ENRON'S 1993 OUTLOOK FOR U.S. GAS REFLECTS NEW TECHNOLOGIES, MARKETS

Margaret Carson, Bruce N. Stram, Michael A. Roberts
Enron Corp.
Houston

Enron Corp., Houston, has revisited its 1991 outlook for U.S. natural-gas supplies, revising upward by 8.6% its view of the nation's natural-gas resource base.

As of Jan. 1, 1993, Enron's U.S. resource assessment for the Lower 48 is 1,303 tcf, or more than a 70-year resource life at the 17.6 tcfy 1992 production rate (Fig. 1). In 1991, Enron had foreseen 1,200 tcf of undiscovered and potential resources (including 160 tcf of proven natural gas reserves).

With an adjustment for 2 years of production, the more recent estimate compares favorably with the 1,295 tcf natural-gas resource projection made by the National Petroleum Council (NPC) in January 1991.

The company foresees the potential for 2.4 tcf of gas-market growth to 22 tcf by 2000 (up from 19.6 tcf in 1992) and to 23.6 tcf by 2005.

This growth is largely the result of incremental natural-gas use in electric-power generation in gas combined-cycle plants, gas for co-firing, and in commercial gas use, including 500 bcf natural-gas-fleet vehicle fuel use by 2000.

With additional environmental and policy initiatives, another new demand increment of 2 tcf or more could be added by 2000.

TECHNOLOGY YIELDS

New applied technologies yielding the larger resource base include enhanced seismic, such as 3-D seismic, amplitude-vs.-offset methods, improved evaluation and completion techniques, refined fracturing diagnostics, improved techniques for assessing coalseam gas, and enhanced drilling technologies, such as horizontal drilling and measurement-while-drilling (MWD).

Engineers and geologists at Enron have determined over the past 5 years that these new practices have been rapidly adopted by the U.S. gas industry in the field.

These developments portend both an increase in the economic viability of new resources (such as San Juan coalseam gas, Devonian shale, and tight gas), and an upsurge in the yields from basins in Wyoming, Texas, and Mobile Bay (offshore Alabama).

In addition, the pace of growth in natural-gas demand in the U.S. and the rise in new U.S. gas-pipeline completions have been significant enough that the previous, 1991 outlook was at risk of becoming obsolete.

According to Cambridge Energy Research Associates, $8-10 billion of new pipeline additions have been added to the system in the past 5 years, facilitating more grid-like flexibilities among markets and opening up previously bottlenecked supply and market corridors.1

To perform the supply/demand evaluation, Enron used a modeling system supplied by Energy & Environmental Analysis Inc., Fairfax Va., and updated by Enron assumptions along with additional information gathered by participation in the NPC's effort to achieve a view of the energy future and the role for natural gas.

The U.S. gas market can grow to 22 tcf by 2000 and to 23.6 tcf by 2005 if the following factors are considered:

Reasonable exploration and production technology assumptions
Recent Clean Air Act environmental regulations to reduce by 50% S02 and NOx emissions from power plants and reduce automotive emissions
Natural gas and oil prices consistent with recent world-oil price behavior. These prices are $3.23/MMBTU for the Gulf Coast spot wellhead price for natural gas by 2000 and for crude oil at $22.68/bbl for refiners' acquisition composite cost of crude oil in 1993 dollars by 2000 (Table 1).

More than 1.3 tcf, i.e., the largest growth component, of total new demand of 2.4 tcf by 2000 is created by the competitiveness on an all-in cost basis of construction of gas-fired, combined-cycle power plants by electric utilities and independent power producers alike and environmental requirements for cleaner fuels such as gas co-firing and reburn with coal (Table 2).

EFFECTS OF POLICIES

Enron also reviewed the possible effects of various energy and environmental policies for potential gas use and determined an additional 2 tcf of gas demand (or more) beyond the 22 tcf market in 2000 is potentially achievable by the end of this decade.

The accompanying box presents Enron's view of energy and environmental policy implications for potential gas use by 2000.

Enron foresees that:

The resource base is expanding to 1,303 tcf because of improvements in recovery technology, particularly in tight-sands gas, but generally as well with "conventional" resources.
Natural-gas prices in the U.S. increased in the summer of 1992 because of growth in demand for gas in U.S. markets (up 15% since 1986), the brief Hurricane Andrew supply shock, and low summer storage fill levels.
Enron's 1993 outlook estimates a $3.23/MMBTU price for U.S. Gulf Coast wellhead spot natural gas by 2000, up from $1.61/MMBTU in 1992, assuming a $22.68/bbl price for crude (both in 1993 $U.S.) by 2000.
A combination of higher prices and lower operating costs, because of greater efficiency in the gas industry, elicits a significant U.S. supply response (i.e., 1.2 tcfy by 2000 and 1.9 tcfy additional by 2005) due to strong gas-market competition and increased supply flexibility in recent years, replacing decades of gas-industry regulation.

Enron forecasts that gas demand will grow from 19.6 tcf in 1992 to 22 tcf by 2000. This growth is facilitated by the 1992 National Energy Act which increases competition in U.S. power generation (between utilities and independent power generators) and by the 1990 Clean Air Act amendments' effect on dirty fuels.

Demand increases for natural gas are mainly in three markets:

Power generation: + 1.3 tcf
Natural-gas vehicles: + 500 bcf by 2000
Mexican imports: + 350 bcf by 2000.

Enron also prepared a comparison case that assumes a $33.13/bbl (in 1993 $U.S.) refiners' acquisition cost of crude oil by 2000. This case yields 21.8 tcf of gas demand by 2000 vs. 22.0 tcf in the 1993 base case in which oil prices are at $22.68/bbl.

Economic activity is one of the key components driving the model.

For this analysis, Enron assumed a gross national product (GNP) annual growth rate of 2.5% through 1998 and 2.4%/year thereafter. Demand for electricity grows at 2%/year through 2000.

ELECTRICITY GROWTH

The Utility Data Institute recently released an estimate indicating 79 gigawatts (gw) of new power generation capacity would be needed in the U.S. by 2000.2

Of this 79 gw of new capacity, 38 ow (or 48%) are expected to be gas-fired units. Enron's outlook assuming increased gas-fired power generation capacity equates to 1.3 tcf of new gas demand by 2000 and 2.2 tcf of added demand by 2005.

ICF Resources, Fairfax, Va., recently studied costs on an all-in basis for large gas combined-cycle power plants.

ICF found that gas combined-cycle plants cost 60% less than coal plants on a $/kw of installed capacity basis of $683/kw vs. a comparable coal-fired plant at 51,820/kw (meeting today's EPA standards).

Gas plants are 63% lower in cost than a comparable nuclear plant meeting today's standards at $1,980/kw, according to the ICF study (Table 3).

Gas combined-cycles are further at an advantage, according to ICF, by sustaining greater utilization rates than competing fuels. For example, the utilization for dispatch of power by gas-fired, combined-cycle plants is 90-95% vs. 70-80% for a coal plant and 65-83% for a nuclear plant.

Power plants burning scrubbed coal or nuclear fuels at more than $0.09/kw-hr are 30-35% more costly on a levelized cost basis than gas combined-cycle plants at $0.063/kw-hr (Table 4).

The ICF study details the environmental benefits of gas-fired plants compared with coal. A natural-gas plant produces virtually no S02 emissions and no solid-waste products such as scrubber sludge, particulates, or ash.

A 500-mw gas plant utilized at a 65% capacity factor lowers NO, emissions by 87% and reduces CO2 emissions by 60% compared - with a comparable coal plant (Fig. 2).

In addition to growth in the power-generation sector, commercial gas use increases 15% by 2000, a 400-bcf increase. Much of this can be attributed to the developing natural-gas fleet vehicle market.

While currently a small market, Enron sees natural-gas vehicle demand growing to as much as 750 bcf by 2005. This figure is based on federal and local fleet use by 5 million vehicles in large urban areas targeted by Clean Air Act initiatives, particularly in California, the Northeast, Texas, and the Upper Midwest urban centers.

Strong growth in demand creates new markets for growing gas supplies. New supply sources prove the resource base is large enough and the supply curve is elastic enough that supplies respond to market growth on a timely basis.

For example, here's Enron's 1993 outlook resource assessment (Fig. 2):

Tight sands resources increase by 50%, up 126 tcf, coalbed methane additions increase 35 tcf, and Devonian shale gains 20 tcf.
Unconventional resources rose 186 tcf compared to Enron's 1991 outlook.
Conventional gas resources increased by 58 tcf.

U.S. recoverable resource base, with application of advanced technology, has added 238 tcf of conventional and unconventional resources combined (Table 5). The significant increases are in the nonconventional category, with gains in tight-sands resources representing half of the 238 tcf overall increase (Fig. 1).

NORTH AMERICA

The Canadian National Energy Board (NEB) estimates total conventional Canadian gas resources at 478 tcf.4

Combining resource-base estimates for the U.S. and Canada yields a total that exceeds 1,780 tcf. This base translates into more than 80 years of gas supply for North American markets at today's annual U.S. production rate of 17.6 tcf and 4 tcf in Canada (Table 5).

Natural-gas imports by pipeline are not constrained in the model. By 2000, the model assumes imports of Canadian gas to the U.S. will reach 2.8 tcf, up from the 1992 1.8 tcf levels.

Another 0.2 tcf of LNG imports are supplied by reopening and full use of portions of the existing U.S. LNG facilities (two of which, in Louisiana and Massachusetts, are now operating) by 2000 but does not provide for any new construction of U.S. LNG facilities.

Exports to Mexico increase to 350 bcf by 2000; beyond 2000, Mexico reverts to being a net supplier to U.S. markets.

REFERENCES

Robinson, Tom, "New Horizons: The Energy Future," Cambridge Energy Research Associates, Cambridge, Mass., Feb. 10, 1993.
"State Directory of New Electric Power Plants," Utility Data Institute, Washington, D.C., February 1992.
Rose, Judah, "The Power Generation Fuel for the 1990's," ICF Resources Inc., Fairfax, Va., February 1992.
"Potential for Natural Gas in the U.S.," National Petroleum Council report, Dec. 17, 1992, Vol. 2, p. 10.