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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
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).
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~.
52 in in CD s U' Q S O s in ~ CD U) - O O Id IL - ~ O SO am o o .O It O ~ O UP O U) Ct) Ct) C\i - to to - 5- V) ~ - o ED o .= g ~ ~ a.~ (pal) UO!~0npO~a See l~n~N s n O ~ O V) aim ~ ~ ¢ · rt _ _ so to ~ ~0 ~ _ UO ~ o au 5- SO o AL) EA O UP O UD O (~0l) UO!~0npO~a S~e l~n~N s n
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.
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
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
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~.
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
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
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
60 U.S. NATURAL GAS DEMAND, SUPPLY, AND TECHNOLOGY FIGURE 4.10 Anadarko's Arctic Drilling Platform in actual operation at Hot Ice #1 well site in Alaska, first quarter 2003. SOURCE: Keith Millheim, Anadarko Petroleum Corporation, personal communication, 2003. test of onshore gas hydrate deposits funded by the U.S. Department of Energy and industry (estimated 590 Tcf resource; National Energy Tech- nology Laboratory (2002~. The Arctic Platform is designed like a scaled- down offshore platform, standing above the tundra and using piers set in the permafrost (see Figure 4.10~. Current ice-pad technology allows for exploration drilling only during frozen winter months (about a 3- to 4- month window). If successful, the Arctic Platform might allow for ex- panded operational windows for both conventional and unconventional resource development without damaging sensitive tundra environments. Research and Development Trends Private funding for oil and gas research, historically the bastion of major oil companies, has dropped precipitously (by more than half) since the early l990s (see Figure 1.4~. This phenomenon has been fueled, in large part, by consolidation in the exploration and production sector,
MEETING U.S. NATURAL GAS DEMAND 100 ~ 75 .2 C' ° 50 Q z 25 fit ~ \ '94 '95 '96 '97 '98 '99 Monthly Data 61 '00 '01 '02 '03 FIGURE 4.11 Number of seismic land crews in the United States for the period 1994 to 2003. SOURCE: Anadarko Petroleum Corporation (2003~. including service companies. Workshop participants were particularly concerned about the number of seismic contractors. In 2002 three major seismic contractors exited in the onshore lower 48 states while the land seismic crew count has diminished to one-third of the 1998 to 1999 lev- els (see Figure 4.11~. In addition, public-sector funding for oil and gas research has also de- clined. The National Science Foundation indicates that petroleum-related research dollars account for less than 1 percent of total U.S. research and development dollars spent in the past decade (Hill, 2000; see Figure 4.12~. In the United States, the number of doctoral degrees granted in the fields of science and engineering has been in gradual decline since 1996 (see Figure 4.13) (Hill, 2002a). Undergraduate and graduate geoscience degrees show a more precipitous decline having dropped to one-third of the high levels experienced in the early to mid-1980s (see Figure 4.14~. Notwithstanding declining trends in both research and development funding and college degrees granted, technology continues to evolve. It was suggested at the workshop that the United States is "off pace" to achieve long-term goals without commitment and cooperation between both private and public sectors (Naresh Kumar, Growth Oil and Gas, per- sonal communication, 2003~. In essence, Kumar stated that the private sec- tor should "pull" technology for short- to mid-term solutions (5- to 10-
62 U.S. NATURAL GAS DEMAND, SUPPLY, AND TECHNOLOGY 180,000 - 160,000 140,000 120,000 1 00,000 80,000 - 60,000 - 40,000 - 20,000 - 1988 1990 1992 1994 Year 1996 1998 2000 Petroleum Refining and Total R&D Extraction FIGURE 4.12 National research and development dollars for petroleum refining and extraction, and total research and development for the period 1988 to 2000. SOURCE: Naresh Kumar, Growth Oil and Gas, personal communication, 2003. Data are from Wolfe, 2000. year horizon). And, the public sector, including academia and govern- ment-funded entities, would do well to focus and leverage its investments toward longer-term, larger-scale opportunities (e.g., gas hydrates, 10- to 20- year horizon) while maintaining programs that help graduate students be- come employable in the energy industry (see Figure 4.15~. Economic Incentives Though somewhat difficult to quantify, economic incentives can pro- vide stimulus to the exploration and production industry where risk- weighted and/or capital-intensive investments are lagging. These incen- tives can come directly in the form of tax credits and royalty holidays. Indirect incentives might include improved acreage access and regula- tory process efficiencies (e.g., improved cycle time), lease extensions and
MEETING U.S. NATURAL GAS DEMAND 25 20 in_ En o s 15 . _ Id En ~ 10 o Q A 5 _ _ . ~ _ _ _ o 1986 1988 1990 1992 _ _ _ 1994 1996 1998 2000 2002 Year · Chinese, South Korean, Japanese, ----- U.S. Citizens in and Taiwanese (in U.S. institutions U.S. Institutions and in their home countries) 63 FIGURE 4.13 Doctoral science and engineering degrees for the period 1985 to 2000. Note: The U.S. curve includes physics, chemistry, astronomy, earth, atmo- spheric, and ocean sciences. Engineering includes aeronautical, astronautical, chemical, civil, electrical, industrial, materials, metallurgical, and mechanical. However, available data for Asian doctorate degrees distinguish the physical sci- ences from other sciences. This means that the Asian curve includes math, com- puter science, agricultural, and biological sciences. SOURCE: Richard Smalley and Emmanuelle Schuler, Rice University, personal communication, 2003. Data are from the National Science Board (2002), and Hill (1997, 2002b).
64 1 0000 - 9000 8000 ~ 7000 cat in o Q A 6000 5000 4000 3000 2000 1 000 U.S. NATURAL GAS DEMAND, SUPPLY, AND TECHNOLOGY O- 7~ o Cat ~ ~ Go 00 00 00 a' 00 o Cat ~ ~ Do o o o ~ ~ ~ ~ ~ Cat Year · PhDs 1~ Undergraduates ~ Masters FIGURE 4.14 Geoscience degrees granted during the period 1980 to 2001. SOURCE: AGI (2001). increasing maximum acreage chargeability limits (e.g., Bureau of Land Management state limitations). Historic incentives affecting U.S. natural gas production include Sec- tion 29 and Section 43 tax credits and deepwater royalty relief. As an ex- ample, Section 29 gas credits were enacted in 1980 that created a $0.50/ Mcf credit for gas produced from unconventional reservoirs (tight gas sands, coalbed methane, and Devonian shale). Success of the program is indicated by production growth from unconventional reservoirs from 2.0 Tcf in 1990 to 4.8 Tcf in 1999 (EIA, 2001a). New economic incentives currently being considered include offshore deep-shelf royalty relief (Richie Baud, Minerals Management Service, per- sonal communication, 2003) and in Alaska exploration credits and a gas tax credit or price floor guarantee for a future gas pipeline. These pro- grams serve to incrementally improve economic returns (e.g., rates of re- turn and net present value) or to guarantee minimum economic returns as a means to accelerate capital investment. Examples of indirect incentives relating to access include the recent opening of federal acreage in the offshore eastern Gulf of Mexico (Sale 181)
MEETING U.S. NATURAL GAS DEMAND o N I (20 years +) (1 0 years +) Technology curve / /Low-cost (5 years +) / production Imaging, drilling / / High temp. , /(3-D basin models) -rotary drilling systems evaluation efficiencies ........................................................................................................................................................................................................................................ / / Hydrates electronics Producers/ Contractors/ National and Academic Operators Service Providers Other Labs Institutions 65 FIGURE 4.15 Likely short-term versus long-term research and development play- ers. SOURCE: Naresh Kumar, Growth Oil and Gas, personal communication, 2003. and on the North Slope in the eastern National Petroleum Reserve Alaska. Future considerations might include expanding these two areas as well as opening the Alaska National Wildlife Refuge. The Minerals Management Service has also recently adopted the Subsalt Extension Rule, which allows for offshore lease extensions beyond the primary term in exchange for ad- ditional high-technology seismic processing James Emme, Anadarko Pe- troleum Corporation, personal communication, 2003~. EXTERNAL SOURCES OF NATURAL GAS The United States currently imports about 11 Bcf/day, or about 18 percent of total consumption (EIA, 2003b). Ninety-four percent of that volume is provided via pipeline imports from Canada (Greg Stringham, Canadian Association of Petroleum Producers, personal communication, 2003), while LNG imports from various sources provide the remaining volumes. Net pipeline imports from Canada have grown since 1994 but remain flat to slightly declining since 2001 (see Figure 4.16~. LNG imports have risen since 1998, though volumes are still modest and are constrained due to long-term commitments to other international markets and the sig- nificant cost of infrastructure.
66 = = o ~ ~ ~ ~ ~ ~ ~ . . . . . . . . _ o o o o o o o (PO°a) Coda ON] _ ^ 1 1 1 _ W _ o _ _ _ ~ o < . ~ I I ~ : I I 1 _ ~ ! I : 1 ~ i I ~ ~ 1 ~ I w o (Pang) sandal GU0Gd!8 1GN . . U o .S .1 .~
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
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
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~.
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~.
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~.
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
MEETING U.S. NATURAL GAS DEMAND 73 I beHa/: ~\~ <: 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-
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~.
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.
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.
