2. Recent Trends and Current Situation

6 Energy consumption data cited in this section are taken from Energy Information Administration, Monthly Energy Review, DOE/EIA-0035(01/03) (Washington, DC, March 2001), unless otherwise noted.

7 Energy Information Administration, Natural Gas Monthly, DOE/EIA-0103(2001/03) (Washington, DC, March 2001).

8 Winter is defined as November 1 through March 31.

9 Only about 91 percent of all natural gas production reaches ultimate end users. The rest is consumed or lost in its production, processing, or transmission.

10 In data collected and published by EIA, industrial sector fuel consumption currently includes fuel consumed by cogenerators, independent power producers (IPPs), and nonutility generators (NUGs). In this section, using data from Form EIA-860B, “Annual Electric Generator Report - Non-Utility” (1999), estimated consumption by IPPs and NUGs was accounted for in the electricity generation sector.

11 According to EIA’s 1994 Manufacturing Energy Consumption Survey (MECS), 39 percent of industrial natural gas consumption in 1994 could have been switched to other fuels. See Energy Information Administration, Manufacturing Consumption of Energy 1994, DOE/EIA-0512(94) (Washington, DC, December 1997), web site www.eia.doe.gov/emeu/mecs/mecs94/consumption/mecs4a.html.

12 “California Haunted by Neglect of Infrastructure,” Natural Gas Week (December 18, 2000), p. 10.

13 U.S. Census Bureau, Current Construction Reports—Characteristics of New Housing Series C25, 1989 and 1999 (Washington, DC: U.S. Department of Commerce, 1990 and 2000).

14 Includes consumption of natural gas by all electric power generators for grid-connected power except cogenerators, which produce electricity and other useful thermal energy. Gas use by IPPs and NUGs is included.

15 When cogeneration is excluded, the shares were 8.8 percent in 1996 and about 11 percent in 2000.

16 Energy Information Administration, Monthly Energy Review, DOE/EIA-0035(2001/03) (Washington, DC, March 2001).

17 Capacity additions by location and fuel type are listed in EIA’s Electric Power Monthly, DOE/EIA-0226(2001/03) (Washington, DC, March 2001).

18 Energy Information Administration, Form EIA-860A, “Annual Electric Generator Report  - Utility,” and Form EIA-860B, “Annual Electric Generator Report - Nonutility” (1999).

19 Because industry revenues come from both gas and oil production, cash flow for gas investments also is related to oil prices. Low oil prices can limit gas investments.

20 Official prices for natural gas at the New York Mercantile Exchange (NYMEX) are provided in dollars per million British thermal unit (Btu). This report follows the convention of stating prices in dollars per million Btu and consumption and production in trillion cubic feet. Monthly average wellhead prices for natural gas fell to $1.64 per million Btu ($1.68 per thousand cubic feet) in March 1999, the lowest level since November 1995, because of declining seasonal demand and growing imports from Canada. The domestic first purchase price for crude oil hit $10.87 per barrel in 1998, the lowest level for crude oil prices (after inflation adjustment) during the entire second half of the 20th century.

21 Energy Information Administration, Natural Gas Monthly, DOE/EIA-0103(2001/03) (Washington, DC, March 2001).

22 On a calendar year basis, the percentage of total production contributed by wells that are no more than 1 year old represents an average of 6 months production. This understates the relative contribution of new wells during the first 12 months of production.

23 Energy Information Administration, Natural Gas Monthly, DOE/EIA-0103(2001/03) (Washington, DC, March 2001).

24 A well is completed when it has been prepared and is ready to produce or already producing.

25 Total discoveries are those reserves attributable to field extensions, new field discoveries, and new reservoir discoveries in old fields.

26 Revisions are changes to estimates of proved reserves at the end of the prior year, resulting from new information other than an increase in proved acreage (extensions).

27 Energy Information Administration, Monthly Energy Review, DOE/EIA-0035(2001/03) (Washington, DC, March 2001), Table 5.2.

28 Energy Information Administration, Monthly Energy Review, DOE/EIA-0035(2001/03) (Washington, DC, March 2001), Table 9.11.

29 Energy Information Administration, Monthly Energy Review, DOE/EIA-0035(2001/03) (Washington, DC, March 2001), Table 5.2.

30 Energy Information Administration, Performance Profiles of Major Energy Producers 1999, DOE/EIA-0206(99) (Washington, DC, January 2001).

31 P. Meroli, “Independents Up Spending, But Not Gas Output,” Oil Daily, Vol. 51, No. 46 (March 8, 2001), pp. 1-2.

32 “Land Rig Drilling, Dayrate Boom, Produce Huge Profits for Industry,” Natural Gas Week (April 30, 2001), pp. 3-4.

33“Futures NYMEX @ Henry Hub,” Gas Daily, Financial Times (December 15, 2000), p. 4.

34“Futures NYMEX @ Henry Hub,” Gas Daily, Financial Times (March 23, 2001), p. 4.

35 B. Campbell, “Hard at Work: Independents Plan To Go the Extra Mile,” The American Oil & Gas Reporter (January 2001), pp. 43-46.

36 Energy Information Administration, Natural Gas Monthly, DOE/EIA-0103(2001/03) (Washington, DC, March 2001).

37 J. Greenberg, “Cautious Optimism Characterizes Gulf of Mexico Activity,” World Oil (January 2001), p. 112.

38 Energy Information Administration, Annual Energy Review 1999, DOE/EIA-0384(99) (Washington, DC, July 2000), Table 6.8.

39 Liquefied natural gas (LNG) is natural gas that has been liquefied by reducing its temperature to minus 260 degrees Fahrenheit at atmospheric pressure.

40 Energy Information Administration, Natural Gas Monthly, DOE/EIA-0103(2001/03) (Washington, DC, March 2001).

41 U.S. Department of Energy, Office of Fossil Energy, Natural Gas Imports and Exports Fourth Quarter Report 2000, DOE/FE-0428 (Washington, DC), based on Energy Information Administration, Natural Gas Annual 1999, DOE/EIA-0131(99) (Washington, DC, October 2000), Table B2. The thermal content of Canadian imports is assumed to be 1.019 million Btu per thousand cubic feet.

42 The United States also exported approximately 271 million cubic feet of LNG to Mexico by truck, crossing the border at Nogales, Arizona, and San Diego, California. LNG deliveries to Mexico began in 1998, when 33 million cubic feet were shipped through Nogales.

43 For a comprehensive analysis of the new pipeline projects, see U.S. Department of Energy, Office of Fossil Energy, Natural Gas Imports and Exports Fourth Quarter Report 2000, DOE/FE-0428 (Washington, DC).

44 Under regulation, supply security tends to receive greater emphasis than does the avoidance of unnecessary costs. Even under competition, high-cost storage injections may be economically justifiable as insurance against severe financial penalties for nonperformance.

45 Underground storage facilities contain working gas and base gas. Base gas is the volume of gas intended as permanent inventory in a storage reservoir to maintain adequate pressure and deliverability rates throughout the withdrawal season. Working gas is the volume of gas in the reservoir above the designed level of the base gas. Working gas is that which is available to the marketplace.

46 The “modern era” is defined here as 1980 to the present.

47 To calculate weighted heating degree-days by Census Division, State-level data on heating degree-days from the National Weather Service are multiplied by the number of residential gas customers in each State, and the products are summed for the States in each of the nine Census Divisions and then divided by the total number of residential gas customers in each Division. A similar calculation is performed at the national level to calculate national weighted heating degree-days.

48 This 5-year period was selected because it is believed that any major operational changes brought on by regulatory reform would have been in place for the 1995-96 heating season. Note that October is shown twice to illustrate that it is both the end of one heating year (a heating year runs from November 1 through October 31) and the beginning of the next.

49 The thermal content of U.S. production is 1.027 million Btu per thousand cubic feet. Based on Energy Information Administration, Natural Gas Annual 1999, DOE/EIA-0131(99) (Washington, DC, October 2000), Table B2.

50 The incident occurred at the El Paso Natural Gas Company’s Pecos River crossing in the southeast corner of New Mexico where three lines (two 30-inch and one 26-inch pipeline) cross the river. While only one 30-inch line ruptured, the other two lines were also shut down. As a result, 1.2 billion cubic feet per day, out of a normal 2.0 billion cubic feet per day, of natural gas flowing along El Paso’s southern route to its Arizona and California markets was affected for several months. In fact, as of April 27, 2001, the blown pipeline segment, although repaired, has yet to be placed back in service. The company reports, however, that with adjustments to pressure in the other two lines, flows through the repaired portion at the site approximate 90 percent of previous levels for all three lines and customer service has not been impaired.

51 Spot prices spiked periodically during the 1990s, but those episodes were of relatively short duration. For example, an unexpected cold snap in February 1996 led to a spot price at the Henry Hub of $14.00 per million Btu on February 2, exceeding the recent peak of $10.53 recorded on December 29, 2000. However, the price a week earlier in 1996 was $2.73, and a week later it had fallen by almost 60 percent to $5.75. In less than 3 weeks, the price returned to below $3 per million Btu.

52 For ease of presentation, the trading centers other than that at the Henry Hub in Louisiana are identified by their more commonly known names. The specific transactions or locations for each are as follows: Chicago—Chicago LDCs, large end-users; Florida—Florida citygates via Florida Gas Transmission; Katy—Katy plant tailgate; New York citygate—Transco Zone 6 for New York delivery; and Southern California (SoCa)l—SoCal gas, large packages.

53 Florida prices were below the Henry Hub price on two separate days during the 9-month period. On December 11, the Henry Hub price rose by $1.87 per million Btu in a single day. Consequently, the Florida price, which had roughly matched the Henry Hub price the day before, was $1.83 below the Henry Hub price for that one day.

54 Annual utilization of pipelines serving State markets varies considerably, and pipeline utilization rates during peak demand periods are significantly higher than the average annual rate.

55 The recent problems with gas deliveries into California were also financial in nature. Some natural gas suppliers have been reluctant to sell on credit to two LDCs, PG&E and SoCal, due to their dire financial situation brought on by their need to purchase large amounts of out-of-state electricity in recent months. See “California Seeks Emergency Measures for PG&E,” Gas Daily (January 17,2001), p. 1.

56 In fact, because a significant portion of the flow on the Kern River Transmission system is currently reserved by shippers moving natural gas into the Las Vegas electric power generation market, only about 60 percent of Kern’s 800 million cubic feet per day of capacity into California is currently flowing gas. To address this situation, and to respond to calls for rapid expansion of pipeline capacity to California, Kern River Transmission Company has been granted approval from the FERC to proceed with an expansion of its system (by installation of additional compression) by June 2001.

57 Total added capacity as measured on an individual project basis rather than interregional additions.

58 Proposals to build new and expanded natural gas pipelines into the Midwest over the next several years suggest that as much as 2.7 billion cubic feet per day of additional capacity into the region may be needed.

59 As compared with 1996 through 2000, when only an average of 0.75 billion cubic feet per day per year was added by completion of these types of projects, the amount of new capacity to be added in 2001 and 2002 could be as much as 2.3 and 2.6 billion cubic feet per day, respectively.

60 The average capacity of new laterals installed between 1996 and 2000 was 100 million cubic feet per day. By comparison, 261 million cubic feet per day could be added in 2001and 238 million cubic feet per day in 2002. In 2001 and 2002, 120 and 189 miles, respectively, of new laterals have been proposed, compared with an average of 98 miles per year for the previous 5 years.

61 Computed from Energy Information Administration, Monthly Energy Review, DOE/EIA-0035(2001/03) (Washington, DC, March 2001), Table 5.2.

62 Based on Energy Information Administration surveys EIA-759, “Monthly Power Plant Report,” and EIA-860B, “Annual Electric Generator Report - Non-utility,” for 1999.

63 The definition of the industrial and power sectors may be a source of confusion, because the restructuring of the electricity and natural gas industries has changed reporting requirements. EIA is currently redesigning its electricity data collection forms to correct the problem. EIA natural gas consumption data for the industrial sector currently include fuels consumed by cogenerators, independent power producers (IPPs), and nonutility generators (NUGs). Using data from Form EIA-860B, it is estimated that 499 billion cubic feet of “industrial” gas consumption in California was consumed by IPPs and NUGs. In this section, that quantity has been moved from the industrial sector to the electricity generation sector, to be consistent with the rest of the report.

64 California Energy Commission, “Natural Gas Price Increases—Frequently Asked Questions” (December 10, 2000), web site www.energy.ca.gov/naturalgas/natural_gas_faq.html.

65 Gas flows generally are lower in the summer due to ambient temperatures. Therefore, summer capacities represent a conservative estimate of pipeline capacity in winter. See Energy Information Administration, “A Snapshot of California Natural Gas Supply and Demand” (March 23, 2001), web site www.eia.doe.gov/pub/oil_gas/natural_gas/presentations/2001/snapshot_of_california/camapcap.pdf.

66 California Energy Commission, “Natural Gas Price Increases—Frequently Asked Questions” (December 10, 2000), web site www.energy.ca.gov/naturalgas/natural_gas_faq.html.

67 Assuming 1.027 million Btu per thousand cubic feet. See Energy Information Administration, Natural Gas Annual  1999, DOE/EIA-0131(99) (Washington, DC, October 2000), Table B2.

68 California Energy Commission Workshop, “Natural Gas Issues That May Affect Siting New Power Plants in California” (January 25, 2001), and California Energy Commission, “Natural Gas Price Increases—Frequently Asked Questions” (December 10, 2000), web site www.energy.ca.gov/naturalgas/natural_gas_faq.html.