1. Recent Trends in U.S. Natural Gas Markets

Background

Natural gas prices rose dramatically in 2000 and remained high through much of the first half of 2001. The sustained runup of prices was unprecedented in U.S. natural gas markets. Contributing to the price increases in 2000 were an increase in natural gas consumption and a decline in the productive capacity of the U.S. natural gas industry, which limited production responses. Rising prices at the beginning of the natural gas storage refill season in April 2000 resulted in lower levels of injections than normal and unusually low levels of natural gas in storage at the start of the 2000-2001 winter. Exceptionally cold weather in November and December 2000 caused spot prices to spike higher, exceeding $10 per million Btu¹on a few days in late December and early January 2001.

From late September to late November 2001, spot market prices for natural gas have fallen below $2 per million Btu on some days, and prospects for consumers in the 2001-2002 winter are much improved over last year. There is still, however, significant public interest in the outlook for natural gas prices and supplies in the longer term. This chapter summarizes the trends, conditions, and market interactions that led to the recent cycle of severe price changes.

Overview

Prices in U.S. natural gas markets were relatively stable in the 1990s. The average monthly wellhead price in the lower 48 States in 1995-1999 was $1.98 per million Btu within a range of $1.39 to $3.31.² Since 1999, however, the price trends have changed dramatically. From January 2000 to June 2001, the mean price was $4.16 per million Btu within a range of $2.53 to $7.85. Daily spot prices showed a similar pattern with an even greater overall variability. For example, spot prices at the Henry Hub peaked at $10.52 per million Btu on December 29, 2000. Although quite high, this price is not the highest ever reported at that location. The price reached $14.50 on February 2, 1996, when an unexpected cold spell hit just before a weekend.³

The most striking aspect of the recent price pattern is the fact that prices were sustained at such high levels. It was the duration of high prices, more than the level itself, that was extraordinary. As a barometer of the markets, the sustained price surge of 2000 raised concerns as to whether the circumstances behind the price increases were transitory or were part of a shift in fundamental aspects of the market.

Natural gas markets have been subject to regulatory restructuring at the Federal level since 1978, when the Natural Gas Policy Act liberalized the existing price ceilings on gas produced for interstate commerce. Subsequent Federal legislative and regulatory actions dealt with removing the remaining price ceilings on all production for interstate commerce and transferring the ownership of interstate pipelines from companies that bought, transported, stored, and sold natural gas to open-access transporters that would provide only transportation services.⁴

The conversion of interstate pipeline companies to open-access transporters altered the nature of those companies and caused a change in the structure of both the upstream and downstream markets. As open-access transporters, the pipeline companies became intermediaries that served as a bridge between a vast population of buyers and sellers within and among the markets. The change also opened up opportunities for new roles for existing suppliers and created the possibility of entirely new companies, such as gas marketers.

Regulatory restructuring of the natural gas market at the Federal level generally has been viewed as successful. Transmission costs for interstate pipeline companies have declined,⁵ and prices at all levels from the wellhead to the burner tip have been lower on average (Figure 1). These results have led some States to move toward a similar system for local distribution operations, in which local distribution companies (LDCs) would operate as open-access transporters and companies such as marketers would compete for retail sales. A number of States have already implemented comprehensive or partial restructuring of retail markets.⁶

Natural Gas Demand

In the late 1990s, the potential capability to consume natural gas expanded considerably, mainly as a result of construction of new housing heated with natural gas and new electricity generation capacity fired with natural gas. Natural gas consumption did not increase as much as might have been expected, however, because of unusually mild winters and the price competitiveness of other fuels. Total end-use consumption of natural gas increased at an average rate of 0.5 percent per year, from 19.8 trillion cubic feet in 1995 to 20.2 trillion cubic feet in 1999,⁷ with the greatest growth (3.3 percent per year) occurring in the electricity generation sector.⁸

When conditions (particularly the weather) changed in 2000, demand surged rapidly. Between 1999 and 2000, end-use consumption of natural gas increased by 3.8 percent to 20.9 trillion cubic feet (Figure 2). Natural gas consumption for electricity generation grew by 12 percent to 4.2 trillion cubic feet, accounting for 20 percent of end-use consumption. Natural gas consumption also grew substantially in the residential and commercial sectors, increasing by 5.8 percent and 7.3 percent, respectively, to 5.0 trillion cubic feet and 3.3 trillion cubic feet. Together, the residential and commercial sectors represented 40 percent of end-use natural gas consumption in 2000. Natural gas use in the industrial sector (including cogeneration of electricity), which declined by 2.2 percent to 8.4 trillion cubic feet in 2000, accounted for the other 40 percent of total end-use consumption.

Effects of Economic Growth

Strong economic growth during the 1990s boosted housing sales and new home construction. From 1991 to 1999, two-thirds of the new homes and 57 percent of the new multifamily buildings constructed were heated with natural gas (Figures 3 and 4). As the decade progressed, the share of gas-heated new homes increased from 60 to 70 percent, reaching 909,000 new units in 1999.⁹ Estimates for 2000 show the share of new natural-gas-heated homes continuing to edge higher.¹⁰ Although many new homes have more efficient furnaces, they also tend to be larger. As a result, the potential for increased consumption has grown, setting the stage for significantly higher consumption during colder weather, as happened in 2000.

There were similar increases in natural gas use in the commercial sector. The number of commercial gas customers increased from 4.6 million in 1995 to 5.1 million in 2000, while consumption rose by 6 percent.¹¹ More natural-gas-fired cogeneration capacity has also been built in the commercial sector since 1995, adding to potential demand. In 2000, the commercial sector accounted for 16 percent of natural gas consumption.

Parallel to the gradual transformation in the residential and commercial sectors, the electricity generation sector added new gas-fired generation capacity, dwarfing gains made by the other traditional generating fuels (Table 1). Between 1995 and 1999, 30.2 gigawatts of natural gas capacity was added, an increase of 18.5 percent. Overall, however, summer electricity generation capacity increased by only 21.1 gigawatts (2.8 percent) as 13.8 gigawatts of oil-fired generating capacity was taken out of service.

The expanding economy of the 1990s particularly affected manufacturing output, for which natural gas is a major fuel source. According to EIA’s most recent Manufacturing Energy Consumption Survey, general manufacturing accounted for 83.2 percent of the natural gas consumed in the industrial sector, either as a fuel or feedstock, in 1998.¹² More nautral gas is used in the industrial sector than in any other end-use sector, despite declines in industrial gas consumption since 1997 (Figure 5), in part because of a shift toward less energy-intensive industries and more efficient equipment.

Weather-Related Factors

Cold weather was a key reason for the increases in natural gas demand during 2000, particularly in the residential and commercial sectors, which use natural gas primarily for space heating. Natural gas transmission and delivery systems are designed to meet peak demand requirements. Peaks usually occur during the winter, when daily consumption in the combined residential and commercial sectors can be nearly double the annual average consumption on a per-day basis. As a result of increased demand in the electricity generation sector, the total amount of natural gas consumed in the winter has increased, and the amount of spare production and transportation capacity during peak demand periods has decreased.

The warm winters of 1997-1998 and 1998-1999, when temperatures were 8.5 percent and 9.2 percent higher than the 1960 to 1990 averages,¹³ obscured the expansion in the underlying capability to consume natural gas. During that time, the capacity of gas-consuming equipment continued to build as new gas-heated homes were added to the housing stock and gas-fired facilities were added to electricity generation capacity. When temperatures plunged in some regional markets in mid-January 2000¹⁴ and then again the following winter, demand shot to new heights, not only in the residential and commercial sectors (where a 10-percent rise in the number of heating degree days would increase aggregate natural gas consumption by an estimated 8.2 percent and 7.3 percent,¹⁵ respectively) but also in the electricity sector. Although the increase in demand in the electricity sector is small in comparison with the weather effects on residential and commercial consumption, an increase in gas-fired generation can significantly worsen an already tight supply situation.

During the winter of 2000-2001, frigid temperatures arrived early in the season with below normal levels in November and December. In December 2000, cold weather gripped the Northeast and Midwest so that, even on a national basis, heating degree days showed a 20-percent increase over 30-year norms¹⁶ and a 32-percent increase over December 1999. Natural gas consumption in the residential and commercial sectors during the month was 26.3 percent higher than the average for the preceding 5 years. Although temperatures moderated by mid-January 2001 and were near or slightly above normal in February and March 2001, the 2000-2001 heating season overall was the first colder-than-normal winter since 1995-1996.

Weather effects were also evident in the California natural gas market. The availability of hydropower had been sharply reduced by 2 years of drought in the Northwest, leaving California and other parts of the West to rely more on natural-gas-fired generation. In addition, very warm summer weather in 2000 followed by cool temperatures in the fall increased the demand for natural gas for air conditioning in the summer and for space heating in the fall. Nationally, hydropower, which provided 7 percent of the electricity generated in 2000, declined by 15 percent from 1998 to 2000. An increase in gas-fired generation—nearly doubling, from 308 billion kilowatthours in 1998 to 612 billion kilowatthours in 2000—has more than compensated for the decline in hydropower.

Competing Fuels

Dual-fuel capable equipment, found mostly in large commercial, industrial, and electricity generation applications, can be adjusted to switch between one fuel and another, sometimes in a matter of hours. The choice of which energy form to consume frequently is based on relative prices, relative combustion efficiency, availability or security of supply, emissions, and other considerations. The most common dual-fuel combinations are natural gas and distillate fuel and natural gas and residual fuel.

Natural gas citygate prices and petroleum spot prices provide an indication of the prices paid by power generators for immediate fuel supplies. The prices in the New York City area show that, since 1997, natural gas has generally been less expensive than distillate fuel but more costly than residual fuel oil (Figure 6). Despite some fluctuations in early 2000, natural gas prices had been lower than distillate prices and not much higher than residual prices, until a combination of cold weather and low stocks pushed natural gas prices higher in December 2000. Generators responded by reducing natural gas purchases and increasing petroleum consumption in those periods.

Without the flexibility provided by dual-fuel equipment, demand pressures on natural gas prices in December 2000 would have been even greater. That flexibility also is significant because it promotes interrelatedness between different fuel markets, with conditions in one market affecting conditions in another. The likely switching from relatively high priced natural gas in late 2000 to lower cost alternatives, such as petroleum fuels, probably increased demand, and hence prices, in other fuel markets.

Natural Gas Supply

Gas supplies consist of domestic production and imports of gas from foreign suppliers. In addition, gas is available from storage during the heating season. Storage gas during the non-heating season months (April-October) represents a demand item, however, because gas is injected during the off-peak months to be available for withdrawal during the heating season. Increased demand for natural gas in 2000 meant that, if supply volumes did not rise correspondingly, prices would increase. The price path since early 2000 indicates that supplies initially did not keep pace with the rapidly expanding consumption requirements.

The supply response to increased prices differs in the short run and longer run. As demand increases cause prices to rise, the prompt response is an attempt to provide a larger volume from the existing supply capacity, because changes in production capacity cannot occur immediately. Production capacity increases require some time for activities such as securing investment capital, preparing sites, installing new equipment, hiring and training personnel, and developing additional infrastructure.

If a significant amount of spare supply capacity exists, volumes can be increased in the short term by increasing utilization. Companies with spare capacity generally respond promptly to opportunities for additional sales or services. Under such conditions markets adjust primarily through volume changes. As utilization rises toward capacity limits, however, further supply increases become more difficult and costly. When utilization rates approach maximum levels, the supply becomes increasingly inelastic, and market adjustments result primarily in price increases. Higher prices reflect either the higher costs of operation or the scarcity of the commodity, and they motivate consumers either to reduce consumption or to redirect some portion of demand to substitute fuels.

Industry Response to Increased Prices

Natural gas prices in January 2000 averaged $2.40 per million Btu at the Henry Hub. Daily prices began a gradual increase that reached $3 in mid-April and $4 at the end of May, eventually to exceed $10 before the end of December. The price increases led to a number of industry actions aimed at boosting production to take advantage of the opportunity for greater revenues and profits.

Attempts by producers to increase output from existing capacity were impeded by the high utilization rates prevailing at the time. Estimated U.S. natural gas effective productive capacity¹⁷ had declined during 1999 because of a preceding falloff in gas drilling.¹⁸ Estimated capacity utilization reached 95 percent in 1999. As prices rose, drilling for gas prospects increased. Despite industry concerns about the availability of drilling rigs and personnel, the number of rotary rigs drilling for gas rose substantially in 2000 to reach 879 at the end of the year, well above the previous high set in 1997¹⁹ and more than double the most recent low of 362 gas rigs reported in April 1999.

Production from incremental drilling initially served as an offset to the effects from the prior drilling slump.²⁰ Market demand expanded so substantially, however, that for a time it was able to absorb all additional production and prices still rose. Eventually, demand expansion slowed, and productive capacity expanded sufficiently to lead to a slight decline in productive capacity utilization rates in 2000.²¹

The increase in domestic supply since early 2000 has been achieved despite a number of factors that have impeded efforts to expand production. As prices for both oil and natural gas climbed from the depressed levels of 1998-1999, many operators hedged their prices for future production at the prices available in the spring of 2000, which seemed unusually high at the time, little knowing that the price would continue to climb in successive months. Although the continuing price gains served as an incentive for additional investment, some operators had locked in prices for later production that were not as high as the prices that prevailed when the volumes were delivered. Consequently, at least some portion of the higher prices did not transfer to the companies in the form of higher revenues, limiting cash flow and reducing investment budgets from what they otherwise would have been. Another factor limiting cash flow was the need to repay debts incurred during the period of low prices in 1998 and 1999. Additional difficulties included a scarcity of drilling rigs and drilling crews, with 6- to 8-month backlogs on specific pieces of equipment, rising prices in all areas of upstream support, and the distraction of mergers or downsizing activity in significant portions of the industry.

Another factor impeding more rapid expansion of domestic production was the nature of the price increase itself. Although the high and rising prices during 2000 undoubtedly motivated high utilization of all available capacity and provided additional cash flow from which to fund investments, new project evaluations at that time were not based on the peak prices.²² Spot prices at the Henry Hub in 1998-1999 averaged $2.18 per million Btu, within a normal range of $1.54 to $2.81. When prices rose rapidly beyond $3, many investors were not sure that the prices would remain at the higher level. They required a clear pattern of sustained higher prices to have the higher prices factored into investment decisions. The judiciousness of that approach to investment evaluation is apparent in view of the subsequent falloff in prices to levels below $3 (Figure 7).

Expanded operations and new investments led to increased production. Domestic production reached 19.0 trillion cubic feet in 2000, an increase of almost 0.2 trillion cubic feet from 1999; however, the increase would not have been sufficient by itself to meet the increase in consumption of more than 0.9 trillion cubic feet. Additional supplies were needed from storage and from sources outside the United States.

Natural Gas from Foreign Sources

U.S. international gas trade consists of trade via pipeline with Canada and Mexico and trade in liquefied natural gas (LNG)²³ via trucks and tanker ships. Net imports of natural gas to the United States, which have grown steadily since 1986, accounted for 16 percent of U.S. consumption in 2000. Like domestic gas operations, natural gas imports operate on a fixed infrastructure at any particular time. Although the import infrastructure operates generally at high utilization rates, the extraordinary prices for natural gas in the latter part of 2000 led to levels that exceeded the long-term trend (Figure 8).

U.S. Trade with Canada. The United States is a net importer of natural gas from Canada. Gas imports from Canada have grown almost every year since 1986, reaching 3,544 billion cubic feet in 2000—more than 5 percent higher than in 1999 and more than four times the volume recorded in 1986. Imports from Canada represented approximately 94 percent of total U.S. natural gas imports in 2000. The weighted average border price of gas imports from Canada in 2000 was $3.90 per million Btu, about 9 percent higher than U.S. wellhead prices.

Most of the growth in imports from Canada during 2000 can be attributed to increased utilization of the Portland Pipeline and two new cross-border pipeline facilities that became operational: the Maritimes & Northeast Pipeline (Maritimes) and the Alliance Pipeline. Maritimes became operational in January 2000, providing approximately 400 million cubic feet of capacity per day. Maritimes links the Sable Island Offshore Energy Project, off Nova Scotia in the North Atlantic, to Wells, Maine, and supplies gas to the New England markets. In 2000, Maritimes shipped about 88 billion cubic feet of natural gas. The Alliance Pipeline, with a capacity of 1.3 billion cubic feet per day, crosses Alberta through Saskatchewan into North Dakota and provides service to the Chicago area markets. Alliance began operations in December 2000, when the pipeline transported 825 million cubic feet per day, or more than 63 percent of its capacity.²⁴

U.S. Trade with Mexico. The United States is a net exporter of natural gas to Mexico. Natural gas pipeline exports to Mexico totaled 105 billion cubic feet in 2000,²⁵ representing a record level of sales to Mexico and an increase of 72 percent from 1999 volumes. The United States also imported approximately 12 billion cubic feet of natural gas from Mexico in 2000, a decrease of 79 percent from the 55 billion cubic feet imported in 1999. The decline in imports and increase in exports likely were the result of increased domestic demand for natural gas and relatively flat levels of natural gas production in Mexico. Thus, Mexico was not in a good position to increase sales to the United States.

Liquefied Natural Gas Trade. After nearly doubling in 1999, LNG imports continued their robust growth during 2000, reaching 226 billion cubic feet, a 38-percent increase over the previous year. In 2000, the continental United States had two operational LNG receiving terminals: at Everett, Massachusetts, and Lake Charles, Louisiana. LNG imports serve as important supplemental gas supplies in the markets near those terminals. In 2000, imports into Everett totaled 99 billion cubic feet, an increase of 3 percent over 1999. The Lake Charles facility received 127 billion cubic feet, an increase of almost 89 percent over 1999. The key factors behind the large increases in LNG import volumes were available capacity at the importing terminals and the ability to gain use of additional tankers for transport, facilitated by attractive prices. Although less than the $3.90 paid for Canadian imports and only slightly higher than the average U.S. wellhead price of $3.58 per million Btu, the average price of $3.20 per million Btu for LNG imports in 2000 was 46 percent above the average price of $2.19 in 1999.

Natural Gas Storage

Storage facilities are essential to the U.S. natural gas industry. Underground natural gas storage inventories provide suppliers with the means to meet customer requirements during the heating season,²⁶ especially on peak demand days.²⁷ Based on the “snapshot” of storage as of the end of March 2000, the industry seemed to be in good shape: with the entire refill season ahead, inventories slightly exceeded the previous 5-year average. However, net storage injections for the first months of the refill season were well below average, primarily because of the high prevailing gas prices.

Beginning in early 2000, spot prices began to rise steadily. In mid-April, just after the beginning of the refill season, they exceeded $3 per million Btu—levels seen only briefly in the fall of 1999. By the middle of May, prices were climbing steeply and jumped to more than $4 per million Btu by the end of the month. Undoubtedly, a number of operators delayed injecting gas into storage in the hope that prices would fall. Although prices dipped briefly during July, they took off again in August and by the middle of September had crossed the $5 per million Btu threshold.

By the end of August 2000, storage levels were 2,190 billion cubic feet, which was not only well below the 5-year average but 55 billion cubic feet below the record low for the 1990s. In the last 6 weeks of the refill season, injections surged above average rates as the industry rushed to put gas in storage for the coming heating season. As of the end of October 2000, stocks stood at 2,732 billion cubic feet—the lowest level for storage at the beginning of the heating season since 1976.

The 2000-2001 heating season began with relatively cold temperatures in November and December 2000. The frigid temperatures caused a surge in demand that led to soaring prices and a rapid drawdown of storage levels. By the end of December, the spot price at the Henry Hub hit $10.52 per million Btu and stock levels stood at 1,719 billion cubic feet—nearly 27 percent below the 5-year average for that point in the heating season. With inventory levels well below expected norms, concerns emerged that they might not be sufficient to last through the heating season. Fortunately, temperatures moderated for the last 3 months of the heating season and the pace of withdrawals eased; so the deficiency between the average and current inventories did not worsen (Figure 9).

Working gas inventories at the end of the heating season were 742 billion cubic feet, 16 billion cubic feet below the previous record end-of-season low, and the Henry Hub spot price averaged slightly more than $5 per million Btu. At that time, a major concern was that the replenishment of the severely depleted storage volumes would add demand pressure to the market, with refill volumes competing against expected demand for electricity generation as cooling requirements increased during the summer. Given the still elevated prices in the spring of 2001, the prevailing view was that prices would remain high as the industry was challenged to meet the overall demand surge expected in mid-2001.

Market Adjustments in 2001

Natural gas prices have declined substantially since early 2001, and supplies have been sufficient to allow record volumes to be added to storage. EIA projects that natural gas prices will be higher in 2001 than in 2000; however, the expected high average for the year is based largely on the extraordinary prices in the early months. Prices have declined throughout 2001, and the trend is expected to continue through 2002.²⁸ Monthly wellhead gas prices are expected to average $3.98 per million Btu in 2001, with decidedly lower prices expected in the latter part of the year than in the early months. In 2002, prices are projected to average $1.91 per million Btu, which would be a 52-percent drop. This price projection reflects changes in a number of key market conditions or trends.

Natural gas demand has been affected by a slowdown in the U.S. economy and by milder temperatures. As a result, consumption in 2001 is expected to be roughly 1 trillion cubic feet lower than in 2000. Demand in the residential and commercial sectors is projected to increase slightly, by an estimated 50 billion cubic feet. The largest impact is expected in the industrial and electricity generation sectors, where combined consumption is expected to decline by 960 billion cubic feet as a result of the economic slowdown and, in part, switching to other fuels. Natural gas consumption for lease and plant fuel and for pipeline operations is expected to increase by 30 billion cubic feet in 2001.

The domestic natural gas industry continued to expand in 2001. The number of rigs drilling for gas prospects has continued to rise, to a record 1,068 in mid-July. Gas well completions have risen accordingly, increasing by 45 percent in 2000 over the 10,513 gas wells completed in 1999 and expected to surpass 20,000 wells in 2001.²⁹ The large number of gas well completions has increased effective productive capacity and resulted in the replacement of produced gas with proved reserve additions. Proved reserves of dry natural gas have increased in 6 of the past 7 years, but the net gain of 6 percent between 1999 and 2000 is by far the largest increase since EIA began estimating the Nation’s proved gas reserves in the late 1970s.³⁰ U.S. natural gas production is expected to reach 19.5 trillion cubic feet in 2001, which would be the highest level since 1974.

Gas imports from Canada are also expected to increase. Pipeline capacity newly opened in 2000 will provide larger volumes in 2001 and beyond because it will be operated over a full 12 months and utilization rates will grow from initial operation levels. With its capacity of 1.3 billion cubic feet per day, the Alliance Pipeline may play a pivotal role in satisfying some portion of the increased demand for the foreseeable future. Furthermore, in October 2000, Maritimes filed an application with the Federal Energy Regulatory Commission (FERC) requesting approval to expand its transportation capacity to eastern Massachusetts by constructing two additional pipelines, Maritimes III and Algonquin’s HubLine. This would enable the transport of an additional 360 million cubic feet per day when it becomes operational in 2002.

Natural gas demand in Mexico is expected to continue growing because of anticipated additions of natural-gas-fired electricity generation facilities. Investments in pipelines to export gas to Mexico from Texas, California, and Arizona have grown rapidly in recent years; and the trend is likely to continue. The majority of new cross-border pipeline projects have been designed to supply natural gas to electricity generators in Mexico. Although Mexico has substantial gas resources, rates of field development are not expected to be sufficient to meet growing demand, and Mexico is likely to remain a net importer of U.S. natural gas for years to come.³¹

LNG imports have considerable potential as a source of natural gas supply for the United States. Expansion of LNG imports is expected in the near future as two U.S. LNG-receiving facilities are reopened for imports. The Elba Island terminal near Savannah, Georgia, has received clearance from the FERC to resume LNG import activities, and initial shipments began in October 2001. Although the Cove Point LNG facility in Maryland has not received any shipments since 1980, in October 2001 the FERC approved an application for resumption of its operation. Imports are expected to begin arriving at the facility in 2002.³²

In an action with important implications for East Coast markets, the U.S. Coast Guard, as a result of the heightened state of national security following the September 2001 terrorist attacks in Washington, DC, and New York City, suspended LNG shipments into Boston harbor. The ban was lifted on October 12, but the Mayor of the City of Boston requested an injunction because of fears of possible attacks on the vessels. A U.S. District Court Judge refused to issue the injunction, and the first LNG tanker arrived at the nearby terminal in Everett, Massachusetts, on October 29. The Everett facility received 45 LNG shipments totaling 99 billion cubic feet in 2000. The additional gas supplies from LNG imports should help to alleviate concerns about winter supply in the New England States.

In addition to small volumes of LNG exports trucked to Mexico, the United States also exported 66 billion cubic feet of LNG to Japan by oceangoing tanker in 2000. The LNG that is exported to Japan is produced in the Cook Inlet area of Alaska and is surplus to local market needs in southern Alaska. It is sold to Japan in part because there are no LNG receiving terminals on the West Coast or pipelines to transport the gas to lower 48 markets. Renewed industry interest in LNG as a source of natural gas has led to proposals to construct West Coast facilities to take advantage of LNG from Alaska and other sources.³³

Net additions to working gas in storage during the 2001 refill season have occurred at a record pace. Working gas stocks are estimated to have reached more than 3,100 billion cubic feet by November 1, 2001, providing an additional margin above the unofficial target of 3,000 billion cubic feet for the start of the heating season and exceeding stock levels at the same time in 2000 by almost 400 billion cubic feet. For most of November 2001, attractive spot and futures prices and unseasonably warm temperatures across much of the country have contributed to a continued stock build. The buildup of 47 billion cubic feet during the first 23 days of November 2001 contrasts with the net withdrawal of almost 200 billion cubic feet during the same period in 2000. As of November 23, 2001, working gas stock levels stood at an estimated 3,156 billion cubic feet, which is 25 percent, or more than 600 billion cubic feet, higher than the 2000 level.

The large volumes of working gas in storage are expected to mitigate upward price pressures during the 2001-2002 heating season. Thus, natural gas markets appear to have met what was identified in the earlier EIA report as the most serious short-term challenge: “to increase production rapidly enough to satisfy natural gas demand at reasonable prices.”³⁴ The recent return of prices to the range observed in 1998-1999, however, was achieved with adjustments on both sides of the market.

Almost 2,400 billion cubic feet of natural gas is estimated to have been added to storage during 2001, which represents average incremental demand of 11.1 billion cubic feet per day. This is almost 4 billion cubic feet per day more than the average of 7.4 billion cubic feet per day during the 2000 refill period. Despite the additional demand pressure, prices have trended downward during this period—a clear indication that the relative supply position has improved greatly over last year. However, the expected increases in gas-consuming capacity indicate a continuing need for supply expansion to be adequate for the growing market.

The potential for natural gas consumption is expected to increase in the mid-term with the pace of new natural-gas-heated housing starts continuing at present levels. By 2005, residential natural gas consumption is expected to be 5.4 trillion cubic feet, compared with 5.0 trillion cubic feet in 2000.³⁵ Gas-fired additions to electricity generation capacity are expected to be 1.4 gigawatts in 2001, and total natural-gas-fired capacity is expected to grow by 2.4 percent per year from 2002 through 2005.³⁶ As a result, natural gas consumption to produce electricity (excluding cogeneration) in 2005 is expected to be 5.4 trillion cubic feet, compared with 4.2 trillion cubic feet in 2000.³⁷ Consumption by cogeneration facilities is also expected to increase, given the expected increase in cogeneration capacity.

As the potential for increased consumption grows in the residential and electricity generation sectors, so does the potential for weather-driven events like those documented in early and late 2000. Severe weather can result in rapid increases in demand and gas prices. Fuel switching to petroleum, reducing or halting operations, and discontinuation of service to interruptible customers will continue to be helpful in providing high-priority customers the additional natural gas supplies required during periods of peak demand.

Natural Gas Transmission Infrastructure

The natural gas infrastructure, especially transmission capacity, faced greater load requirements during 2000 as gas demand increased. Despite the increased demand for pipeline capacity, the movement of natural gas from production areas to end-use markets encountered very few infrastructure difficulties. Although the use of available natural gas pipeline capacity rose to high levels (90 to 100 percent in many locations), there were few, if any, reported sustained instances of service disruptions or capacity constraint.³⁸ The demand for natural gas appears to have approached pipeline capacity limits in some fast-growing market areas, including California, Florida, and New York; however, the conditions that underlie those situations are often short term in nature and readily resolved. For example, a localized capacity constraint that occurred periodically in the metropolitan area of Boston, Massachusetts, was alleviated when an expansion of the regional Tennessee Gas Pipeline system was completed in 2001.

The natural gas pipeline industry continues to respond to actual and projected increases in demand. Through September 2001, approximately 21 interstate natural gas pipeline projects were completed in the United States, out of a total of 59 scheduled for completion during 2001. The completed projects added 3.8 billion cubic feet per day of new capacity and 1,660 miles of pipeline to the existing 280,000-mile U.S. pipeline grid. If all the remaining scheduled 2001 projects are completed, an additional 6.5 billion cubic feet per day of capacity will be added to the network.

Market Area Influences on the Transmission System

During the past decade, natural gas pipeline capacity growth into major natural gas market areas was substantial, driven by growing demand in all segments of the consumer market. The Midwest Region showed the largest volumetric increase, 5.5 billion cubic feet per day (24 percent), and capacity into the Western Region grew by the largest percentage, 52 percent (3.0 billion cubic feet per day). The Northeast Region had both the largest percentage increase (532 percent) and volumetric increase (2.5 billion cubic feet per day) among the regions with access to Canadian supplies.

The Northeast Region’s interstate natural gas pipeline capacity is already being utilized at high load levels during peak months. Increasing demand for natural gas to feed industrial growth and new and planned natural-gas-fired electric power generators has burdened the local infrastructure, which has occasionally had transitory capacity constraint problems. At least four major pipeline expansion projects are scheduled to be completed to serve the New England market before the end of 2001, and two new local pipelines are proposed for implementation in 2002. Those six projects include the possible installation of 1.3 billion cubic feet per day of new capacity in the Boston area alone.

Elsewhere within the Northeast Region, the New York City area is the destination and focal point of a number of major pipeline expansions and new lines. Currently, approximately 3.2 billion cubic feet per day of natural gas pipeline capacity reaches the area. For example, the Cross Bay Pipeline, a joint project between Duke Energy Corporation and The Williams Companies (Transcontinental Gas Pipeline Company), would increase natural gas pipeline capacity into New York City and Long Island by 125 million cubic feet per day by late 2002, where currently only about 650 million cubic feet per day is available.

New natural gas pipeline capacity into the Northeast in 2002 could reach 0.5 billion cubic feet per day, and expansions within the region could total 1.1 billion cubic feet per day. All told, a total of more than 6.5 billion cubic feet per day of new capacity (more than 30 projects) could be installed into and within the Northeast Region, although it remains to be seen whether all the projects currently planned will garner the necessary shipper commitments to survive market and FERC scrutiny.

Pipeline capacity into the Midwest Region has grown rapidly. During the past 2 years alone (1999 and 2000), regional import capacity grew by 5 percent, primarily because of the completion of the Alliance Pipeline in 2000. Utilization of the new capacity installed in late 2000 began high and has remained so. During the past heating season (2000-2001), pipeline capacity usage averaged 90 percent and above on those pipelines importing Canadian supplies (Alliance, Northern Border, Great Lakes, and Viking pipeline systems). Yet demand for natural gas in the Midwest Region, including the southern Wisconsin area, is still growing. Several pipeline projects that have been approved or are awaiting regulatory review would provide substantial additional capacity within the region itself.

Although the California market has been the prime target of most of the recent proposals to expand natural gas pipeline capacity in the Western States, other parts of the region also have demanded increases in natural gas pipeline capacity sufficient to handle potential future growth. In Oregon and Washington, a series of proposals have been put forward to build a number of large laterals or new pipelines from the existing mainlines of Northwest Pipeline Company and PG&E Gas Transmission-NW, to serve growing natural gas markets within the northwest portion of the region. Completion of the projects would add approximately 500 million cubic feet per day of new capacity to the area by the end of 2002. An additional 700 million cubic feet per day also could be installed in 2003 if current demand growth factors, especially natural-gas-fired power plant capacity, continue to rise.

The need to supply new natural-gas-fired power plants in Arizona and Nevada is also generating proposals to expand available natural gas pipeline capacity to those areas as well. Several proposed interstate pipeline expansion projects slated to serve the California market may initially provide all or part of their capacity to markets in Arizona and Nevada. For example, the Questar Southern Trails pipeline, which will terminate at the southern California border, will provide most of its 90 million cubic feet per day of capacity at least initially to new gas-fired power plants in western Arizona. And although the Kern River Transmission Pipeline system was expanded by 135 million cubic feet per day in July 2001 to increase available capacity to California, 220 million cubic feet per day of the system’s capacity will be drawn off in 2002 to serve a new gas-fired power plant northeast of Las Vegas, Nevada. Kern River is expected to complete its system-wide expansion and double its current capacity to 1.6 billion cubic feet per day in 2003. Until then, the pipeline may have difficulty meeting the needs of both markets.

Over the next several years, as much as 2.7 billion cubic feet per day of new pipeline capacity could be installed in the Western Region if all the 17 projects currently planned are actually completed. That would represent a major reversal from 1999-2000, when pipeline capacity within and into the Western Region grew by only 49 million cubic feet per day. It remains to be seen, however, whether the market conditions shift during the interim and demand for new capacity drops. If that does happen, then it is possible that only a fraction of the currently proposed capacity actually will be installed.

Supply Influences on Transmission Capacity Expansion

The growth in natural gas consumption and production in the past several years has been accompanied by a steady increase in new pipeline capacity exiting supply areas. Expanded coalbed methane production in the Rocky Mountains area and natural gas development in the deep waters of the Gulf of Mexico have led to the installation of several new lines and proposals to construct additional pipelines exiting the areas. Between 1997 and 2000, for example, 22 natural gas pipeline projects were completed in the Gulf, adding 8.2 billion cubic feet per day of new pipeline capacity. Plans are underway for a number of new pipelines in the Gulf, including the 55-mile, 500 million cubic feet per day Canyon Express system, which will be constructed in deep water 120 miles southeast of New Orleans. Another major project announced for the Gulf is the 74-mile, 1 billion cubic feet per day Okeanos Project designed to transport gas from new platforms in the developing NaKika deepwater field.

In the Rocky Mountains, proved natural gas reserves in the Wyoming/Montana area increased by 37 percent, or 3.6 trillion cubic feet, between 1990 and 1999. To accommodate the supply growth, a number of new gathering and header systems have been built in the area. Four projects totaling 1.3 billion cubic feet per day were completed in 1999-2000 to move natural gas from the production field to transmission lines, and several proposals have been made for a significant expansion of the area’s interstate takeaway capacity (as much as 2.1 billion cubic feet per day could be added between 2001 and 2003). Proposals include several new long-haul pipelines to transport natural gas from the Cheyenne Hub in northern Colorado to interconnections with major interstate pipelines in Kansas, which would provide shippers with a substantial increase in access to Midwest markets.

Since 1998, natural gas import capacity from Canada has increased by 58 percent into the Midwest Region and by 23 percent into the Northeast Region. The installation of the Maritimes and Northeast Pipeline and the Portland Natural Gas Pipeline into the Northeast Region in 1999 (578 million cubic feet per day) provided 15 percent of the increase in natural gas import capacity from Canada that year. The completion of the Alliance Pipeline System (1.3 billion cubic feet per day) into the Midwest in 2000 represented another 10-percent increase in overall Canadian gas import capacity.

Transmission Outlook

In light of the available capacity and capacity utilization patterns, it seems unlikely that the natural gas infrastructure played a significant sustained role in the price spikes of 2000 and early 2001. The available volumes of natural gas simply were inadequate to satisfy total demand. The delivery system moved as much gas as was available to customers, albeit at prices higher than were typical through the 1990s.

Price spikes may occur this winter in localized or regional markets when demand or supply conditions shift. Such events, when limited in geographic scope, tend to be transitory. The experience in California from late 2000 to mid-2001 is a notable exception, as discussed below.³⁹

Electricity and Natural Gas Prices in California

Normally, price increases bring a market into equilibrium by both increasing supply and decreasing demand. In some cases, however, especially in the short term, either supply or demand may not readily adjust, and price increases can be extreme. Unusually high prices in California’s electricity and natural gas markets in 2000 and 2001 were caused by rigidities of supply and demand in both markets. Whether such price spikes will occur again in the future will depend on whether the rigidities in supply and demand can be alleviated.

The California Electricity Market

The unusually high wholesale prices for electricity in California reflected a sharp decline in hydroelectric supply due to low precipitation levels in the Northwest; a lack of sufficient electricity generation and transmission capacity to compensate for the reduction in hydroelectric generation; and the rigidity of electricity demand due to fixed retail prices.⁴⁰

On the electricity supply side, hydroelectric generation in the Northwest was 14 percent lower in 2000 than in 1999, amounting to a reduction of 46.4 million megawatthours in total Northwest generation. In the last 7 months of 2000, hydroelectric generation was 19 percent lower than in the same period in 1999, a decline of 28.7 million megawatthours.⁴¹ In California, natural-gas-fired generation made up some of the deficit. Total annual generation from natural-gas-fired power plants in California rose by 31.7 percent in 2000, a gain of 27.2 million megawatthours over the 1999 level; and during the last 7 months of 2000, gas-fired generation was 19.6 million megawatthours (32 percent) higher than during the same period in 1999. As a result, demand for natural gas increased, contributing to a scarcity of natural gas supplies and higher prices.

On the demand side, retail electricity prices were fixed by regulation for the two largest California utilities. The fixed retail prices, which were lower than those prevailing before the State’s restructuring plan was implemented, encouraged electricity consumers to use 6 percent more electricity during 2000 than they had in 1999, even in the face of reduced hydroelectric supplies and higher generating costs. California’s largest electric utilities operated under a regulatory requirement that they provide electricity to the State’s consumers at fixed rates, regardless of wholesale prices. The scarcity of electricity generation and the high demand caused California wholesale electricity prices to escalate to unusually high levels during the latter half of 2000 and early 2001. Blackouts were the only means for moderating peak consumption, because every available in-State and out-of-State source for electricity had been committed. Even the extremely high wholesale prices could not elicit the electricity supplies necessary to satisfy California’s electricity demand.

Building new electricity generation plants and transmission facilities in response to California’s recent electricity shortage will likely take some years. During the last 6 months of 2000, no new electricity generation plants went into operation in California. Through October 2001, 1,914 megawatts became operational (Table 2). California’s electricity generation capacity may still be inadequate, however, as a result of continuing low levels of hydroelectric generation. Hydroelectricity supply in the Northwest was 37 percent lower during the first 7 months of 2001 than it was during the first 7 months of 2000.⁴² Another 8,209 megawatts of capacity are under construction in California and are expected to go into operation by July 30, 2003. Plans for another 1,782 megawatts of new generating capacity have been approved by the State, but construction has not begun on any of those projects.

The reconnection of retail and wholesale electricity prices in California has also taken a step forward. On March 27, 2001, the California Public Utility Commission (CPUC) approved retail electricity rate increases of up to 46 percent for the State’s two largest electric utilities. As a result of the retail rate increase and a variety of conservation measures, California utility retail sales posted a modest (0.4 percent) increase during the first 7 months of 2001, from 140.4 million megawatthours in 2000 to 140.9 million megawatthours in 2001.⁴³

The California Natural Gas Market

In 1999, 83 percent of California’s natural gas supply was transported from outside the State.⁴⁴ In 2000, natural gas transmission capacity was not adequate to transport all the gas that was needed to meet demand in the California market, and natural gas prices in the State rose well above those in the rest of the U.S. gas market. A comparison of Henry Hub⁴⁵ spot prices with delivered prices to California electric utilities shows that the average annual price difference typically varied between 40 and 70 cents per thousand cubic feet from 1997 through 1999. As gas prices at the Henry Hub rose during 2000, so too did the price of gas delivered to California gas utilities. During the first half of 2000, the differential between the Henry Hub price and the delivered California price stayed within the bounds of the historic price differentials. In the latter part of 2000, however, the difference between the Henry Hub price and the delivered California gas price increased substantially. By December 2000, the average monthly price difference was over $10.00 per thousand cubic feet.⁴⁶ On some days during that month, the differences were much larger.

Interstate transmission capacity to deliver natural gas at the California border exceeds the takeaway capacity of California’s intrastate pipeline system by approximately 300 to 590 million cubic feet per day.⁴⁷ Temporary constraints on interstate pipelines also played a role in limiting supplies to California consumers. For example, on August 19, 2000, the El Paso Natural Gas pipeline experienced a rupture outside of Carlsbad, New Mexico, temporarily reducing gas transmission service. After the rupture, the Henry Hub/California price differentials for September and October rose to 86 cents per thousand cubic feet and 94 cents per thousand cubic feet, respectively, from 38 cents per thousand cubic feet in August.

Since the winter of 2000-2001, overall pipeline transmission capacity to California has been increased, but only by about 2 percent. In June 2001, Kern River Transmission brought into service its Mainline 2001 System Expansion, which added 135 million cubic feet per day of new capacity. On July 11, 2001, El Paso Natural Gas announced the return to full service of the ruptured pipe near Carlsbad, New Mexico.

Within California, Southern California Gas (SoCal) is proceeding with two projects to increase its intrastate capacity by more than 375 million cubic feet per day by January 2002 (Table 3). These two projects will expand the intrastate receipt capabilities at several points where the SoCal system interconnects with the interstate transmission systems. Pacific Gas and Electric (PG&E) had planned to increase its intrastate system capacity by 200 to 600 million cubic feet per day by January 2003,⁴⁸ but those plans are now uncertain due to PG&E’s bankruptcy. Table 3 shows other gas transmission projects expected to come into operation by the end of 2002.

Natural gas prices remained high in California through May 2001, even as they declined in other regions of the country, at least in part because local gas utilities and others in the State were injecting as much gas into storage as possible. By the end of August, however, California facilities had 186.7 billion cubic feet of working gas in storage (an increase of 33 percent over same time in 2000⁴⁹), and natural gas prices in the State had fallen to levels near the Henry Hub prices. By November 30, 2001, with gas storage facilities full,⁵⁰ prices had declined to $2.19 per million Btu at the southern California border and $2.44 per million Btu at PG&E’s citygate—not much higher than the Henry Hub price of $1.77 per million Btu on the same date.⁵¹

Mid-Term Prospects

Whether electricity generation and natural gas supplies in California will be sufficient to prevent high prices in the future is difficult to predict. The winter of 2000-2001 saw the confluence of a number of factors that might not occur again—rapidly growing electricity and gas consumption, inadequate hydroelectric generation, constrained gas and electric transmission capacity, and a nationwide scarcity of natural gas supplies. Electricity and gas suppliers, however, have an economic incentive to build facilities with sufficient capacity to meet expected demand. Whether capacity will always match California’s demand in the future cannot be predicted, especially with respect to unforeseeable circumstances, but given the economic incentive to build the facilities, one would expect any shortfalls to be temporary.

Conclusion

Although the mid-term outlook for U.S. natural gas markets and prices seems relatively stable, a key challenge facing the domestic natural gas industry over time, as stated in the earlier EIA report, is “moderating the recurrence and severity of ‘boom and bust’ cycles while meeting increasing demand at reasonable prices.” Episodes of elevated prices have occurred in the past, such as the winter of 1996-1997, but these events were short-lived, except for the most recent one from early 2000 to mid-2001. Although the difficulties in expanding supplies seem to have been transitory given the eventual turnaround in gas prices, the market experience after 1999 has indicated that the shift in domestic market practices has perhaps introduced a vulnerability to severe high price events. The shift from a regulatory framework to a competitive one has encouraged the natural gas industry to manage costs differently and more efficiently. The shift to streamlined operations and “just-in-time” principles has reduced the additional productive capacity and infrastructure that might have been available under earlier regulation to mitigate the impact of the sudden occurrence of a high level of demand.

Maintaining productive capacity for natural gas “depends on the drill bit,” as has always been true for this extractive industry. In recent years, however, the relationship between production and new drilling has intensified as the share of natural gas production from relatively new wells has increased. This trend reflects the competitive goal of managing costs more effectively and maximizing returns by accelerating the recovery of reserves. The successful technological development that supports this objective enhances the economics of all suitable prospects, but it also accelerates the exhaustion of reserves wherever applied. The implied “cushion” of spare productive capacity has shrunk correspondingly. Thus, sudden surges in demand now must be accommodated by a relatively smaller capacity margin. If the incremental demand is considerable, as happened in 2000 when an unprecedented combination of factors led to a large demand increase, the supply system may approach its productive limits, and price surges can result.

The ability to mitigate or avoid sustained price increases depends on the potential to expand supply capacity. When prices rise suddenly after a period of low prices, the industry will tend to have a portfolio that includes marginal or previously subeconomic prospects. At the then higher prices, a number of those projects may become economically attractive. Some ready prospects may be implemented quickly, but they tend to be ones that were previously uneconomical due to limited production potential. The marginal prospects generally yield relatively smaller production flows and do not increase aggregate supplies greatly until large numbers of them have been brought into production. More sizable deposits or additional exploration effort involve difficulties and delays that prolong the lag time between first actions and actual production. Chapter 2 provides more detailed discussion of this aspect of natural gas supplies.

Short-term price cycles seem inevitable in competitive markets for natural gas. When the industry operates at close to full capacity, small changes in supply and/or demand can cause significant market pressures and substantial price increases or decreases. A key facet of competition is the necessity for economic decisionmaking with regard to tradeoffs between lowering costs and maintaining supply capability to meet expected demand. When actual demand exceeds expectations, considerable strain may be imposed on the industry. The industry responds by increasing supply, but when the limits of supply capacity are approached, price increases are likely.

The capacity to consume or supply natural gas is based on an accumulation of capital that reflects the outcome of a series of investment decisions over an extended period. Significant changes in the capital stock are not achieved rapidly. The supply difficulties in 2000 do not seem to have been caused by a fundamental inadequacy, such as a serious resource limitation, because prices have since returned to levels consistent with the pattern of 1998-1999. The supply situation was at least partly attributable to the relatively low prices for an extended period that preceded the 2000-2001 spikes. Low prices led to expansion of gas-consuming equipment while discouraging further development of production prospects and needed infrastructure. Actual consumption levels were affected by weather conditions and by prices for competing fuels that limited natural gas consumption to levels that were disproportionately low relative to the underlying capacity. Unless market prices balance contemporaneous supply and demand and also provide the stimulus appropriate to maintain that balance at stable prices, recurrence of sustained price spikes is likely.

The significant price reductions and record storage additions that have occurred since May 2001 indicate that the U.S. natural gas market contains the self-correcting mechanisms associated with well-functioning markets. This bodes well for the market outlook in the short term and beyond. Domestic resources are expected to be substantial, and the potential for foreign supplies is limited only by the U.S. capacity to import, which is expandable. On the other hand, the market experience in 2000-2001 indicates that natural gas prices can be vulnerable to short-term fluctuations in market conditions.

Notes