3. Outlook for the U.S. Natural Gas Market

Short-Term Outlook

Demand

The next few years⁶⁹ promise to provide an extraordinary boom in natural-gas-fired generating capacity additions, marked by the introduction into commercial service of about 22 gigawatts of new gas-fired capacity in 2000.⁷⁰ These additions contribute to expectations that natural gas will be the key fuel behind economic growth over the next few years. In the Energy Information Administration’s (EIA’s) Short-Term Energy Outlook for April 2001, the average growth rate for gas consumption in the 2000-2002 time period is expected to be 3.6 percent per year, as compared with just 0.9 percent per year from 1994 to 1999.

Factors that could limit the upward momentum in natural gas demand are lagging production increases (with concomitant sharp rises in wellhead and delivered natural gas prices), a slowdown in U.S. economic growth, or a return to successive seasons of below-normal heating (and cooling) demand. However, natural gas demand requirements are likely to absorb expected supply increases and maintain market prices well above what was common in the 1990s for at least the next 2 years.

Industrial Sector

Industrial natural gas demand is tied to the level of output in industries that typically use natural gas as fuel for process heat or as feedstock. Weak output growth in natural-gas-intensive industries (up only 0.9 percent) combined with rapidly rising natural gas prices (up approximately 44 percent to the industrial sector) apparently drove total industrial gas demand down in 2000 by about 2.3 percent. Despite overall slowing in the U.S. economy in 2001, a composite index of natural-gas-intensive industries looks likely to recover somewhat in 2001. Although natural gas prices remain high, industrial natural gas demand is expected to increase by about 0.9 percent in 2001. In 2002, a strengthening recovery in natural-gas-intensive output (4.4 percent) and the prospect of lower average gas prices yields the expectation that industrial natural gas demand will climb by about 4 percent.

Residential Sector

The preliminary year-2000 growth rate for residential natural gas consumption was 4.3 percent, due mostly to increased heating demand, particularly in the fourth quarter. Growth in gas consumption in 2001 is expected to be even higher, at 4.9 percent over year-2000 levels (Figure 16). These are robust growth rates; residential natural gas demand would normally be expected to grow at about the rate of household formation, or about 1 percent per year.

In 2001, the impetus for above-normal natural gas demand growth stems from the higher level of heating degree-days measured in the first quarter compared to year-ago levels.⁷¹ Given normal weather for the rest of 2001 and 2002, along with the other assumptions used in EIA’s latest base case projections, residential natural gas demand is expected to decline by about 0.8 percent in 2002.

The rate of demand growth that is likely to be measured for 2001 is uncertain beyond the question of whether degree-days remain normal from here on in. Generally, the consumption response of consumers to changes in natural gas prices is quite low in the short run. However, the sharp increases in residential delivered prices estimated for average natural-gas-heated households this past winter may have forced additional conservation. Average heating bills for the October-March period probably rose by an average of about 70 percent nationally, possibly enough to bring budget constraints into play for many end users. Precise data on the net offset to estimated residential demand increases this winter as a result of conservation efforts are not available.

Commercial Sector

Natural gas demand growth in the commercial sector averaged 10 percent in 2000. This rate of growth was nearly 7 percentage points above the average annual rate observed during the 1986 to 1997 period and was generated by the combination of strong domestic economic growth, colder than normal weather, and growth in commercial cogeneration. Gas consumption growth in 2001 is expected to slow to 3.5 percent as the U.S. GDP growth rate falls to less than one-half the torrid 5-percent rate of 2000. The combination of slower growth in commercial employment and output plus lower heating degree-days is expected to yield commercial gas consumption growth of about 1.3 percent in 2002.

Electricity Generation

The change in relative energy prices and a slowing down in the growth of electricity demand in 2001 point toward low growth in the demand for gas in the power sector this year. A rebound in economic growth and modestly declining gas prices are expected to result in robust growth in gas demand for electricity generation (12.4 percent) in 2002.

In general, U.S. gas-fired generating capacity is growing rapidly. EIA reported that about 22 gigawatts of new gas-fired generating capacity was added in 2000 (an 18-percent increase from the 1999 level).⁷² Various surveys by private organizations indicate that a much greater increment (30 to 50 gigawatts⁷³) of gas-fired generating capacity in 2001 is implied by the announced additions around the country. A similarly large increase for 2002 is possible given public announcements compiled to date.

While the likelihood that all the announced additions will actually enter commercial service as scheduled is low, it does appear likely that the additions will be at least as high as observed in 2000. The potential for net increases in gas demand associated with these new generating plants reinforces the conclusion that significant new natural gas supply, which may accrue from the very high rate of gas well completions currently estimated for North America, would probably be quickly absorbed. This would suggest that a relatively high floor for spot gas prices should be expected for at least the next few years.

Supply

Production

Preliminary data indicate that dry gas production increased by about 3.7 percent in 2000. These figures are consistent with the available well completion data. It is expected that an additional 2.7-percent production increase will occur in 2001, followed by a 2.5-percent increase in 2002, to 20.3 trillion cubic feet. Similar production increases and higher exports to the United States are expected from Canada.

Drilling

In March 2001, the gas rig count stood at about 900 units (Figure 17).⁷⁴ EIA estimates that the number of new (i.e., excluding recompletions) gas well completions in 2000 was 15,200, 45 percent above the (depressed) 1999 total.⁷⁵ Assuming that rig activity continues to increase at about the current rate, one would expect an additional 25-percent increase in gas well completions in 2001. Given the underlying strength in gas demand expected through 2002, it is reasonable to expect price incentives for continued high completion rates next year.

Imports

Total net imports increased by about 4 percent in 2000 following a strong 14-percent growth spurt in 1999 due to significant increases in cross-border capacity from two projects completed in late 1998 (Great Lakes Transmission expansion and Northern Borders expansion). In 2000 new gas from Sable Island (Nova Scotia) was shipped to the Northeast via the Maritimes and Northeast pipeline, which opened in late 1999, and gas from the Alliance pipeline was available late in 2000.

One sign that net foreign supply to the United States will contribute measurably to the U.S. market in 2001 comes from preliminary data for December 2000, which indicate that total net imports of natural gas to the United States for the month were 16 percent higher than the December 1999 level. With strong natural gas prices expected to persist in 2001 and 2002, net natural gas imports are expected to increase by another 13 percent in 2001 and an additional 4 percent in 2002, rising to 4.18 trillion cubic feet, as gas prices abate somewhat.

Storage

Despite improvements in domestic gas supply, it is unlikely that spot gas prices will move to levels much lower than current levels (about $5 per million Btu) for the rest of the year. This is because of the large amount of new gas supply that will have to go into storage to replenish the very low levels that developed over the past winter (Figure 18). Assuming that a return to near normal levels is required before the beginning of the next heating season, net injections that are about 20 to 25 percent above the average for recent years (1996-2000) would be needed. Thus, the probability that storage will not reach average levels at the end of the summer is relatively high. Monitoring storage this summer will be useful for anticipating the strength of gas prices going into the next heating season.

Prices

The average wellhead price of natural gas in the 2000-2001 heating season (October 2000-March 2001) is estimated to have been 144 percent higher than the average recorded for the 1999-2000 heating season. The length of time that nominal gas prices have remained this high is unprecedented. Moreover, the current dynamics of the natural gas market suggest that prices at the wellhead will not soon be returning to the low $2.00 per million Btu experienced just one year ago. The chief basis for this view is an outlook for robust levels of gas demand growth over the next two years, particularly in the electric power sector. About 90 percent of the planned additions to electric generating capacity over the next few years are designed to use natural gas as the primary fuel. Although gas production and imports are expected to increase in the forecast period, the gains in supply may not be enough to bring the wellhead price below $3.00 per million Btu in the short term.

It is estimated that winter (October 2000-March 2001) natural gas prices at the wellhead averaged about $5.60 per million Btu. Current estimates suggest that residential prices for natural gas were about 42 percent higher for the October 2000-March 2001 period compared to the previous winter. Beyond the end of the heating season it is projected that average wellhead prices will decline somewhat, averaging near $4.40 per million Btu for the spring and summer. However, if the summer weather is exceedingly hot in regions that consume large quantities of gas-fired electricity (California and Texas for example), then injections into underground storage for the next winter would be strained and prices could start rising more sharply and sooner than expected. For 2001, the annual average wellhead price is projected to be about $4.85 per million Btu. The storage situation is expected to improve modestly in 2002, with an expected decrease in the average annual wellhead price to about $4.43 per million Btu.⁷⁶

Economic Impacts

The full extent of the macroeconomic impacts of the rapid natural gas price increases that developed over the past winter in terms of reduced output, increased unemployment, and lower real income are not completely understood at this point. However, some indicators of the significance of the increase in natural gas costs can be estimated. Large increases in aggregate national expenditures for natural gas used by consumers, businesses, and power plants have been seen since April 1999. Households that use natural gas, particularly those that heat with natural gas, have seen winter fuel bills rise dramatically between the 1999-2000 and 2000-2001 heating seasons.

On balance, it is estimated that the rapid increase in natural gas prices that occurred between 1999 and 2001 has reduced near-term economic growth in the United States by between 0.5 and 1.0 percent from what would have been the case with constant natural gas prices. One result of high natural gas prices that is obvious, but is nevertheless worth some detailed discussion, is that natural gas producers’ income increased dramatically. Large infusions of net cash flow to natural gas producers would, among other things, be expected to support strong increases in spending for natural gas resource development. Financial data for domestic oil and natural gas companies that report such information publicly show strong increases in profits for the fourth quarter 2000. Equally strong or stronger financial results are expected for the first quarter of 2001 when those data are available.

Consumer Prices

Natural gas price increases seen in 2000 (including an approximate increase at the residential level of 15 percent) probably contributed an average of 0.3 percentage point to consumer prices last year. Based on the track for natural gas commodity costs so far in 2001 and the base case projections through the end of the year, it is expected that natural gas price increases will result in a consumer price index (CPI) for 2001 that is about 1.0 percent above the level that would have resulted from natural gas prices remaining constant at 1999 levels.

In terms of the rate of consumer inflation, the analysis indicates that the rate of increase in the CPI would have been about 0.3 percent lower than it actually was in 2000 except for the runup in natural gas prices. Also, the expected rate of growth in the CPI this year (2.4 percent) is about 0.7 percentage point greater than would have been the case if natural gas prices had remained constant. Because of lags in the effects of natural gas price increases on consumer prices of other energy and non-energy goods, it is likely that some (rapidly diminishing) impacts on consumer prices would remain even after natural gas prices returned to baseline levels. Overall, consumer price inflation during the 1999-2001 will probably prove to be about 0.5 percentage point above the average rate that would have resulted if new natural gas supply could have been obtained without significant price changes from the 1999 levels (Figure 19).

Expenditures

The extent to which domestic end-use expenditures for natural gas increased in 2000 and so far in 2001 relative to levels that were generally prevailing in 1998 and 1999 is rather startling in nominal terms.⁷⁷ In inflation-adjusted terms the level of natural gas expenditures seems slightly less remarkable but still noteworthy. Total expenditures for natural gas in the United States (calculated as the estimated sum paid for natural gas delivered to residences, commercial establishments, industrial plants, and electric power plants) rose from $105 billion in 1999 to $134 billion in 2000, an increase of 28 percent (Figure 20). In real (inflation-adjusted) terms the increase amounted to 25 percent.⁷⁸ Total natural gas expenditures as a percent of GDP, which averaged 1.33 percent between 1995 and 1999 but moved up to 1.44 percent in 2000, are expected to average 1.80 percent in 2001 and 1.69 percent in 2002 (Figure 21).

To put the higher natural gas costs to households in some perspective, it is useful to calculate the dollar increase in costs of home heating for a typical natural-gas-heated home.⁷⁹ Due to successive warm winters and low natural gas prices in the years prior to the 2000-2001 heating season, winter household natural gas costs averaged about $540 for the three previous winters. It is estimated that for the 2000-2001 heating season, winter household natural gas costs were about $920, 70 percent above the year-ago level. Looking ahead to next winter, slightly warmer temperatures (assuming normal weather) and somewhat lower residential natural gas prices suggest a decline in expenditures of perhaps 8 percent (Figure 22).⁸⁰

Macroeconomic Impacts

Since 1999, dramatic increases in natural gas prices have meant increasing consumer expenditures for energy and have been indicative of strong demand and constrained natural gas supply. Rapid increases in costs have impacts on inflation and output. EIA has performed some preliminary analysis on the impacts of increases in natural gas costs on the U.S. economy by reconstructing the pattern of gas price increases seen between 1999 and 2001 as an alternative scenario for the baseline macroeconomic forecast used in the April 2001 Short-Term Energy Outlook. The alternative macroeconomic simulation was created by using the McGraw-Hill/DRI quarterly model of the U.S. economy.⁸¹ Comparing the results from this alternative scenario and the reference case forecast may yield some insight into the aggregate effects of the recent rapid increase in natural gas prices on inflation and economic output. Of course, any attempt to simulate an alternative history cannot fully account for the dynamic events that shaped the past.

High costs of natural gas have reduced real incomes of consumers and reduced the profitability of gas-consuming industries. Because short-run substitution possibilities between gas and other fuels are limited, one would expect substantial increases in gas prices to result in declining output. Production and profits are higher for gas producers, but natural gas consumers have seen their expenditures rise.

Real GDP would have been about 0.2 percent higher in 2000 except for the tightening supply conditions for natural gas. Furthermore, expectations for GDP growth in 2001 would be about 0.7 percentage point higher if natural gas prices had remained at average 1999 levels through 2001 (Figure 23). Real disposable personal income, which grew by 2.8 percent in 2000 and is projected to post a 2.5-percent increase in 2001, would have likely grown by an average 3.1 percent for both years without the natural gas price increases (Figure 24).

Natural Gas Industry Finances

Major Energy Companies.⁸² Major energy companies with domestic oil and gas operations reported that earnings rose due to much higher crude oil and natural gas prices. Although the results were strongly influenced by the operations of BP Amoco and Exxon Mobil, which together accounted for 44 percent of the net income total for this category, almost all the companies reported higher net income from domestic oil and gas production in the fourth quarter of 2000 than in the fourth quarter of 1999. The benefits of higher oil and domestic natural gas prices were somewhat magnified by higher domestic oil and gas production relative to the fourth quarter of 1999, both of which increased by 11 percent. However, much of the higher production was due to major asset acquisitions (mergers). Omitting the data for companies with significant acquisitions results in a 6-percent decline in domestic production of crude oil and a 5-percent increase in natural gas production for the fourth quarter of 2000 relative to the fourth quarter of 1999.

On the negative side, the majors reported an 86-percent decline in net income from chemical operations. The reason given for the decline in chemical net income in the fourth quarter of 2000 relative to the fourth quarter of 1999 was reduced margins due to higher raw materials costs as both crude oil and natural gas prices increased relative to the fourth quarter of 1999.

Independent Companies.⁸³ Independent oil and gas producers, oil field companies, and refiner/marketers all reported big gains in net income in the fourth quarter of 2000 compared with the fourth quarter of 1999. Oil and gas producers led the group with a 312-percent increase. In total, net income for independents was up 271 percent in the fourth quarter of 2000 over the fourth quarter of 1999. Price increases for oil and, especially, natural gas led to large increases in net income for independent oil and gas producers over the past year. Oil prices increased by 23 percent and natural gas wellhead prices by 131 percent. EIA reported in its February 2001 Monthly Energy Review that domestic oil production declined by 1.9 percent while natural gas production grew by 4.4 percent between the fourth quarter of 1999 and the fourth quarter of 2000.

Mid-Term Outlook

The mid-term outlook for the U.S. natural gas market summarized in this report was developed from the Annual Energy Outlook 2001 (AEO2001),⁸⁴ a mid-term annual energy-economy projection of U.S. energy markets developed using EIA’s National Energy Modeling System (NEMS). The AEO2001 reference case assumes no change in current laws, regulations, or policies and no change in the basis for consumer choices.

Because gas resources are expected to be adequate to meet future natural gas demand through 2020, and technological progress for exploration and development is expected to be sustained, natural gas prices in the AEO2001 forecast are expected to return to a lower price path after 2005 and gradually increase to $3.05 per million Btu in 2020. Advances in drilling technologies are expected to offset some of the cost increases associated with harder-to-find natural gas pockets and smaller pools.

In the near term, natural gas prices are likely to be higher than projected in AEO2001. The higher near-term natural gas prices are expected to stimulate more non-gas-fired generation capacity between 2004 and 2010 than was anticipated in AEO2001. However, the expected surge in natural gas drilling activities, prompted by relatively high natural gas prices between 2000 and 2005, should add considerable natural gas productive capacity and increase proven reserves, lowering natural gas prices and making natural gas generating technologies the preferred choice in the post-2010 time period.

The United States consumed about 22.8 trillion cubic feet of natural gas in 2000.⁸⁵ The previous record for U.S. annual consumption of natural gas, 22.1 trillion cubic feet, was set in 1972. In the AEO2001 forecast, natural gas consumption is projected to reach 31.6 trillion cubic feet in 2015 and continue to rise to 34.7 trillion cubic feet in 2020. As demand increases, pressure on natural gas supply and the transportation infrastructure are expected to grow. These demand-side pressures will raise such questions as “Is there enough gas to meet demand?” “Can we produce the gas fast enough?” “Can we build pipelines fast enough?” and, ultimately, “How high will prices go?”

Demand

The macroeconomic projection for AEO2001 was derived from DRI’s baseline,⁸⁶ adjusted for world oil prices and other energy prices projected in NEMS.⁸⁷ In the reference case, between 1999 and 2020, the economy is projected to grow at an annual average rate of 3.0 percent. Economic growth leads to growth in housing starts, commercial floorspace, disposable income, and industrial output, all of which tend to lead to growth in energy consumption.

In 2000, U.S. natural gas consumption was more than 22 trillion cubic feet and accounted for almost 24 percent of domestic energy consumption.⁸⁸ Natural gas consumption is expected to grow by 2.3 percent annually from 1999 to 2020 (to 34.7 trillion cubic feet)—faster than any other major fuel source—mainly because of growth in natural-gas-fired electricity generation. The increase is expected to occur with a relatively moderate mid-term impact on natural gas wellhead prices in real terms (1999 dollars), which are expected to rise slowly along a “fundamental path,”⁸⁹ reaching about $3.05 per million Btu in 2020. Natural gas consumption in 2015 is expected to be more than 10 trillion cubic feet higher than in 1999. More than half the increase, 5.5 trillion cubic feet, is expected in the electricity generation sector (Figure 25).

Although industrial output is projected to grow at an average annual rate of 2.6 percent from 1999 through 2020, the most rapid growth is for the non-energy-intensive manufacturing sectors, particularly electronics and industrial machinery. The greater growth in non-energy-intensive industries results in energy consumption increases that are less than proportional to the increase in industrial output.

The industrial sector (including cogeneration) is the largest natural-gas-consuming sector, with significant amounts of natural gas used in the bulk chemical, refining, and metal durables sectors. Industrial natural gas consumption is projected to increase by 2.2 trillion cubic feet over the forecast—about 1.2 percent per year—particularly in the metal durables and bulk chemical sectors, because of relatively low and stable natural gas prices in the long run.

Combined, the residential and commercial sectors are expected to add 2.4 trillion cubic feet to 1999 annual gas use by 2020. Natural gas demand in the residential and commercial sectors is driven by housing and building stock, increasing housing size (i.e., larger homes being built), and steady consumer prices. In the forecast, the relatively stable prices paid by residential consumers reflect increased natural gas distribution efficiencies in an increasingly competitive market. Because residential natural gas prices are generally lower than the prices of other fuels, the increase in the number of homes heated by natural gas is projected to be more than three times the increase in those heated by electricity. Residential and commercial natural gas consumption is expected to grow by 1.3 percent annually from 1999 through 2020.

Coal is projected to remain the dominant fuel for electricity generation throughout the forecast period; however, its share of total electricity generation is expected to decline from 51 percent in 1999 to 44 percent in 2020. The natural gas share of total generation is expected to increase from 16 percent in 2000 to 36 percent in 2020.⁹⁰ Natural gas consumption by electricity generators, not including industrial cogenerators, increases threefold in the forecast, from 3.8 trillion cubic feet in 1999 to 11.3 trillion cubic feet in 2020. Significant growth in natural-gas-fired generation is reinforced by electric industry restructuring and other related factors, including lower capital costs, shorter construction lead times, and higher efficiencies for natural gas turbines and combined-cycle units than for coal, renewables, and nuclear alternatives.

Natural-gas-fired electricity generation (including industrial cogeneration) is projected to grow rapidly, from a 15-percent share of generation in 1999 and a 16-percent share in 2000⁹¹ to a 36-percent share in 2020 (Figure 26). Throughout the forecast, natural gas technologies are projected to capture the majority of capacity additions for electricity generation, excluding cogeneration. Of this new capacity, it is projected that 92 percent will be combined-cycle plants or combustion turbines, including distributed technologies, fueled by natural gas. Only 6 percent is projected to be coal-fired plants and 2 percent renewable technologies. Renewable technologies for electricity generation are projected to grow slowly because of the relatively low cost of fossil-fuel-fired generation technologies, and because electricity industry restructuring is expected to favor less capital-intensive natural gas technologies.

Supply

Domestic Production

Domestic natural gas production is expected to increase more slowly than consumption over the forecast, from 19.3 trillion cubic feet in 2000 to 29.0 trillion cubic feet in 2020 (Figure 27). To satisfy demand of 31.6 trillion cubic feet in 2015, annual domestic natural gas production will need to increase by 7 trillion cubic feet. Thus, over the next 15 years, production increases must average over 460 billion cubic feet per year. To produce 29.0 trillion cubic feet of gas in 2020, lower 48 natural gas wells drilled will have to increase from about 10,500 in 1999 to about 24,000 in 2020 (Figure 28).

From 1955 to 1972 the industry increased production at more than 140 percent⁹² of the projected rate required from 1999 to 2015. Of course, conditions are different from those earlier years. Undiscovered field sizes in mature producing areas are smaller, and larger prospects are located in more remote areas. On the other hand, the real price (in 1999 dollars) of natural gas was more than three times higher in 1999 ($2.11 per million Btu) than it was in 1955 ($0.52 per million Btu), real exploration and production costs are lower, technology is better, and the regulatory environment is more favorable to natural gas production. Figure 29 shows the expected domestic sources of natural gas.

In the past, producers were constrained by price controls and the market was unable to send clear signals about consumers’ interest in purchasing and suppliers’ willingness to sell. As a result, during some periods curtailments in supply were of great concern. In today’s competitive market, improved price signals are sent to sellers and purchasers, allowing for the setting of market clearing prices. The current episode with high natural gas prices and the natural gas industry’s investment response confirms that the question is less “Will the natural gas be there?” and more “How much will it cost?”

Current estimates of technically recoverable natural gas resources indicate that the resource base is expected to be adequate to sustain growing production volumes for many years, based primarily on the assessments done by the U.S. Geological Survey for onshore regions and by the Minerals Management Service for the offshore. As of January 1, 1999, technically recoverable resources were 1,281 trillion cubic feet. Resources include not only proved reserves, which were 164 trillion cubic feet, but also inferred reserves from known fields and undiscovered resources from new fields. Inferred reserves, representing the expected growth from previously discovered fields, totaled 244 trillion cubic feet as of January 1, 1999, most of that located in onshore areas. Resources in lower 48 undiscovered fields not associated with oil deposits accounted for 319 trillion cubic feet of the total. Of all the undeveloped resources, the largest share belongs to unconventional natural gas from tight sandstone formations, coalbeds, and shales at 393 trillion cubic feet. Natural gas associated with oil makes up most of the balance of the total technically recoverable resource base (Figure 30). Cumulative natural gas production from 1999 through 2020 is likely to total between 480 and 512 trillion cubic feet, well under the estimate of 1,281 trillion cubic feet for recoverable natural gas resources.

Uncertainty with regard to estimates of the Nation’s natural gas resources has always been an issue in projecting production, and could affect production and prices. The uncertainty surrounding recoverable natural gas resource estimates is reflected in the differing views on the subject. For example, GRI’s latest baseline⁹³ asserts that using current technologies only, the total recoverable resources in all categories is over 1,800 trillion cubic feet—roughly 50 percent higher than EIA’s estimate. When advanced technologies are considered, GRI shows that over 1,300 trillion cubic feet is economically recoverable at $3 per thousand cubic feet. GRI’s analysis is not the most optimistic assessment. Dr. William Fisher at the University of Texas at Austin has a much higher estimate, well over 2,400 trillion cubic feet.⁹⁴

EIA’s estimates are taken largely from the USGS, which tends to be cautious because it is difficult to estimate resources of oil and gas that cannot be explicitly measured.⁹⁵ Because of such uncertainties, the USGS and other resource professionals have often underestimated the size of the resource base. Because of unanticipated technological progress, professionals have also typically overestimated production costs. The AEO2001 projects that about 512 trillion cubic feet of the 1,281 trillion cubic feet estimated recoverable resources will be produced between 1999 and 2020 at prices less than $3.05 per million Btu in 1999 dollars. Like any commodity price, however, actual natural gas prices are likely to oscillate significantly around the trend line projected in AEO2001 as a result of business cycles in the industry, unusual seasonal temperature variations, or other special circumstances like pipeline ruptures—events that have been experienced in the past 24 months.

Imports

Net natural gas imports are expected to grow in the forecast from 16 percent of total natural gas consumption in 1999 to 17 percent or 5.8 trillion cubic feet in 2020. Most of the increase is attributable to imports from Canada, primarily from western Canada, although some new natural gas is also expected from Sable Island in the offshore Atlantic. As in the United States, Canadian resources are adequate to sustain production for many years. The Canadian Gas Potential Committee indicates that there is an estimated 184 trillion cubic feet of marketable discovered and undiscovered conventional natural gas in the Western Canada Sedimentary Basin as of 1993.⁹⁶ Similar estimates from the National Energy Board of Canada range from 153 to 224 trillion cubic feet as of the end of 1997, with 362 trillion cubic feet of additional resources in other areas in unconventional formations.⁹⁷

Mexico also has a considerable natural gas resource base, but natural gas trade with Mexico is expected to consist primarily of exports. Conversion of power plants from heavy fuel oil to natural gas, in compliance with Mexico’s environmental regulations, is expected to gain momentum, and it is unlikely that indigenous production can be increased enough to satisfy rising demand. LNG provides another source of natural gas imports; however, given the projected low natural gas prices in the mid-term trend in the lower 48 markets, LNG is expected to supply just 2 percent (0.77 trillion cubic feet) of U.S. natural gas consumption in 2020, up from 0.6 percent in 2000.

Transmission and Distribution

AEO2001 projects a 22-percent increase in interregional pipeline capacity⁹⁸ from 1999 through 2020 to satisfy the projected demand for natural gas. Pipeline capacity crossing the 12 regions used for analysis, including import/export capacity, is projected to increase from 125 billion cubic feet per day of design capacity in 1999 to about 152 billion cubic feet per day in 2020 (Figure 31). Much of the expansion is either already completed, under construction, or far enough along in the planning and approval process to be deemed likely to occur. The added capacity will provide access to new and expanding production areas—such as Canada, the deep offshore, and unconventional resources in the Rocky Mountain region—and will accommodate shifts in demand patterns, such as new demand for natural gas to replace electricity generation capacity lost as a result of nuclear retirements.

In recent history, the largest annual increase in pipeline capacity was 8.5 billion cubic feet per day in 1998. Although a large portion of the new capacity in 1998 came from the construction of several major new pipelines bringing natural gas onshore from deepwater production projects in the Gulf of Mexico, the expansion of Canadian import capacity via such projects as the Northern Border Pipeline expansion into the Midwest also added significantly to the total. In view of the historical and expected near-term annual increases in capacity, peaking at a potential 12.9 billion cubic feet per day in 2002, the ability to construct enough additional natural gas pipeline capacity to handle a total U.S. natural gas market of 35 trillion cubic feet in 2020 is not likely to be a problem.

In addition, Government policy supports an optimistic outlook for the post-2000 pipeline expansion forecast. FERC policy supports more rapid approval of expansion by the pipelines as long as they are willing to assume more risk rather than requiring firm contracts to be in place before approving an expansion.

Uncertainties in the Mid-Term Outlook for Natural Gas

Putting aside those factors that cause short-term volatility and those factors that are part of the normal business cycle for the natural gas industry, a number of sensitivity cases described in AEO2001 examined the sensitivity of the natural gas market to alternative levels of resources, alternative rates of technological progress, and a higher growth rate for electricity demand (Table 3). Combinations of the worst of all assumptions (low resource availability, slow technology progress, and high electricity demand growth) and the best of all assumptions (high resource availability, rapid technology progress, and slow electricity demand growth) were not examined.

Notes