2. Recent Trends and Current Situation

Trends in Natural Gas Consumption

From the high levels of the early 1970s, U.S. natural gas consumption declined to a low of 16.2 trillion cubic feet in 1986.⁶ Since then it has increased at an average annual rate of about 2.4 percent. In 2000, total natural gas consumption in the United States reached an all-time high of 22.8 trillion cubic feet, 4.8 percent higher than in 1999. The previous record was 22.1 trillion cubic feet in 1972. Total end-use consumption of natural gas increased by 0.8 trillion cubic feet from 1999 to 2000.⁷ While industrial consumption declined, the increase in other sectors was about evenly split between electricity generation and the residential and commercial sectors combined.

Much of the variation from the general year-to-year trend of U.S. natural gas use can be attributed to variations in average winter temperatures.⁸ The larger than average increase in gas use from 1999 to 2000 was primarily the result of a change from the particularly warm winter weather of 1999-2000 (3,351 heating degree-days or 457 fewer heating degree-days than normal) to the particularly cold winter of 2000-2001 (4,048 heating degree-days or 270 more heating degree-days than normal). Average national temperatures in November and December 2000 were near record cold levels (20 percent below normal) for those months. Other factors that can contribute to short-term increases in natural gas consumption are changes in natural gas prices relative to other fuel prices and changes in the availability of other fuels.

Consumption by Sector

In 2000, the residential, commercial, industrial, and electricity generation sectors accounted for about 24 percent, 16 percent, 39 percent, and 21 percent of the end-use natural gas market on an annual basis, respectively.⁹ A small amount was consumed by natural gas vehicles.

Consumption levels in the residential and commercial sectors are the most sensitive to temperature, those in the industrial sector the least. In these three sectors, natural gas use peaks in the winter period when heating loads are high. The electricity generation sector has a marked peak in the summer months when air conditioning demand is high and a second, smaller peak in the winter.

Industrial

The industrial sector consumes the greatest quantity of natural gas¹⁰ and shows the least monthly variation in gas consumption throughout the year, with the peak month in the winter period averaging about 12 percent higher than the monthly average in recent years. Industrial consumption rose steadily from 1986 to 1996, at an average annual rate of 4.6 percent. From 1996 to 2000, industrial gas consumption fell by an average of about 1.9 percent per year, despite increases in manufacturing output that have averaged 2.9 percent annually since 1996.

In 1996 the U.S. industrial sector consumed 8.7 trillion cubic feet of natural gas. With a shift toward less energy-intensive industries and an overall increase in industrial energy efficiency resulting from the introduction of new capital equipment, however, industrial gas consumption dropped to 8.3 trillion cubic feet in 1999 and 8.1 trillion cubic feet in 2000. From September through December 2000, natural gas consumption in the industrial sector was down by 8 percent from 1999 levels. Manufacturing output growth began to slow during the third quarter of 2000, followed by a more significant slowdown during the fourth quarter of 2000, in part because of higher energy costs.

Many industrial consumers of natural gas do not have the option of switching to other fuels when natural gas prices rise. Others have some limited fuel switching capability.¹¹ An option that has been exercised by some industrial users recently as natural gas prices have risen dramatically is to reduce operations and sell contracted gas to the highest bidder. Examples include Terra Nitrogen, which shut down its Arkansas fertilizer plant in 2000 and cut back operations at its Oklahoma plant, and Mississippi Chemical, which halted fertilizer production. Both companies sold their natural gas futures contracts.¹²

Residential

From 1986 to 2000, residential natural gas use grew by an average of 1.0 percent per year. Several factors contributed to the increase. Newly constructed single-family homes increased in average size from 1,825 square feet in 1996 to 2,225 square feet in 1999 (22 percent), and in 1999 70 percent of those new homes used natural gas for space heating, compared with 47 percent in 1986.¹³ Natural gas fireplaces have also become more popular in newly constructed homes. Over the same period, however, increases in both furnace and building shell efficiencies have tempered the growth in residential natural gas use.

Residential natural gas consumption in 2000 was 4.3 percent higher than in 1999, largely due to the colder winter. About 70 percent of annual residential gas consumption occurs during the winter months (November through March), which represents just 41 percent of the calendar year. In the peak consumption month (typically January), residential consumption typically has reached or exceeded industrial consumption. Colder than normal temperatures during peak months can further increase the peak demand.

With record low temperatures in the last 2 months of 2000, it is estimated that residential natural gas consumption in December 2000 and January 2001 was at record levels. Residential gas use in December 2000 is estimated at 893 billion cubic feet, which would be 13 percent above the previous record of 791 billion cubic feet in December 1989, as well as the largest-ever increase from the previous year and from the previous month in absolute terms. Residential gas consumption in January 2001 is estimated to have been even higher, at 1,006 billion cubic feet, 6 percent above the previous record of 953 billion cubic feet in January 1994 and 14 percent above the January 2000 level. During the 2000-2001 winter heating season, natural gas consumption in the residential sector is estimated to have been 20 percent greater than in the previous winter season.

Residential customers typically are the least responsive to natural gas prices, particularly in the short term. There are few short-term options for decreasing residential gas use other than lowering thermostats and sealing leaky doors and windows. Some households may be able to resort to backup heat, such as electric room heaters or woodstoves and fireplaces, but most are truly captive customers. In addition, residential customers often are not as informed about natural gas prices as they are about the prices of other, more widely advertised products such as gasoline, and frequently they do not receive price signals (monthly bills) in a timely manner. Some opt for levelized payment plans, which are beneficial for household budgeting but can delay price signals.

Commercial

The commercial natural gas market is only about two-thirds the size of the residential market, with only about half the January peak. Although consumption in the commercial sector is affected by winter temperatures, only 62 percent of its total annual consumption occurs during the winter months (as compared with 70 percent for the residential sector). Commercial consumption has grown much faster than residential consumption since 1986, by about 2.7 percent per year on average, and the annual total in 2000 was about 7 percent higher than the average, due mainly to the colder winter.

Like the residential sector, the commercial sector is estimated to have had record levels of natural gas consumption in December 2000 and January 2001. Total natural gas use in the commercial sector during the 2000-2001 winter heating season is estimated to have been about 16 percent higher than during the 1999-2000 heating season.

Electricity Generation

Natural gas consumption by electricity generators was relatively stable in the 1980s and early 1990s, averaging around 2.9 trillion cubic feet per year.¹⁴ From 1996 to 2000, however, the use of natural gas for electricity production grew by an average of nearly 11 percent per year, to 3.9 trillion cubic feet in 1999 and 4.4 trillion cubic feet in 2000. The natural gas share of U.S. electricity generation, including cogeneration, rose from 13.2 percent in 1996 to about 16 percent in 2000.¹⁵

The sharp increase in natural gas consumption for electricity generation since 1996 has resulted from increasing demand for electricity and from the growing use of gas in new generating plants. Recent increases in electricity sales have contributed significantly to recent increases in natural gas consumption. Electric utility retail sales have increased by 2.4 percent per year on average since 1995. The most rapid growth in electricity sales has been in the commercial sector (30 percent of the total market), at an average annual rate of about 3.6 percent. Between 1998 and 1999 total retail sales increased by 2.2 percent, from 3.24 to 3.31 trillion kilowatthours, and the increase from 1999 to 2000 was 2.5 percent.¹⁶

Annual variations in natural gas demand in the electricity generation sector are attributable to weather variations (particularly during the summer months), the availability of alternative energy supplies (e.g., hydropower), and fuel prices. In terms of weather, 1998 had a particularly warm summer, but the 1999 and 2000 summers were close to average on a national basis. In terms of alternative supplies, low water levels at hydroelectric dams in the Northwest over the past 2 years have resulted in relatively low levels of generation from hydroelectric sources, leading to a significant (12 percent) increase in natural-gas-fired electricity generation. Estimates for 2001 are for even lower levels of hydropower generation in the Northwest.

Even with the high prices for natural gas in 2000, natural gas use by electric generators increased to assist in satisfying higher demand for electricity and to supplement low levels of generation from hydropower. With the exception of hydroelectric power, petroleum, and some renewable energy sources, net generation of electricity, including cogenerators, from all sources increased from 1999 to 2000. While total net generation increased by 96 billion kilowatthours, conventional hydroelectric generation decreased  by 44 billion kilowatthours, requiring a net increase from other sources of 140 billion kilowatthours. About half the increase came from coal, a third from natural gas, and about 17 percent from nuclear power. With relatively high prices of oil and still relatively low prices of natural gas at the beginning of 2000, generation from petroleum was down from 1999 levels (when petroleum prices were low). By the end of the year, as natural gas price increases far exceeded those of petroleum products, generation from petroleum increased more dramatically, so that by December net generation from petroleum was nearly triple 1999 levels. Although generation from natural gas slowed somewhat toward the end of 2000, estimates for December 2000 still exceeded 1999 levels.

While most areas of the country entered the 1990s with sufficient generating capacity, the need for new capacity started to grow in the mid-1990s. Natural gas turbine and combined-cycle plants were the units of choice for new plant construction because of their relatively low costs, high efficiencies, and short construction lead times. From 1995 through 1999, natural-gas-fired capacity in the United States increased by 21.4 gigawatts. The largest increase, 6.7 gigawatts, was in 1999. Twenty-two gigawatts of gas-fired generating capacity was added in 2000.¹⁷ Estimates for additional planned gas-fired capacity for 2001 generally are in the range of 25 gigawatts.¹⁸

Natural Gas Supply

Domestic Production

Natural gas prices affect both short- and long-term domestic gas production. In the short term, price surges determine the degree of utilization for present productive capacity. Costs rise at an increasing rate as capacity limits are approached. In the longer term, higher gas prices provide both the primary means (cash flow) and incentive to invest in additional projects to either maintain or expand productive capacity.¹⁹

Recent gas production patterns show the impact of a lengthy period of low gas and oil prices, which had turned around by mid-1999.²⁰ In response to the relatively low gas and oil prices, gas production in 1999 hit a recent low of 18.6 trillion cubic feet. Incremental gas consumption requirements that year were satisfied by increased imports and a drawdown from storage during the year. Gas consumption in 1998 fell from the 1997 level of 22.0 trillion cubic feet ²¹ as a result of warm winters. With the decline in demand, production decreased in 1998 (by 0.2 trillion cubic feet) and 1999 (by less than 0.1 trillion cubic feet). As demand for gas diminished, prices also weakened, leading to a falloff in gas rig activity from a relative peak of 657 rigs drilling gas wells as of December 19, 1997, to 362 as of April 23, 1999 (Figure 1). Rig activity picked up in May of 1999 and accelerated in the fall of that year. By December 1999, active gas rigs averaged 636 units for the month. Gas rig activity continued to strengthen in 2000, yielding a count of 854 by December.

The reduced gas drilling activity through April 1999 did not affect production immediately. Changes in drilling generally affect the system over a 6- to 18-month period because of the time required to acquire investment funds, install production equipment, and construct gathering lines and pipelines for transportation. Extraction of natural gas resources occurs at a declining rate as gas deposits are depleted and pressures decline. Consequently, the development of new wells is important. More than 30 percent of U.S. gas production in recent years has flowed from wells that are no more than 2 years old (Figure 2).²² When drilling falls, the natural decline in production from existing wells is not offset with new well capacity. If there is under- or unutilized productive capacity, production can be maintained by increased utilization of existing wells. Absent spare capacity, however, decreased drilling leads to an aggregate decline in production as producing wells are depleted. Subsequently, accelerated drilling must be undertaken to return to the previous production level or achieve higher production rates.

Although gas well completions have increased steadily since April 1999, production did not respond robustly enough to satisfy the expanding market demand, because the industry initially had to overcome the prior drilling slump. Despite this handicap, domestic production increased by about 0.7 trillion cubic feet in 2000, equivalent to about 66 percent of the increase in consumption from 1999 to 2000.²³ Given an industry apparently pressing the limits of its productive capacity, production could not increase sufficiently to meet rising demand, so prices were driven higher.

Drilling Activity and Reserve Additions

Natural gas well completions have outpaced oil well completions since 1993.²⁴ Gas completions as a share of all successful oil and gas wells increased from 63 percent in 1998 to 72 percent in 1999. Overall, however, gas drilling levels dropped by 13 percent between 1998 and 1999, in part because of low levels of cash available for investment in exploration and development.

Despite a lower number of gas wells, natural gas reserve additions were higher in 1999 than in 1998, replacing 118 percent of dry gas production with new reserves (Figure 3). Although total reserve additions were larger, total dry natural gas discoveries²⁵ in 1999 were 5 percent lower than in 1998 and 31 percent lower than in 1997. The decline in gas discoveries was not just a result of fewer exploratory wells. Average discoveries per exploratory well (the finding rate) also declined, and this level of reduced productivity is expected to have continued through 2000.

However, with average wellhead prices averaging roughly $2.50 per million Btu in mid-1999, net revisions and adjustments to proved reserves almost tripled, from 4.1 trillion cubic feet to 11.5 trillion cubic feet.²⁶ With continued high prices in 2000, reserve additions through revisions and adjustments are expected to remain well above the post-1976 average of 3.8 trillion cubic feet per year.

Drilling Investment Trends

Analysis of available data suggests that the natural gas industry behavior in 2000 was consistent with its practices of the past decade. In response to the natural gas price increases in 2000 there were an average of 720 rotary gas rigs in operation, a 45-percent increase from 1999.²⁷ Gas rigs accounted for almost 80 percent of the total operating rigs. Between 1999 and 2000, both exploratory and developmental gas drilling increased significantly, by 31 percent and 45 percent, respectively.²⁸

Drilling behavior (exploratory and developmental drilling) is correlated with natural gas wellhead prices (Figure 4). Exploratory wells are wells drilled with the goal of finding new reserves. Developmental wells are wells drilled with the aim of producing from existing proved reserves. The two types of wells are vastly different in terms of their riskiness. In 2000, fewer than one-third of all exploratory wells were successful. In contrast, more than 85 percent of development wells in 2000 were successful.²⁹

From the mid-1970s to 1980 the gas industry and most forecasters expected gas prices to rise as supplies remained constrained and price ceilings were increased. This situation continued into the early 1980s after the passage of the Natural Gas Policy Act. Consequently, exploratory drilling reached very high levels with more than 8,500 exploratory wells, including dry holes (Figure 5); however, prices (measured in constant 1999 dollars) began to decline after 1983 and then fluctuated around $2.00 per million Btu. As natural gas prices declined and later moderated, so did exploratory drilling. When prices are low, the industry typically focuses more on producing from existing proved reserves, based on their expected profitability, rather than aggressively trying to add to reserves.

In 1998, capital expenditures for the major companies in the natural gas industry substantially exceeded cash flow,³⁰ leading to increases in borrowing, decreases in payouts to investors, and drawdowns of cash balances. Repairing balance sheets and boosting investor confidence became the focus in 1999, leading to reductions in capital expenditures, increased payments to reduce debt, and decreased payouts to investors.

As prices rose in 2000, the increases to expected profitability and industry cash flow motivated increased investment spending. The Oil and Gas Journal noted that 154 independent U.S. producers had increased capital spending by 48 percent in 2000 and that the top independent U.S. producers announced budget plans to increase spending in 2001 by about another 35 percent.³¹

The prospects for adding significant amounts of new gas supplies from 2002 to 2005 look promising in view of expected natural gas prices. Natural Gas Week reports that U.S. contractors and service companies, pumped up by profits from current natural gas sales, “are flinging themselves into a headlong rush for rigs as the boom is beginning to take on fabled proportions.” First-quarter 2001 profits reported by Baker and Hughes rose by 600 percent over first-quarter 2000 profits, and Senior Vice President Andrew Sczescila predicted that 2001 would be the best year for service companies since 1981.³²

Factors Limiting Rapid Expansion of Domestic Gas Supply

Investor uncertainty about the duration of high prices moderates the rate of drilling investment. Investors do not initiate projects with long payback periods in any industry based on temporary price increases unless those prices are thought to be representative of a long-term market condition. Investments are based on expected prices over the project lifetime, and price expectations are not adjusted automatically and completely on the basis of a sudden shift in price trends. Thus, the impact of recent high prices on drilling investment may have been muted by uncertainty about their duration.

Natural gas prices at the Henry Hub in most of 2000 were well above the average range of the 1990s, including 1998 and 1999. In 2001, temperatures since the first of the year have been warmer than normal across the Lower 48 states, reducing gas demand and the natural gas spot prices at the Henry Hub by more than 50 percent from the winter peak—down to a level slightly above $5 per million Btu by late February 2001, which continued through April 23. Earlier episodes of severe price runups (such as in February 1996) were not as sustained as they have been in 2001.

The NYMEX prices for future delivery are a helpful barometer for identifying the consensus view of managers in the gas industry as well as outside investors regarding price expectations related to gas investment decisionmaking. Although NYMEX prices in mid-December 2000 approached roughly $10 per million Btu, prices were expected to return to a level slightly exceeding $4 per million Btu by summer 2002 and were expected to fall into the $3 range by March 2003.³³ In mid-January 2001, NYMEX prices had become more stable through 2003, with futures prices lower in the near-term months of 2001 and remaining above $4 per million Btu into 2003.³⁴

An industry survey of independent operators in November 2000, when gas spot prices ranged from $4.38 to $6.34 per million Btu and oil prices were between $34 and $35 per barrel, indicated that gas prices averaging $3.58 per million Btu and oil prices averaging $25.35 per barrel were anticipated in their 2001 investment plans.³⁵ Coincidentally, the average wellhead gas price for 2000 is estimated to have been $3.51 per million Btu.³⁶

Unexpected rapid price surges do not allow the industry to carry out the preparatory planning and other activities necessary to build productive capacity efficiently. Virtually all industry participants attempt to respond in a short time frame, which leads to heightened competition for investment funding, personnel, and equipment. Heated competition for labor and equipment drives up associated costs, limiting the actual supply activities that can be accomplished under any given exploration and development budget and reducing the net benefit of higher prices for producers. For example, rates for a jackup rig in the Gulf of Mexico rose from an average of roughly $23,000 per day in January 2000 to an average of $45,000 in November—an increase of 95 percent in less than a year.³⁷

As a result of the relatively low gas prices that prevailed through most of the 1980s and 1990s and the associated industry consolidations and downsizing, trained personnel have become quite scarce. Even at elevated salaries, the availability of trained crews for drilling and other operations often are limited. Further, although investment has been higher, the period of very high prices has been relatively short—not long enough to alter price expectations strongly. Natural gas prices in 1981-1983 averaged over $3.75 per million Btu.³⁸ If relatively high natural gas prices are sustained, additional supplies will be stimulated and the short-term difficulties will be resolved over time.

U.S. imports of natural gas have also increased in response to higher prices, but import volumes generally are limited by available transportation capacity, which is fixed in the short term. Imports from Canada have increased as new cross-border capacity has come on line. Shipments of liquefied natural gas (LNG) received in Massachusetts and Louisiana have also increased in response to higher U.S. gas prices.³⁹

Imports and Exports

For the United States, international gas trade consists primarily of trade with Canada and Mexico and trade in LNG (Figure 6). Net imports accounted for 16 percent of U.S. natural gas consumption in 2000. With tight domestic supplies and growing demand for natural gas, imports are an important source of supplemental supply.

U.S. Trade with Canada

The United States is a net importer of natural gas from Canada, which provided approximately 94 percent of total U.S. imports in 2000.⁴⁰ Net imports from Canada in 2000 totaled 3.5 trillion cubic feet, 5 percent more than in 1999. The weighted average price of gas imports from Canada in 2000 was approximately $3.90 per million Btu,⁴¹ almost 20 percent lower than the average citygate price in the United States.

The 5-percent increase in net imports from Canada in 2000 followed increases of 10 percent in 1999, 5 percent in 1998, 1 percent in 1997, and 2 percent in 1996. The extraordinary growth during 1999 was the result of increased utilization of transportation capacity from three pipeline projects that were completed in 1998 and operational in 1999. New pipeline capacity added in 2000 (see “Pipelines”) contributed to the continued growth in imports.

U.S. Trade with Mexico

The United States is a net exporter of natural gas to Mexico. Pipeline exports to Mexico totaled 110 billion cubic feet in 2000,⁴² representing an increase of almost 80 percent from the 1999 total. The United States also imported approximately 6 billion cubic feet of natural gas from Mexico in 2000, a decrease of 90 percent from the 1999 level. Both the decline in imports and the increase in exports probably are attributable to increased domestic demand and relatively flat production levels for natural gas in Mexico. Natural gas demand in Mexico has shown considerable growth over the past several years primarily because of new additions of natural-gas-fired electricity generation capacity. To meet the increasing demand, investments in infrastructure for export from Texas, California, and Arizona have grown rapidly. The majority of new cross-border pipeline projects have been designed to supply natural gas to Mexico’s power producers.⁴³

LNG Trade

After nearly doubling in 1999, LNG imports continued their robust growth in 2000 to a total of 220 billion cubic feet, a 35-percent increase over 1999. Trinidad and Tobago and Qatar surpassed Algeria for the first time in 2000 as suppliers of LNG to the United States. Trinidad supplied 96 billion cubic feet of LNG, or 44 percent of total LNG imports in 2000, and Qatar supplied 46 billion cubic feet of LNG or 21 percent. Algeria continued to be a major supplier of LNG among the eight nations that export LNG to the United States (see Figure 6), with exports totaling 44 billion cubic feet or 20 percent of all LNG imports.

In 2000 the continental United States had two operational LNG receiving terminals, at Everett, Massachusetts, and Lake Charles, Louisiana. Imports into Everett totaled 99 billion cubic feet in 2000, an increase of 3 percent over 1999. Almost 81 percent of the imports received in Everett came from Trinidad, primarily under long-term arrangements. The Lake Charles facility received 124 billion cubic feet, an increase of almost 85 percent over 1999. Many of the shipments to Lake Charles were spot purchases. Algeria delivered to both facilities, primarily under long-term arrangements.

Expansion of LNG imports is expected in the near future as two other mothballed U.S. LNG receiving facilities are reopened for imports. Although the Cove Point LNG facility in Maryland has not received any shipments since 1980, it is filing an application with the FERC to resume importing LNG in 2002. The Elba Island terminal near Savannah, Georgia, has received clearance from the FERC to resume its LNG import activities and is expected to begin receiving shipments in 2002.

Storage

The ability to store natural gas is essential to the operation of the natural gas market. Withdrawals from storage provide additional gas supply during seasonal and short-term gas demand peaks, help keep pipelines and distribution systems in physical balance, and play an important role in commodity trading and management. In general storage is filled during low utilization periods (April-October) and withdrawn during high utilization periods (winter); however, increased demand for natural gas in the electricity generation sector during the traditional off-peak period in recent years has increased competition for gas to refill storage and put upward pressure on natural gas prices. In order for the storage of gas to be economical in competitive markets, the cost of storing generally should be less than the differential between the cost of natural gas in the withdrawal period and in the refill period.⁴⁴ With relatively high gas prices in mid-2000 (during the off-peak period), incentives to rebuild inventories to levels closer to the average were diminished.

During the refill season of 2000, with relatively high natural gas prices, net injections into storage were down by almost 10 percent from 1999 levels, leading to low storage levels and increased pressure on natural gas prices going into the winter of 2000-2001. Many LDCs can recover the costs of higher gas prices under cost-of-service regulation, but restructuring has placed other storage operators and marketers at greater risk of not recovering their costs. When gas demand suddenly increased in the winter of 2000-2001 and gas storage levels were well below average, gas prices reached their recent peak levels.

Up until the latest heating season (November 2000-March 2001), working gas inventories⁴⁵ at the beginning and end of the heating season had reached their “modern era” lows in 1996.⁴⁶ In March 1996, the heating season ended with 758 billion cubic feet in storage. In November 1996, the heating season began with 2,810 billion cubic feet in storage, a record low partly because of the industry’s record low starting point from which to refill inventories. The 1996-97 heating season began with a colder than normal November. Although temperatures moderated significantly in December 1996, temperatures for the entire heating season were slightly lower than average. In the three heating seasons that followed (1997-98 through 1999-2000) the weather was warmer than normal. At the national level, beginning with December 1996, 17 of the next 19 heating-season months over the ensuing 4 heating seasons were warmer than normal (using weighted heating degree-days⁴⁷ as the measure). Figure 7 shows recent storage performance with respect to both the 5-year average and lowest end-of-month inventory levels over the period 1995-1999.⁴⁸

Monthly natural gas stock levels from October 1998 through December 1999 were significantly above average, but a large net stock draw in January 2000 (780 billion cubic feet—the largest for the month of January in the modern era) brought inventory levels below the average. In March 2000, during which weather nationally was 19 percent warmer than normal, light net withdrawals allowed working gas levels to return to above average.

Although the industry ended the 1999-2000 heating season with natural gas stocks slightly above average in March 2000, rising spot prices over the next 5 months due to continued strong demand, particularly for electricity generation, inhibited gas storage refill activity. Industry experience with previous storage refill periods suggested that gas prices might fall. For example, spot prices during 1998 and 1999 averaged only $2.17 per million Btu,⁴⁹ with almost all daily prices within a fairly limited range of $1.53 per million Btu to $2.81 per million Btu (Figure 8).

As the refill season began in April 2000, spot prices exceeded $3 per million Btu—levels seen only briefly in the fall of 1999. Gas demand continued to strengthen, and prices jumped to over $4 per million Btu by the end of May 2000, then declined slightly in July and took off again in August. Although supply adjusted to the increasing prices, the adjustment occurred at a slower pace, and additional supplies were readily absorbed by a growing market. By the middle of September, spot prices had crossed the $5 per million Btu threshold.

Undoubtedly, the high prices contributed to 5 consecutive months of lower than average storage injections. By the end of August, storage levels were not only well below the 5-year average but also below the record 5-year low. In the last 6 weeks of the refill season, injections accelerated to above average rates for that point in the year as the industry now had its final opportunity to put gas in storage for the coming heating season. As of the end of October 2000, stocks stood at 2,699 billion cubic feet—a new low for the beginning of the heating season in the modern era.

The 2000-2001 heating season began with two very cold months. November and December were colder than normal and 43 and 32 percent colder (measured in heating degree days) than the previous year. By the end of December, natural gas stock levels stood at 1,720 billion cubic feet—nearly 27 percent below the 5-year average for that point in the heating season. The situation was worse in the West. In the late summer of 2000, underground storage facilities in California and New Mexico were called upon to supplement regional supplies lost because of the El Paso pipeline disruption in New Mexico in August 2000.⁵⁰ The high level of withdrawals drew down storage inventories in the region just as unseasonable weather and difficulties in the region’s electricity market developed. By the end of February 2001, inventories in the West stood at an estimated 99 billion cubic feet—less than half the average level. Nationally, working gas inventories ended the season at an estimated 718 billion cubic feet, about 5 percent below the previous end-of-season low of 758 billion cubic feet in March 1996.

A major issue facing the industry in 2001 will be the replenishment of storage to normal levels and the price implications of large net injections during the April-October refill season. More than 1.6 trillion cubic feet of gas was injected into storage during each of the past 2 years. Given the low level of stocks at the end of the 2000-2001 heating season, however, net storage injections of about 2.0 trillion cubic feet will be required just to return to the level of 2.7 trillion cubic feet recorded for November 1, 2000. The more than 400 billion cubic feet of additional gas needed for storage will be an incremental requirement of almost 2 billion cubic feet per day during the 214-day refill season, which is the equivalent of nearly 20 percent of daily net injections from April through October 2000, compared with the historical average of about 16 percent. The increased demand will continue to place upward pressure on natural gas prices in 2001.

Prices

Some price volatility in a freely traded commodity with seasonal variations in demand is normal and expected. For example, average wellhead prices for natural gas have fluctuated around $2 per million Btu for almost a decade, but for most years (excluding the winter of 1996-97), peak-month and off-peak prices have not varied by much more than 35 percent above or below the yearly average. In 2000, however, wellhead prices have varied by 100 percent or more, and the volatility of delivered end-use prices has also been severe in some cases, particularly for large industrial customers and electricity generators.

Anything that disrupts the normal cycle of supply and demand can exaggerate the volatility of natural gas prices. Such short-term disruptions can include supply disruptions—such as pipeline ruptures or closings, line freeze-ups, and storage operation failures, as well as demand surges due to cold weather or fuel switching by customers. If the growth in regional infrastructure has been constrained relative to growth in demand, the conditions for regional price differentials or price volatility are present.

Constrained pipeline capacity and infrastructure in a competitive market can result in price volatility during peak periods. Rapidly growing regions of the country are susceptible to such growing pains when the growth is not adequately anticipated. Further, unusually cold weather in the South and North, as was experienced in December 1989, can cause well freeze-ups and storage operation failures at some facilities. If demand is high and supply is curtailed for an extended period, gas prices may become quite volatile, as they did in the Northeast in 1989.

U.S. natural gas spot prices in 2000 reached levels that were unprecedented on a sustained basis.⁵¹ Spot prices in major trading centers across the country have been at higher levels than those prevailing in recent years; however, prices have shown interesting variations in some locations.

Influences on regional price patterns differ, depending on whether the markets are upstream (close to major producing areas) or downstream (close to major consuming markets). Prices rise in upstream markets generally when there is widespread expansion in demand or a supply disruption. Higher prices in upstream markets affect prices downstream as the greater commodity costs are passed along in the supply process. Prices in downstream markets may also rise with a surge in local demand or a disruption in supply to the area, both of which can result in relative scarcity of the commodity. Price increases under those conditions tend to be localized within the downstream markets.

Quarterly average prices for the most recent three quarters (third quarter 2000 through first quarter 2001) show a general increase. The Henry Hub is a key upstream market in Louisiana, based on the relatively large volumes traded there and its strategic position relative to producing and consuming markets—in the Southwest and on the Gulf Coast for production and in the Midwest and the East for consumption. The Henry Hub is often used as a benchmark for upstream spot prices in the United States. Prices at the Henry Hub rose from the third quarter and then changed little when averaged on a quarterly basis (Table 1).

This price pattern is evident also at the Chicago, Florida, and Katy markets.⁵² Average quarterly price movements in these markets are similar, subject to slight differentials reflecting local conditions and transportation costs. The differential between the Chicago and Henry Hub markets rose slightly in the fourth quarter of 2000, as brief episodes of price spikes occurred in Chicago in December. The largest differential was $5.22 per million Btu, which occurred when the industry was preparing for the Christmas holiday weekend. In each case, markets adjusted rapidly and the periods of elevated prices above the Henry Hub price were brief.

The similarity in price patterns between the Florida and Katy markets and the Henry Hub suggests that, although prices rose because of generally higher U.S. demand, there were no significant impediments hindering competitive adjustments between those markets. Price differentials for the Florida market ranged up to $1.83 per million Btu.⁵³ At the Katy market, prices varied above and below the Henry Hub price within a fairly narrow range of $0.59 and -$0.38 per million Btu. Price levels in Chicago, Florida, and at the Katy market, although high this winter relative to previous seasons, reflected the general tight gas markets prevailing across the country.

Prices at two major downstream markets, New York City and SoCal, showed significant differences from the Henry Hub price on a persistent basis. The New York City price in the third quarter of 2000 was $0.34 per million Btu above the Henry Hub price. During the fourth quarter, however, New York prices showed the influence of demand pressures. Although the average differential in October and November was only about 10 cents more than the third quarter average of $0.34 per million Btu, the maximum difference for each month grew from $0.77 to $1.18. During December, New York prices spiked at $39.02 per million Btu at the end of the month, which was $28.49 above the Henry Hub price. As elsewhere, the largest price spikes were of relatively short duration as markets adjusted both demand and supply.

The largest regional price discrepancies for any market occurred on the SoCal system, where there were extremely large differentials from the Henry Hub benchmark price. The average differential of $0.81 per million Btu in the third quarter of 2000 was eclipsed by price differentials of $7.18 and $8.75 recorded in the fourth quarter of 2000 and first quarter of 2001. The average for December at SoCal was $16.92, with a maximum differential of $49.49. Although prices settled down somewhat in January, extreme price shocks were experienced again in February, when the average differential exceeded $13 per million Btu and the maximum fell just short of $31. Although prices in March 2001 improved slightly on average, the minimum differential remained in excess of $4, suggesting that markets have not yet been able to adjust, and that difficult conditions in southern California may continue for some time to come.

Natural Gas Transmission and Distribution

Overview

The U.S. has a complex and extensive pipeline infrastructure for transporting natural gas from production areas to ultimate consumers. More than 165 U.S. intra- and interstate natural gas pipeline companies operate about 278,000 miles of transmission lines, hundreds of compressor stations and numerous storage facilities, allowing gas delivery throughout the lower 48 States. In addition, more than 1,300 LDCs provide local delivery services through another 700,000+ miles of pipeline infrastructure. In 2000, these lines transported an estimated 22.8 trillion cubic feet of natural gas from supply sources to end-use markets. As sources of new supply have developed, new pipelines have been built and a large number of existing pipelines have been expanded to increase the level of service to a growing customer base.

Regional markets in the United States have widely varying patterns of energy use and natural gas requirements. The numerous natural gas pipeline systems that have evolved over time provide transportation services to and within these end-use markets and are designed to accommodate variations. For instance, in the colder seasonal markets, regional natural gas distribution systems are designed to meet space-heating demands by residential and commercial customers and are supported by underground storage and peaking facilities. In less weather-sensitive markets, where natural gas demand is mainly for electric power generation and/or industrial usage, storage is needed less for backup and more to support short-term fluctuations in demand and pipeline transportation system balancing.

Pipelines

The natural gas pipeline network has grown substantially since 1990, with more than 20 billion cubic feet per day of interregional capacity (a 27-percent increase) added through the end of 2000. The network has also become more interconnected, its routings more complex, and business operations more efficient. New types of facilities, such as market centers, and established operations, such as underground storage facilities, have become further integrated into the national pipeline grid, allowing the system to operate with greater flexibility. The restructuring of the industry has changed the way in which network resources are used and has caused some shift in transportation routes and trading and shipping arrangements, but system reliability has continued to improve. Except during periods of extreme weather conditions or disruptions caused by isolated pipeline outages, there has been no sustained disruption of the network since the mid-1970s.

Nonetheless, the increasing growth in natural gas demand over the past several years has led to an increase in the utilization of pipelines (Figure 9) and has resulted in some pressure for expansion in several areas of the country.⁵⁴ For instance, pipeline utilization levels in parts of the West (notably, pipelines delivering gas to the California market) have recently been well above 95 percent on a continuing basis. Further increases in demand could cause capacity bottlenecks to develop.⁵⁵ Growing gas service needs in the southern Nevada area also suggest the need for system expansion there.⁵⁶

Over the past 2 years, more than 60 natural gas pipeline construction projects (35 in 1999 and 28 in 2000) have been completed and placed in service in the United States, accounting for more than 12.3 billion cubic feet per day of new pipeline capacity, an increase of 15 percent over the capacity level in 1998.⁵⁷ Since 1996, natural gas pipeline capacity has grown by more than 5 billion cubic feet per day annually in most years, totaling almost 30 billion cubic feet per day (Figure 10). Annual expenditures on pipeline development have exceeded $1.4 billion in most years (Figure 11). Expenditures on new pipeline development and major extensions and laterals to existing systems have accounted for more than 70 percent of total expenditures, with expansions to existing systems accounting for the rest. In 1999 the largest share of expenditures, totaling $1.1 billion, was for projects terminating in the Northeast. In 2000, projects terminating in the Midwest accounted for the largest share of expenditures, at $1.8 billion.

A major growth area in pipeline expansion during the past several years has been the import/export market for natural gas. Much of the pipeline construction of the past several years has been focused on expanding import capacity for Canadian gas into the U.S. Midwest and Northeast. The completion of the Maritimes and Northeast, Portland Gas Transmission, and Alliance Pipeline systems represented a 15-percent increase in overall natural gas import capacity since 1998: a 58-percent increase into the Central region (most destined for the Midwest) and a 23-percent increase into the Northeast. In addition, natural gas export capacity to Mexico has more than doubled since 1996. Export capacity to Mexico totaled 2.1 billion cubic feet per day at the end of 2000, compared with only 0.9 billion cubic feet per day in 1996.

On the supply side, expanding coalbed methane production in the Rocky Mountains area of Wyoming and Montana has increased the need for additional long-haul capacity to carry the gas to end-use markets. Although several new gathering and header systems have been built over the past 2 years to move the gas from the production field to transmission lines, not enough matching interstate pipeline capacity has been installed so far. Only in the past 6 months have proposals been made for significant expansions of the area’s interstate systems.

Current pipeline capacity levels into the Midwest region were sufficient to meet 2000-2001 winter demand, even though the first 2 months of the heating season were colder than anticipated. Because of the cold weather, the Alliance Pipeline began operation at close to full capacity shortly after service was inaugurated in December 2000. Demand in the Midwest is still growing, however,⁵⁸ and some of the capacity currently serving the region will be needed to serve the Northeast in 2002. As a result, additional capacity to the Midwest region will be needed.

In most other parts of the country, immediate pipeline capacity limitations have not surfaced, although recent proposals to develop new pipeline capacity reflect a recognition that steady growth in natural gas demand is occurring. Florida, North Carolina, and South Carolina, for instance, have experienced significant growth in natural gas demand over the past decade, but with sufficient additional pipeline capacity being installed to match the increase in demand.

While overall natural gas production dropped somewhat in the Gulf of Mexico, after several consecutive years of extensive pipeline development, installation of additional offshore Gulf of Mexico pipeline capacity has slowed. In 1997 and 1998, for instance, 14 natural gas pipeline projects were completed that added a total of 6.4 billion cubic feet per day of new pipeline capacity in the Gulf, most of which represented large-capacity pipelines connecting onshore facilities with developing offshore sites, particularly in the deepwater areas of the Gulf. During 1999-2000, 8 significant projects were completed, adding 1.8 billion cubic feet per day to the area’s pipeline capacity. The majority of these projects were built primarily to improve gathering operations and to link new and expanding producing platforms in the Gulf with recently completed offshore mainlines directed to onshore facilities.

A major factor in much of the recent installation of new natural gas pipelines and expansion of existing systems has been the construction of many new gas-fired electric power plants and cogeneration of electricity by industrial and other large users of natural gas. Moreover, since a large number of gas-fired electric power plants are currently planned for development throughout the country over the next several years, many new laterals will be needed to link the new plants to local pipeline systems. In many instances an existing local natural gas pipeline or LDC will provide the link, but some of those systems may have to be expanded to accommodate the new plants.

The quickest and least expensive way of providing additional gas transportation capacity is to increase compression on the system, if feasible. Looping (integrating a parallel pipeline with all or a portion of the system) or a combination of looping and compression would be the next least expensive capacity expansion alternative. The number of proposals over the past several years to develop new laterals or to expand capacity by increasing compression reflects growth in this trend. To date, the U.S. natural gas pipeline industry has been able to finance and install the additional infrastructure needed to accommodate the decade-long growth of the network. Barring any major disruption of financial markets, it should be able to continue doing so.

Based on 88 announced pipeline projects covering the next several years, U.S. natural gas pipeline companies have proposed to install an additional 20.8 billion cubic feet per day of capacity within the national network (Figure 12). Of the projects announced, 21 would terminate in the Northeast region. The largest amount of new capacity (5 billion cubic feet per day) would be added in the Midwest region. Several of the projects terminating in the Northeast region in 2002 represent projects that originally were proposed for 2000 but were delayed due to public opposition and/or failure on the part of the sponsors to meet regulatory filing requirements. In other areas of the country, a number of projects are planned for areas where new supply sources are being tapped, such as deepwater development in the Gulf of Mexico and expanding growth in coalbed methane production in the Rocky Mountains area. The large amount of capacity and expenditures estimated for 2002 (see Figures 10 and 11) partly reflect this situation; however, the large increase in capacity expected in 2002 also reflects a number of large new projects scheduled to be completed that year. In fact, 9 of the 37 projects that may be constructed in 2002 have capacity levels of 500 million cubic feet per day or more. Many, if not most, of those major projects have been premised on the need to serve growing electric power generation markets.

Another near-term trend that is reflected in the proposed 2001-2002 pipeline projects is the increased number and incremental capacity represented by compression-only or looping and compression expansion projects.⁵⁹ The increase use of looping and compression expansion reflects the maturity of many of the systems that make up the national network. Using these methods, pipelines can more quickly add capacity to meet increasing demand while minimizing the potential opposition, especially in heavily populated areas. Additionally, with the growth in new gas-fired electric power plants, the miles of “lateral” projects and the average capacity increases they represent have increased over the past several years.⁶⁰

Distribution System

The institutional and pipeline infrastructures associated with the local delivery of gas have been undergoing substantial adjustment and ongoing investment. Increasingly, as individual States restructure their natural gas markets, LDCs are becoming primarily transporters of natural gas. Currently, about two-thirds of the States have taken at least some steps toward increasing retail competition for residential and small commercial customers by providing a choice of fuel supplier. Large commercial and industrial consumers have had the option to purchase gas from different providers for years, whereas choice for residential and small commercial customers has only recently been made available. State regulators and lawmakers, who are responsible for designing and implementing the retail restructuring programs, have in some cases delayed implementing customer choice until they could ensure reliable service and protect the interests of captive residential and commercial customers.

The degree to which core customers are eligible to participate in choice programs varies from State to State. Some customers and State regulators have raised questions about the benefits of retail unbundling. In addition, several instances of marketer nonperformance or bankruptcy have occurred, leaving it up to LDCs, which are obligated to provide service if marketers (or third-party service providers) fail to deliver gas, to provide local delivery service. Another variation in retail choice programs is the number of marketers offering service in local markets. In some States, such as New York, more than 100 marketers are operating; in others only 2 to 5 marketers are active. Some marketers have withdrawn from certain markets because of lack of customer participation or because of eroding profitability. In Georgia, there are currently 9 marketers offering services, down from 24 marketers 16 months ago.

LDCs continue to invest in new and replacement main and service lines and local compression facilities in order to satisfy the firm service requirements of their sales and transportation customers. According to the American Gas Association, construction projects by distribution companies totaled $9.7 billion (nominal) in 1998 and 1999, a 16-percent increase from $8.4 billion in 1996 and 1997.

As the interstate and intrastate natural gas pipeline systems expand, LDCs may have to expand correspondingly. A substantial portion of the new pipeline capacity will provide additional delivery capacity to LDCs, which either are expanding their own capabilities to serve their existing service territories or are building new pipe segments to extend their systems into new neighborhoods or to serve new industrial or electric power customers. Indeed, in almost all instances, except when a pipeline developer plans to bear the full cost and risk of a new or expansion project and its recovery, interested shippers (including LDCs in the potential market area), are given an opportunity to sign up for future service on the proposed expansion in a process called an “open season.” A successful open season is a good indicator that demand is increasing or is expected to develop in the downstream market by the time the project is completed and placed in service. Any LDC that commits to the project will have plans in place to expand its system to accommodate increased supply commitments when the expanded service begins.

Challenges Facing the Natural Gas Industry

Moderating the recurrence and severity of “boom and bust” cycles while meeting increasing demand at reasonable prices is one of the major challenges facing the U.S. natural gas industry today. The most serious short-term challenge will be to increase production rapidly enough to satisfy natural gas demand at reasonable prices. The short-term challenge is inextricably woven into the investment cycles of the gas industry. Sustained high short-term natural gas prices can prompt significant new drilling investments and bring on new supply, but they can also prompt consumers to make potentially irreversible equipment investments and switch to lower cost fuel options. Both factors tend to put downward pressure on natural gas prices.

Recent events in the oil and gas industry have led some to question the industry’s ability to meet a projected 41-percent increase in domestic gas production by 2015. Periodic downturns in the gas industry, such as in the 1984-89 and 1998-99 periods, triggered significant downsizing and cutbacks in spending for exploration and development of new gas sources. Reduced spending slowed the construction of drilling rigs and other infrastructure needed to support future drilling, and continued downsizing and layoffs reduced the industry’s ability to attract qualified new employees.

The availability of capital for new natural gas production is dependent on cash flow from the industry’s sales of crude oil and natural gas. During the 1998-99 downturn, new supply development in the United States slowed considerably, and production exceeded reserve additions for the first time in 6 years. More recently, while the number of new gas well completions increased by almost 45 percent in 2000,⁶¹ gas production increased by only 3.7 percent. The discrepancy reflects, in part, the lag in production following a shift in drilling (usually about 6 to 18 months).

An example of the market complications that can occur is provided by the recent developments in California. California is the Nation’s second-largest State market for natural gas and the tenth-largest producing State. With natural gas accounting for more than 45 percent of the power generated in California,⁶² the State’s recent electricity problems have prompted greater scrutiny of natural gas markets.

Recent Challenges for Natural Gas and Electricity Markets in California

Residential and commercial demand for natural gas in California grew by an average of 1.8 percent per year from 1995 to 1999. In 1999, California’s residential and commercial sectors consumed 813 billion cubic feet of natural gas (Table 2), more than in any other State. Although 60 percent of the State’s population resides in its nine southernmost counties, more natural gas is consumed in the north, where demand for space heating is higher.

In combination, the State’s industrial and electric utility sectors consumed 1,254 billion cubic feet of natural gas in 1999, following 3.7-percent average annual growth from 1995 to 1999. In addition to manufacturers, the industrial sector includes cogeneration facilities.⁶³ For cogeneration facilities the primary product is usually heat or steam and the secondary product is electricity, usually for own use. Electricity production from these facilities is periodically sold to the power grid and is on the rise. Tremendous economic growth has been the impetus for the increase in power generation in both the industrial and electric utility sectors. The only State using more natural gas for electricity generation is Texas.

Steady increases in natural gas demand have been met by increasing gas production in California, which rose by 104 billion cubic feet between 1995 and 1999, to 372 billion cubic feet in 1999. Production, which accounted for just under 20 percent of consumption in 1999, is located solely in the southern part of the State. Much of the gas consumed in California comes from interstate pipelines delivering gas from other States and from Canada (Figure 13). The expansion of Pacific Gas Transmission Company’s Northwest pipeline in the early 1990s allowed California’s use of Canadian gas to jump by 300 billion cubic feet per year to 1,200 billion cubic feet per year in 1999.

According to the California Energy Commission (CEC), the interstate natural gas pipelines serving California (PG&E Northwest, Tuscarora, El Paso Natural, Transwestern, Kern River, and Mojave) have adequate capacity to meet current State demand, although all but Kern River and Mojave have been operating at full capacity much of the time during the past several months.⁶⁴ These interstate pipelines have the capability to deliver more than 7.5 billion cubic feet per day of summer capacity⁶⁵ to the State if needed. The current load on the State’s major internal transmission and distribution networks, however, is near 100 percent of certified capacity and periodically exceeds it.⁶⁶

A significant portion of the natural gas in storage in California is dedicated to core or high-priority customers, leaving other customers vulnerable to disruption before stocks are completely drained. Another issue, not unique to California, is that deliverability from underground storage reservoirs declines as the amount of gas remaining in storage is reduced.

California started off the 2000-2001 heating season with 152 billion cubic feet of natural gas in storage, 34 billion cubic feet below the 5-year (1995-99) average (Figure 14). During the summer of 2000, natural gas demand for electricity generation was strong due to unusually high cooling requirements. In November 2000, nuclear power outages contributed to a notable draw of 27 billion cubic feet from storage during a month when a small net addition to stocks typically occurs. Low rainfall for 1999 and 2000 in the Northwest significantly reduced hydroelectric generation and led to a sustained increase in demand for gas-fired generation. December’s call on stocks was attributed to cold weather and electricity outages caused by environmental concerns and equipment failure. Continued cold weather, electricity generation outages, and then nondelivery of supplies due to financial uncertainties caused stocks to dwindle further. By mid-February, California’s working gas inventories were estimated at less than 70 billion cubic feet, well below the 1995-1999 average of 100 billion cubic feet for the end of March, the traditional end of the heating season.

When warm weather finally returned and the financial security of the utilities improved, reports of injections to storage surfaced by the week ending March 15, 2001. As of March 23, however, stocks in the West region, which includes California, remained at half the 5-year average. If natural gas is required to meet a heavy cooling demand this summer, stocks may not be replenished at the same rate as in previous years, and the 2001-2002 heating season may open with an even smaller volume in storage than at the beginning of the past heating season.

Tightness in the balance between supply and demand is reflected in prices. Last summer, spot prices for natural gas in California moved higher as more gas was required to generate electricity. The pipeline explosion on the El Paso pipeline system in southern New Mexico in August 2000 also caused price trends in California to break from the national pattern. The next price shock took place in mid-November, when cool weather in combination with unplanned outages in the power sector caused a spike in the demand for natural gas. As a result, stocks declined rather than being supplemented.

Environmental regulations also played a role in keeping prices elevated through the end of year, as other forms of generation were idled after using their annual emissions allotments. Prices have been bid higher recently in order for financially strapped utilities to attract supplies. A Federal order requiring suppliers to provide natural gas to California’s utilities was implemented on January 19, 2001, extending through February 7, 2001.

Throughout 1998-99, spot prices for natural gas at the Henry Hub, on SoCal for large packages, and at the PG&E citygate tracked fairly closely. Beginning in June 2000, however, California prices began to diverge from Henry Hub prices (Figure 15). Thus far in 2001, the average differentials have spiked to as much as to $30.92 per million Btu⁶⁷ on SoCal (February 14) and $8.55 per million Btu on PG&E (February 15). The peak 2000-2001 heating season prices on PG&E occurred on December 9, 2000, spiking to about $50.80 per million Btu. SoCal prices peaked at a midpoint of $59.40 per million Btu 3 days later. While prices at the Henry Hub generally began to decline around the second week of January 2001, prices on the two California LDCs have persisted at high levels, with much volatility, particularly on the SoCal system.

Aside from weather and equipment failure, a key determinant of prices in the short term is how much additional planned pipeline capacity is built and placed in service. With less than 20 percent of California’s current gas demand being met from the State’s own production, the rest of its supplies must come via interstate pipelines. Currently, only 90 million cubic feet per day of new interstate natural gas pipeline capacity (only a 1-percent increase) is slated for installation in California in 2001. Intrastate receipt points will also be enlarged to receive expanded deliveries. Several projects have been proposed for the next several years, but only one has been filed with the FERC to date, and the others are only in the planning stage. If all these projects are completed, the increase in capacity will represent an 11-percent increase (about 800 million cubic feet per day) over today’s levels. Natural gas demand is projected to increase by 550 million cubic feet per day, or about 7 percent, between 2000 and 2003 according to the CEC.⁶⁸

Notes