Natural Gas

Natural gas is an important source of energy in the United States. Like petroleum, natural gas is composed of hydrocarbons, which are chemical compounds containing both hydrogen and carbon. The molecular structure of hydrocarbon compounds varies from the simplest, methane, to very heavy and very complex molecules, such as those found in petroleum.

Methane, ethane, and propane are the primary constituents of natural gas, with methane making up 73% to 95% of the total. Consumer-grade natural gas is ‘‘dry gas,’’ which means that it has been processed to remove water vapor, nonhydrocarbon gases (such as helium and nitrogen), and certain compounds that liquefy during the processing (such as lease condensate and natural gas plant liquids). Lease condensate is a liquid mix of heavy hydrocarbons recovered during natural gas processing at a lease, or field separation, facility. Natural gas plant liquids are compounds such as propane and butane that are recovered as liquids at other facilities later in the processing.

The natural gas industry developed out of the petroleum industry. Wells drilled for oil often produced considerable amounts of natural gas, but early oilmen had no idea what to do with it. Originally considered a waste by-product, natural gas had no market. Even if a use for natural gas had been known at the time, there were no transmission lines to deliver it. As a result, the gas was flared, or burned off. Pictures of southeastern Texas in the early twentieth century show thousands of wooden drilling rigs, each topped with a plume of flaming gas. Even today, flaring sites are sometimes the brightest spots in nighttime satellite images, outshining even the largest urban areas.

Eventually, researchers found ways to use natural gas for lighting, cooking, and heat. In 1925 the first natural gas pipeline, more than 200 miles (322 km) long, was built from Louisiana to Texas. U.S. demand grew rapidly, especially after World War II (1939–1945). By the 1950s natural gas was providing a quarter of the nation’s energy needs. At the beginning of the twenty-first century natural gas was second only to coal in the share of U.S. energy produced. (See Table 1.1 in Chapter 1.) Crude oil was third. A vast pipeline transmission system now connects production facilities in the United States, Canada, and Mexico with natural gas distributors.

Figure 3.1 shows the overview of production and consumption of natural gas for 2007. Notice how imports make up only a small share of the natural gas that is consumed in the United States. The industrial sector consumed the largest amount of natural gas resources in 2007, and the transportation sector consumed the least amount.

Figure 3.2 shows the pattern of natural gas supply and distribution in the United States in 2006. Not all the gas withdrawn from gas and oil wells ends up as dry gas that can be immediately used; about 20% is lost during extraction and processing. Some natural gas is imported, primarily from Canada, a small amount is exported, and some is stored. Natural gas that is produced in this country, imported, and withdrawn from storage is then used immediately as fuel primarily in the residential, commercial, industrial, and electric power sectors. A small amount is used by the gas industry itself and in transportation.

The Production of Natural Gas

As mentioned previously, natural gas is produced from gas and oil wells; there is little delay between production and consumption, except for gas that is placed in storage. Therefore, changes in demand are almost immediately reflected by changes in wellhead flows, or supply.

The Energy Information Administration (EIA) reports in Annual Energy Review 2007 (June 2008, http://www.eia.doe.gov/aer/pdf/aer.pdf) that from 1970 through 1973 the total U.S. natural gas production peaked at around 21 trillion cubic feet (Tcf; 594.6 billion cubic m [bcm]). By 2007 it had dropped to 19.3 Tcf (538 bcm). (See Figure 3.3.). The EIA notes that Texas, Louisiana, and Oklahoma accounted for 38% of the natural gas produced in the United States in 2007. Even though production is increasing because of demand and rising prices, it continues to be outpaced by consumption. Imported gas makes up the difference between supply and demand.

Natural Gas Wells

In 2007 there were 427,000 gas wells in operation in the United States. (See Figure 3.4.) Even though the number of producing wells increased steadily after 1960 and more sharply after the mid-1970s, the number of gas wells in operation fluctuates from year to year because new wells are opened and old wells are closed. Weather and economic conditions also affect well operations.

The average productivity of natural gas wells peaked in 1971, then dropped throughout most of the 1970s and the mid-1980s. It has remained at a relatively steady low level since then. At the peak of productivity in 1971, U.S. natural gas wells averaged 435,000 cubic feet of natural gas per day per well. (See Figure 3.5.) In 2007 they averaged 118,000 cubic feet per day per well.

Offshore Production

Most offshore natural gas wells are located in the Gulf of Mexico and off the coast of California. Offshore wells accounted for about 3.5 Tcf (99.1 bcm) of the estimated 24.5 Tcf (693.8 bcm) of gross withdrawals of natural gas in 2007, or about 14% of the total U.S. production. (See Figure 3.6.) This percentage does not include wells off the shores of states, but includes only federal (Outer Continental Shelf) offshore wells.

Most offshore drilling occurs on the Outer Continental Shelf, in waters up to 600 feet (183 m) deep. Figure 3.7 is a diagram of a continental margin. The continental shelf varies from one coastal area to another: the shelf is relatively narrow along the Pacific coast, wide along much of the Atlantic coast and the Gulf of Alaska, and widest in the Gulf of Mexico.

The development of offshore oil and gas resources began with the drilling of the Summerland oil field along the coast of California in 1896, where about four hundred wells were drilled. Since then the industry has continually improved drilling technology. In the twenty-first century, deepwater petroleum and natural gas exploration occurs from platforms and drill ships, and shallow-water exploration occurs from gravel islands and mobile units.

Even though most natural gas is transported by pipelines, rather than by tanker ships, accidents such as the 1989 Exxon Valdez oil spill in Alaska and the 2002 Prestige oil spill off the coast of Spain have focused attention on all types of offshore drilling and tanker transport. Even before the Exxon Valdez oil spill, environmentalists were calling for the curtailment of offshore drilling for both oil and gas. The spills from refining and storage facilities triggered by Hurricane Katrina in 2005 raised additional concerns. (See Chapter 2.)

Natural Gas Reserves

Reserves are estimated volumes of gas in known deposits that are believed to be recoverable in the future. Proved reserves are those gas volumes that geological and engineering data show with reasonable certainty to be recoverable. Proved reserves of natural gas amounted to 211.1 Tcf (5.9 trillion cubic m [Tcm]) in 2006. (See Table 3.1.)

Natural gas reserves in North America are generally more abundant than crude oil reserves. In U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves: 2006 Annual Report (November 2007, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/current/pdf/arr.pdf), the EIA indicates that in 2006 Texas had the largest percentage of the U.S. dry natural gas proved reserves at 61.8 Tcf (1.7 Tcm), which represented 29% of the U.S. natural gas reserves. Wyoming had 23.5 Tcf (11%; 665.4 bcm) and New Mexico, Oklahoma, and Colorado each had over 17 Tcf (481.4 bcm), representing 8% of the proved natural gas reserves for each of these states.

According to the EIA, the North Slope fields of Alaska were estimated to contain reserves amounting to 10.2 Tcf in 2006, or 5% of the U.S. natural gas reserves. As of September 2008, there was still no easy way to transport those reserves to the lower forty-eight states, but progress was being made. The Federal Energy Regulatory Commission explains in Fifth Report to Congress on Progress Made in Licensing and Constructing the Alaska Natural Gas Pipeline (February 2008, http://www.ferc.gov/legal/staff-reports/angta-fifth.pdf) that in May 2007 the Alaska legislature passed the Alaska Gasline Inducement Act (AGIA), which allowed the state to choose an

applicant to proceed with a federal application to construct an Alaskan natural gas pipeline. In July 2008 Alaska had chosen an applicant, and in August 2008 the Alaska legislature authorized the awarding of the AGIA license to TransCanada Alaska.

Underground Storage

Because of seasonal, daily, and even hourly changes in demand, substantial natural gas storage facilities have been created. Many are depleted gas reservoirs located near transmission lines and marketing areas. Gas is injected into storage when market needs are lower than the available gas flow, and gas is withdrawn from storage when supplies from producing fields and the capacity of transmission lines are not adequate to meet peak demands. At the end of 2007 gas in underground storage totaled approximately 7.1 Tcf (198.2 bcm). This natural gas consisted of base gas (permanently stored gas needed to maintain the proper pressure in the storage area) plus working gas (gas that can be released from storage and used). (See Figure 3.8.)

Transmission of Natural Gas

A vast network of natural gas pipelines crisscrosses the United States. The natural gas in this 250,000-mile (402,000-km) system generally flows northeastward, primarily from Texas and Louisiana, the two major gas-producing states, and from Oklahoma and New Mexico. (See Figure 3.9.) It also flows west to California.

Imports of natural gas enter the United States via pipe-line from Canada into Idaho, Maine, Michigan, Montana, New Hampshire, New York, North Dakota, Washington, and Vermont. Natural gas also enters via pipeline into Texas from Mexico. According to the EIA, in Natural Gas Annual 2006 (October 2007, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/natural_gas_annual/current/pdf/nga06.pdf), 86% of imported natural gas arrived in the United States by pipeline in 2006. The remainder was shipped as liquefied natural gas, arriving by tanker from Algeria, Egypt, Nigeria, and Trinidad/Tobago. (For the amount from each country, see Figure 3.2.) Liquefied natural gas is produced by cooling natural gas to -260^° Fahrenheit (-162^° C); at this temperature natural gas changes from a gas to a liquid.

Domestic Natural Gas Consumption

Natural gas fulfills an important part of the country’s energy needs. It is an attractive fuel not only because its price is relatively low but also because it burns cleanly and efficiently, which helps the country meet its environmental goals.

Nationally, natural gas consumption rose from 1949 through 1972, then generally declined through 1986. Since 1986 natural gas consumption has been rising, hitting an all-time high of 23.3 Tcf (651.3 bcm) in 2000. (See Table 3.2.) From 2000 through 2007, prices have fluctuated slightly but remained somewhat stable.

In 2007, 7.8 Tcf (34% of the natural gas consumed; 226.5 bcm) was used by industry; 6.9 Tcf (30%; 198.2 bcm) was used by electric utilities; 4.9 Tcf (20%; 141.6 bcm) was used by residences; 3 Tcf (13%; 85 bcm) was used by commercial customers; and 0.7 Tcf (3%; 21.2 bcm) was used to transport the gas through pipelines, deliver gas to consumers, and fuel vehicles. (See Figure 3.1 and Table 3.2.)

Residential energy consumption depends heavily on weather-related heating demands and the number and types of uses of this energy source. According to the U.S. Census Bureau (June 3, 2008, http://www.census.gov/prod/2007pubs/08abstract/construct.pdf), about 52% of all residential energy consumers in the United States used gas to heat their homes in 2005. Residential consumption is also affected by conservation practices and the efficiency of gas appliances such as water heaters, stoves, and gas clothes dryers. In Natural Gas Annual 2006, the EIA lists Texas, California, Louisiana, and New York, respectively, as having been the largest residential users of natural gas by volume in 2006. According to the Census Bureau (December 22, 2006, http://www.census.gov/compendia/statab/tables/08s0013.pdf), California, Texas, and New York were the top three most populous states, in that order, as of July 1, 2006, which would help explain their high volume of natural gas consumption. Louisiana was the twenty-fifth most populous state at that time.

In 2007 the commercial sector used 3 Tcf (85 bcm) of natural gas. (See Table 3.2.) Its use, as with residential consumption, depends heavily on seasonal requirements and on the number of users and conservation measures they have taken.

The industrial sector has historically been the largest consumer of natural gas. Consumption in this sector was 7.8 Tcf (226.5 bcm) in 2007, up slightly from 7.6 Tcf (170 bcm) in 2006, but below the high of 10.2 Tcf (283.2 bcm) used in 1973. (See Table 3.2.) After 1973 natural gas consumption in the industrial sector declined quite steadily through 1986, increased through 1997, and then generally declined through 2007. Industrial use grew from 1986 through 1997 because natural gas was substituted for petroleum for some purposes.

Natural Gas Prices

Natural gas prices can vary across the nation because federal and state rate structures differ. Region also plays a role. For example, prices are lower in major natural gas–producing areas where transmission costs are lower.

From the mid-twentieth century through the early 1970s natural gas prices were relatively stable. (See Figure 3.10.) Then governmental deregulation of the industry and the restructuring of companies brought about a period of sharply rising prices, with wellhead prices (the value of natural gas at the mouth of the well) reaching a high in 1983, generally declining through 1995, and then generally increasing through 2005. Prices fell in 2006 and

2007. According to the EIA, in Annual Energy Review 2007, the average price of natural gas at the wellhead was $5.34 in real dollars (i.e., adjusted for inflation) per 1,000 cubic feet in 2007, sharply up from $2.83 in 2002.

At the retail price level (in real dollars), residential customers paid $10.87 per 1,000 cubic feet of natural gas in 2007, compared to $7.57 in 2002. (See Table 3.3.) Commercial consumers paid $9.45 per 1,000 cubic feet in 2007, and industrial consumers paid $6.36 per 1,000 cubic feet that year.

Much of the variation in natural gas prices through the years can be attributed to changes in the natural gas industry. The passage of the Natural Gas Policy Act of 1978 allowed prices at the wellhead to rise sharply. (See Figure 3.10.) On January 1, 1985, prices for new gas (that which was produced from new formations and fields or drilling after April 1977) were deregulated, and additional volumes of onshore production were deregulated on July 1, 1987. In 1988 President Ronald Reagan (1911–2004) signed legislation removing all remaining wellhead price controls by 1993.

The 1978 law not only allowed prices to go up but it also opened the market to the forces of supply and demand. Now that prices are deregulated and the industry is no longer constrained by federal controls, the natural gas industry has become more sensitive to market signals and responds more quickly to changes in economic conditions.

Natural Gas Imports and Exports

U.S. natural gas trading was limited to the neighboring countries of Mexico and Canada until shipment of natural gas in liquefied form became a feasible alternative to pipelines. In 1969 the first shipments of liquefied natural gas were sent from Alaska to Japan, and U.S. imports of liquefied natural gas from Algeria began the following year.

The EIA states in Annual Energy Review 2007 that in 2007 U.S. net imports of natural gas (total imports minus total exports) by all routes totaled 3.8 Tcf (113.2 bcm), or 16.5% of domestic consumption. Natural gas imports have been increasing significantly since 1986. Historically, Canada has been by far the major supplier of U.S. natural gas imports, accounting for 82% of the natural gas imported in 2007. (See Figure 3.11.)

The EIA notes that the United States exported 809 billion cubic feet of natural gas in 2007. (See Figure 3.11.) Canada bought the largest amount (472 billion cubic feet), followed by Mexico (288 billion cubic feet), and Japan (47 billion cubic feet).

International Natural Gas Usage

World Production

The world production of dry natural gas totaled 104.7 Tcf (2.9 Tcm) in 2006. (See Table 3.4.) Russia and the United States were the two top producers of this energy source. Russia accounted for 23.2 Tcf (651.3), or 22% of the world production, and the United States produced 18.5 Tcf (538 bcm), or 18% of the world production.

World Consumption

In Annual Energy Review 2007, the EIA shows that the world consumption of natural gas has increased steadily over the past several decades, from 52.9 Tcf (1.5 Tcm) in 1980 to 105.4 Tcf (2.9 Tcm) in 2006. The United States consumed the largest amount of natural gas in 2006, followed by Russia. (See Figure 3.12.) Combined, they accounted for 36% of world consumption in 2006.

Future Trends in the Gas Industry

The EIA predicts in Annual Energy Outlook 2008 (June 2008, http://www.eia.doe.gov/oiaf/aeo/pdf/0383(2008).pdf) that from 2006 to 2030 the total U.S. natural gas production will grow modestly. Consumption will increase through 2016 and then decrease through 2030, but its share of total energy consumption during these years will fall from 22% in 2006 to 20% in 2030. The importation of liquid natural gas from overseas will increase from 2006 to 2030, but imports of natural gas from Canada are expected to decline during this period. Natural gas prices for residential customers are projected to increase after 2016.

Domestic Production

According to the EIA, in Annual Energy Outlook 2008, total domestic natural gas production is projected to increase somewhat from 2006 (18.5 Tcf; 523.8 bcm) through 2030 (19.4 Tcf; 538 bcm), primarily from two sources: unconventional resources in the lower forty-eight states and Alaska, if a natural gas pipeline becomes operational in 2020. Other sources are expected to decline. Figure 3.13 shows projected figures for these different types of natural gas production. Unconventional sources are those from which it is more difficult and less economically sound to extract natural gas, because the technology to reach it has not been developed fully or is too expensive.

Domestic Consumption

In Annual Energy Outlook 2008, the EIA projects that consumption of natural gas will increase from 21.7 Tcf (623 bcm) in 2006 to a peak of 23.8 Tcf (679.6 bcm) in 2016. At that time the price of natural gas is projected to rise, and consumption is expected to decline to 22.7 Tcf (651.3 bcm) in 2030. Demand for natural gas by industrial consumers is expected to grow slowly because of high prices from 7.6 Tcf (212.4 bcm) in 2006 to 8.1 Tcf (226.5 bcm) in 2030. High prices will also limit growth in the residential and commercial sectors, where natural gas use will grow from a combined 7.2 Tcf (198.2 bcm) in 2006 to 8.8 Tcf (254.9 bcm) in 2030. (See Figure 3.14.) High prices will result in a projected decrease in the use of natural gas for electricity generation.

Imports and Exports

Net imports of natural gas are projected to increase to meet demand from 2006 to 2030. Most of these imports will come from overseas in the form of liquefied natural gas. (See Figure 3.15.) A decline in Canada’s non-Arctic conventional natural gas production will be only partially offset by its Arctic and unconventional production. This estimation is based on projections that the Canada natural gas pipeline will not be built by 2020 due to reportedly high costs for its construction, along with the development costs for three natural gas fields that would supply the gas. Natural gas exports to Mexico peaked in 2004 (shown as a negative import value in Figure 3.15) and then declined for a period as Mexico developed its own natural gas infrastructure. However, exports to Mexico are expected to increase again fairly steadily beginning in about 2012.