Challenges Face U.S. Gas Suppliers

ear-term projections by gas industry re- N search and trade organizations’ indicate that natural gas consumption (supplied prima- rily by drilling in the lower 48 states) could increase by as much as 33 percent. Such an increase would raise consumption from the current 21 trillion cubic feet annually to more than 28 trillion cubic feet annually by the year 2015. This increase would give natural gas a 26- percent share of U.S. total energy usage. Gas to meet this supply challenge will be produced both from current proved reserves of 164 trillion cubic feet2 and from the remaining potential resource base of 1,028 trillion cubic feet.3

John B. Curtis and Stephen D. Schwochow

. . . 28 trillion cubic feet annually by the year 2015.

Three regions-Gulf Coast, Mid-Continent, and Rocky Mountain-undoubtedly will pro- vide the bulk of future domestic gas supply. Potential Gas Committee (PGC) findings illus- trate that the amount of gas required indeed exists and is believed to be technically recover- able from each of these regions. New pipelines, expansions, and added capacity will help move more of this gas to more distant markets. How- ever, in fully meeting these expectations, pro- ducers face several obstacles-in particular, gas imports from Canada and disparities in gas prices. Price differentials, arising from excess

John B. Curtis is director of the Potential Gas Agency and associate professor of geology and geological engineering at Colorado School of Mines, Golden, Colorado. Stephen D. Schwochow is a geological consultant and chief editor with Denver-based Cairn Point Publishing, Inc., an energy publishing com- pany specializing in coal seam gas.

production capacity and, to a lesser extent, transportation costs, will affect the gas supply mix from these regions.

Gas Resource Estimates Underlying any analysis of U.S. gas deliver-

ability is the fact that an adequate supply of natural gas first must exist in the ground and be technically recoverable. An examination of findings by the PGC illustrates that, although a large in-place potential resource indeed is known, estimates of gas resources among the various provinces invariably change through time. These changes depend on our geological knowledge and on exploration results. How the productive potential of a given field, basin, or province is assessed initially and then confirmed (or not) through field activity directly influences the decision to secure markets and build the neces- sary transportation infrastructure.

The PGC has provided industry with reliable estimates of U.S. potential gas resources for over 30 years. The PGC’s estimates are expressed as probable, possible, and speculative resources. Probable resources are associated with the further development of fields already discov- ered and include potential extensions and new pool discoveries. Possible resources exist in new field discoveries associated with estab- lished trends of producing fields. Speculative or frontier resources exist in new field discoveries associated with rock formations (often deeper) not yet proved to be productive. The PGC’s estimates do not include proved reserves.

Estimates are further categorized by drilling or water depth:

0-15,000 feet (shallow) and 15,000-30,000 feet (deep) for onshore areas 0-200 meters, 200-1,000 meters, and deeper than 1,000 meters for offshore areas

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Estimates of total potential gas resource from year to year may increase as a result of new discoveries and reserve additions, or decrease as a result of production and reclassification of resources to proved reserves. How any of these factors influences a resource estimator’s judg- ment is a direct reflection of the amount and quality of information that becomes available through exploration activities, drilling and pro- duction, and development and application of new technologies or new concepts and inter- pretations. Some of this information may con- firm industry’s original expectations about a field or new play-others may not. Their com- bined effect from year to year is either an overall net increase, a net decrease, or no substantial change.

To illustrate how these aspects do affect resource estimates, we can examine percentage changes in the PGC’s estimates over the period 1986 to 1994 for individual provinces within each of three most important regions (Exhibit 1 X u l f Coast, Mid-Continent, and Rocky Moun- tain. These areas together hold over 62 percent of the total potential resource of the entire

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country and 78 percent of that in the Lower 48 (Exhibit 2). (Total resource, as expressed here, is the sum of the “most likely” values for all resource categories and all depths, exclusive of coal-bed gas.) Both the U.S. Geological Survep and Gas Research Institute5 also have assessed these three regions as the most significant current and future supply areas.

Gulf Coast Region The Gulf Coast region is the nation’s domi-

nant natural gas producing area; much of this

7

gas is transported to northern and eastern mar- kets. Although most of the region is in a mature exploration stage, important new fields con- tinue to be discovered. The Gulf of Mexico

continental slope and the eastern shelf are still in early stages of exploration.

The greatest changes in the PGC’s estimates (Exhibit 3) from 1986 through 1994 occurred in the Texas Gulf Coast and East Texas basin provinces. The nearly 180-percent increase in the Texas Gulf Coast estimate is attributed primarily to a substantial increase in shallow probable resources from 1992 to 1994 as a result of drilling in existing fields. A large increase in the deep speculative resource estimate from 1992 to 1994 also contributed to the net in- crease. The 134-percent overall increase in all shallow resources for East Texas has evolved more gradually since 1986.

Despite large increases in speculative re- sources for the Texas-Louisiana continental shelf and slope since 1992-a reflection of the inter- est in subsalt trends-the overall estimates for these areas have declined 30 percent or more since 1986 through transfers of potential re- sources to proved reserves.

Mid-Continent Region The Mid-Continent region is second to the

Gulf Coast area in natural gas production. The Permian and Anadarko basins and the extensive Hugoton-Panhandle area not only are important gas-producing areas but also hold great poten- tial for future gas exploration and development, especially the deep, unexplored areas, includ- ing the deep Arkoma basin. Nearly all the region is in a mature stage of exploration.

Unlike any other PGC region, all Mid-Con- tinent provinces showed marked decreases in recent resource estimates (Exhibit 4). A large part of the declines occurred after 1992. For example, based on field-size distributions for established production and the absence of large fields, PGC estimators decreased the Arkoma basin estimates from as much as 35 percent for all shallow resources to more than 70 percent for deep resources. All categories of shallow Anadarko resources also were revised down- ward, based on field-size distribution trends.

For the Permian basin, a field-size distribu- tion of production below 15,000 feet prompted a large downward revision in probable and possible resources and a corresponding shift of those resources into speculative resources, re- flecting the fact that huge areas of unexplored prospective acreage have been revealed by deep well penetrations.

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Rocky Mountain Region The Rocky Mountain area has been one of

the country’s most actively drilled areas since 1992. Some of the activity is attributed to Section 29 (coal-bed and tight gas) tax-credit drilling and completion programs under way at the time of the deadline for qualified drilling. However, more of the activity is the result of many properties changing ownership or operatorship through divestitures or farm-outs. The new operators are developing the properties with new ideas and, more importantly, at lower operating costs. Consequently, the overall Rocky Mountain resource base has remained essen- tially unchanged since year-end 1992. How- ever, significant changes were noted within individual provinces (Exhibit 5).

The most conspicuous change (+281 per- cent) occurred in the Montana Folded Belt province. Its rise from eighth to third position in resource potential in the region between 1992 and 1994 resulted from large increases in shal- low possible and speculative resources and the first designation of significant deep speculative resources within the province. The area is considered largely undeveloped because gas is produced from only four fields. However, pos- sible and speculative resources were increased substantially because the northern part of the province is now considered to be an extension of an area of prolific gas production of the Cordilleran Thrust Belt in Alberta and British Columbia.

The greatest potential for nonassociated natural gas is concentrated in southwestern Wyoming and adjacent Colorado and Utah, including the Greater Green River basin (high- est) and the Uinta-Piceance basins (second highest). The overall estimate for the Greater Green River basin for 1994 increased only slightly over 1992. The reduction in resource estimates as a result of recent development and exploitation drilling was offset by increased potential indicated by the developing overpres- sured play.

San Juan basin, the largest known gas re- serve in the region, is conspicuous at the center of the trend for its zero net change. Increases in probable and possible resources due to new discoveries and an analysis of drilling locations have been offset essentially equally by in- creased production and the rapid booking of resources to proved reserves.

At the other end of spectrum, the Wyoming- Utah-Idaho Overthrust Belt province experi- enced the largest decline in resource estimates as a result of new data and discouraging drilling results. First, despite moderate drilling activity during the past decade, no significant success has been achieved. Second, several major fields have reached a mature stage of development drilling and pressure maintenance. As these fields approach blow-down, remaining gas po- tential will be restricted to bypassed reservoirs of relatively limited deliverability. Finally, the regional reservoir quality of many less-produc- tive reservoirs in the province is uncertain. If no significant wells are completed in the next several years, the resource estimate may con- tinue to decline. Poor drilling and production results also characterize the decline for the Sweetgrass Arch and Central Montana Uplift.

Canadian and Mexican Imports An issue of growing importance to U.S.

producers and pipelines is the importation of gas from Canada. Canadian imports in 1995 totaled 2.8 trillion cubic feet, or 13 percent of U.S. consumption, and are projected to top 3.3 trillion cubic feet by 2015, according to the American Gas Association (AGA). The bulk of this gas will continue coming from the Western

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Canada Sedimentary Basin (Alberta and British Columbia) and to a lesser extent from offshore Nova Scotia (Sable Island field). Canadian pipe- lines and producer consortia are planning ag- gressive expansions into the United States, namely the Midwest and New England. Gas exports to West Coast U.S. markets will increase, too, but at a much lower rate. In particular, the $800 million Northern Border expansion and the $2.5 billion Alliance Partnership pipelines into the Chicago market area could bring in 4 billion cubic feet of gas daily by 2010.6 This gas would affect U.S. deliveries by diverting gas from western and Gulf Coast fields farther eastward. However, these and other pending projects still face regulatory approval-by both the National Energy Board of Canada and FERC in the United States-as well as close scrutiny by other Canadian pipelines and producers.

Mexican imports and exports currently are balanced when examined over year-long time periods and are forecast by the AGA to remain at a zero net trade balance through 2015. Gas does flow in both directions depending on the near-border market conditions. As is the case in Canada, Mexico has technically recoverable resources far in excess of its own domestic demand, even when examined over a 20-year time period. The transmission and distribution infrastructure is not yet as well-developed as required for Mexico to become a net exporter of natural gas.

Gas Price Differentials The most dramatic gas futures price differ-

ential in the three regions is between the Gulf Coast (Henry Hub) and the Rocky Mountains (Opal Hub). Differentials in excess of $1.50 a million BTUs have been all too common. Con- ventional wisdom attributes most of the dispar- ity on excess production capacity in the Rocky Mountain region, as variations in transmission costs explain only part of the difference. The Rockies are further disadvantaged by a rela- tively smaller and more widely distributed popu- lation and industrial base, with less than 5 percent of the U.S. population living within the Mountain time zone. Plans for pipeline expan- sions to move more gas out of the region, particularly eastward, are in place. Wyoming Interstate Company/Trailblazer, KN Energy, the proposed TransColorado Gas pipeline, and Transwestern are among the potential players.

Strangely, all of this activity is being planned at a time when only small increases in wellhead gas prices are projected. For example, the AGA projects that gas prices will not rise beyond $2.09 a million BTU (1996 dollars) through 2015. Similarly, the Gas Research Institute foresees a low price-growth scenario. These low project- ed prices require that technological innovations and other costcutting measures replace higher prices in order to allow viable explomtion and production of gas at the lower prices.

. . - low projected prices require that technological

innovations and other cost- cutting measures replace

higher prices in order to allow viable exploration - - -

Conclusion The price increases anticipated, in particu-

lar by many Rocky Mountain gas producers with expanded pipeline capacity out of the region, may not materialize or be as substantial as hoped if the new transmission capacity to the East and Midwest becomes excessive and brings about a general lowering of Henry Hub prices. Although each of the regions in this discussion has large gas potential, due to their geologic endowment, the market will deter- mine the mix and quantity of gas production from each area. 4

Notes 1.

2.

3.

4.

5.

6.

For example, GasEnergy SupplyandDemandOutkwk 1996-2015 6 (American Gas Association, June 1996). U S . Ctude Oil, Natural Gas, and NatuuI Gas Liquids Resenes, 1994 Annual Report (U.S. Dept. of Energy, Energy Information Administration, Oct. 1995).

Potential Supply of Natural Gas in the United States (Biennial Reports of the Potential Gas Committee for yearend 1986, 1988, 1990, 1992, and 1994, Potential Gas Agency, Colorado School of Mines).

D.L. Gautier et al., eds., 1995 NationalAssmment of United States Oil and Gas ResourcesResults, Method- ology, and Supporting Data (US. Geological Survey Digital Data Series 30 [CD-ROM], 1995).

Baselinehjection of U.S. Energy Supply and Demand 71(Gas Research Institute, Aug. 1995).

R. George, “The No-Border Border,” Natural Gas Focus 26 (Mar. 1996); “Canadian Pipelines Expanding In- volvement in Foreign Operations,” Oil G Gas Journal 16 (June 24, 1996).

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