russia). More than 5 Tcf was transported as LNG in 2001, led by Indone-
sia, Algeria, Malaysia, and Qatar (see Table 3.2~. LNG world trade has
grown since the early 1970s by about 6.4 percent/year and accounts for
about 21 percent of all natural gas traded internationally, largely serving
Asian and European markets (see Figure 3.12~. Continued growth is an-
ticipated with new worldwide liquifaction capacity of 6 Bcf/day currently
under construction (See, 2003~.
LNG currently supplies less than 2 percent of U.S. consumption, or
about 229 Bcf in 2002 (Colleen Sen, Gas Technology Institute, personal com-
munication,2003~. Historically, lack of growth in U.S. markets can be attrib-
uted to disadvantaged costs relative to domestic and Canadian supplies.
About two-thirds of U.S. LNG imports are currently supplied by Trinidad,
which has been more competitive due to shorter shipping distances.
The EIA (2003a) suggests that LNG imports to the United States could
grow by 2 Tcf/year or more by 2025 (see Figure 4.17~. Four 1970s vintage
regasification terminals exist in the eastern United States and in total have
underutilized capacity of about 2.1 Bcf/day (see Table 4.1~. Expansions of
these facilities could be carried out by 2005 and could increase capacity by
another 2.2 Bcf/day (though adequate take-away pipeline capacity may
not exist) (See, 2003~. Nevertheless, 11 new U.S.-based LNG terminals are
in the "planning stages" (see Figure 4.23~. So far, the Federal Energy Regu-
latory Commission has received only one application for certification for
a new terminal to be built in Hackberry, Louisiana. In total, all existing
and potential U.S. terminal capacity could yield almost 18 Bcf/day, or
more than 6 Tcf/year, with the expansion of existing facilities by 2005 and
potential construction of 11 new facilities. In Figure 4.24, the timing of
new construction is not defined. For various economic and regulatory rea-
sons, it is considered unlikely that many of the recently announced
projects will ever be built (See, 2003~.
Though not all announced projects are expected to proceed, cost re-
ductions in the LNG business promise a growing competitive niche in
U.S. markets. Over the past 15 years, capital costs to build liquefaction
plants and ships have declined 35 to 50 percent (See, 2003~. Also, shorter-
term contracts (5 to 10 years) and an emerging LNG "spot" market allow
for more flexible marketing arrangements. As such, the Gas Technology
Institute indicates that LNG in U.S. markets should be competitive at
$2.50/Mcf for Trinidad and Algeria and $3.00 to $3.50/Mcf for Middle
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MEETING U.S. NATURAL GAS DEMAND
73
I be—Ha/: ~\~ <: l
~~Ij Aft \
In n
· Marine terminal for export
· Marine terminal for import
· Storage (with liquefaction)
1' Storage (without liquefaction)
· Other
Proposed import terminal
Source/destination of present
LNG imports and exports
0 400 800 Miles
0 400 800 km
~H,CitiC~
it Lake Charles,,~; ~;~
:~ 10 :~
~,~ON~ Caribbean Sea TRINlbAD
E L S A LV A Drom If; ~G O
COSTA ROOM B: - V E N EZ U E LA ~
tla n tic
Ocean
from
Australia
Algeria
Nigeria
Oman
Ha;
FIGURE 4.23 North American LNG plants. SOURCE: Sen (2003~.
Eastern and Asian sources (See, 2003~. The EIA (2003a) suggests a com-
petitive range of $3.25 to $4/Mcf (see Figure 4.25~.
The LNG industry faces challenges in the United States due to per-
ceived environmental safety, security, and aesthetic concerns, despite a
sterling safety record (Colleen Sen, Gas Technology Institute, personal
communication, 2003~. Recent protests of planned terminals in Radio Is-
land, North Carolina, and Vallejo, California, have led to their subsequent
withdrawals. Emerging LNG technologies offer promising alternatives to
land-based terminals. In the Gulf of Mexico, various plans for floating
offshore facilities are being considered whereby LNG shipments could be
offloaded, regasified, and injected directly into the existing offshore pipe-
line infrastructure (Colleen Sen, Gas Technology Institute, personal com-
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74
U.S. NATURAL GAS DEMAND, SUPPLY, AND TECHNOLOGY
20 -
18 -
16 -
14 -
12 -
10 -
8-
6-
4-
o
1
Existing Expansion Pending Potential
(2005)
FIGURE 4.24 Existing and projected U.S. terminal capacity in billion cubic feet
per day. SOURCE: Colleen Sen, Gas Technology Institute, personal communica-
tion, 2003.
TABLE 4.1 Status of LNG Terminals
Terminal Location Owner
Peak Sendout
Plus Expansion
Capacity (Bcf/day)
Capacity Holder
Everett, MA
Cove Point, MD
Tractebel NA
Dominion Resources
435 + 600
0 + 750
Elba Island, GA Southern LNG 675 + 540
Lake Charles, LA Southern Union 1,000 + 300
Panhandle
Total for lower 48
states
Penuelas, PR EcoElectrica 186
Tractebel
Shell, 33%; British
Petroleum, 33%;
Statoil, 33%.
E1 Paso Merchant
Energy, 59%;
Marathon, 41%;
Shell has expansion
capacity.
Duke, 20% until
2005,
BG, 80% now, 100%
from 2005
2,110 + 2,240
EcoElectrica
SOURCE: Sen (2003~.
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MEETING U.S. NATURAL GAS DEMAND
$5 - .
$4
$3
o $2
lo
~1
Id,
$0
75
Existing
New
Everett Cove Elba Lake
Point Island Charles
New Mid Atl. S.Atl. Florida* Gulf WA/OR CA
Eng. Coast
|. production ~1 liquefaction I: shipping ~ regasification
* Regasification includes pipeline cost from Bahamas
FIGURE 4.25 Minimum regional LNG costs in 2001 dollars per thousand cubic
feet. Regasification includes pipeline costs from the Bahamas. SOURCE: EIA
(2002b).
munication, 2003~. Even though new LNG import terminals may be built,
the United States will have to compete in the international marketplace
for future LNG imports beyond current contracts.
SUMMARY OBSERVATIONS AND ISSUES
Long-term U.S. demands for natural gas can be adequately met by
combined input from both internal and external supplies. It was a com-
mon theme among workshop participants that the remaining natural gas
resource estimates in the United States and Canada vary widely and bear
further scrutiny. In the short term (through 2006), most data suggest that
both U.S.- and Canadian-sourced production will remain flat to slightly
declining. Workshop participants suggested that some common keys to
increasing mid- to long-term gas supplies from U.S. and Canadian basins
include increased access to the resource, more efficient and competitive
fiscal and regulatory regimes, rapid technological improvements (with
emphasis on the development of unconventional reservoirs and conven-
tional deepwater and frontier resources), and incremental incentives for
construction. Rapid technological improvements could benefit from in-
creased capital investments in oil- and gas-related research and develop-
ment from both the private and public sectors. Sources of funding and
expertise remain in question.
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76
U.S. NATURAL GAS DEMAND, SUPPLY, AND TECHNOLOGY
New external sources of natural gas from northern pipelines and/or
LNG appear to be competitive in a sustained $3.25 or more/Mcf price
environment. Both of these alternatives are capital intensive, and as such,
up-front investments may lag near- to mid-term demand shortfalls (i.e.,
demand cycles will continue to result in price and storage volume vola-
tility until these projects are in place). Pipeline and LNG investments
will likely compete with each other, though common stakeholders have
positions in both arenas and may exert strategic influence on preferred
alternatives.
Representative terms from entire chapter:
gas demand
