DOE/EIA-0600

Distribution Category UC-950

Oil and Gas Development in the United States

in the Early 1990’s: An Expanded Role

for Independent Producers

October 1995

Energy Information Administration

Office of Energy Markets and End Use

U.S. Department of Energy

Washington, DC 20585

This report was prepared by the Energy Information Administration, the independent statistical and

analytical agency within the Department of Energy. The information contained herein should not be

construed as advocating or reflecting any policy position of the Department of Energy or of any other

organization.
Contacts

This report was prepared in the Office of Energy

Markets and End Use of the Energy Information

Administration, U.S. Department of Energy, under the

general direction of W. Calvin Kilgore. The project was

directed by Mark E. Rodekohr, Director of the Energy

Markets and Contingency Information Division (202)

586-1441, and Mary E. Northup, Chief of the Financial

Analysis Branch (202) 586-1445. Specific technical

information concerning this report may be obtained

from Jon A. Rasmussen (202) 586-1449 or Marie N.

Fagan (202) 586-1452.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

ii An Expanded Role for Independent Producers
Contents Page

Highlights ........................................................................... v

1. Introduction ........................................................................ 1

2. Sources of Increased Production ........................................................ 5

Oil Production ..................................................................... 5

Natural Gas Production .............................................................. 7

3. Composition of Oil and Gas Producers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Size and Numbers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Entry and Exit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

4. Resource Development Costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Resource Development Costs: The Company Perspective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Resource Development Costs: An Economywide Perspective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

5. Financial Performance of the Independent Oil and Gas Producers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Financial Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Characteristics of Surviving Producers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Appendix. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers iii
Tables Page

1. Lower 48 Onshore Oil Reserves and Production for Nonmajors, 1989-1993 ....................... 6

2. Offshore Natural Gas Reserves and Production for Nonmajors, 1986-1989 and 1990-1993 ............ 8

3. Percent Distribution of U.S. Oil and Gas Production for Majors, Independents, and Other Producers,

1985 and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

4. Sources and Uses of Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

5. Average Betas for Majors and Surviving Independent Oil and Gas Producers . . . . . . . . . . . . . . . . . . . . 23

A1. Companies Reporting to the Financial Reporting System, 1977-1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Figures

1. Percent of U.S. Oil and Gas Production, Reserves, and Exploration and Development

Expenditures for Nonmajor Oil and Gas Producers ........................................ 2

2. U.S. Oil Production by Region for Majors and Nonmajors ................................... 5

3. Extraction Rates for Lower 48 Onshore Oil Reserves ....................................... 6

4. U.S. Natural Gas Production for Majors and Nonmajors ..................................... 7

5. Offshore Development Gas Wells Completed and OCS Acreage Awarded for Nonmajors ........... 8

6. Extraction Rates for Offshore Natural Gas Reserves ........................................ 9

7. Composition of Publicly Traded Nonmajor Companies’ U.S. Oil and Gas Production . . . . . . . . . . . . . . . 12

8. Total Assets of Publicly Traded Independent Oil and Gas Producers . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

9. U.S. Reserve Replacement Costs for Majors and Publicly Traded Oil and Gas Producers . . . . . . . . . . . . 16

10. Overall Finding Costs for Majors and Publicly Traded Surviving Independents . . . . . . . . . . . . . . . . . . . 16

11. Sources of Cash for Surviving Publicly Traded Independents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

12. Total Debt to Equity for Majors, Surviving Independent Oil and Gas Producers, and the S&P 400 . . . . . 21

13. Return on Equity for Petroleum Companies and U.S. Industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

14. Ratio of Market Value to Book Value for Majors, Publicly Traded Independents, and the S&P 400 . . . . 22

15. Effective Interest Rate for Majors and Publicly Traded Independent Oil and Gas Producers . . . . . . . . . . 22

16. Return on Equity for Publicly Traded Independent Oil and Gas Producers . . . . . . . . . . . . . . . . . . . . . . 23

17. Market Value as a Percent of Book Value for Publicly Traded Independent Oil and Gas Producers . . . . 24

18. Total Debt as a Percent of Stockholders’ Equity for Publicly Traded Independent Oil and Gas Producers 24

19. Interest Expense as a Percent of Cash Flow for Publicly Traded Independent Oil and Gas Producers . . . 24

20. Interest Expense as a Percent of Total Debt for Publicly Traded Independent Oil and Gas Producers . . . 24

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

iv An Expanded Role for Independent Producers
Highlights

Since the oil price collapse of late 1985 and early 1986,

the U.S. oil and gas industry has changed dramatically.

The major oil companies have shifted much of their exploration and development efforts to targets outside the

United States. Although hundreds of nonmajor oil and

gas producers were casualties of the price collapse, the

survivors became more important players in the industry. Investment by the nonmajors in U.S. oil and gas

resource development increased from about 33 percent

of total U.S. exploration and development expenditures

in 1988-1990 to nearly 50 percent in recent years.

The increasing dependence of U.S. oil and gas

development on the typically much smaller nonmajor

companies raises a number of issues, which are

analyzed in this report. Did those companies gain

prominence by default, or have they been significantly

adding to the U.S. reserve base? What are the

characteristics of surviving producers compared with

companies that exited the industry? Do the nonmajors

add reserves at higher cost than the majors, or possibly

pay more for borrowed funds?

To identify areas of growth of nonmajor oil and gas

producers in the context of the entire U.S. industry, this

analysis first distinguishes companies as major versus

nonmajor petroleum companies. The analysis draws

heavily on data from the Energy Information Administration’s (EIA) Financial Reporting System, as well as

relying on data from EIA’s oil and gas reserves report

series.

In order to further analyze the corporate features of the

nonmajors, the companies are further classified by

characteristics such as degree of specialization and

corporate structure. In particular, the companies

specializing in oil and gas production, generally termed

the “independents,” were the ones mainly responsible

for the nonmajors’ growth in oil and gas production.

This report uses publicly available company data to

evaluate financial results and arrive at conclusions

about the independents’ standing in the capital markets.

The oil price collapse provides a backdrop to assess the

effectiveness of corporate strategy and the influence of

investor evaluations on independent oil and gas producers. The analysis highlights the differences in

resource development and financial results for firms

that survived the oil price collapse and firms that did

not survive. Comparison to the majors offers an

additional benchmark of financial and operating performance.

Chief findings of this report include:

• Offshore Gas Led Upswing in Nonmajors’ Production

Post-1986. The nonmajors’ production of natural

gas from offshore locales more than doubled in

absolute terms, from 741 billion cubic feet in 1986

to 1,526 billion cubic feet in 1993. This mainly

reflected reserve additions, but stepped-up

depletion rates also contributed to increased

production.

• Onshore Oil Focus of Growth for Nonmajors. The

nonmajors’ share of U.S. oil production from the

onshore lower 48 increased from 45 percent (835

million barrels) in 1989 to 54 percent (935 million

barrels) in 1993, due to increased production and

exit of the majors from these areas.

• Surviving Independents’ Reserve Replacement Costs

are Now Similar to Majors. The cost of reserve

replacement (including purchases) for the surviving independents decreased over the 1986-1993

period, and by the 1990’s was almost equal to that

of the majors at about $5 per barrel. However, the

overall cost of exploring for and developing oil

and gas reserves (which does not include purchases) was higher for the surviving independents

than for the majors, even into the 1990’s.

• Capital Markets Primarily Value Low Cost Reserve

Replacement. The publicly traded independent

producers that survived through 1993 tended to

incur lower costs in replacing reserves than those

companies that exited the U.S. oil and gas industry. And, in spite of greater reliance on debt

and lower returns than the majors, the publicly

traded independents’ cost of capital is comparable to the majors’. This finding indicates that the

market has tended to value low cost resource

development more than conventional measures of

financial performance.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers v
1. Introduction

As the major oil companies have shifted their upstream

investment commitments to targets outside the United

States, other, typically smaller companies have become

more prominent in U.S. oil and gas production.

Between the collapse of oil prices in 1986 and 1989,

U.S.-based major petroleum companies’ (see box

entitled “Defining the Majors, Nonmajors, and Independents”) foreign exploration and development

expenditures nearly doubled, while their U.S. expenditures declined by 14 percent. Since 1991, the majors’

foreign exploration and development expenditures have

exceeded their U.S. exploration and development

expenditures. Costs, fiscal regimes, regulations, and

other factors directly affecting profitability, as well as

geology and attitudes toward foreign investment, all

contributed to this shift in investment.1

Although the majors’ primary upstream (exploration,

development, and production) investment targets

shifted abroad, the reduced role for the majors in U.S.

oil and gas production did not become strongly

apparent until the 1990’s (Figure 1). Reductions in

spending and production by other U.S. producers

responding to the oil price collapse of 1986 and its

aftermath, together with lags inherent between exploration and development activity and production

accounted for this delay. Also, the majors did not

become net sellers of U.S. oil and gas reserves until the

1990’s.2 After the late 1980’s, the role of other producers increased. Their share of combined U.S. oil and

gas production (crude oil equivalent (COE)),3 on a net

ownership basis,4 rose from 39 percent in the 1986-1988

period to 45 percent in 1993.

Investment exhibited an even sharper upward trend.

Producers other than the majors accounted for only

about a third of total U.S. exploration and development

expenditures in 1988-1990.5 In recent years, the

comparable share has risen to nearly 50 percent.

The increasing dependence of U.S. oil and gas

development on the typically much smaller nonmajor

companies raises a number of issues. Did those companies gain increased prominence largely through the

reduced commitments of the majors or have they been

significantly adding to the U.S. reserve base? What are

the characteristics of surviving and growing producers

compared with companies exiting the U.S. oil and gas

business? Differences between the majors’ development

strategies and those of other U.S. oil and gas producers

appear considerable.6 As the mix of exploration and

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 of 1995 Worldwide Oil and Gas Exploration and Production Expenditures (January 3, 1995). It

should be noted that expenditures, and expenditure 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.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers 1
Percent

1986 1987 1988 1989 1990 1991 1992 1993 1994

30

35

40

45

50

Reserves

Production

Expenditures

0

Figure 1. Percent of U.S. Oil and Gas

Production, Reserves, and Exploration

and Development Expenditures for

Nonmajor Oil and Gas Producers

Note: Due to year-to-year volatility, expenditures are shown as

a three-year moving average. Nonmajors = Total (less 15 percent

for royalties) minus majors.

Source: Reserves and production: U.S. Total: Energy

Information Administration, U.S. Crude Oil, Natural Gas, Natural

Gas Liquids Reserves, DOE/EIA-0216(93) (Washington, DC,

October 1994). Majors: Energy Information Administration, Form

EIA-28. Expenditures: Energy Information Administration, U.S.

Energy Industry Financial Developments, 1995 First Quarter,

DOE/EIA-0543 (95/1Q) (Washington, DC, June 1995).

development strategies in U.S. oil and gas increasingly

reflects the decisions of smaller, typically more

specialized producers, what consequences can be seen

regarding the costs of adding to U.S. reserves? How are

capital markets accessed? Are U.S. oil and gas investments by the nonmajors likely to be undertaken only

with higher costs of capital? The remainder of this

report analyzes these issues.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

2 An Expanded Role for Independent Producers
Defining the Majors, Nonmajors, and Independents

The Energy Information Administration (EIA) collects annual financial and operating information from companies

that are determined to be major energy producers. In 1993, the latest year of data availability, 25 companies

(the “majors”) reported on Form EIA-28 (Financial Reporting System (FRS)).a Information is reported on a net

ownership basis. Net ownership includes all of a company’s fractional ownership shares in oil and gas

properties but excludes royalty interests.

EIA also collects annual data on U.S. reserves of oil (crude oil and natural gas liquids) and natural gas,

changes in reserves, and production from reserves.b These data are collected on an operator basis, rather than

an ownership basis, and include royalty interests. However, reserves and production on a net ownership basis

for companies other than the majors can be estimated. Royalty interests are about 15 percent of U.S. oil and

gas production. Aggregate estimates of reserves, production, and changes in reserves for companies other

than the majors (“nonmajors”) can be obtained by subtracting the FRS totals from the U.S. totals, excluding

royalty interests. In Chapters 1 and 2, this aggregate of net ownership interest other than the majors will be

termed “nonmajors.” This dichotomy will prove useful in understanding the structure and performance of the

U.S. oil and gas industry.

Most of the nonmajors are specialized oil and gas producers, often referred to as “independents.” However,

other types of companies, such as pipeline and refinery operators, account for a significant share of U.S. oil

and gas production and reserves. Since the distinctions among the nonmajors will help in understanding the

structure and performance of the U.S. oil and gas industry, differences among these company groups will be

addressed in Chapters 3 through 5.c

a

A list of the companies included in the FRS and the criteria for respondent selection are in the Appendix.

b

These data are presented annually in Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves,

DOE/EIA-0216 (Washington, DC). c

A small number of foreign subsidiaries are included in other operations.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers 3
2. Sources of Increased Production

The share of the nonmajors’ combined U.S. oil and gas

production has shown a fairly steady increase since

1989 (Figure 1). However, patterns over time differ

considerably between oil and gas and between onshore

and offshore locales. Accordingly, the review in this

chapter is separated by energy source and locale.

Oil Production

Growth in the nonmajors’ oil production in the 1990’s

was largely derived from the lower 48 onshore (Figure

2).7 This growth in the 1990’s marks a change from

sharp cutbacks in production by the majors and

nonmajors following the oil price collapse of late 1985

and early 1986. The nonmajors cut their lower 48

onshore oil production by nearly 500,000 barrels per

day between 1985 and 1989 (an 18-percent decline)

while the majors made even larger reductions. After

1989, the nonmajors reversed the earlier trend in oil

production and, by 1993, about matched their 1986

production. However, the majors’ lower 48 onshore oil

production continued to decline through the early

1990’s.

Drilling Adds More Reserves than

Purchases

What were the sources of growth in the nonmajors’ oil

production? Within the context of accounting for

energy reserves and production, there are three

possibilities: purchases from the majors, exploration

and development performance, or more rapid extraction

of oil reserves.

Production may have grown through purchases of

reserves from the majors. Net purchases of oil reserves

Million Barrels

1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993

0

500

1,000

1,500

Onshore

Offshore

Majors

Lower 48

Nonmajors

Lower 48

Alaska

(Majors)

Majors

Lower 48

Nonmajors

Lower 48

Figure 2. U.S. Oil Production by Region for

Majors and Nonmajors

Note: Data are on a net ownership basis and exclude

estimated royalties of 15 percent. Nonmajors = U.S. totals minus

majors.

Sources: Majors: Energy Information Administration, Form EIA28; U.S. Totals: Energy Information Administration, U.S. Crude

Oil, Natural Gas, and Natural Gas Liquids Reserves, DOE/EIA0216(93) (Washington, DC, October 1994).

from the majors (i.e., from the FRS group to nonmajors

in total) totaled nearly 500 million barrels over the

1989-1993 period. However, net purchases accounted

for only 14 percent of the nonmajors’ total U.S. oil

reserve additions in the lower 48 onshore (Table 1).

Reserves added through drilling may have outpaced

production. Nonmajors added 2.9 billion barrels of oil

to their lower 48 onshore reserves through extensions,

discoveries, improved recovery, and revisions of earlier

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.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers 5
Table 1. Lower 48 Onshore Oil Reserves and

Production for Nonmajors, 1989-1993

Million

Barrels

Beginning-of-1989 Reserves .............. 8,914

+ Reserve Additions, 1989-1993 .......... 2,937

+ Net Purchases from Majors, 1989-1993 . . . 486

- Production, 1989-1993 ................ -4,435

= End-of-1993 Reserves ................ 7,902

Replacement Rate, 1989-1993 (percent)

Excluding Net Purchases . . . . . . . . . . . . . . . 66

Including Net Purchases ................ 77

Note: Replacement rate = Reserve additions/production.

Nonmajors = Total United States (less 15 percent royalty

interest) minus majors.

Sources: Majors: Energy Information Administration, Form

EIA-28; Total United States: Energy Information

Administration, U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves, 1989-1993 issues, DOE/EIA-0216

(Washington, DC).

estimates over the 1989-1993 period. Even including net

purchases, growth in the nonmajors’ reserve base was

insufficient to replace production. If growth in the

reserve base did not offset the growth in production,

then only one other source of increased production is

apparent.

Growth Through More Rapid Depletion

An increased rate of extraction may have added to production. The rate of extraction is the proportion of

reserves going to production. The annual rate of extraction8 of lower 48 onshore oil reserves by the nonmajors

steadily increased, from 8.9 percent in 1989 to 10.6

percent in 1993 (Figure 3). In contrast, the comparable

extraction rate for the majors varied within a narrow

8.0-percent to 8.5-percent range over the same period.

The nonmajors’ increased extraction rate was probably

a phase of their adjustment to lower oil prices. During

the U.S. drilling boom of the late 1970’s and early

1980’s, oil and gas reserves were added which not only

Percent

1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993

7

8

9

10

11

12

Nonmajors

Majors

0

Figure 3. Extraction Rates for Lower 48 Onshore

Oil Reserves

Note: Extraction Rate = Production/(End-of-year reserves +

production). Nonmajors = Total United States (less 15 percent

royalty interest) minus majors.

Sources: Majors: Energy Information Administration, Form EIA28; Total United States: Energy Information Administration, U.S.

Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1981-

1993 issues, DOE/EIA-0216 (Washington, DC).

were costly to discover and develop but also entailed

high costs of production (lifting costs). High oil prices

and the expectation of rising oil prices in the future

justified adding high-cost reserves to producers’ books.

The downside of this high-cost strategy became painfully evident when oil prices began to decline modestly

at first in the early 1980’s and then crashed in late 1985

and early 1986. Oil producers responded by cutting

back on higher cost production, but, as long as asset

values were properly adjusted,9 there was no imperative to remove reserves from their books unless the

associated field was fully abandoned. Consequently, the

decline in the computed extraction rate from 1985 to

1989 may largely have reflected the combination of

production cutbacks and a reluctance to remove

reserves from the books.

After low oil prices were recognized as the norm, highcost reserves were removed from companies’ books

altogether. However, by the late 1980’s, prices of

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.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

6 An Expanded Role for Independent Producers
drilling and production services had declined in

response to lower oil prices, making some fields again

economic. Also, given lower oil prices, new production

was likely to be derived from low-cost reserves. Consequently, the rise in extraction rates in the 1990’s

reflected the combination of removing high-cost

reserves from the books and increased production—in

part, from new low-cost fields and, in part, from

formerly subeconomic fields. Nevertheless, nonmajors’

extraction rates from lower 48 oil reserves have not yet

quite matched the extraction rates of the early 1980’s.

In the context of reserve accounting, the increase in the

nonmajors’ lower 48 onshore oil production between

1989 and 1993 breaks down as follows: reserves added

through drilling, 57 percent; increased extraction rate,

33 percent; and net purchases of reserves, 10 percent.10

Offshore locales11 contributed little to the growth in

the nonmajors’ share of U.S. oil production. For both

majors and other producers, there was little overall

change in offshore oil production in the late 1980’s and

thus far in the 1990’s (Figure 2). Instead, the nonmajors

directed offshore operations toward producing natural

gas.

Natural Gas Production

Offshore locales, mostly in the Gulf of Mexico, have

been the most important source of gains by the nonmajors in U.S. natural gas production. Onshore, growth

in the majors’ natural gas production outpaced that of

other producers (Figure 4), reducing the nonmajors’

share of Lower 48 onshore natural gas production from

56 percent in 1986 to 54 percent in 1993. By contrast, the

nonmajors’ offshore natural gas production more than

doubled between 1986 and 1993, with their associated

share rising from 20 percent to 38 percent.

Billion Cubic Feet

1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Onshore

Nonmajors

Nonmajors

Majors

Majors

Offshore

Figure 4. U.S. Natural Gas Production for Majors

and Nonmajors

Note: Data are on a net ownership basis and exclude estimated

royalties of 15 percent. Nonmajors = U.S. totals minus majors.

Sources: Majors: Energy Information Administration, Form EIA28; U.S. Totals: Energy Information Administration, U.S. Crude

Oil, Natural Gas, and Natural Gas Liquids Reserves, DOE/EIA0216(93) (Washington, DC, October 1994).

Two distinct phases in the nonmajors’ offshore

ascendence are evident (Figure 4). Between 1986 and

1989, their offshore natural gas production increased

120 percent, but, during the 1990’s, production fell

slightly. Exploration and development strategies and

performance differed markedly between the two

periods.

Large Offshore Gains in the 1980’s

Offshore drilling activity by the nonmajors nearly

tripled in the late 1980’s, with drilling for natural gas

accounting for most of the growth (Figure 5). Over the

10This 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. 11Offshore includes the Federal Outer Continental Shelf and State offshore areas.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers 7
Wells or 10 Acres

1985 1986 1987 1988 1989 1990 1991 1992 1993

0

100

200

300

4

Wells

Acreage

Figure 5. Offshore Development Gas Wells

Completed and OCS Acreage Awarded

for Nonmajors

Note: Nonmajors = Total United States minus majors.

Sources: Wells completed: Majors: Energy Information

Administration, Form EIA-28; Total United States: Special

compilation provided by the Office of Oil and Gas, Energy

Information Administration, based on data which appeared in the

Monthly Energy Review, September 1994, p. 83. Acreage

awarded: Majors: Special compilation provided by the U.S.

Department of the Interior, Minerals Management Service. Total

United States: U.S. Department of the Interior, Minerals

Management Service, Federal Offshore Statistics: 1993 (Herndon,

VA, 1994).

same span, Federal Outer Continental Shelf (OCS)

acreage awarded to nonmajors registered substantial

growth as well. Part of this surge in activity was

attributable to the change in Federal OCS leasing

policy. Area wide leasing, which was instituted by the

U.S. Department of the Interior in the early 1980’s,

made much more acreage available. In 1983, for

example, 120 million acres in the OCS were offered for

bid compared with 8 million acres the year before.12 In

particular, the generally smaller, more proximate pools

favored by the nonmajors were in abundance.

Technological improvements also contributed to the

growth in drilling activity. Some developments, such as

three-dimensional seismic techniques, benefitted both

the majors and other companies, while other

developments, such as “off-the-shelf” platforms, were

boons especially to the smaller companies.

The upswing in the nonmajors’ offshore gas drilling

activity in the late 1980’s added considerably to their

reserve base and production capability. Over the 1986-

1989 period, the nonmajors more than replaced their

production with reserve additions gained through

drilling (Table 2). Purchases of offshore gas reserves

from the majors, on balance, were practically nil over

this period. Adding reserves at a pace that exceeded

production was a key source of the nonmajors’ heightened role in offshore gas production in the 1980’s.

Table 2. Offshore Natural Gas Reserves and

Production for Nonmajors, 1986-1989

and 1990-1993

(Billion Cubic Feet)

1986-

1989

1990-

1993

Beginning Reserves ......... 7,520 7,828

+ Reserve Additions ........ 5,142 1,271

+ Net Purchases from Majors . -16 1,604

- Production .............. -4,818 -5,875

= Ending Reserves ......... 7,828 4,828

Replacement Rate (percent)

Excluding Net Purchases . . . . 107 22

Including Net Purchases ..... 106 49

Note: Replacement rate = Reserve additions/production.

Nonmajors = Total United States (less 15 percent royalty

interest) minus majors.

Sources: Majors: Energy Information Administration, Form

EIA-28; Total United States: Energy Information

Administration, U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves, 1989-1993 issues, DOE/EIA-0216

(Washington, DC).

Offshore Gains Wiped Out in the 1990’s,

Smaller Fields Predominate

The 1990’s present a much different picture. Offshore

gas reserves added by the nonmajors through drilling

replaced only 22 percent of their production over the

1990-1993 period. Reserve additions were only a quarter

of the level achieved in the prior 4 years. The sharp

falloff in reserve additions reflected the plunge in the

nonmajors’ offshore drilling activity, led by cutbacks in

gas well completions (Figure 5). However, reserve

purchases from the majors became an important source

12U.S. Department of the Interior, Minerals Management Service, Federal Offshore Statistics: 1993, MMS 94-0060 (Herndon, VA, 1994),

Table 3.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

8 An Expanded Role for Independent Producers
of added production in the 1990’s, and exceeded

reserve additions gained through drilling by a considerable margin. Nevertheless, even with this increase

in reserve purchases, the nonmajors replaced only 49

percent of their offshore gas production in the 1990-

1993 period.

With this sort of performance, and with reserves falling

by nearly 40 percent, how did the nonmajors maintain

only a slightly diminished level of offshore gas production in the 1990’s (Figure 4)? Again, reserve

accounting reveals a rise in the rate at which offshore

gas reserves were drawn down (Figure 6). In contrast,

the majors’ extraction rate was up less than half a

percentage point between 1986 and 1993. Unlike the rise

in the nonmajors’ extraction rate for lower 48 onshore

oil reserves, which was mainly interpreted as a return

to pre-oil price collapse rates of extraction, the sharp

upswing in offshore gas extraction rates probably

reflects smaller field sizes.

Generally, smaller oil and gas deposits entail higher

production costs. Among the majors, a one-percent

reduction in field size corresponds to a 0.18-percent

increase in direct lifting costs.13 14 With higher (perunit) production costs, more rapid rates of extraction

are usually required in order for smaller fields to be

economic.

Rising rates of extraction probably reflect, in part,

smaller offshore gas fields for the nonmajors. Average

discovery size offshore for the nonmajors fell from 1.3

million barrels (COE) per well completed, in 1988-1990,

to 1.1 million barrels in 1991-1993, a 21-percent

decline.15 In contrast, the majors’ average offshore

discovery increased from 1.5 million barrels to 2.0

million barrels over the same period.

Percent

1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993

5

10

15

20

25

0

Majors

Nonmajors

Figure 6. Extraction Rates for Offshore Natural

Gas Reserves

Note: Extraction Rate = Production/(End-of-year reserves +

production). Nonmajors = Total United States (less 15 percent

royalty interest) minus majors.

Sources: Majors: Energy Information Administration, Form

EIA-28. Total United States: Energy Information Administration,

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves,

1981-1993 issues, DOE/EIA-0216 (Washington, DC).

Area wide leasing has caused marked changes in the

nonmajors’ involvement in offshore activity. In 1983,

the first year of area wide leasing, about 30 nonmajors

were producing from the Federal OCS. By 1993, nearly

100 nonmajors were OCS producers.16 Field sizes

changed dramatically, as well. Offshore reserves added

per well in 1980-1982, prior to area wide leasing, for

nonmajors averaged 3.9 million barrels, compared with

1.1 million barrels in 1991-1993. The majors, by contrast,

13Direct 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. 14The 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.

The 769 annual observations are for onshore and offshore separately, by company, for the years 1977-1993. Dollars were adjusted for

inflation using the implicit Gross Domestic Product deflator (in 1993 dollars). The coefficient on a dummy variable for offshore

observations was not significant. Inclusion of a dummy variable for each year did significantly reduce the residual variance. 15Average 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.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers 9
appeared to go further offshore seeking ever larger

fields: their average offshore discovery size more than

doubled over the same period.

Statements made by the president of a nonmajor

company “... that has as its primary objective

developing already discovered [offshore] reserves that

were uneconomic to previous operators...” are also

instructive:17

...Control over timing is the most important

factor. We can push development at every

stage and get a quick pay out, and this is

vital to smaller independents. ... We force

projects through very small hoops. They

have to pay for themselves very quickly.

17“Independents Stake Claim on Rich Gulf Reserves,” The American Oil and Gas Reporter, April 1995, pp. 86, 88.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

10 An Expanded Role for Independent Producers
3. Composition of Oil and Gas Producers

In the previous chapter, companies were only distinguished by whether or not they could be classified as

major petroleum companies. This gross dichotomy was

necessary in order to review the overall role of

nonmajor U.S. oil and gas producers in the context of

the entire industry. However, far from being a homogeneous group, the nonmajors are diverse in a number

characteristics such as degree of specialization and

corporate structure. Specialized companies, generally

termed the “independents,” were mainly responsible

for the nonmajors’ growth in oil and gas production, as

reported in the previous chapter.

Size and Numbers

Most Producers Are Small and Private

Most oil and gas producers are privately owned

companies, which tend to be much smaller than

publicly traded oil and gas producers. For example, in

1992, when the majors produced a per company

average of 345,000 barrels per day (COE), the other

publicly-traded oil and gas companies included in this

report produced an average of 10,000 barrels per day,

and the remaining oil and gas companies produced an

average of only 300 barrels per day.18 These small

private producers are quite numerous, accounting for

about 7,400 of the nearly 8,000 companies reporting oil

and/or natural gas production in the United States in

1992.19 In the same year, 427 publicly traded corporations disclosed that Standard Industrial Code (SIC) 1311

(oil and gas extraction) was one of the industries in

which they operate, of which 327 stated that SIC 1311

was their primary industry.20

The publicly traded producers annually disclose their

oil and gas reserves, production, and exploration and

development expenditures. The firm of Arthur Andersen and Company has compiled these disclosures for

the 1981-1993 period. These compilations, together with

other corporate financial disclosures, will be utilized

throughout the remainder of this report. Since oil and

gas producers are subject to the same market forces,

regardless of ownership structure, it is reasonable to

expect that findings based on data for publicly traded

independent producers apply to the privately owned

independent producers as well.

Companies in the Arthur Andersen and Company database were classified (for purposes of this report) as

follows, based on the companies’ disclosures of their

primary and secondary SIC codes: “independent producers” (primary industry code SIC 13) and “other

producers” (primary SIC other than SIC 13, but

reporting oil and/or gas production). Other publicly

traded oil and gas producers were further subdivided

(based on primary SIC’s) into refiners, pipelines/utilities, Canadian or other foreign-based, or diversified

companies.

Independents Increase Production Share

Among U.S. oil and gas producers, the independents

have gained an increased role in the industry following

the oil price collapse. The publicly traded independents’

share of U.S. oil and gas production, on a net ownership basis, increased from 7 percent in 1985 to 8 percent

in 1993 while the privately owned producers’ share

increased from 26 percent to 31 percent (Table 3). The

majors’ share fell from 61 percent to 56 percent. The

18For 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. 19U.S. Department of Commerce, Bureau of the Census, 1992 Census of Mineral Industries, Industry Series, Crude Petroleum and Natural

Gas (July 1995). 20Based on company filings of Security and Exchange Commission Form 10K as compiled by Disclosure, Inc.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers 11
Table 3. Percent Distribution of U.S. Oil and Gas

Production for Majors, Independents, and

Other Producers, 1985 and 1993

Percent Share of U.S.

Oil and Gas Production

(Crude Oil Equivalent)

1985 1993

Majors ............... 60.6 56.0

Publicly-traded Companies

Independents . . . . . . . . . 7.0 8.2

Other Producers . . . . . . . 6.4 5.2

Private Companies ...... 26.0 30.7

Totala ............... 100.0 100.0

a

Assumes a 15 percent royalty on production.

Note: Private companies = U.S. Total minus majors minus

publicly traded companies.

Sources: Majors: Energy Information Administration, Form

EIA-28; Publicly traded companies: Arthur Andersen & Co.,

Oil and Gas Reserve Disclosures, 1981-1985, and Fifteenth

Edition 1994 (Chicago, IL, 1986 and 1994); Total United

States: Energy Information Administration, U.S. Crude Oil,

Natural Gas, and Natural Gas Liquids Reserves, DOE/EIA0216 (Washington, DC, October 1994).

share for other publicly traded producers decreased

from 6 percent to 5 percent.

Apart from the majors, diversified companies showed

the most retrenchment in U.S. oil and gas production

following the oil price collapse (Table 3 and Figure 7).

Pipelines and utilities also reduced their commitment to

upstream production. Overall, refiners and Canadianbased producers showed little change in their role in

U.S. oil and gas production.

Entry and Exit

Although entry and exit into the ranks of the majors are

infrequent, the rest of the U.S. oil and gas industry has

experienced considerable comings and goings of

companies. The Arthur Andersen and Company

database was reviewed and the independents were

classified as survivors (independents that were in

production in 1985 and 1993), nonsurvivors (companies

that were not in production in 1993), and entrants

(companies that were in production in 1993 but not in

1985). For the independents overall, total assets

declined by about a third between the end of 1985 and

the end of 1993 (Figure 8). All of this decline was

Percent

1985 1986 1987 1988 1989 1990 1991 1992 1993

0

10

20

30

40

50

60

70

Independents

Canadian

Pipelines/Utilities

Diversified Refiners

Figure 7. Composition of Publicly Traded

Nonmajor Companies’ U.S. Oil and Gas

Production

Note: Companies are classified on the basis of their primary

Standard Industrial Codes.

Source: Compiled from Arthur Andersen & Co., Oil and Gas

Reserves Disclosures Database, 1984-1988 and 1989-1993

(Chicago, IL, 1989 and 1994). Billion Dollars (Cumulative Scale)

1985 1986 1987 1988 1989 1990 1991 1992 1993

0

10

20

30

40

Nonsurvivors

Entrants

Survivors

Figure 8. Total Assets of Publicly Traded

Independent Oil and Gas Producers

Note: Companies’ primary industry is Standard Industrial

Code 13.

Source: Compustat, a service of Standard & Poor’s.

attributable to exiting companies. Excluding these

nonsurvivors, total assets of the independents grew by

about a third. Entrant companies accounted for most of

the growth. Independents that survived the period as

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

12 An Expanded Role for Independent Producers
intact corporate entities and are still producing oil and

gas showed a modest decline in total assets during the

1980’s but have clearly registered some growth in assets

in the 1990’s.

The U.S. oil and gas industry exhibited considerable

dynamism following the oil price collapse. In order to

better understand the current and future development

of the industry, it is worth inquiring as to what factors

contributed to the patterns of growth, decline, and exit

following the oil price collapse.

The sources of growth and decline in U.S. oil and gas

production are rooted in companies’ ability to add

efficiently to their reserves. This report turns next to a

review of resource development costs. The analysis is

directed to the relationships between resource development costs and changes in industry structure and some

of the consequences of these relationships for future

development of the U.S. oil and gas industry.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers 13
4. Resource Development Costs

Replacing reserves used up in production is a fundamental requirement of survival in the oil and gas

industry. In a low oil price environment, as has been

the situation since 1986, adding reserves at a low cost

becomes imperative. The first part of this chapter

examines reserve replacement costs for surviving and

nonsurviving independent oil and gas producers in

order to evaluate the effect of these costs on product

markets’ and capital markets’ sorting of winners and

losers in the oil and gas industry. The second part of

this chapter compares the costs of adding to U.S. oil

and gas reserves of the majors and the surviving

independents. The resource development strategies of

these two groups have been shown to be markedly

different.21 Consequently, their respective costs of

adding reserves might differ. If the independents

continue to expand their role in U.S. oil and gas

development, then cost differences will tend to be

amplified in the future.

Resource Development Costs:

The Company Perspective

A company can replace its oil and gas reserves by

successful exploration and drilling, whereby formerly

untapped deposits are added to productive capacity, or

by outright purchase of proven reserves from another

reserve owner. Since either method can be employed,

measuring the costs to the company should account for

both. One such measure that has been employed

frequently within the oil and gas industry22 is termed

reserve replacement costs. For a company, reserve

replacement costs are measured by the ratio of

expenditures (for unproved lease acquisitions, acquisition of proven reserves, exploration, and development)

to barrels of oil and gas reserves (on a COE basis)

added to the company’s books (through extensions,

discoveries, improved recovery, revisions of previous

estimates, and purchase of proven reserves from other

companies).

Since there can be lags between expenditures and

associated reserve additions, reserve replacement costs

are measured as three-year weighted averages. Reserve

replacement costs are measured before tax effects. The

overall effect of taxes on reserve replacement costs has

been found to differ little between majors and

nonmajors.23 For the purposes of comparison, reserve

replacement costs are computed for four categories of

U.S. oil and gas producers: the majors (represented by

the FRS companies), surviving independents (i.e.,

specialized companies that produced oil and/or gas in

1993), nonsurviving independents (i.e., specialized

companies that produced U.S. oil and/or gas sometime

prior to 1993 but did not exist in 1993), and other

producers (refiners, pipelines, utilities, Canadian-based

companies, and diversified companies).

In the 1990’s, U.S. reserve replacement costs of the

majors and surviving independents were nearly equal

at about $5 per barrel of added reserves (in 1993

dollars) (Figure 9). Even in the late 1980’s, reserve

replacement costs of the two groups differed by only a

few cents per barrel. Reserve replacement costs for

independents that exited the industry were slightly

higher at about the time of the oil price collapse.

Thereafter, the costs for nonsurviving independents

compared to surviving independents continued to

grow, and by 1990-1992 were nearly $4 per barrel

higher. Other producers (such as diversified companies)

also incurred higher reserve replacement costs.

These results reinforce the view that the market forces

to which U.S. oil and gas producers have been subject

forced efficiency in resource development. That is, as

the industry adjusted to the lower level of prices

21See Energy Information Administration, Performance Profiles of Major Energy Producers 1986, DOE/EIA-0206(86) (Washington, DC,

January 1986), Table 38. 22See 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. 23Energy 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.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers 15
Dollars (1993) per Barrel (COE)

1987 1988 1989 1990 1991 1992 1993

0

2

4

6

8

10

12

Majors

Independent

Survivors

Independent

Nonsurvivors

Other Producers

Figure 9. U.S. Reserve Replacement Costs for

Majors and Publicly Traded Oil and Gas

Producers

COE = Crude oil equivalent.

Note: Reserve replacement costs = Exploration and

development expenditures (including acquisitions of unproved and

proved acreage)/reserves added (including purchases of proved

reserves), three-year weighted average. Independent oil and gas

producers’ primary industry is Standard Industrial Code 13.

Sources: Majors: Energy Information Administration, Form EIA28; Publicly traded companies: compiled from Arthur Andersen

& Co., Oil and Gas Reserves Disclosures Database, 1984-1988

and 1989-1993 (Chicago, 1989 and 1994).

following the oil price collapse of the mid-1980’s, the

companies that competed successfully tended to incur

lower costs of adding to their reserve bases than those

companies that reduced or withdrew their asset

commitments to U.S. oil and gas production.

Resource Development Costs: An

Economywide Perspective

Reserve replacement costs measure the cost to the company of adding to their reserve base, whether through

the company’s own exploration and development

efforts or through outright purchase of proven reserves

from another company. For the economy as a whole,

though, reserve replacement costs may not be the most

appropriate measure of the actual costs of adding to

U.S. oil and gas reserves. Reserve replacement costs

include expenditures for acquisitions of proven reserves

as well as acquisitions of leases for unproven acreage.

However, for the economy as a whole, acquisitions

represent only a transfer of ownership. Net additions to

U.S. reserves from acquisitions are always zero. In

order to ascertain if the structural changes in the U.S.

oil and gas industry might affect the costs of adding to

reserves for the economy as a whole, a different

measure is needed.

Excluding expenditures for acreage acquisitions,

whether proven or unproven, and excluding existing

reserves gained through purchases will more accurately

reflect the economywide costs of adding to U.S. oil and

gas reserves. Thus, the ratio of exploration and

development expenditures (excluding acquisitions of

leases and proven acreage) to reserve additions

(excluding purchases of proven reserves) will be used

as the economywide cost measure, and will be termed,

“overall finding costs.”24 Figure 10 presents overall

U.S. finding costs for two groups: Majors and surviving

independents. Dollars (1993) per Barrel (COE)

1987 1988 1989 1990 1991 1992 1993

0

2

4

6

8

10

12

Surviving

Independents

Majors

Figure 10. Overall Finding Costs for Majors and

Publicly Traded Surviving

Independents

COE = Crude oil equivalent.

Note: Overall finding costs = exploration and development

expenditures (excluding acquisitions of unproved and proved

acreage)/reserves added (excluding purchases of proved

reserves), three-year weighted average. Independent oil and gas

producers’ primary industry is Standard Industrial Code 13.

Sources: Majors: Energy Information Administration, Form EIA28; Publicly traded companies: compiled from Arthur Andersen

& Co., Oil and Gas Reserves Disclosures Database, 1984-1988

and 1989-1993 (Chicago, 1989 and 1994).

24For 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.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

16 An Expanded Role for Independent Producers
Overall U.S. finding costs for surviving independents

are clearly higher than the majors’ overall U.S. finding

costs. Most recently (1991-1993), surviving independents’ costs were nearly $2 per barrel of added

reserves (in 1993 dollars) more than the majors. In the

mid-1980’s, the difference was about $5 per barrel, so

the gap has narrowed but not disappeared.25

This latter result should be interpreted very carefully.

Beginning in the early 1980’s, the costs of finding oil

and gas have declined in the United States.26 Technological change and market adjustments have over time

reduced the costs of adding reserves. However, at any

point in time, finding more oil and gas will typically

entail ever higher costs. That is, finding oil and gas

reserves is subject to diminishing returns. Consequently, there is a tendency for companies that are

expanding their reserves base to have higher finding

costs than companies that are contracting.

In the 1990’s, the surviving independents, overall, have

been increasing their investments in U.S. exploration

and development. In contrast, the majors, overall,

sharply reduced their U.S. exploration and development

commitments until the early 1990’s from which time

they have leveled off. The higher overall finding costs

of the surviving independents compared with the

majors, in part, reflects both an expansion of the

independents’ U.S. oil and gas operations and a

consolidation of the majors’ operations.

25The 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.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers 17
5. Financial Performance of the

Independent Oil and Gas Producers

A company’s standing in the capital markets is reflected

in the markets’ evaluation of the company and investor

willingness to provide funds to it. Investor perceptions

are, in turn, influenced by financial results. For the

independents, the oil price collapse of 1986 was the

defining event in shaping financial factors such as cash

flow, profitability, and cost. Independents that were

able to survive the oil price collapse might be expected

to have distinguishing characteristics which may have

been discerned by investors.27

Financial Performance

Independents Rely Heavily on External

Funds

The surviving independent oil and gas producers rely

on external funds (from issues of long-term debt and

equity securities, and change in current debt) more than

on cash generated by operations (Figure 11). In contrast,

the major petroleum companies use cash flow from

operations as the predominant source of funds (Table

4). The main source of external funds for both the

majors and the surviving independents has been longterm debt (Table 4). The majors currently rely on longterm debt for 27 percent of their funds, while the

surviving independents rely on long-term debt for 49

percent of their funds.

Although they are more debt-dependent than the

majors, the independents have been conscientious about

reducing their dependence on debt. A highly leveraged

firm (a firm with more debt than its peers) usually

finds itself with higher fixed charges in the form of

interest payments relative to discretionary outlays such

as dividend payments. Faced with a crisis such as the

oil price collapse, it would be less likely that a highly

leveraged firm would be able to cover its interest

payments with its operating cash flow, and may default

on debt. The prospect of default and bankruptcy can be

Billion Dollars (cumulative)

1985 1986 1987 1988 1989 1990 1991 1992 1993

0

2

4

6

8

10

12

Operations Asset Sales External Funds

Figure 11. Sources of Cash for Surviving

Publicly Traded Independents

Note: External funds are the sum of proceeds from long-term

debt, equity security offerings, and net changes in current debt.

Source: Compustat, a service of Standard and Poor’s.

assumed to have a negative effect on investors, and the

hope of reassuring investors may have motivated the

independent oil producers to reduce debt. Since 1986,

the surviving independents have allocated about 44

percent per year of their cash for debt reduction, while

the majors have allocated about 27 percent of funds to

reduce debt (Table 4). This allocation of funds has

resulted in a dramatic decrease in the ratio of debt to

equity for the surviving independents from over 150

percent to just under 110 percent in 1993 (Figure 12).

This is in contrast to the large industrial companies (as

represented by the Standard and Poor’s (S&P) 400

group of industrial firms), who have increased debt

relative to equity markedly since the 1980’s.

In addition to reduction of debt, the independents

devoted the bulk of their cash to reinvestment in their

own operations, about 52 percent of cash outlays from

27The group of surviving independents includes entrants, defined as firms who entered the industry after 1985, and existed through

1993.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers 19
Table 4. Sources and Uses of Cash

1986-1990 1991-1993 1986-1990 1991-1993

billion dollars percent distribution

Publicly Traded Independent Oil and Gas Producers

Main Sources of Cash

Cash Flow from Operations . . . . . . . . . . . . . . . 8.0 7.5 36.8 30.4

Proceeds from Long-Term Debt . . . . . . . . . . . . 9.5 12.1 43.4 48.9

Proceeds from Disposal of Assets . . . . . . . . . . 1.8 1.9 8.1 7.9

Proceeds from Equity Security Offerings . . . . . . 2.6 3.2 11.7 12.8

Total ............................... 21.8 24.8 100.0 100.0

Main Uses of Cash

Additions to Investment in Place ........... 10.3 13.1 45.3 52.4

Reductions in Long-Term Debt ............ 10.2 10.7 44.7 43.0

Dividends to Shareholders . . . . . . . . . . . . . . . . 1.4 0.9 6.3 3.5

Stock Repurchases . . . . . . . . . . . . . . . . . . . . . 0.8 0.3 3.7 1.1

Total ............................... 22.7 24.9 100.0 100.0

Other Sources and Uses, Net ............ 1.2 -0.2

Net Change in Cash and Cash Equivalents . . 0.3 -0.2

Majors

Main Sources of Cash

Cash Flow from Operations .............. 243.0 142.8 58.0 58.7

Proceeds from Long-Term Debt ............ 105.9 65.8 25.3 27.1

Proceeds from Disposal of Assets .......... 54.1 28.4 12.9 11.7

Proceeds from Equity Security Offerings ...... 15.8 6.1 3.8 2.5

Total ............................... 418.8 243.1 100.0 100.0

Main Uses of Cash

Additions to Investment in Place ........... 214.6 128.7 51.1 54.3

Reductions in Long-Term Debt ............ 116.1 64.6 27.6 27.2

Dividends to Shareholders ................ 64.3 40.6 15.3 17.1

Stock Repurchases ..................... 24.9 3.3 5.9 1.4

Total ............................... 420.0 237.2 100.0 100.0

Other Sources and Uses, Net ............ -4.1 -7.4

Net Change in Cash and Cash Equivalents . . -5.3 -1.5

Note: Totals may not equal sum of components due to independent rounding.

Sources: Surviving Independents: Compustat, a service of Standard and Poor’s; Majors: Energy Information

Administration, Form EIA-28.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

20 An Expanded Role for Independent Producers
Percent

1985 1986 1987 1988 1989 1990 1991 1992 1993

0

40

80

120

160

200

Majors

Surviving Independents

S&P 400 (Excluding Majors)

Figure 12. Total Debt to Equity for Majors,

Surviving Independent Oil and Gas

Producers, and the S&P 400

Source: Majors: Energy Information Administration, Form EIA28; S&P 400 and Surviving Independents: Compustat, a service

of Standard & Poor’s.

1991 through 1993 (Table 4). The increases in debt

reduction and reinvestment came at the expense of

stockholder payout. Cash dividends paid to stockholders fell from 6 percent of cash outlays in 1986

through 1990 to only 4 percent of cash outlays in 1991

through 1993.

Profitability

Expected profitability is an important determinant of

investors’ perceptions of a company. Past profitability

is usually regarded as a useful indicator of future profitability, and can be a guide to comparing companies’

financial performance. An often-used measure of

company profitability is net income as a percent of

stockholders’ equity, referred to as return on equity.

The major oil companies typically engage in oil and gas

production (“upstream” operations) and in refining and

marketing (“downstream” operations). Poor profitability in the majors’ upstream operations in low-oilprice years can sometimes be offset by better

performance in downstream operations. Lacking this

integration, the independents were devastated by the

oil price collapse, earning a negative rate of return on

investment for the years immediately following the

price collapse (Figure 13).

Percent

1986 1987 1988 1989 1990 1991 1992 1993

0

5

10

15

20

25

30

0

-5

-10

-15

-20

-25

-30

Surviving

Independents

S&P 400

(Excluding

Majors)

Majors

Figure 13. Return on Equity for Petroleum

Companies and U.S. Industry

Source: Compustat, a service of Standard & Poor’s.

The independents that survived the oil price collapse

managed to improve profitability through the

remainder of the 1980’s (Figure 13). One indicator of

investors’ evaluation of this improved performance is

the ratio of market value of the companies’ shares to

book value of the companies’ net assets (i.e., stockholders’ equity). A company’s current share price

reflects investors’ expectations of profitability at the

time the shares are purchased; book value reflects the

future expected profitability of productive assets at the

time the assets were purchased. The steadily increasing

ratio of market value to book value for the independents reflected investor expectations of continued

improvement in profitability (Figure 14). However,

investors are more optimistic about the future of

companies outside of oil and gas production, as

evidenced by the much greater growth in the ratio of

market value to book value for the S&P 400 group

during the 1990’s (Figure 14).

Although profitability has improved since the 1980’s,

return on equity for the independents has been

persistently lower than return on equity for the majors

and for the S&P 400 group of companies since 1986

(Figure 13). Coupled with their relatively high rate of

reinvestment of funds and low payout to shareholders,

this could indicate that the independents tend to overinvest in their own operations, allocating operating cash

flow to relatively low-return projects, at least as

measured by accounting rates of return.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers 21
Percent

1985 1986 1987 1988 1989 1990 1991 1992 1993

50

100

150

200

250

300

350

0

S&P 400 (Excluding Majors)

Surviving Independents

Majors

Figure 14. Ratio of Market Value to Book Value

for Majors, Publicly Traded

Independents, and the S&P 400

Source: Compustat, a service of Standard & Poor’s.

Investor Risk and the Cost of Capital

The greater the chance of loss, the riskier the prospect

of buying a company’s stock or debt. In order to attract

investment, a relatively risky firm must offer greater

returns, in the form of higher dividend payments,

greater growth opportunities, or higher interest

payments on debt. One might expect given the risk of

loss and lower returns in comparison with the majors

(Figure 13), that the market would demand relatively

higher rates of interest on debt issued by the

independents. Surprisingly, this is not the case. The rate

of interest (interest expense as a percent of long- and

short-term debt) incurred by the independents was

often slightly lower than the rate paid by the majors

(Figure 15).

A closer analysis of another measure of investor

perception of risk helps explain the apparent anomaly

of the low interest rates paid by the independents. An

investor can reduce the risk of loss within a portfolio of

assets by purchasing a variety of stocks. As long as the

returns from the stocks are not perfectly correlated with

one another, adding even a relatively risky stock may

reduce portfolio risk. The risk of owning the stock of an

independent oil company can thus be reduced by diversification, and only the undiversifiable, or systematic,

risk is relevant to the investor.

Percent

1986 1987 1988 1989 1990 1991 1992 1993

0

2

4

6

8

10

12

14

Surviving

Independents

Majors

Moody’s Aaa Corp.

Figure 15. Effective Interest Rate for Majors and

Publicly Traded Independent Oil and

Gas Producers

Note: The effective interest rate is calculated by dividing

interest expense by total long-term and short-term debt.

Source: Independents and Majors: Compustat, a service of

Standard & Poor’s; Moody’s Aaa Corporate: Moody’s Investor

Service, Moody’s Industrial Manual 1994, Vol. 1 (New York, 1994),

p. a48.

An often used measure of a company’s systematic risk

is “beta,” which is the regression coefficient of stock

value of a company with the value of the market. A

stock with a beta value of one moves exactly with the

market. If the market goes up 1 percent, the stock will

go up 1 percent. A stock with a beta of less than 1 is

less volatile than the market. If the value of the overall

market decreases by 1 percent, the value of a stock with

a beta of 0.8 will decrease by 0.8 percent. Thus, a stock

with a beta of less than one is regarded as a valuable

defense against a declining market.28 Even highly

volatile stocks may have low betas, as long as they do

not tend to move with the overall market.

The beta values for the independents tend to be less

than one, and following the oil price collapse, are

usually less than the betas for the majors until 1992

(Table 5). This finding indicates that investors have

been able to diversify away a substantial portion of the

risk of investing in these companies. The independents’

unexpectedly low interest rates reflect relatively low

systematic risk.

Whether interest rates reflect systematic or unsystematic

risk, the oil price crash appeared to increase the capital

28Alan C. Shapiro, Modern Corporate Finance (New York: Macmillan, 1990), p. 120.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

22 An Expanded Role for Independent Producers
Table 5. Average Betas for Majors and Surviving

Independent Oil and Gas Producers

Year Majors Independents

1986 .......... 0.77 0.52

1987 .......... 0.96 0.75

1988 .......... 0.89 0.53

1989 .......... 0.97 0.80

1990 .......... 0.51 0.39

1991 .......... 0.79 0.60

1992 .......... 0.69 0.78

1993 .......... 0.62 0.84

Note: Betas reported are arithmetic averages, excluding

observations with negative values.

Source: Rate of return information for calculating

company-level betas: Center for Research in Security

Prices (CRISP), University of Chicago. Company-level

betas calculated using econometric methodology described

in Energy Information Administration, Investor Perceptions

of Nuclear Power, DOE/EIA-0446 (Washington, DC, May

1984).

markets’ risk premium for investment in both the

majors and the independents. The average interest rate

for the independents was 30 percent higher than the

Moody’s Aaa rate on low risk corporate bonds in 1986,

and the majors’ overall interest rate was noticeably

higher as well.29 Since then, the gap between the rates

has steadily narrowed, indicating a lessening of the risk

premia demanded by investors of the majors and the

independents.

Because the predominant source of external funds for

the independents is long-term debt (and because, for

any firm, the alternative to investing in one’s own

operations is simply to invest in other stocks and

bonds), the rate of interest is a good reflection of the

independents’ cost of capital. The reductions in debt

and improvement in profitability accordingly reduced

their cost of capital, and the rates of interest paid by

both the majors and the independents have approached

the yield on low risk (rated “Aaa” by Moody’s Investor

Service) corporate bonds (Figure 15).

Characteristics of Surviving

Producers

In 1985, 264 firms fit the classification (discussed in

Chapter 3) of publicly traded independent oil and gas

producer. By 1993, this number had decreased to 138,

including new corporate entities that entered the U.S.

oil and gas industry after 1985. What characteristics of

performance distinguished survivors (and a handful of

entrants) from the publicly traded independents that

exited the industry?

Little Difference in Financial Performance

Survivor profitability, as measured by return on equity,

was unremarkable in comparison with nonsurvivors

(Figure 16). Given the lack of difference in return on

equity, it is not surprising that the ratio of market value

to book value for the survivors did not continuously

exceed that of the nonsurvivors until 1990 (Figure 17). Percent

1986 1987 1988 1989 1990 1991 1992 1993

0

10

-10

-20

-30

-40

-50

Survivors

Nonsurvivors

Figure 16. Return on Equity for Publicly Traded

Independent Oil and Gas Producers

Note: Return on equity is calculated as net income divided

by stockholders’ equity.

Source: Compustat, a service of Standard & Poor’s.

The survivors carried more debt relative to equity than

the nonsurvivors throughout the post-price collapse

period (Figure 18). They also tied up relatively more

cash in fixed interest payments than did the

nonsurvivors (Figure 19). The greater reliance on debt

may reflect an intentional strategy on the part of the

survivors, or may have been the result of investor

perception that these firms were a better bet for

eventual repayment of debt.

The cost of capital for the surviving independents,

represented by interest expense on total debt, has

29The Moody’s Aaa rate is given to corporate debt issues that have the lowest risk of default.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers 23
Percent

1986 1987 1988 1989 1990 1991 1992 1993

80

100

120

140

160

180

200

220

240

0

Nonsurvivors Survivors

Figure 17. Market Value as a Percent of Book

Value for Publicly Traded Independent

Oil and Gas Producers

Source: Compustat, a service of Standard & Poor’s. Percent

1986 1987 1988 1989 1990 1991 1992 1993

40

60

80

100

120

140

160

180

0

Survivors

Nonsurvivors

Figure 18. Total Debt as a Percent of

Stockholders’ Equity for Publicly

Traded Independent Oil and Gas

Producers

Note: Total debt is the sum of short-term debt, long-term

debt, and accounts payable.

Source: Compustat, a service of Standard & Poor’s.

Percent

1986 1987 1988 1989 1990 1991 1992 1993

25

30

35

40

45

50

55

60

65

70

0

Survivors

Nonsurvivors

Figure 19. Interest Expense as a Percent of Cash

Flow for Publicly Traded Independent

Oil and Gas Producers

Source: Compustat, a service of Standard & Poor’s. Percent

1986 1987 1988 1989 1990 1991 1992 1993

6

9

12

15

0

Survivors

Nonsurvivors

Figure 20. Interest Expense as a Percent of Total

Debt for Publicly Traded Independent

Oil and Gas Producers

Source: Compustat, a service of Standard & Poor’s.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

24 An Expanded Role for Independent Producers
declined throughout the post-price collapse period

(Figure 15). The decline reflected steadily falling longterm interest rates (e.g. Moody’s Aaa rate) and a

reduction in investors’ perceptions of the riskiness of

the independents. Still, the surviving independents paid

about the same for borrowed funds as the nonsurvivors

(Figure 20).

Low Reserve Replacement Costs

Distinguish Survival

The one remarkable difference between the surviving

and nonsurviving independent oil and gas producers

was the cost of replacing oil and gas reserves. Throughout the post-price collapse period, the surviving

independents (who began the period with slightly

lower reserve replacement costs than the nonsurvivors)

successfully added to reserves at ever lower costs than

the nonsurvivors (Figure 9 in Chapter 4). By 1990, their

costs were as low as those of the majors. This was a

critical accomplishment for the independents, since the

majors in general achieved lower costs by scaling back

exploration, development, and reserve purchases,

presumably dropping higher cost operations. The independents achieved lower costs in spite of the expansion

of their U.S. reserve and asset base (Figures 1 and 8).

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers 25
Appendix

Twenty-seven companies were initially notified of a

requirement to file Form EIA-28 (Financial Reporting

System). This group was initially chosen from the top

50 publicly owned U.S. crude oil producers, in 1976,

who had at least 1 percent of either the production or

the reserves of oil, gas, coal, or uranium in the United

States or 1 percent of refining capacity or petroleum

product sales in the United States. The list of companies

required to report was updated for mergers, acquisitions, and spinoffs which, together with the selection

criteria applied to 1991 data, resulted in the list of

companies shown in the tabulation on the following

page.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

An Expanded Role for Independent Producers 27
Table A1. Companies Reporting to the Financial Reporting System, 1977-1994

Company 1977-81 1982 1983-84 1985-86 1987 1988 1989-90 1991 1992-93 1994

Amerada Hess Corporation .............. X X X X X X X X XX

American Petrofina Inc.a ................ X X X X XX X

Amoco Corporationb ................... X X X X X X X X XX

Anadarko Petroleum, Inc. ............... X X

Ashland Oil, Inc. ...................... X X X X X X X X XX

Atlantic Richfield Co. (ARCO) ............ X X X X X X X X XX

BP America, Inc.c ..................... X X X X XX

Burlington Northern Inc.d ................ XXXXX

Burlington Resources Inc.d .............. X X X XX

Chevron Corporatione f ................. X X X X X X X X XX

Cities Serviceg ....................... X X

Coastal Corporation ................... X X X X X X X X XX

Conocoh ............................ X

E.I. du Pont de Nemours and Co.h ......... X X X X X X X XX

Enron Corporation ..................... X X

Exxon Corporation .................... X X X X X X X X XX

Fina, Inc.a ........................... X XX

Getty Oili ........................... X X X

Gulf Oilf ............................ X X X

Kerr-McGee Corporation ................ X X X X X X X X XX

Marathonj ........................... X

Mobil Corporationk .................... X X X X X X X X XX

Nerco, Inc.l .......................... X

Occidental Petroleum Corporationg ......... X X X X X X X X XX

Oryx Energy Companym ................ X X X XX

Phillips Petroleum Company ............. X X X X X X X X XX

Shell Oil Company .................... X X X X X X X X XX

Standard Oil Co. (Ohio) (SOHIO)c ......... XXXX

Sun Company, Inc.m ................... X X X X X X X X XX

Superior Oilk ......................... X X X

Tenneco Inc.n ........................ XXXXXX

Texaco Inc.i ......................... X X X X X X X X XX

Total Petroleum (North America) Ltd.o ...... X X

Union Pacific Corporation ............... X X X X X X X X XX

Unocal Corporation .................... X X X X X X X X XX

USX Corporationj ..................... X X X X X X X X X

a

American Petrofina, Inc. changed its name to Fina, Inc. effective April 17, 1991.

b

Formerly Standard Oil Company (Indiana).

c

In 1987, BP America acquired all shares in Standard Oil Company (Ohio) that it did not already control.

d

Burlington Resources was added to the FRS system and Burlington Northern was dropped for 1988. Data for Burlington Resources covers the full

year 1988 even though that company was not created until May of that year. e

Formerly Standard Oil Company of California.

f

Chevron acquired Gulf Oil in 1984 but separate data for Gulf continued to be available for the full 1984 year.

g

Occidental acquired Cities Service in 1982. Separate financial reports were available for 1982, so each company continued to be treated separately

until 1983. h

DuPont acquired Conoco in 1981. Separate data for Conoco were available for 1981, DuPont was included in the FRS system in 1982.

i

Texaco acquired Getty in 1984, however, Getty was treated as a separate FRS company for that year.

j

U.S. Steel (now USX) acquired Marathon in 1982.

k

Mobil acquired Superior in 1984 but both companies were treated separately for that year.

l

RTZ America acquired the common stock of Nerco, Inc. on Feb. 17, 1994. In Sept., 1993, Nerco, Inc. sold Nerco Oil & Gas, Inc., its subsidiary.

Nerco’s 1993 submission includes operations of Nerco Oil & Gas, Inc. through Sept. 28, 1993. mSun Company spun off Sun Exploration and Development Company (later renamed Oryx Energy Company) during 1988. Both companies were

included in the FRS system for 1988 therefore some degree of duplication exists for that year. n

Tenneco sold its worldwide oil and gas assets and its refining and marketing assets in 1988. Other FRS companies purchased approximately 70

percent of Tenneco’s assets. o

Effective June 1, 1991 Total’s exploration, production and marketing operations in Canada were spun off to Total Oil & Gas, a new public entity.

Note: “X” indicates that the company was included in the FRS system for the year indicated.

Source: Energy Information Administration, Form EIA-28.

Energy Information Administration/ Oil and Gas Development in the United States in the Early 1990’s:

28 An Expanded Role for Independent Producers