Endnotes

  1. For detailed reviews of these factors, see Energy Information Administration, Performance Profiles of Major Energy Producers, 1991 and 1993 issues, DOE/EIA-0206 (Washington, DC, 1992 and 1995), Chapters 3 and 7, respectively.
  2. Energy Information Administration, Performance Profiles of Major Energy Producers 1993, DOE/EIA-0206(93) (Washington, DC, January 1995), p. 16.
  3. Consistent with EIA conversion factors, dry natural gas production is converted to crude oil equivalent at the rate of 0.18 barrels per thousand cubic feet.
  4. See the box, "Defining the Majors, Nonmajors, and Independents," for an explanation of net ownership and producers other than the majors.
  5. The last estimates of total U.S. exploration and development expenditures based on an industrywide statistical survey was in 1991 and was reported in the American Petroleum Institute, Survey of Oil and Gas Expenditures (Washington, DC, November 1992). In this report, total U.S. exploration and development expenditures for 1992 were estimated by first computing the percent change in expenditures from 1991 to 1992 for companies other than the major energy companies reporting expenditures to EIA's Financial Reporting System (FRS) that reported expenditures for both 1991 and 1992 and were included in Arthur Andersen & Co., Oil and Gas Reserve Disclosures (Chicago, IL: July 1994): This percent change from 1991-1992 was applied to the total 1991 U.S. expenditures (reported by the American Petroleum Institute) less the total for FRS companies to obtain an estimate for the independent non-FRS oil and gas producers' U.S. expenditures in 1992. This estimate, plus the actual reported 1992 expenditures of the FRS companies, yields the estimate of total U.S. expenditures for 1992. For the 1993 estimate, a similar procedure based on companies reporting expenditures in both 1992 and 1993 was applied to the 1992 estimate. For 1994 and 1995, the estimate was based on companies included in both the Arthur Andersen & Co. publication and Salomon Brothers, Inc., Survey and Analysis estimates, exclude expenditures for proved acreage.
  6. See, for example, Energy Information Administration, Performance Profiles of Major Energy Producers 1986, DOE/EIA-0206 (86) (Washington, DC, January 1986), Table 38.
  7. Reserves and production data for the majors (i.e., the FRS companies) are collected, through Form EIA-28, separately for onshore (which includes Alaska) and offshore (which includes the Federal Outer Continental Shelf and State offshore). State-by-State reserves and production data, including separate reporting of Federal Outer Continental Shelf and State offshore data, are available from the Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves. The task of deriving estimates of the majors' lower 48 onshore production and reserves is made easy by the fact that ownership (excluding royalty interests) of virtually all of the reserves and production in Alaska is attributable to the FRS companies. Thus, lower 48 onshore data for the majors is estimated as the difference between values reported as onshore on Form EIA-28 minus corresponding values (less 15 percent for royalty interest) for Alaska in the reserves report.
  8. Extraction rate = annual production/(end-of-year reserves + annual production).
  9. For companies using the full-cost method of accounting, the net value of oil and gas properties carried on the balance sheet should not exceed the present value (discount of 10 percent) of future cash flows from proved reserves. If the balance sheet value exceeds the net present value, then the balance sheet value must be reduced by the excess value. However, this accounting rule does not require any removal of oil and gas reserves from a company's books. For a detailed explanation, see Sidney Davidson and Roman L. Weil, Handbook of Modern Accounting, Third Edition (Colorado Springs, CO: Shepards/McGraw-Hill, 1983), Chapter 18, especially pp. 18-14 and 18-15.
  10. This calculation was made using successively applied sets of assumptions. The first set of assumptions was that no reserves were added or purchased over the 1989-1993 period and remaining reserves were extracted at 1989's 8.9-percent rate for the entire period. Under these assumptions, implied production in 1993 would be 546 million barrels. Next, assume reserve additions (excluding purchases of proved reserves) over the 1989-1993 period were equal to their actual values, but reserves were extracted at 1989's 8.9 percent rate for the entire period. In this case, implied 1993 production would be 768 million barrels. Thus, an estimate of the increment in 1993 production due to actual reserve additions (excluding purchases of proved reserves) is 768 million barrels - 546 million barrels = 222 million barrels. Thirdly, assume reserve additions and net purchases of proved reserves were equal to their actual values over 1989-1993 and the extraction rate was assumed equal to 8.9 percent. In this case, implied 1993 production would be 807 million barrels and the increment attributable to purchases can be estimated as 807 million barrels - 768 million barrels = 39 million barrels. Finally, the increment in 1993 production attributable to increased extraction is 935 million barrels (actual 1993 production) - 807 million barrels = 128 million barrels. Thus, the sources of increased production are reserve additions, 57 percent (i.e., 222/(935-546)); net purchases, 10 percent; and increased extraction rate, 33 percent.
  11. Offshore includes the Federal Outer Continental Shelf and State offshore areas.
  12. U.S. Department of the Interior, Minerals Management Service, Federal Offshore Statistics: 1993, MMS 94-0060 (Herndon, VA, 1994), Table 3.
  13. Direct lifting costs are the costs associated with the extraction of oil and/or natural gas from a producing property, excluding production and property taxes. Field size is measured by annual oil and gas production (barrels of crude oil equivalent) per producing well.
  14. The negative (logarithmic) relationship between direct lifting costs (per unit of offshore production) and field size (t-ratios in parentheses) was estimated utilizing the FRS data: log (Direct lifting costs) = 2.73 - 0.18 log (Field size)
    (15.88) (4.15)
    n = 769, adjusted R2 = 0.24.
  15. Average discovery size = Reserves added/wells completed, three-year weighted average.
  16. U.S. Department of the Interior, Minerals Management Service, Federal Offshore Statistics: 1993, MMS 94-0060 (Herndon, VA, 1994) p. 98.
  17. "Independents Stake Claim on Rich Gulf Reserves," The American Oil and Gas Reporter, April 1995, pp. 86, 88.
  18. For these averages, the data for the majors were taken from Energy Information Administration, Performance Profiles of Major Energy Producers 1992, DOE/EIA-0206(92) (Washington, DC, January 1994). The data for other publicly traded oil and gas companies were compiled from Arthur Andersen & Co., Oil and Gas Reserves Disclosures Database, 1989-1993 (Chicago, IL, 1994); the U.S. totals for production and number of companies came from U.S. Department of Commerce, Bureau of the Census, 1992 Census of Mineral Industries, Industry Series, Crude Petroleum and Natural Gas (July 1995). Remaining oil and gas companies = U.S. total - majors - other publicly traded oil and gas companies.
  19. U.S. Department of Commerce, Bureau of the Census, 1992 Census of Mineral Industries, Industry Series, Crude Petroleum and Natural Gas (July 1995).
  20. Based on company filings of Security and Exchange Commission Form 10K as compiled by Disclosure, Inc.
  21. See Energy Information Administration, Performance Profiles of Major Energy Producers 1986, DOE/EIA-0206(86) (Washington, DC, January 1986), Table 38.
  22. See Arthur Andersen & Co., Oil & Gas Reserve Disclosures (Chicago, IL, 1994), pp.11-12, and "Pros, Cons of Techniques Used to Calculate Oil, Gas Finding Costs," Oil and Gas Journal, June 1, 1992, pp. 93-95.
  23. Energy Information Administration, Performance Profiles of Major Energy Producers 1987, DOE/EIA-0206(87) (Washington, DC, January 1989), pp. 62-65. The calculations in this source assumed no benefits from percentage depletion.
  24. For an extensive review of alternative measures of the cost of adding oil and gas reserves, see "Pros, Cons of Techniques Used to Calculate Oil, Gas Finding Costs," Oil and Gas Journal, June 1, 1992, pp. 93-95.
  25. The difference of $2 per barrel for overall finding costs between the independents and majors and virtually no difference for reserve replacement costs suggest that the independents paid less for their purchases of proven reserves than did the majors. However, this was not the case. The cost per COE barrel of purchased reserves for the majors (in 1993 dollars) was $2.64 (based on FRS data) but $3.59 for the surviving independents (based on the Arthur Andersen and Company data base) in 1991-1993. The seeming anomaly is explained by differences in the relative importance of reserve additions gained through drilling versus purchases. For the majors, 88 percent of total reserve additions came through drilling with 12 percent gained through purchases. For the independents, 37 percent of total reserve additions were attributable to drilling but 63 percent were obtained through purchases.
  26. Energy Information Administration, Performance Profiles of Major Energy Producers 1993, DOE/EIA-0206(93) (Washington, DC, January 1995), pp. 79-83.
  27. The group of surviving independents includes entrants, defined as firms who entered the industry after 1985, and existed through 1993.
  28. Alan C. Shapiro, Modern Corporate Finance (New York; Macmillan, 1990), p. 120.
  29. The Moody's Aaa rate is given to corporate debt issutes that have the lowest risk of default.