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

1 Natural gas prices in this chapter are reported in dollars per million British thermal units (Btu). Prices originally reported in dollars per thousand cubic feet were converted using the following heat content factors (Btu per cubic foot): U.S. natural gas, 1,027; Canadian imports, 1,019; Mexican imports, 1,000; and LNG imports, 1,090. Sources: Average U.S. factor for both overall production and consumption as reported in Energy Information Administration, Annual Energy Review 2000, EIA/DOE-0384(2000) (Washington, DC, August 2001), web site www.eia.doe.gov/aer/index2000.htm. All import factors represent the averages for 1999 and 2000 as reported in Energy Information Administration, “U.S. Natural Gas Imports and Exports—2000,” Natural Gas Monthly, EIA/DOE-0130(2001/08) (Washington, DC, August 2001).

2 Prices in nominal dollars unless otherwise noted.

3 Spot prices from Natural Gas Intelligence: Daily Gas Price Index. Quoted spot prices are the average of the reported prices.

4 Corporations that own and operate interstate natural gas pipeline companies often have subsidiaries that engage in other supply activities, but they are separate enterprises required to operate “at arm’s length” from the pipeline transportation unit. Pipelines still provide storage services on behalf of others in some cases. Pipeline systems often include storage as an integral part of operations for balancing purposes, and capacity beyond a pipeline’s operational requirements is made available for other customers.

5 Energy Information Administration, Natural Gas 1996: Issues and Trends, DOE/EIA-0560(96) (Washington, DC, December 1996), Figure 8, p. 16.

6 Energy Information Administration, “Status of Natural Gas Residential Choice Programs by State,” web site www.eia.doe.gov/ oil_gas/natural_gas/restructure/restructure.html.

7 Annual natural gas volumes in this section are from EIA’s Annual Energy Outlook 2002, in order to present consumption data including utility and nonutility power generation use on a consistent basis.

8 Included in this category are electric utility companies and independent power producers. Not included are cogeneration facilities that produce electricity and another form of useful thermal output (such as heat or steam) for industrial applications.

9 U.S. Department of Housing and Urban Development and U.S. Department of Commerce, Characteristics of New Housing, C25, Table 10 (various issues).

10 Energy Information Administration, Annual Energy Outlook 2001, DOE/EIA-0383(2001) (Washington DC, December 2000), Supplemental Table 21.

11 Energy Information Administration, Natural Gas Annual 2000, DOE/EIA-0131(2000) (Washington DC, November 2001), and earlier issues, Table 1.

12 On a delivered basis. Does not include losses for electricity generation.

13 U.S. National Oceanic and Atmospheric Administration, Heating Degree Days, Historical Climatology Series 5-1, Table 3-3 (various issues).

14 Nationally, natural gas consumption in the residential and commercial sectors in January and February 2000 was only 1.3 percent higher than the average for the same months in the previous 5 years. However, the aggregate data obscure the sharp demand increases that occurred during several weeks and in some regional markets. The cold weather mainly affected New England and then extended to the Middle Atlantic States, with temperatures in the Northeast shifting from 17 percent warmer than normal to as much as 24 percent colder than normal. In total, weekly heating requirements in the Northeast increased by an estimated 40 percent. See Energy Information Administration, Impact of Interruptible Natural Gas Service on Northeast Heating Oil Demand, SR/OOG/2001-01 (Washington DC, December 2000), p. 29.

15 Energy Information Administration, Short-Term Energy Outlook (Washington DC, November 2001), Table 6.

16 Energy Information Administration, Natural Gas Monthly, DOE/EIA-0130(2001/03) (Washington, DC, March 2001), Table 26.

17 Natural gas effective productive capacity is a measure of the maximum production available from natural gas wells.

18 Energy Information Administration, “Natural Gas Productive Capacity for the Lower-48 States,” web site www.eia.doe.gov/pub/ oil_gas/natural_gas/analysis_publications/nat_gas_productive_capacity_2001/sld001.htm (May 2001).

19 Rotary rigs running have been identified as drilling for oil or gas only since 1988, and the comparison is limited to the period since then.

20 For more detail on the lagged supply response, see Chapter 2 of this report.

21 Energy Information Administration, “Natural Gas Productive Capacity for the Lower-48 States,” web site www.eia.doe.gov/pub/ oil_gas/natural_gas/analysis_publications/nat_gas_productive_capacity_2001/sld001.htm (May 2001).

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

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

24 Additional information on current capacity and planned expansions is available in Energy Information Administration, “Natural Gas Transportation—Infrastructure Issues and Operational Trends,” web site www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/natural_gas_infrastructure_issue/pdf/nginfrais.pdf (October 2001).

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

26 The heating season for natural gas markets is considered the 5-month period from November through the following March. The other 7 months, April through October, are an inventory-building period called either the “non-heating season” or “refill season.”

27 In addition to meeting winter demand loads, storage also is used for load balancing on pipeline systems, “parking” of gas between days, and capturing arbitrage opportunities.

28 Projected values for 2001 and 2002 in this section are from Energy Information Administration, Short-Term Energy Outlook, web site www.eia.doe.gov/emeu/steo/pub/contents.html (December 2001).

29 Energy Information Administration, Monthly Energy Review, November 2001, DOE/EIA-0035(2001/11) (Washington, DC, November 2001). Estimate for 2001 based on 17,090 gas wells completed in the first 10 months of 2001.

30 Energy Information Administration, Crude Oil, Natural Gas, and Natural Gas Liquids Reserves: 2000 Annual Report, DOE/EIA-0216(2000) (publication pending).

31 For example, see Energy Information Administration, Annual Energy Outlook 2002, DOE/EIA-0383(2002) (Washington, DC, December 2001).

32 The Williams Companies, Inc., “FERC Grants Certificate To Reactivate Williams’ Cove Point LNG Terminal,” News Release (October 12, 2001), web site www.williams.com/news/newsreleases/rel809.html.

33 For further discussion of proposed LNG import facilities, see Chapter 3 of this report.

34 Energy Information Administration, U.S. Natural Gas Markets: Recent Trends and Prospects for the Future, SR/OIAF/2001-02 (Washington, DC, May 2001), p. 20.

35 Energy Information Administration, Annual Energy Outlook 2002, DOE/EIA-0383(2002) (Washington, DC, December 2001), Table 13.

36 Energy Information Administration, Annual Energy Outlook 2002, DOE/EIA-0383(2002) (Washington, DC, December 2001), Table 9. Electricity generation capacity is summer capacity.

37 Energy Information Administration, 110 Annual Energy Outlook 2002, DOE/EIA-0383(2002) (Washington, DC, December 2001), Table 13.

38 A more detailed discussion of transmission systems is available Energy Information Administration, “Natural Gas Transportation—Infrastructure Issues and Operational Trends,” web site www.eia.doe.gov/pub/oil_gas/natural_gas/analysis_publications/natural_gas_infrastructure_issue/pdf/nginfrais.pdf (October 2001).

39 Additional information on California gas markets in 2000-2001 is available in Energy Information Administration, “Electricity Shortage in California: Issues for Petroleum and Natural Gas Supply,” web site www.eia.doe.gov/emeu/steo/pub/special/california/june01article/casummary.html (June 2001).

40 The high marginal cost of natural-gas-fired electricity generation also played a role.

41 These hydroelectric generation data are for the States of California, Idaho, Oregon, and Washington. The reduction in hydroelectric generation affected electricity consumers not only in California but in the entire four-State region.

42 The four-State hydroelectric generation for January through July 2000 was 110,522 million kilowatthours and for January through July 2001 was 69,539 million kilowatthours. Energy Information Administration, Electric Power Monthly, DOE/EIA-0226(2001/09) (Washington, DC, October 2001), p. 20, Table 11.

43 Energy Information Administration, Electric Power Monthly, DOE/EIA-0226(2001/09) (Washington, DC, October 2001), p. 57, Table 47.

44 Energy Information Administration, Natural Gas Annual 1999, DOE/EIA-0131(99) (Washington, DC, October 2000), p. 100, Table 45. In 1999, California dry gas production was 372 billion cubic feet, and its interstate receipts were 1,795 billion cubic feet.

45 The Henry Hub in Louisiana is the physical delivery point for NYMEX futures trading contracts. It is the largest-volume market center for natural gas in North America. The Henry Hub price is a widely used benchmark for upstream prices in the United States and is particularly representative of natural gas production prices in the Southwest and the Gulf of Mexico.

46 Natural Gas Intelligence: Daily Gas Price Index for Henry Hub prices; and Energy Information Administration, Natural Gas Monthly, DOE/EIA-0130 (various editions), Table 18.

47 Energy Information Administration, “Electricity Shortage in California: Issues for Petroleum and Natural Gas,” web site www.eia.doe.gov/emeu/steo/pub/special/california/june01article/canatgas.html.

48 California Energy Commission, Natural Gas Infrastructure Issues, P200-01-001 (Sacramento, CA, October 2001), p. 15.

49 Energy Information Administration, Natural Gas Monthly, DOE/EIA-0130(2001/10) (Washington, DC, October 2001), p. 26, Table 14.

50 The total rated capacity of the California facilities (base plus working gas) is 388.5 billion cubic feet. At the end of August 2001, the storage level for base and working gas was 433.3 billion cubic feet, exceeding the rated capacity.

51 Natural Gas Intelligence: Daily Gas Price Index.

2. Mid-Term Natural Gas Supply: Analysis of Federal Access Restrictions

52 Lease stipulations are mandated modifications to a lease. As defined in Uniform Format for Oil and Gas Lease Stipulation, prepared by the Rocky Mountain Regional Coordinating Committee (March 1989): “Stipulations are conditions, promises, or demands to be part of a lease when the environmental and planning record demonstrates the necessity for the stipulations. Stipulations, as such, are neither ‘standard’ nor ‘special,’ but rather a necessary modification of the terms of the lease. In order to accommodate the variety of resources encountered on Federal lands, stipulations are categorized as to how the stipulation modifies the lease rights, not by the resource(s) to be protected. What, why, and how this mitigation/protection is to be accomplished is determined by the land management agency through land use planning and National Environmental Policy Act (NEPA) analysis.”

53 The offshore area of the United States extending outward beyond the 3 nautical mile line in the Atlantic and Pacific and the 9 nautical mile line in the Gulf of Mexico makes up the Outer Continental Shelf.

54 The Rocky Mountain oil and gas supply region includes Arizona, Colorado, Idaho, Montana, Nevada, western New Mexico, North Dakota, South Dakota, Utah, and Wyoming.

55 Unproved resources are those resources that are estimated to exist but are not yet proven to exist. Proved reserves of natural gas as of December 31 of the report year are the estimated quantities which analysis of geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proven if economic producibility is supported by actual production or conclusive formation test (drill stem or wire line), or if economic producibility is supported by core analyses and/or electric or other log interpretations. Source: Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999, DOE/EIA-0216(99) (Washington, DC, December 2000), p. 154.

56 Technically recoverable resources are resources in accumulations producible using current recovery technology but without reference to economic profitability. These are oil and natural gas resources that may be produced at the surface from a well as a consequence of natural pressure within the subsurface reservoir, artificial lifting of oil from the reservoir to the surface, and the maintenance of reservoir pressure by fluid injection. These resources are generally conceived as existing in accumulations of sufficient size to be amenable to the application of existing recovery technology. Source: U.S. Geological Survey, National Oil and Gas Resource Assessment Team, 1995 National Assessment of United States Oil and Gas Resources, U.S. Geological Survey Circular 1118 (1995), p. 5.

57 Advanced Resources, International, “Technical Memorandum: Federal Lands Access for the NEMS Oil and Gas Supply Module,” FE 30 Support Contract: DE-AC01-99FE65607 (July 2001).

58 Advanced Resources, International, Federal Lands Analysis, Natural Gas Assessment, Southern Wyoming and Northwestern Colorado: Study Methodology and Results (May 2001); National Petroleum Council, Natural Gas: Meeting the Challenges of the Nation’s Growing Natural Gas Demand (December 1999).

59 Undiscovered resources are unproved resources that are estimated to exist in fields that have yet to be discovered.

60 Energy Information Administration, Annual Energy Outlook 2002, DOE/EIA-0383(2002) (Washington, DC, December 2001), web site www.eia.doe.gov/oiaf/aeo/.

61This is consistent with the cost factor adjustment utilized in the 1999 National Petroleum Council Study, Natural Gas: Meeting the Challenges of the Nation’s Growing Natural Gas Demand (December 1999), Volume II, Task Group Reports.

62 Total Alaskan gas production is 2.2 trillion cubic feet, with 0.6 trillion cubic feet being consumed in Alaska.

63 Both expansion at existing facilities and construction of new regasification terminals in the United States are needed to reach the net LNG import level of 1.35 trillion cubic feet per year.

3. Mid-Term Natural Gas Supply: Analysis of LNG Imports

64 Energy Information Administration, Annual Energy Outlook 2002, DOE/EIA-0383(2002) (Washington, DC, December 2001).

65 Sustainable capacity is closer to 80 percent of design capacity and varies because of differences in utilization rates, down time for maintenance, etc.

66 According to EIA’s November 2001 Short-Term Energy Outlook, first-quarter wellhead prices averaged $6.37 per thousand cubic feet, second quarter $4.55, third quarter $3.06, and fourth-quarter prices are expected to average $2.70 (all in 2001 dollars).

67 Security and safety concerns raised in the wake of the September 11th terrorist attacks regarding Cove Point’s proximity to the Calvert Cliffs nuclear facility have prompted the rehearing requests.

68 NIMBY is the acronym for “Not In My Back Yard.” It is used when residents of an area are not necessarily opposed in general to a particular facility being built, but they want it to be somewhere other than in their neighborhood, city, or even State.

69 Zeus Development Corporation, 2001 World LNG/GTL Review, p. iv.

70 Statistics on LNG trade are from D. Bamber, ed., Fundamentals of the Global LNG Industry (London, UK: Petroleum Economist, Ltd., March 2001), pp. 166-167.

71 A “train” is the term used in the industry to describe a complete processing facility.

72 Atlantic LNG Media Release (June 26, 2001).

73 Cost information is based on D. Bamber, ed., Fundamentals of the Global LNG Industry (London, UK: Petroleum Economist, Ltd., March 2001), p. 11.

74 Not only is the Boston market about as far as one could get from the major sources of U.S. conventional natural gas supplies, the geology of the region (i.e., granite) precludes the construction of nearby underground storage facilities. As a result, the Algonquin Gas Pipeline typically operated at a 40 percent annual load factor. Since storage availability serves to levelize the load for pipelines and thus reduce overall transportation costs, the lack of these facilities put the area at a distinct disadvantage.

75 The reopening of Lake Charles was one condition agreed to with Algeria as part of the Panhandle Eastern bankruptcy agreement.

76 See web site www.NEGA.com/industry_trends/about_LNG0901.html.

77 Ships are typically characterized by their cargo volume in cubic meters of LNG. Most current ships are in the 125,000 to 138,000 cubic meter gross volume range, and some 144,000 cubic meter ships are anticipated in the future. A net cargo offloaded of 130,000 cubic meters is equivalent to 2.87 billion cubic feet of methane (assuming a heat rate of 1,009 Btu per cubic foot, lower than the heat rate of most LNG delivered to U.S. markets, which is closer to 1,100 Btu per cubic foot). If cargos have heavier components, the number of cubic feet and heating value will be greater and the total amount delivered will be greater. Tanks are also characterized by liquid volume—barrels in the United States and cubic meters internationally. A 1 billion cubic foot tank is 284,778 barrels or 45,278 cubic meters. Tanks range from 0.5 to 3.5 billion cubic feet. Most new terminal tanks are in the 2 to 3.5 billion cubic feet size, and larger tanks are probable in the future.

78 Web site www.williams.com/gaspipeline/htm/releases/2001/013001.htm.

79 In 1972, the Maryland Conservation Council and the National Sierra Club went to court to stop Columbia LNG Corporation from constructing the Cove Point LNG import terminal. The issue was one of proper use of a prime natural area that had been designated by the State as a State park. The case was settled out of court. Provisions of the agreement permitted Columbia to proceed with its plans, but required major modifications to the design of its facility to protect the beach and the appearance of the shoreline. These modifications limit physical expansion onto surrounding land.

80 Web site www.epenergy.com/press/.

81 Web site www.panhandlecompanies.com/term_lng.asp.

82 In December, 1977, the DOE approved, subject to renegotiation of certain pricing provisions, a proposal to import 200 billion cubic feet of Indonesian LNG annually for 20 years into a facility to be constructed on a 210 acre site in Oxnard, California, that would be owned and operated by Western LNG terminals. Due to difficulties in negotiating new pricing provisions, regulatory delays, environmental concerns, and changes in the marketplace, the sponsors filed notice with the DOE in 1985 formally canceling the project.

83 The costs were developed by Project Technical Liaison (PTL) Associates under contract to the Energy Information Administration.

84 Extra days beyond the days agreed upon to unload the cargo are called days of demurrage. The term is also applied to a charge for delaying a steamer beyond a stipulated period.

4. Mid-Term Trends in Natural Gas Supply and Prices: Potential for Cyclic Price and Investment Behavior

85 Energy Information Administration, Annual Energy Review 2000, DOE/EIA-0384(2000) (Washington, DC, August 2001), Table 6.1, p. 177.

86 Energy Information Administration, Annual Energy Review 2000, DOE/EIA-0384(2000) (Washington, DC, August 2001), Table 8.2, p. 221. Total net electricity generation equaled 2,310 billion kilowatthours in 1983 and an estimated 3,792 billion kilowatthours in 2000.

87 Energy Information Administration, Annual Energy Review 2000, DOE/EIA-0384(2000) (Washington, DC, August 2001), Table 6.5, p. 185. Total natural gas consumption for electricity generation equaled 2.9 trillion cubic feet in 1983 and an estimated 6.3 trillion cubic feet in 2000. The 2000 figure includes both independent power production and cogeneration.

88 This is a simplification, because the mix of generation assets (i.e., hydroelectric, nuclear, coal and natural gas) varies greatly from region to region. Consequently, some areas of the country could be using natural-gas-fired capacity for baseload generation while other areas use it exclusively for peak load demand. Because more than 50 percent of all oil- and natural-gas-fired capacity is dual-fired, a capacity factor cannot be determined separately for natural-gas-based capacity. A combined capacity factor for oil- and natural-gas-fired capacity can be calculated from 1989 through 2000, during which fuel-specific electricity generation capacity data were collected by the Energy Information Administration. The average combined capacity factor was 27.7 percent in 1989 and 28.6 percent in 2000, indicating that on a national basis the capacity serves primarily intermediate and peak power loads, and that the situation did not change appreciably from 1989 through 2000.

89 The validity of this observation is not dependent on whether natural gas heating requirements and natural gas electricity generation requirements are coincident events or separate seasonal events. Although generation requirements peak during the summer cooling season, they also have a significant peak in the winter heating season, which is coincident with the natural gas space heating peak. Even so, extremely high levels of summer natural-gas-fired electricity generation could reduce winter natural gas supplies by diverting wellhead natural gas supplies away from summer storage injection. This would reduce the following winter’s working gas in storage and its ability to moderate winter price increases.

90 Base gas is gas held in permanent inventory to maintain adequate underground storage reservoir pressures and withdrawal rates; working gas is gas held for withdrawal as needed. 1988 was the first year that total natural gas storage capacity was reported. Total storage capacity is the sum of base and working gas capacity volumes. The 1988 working gas capacity volume equals the total capacity figure of 8,124 billion cubic feet minus a reported base gas volume of 3,800 billion cubic feet. The 2000 working gas capacity volume equals the total capacity figure of 8,241 billion cubic feet minus a reported base gas storage volume of 4,279 billion cubic feet. Source for total storage volume: Energy Information Administration (EIA), Natural Gas Annual 1988, Table 13, and Natural Gas Annual 2000, Table 14. Source for base gas storage volumes: EIA, Annual Energy Review 2000, Table 6.7. It should be noted that the definition of “base gas” storage volumes has some flexibility. For example, it has been reported that some storage operators withdrew base gas during the 2000-2001 winter to serve consumers. Moreover, natural gas storage facility maximum withdrawal rates are as important as the actual volume of working gas capacity, but they are not collected by EIA. Consequently, the actual capability of natural gas storage to moderate extreme price swings is neither precisely defined nor measured, although it is generally acknowledged that higher working gas storage volumes can better moderate winter natural gas price increases than can lower volumes.

91 Energy Information Administration, Annual Energy Review 2000, DOE/EIA-0384(2000) (Washington, DC, August 2001), Table 6.7.

92 Natural gas storage use moderates summer price declines and winter price increases, but it does not change the overall natural gas supply situation, because gas withdrawals normally equal gas injections over the course of a year. Gas storage contracts usually require contract parties to withdraw all the natural gas injected by the end of the winter heating season (March 31) to make the capacity available to next season’s users. Consequently, natural gas storage facilities change the timing of when natural gas supplies are made available to consumers, but they do not change whether natural gas supplies are fundamentally scarce or abundant, relative to demand.

93 1999 Canadian natural gas consumption equaled 64,921 million cubic meters or 2.29 trillion cubic feet. Source: “1999 Statistical Handbook for Canada’s Upstream Petroleum Industry,” Canadian Association of Petroleum Producers. 1999 U.S. natural gas consumption was 21.62 trillion cubic feet; Energy Information Administration, Natural Gas Annual 2000, DOE/EIA-0131(2000) (Washington, DC, November 2001), Table 1.

94 Figure 22 shows the relationship between monthly wellhead natural gas prices and the average monthly number of rigs drilling for natural gas. Drilling rig data were obtained from the Baker-Hughes web site, bakerhughes.com/investor/rig/index.htm, from which the database “US Rig Report.xls” was downloaded. The average monthly natural gas rig count equals the arithmetic average of the weekly data. In Figure 22, the average wellhead natural gas price is “led” 6 months relative to the gas rig numbers. That is, September 2001 gas rig rates are matched with March 2001 natural gas prices. Thus, the natural gas price data series encompassed the period of July 1992 through March 2001, and the gas drilling rig data series encompassed the period January 1993 through September 2001. January 1993 was chosen as the starting point for the gas drilling rig data, because 1993 appears to be the first full year in which natural gas productive capacity exceeded 90 percent, which would make drilling more responsive to prices than in the earlier period when considerable spare productive capacity existed. The correlation coefficient for the two data series is 0.804, which indicates that 80 percent of the variation in gas drilling rig levels can be explained by the variation in wellhead natural gas prices. Monthly natural gas price data series (N9190US3) from Energy Information Administration, web site http://tonto.eia.doe.gov/ oog/ftparea/wogirs/xls/ngm04vmwhprc.xls.

95 The correlation coefficient for the two data series in Figure 23 is 0.898. However, the relatively low number of data points limits the ability to make an inference from this statistic. Natural gas discoveries equal new field discoveries, plus new reservoir discoveries in old fields, plus extensions. See Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, DOE/EIA-0216 (Washington, DC, 1993 through 2000 annual reports), for detailed definitions of reserve categories. Annual average natural gas drilling rig count is the arithmetic average of the weekly gas rig counts. See footnote 94 for gas drilling rig data source.

96 A linear regression, where gas discoveries = coefficient times average annual gas rigs, yields the following results: coefficient = 25.045, standard error = 0.8557, t-statistic = 29.27, R-squared = 0.8011, Durbin-Watson statistic = 1.813.

97 For 1995 through 1999, average annual total natural gas reserve additions (i.e., natural gas discoveries plus net revisions and adjustments) equaled 19,451 billion cubic feet. In 2000, total natural gas reserve additions equaled 25,209 billion cubic feet, excluding net of sales and acquisitions. See Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, DOE/EIA-0216 (Washington, DC, 1993 through 2000 annual reports).

98 Total natural gas reserve replacement for 2000 was 131 percent when new natural gas discoveries plus net revisions and adjustments are considered and net sales and acquisitions are excluded. Only new wellhead natural gas discoveries are considered in this discussion, because new reserves are a direct result of the natural gas found through drilling activity. In contrast, reserve revisions can represent the installation of recovery equipment that is made more affordable by high natural gas prices.

99 1999 is the last data point presented because sufficient experience with a well’s production profile is necessary before its half-life can be calculated.

100 Energy Information Administration, Office of Oil and Gas, Reserves and Production Division.

101 For example, periods of high natural gas prices might induce consumers to purchase higher efficiency appliances than they would have if their decision had been based on average natural gas prices.

5. The Need for Improved Data on Natural Gas

102 Monthly storage reports had been requested in prior years on an annual survey.

103 Estimates of more current activity are provided by the Short-Term Integrated Forecasting System and released in the Short-Term Energy Outlook and as preliminary estimates in the Natural Gas Monthly.

104 The methodology for monthly estimation of the average U.S. wellhead price is presented in the Natural Gas Monthly, Appendix A, Note 8.

105 Data for the years before 2001 were collected on Form EIA-759, “Monthly Power Plant Report.”

106 A therm is equal to 100,000 Btu.