ENRON SEES MAJOR INCREASES IN U.S. GAS SUPPLY, DEMAND

Oct. 7, 1991
Margaret M. Carson, Bruce Stram Enron Corp. Houston Enron Corp., Houston, in an extensive study of U.S. natural-gas supply and demand through the year 2000, has found that the U.S. gas-resource base is 1,200 tcf. Despite current weaknesses in natural-gas prices, demand growth will be strong although affected by oil-price assumptions. Highlights in the areas of reserves and production include gains in both categories in the Rockies/Wyoming, San Juan basin, and Norphlet trends (offshore Alabama).
Margaret M. Carson, Bruce Stram
Enron Corp.
Houston

Enron Corp., Houston, in an extensive study of U.S. natural-gas supply and demand through the year 2000, has found that the U.S. gas-resource base is 1,200 tcf.

Despite current weaknesses in natural-gas prices, demand growth will be strong although affected by oil-price assumptions.

Highlights in the areas of reserves and production include gains in both categories in the Rockies/Wyoming, San Juan basin, and Norphlet trends (offshore Alabama). The Midcontinent/Hugoton area exhibits reserve declines in a period of flat production.

In the U.S. Gulf Coast (USGC) offshore, both production and reserves decline over the forecast period.

These projections are derived from a base-case price of $4.07/MMBTU by 2000.

U.S. gas production exhibits a production decline in a low oil-price case from 19 to 16.4 tcf by 2000, if prices are 30% below the base case, that is, $2.93/MMBTU.

Gains in commercial gas use are strong under either scenario of a base oil price of $29.80 in 1990 dollars in the year 2000 or a low oil price of $20.50 in 1990 dollars in 2000.

Demand for natural gas for power generation grows as much as 1.5 tcf by 2000 in the Enron base case and by 300 bcf by 2000 in the low crude-oil price case.

FORECASTERS' AGREEMENT

It's no surprise that regional natural-gas supply and demand patterns in North America are constantly changing. A consensus of forecasters agrees that, to protect the environment, more gas will be burned by U.S. power generators to meet growth in electricity demand. But how much more will be needed is unclear.

New pipeline projects are springing up all over the gas patch, mainly connecting gas deliverability out of basins west of the Mississippi to new markets along the East Coast.

Enron has identified 3 bcfd of new (largely interstate) pipeline capacity that has been brought into service since 1989. Another 3 bcfd of incremental pipeline capacity is expected to be onstream by 1995.

Under the assumption that about 3 miles of gathering system are behind every 1 mile of interstate pipeline, options for moving gas from nontraditional sources are growing exponentially with pipeline construction and changes in reserves patterns resulting from new efficiencies in exploration and development.

These changes, of course, increase uncertainty about future U.S. gas flow patterns. For example:

  • To move gas to traditional markets, will USGC onshore and offshore production continue its historical decline or will these trends flatten or be reversed?

  • Will San Juan reserve additions and production grow exponentially over the next 10 years, or will they level off?

  • How much natural gas will actually be needed to meet power generation demand by the end of the decade if oil prices are low?

In 1989, some analysts were concerned that the U.S. was rapidly depleting its natural-gas resource base. Enron decided that it was in its long-term interests to explore the size of that resource and what the future holds for the U.S. gas industry.

BASE-CASE OUTLOOK

The prime focus of the base-case outlook is on the current size of the U.S. natural-gas resource base. Proved reserves (for the Lower 48 states) in 1990 total 158 tcf (Table 1).

Enron projects that if available technology improves at the same rate as over the past 5 years so that improved seismology, stimulation techniques, and horizontal drilling are even more widely used, the total economically recoverable U.S. natural-gas resource base can total 1,200 tcf (including 158 tcf of proved reserves).

In 1990, the Midcontinent/Hugoton area with 30 tcf of reserves is the top ranked region by reserves. It falls, however, to second place by 1995, displaced by U.S. Gulf Coast offshore reserves totaling about 25 tcf. This offshore-reserves performance is supported by strong reserve additions in this area for the next 10 years.

Fig. 1 shows Enron's base-case reserves assessment, 1990 vs. 2000.

BASIN BY BASIN

A basin-by-basin analysis of the Enron base case in Fig. 1 shows significant trends that underlie this U.S. reserves assessment. San Juan basin and the Norphlet off Alabama have the largest reserves increases from 1990 to 2000.

Based on 158 tcf of proved reserves, combined with a 1,032-tcf resource base (Table 2), U.S. gas supply at today's annual consumption rate of 18.5 tcf is equal to more than 60 years' resource life, or 1,190 tcf.

Gas out of new fields (442 tcf) represents about one third of the resource base, and gas from very tight sands formations equals another one fifth (200 tcf).

Areas near West Coast markets in these key resource areas are: Rockies/Wyoming (new fields); Overthrust (new fields); West Coast; coalseam bed; and very tight sands.

Having established that the resource base is indeed ample, let's turn next to U.S. gas supply trends.

Table 3 depicts the U.S. Lower 48 production in the Enron base case, together with approximate market-share changes for gas exports to the U.S. and LNG/SNG.

Canadian supplies are 2 tcf/year by 2000, up 0.6 tcf from today's 1.4 tcf levels. LNG/SNG use grows from 0.2 tcf today to 0.8 tcf by 2000 in the base case, utilizing the four existing U.S. LNG gasification facilities but without requiring any expansions to U.S. regasifiers.

Algerian LNG and possibly some Nigerian LNG by later in the decade are the supply sources.

Comparison of Table 3 with the low oil-price case (Table 4) shows a more modest supply profile: 19.2 tcf by the year 2000 instead of 21.8 tcf in the Enron base case.

Demand for gas stays relatively flat in the low oil-price case, as fuel-switchable load losses are offset by growth in commercial use.

U.S. regional gas production trends show that for 1990, most gas flows from U.S. Gulf Coast offshore and Midcontinent areas largely to Northeast and Midwest markets.

CANADIAN EXPORTS

Canadian volumes are outside the model. If a more aggressive export policy is employed by the Canadian government, exports could be 400-600 bcf higher (or U.S. production lower) and demand could well be higher.

In the Enron base case, offshore declines are modest by 2000 and Midcontinent flows increase. By 2000, production growth is most significant from the Norphlet trend, San Juan, and the Rockies/Wyoming (Table 5).

San Juan basin reserve additions grow annually through 1995 and peak. They then decrease back to today's 1.5 tcf additions per year by 2000 in the base case (Table 6) but fall behind today's levels by 2000 in the low oil-price case.

To move gas to traditional markets, U.S. Gulf Coast onshore and offshore production continues its historical declines in both the base case and the low oil-price cases.

The large Norphlet production increases (up from 16 bcf in 1990 to 822 bcf in 2000) and production growth from Appalachia, Alabama/Mississippi, and Canada replaces Gulf Coast production losses in Northeast markets.

San Juan basin production nearly quadruples over the 1990-2000 period in the base case-434 bcf/year to 1.671 tcf or 1.2 bcfd to 4.5 bcfd (Table 5); and still triples in the low oil-price case (Table 7).

Reserve additions over the 10 years in the base case (Table 6) are strongest in four areas: USGC offshore, Appalachia, Midcontinent/Hugoton, and Rockies/Wyoming.

LOW OIL-PRICE CASE

Under Enron's view of natural-gas supplies and production under the low oil-price case (Table 4), Lower 48 gas production by 1995 grows to 17.9 tcf. This is up from today's 16.9 tcf levels.

After 1995, however, U.S. production declines from Gulf Coast offshore and Texas onshore, resulting from continued low oil and gas prices and more than offsetting gains out of San Juan and the Norphlet trends. The result is an overall drop in U.S. production.

Lower 48 gas production, as a result, drops to 16.4 tcf by the year 2000.

To meet low oil-price case demand levels for gas, 2.8 tcf of imported Canadian and LNG supplies would be required by the year 2000.

In the low oil-price case, U.S. offshore and Louisiana and Texas onshore production declines are deep (Table 7) and result in demand decreases in fuel switchable markets.

Comparing the required gas-reserves assessment by 2000 in the low oil-price case (that is, lower demand for gas means fewer producible reserves) shows gas reserves to be 119 tcf, or 31 tcf lower than in the base case at 150 tcf (Table 8). Reserves increases are mainly in the San Juan and Norphlet trend offshore Alabama.

As for reserve additions changes, Appalachia, the Overthrust, and the Permian maintain their strength in the low oil-price case, but the effects of these gains are neutralized by declines in reserve additions in Gulf Coast offshore areas.

Reserve additions in the low oil-price case grow modestly in the short term, to 16.3 tcf by 1995 from 13.6 tcf in 1990. They revert to present levels, however, by 2000: 13.2 tcf. This results from the strength of improved efficiency in exploration and development technology and to new field additions in the Appalachian, Overthrust, and Permian areas.

The most aggressive reserves-to-production ratios in the base case are San Juan, the Overthrust, and the Rockies/Wyoming.

Appalachia and the Norphlet trend also exhibit a strong reserves life.

CAPACITIES, CONSTRUCTION

To gain access to a future 21.7-tcf U.S. gas market and to accommodate growth in deliveries out of new as well as traditional reserves basins, new U.S. and Canadian pipeline projects are in various stages awaiting completion, design, or regulatory consideration.

Enron recently completed a regional survey of pipeline construction projects (Table 9). The survey identified 8,500 miles and 16.3 bcfd of new projects.

The West Coast/Rockies area is by far the most active in the country with proposed new pipeline capacity representing 38% of total projects. The average costs of the supply area pipelines are lower than the projects serving the Northeast.

Although not all of these proposed U.S. projects are expected to be built, and others may slip their completion dates a year or more, it is estimated that at least two out of three of these projects will, in time, be completed.

This ratio of 2 to 3 equates to about 4.0 tcf of new annual capacity, out of the 6.0 tcf proposed.

The magnitude of these expansions is more than adequate to serve the 3.1 tcf of market growth forecast in the Enron base case by the year 2000.

Two thirds of the 2 bcfd of Northeast and East Coast projects are to move new Canadian and Midcontinent supplies to markets in the East; the remaining ones expand access to USGC and offshore supplies to access new East Coast markets.

These projects, totaling 3.7 bcfd, largely access the growing production volumes out of Mobile Bay and other offshore areas for East Coast markets.

New projects also plan to move Black Warrior coalseam gas to South Atlantic markets.

These projects, totaling 4.3 bcfd, provide access for Oklahoma gas to Northeast and upper Midwest markets and provide outlets for the new Antrim gas and other local Michigan production.

These projects represent up to 6.2 bcfd from three growing sources of supply competing for markets west of the Rockies:

  • Canadian export volumes

  • Incremental Rockies/Wyoming supplies

  • Rapidly increasing volumes out of the San Juan basin.

About one third of these projects provide for gas to flow either east or west.

Table 10 depicts the natural-gas demand regions described within the Enron outlook (Fig. 2). The forecast assumes GNP growth at an annual rate of 2.6%.

Electricity consumption in the U.S. grows at a 2.2%/year rate between 1990 and 2000.

Gas use for power generation, the main growth market in the base case, grows by 1.5 tcf over the next 1 0 years.

Movements of 8 bcfd of new gas flows occur by year 2000 in the Enron base case, led by overall electric generation use gains and in industrial-gas use growth in the South Atlantic area.

The U.S. demand for gas for power generation increases by 1.5 tcf from today's levels of 2.8 tcf to 4.3 tcf in 2000, in Enron's base case, but only rises 0.2 tcf to 3.0 tcf under the low oil-price scenario.

Across most regions of the country, gas for electric power generation sustains significant gains, particularly in the South Atlantic, the Mid-Atlantic states, and Southwest markets.

In the U.S., 28,000 mw of gas-fired, combined-cycle capacity are forecast to be entering service between now and 2000.

About half of that is in independent power projects to meet both power-growth needs and compliance with environmental regulations, especially after 1998, as a result of the Clean Air Act amendments.

This is not a great deal of new electric generating capacity, representing only about 3.5% of net generating capacity today (782 gw).

Commercial natural-gas use increases 1 tcf by 2000, led by the Pacific and Northeast markets.

Compressed natural-gas (CNG) vehicles are included in the commercial-use segment because commercial fleets will lead the market growth as a result of Clean Air Act fleet mandates in 22 U.S. cities.

By 2000, the Enron base case includes 500 bcf of CNG use.

This equates to 2.5 million vehicles (or 15% of commercial fleets). Commercial gas-use gains are strong across the board, particularly following new pipeline-capacity additions and interconnects bringing incremental gas to growth markets.

Residential gas use in the base case, however, is flat to 2000, growing just 100 bcf. U.S. industrial gas use is showing modest gains of 355 bcf nationally, due to growth in the Southwest, growing only 100 bcf.

Residential gas use in the base case is relatively flat for all regions as a result of conservation effects of more efficient appliances and competition from electricity, offsetting modest gas-consumption gains.

The price forecasts used in the model behind the two case sensitivities were based on a 1989-90 consensus of oil prices of major forecasts (for example, DRI, Wharton Econometrics Forecasting Associates, and U.S. Energy Information Administration) for the base case. And the forecasts were also based on a sustained low crude-oil price case of $20.50/bbl for 1990-2000 (in 1990 dollars), adjusted only for inflation (Table 11).

Copyright 1991 Oil & Gas Journal. All Rights Reserved.