WORLD GAS DEMAND TO HIT 116 TCF BY 2010

Margaret M. Carson, Michael A. Roberts
Enron Corp.
Houston

World natural-gas consumption will grow by 55% to 116 quadrillion BTUs (quads; 116 tcf or 3,280 billion cu m) by 2010 from 75 quads in 1994.

This 55% gas-use growth represents a 41 quad increase in gas use and a 3% annual world gas-use growth rate when averaged over the 16 years to 2010 (Table 1)(16894 bytes).

These are the projections of Enron Corp., Houston, in its recent forecast of world energy trends.

Enron revisited its 1993 outlook for North America and expanded the view to include the world natural-gas resource base and global outlook for natural-gas demand through 2010.

METHODS

In early 1994, Enron acquired the U.S. Department of Energy (DOE) energy model based on the new World Energy Modeling System.

Key drivers behind the DOE model are gross domestic product (GDP) growth rates, energy consumption ratios per unit of GDP, world oil demand, and percent shares of incremental energy use growth by fuel type.

Enron adjusted the DOE model to add country and regional detail. With country-specific energy and economic data on 82 nations, the authors developed the assumptions to be entered as inputs to the model.

These assumptions were developed based on recent trends as reported by American Gas Association, Bank of America, British Petroleum, Cambridge Energy Research Associates, Cedigaz, Data Resources Inc., Donaldson, Lufkin & Jenrette, Gotaas Larsen, European Commission Directorate General, ICE Resources, National Petroleum Council, OECD, Oil & Gas journal, Salomon Bros., U.S. Central Intelligence Agency, U.S. Office of Technology Assessment, U.S. Department of Energy (DOE), the World Bank publications, and the 1994 World Gas Conference proceedings.

WORLD GROWTH

Over the time frame of the 1995 Enron outlook, which was prepared by adapting the U.S. Department of Energy's world energy model, Enron's assumed an estimated annual world gross domestic product (GDP) growth of 2.8% overall.

Country-by-country and regional GDP assessments were made with Bank of America World Information Services data, supplemented by U.S. DOE data, and GDP data from Blue Chip Economic Indicators. 1-3

Enron used world electricity consumption trends in its demand-side analysis.

The European Commission (EC) Directorate General XVII for Energy World forecast electricity generation to increase at 2.6%/year by 2005. Growth in energy inputs to generate this electric power, according to the EC world electricity study, will average 2.6%/year.

Natural-gas growth is estimated at 5.2%/year (that is, twice the average rate for all fuel use for power generation), coal/lignite growth is estimated at 2.5%/year, and hydropower growth is estimated at 3.7%/year.

Oil use for power generation is expected to decline 1.3%/year by 2005. Renewables and nuclear power are forecast to grow at 2.7% and 1.2%/year, respectively, in the EC estimate.

While Enron forecasts world natural-gas use to increase 3%/year to 2010, oil use will increase at 1.5%/year, and overall coal use increases by 1.9%/year.

For oil use, Enron adopted the DOE's demand assumptions for the Organization for Economic Cooperation and Development (OECD) but adjusted oil-use volumes for nations outside the OECD, based on the most recent economic and infrastructure development trends (Table 2)(14872 bytes).

World oil use will grow 17 million b/d by the year 2010, up 25% from 1994.

Natural-gas world market share increases from 21.2% in 1994 to 24% by 2010, while oil share decreases from 40% to 36.2% by 2010 (Fig. 1)52909 bytes). Coal and nuclear/hydro/renewables will combine to sustain a 1.0% market share increase.

Total world energy consumption growth from 1994 to 2010 will increase at 2.2%/year to 484 quadrillion BTUs, less than the 2.8%/year world overall GDP growth. This is due, in part, to changes in the effects of energy intensity (or BTU use per dollar of GDP) gradually decreasing by 2010.

Natural-gas use will grow at 3%/year in comparison.

Factors contributing to the lessening in world energy intensity are improvements in energy consuming infrastructure. These occur under the following conditions:

• Economic growth spurs construction of more efficient boilers, process units, cogeneration, and combined-cycle power plants.

• More efficient fuels and motor vehicles enter the world vehicle pool.

• Energy and process cost-control efforts due to global competition and emerging environmental protection trends foster more efficient operations (particularly in the Pacific Rim and Latin America).

• Global privatization trends gradually remove some of the limiting effects on efficiency of price subsidies and cost under-recoveries better to reflect actual costs of fuel and raw material use in adding value for export goods.

• Conservation is promoted in domestic economies.

  Energy intensity declined about 0.3%/year from 1983 to the present. Over 1995-2010, it will decline further, at an average annual rate of 0.6-0.7%.

U.S. ENERGY

With expected strong GDP growth in the U.S. in the 2.6%/year range to 2010, Enron forecasts total U.S. primary energy consumption will increase to 112.1 quadrillion BTUs by 2010, up 22.5 quads (1.5%/year) from 89.6 quads in 1994.

This rate is down slightly from the historical U.S. energy-use growth rate of 1.7%/year since 1985, according to the DOE.

Of this 22.5-quad BTU increase in U.S. energy use by 2010, natural-gas use will increase 7.5 quads. U.S. natural-gas demand growth, up 35% by 2010 (2%/year) is led by gas use for power generation (Table 3)(17422 bytes) which is expected to increase to 5.8 tcf by 2010.

Worldwide growth in natural-gas demand by segment is also led by power generation, which grows 22.8 quads by 2010 (Table 4)(17635 bytes).

Residential and commercial sectors exhibit modest growth of 0.3 and 0.6 quads, respectively, over 1994-2010 due to higher efficiency of newer types of beating units, burners, and commercial gas cooling units in use.

In the U.S., 51% of households currently use natural gas for heating, and 62% of all new furnace additions in 1993 were gas fired. There were 6.2 million more U.S. homes using natural gas in 1993 than in 1986.4

Commercial gas demand grows 1.1%/year and accounts for 800,000 new commercial gas use sites in the U.S. since 1986.

Greater efficiency of commercial gas use has offset a portion of the growth. Average annual gas use per commercial site has decreased 13% since 1986 as a result of conservation and more efficient equipment, operations, and processes.

New gas applications in service-sector growth such as natural-gas vehicles, commercial fleets, and environmentally compatible gas cooling units, which are replacing chlorofluorocarbons, fuel much of this U.S. commercial gas-use growth.

Commercial natural-gas vehicle fuel use will grow from a modest 35 bcf in 1993, with 35,000 natural-gas vehicles on U.S. highways, to 350 bcf by 2010, a tenfold increase assuming a 350,000-unit vehicle count by that time.

If federal and state government mandates are strengthened beyond large commercial fleets, the U.S. natural-gas vehicle count (and the gas-use volume to fuel these vehicles) could more than double by 2010, a 700-bcf new market potential. (This is outside the range of the base case at this time awaiting further legislative and regulatory initiatives.)

There were an estimated 49,600 natural-gas vehicles in commercial fleets in the U.S. by year-end 1994, due to aggressive fleet additions in nine large urban markets, as well as in other locations around the country (OGJ, Aug. 8, 1994, p. 21).

Worldwide, there are currently more than 976,000 natural-gas vehicles, many of which are located in Europe and South America. There are more than 2,300 natural-gas stations in the world.5

Most nations that are major users of natural-gas vehicles have plentiful access to supplies of natural gas, especially the CIS (380,000), Italy (240,000), and Argentina (210,000). These nations use natural gas as a substitute for domestic oil and for pollution reduction in urban areas.

U.S. INDUSTRY, POWER GEN

Future U.S. natural-gas use by industry will increase from 7.5 tcf of gas in 1994 to 8.0 tcf by 2010 (Table 3)(17422 bytes).

Restructuring of the U.S. industrial sector in the Snow Belt along with industrial growth in the Sun Belt over the past decade has improved productivity and capacity utilization in manufacturing industries, including metals processing, petrochemicals and allied products (including methanol production and MTBE production), food processing, building and construction materials, and pulp and paper products.

Industrial cogen and private (non-utility generator, or NUG) power plant gas-use volumes are included in the following discussion of power generation.

Enron's model forecasts that U.S. natural-gas use for power generation will grow to 10.1 tcf by 2010 (Table 3)(17422 bytes). By 2005, power-generation gas use overtakes U.S. industrial gas use as the largest gas-consuming sector.

The National Electricity Reliability Council (NERC), for example, estimates that by 2002, 82 gigawatts (gw) of new U.S. power plant capacity will be required.

NERC estimates about half of these plants will be built by non-utility generators and developers, and the majority of these planned new plants will be gas fired.6

The trends toward wholesale electricity wheeling and increased competition, however, could be expected to reduce the 82 gw of new plants required in the U.S. by perhaps 10-20%, as companies rationalize their plant operations and lower their costs by wheeling in power before construction of incremental capacity.

Because of the lower capital costs and faster lead times to build gas combined-cycle plants vs. scrubbed-coal plants, much of the troubled U.S. nuclear capacity will be displaced by gas combined-cycle plants during the forecast period.

Based on Enron's estimates, up to two-thirds of these new NUGs will be gas fired, together with more peaking or intermediate-use power plants shifting into base-load utilization. This estimate also assumes an early shut down of up to 35 gw of troubled U.S. nuclear power plants and slowing in addition of nuclear-waste storage programs, representing an additional 2 tcf of natural-gas demand as nuclear plants are replaced with gas combined-cycle plants.

The independent power plant (IPP) segment of the power-generation market will consume 4.0 tcf of incremental natural gas by 2010, and this volume could be affected by wheeling of power from existing power plants.

This strategy is more in line with the U.S. sustainable energy future than capital spending for nuclear-waste storage and rising capital costs for nuclear-plant repairs, expenditures for which net the U.S. economy no new kilowatts of power.

In the U.S., construction of 14 bcfd of proposed new gas-pipeline capacity (up to 5 tcf annualized) will facilitate new U.S. gas flows for baseload power generation (Table 5)(23166 bytes).

WORLD GAS DEMAND

World natural-gas use by segment is growing primarily in the power plant and industrial segments. Power plant natural-gas use growth represents 22.8 quads by 2010, compared to world incremental gas demand growth of 41 quads (Table 4)(17635 bytes).

Industrial gas demand is the second largest gas use growth area.

The following trends are converging:

• New gas supplies from the former Soviet Union (FSU), U.K., Norway, The Netherlands, Algeria, and other sources seeking markets in Europe

• Movement toward a competitive natural-gas market and expansion of the pipeline system in Europe

• Improving GNP growth in the 1994-2010 period vs. the slow growth of the early 1990s

• Environmental protection trends toward cleaner fuel use vs. coal and residual fuel oil.

This convergence suggests gas use will increase in Europe 4.1%/year, or 82% by 2010. This increase, led by growth in the U.K., Germany, and Italy, equates to another 8.6 tcf of annual natural-gas demand growth by 2010 (Table 6)(10140 bytes).

To assist in transporting this additional natural gas, 60 pipeline projects representing 15,000 miles (24,000 km) of gas pipelines are being planned to serve European markets.

In South America, with privatization fostering industrial efficiency and export growth, gas use will grow 6.9%/year or nearly triple by 2010 to 5.9 tcf by 2010 (Table 7)(11572 bytes).

South America is largely an undeveloped market for gas, except for Argentina and Venezuela, and its gas-use growth rate is therefore high. There are 24 proposed gas pipeline projects, representing more than 11,700 miles of new pipelines to support this growth.

In the Pacific Rim, with strong inter-regional gas-pipeline projects and continued growth in LNG trade and GNP trends, as well as growth in gas use for powerplant fuel in the region, gas use will increase 3.3%/year, or by 66%, an increase of 4.4 tcf, over 1994-2010 (Table 8)(9721 bytes).

In the Middle East and Africa (Table 9)(10029 bytes), with the emphasis on clean, value-added fuels for energy use and by-products, such as LNG, methanol, methyl tertiary butyl ether (MTBE), and ammonia, and growth in gas-fired power plant fuel use, consumption of natural gas will increase by 4.3%/year (or by 83% by 2010) from 6.1 tcf to 11.2 tcf.

Gas use in West, North, and South Africa is growing inter-regionally due to developing cross-border gas pipeline trade and emphasis on domestic fuel use vs. oil imports.

Because of strong economic growth rates in the rest of the world in 1994-2010, and because of access to plentiful gas resources in such large markets as Canada, Mexico, and Turkey, and countries that plan to develop domestic gas production and reduce flaring, gas use will increase by 8.5 tcf by 2010 in the non-European OECD nations and the rest of the world markets.

Many of these areas with large populations are in need of new and replacement power-generation capacity and gas for industrial development. Natural gas and LNG-fired, combined-cycle plants will supply clean energy to these markets.

Because of the economic recession in the FSU, the negative GDP growth has decreased gas use from its peak rates in 1991 to 21 tcf today. Modest growth in gas use, 0.3%/year, in the large FSU market will occur over 1994-2010 with greater potential for growth thereafter.

This forecast is based on the following four factors:

1. Efforts to increase domestic energy prices to eliminate waste and decrease unaccounted for volumes, as demand decreases in the short term

2. Industry restructuring and foreign investment adding more energy-efficient processes and equipment

3. The need to export additional gas and gas-related products to European and world markets to earn hard currency

4. Long-lead times for major grassroots production areas and export pipelines to be in operation.

Eastern European demand for gas will grow by 66%, or 3.7%/year, by 2016, from 3 to 5 tcf, due to economic expansion, more gas use in electric-power generation, commercial gas use growth, and supply competition from various gas sources. Eastern Europe and the FSU together increase their gas use 0.8%/year by 2010, led by volume increases in Fast European power plants.

Enron forecasts that by 2010, growth in world gas use will equate to an increment about twice the size of the Russian domestic gas market today. Leading the trend for 41 tcf of world gas use growth by 2010 is gas for power generation.

Outside North America, 545 gw of new power-plant capacity may be required by 2000 (Table 10)(12822 bytes).7 Assuming capital costs per kilowatt installed with the average investment at $1,000/kw, capital cost estimates worldwide could exceed $545 billion by 2000.

The majority of this new capacity is planned outside OECD nations in developing and newly industrialized countries. An estimated 100 gw are required for China and 99 gw are planned for Western Europe by 2000.

Taking into account these high capital investment requirements, lower capital cost power plant options become critical in selection of power-generation systems. Gas power plant options are 31-33% less costly on an all-in cost basis (that is, capital costs and variable costs) for a gas combined-cycle plant.

Capital costs for gas combined-cycle plants are about two-thirds lower than the capital cost of comparable coal and nuclear plants (Table 11)(18061 bytes).

Gas combined-cycle power plants, with lower capital and operating costs, also reduce air and water emissions by using 50% less process water and in decreases of 58% in CO2, 81% in No, 95% in particulates, 100% in SO2, and 100% in ash and sludge, all according to the U.S. Environmental Protection Agency and AGA.

GAS MOVEMENTS

To facilitate the 3% annual growth in world natural-gas consumption and to fuel new gas-fired power plant requirements, increases in global natural-gas pipeline construction and new LNG projects will be required.

Of the world's 775,000 miles of natural-gas pipeline transmission infrastructure, 391,000 miles are outside the U.S. and Russia.8

Another 77,000 miles of new gas-pipeline projects, based on nearly 400 projects, are planned by 2000. This represents another 10% of global gas-pipeline capacity.

Further projects are expected to be announced as specific countries' gas strategies continue to develop by 2000 and beyond (Fig. 2)(123479 bytes).

In 1993, 3 tcf (61 million tons/year) of LNG were traded worldwide (Tables 12 (12861 bytes)and 13)(10725 bytes) representing an 85% LNG plant utilization rate.9

Indonesian and Algerian plants represent 60% of world LNG capacity. Japan is the world's largest LNG importer, representing 38.9 million tons consumed in 1993, or more than 60% of the world's LNG use in 1993.

As much as 6.5-7.5 tcf of LNG may be traded by 2010, or more than double today's levels.10

GLOBAL GAS RESOURCES

Enron's 1993 outlook for natural gas identified a potential U.S. natural-gas resource base of 1,303 tcf for the lower-48 states, representing a 67-year resource life based on the 1993 U.S. natural-gas production rate of 19.2 tcf.

The resource base excludes 210 tcf of potential gas resources in Alaska. This is currently untapped by pipeline and, therefore, is without direct market access (except in Alaska).

Canadian gas resources represent another 743 tcf of potential gas supply. Canadian gas currently supplies 12% of all U.S. natural-gas demand, a large increase since Canada supplied 7% in 1988.

On Jan. 1, 1995, the volume of U.S. potential gas resources, adjusted for production and additions, was 1,264 tcf, based on such recent technological advancements as 3D seismic, measurement while drilling, and horizontal drilling.

These technologies continue a recent trend in gas exploration and production efficiency and technological advances which promises to yield even more resources in the future, as much as 1,400-1,500 tcf or greater.

The trend also will allow these resources to be produced within a range of reasonable economic and technical conditions.

The 1,264 tcf of U.S. gas resources represents 9% of all world proved and potential natural-gas resources of 14,024 tcf (Table 14)(11431 bytes).

OUTLOOK FOR GAS PRICES

There is a fundamental relationship between the cost of recovery of a natural resource and how much of that resource will be recovered.

In a market economy, the "Theory of the Mine" posits that an operator will run out of economics before he runs out of resources. This is generally manifested in having to drill too deep or tap into a dispersed ore.

It also can manifest in an operator having to comply with too onerous a regulatory environment or too costly a geography. Every gas-producing country has its own distinct parameters, from Argentina to Zaire.

The one consistent economic dictum is that the long-run netback price of an Mcf of natural gas must exceed the sum of the exploration, development, and operating costs. The margin of excess must be sufficient to motivate an operator to explore, develop, and produce.

For each of the 86 gas-producing countries of the world, localized wellhead prices were coupled with total costs of recovery plus a deemed 15% pre-tax rate of return to develop a required netback price in order to provide incentives for resource exploitation.

Each country's current profit margin was then compared to that of the U.S., with some of the most maturely developed gas reserves in the world, to determine whether the netback prices in each particular country will experience market pressures to rise or fall more or less rapidly than those in the U.S.

The second factor considered in the price analysis is the abundance of gas resources. The reserve-to-resource ratio for each country was calculated and compared to that of the U.S. to develop a normalized relative ratio which indicates, from a resource-abundance perspective, whether pressure will be exerted to accelerate or attenuate price movements over time, again relative to the U.S.

With this formula, the world average netback price for gas in 1994 is $1.19/MMBTU (nominal dollars).

Given then-current netback prices and two relative price-pressure determinants, a projection for each country can be developed relative with the U.S. serving as a benchmark.

Table 15 (15517 bytes) details the results of this analysis based on North American and world average netback prices for natural gas.

After deriving world netback pricing for gas based on a resources analysis, with world 2010 oil prices used for comparison (also in nominal dollars), the relative regional netback gas price based on resources and economics, at 6 MMBTU of gas/1 bbl of oil, results in a 47/MMBTU netback price spread or $2.15-2.62/MMBTU price in 2010, based on $18-22/bbl estimated costs for crude oil (in nominal dollars).

The addition (or reduction) of large amounts of gas resources, i.e., gas giants, between now and 2010 obviously could shift the price relationships among these regions.

Historically, natural-gas price projections have been keyed to oil price projections using "MMBTU parity ratios." While these ratios are still valid for determining competing fuel-price constraints, the underlying oil-price projections based on "oil capacity utilization" function appears inappropriate for forecasting gas wellhead prices when viewed in light of recent market demand and price behavior for gas, coal, and petroleum products.

In the past, these parity and oil productive capacity functions were used to forecast world prices based on OPEC's price-setting power, using statistical regressions for the rate of change in world price to OPEC's capacity utilization.

This gas-price analysis utilizes specific cost of gas recovery and gas resource abundance to project netback prices in 86 countries to yield world regional netback gas prices.

ACKNOWLEDGMENT

The authors appreciate the assistance and direction provided by the staff of the U.S. DOE Energy Information Administration's Office of Integrated Analysis and Forecasting in Washington, D.C.

REFERENCES

1. The Bank of America, World Information Services, Country Outlooks, 1993 94.

2. U.S. Department of Energy, Energy Information Administration, International Energy Outlook 1994-2010, July 1994.

3. Blue Chip Economic Indicators International Forecasts, Capitol Publications Inc., Alexandria, Va., Feb. 10, 1994.

4. American Gas Association, 1993 Gas Facts, Arlington Va.

5. International Gas Union, The World Gas Conference, Milan, June 1994.

6. Power Generation Fuel for the 1990's, ICE Resources, Arlington, Va., 1993.

7. Global Power Markets and Trends, Saloman Bros., N.Y. (August 1994).

8. The U.S. Office of Public and Agency Information's 1993 World Factbook.

9. British Petroleum, Review of World Gas, 1993.

10. Cedigaz, International Gas Projects: The Financial Challenge, Montreux Energy Roundtable IV, May 1993.