DOE/EIA–0216(97)

Distribution Category UC–950

U.S. Crude Oil, Natural Gas,

and Natural Gas Liquids Reserves

1997 Annual Report

December 1998

Energy Information Administration

Office of Oil and Gas

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 U.S. Department of Energy. The information contained herein should be attributed to the

Energy Information Administration and should not be construed as advocating or reflecting any policy position

of the Department of Energy or any other organization.
Preface

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

Liquids Reserves 1997 Annual Report is the 21st

prepared by the Energy Information Administration

(EIA) to fulfill its responsibility to gather and report

annual proved reserves estimates. The EIA annual

reserves report series is the only source of

comprehensive domestic proved reserves estimates.

This publication is used by the Congress, Federal and

State agencies, industry, and other interested parties

to obtain accurate estimates of the Nation's proved

reserves of crude oil, natural gas, and natural gas

liquids. These data are essential to the development,

implementation, and evaluation of energy policy and

legislation.

This report presents estimates of proved reserves of

crude oil, natural gas, and natural gas liquids as of

December 31, 1997, as well as production volumes

for the United States and selected States and State

subdivisions for the year 1997. Estimates are

presented for the following four categories of natural

gas: total gas (wet after lease separation),

nonassociated gas and associated–dissolved gas

(which are the two major types of wet natural gas),

and total dry gas (wet gas adjusted for the removal

of liquids at natural gas processing plants). In

addition, reserve estimates for two types of natural

gas liquids, lease condensate and natural gas plant

liquids, are presented. The estimates are based upon

data obtained from two annual EIA surveys: Form

EIA–23, “Annual Survey of Domestic Oil and Gas

Reserves” and Form EIA–64A, “Annual Report of the

Origin of Natural Gas Liquids Production.” Also

included is information on indicated additional crude

oil reserves and crude oil, natural gas, and lease

condensate reserves in nonproducing reservoirs. A

discussion of notable oil and gas exploration and

development activities during 1997 is provided.

The appendices contain data by operator production

size class for crude oil and natural gas reserves and

production; the top 100 U.S. fields ranked within an

oil or gas proved reserves group for 1997; report

Table 1 converted to metric units; historical State

data; a summary of survey operations; a discussion

of statistical considerations; methods used to develop

the estimates provided in this report; maps of

selected State subdivisions; and examples of the

survey forms. A glossary of the terms used in this

report and in survey Forms EIA–23 and EIA–64A is

provided to assist readers in more fully

understanding the data.

This annual reserves report was prepared by the

Reserves and Production Division (located in Dallas,

Texas), Office of Oil and Gas, Energy Information

Administration. General information regarding

preparation of the report may be obtained from

Kenneth A. Vagts, Director, Office of Oil and Gas

and John H. Wood, Director, Reserves and

Production Division (214.720.6160).

Authors were John H. Wood, Steven G. Grape and

Rhonda S. Green. Technical contributions were made

by Rafi M. Zeinalpour and technical editing was

provided by David F. Morehouse.

Address questions on specific sections of the

publication to the following analyst/author:

n Executive Summary and Appendices F and G

John H. Wood

Phone: 214.720.6160

E–mail: jwood@eia.doe.gov

Fax: 214.720.6155

n Chapter 2, 3, 4, 5

Steven G. Grape

Phone: 214.720.6174

E–mail: sgrape@eia.doe.gov

Fax: 214.720.6155

n Chapter 1, Appendices A, B, C, D, E, H, and I

Rhonda S. Green

Phone: 214.720.6161

E–mail: rgreen@eia.doe.gov

Fax 214.720.6155

n Field-level Reserves Quality Assurance

Rafi M. Zeinalpour

Phone: 214.720.6191

E–mail: rzeinalp@eia.doe.gov

Fax 214.720.6155

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report iii
Contents

Page

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix

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

Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Survey Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Form EIA-23 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Form EIA-64A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Data Collection Operations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

2. Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

National Summary. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Crude Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Natural Gas Liquids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Reserves Changes Since 1977 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Economics and Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Reserve-to-Production Ratios and Ultimate Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

R/P Ratios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Proved Ultimate Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

International Perspective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

International Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Petroleum Consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Dependence on Imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

List of Appendices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

3. Crude Oil Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Discussion of Reserves Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Total Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

New Field Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

New Reservoir Discoveries in Old Fields. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Revisions and Adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Areas of Note: Large Discoveries and Reserve Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Gulf of Mexico Federal Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Other Gain Areas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Areas of Note: Large Reserve Declines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Other Decline Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Reserves in Nonproducing Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Indicated Additional Reserves. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

4. Natural Gas Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Dry Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Discussion of Reserves Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Revisions and Adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Wet Natural Gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Nonassociated Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report v
Page

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Associated-Dissolved Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Coalbed Methane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Areas of Note: Large Discoveries and Reserves Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Areas of Note: Large Reserves Declines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Reserves in Nonproducing Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

5. Natural Gas Liquids Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Natural Gas Liquids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Natural Gas Plant Liquids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Lease Condensate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Reserves in Nonproducing Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Appendices

A. Operator Data by Size Class . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

B. Top 100 Oil and Gas Fields for 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

C. Conversion to the Metric System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

D. Historical Reserves Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71

E. Summary of Data Collection Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

F. Statistical Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105

G. Estimation of Reserves and Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125

H. Maps of Selected State Subdivisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135

I. Annual Survey Forms for Domestic Oil and Gas Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145

Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153

Tables

1. U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids, 1987-1997 . . . . . . . . . . . . 4

2. Reserves Changes, 1977-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

3. U.S. Average Annual Domestic Wellhead Prices for Crude Oil and Natural Gas, and the

Average Number of Active Rotary Drilling Rigs, 1970-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . 10

4. U.S. Exploratory and Development Well Completions, 1970-1997 . . . . . . . . . . . . . . . . . . . . . . . . . 12

5. International Oil and Natural Gas Reserves as of December 31, 1997 . . . . . . . . . . . . . . . . . . . . . . . 16

6. Crude Oil Proved Reserves, Reserves Changes, and Production, 1997 . . . . . . . . . . . . . . . . . . . . . . 20

7. Reported Indicated Additional Crude Oil Reserves, 1997. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 1997 . . . . . . . . . . . . . . . . . . 28

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vi U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
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9. Natural Gas Proved Reserves, Reserves Changes, and Production,

Wet After Lease Separation, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

10. Nonassociated Natural Gas Proved Reserves, Reserves Changes, and Production,

Wet After Lease Separation, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

11. Associated-Dissolved Natural Gas Proved Reserves, Reserves Changes, and Production,

Wet After Lease Separation, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

12. U.S. Coalbed Methane Proved Reserves and Production, 1993-1997 . . . . . . . . . . . . . . . . . . . . . . . 35

13. Reported Reserves of Natural Gas, Wet After Lease Separation, in Nonproducing Reservoirs, 1997 . . . . . . . 38

14. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 1997 . . . . . . . . . . . . . . . . 40

15. Natural Gas Plant Liquids Proved Reserves and Production, 1997. . . . . . . . . . . . . . . . . . . . . . . . . 41

16. Lease Condensate Proved Reserves and Production, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

Figures

1. U.S. Crude Oil Proved Reserves, 1986-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

2. Components of Reserves Changes for Crude Oil, 1986-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

3. U.S. Dry Natural Gas Proved Reserves, 1986-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

4. Components of Reserves Changes for Dry Natural Gas, 1986-1997 . . . . . . . . . . . . . . . . . . . . . . . . 6

5. U.S. Natural Gas Liquids Proved Reserves, 1986-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

6. Components of Reserves Changes for Natural Gas Liquids, 1986-1997 . . . . . . . . . . . . . . . . . . . . . . 8

7. U.S. Exploratory Gas Well Completions, 1977-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

8. U.S. Exploratory Oil Well Completions, 1977-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

9. U.S. Total Discoveries of Dry Natural Gas per Exploratory Gas Well Completion, 1977-1997 . . . . . . . . . . . 13

10. U.S. Total Discoveries of Crude Oil per Exploratory Oil Well Completion, 1977-1997 . . . . . . . . . . . . . . . 13

11. Reserves-to-Production Ratios for Crude Oil, 1945-1997. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

12. Reserves-to-Production Ratios for Wet Natural Gas, 1945-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . 15

13. Components of Ultimate Recovery for Crude Oil and Lease Condensate, 1977-1997 . . . . . . . . . . . . . . . 15

14. Components of Ultimate Recovery for Wet Natural Gas, 1977-1997 . . . . . . . . . . . . . . . . . . . . . . . . 15

15 Reserve Additions Nearly Replace U.S. Oil Production in 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . 19

16. 1997 Crude Oil Proved Reserves by Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

17. Changes in Crude Oil Proved Reserves by Area, 1996 to 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . 21

18. Reserve Additions Exceed U.S. Natural Gas Production 3 Years in a Row . . . . . . . . . . . . . . . . . . . . 27

19. 1997 Dry Natural Gas Proved Reserves by Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

20. Changes in Dry Natural Gas Proved Reserves by Area, 1996 to 1997 . . . . . . . . . . . . . . . . . . . . . . . 29

21. Coalbed Methane Proved Reserves, 1990-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report vii
Executive Summary

U.S. proved reserves of crude oil increased in 1997

for the first time in a decade. Natural gas reserves

were up for the fourth year in a row. Surprisingly

large revisions in some of California’s old and heavy

oil fields provided over half the oil increase. Oil and

gas discoveries in the Federal offshore—several in

deep water—also played a major role in the oil

reserves increase and the continuation of gas reserves

increases. Successful oil and gas well completions

were up.

Proved reserves are those quantities that geological

and engineering data demonstrate with reasonable

certainty to be recoverable in future years from

known reservoirs under existing economic and

operating conditions. Petroleum engineering and

geological judgment are required in estimating

proved reserves; therefore, the results are not precise

measurements. This report of 1997 U.S. proved

reserves of crude oil, natural gas, and natural gas

liquids is the 21st in the annual series prepared by

the Energy Information Administration.

Natural Gas

Gas reserve additions replaced gas production again

in 1997. Lower 48 States natural gas reserves

declined slightly in 1997, but increases in Alaskan

reserves due to revisions and adjustments more than

made up for it. Gas production has trended up since

1986 and is now 3.6 trillion cubic feet higher, yet, in

each of the last four years reserve additions replaced

production. The largest gas reserve additions were in

the Federal Offshore closely followed by those in

Texas. For 1997, revisions and adjustments to reserves

in existing fields were the lowest in the past decade

and half of 1996’s. In contrast, total gas discoveries

were the highest in the past decade.

U.S. total discoveries of dry gas reserves were 15,648

billion cubic feet in 1997, up 27 percent from a very

good 1996. Texas and the Gulf of Mexico Federal

Offshore accounted for over three-fifths of them.

Total discoveries, which equaled 81 percent of 1997 gas

production, are those reserves attributable to field

extensions, new field discoveries, and new reservoir

discoveries in old fields. They result from drilling

exploratory wells.

n New field discoveries were 2,681 billion cubic feet,

up substantially from 1996 and twice the prior

10-year average.

n Field extensions were 10,585 billion cubic feet, up

from 1996 and 68 percent above the prior 10-year

average.

n New reservoir discoveries in old fields were 2,382

billion cubic feet, down from 1996.

Coalbed methane reserves continued to grow faster

than conventional natural gas reserves, accounting

for nearly 7 percent of 1997’s proved gas reserves.

Coalbed methane production, now over 5 percent of

the U.S. total, also increased faster.

Other 1997 natural gas events of note:

n Exploratory gas well completions were down

slightly at 538 in 1997.

n Total discoveries per exploratory gas well were

up in 1997 and more than four times the rates of

the early 1980s.

n Natural gas prices at the wellhead increased

slightly to an annual average of $2.23 per

thousand cubic feet.

Crude Oil

Crude oil reserve additions replaced 125 percent of

1997 oil production, a result of the first reserves

increase in a decade.

Total discoveries of crude oil were 1,233 million

barrels in 1997, roughly twice as high as the prior

10-year average and a third higher than in 1996. The

Gulf of Mexico Federal Offshore accounted for over

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report ix

As of December 31, proved reserves were:

Dry Natural Gas (billion cubic feet)

1996 166,474

1997 167,223

Increase +0.4%

Crude Oil (million barrels)

1996 22,017

1997 22,546

Increase +2.4%

Natural Gas Liquids (million barrels)

1996 7,823

1997 7,973

Increase +1.9%
50 percent, much of it in deep water, Texas had 15

percent, and Alaska 11 percent.

Improved technologies for exploration and

deepwater production enhanced the ability to

discover and develop offshore fields, especially in

deep water. British Borneo’s Morpeth project in 1700

feet of water is an example of the use of

state-of-the-art engineering and technology that

lowers field development cost in deep water. The

field needed a way to inject water to maintain

reservoir pressure and oil production. A mini-tension

leg platform (SeaStar) and the first subsea injection

well in the Gulf of Mexico were used to develop this

oil field that would otherwise have been

uneconomic.

New field discoveries were 637 million barrels, more

than twice those of 1996 and over 5 times the prior

10-year average. The Gulf of Mexico Federal Offshore

had 79 percent of the new field discoveries, Alaska

had 18 percent, and the rest of the country had less

than 3 percent. Well over half of the proved reserves

of oil in the Gulf of Mexico are now in deep water

(water depths greater than 200 meters, about two

football fields).

Reserves in new fields are not counted by EIA until

they are proved. Many years may elapse between the

time an exploratory well locates a new field and the

year those oil or gas reserves are accepted as proved.

For example, the well that discovered the West Sak

Field in Alaska was drilled in 1971. But it was not

until 1997 that production facility sharing

arrangements and new low-cost drilling and

completion technologies made the field economic to

develop and hence proved.

n New reservoir discoveries in old fields were 119

million barrels, down some from 1996 but still

close to the prior 10-year average.

n Field extensions, up in 1997, added 477 million

barrels of proved oil reserves.

n Revisions and adjustments were 1,434 million

barrels in 1997. Even in an outstanding discovery

year, they still accounted for over half of total oil

reserve additions. Texas and California, States

with large oil reserves and large enhanced oil

recovery projects, had over half of revisions and

adjustments.

Technology improvements allowed California

operators to revise upward the reserves in old fields

with viscous heavy oil. For example, more oil is

efficiently heated by replacing less efficient steam

cycling processes with continuous steam injection

that lowers the oil viscosity allowing it to move more

easily to producing wells. This lowers costs and

increases production rates.

Alaska’s reserves declined in 1997 despite substantial

new field discoveries because there were not enough

revisions and adjustments to replace production.

Other 1997 crude oil events of note:

n The annual average domestic first purchase price

for crude oil declined 7 percent during 1997 to

$17.24 per barrel.

n Exploratory oil completions were down some at

418. However, total oil well completions

increased to 10,310 owing to an increase in oil

development activity.

n Total discoveries per exploratory oil well were

up over 50 percent in 1997, and over six times

the rates of the early 1980’s when oil prices and

the drilling boom peaked.

Indicated additional reserves of crude oil increased

to 3,207 million barrels in 1997. These are crude oil

volumes that may become economically recoverable

from known reservoirs through the application of

improved recovery techniques using current

technology. The presence of large indicated

additional reserves in north Alaska, California,

Texas, and Louisiana implies that significant upward

revisions to crude oil proved reserves can continue to

occur in the future.

Natural Gas Liquids

U.S. natural gas liquids proved reserves increased 2

percent to 7,973 million barrels in 1997. Natural gas

liquids reserves are the sum of natural gas plant

liquids and lease condensate reserves.

Total proved reserves of liquid hydrocarbons (crude

oil plus natural gas liquids) were 30,525 million

barrels in 1997, another increase. Natural gas liquids

were about a quarter of total proved reserves of

liquid hydrocarbon in 1997.

Data

These estimates are based upon analysis of data from

Form EIA-23, “Annual Survey of Domestic Oil and

Gas Reserves,” filed by 3480 operators of oil and gas

wells, and Form EIA-64A, “Annual Report of the

Origin of Natural Gas Liquids Production,” filed by

operators of 697 active natural gas processing plants.

The U.S. proved reserves estimates for crude oil and

natural gas are associated with sampling errors of

less than 1 percent.

Energy Information Administration

x U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
1. Introduction

Background

The principal focus of this report is to provide accurate

annual estimates of U.S. proved reserves of crude oil,

natural gas, and natural gas liquids. These estimates

are essential to the development, implementation, and

evaluation of national energy policy and legislation. In

the past, the Government and the public relied upon

industry estimates of proved reserves. However, the

industry ceased publication of reserve estimates after

its 1979 report.

In response to a recognized need for credible annual

proved reserves estimates, Congress, in 1977, required

the Department of Energy to prepare such estimates.

To meet this requirement, the Energy Information

Administration (EIA) developed a program that

established a unified, verifiable, comprehensive, and

continuing annual statistical series for proved reserves

of crude oil and natural gas. It was expanded to include

proved reserves of natural gas liquids for the 1979 and

subsequent reports.

Survey Overview

EIA defines proved reserves, the major topic of this

report, as those volumes of oil and gas that geological

and engineering data demonstrate with reasonable

certainty to be recoverable in future years from known

reservoirs under existing economic and operating

conditions. There are other categories of reserves, but

by definition they are more speculative and less precise

than proved reserves. Readers who are unfamiliar with

the distinctions between types of reserves or with how

reserves fit in the description of overall oil and gas

resources should see Appendix G.

While the primary topic of this report is proved

reserves, information is also presented on indicated

additional crude oil reserves. Indicated additional

crude oil reserves are not included in proved reserves

because of their uncertain economic recoverability.

When economic recoverability is demonstrated, these

volumes will be reclassified and transferred to the

proved reserves category as positive revisions.

This report provides proved reserves estimates for

calendar year 1997. It is based on data filed by large

operators of oil and gas wells on Form EIA-23, “Annual

Survey of Domestic Oil and Gas Reserves,” and by

operators of all natural gas processing plants on Form

EIA-64A, “Annual Report of the Origin of Natural Gas

Liquids Production.” The U.S. crude oil and natural gas

proved reserves estimates are associated with

sampling errors of less than 1 percent at a 95-percent

confidence level.

Form EIA-23

On Form EIA-23, an operator is defined as an

organization or person responsible for the

management and day-to-day operation of oil and/or

gas wells. This definition eliminates responses from

royalty owners, working interest owners (unless they

are also operators), and others not directly responsible

for oil and gas production operations.

Operator size categories are based upon their annual

production as indicated in various Federal, State, and

commercial records. Large operators are those that

produced at least 1.5 million barrels of crude oil or 15

billion cubic feet of natural gas, or both, during the

report year. Intermediate operators produced less than

large operators, but more than 400,000 barrels of crude

oil or 2 billion cubic feet of natural gas, or both. Small

operators are those that produced less than

intermediate operators. All data are reported on a total

operated basis, encompassing all proved reserves and

production associated with wells operated by an

individual operator. This concept is also called the

“gross operated” or “8/8ths” basis.

Large operators and most intermediate size operators

report reserves balance data on Form EIA-23 to show

how and why reserves components changed during

the year on a field-by-field basis. Intermediate size

operators who do not keep reserves data were not

asked to provide estimates of reserves at the beginning

of the year or annual changes to proved reserves by

component of change; i.e., revisions, extensions, and

new discoveries. These volumes were estimated by

applying an algebraic allocation scheme that preserved

the relative relationships between these items within

each State or State subdivision, as reported by large and

intermediate operators.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 1
The published reserve estimates include an additional

term, adjustments, calculated by the EIA, that

preserves an exact annual reserves balance of the form:

Adjustments are the annual changes in the published

reserve estimates that cannot be attributed to the

estimates for other reserve change categories. They

result from the survey and statistical estimation

methods employed. For example, variations caused by

changes in the operator frame, different random

samples, changes in reserve estimates following

ownership changes, incorrectly reported data, or

imputations for missing or unreported reserve changes

can contribute to adjustments.

Form EIA-64A

Form EIA-64A data were first collected for the 1979

survey year in order to develop estimates for total

natural gas liquids reserves. Data on liquids recovered

from natural gas, as reported by natural gas processing

plant operators, are combined with lease condensate

data collected on Form EIA-23 to provide the total

natural gas liquids reserves estimates.

Data Collection Operations

An intensive effort is made each year to maintain an

accurate and complete survey frame consisting of

operators of oil and gas wells and of natural gas

processing plants. The Form EIA-23 operator frame

contained 22,678 probable active operators and the

Form EIA-64A plant frame contained 654 probable

active natural gas processing plants in the United

States when the 1997 surveys were initiated. As usual,

additional operators were added to the survey as it

progressed, and many operators initially in the sample

frame were found to be inactive in 1997.

For the report year 1997, EIA mailed 641 EIA-23 forms

to all known large and intermediate size oil and gas

well operators that were believed to be active during

1997. Of these, 51 were found to be nonoperators that

did not have successor operators in 1997. Data were

received from 587operators, an overall response rate of

100 percent of the active operators in the Form EIA-23

survey. EIA mailed 654 EIA-64A forms to natural gas

processing plant operators. More than one form is

received for a plant that has more than one operator

during the year. Forms were received from 100 percent

of the operators of the 652 unique active natural gas

processing plants in the Form EIA-64A survey.

National estimates of the production volumes for crude

oil, lease condensate, natural gas liquids, and dry

natural gas based on Form EIA-23 and Form EIA-64A

were compared with corresponding official production

volumes published by EIA, which are obtained from

non-survey based State sources. For report year 1997,

the Form EIA-23 National production estimates were

1.8 percent lower than the comparable Petroleum Supply

Annual 1997 volumes for crude oil and lease

condensate combined, and were 1.6 percent higher

than the comparable Natural Gas Annual 1997 volume

for 1997 dry natural gas. For report year 1997, the Form

EIA-64A National estimates were 4.1 percent higher

than the Petroleum Supply Annual 1997 volume for

natural gas plant liquids production.

Energy Information Administration

2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Published Proved Reserves at End of Previous Report Year

+ Adjustments

+ Revision Increases

– Revision Decreases

+ Extensions

+ New Field Discoveries

+ New Reservoir Discoveries in Old Fields

– Report Year Production

= Published Proved Reserves at End of Report Year
2. Overview

National Summary

The United States had the following proved reserves as

of December 31, 1997:

n Crude Oil — 22,546 million barrels

n Dry Natural Gas — 167,223 billion cubic feet

n Natural Gas Liquids — 7,973 million barrels.

This Overview summarizes the 1997 proved reserves

balances of crude oil, dry natural gas, and natural gas

liquids on a National level and provides historical

comparisons between 1997 and years past.

Table 1 lists the estimated annual reserve balances

since 1987. In 1997, proved reserves of crude oil

increased by 2.4 percent, the first increase in the last

decade. Proved reserves of dry natural gas increased by

0.4 percent over the 1996 proved reserves level, making

1997 the fourth consecutive year that gas reserves have

increased.

Crude Oil

Proved reserves of crude oil increased by 529 million

barrels in 1997. The largest increase occurred in the

Federal Offshore portion of the Gulf of Mexico, where

382 million barrels of crude oil proved reserves were

added. California was a close second, where reserves

additions in the heavy oil fields raised the State total by

313 million barrels. Figure 1 shows the crude oil proved

reserves levels by major region and Figure 2 shows the

components of reserves changes from 1987 through

1997.

As shown in Figure 2, total reserve additions (the

positive side of the scale) were up substantially in 1997,

due to large increases in the volumes of new field

discoveries and revisions and adjustments. Production of

crude oil (the negative side of Figure 2‘s scale) declined

slightly for the sixth year in a row.

Total discoveries are those reserves attributable to field

extensions, new field discoveries, and new reservoir

discoveries in old fields. There were 1,233 million barrels

of total discoveries of crude oil proved reserves in 1997.

This is 33 percent more than in 1996.

Extensions added 477 million barrels of proved

reserves. This is 12 percent less than in 1996 (543

million barrels) and 9 percent more than the average

extensions in the prior 10 years (436 million barrels).

New field discoveries were 637 million barrels, more than

twice the 1996 level and more than five times the

average volume discovered in the prior 10 years (122

million barrels). New field discoveries in Alaska and

the Gulf of Mexico Federal Offshore made up 98

percent of the 1997 volume.

New reservoir discoveries in old fields added 119 million

barrels of proved reserves. This is less than the 1996

level (141 million barrels) and the prior 10-year average

for the United States (135 million barrels).

Revisions and adjustments added 1,434 million barrels of

proved reserves. This is 57 percent more than the 1996

volume (912 million barrels) and 11 percent more than

the average volume in the prior 10 years (1,293 million

barrels).

Production removed an estimated 2,138 million barrels

of proved reserves from the National total. Production

was down 2 percent from 1996’s level (2,173 million

barrels) and at 86 percent of the prior 10-year average

(2,473 million barrels). Reserves additions in 1997

replaced 125 percent of production.

Natural Gas

U.S. proved reserves of dry natural gas increased for

the fourth year in a row in 1997—up 0.4 percent from

1996’s level to a total of 167,223 billion cubic feet. Dry

natural gas reserves declined by 519 billion cubic feet in

the Lower 48 States, but reserves additions in Alaska

more than made up for that. Figure 3 shows the dry

natural gas proved reserves levels by major region and

Figure 4 shows the components of reserves changes

from 1987 through 1997. Dry natural gas production

increased for the second consecutive year in 1997, and

operators were able to replace 104 percent of 1997’s dry

gas production with new reserves.

For 1997, U.S. total discoveries of dry gas reserves were

15,648 billion cubic feet, up 27 percent from 1996. Total

discoveries were 78 percent of all reserve additions in

1997, while revisions and adjustments provided the

remaining 22 percent.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 3
Energy Information Administration

4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table 1. U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids, 1987-1997

Revisionsa New Reservoir Provedc Change Revision Revision and New Field Discoveries Totalb Reserves from

Adjustments Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

Crude Oil (million barrels of 42 U.S. gallons)

1987 233 3,687 1,371 2,549 484 96 111 691 2,873 27,256 +367

1988 364 2,684 1,221 1,827 355 71 127 553 2,811 26,825 -431

1989 213 2,698 1,365 1,546 514 112 90 716 2,586 26,501 -324

1990 86 2,483 1,000 1,569 456 98 135 689 2,505 26,254 -247

1991 163 2,097 1,874 386 365 97 92 554 2,512 24,682 -1,572

1992 290 1,804 1,069 1,025 391 8 85 484 2,446 23,745 -937

1993 271 2,011 1,516 766 356 319 110 785 2,339 22,957 -788

1994 189 2,364 1,357 1,196 397 64 111 572 2,268 22,457 -500

1995 122 1,823 795 1,150 500 114 343 957 2,213 22,351 -106

1996 175 1,723 986 912 543 243 141 927 2,173 22,017 -334

1997 520 1,998 1,084 1,434 477 637 119 1,233 2,138 22,546 +529

Dry Natural Gas (billion cubic feet, 14.73 psia, 60° Fahrenheit)

1987 1,268 17,527 14,231 4,564 4,587 1,089 1,499 7,175 16,114 187,211 -4,375

1988 2,193 23,367 d38,427 -12,867 6,803 1,638 1,909 10,350 16,670 d168,024 -19,187

1989 3,013 26,673 23,643 6,043 6,339 1,450 2,243 10,032 16,983 167,116 -908

1990 1,557 18,981 13,443 7,095 7,952 2,004 2,412 12,368 17,233 169,346 +2,230

1991 2,960 19,890 15,474 7,376 5,090 848 1,604 7,542 17,202 167,062 -2,284

1992 2,235 18,055 11,962 8,328 4,675 649 1,724 7,048 17,423 165,015 -2,047

1993 972 17,597 12,248 6,321 6,103 899 1,866 8,868 17,789 162,415 -2,600

1994 1,945 21,365 15,881 7,429 6,941 1,894 3,480 12,315 18,322 163,837 +1,422

1995 580 20,465 12,731 8,314 6,843 1,666 2,452 10,961 17,966 165,146 +1,309

1996 3,785 17,132 13,046 7,871 7,757 1,451 3,110 12,318 18,861 166,474 +1,328

1997 -590 21,658 16,756 4,312 10,585 2,681 2,382 15,648 19,211 167,223 +749

Natural Gas Liquids (million barrels of 42 U.S. gallons)

1987 231 847 656 422 213 39 55 307 747 8,147 -18

1988 11 1,168 715 464 268 41 72 381 754 8,238 +91

1989 -277 1,143 1,020 -154 259 83 74 416 731 7,769 -469

1990 -83 827 606 138 299 39 73 411 732 7,586 -183

1991 233 825 695 363 189 25 55 269 754 7,464 -122

1992 225 806 545 486 190 20 64 274 773 7,451 -13

1993 102 764 640 226 245 24 64 333 788 7,222 -229

1994 43 873 676 240 314 54 131 499 791 7,170 -52

1995 192 968 691 469 432 52 67 551 791 7,399 +229

1996 474 844 669 649 451 65 109 625 850 7,823 +424

1997 -14 1,199 910 275 535 114 90 739 864 7,973 +150

aRevisions and adjustments = Col. 1 + Col. 2 - Col. 3.

bTotal discoveries = Col. 5 + Col. 6 + Col. 7.

cProved reserves = Col. 10 from prior year + Col. 4 + Col. 8 - Col. 9.

dAn unusually large revision decrease to North Slope dry natural gas reserves was made in 1988. It recognizes some 24.6 trillion cubic

feet of downward revisions reported during prior years by operators because of economic and market conditions. The Energy Information

Administration (EIA) in previous years carried these reserves in the proved category.

Notes: Old means discovered in a prior year. New means discovered during the report year. The production estimates in this table are

based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves” and Form EIA-64A, “Annual Report of the Origin

of Natural Gas Liquids Production.” They may differ from the official EIA production data for crude oil, natural gas, and natural gas liquids for

1997 contained in the Petroleum Supply Annual 1997, DOE/EIA-0340(97) and the Natural Gas Annual 1997, DOE/EIA-0131(97).

Sources: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1987 through 1997 annual reports, DOE/EIA-0216.{10-20}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 5

Figure 1. U.S. Crude Oil Proved Reserves, 1987-1997

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1987-1997 annual reports, DOE/EIA-0216.{10-20}

-5

-4

-3

-2

-1

0

1

2

3

4

5

1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997

Crude Oil, Billion Barrels

-5

-4

-3

-2

-1

0

1

2

3

4

5

New Fields New Reservoirs Extensions

Production Revisions & Adjustments Net Reserves Changes

0

5

10

15

20

25

30

1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997

Crude Oil, Billions of Barrels

0

5

10

15

20

25

30

U.S. Total

Lower 48 Onshore

Lower 48 Offshore

Alaska

Figure 2. Components of Reserves Changes for Crude Oil, 1987-1997
Energy Information Administration

6 U.S. Crude Oil, NaturalGas, and Natural Gas Liquids Reserves 1997 Annual Report

Figure 4. Components of Reserves Changes for Dry Natural Gas, 1987-1997

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1987-1997 annual reports, DOE/EIA-0216.{10-20}

Figure 3. U.S. Dry Natural Gas Proved Reserves, 1987-1997

0

20

40

60

80

100

120

140

160

180

200

1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997

Dry Natural Gas, Trillion Cubic Feet

0

20

40

60

80

100

120

140

160

180

200

U.S. Total

Lower 48 Onshore

Lower 48 Offshore

Alaska

-30

-20

-10

0

10

20

30

1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997

Dry Natural Gas, Trillion Cubic Feet

-30

-20

-10

0

10

20

30

New Fields New Reservoirs Extensions

Production Revisions & Adjustments Net Reserves Changes
Extensions added 10,585 billion cubic feet of proved

reserves. This is 36 percent more than 1996’s extensions

and 68 percent more than the average of extensions in

the prior 10 years (6,309 billion cubic feet).

New field discoveries added 2,681 billion cubic feet of

proved reserves. This is 85 percent more than what was

discovered in 1996 and 97 percent higher than the

average volume discovered in the prior 10 years (1,359

billion cubic feet).

New reservoir discoveries in old fields added 2,382 billion

cubic feet of proved reserves. This is 23 percent less

than the volume discovered in 1996, but 7 percent

higher than the prior 10-year average (2,230 billion

cubic feet).

Revisions and Adjustments added 4,312 billion cubic feet

of proved reserves. This is 45 percent less than 1996’s

revisions and adjustments and 85 percent of the prior

10-year average.

Production removed an estimated 19,211 billion cubic

feet of proved reserves from the National total. Gas

production increased compared to 1996, for the second

consecutive year.

Coalbed methane gas production and reserves are

included in the 1997 totals. However, EIA separately

tracks of these reserves in order to record the

development and performance of this gas source.

Coalbed methane reserves increased in 1997 to a

volume of 11,462 billion cubic feet. Coalbed methane

accounts for 7 percent of 1997 U.S. dry natural gas

reserves and 6 percent of 1997 U.S. dry gas production.

No Federal tax incentives for new coalbed methane

wells have been available for 4 years.

Natural Gas Liquids

Proved reserves of natural gas liquids increased 150

million barrels to 7,973 million barrels during 1997—2

percent higher than 1996 levels. An increase of 294

million barrels occurred in Alaska, while the lower 48

States’ reserves decreased by 144 million barrels.

Figure 5 shows the natural gas liquids proved reserves

levels by major region and Figure 6 shows the

components of reserves changes from 1987 through

1997.

Operators replaced 117 percent of their 1997 natural

gas liquids production with reserve additions. Total

discoveries accounted for 73 percent of all reserve

additions, while revisions and adjustments accounted for

the remaining 27 percent.

Total proved reserves of liquid hydrocarbons (crude oil

plus natural gas liquids) were 30,519 million barrels in

1997—an increase of 679 million barrels from the 1996

level. Natural gas liquids represented 26 percent of

total liquid hydrocarbon proved reserves in 1997.

Reserves Changes Since 1977

EIA has collected oil and gas reserves estimates

annually since 1977. Table 2 lists the cumulative totals

of the components of reserves changes for crude oil and

dry natural gas from 1977 through 1997. Table 2

contains two sections, one for the lower 48 States and

another for the U.S. total (which includes Alaska's

contribution). Annual averages for each component of

reserves changes are also listed, along with the

percentage of that particular component's impact on

total U.S. proved reserves. In this section, we compare

these averages to the 1997 proved reserves estimates as

a means of gauging the past year against history.

Crude Oil: Since 1977 U.S. operators have:

n discovered an average of 813 million barrels per

year of new reserves

n revised and adjusted their proved reserves

upward by an average of 1,363 million barrels

per year from revisions and adjustments

n ended each year with an average net reduction

in U.S. proved reserves of 522 million barrels

(the difference between post-1976 average

annual production and post-1976 average

annual reserve additions) because production

has outpaced reserve additions.

Since 1977, crude oil reserves have been primarily

sustained by the extension and development of

existing fields (called field growth, reserves growth, or

the EIA preferred term: proved ultimate recovery

appreciation. See Proved Ultimate Recovery section

later in this chapter.), rather than the discovery of new

oil fields. Only 7.6 percent of reserves additions since

1976 were booked as new field discoveries. Proved

ultimate recovery appreciation is the sum of net

revisions and adjustments, extensions, and new

reservoirs in old fields. Since 1977, the largest

component of proved ultimate recovery appreciation

for crude oil is upward revisions and adjustments, which

accounted for 63 percent of all crude oil reserves

additions. The 17,069 million barrels of total discoveries

accounted for the remaining 37 percent of reserves

additions.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 7
Energy Information Administration

8 U.S. Crude Oil, NaturalGas, and Natural Gas Liquids Reserves 1997 Annual Report

Figure 5. U.S. Natural Gas Liquids Proved Reserves, 1987-1997

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1987-1997 annual reports, DOE/EIA-0216.{10-20}

0

1

2

3

4

5

6

7

8

9

1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997

Natural Gas Liquids, Billion Barrels

0

1

2

3

4

5

6

7

8

9

U.S. Total

Lower 48 Onshore

Lower 48 Offshore

Alaska

-2

-1.5

-1

-0.5

0

0.5

1

1.5

2

1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997

Natural Gas Liquids, Billion Barrels

-2

-1.5

-1

-0.5

0

0.5

1

1.5

2

New Fields New Reservoirs Extensions

Production Revisions & Adjustments Net Reserves Changes

Figure 6. Components of Reserves Changes for Natural Gas Liquids, 1987-1997
Compared to the average reserves changes since 1977,

1997 was a good year for crude oil discoveries. 1997’s

total discoveries of crude oil exceeded the post-1976 U.S.

average by 52 percent, while revisions and adjustments

were 5 percent higher than the post-1976 U.S. average.

Only one component of total discoveries exceeded the

post-1976 averages—new field discoveries. Since 1977,

operators have found only an average of 166 million

barrels of crude oil proved reserves per year from new

field discoveries. In 1997, operators discovered 637

million barrels of proved reserves—384 percent of the

post-1976 average.

Dry Natural Gas: Since 1977, U.S. operators:

n discovered an average of 12,054 billion cubic

feet per year of new reserves

n revised and adjusted their proved reserves

upward by an average 3,381 billion cubic feet

per year

n had an average net reduction in U.S. reserves of

2,193 billion cubic feet per year.

Like crude oil reserves, natural gas reserves have been

sustained primarily by proved ultimate recovery

appreciation since 1977. However, extensions rather

than net revisions and adjustments is the largest

component. Extensions account for 48 percent while

revisions and adjustments account for only 22 percent of

all reserve additions since 1977. In recent years, the

percentage of net revisions and adjustments has been as

high as 39 percent, but in 1997 it matched the National

average of 22 percent.

Compared to the average reserves changes since 1977,

1997 was a good year for natural gas reserve additions

from total discoveries. U.S. total dry natural gas reserves

increased for the fourth year in a row. Operators

reported 15,648 billion cubic feet of total discoveries to

their dry natural gas proved reserves—30 percent

higher than the post-1976 average (12,054 billion cubic

feet). However, compared to the post-1976 U.S.

average, net revisions and adjustments were lower.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 9

Table 2. Reserves Changes, 1977-1997

Lower 48 States U.S. Total

Average Percent Average Percent

per of Reserve per of Reserve

Components of Change Volume Year Additions Volume Year Additions

Crude Oil (million barrels of 42 U.S. gallons)

Proved Reserves as of 12/31/76 ...... 24,928 –– –– 33,502 –– ––

New Field Discoveries ........... 2,987 142 8.1 3,482 166 7.6

New Reservoir Discoveries in Old Fields . . 2,879 137 7.8 2,909 139 6.4

Extensions ................ 9,557 455 26.0 10,678 508 23.4

Total Discoveries ............. 15,423 734 41.9 17,069 813 37.4

Revisions and Adjustments ........ 21,348 1,017 58.1 28,620 1,363 62.6

Total Reserve Additions .......... 36,771 1,751 100.0 45,688 2,176 100.0

Production ................ 44,314 2,110 120.5 56,645 2,697 124.0

Net Reserve Change............ -7,543 -359 -20.5 -10,956 -522 -24.0

Dry Natural Gas (billion cubic feet at 14.73 psia and 60° Fahrenheit)

Proved Reserves as of 12/31/76 ...... 180,838 –– –– 213,278 –– ––

New Field Discoveries ........... 41,567 1,979 12.3 41,655 1,984 12.9

New Reservoir Discoveries in Old Fields . . 54,138 2,578 16.0 54,503 2,595 16.8

Extensions ................ 156,060 7,431 46.0 156,975 7,475 48.4

Total Discoveries ............. 251,765 11,989 74.3 253,133 12,054 78.1

Revisions and Adjustments ........ 87,274 4,156 25.7 71,009 3,381 21.9

Total Reserve Additions .......... 339,039 16,145 100.0 324,142 15,435 100.0

Production ................ 363,216 17,296 107.1 370,197 17,628 114.2

Net Reserve Change............ -24,177 -1,151 -7.1 -46,055 -2,193 -14.2

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1977-1997 annual reports, DOE/EIA-0216.{1-20}
Economics and Drilling

Economics: Table 3 lists the average annual domestic

wellhead prices of crude oil and natural gas, as well as

the average number of active rotary drilling rigs, from

1970 to 1997.

The U.S. crude oil first purchase price (less the Alaskan

North Slope) started at an average of $22.68 per barrel

in January 1997, but declined to $17.21 per barrel in

April. Prices wavered until October, when they began

an unabated five-month decline from $18.56 in October

1997 to $11.53 in March 1998. In 1997 constant dollars,

this price was approximately the same as the price in

1970. The average U.S. crude oil first purchase price

(less the Alaskan North Slope) declined from an

average $19.41 in 1996 to $17.92 per barrel in 1997.

Oil prices vary by region. In Texas the average 1997

price was $18.64 per barrel, while in California it was

$15.78 per barrel, and only $14.84 per barrel on the

Alaskan North Slope. The lowest average crude oil first

purchase price in 1997 was for Federal Offshore

California oil—$12.97 per barrel{21}.

The average annual wellhead natural gas price

increased from $2.17 in 1996 to $2.23 per thousand

cubic feet in 1997. Gas prices started at $3.42 per

thousand cubic feet in January 1997, but declined to

Energy Information Administration

10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table 3. U.S. Average Annual Domestic Wellhead Prices for Crude Oil and Natural Gas, and the

Average Number of Active Rotary Drilling Rigs, 1970-1997

Crude Oil Natural Gas

Year Current 1997 Constant Current 1997 Constant

(dollars per barrel) (dollars per thousand cubic feet) Number of Rigs

1970 3.18 11.60 0.17 0.62 1,028

1971 3.39 11.75 0.18 0.62 976

1972 3.39 11.29 0.19 0.63 1,107

1973 3.89 12.26 0.22 0.69 1,194

1974 6.87 19.91 0.30 0.87 1,472

1975 7.67 20.28 0.44 1.16 1,660

1976 8.19 20.49 0.58 1.45 1,658

1977 8.57 20.18 0.79 1.86 2,001

1978 9.00 19.69 0.91 1.99 2,259

1979 12.64 25.51 1.18 2.38 2,177

1980 21.59 39.89 1.59 2.94 2,909

1981 31.77 53.80 1.98 3.35 3,970

1982 28.52 45.40 2.46 3.92 3,105

1983 26.19 39.98 2.59 3.95 2,232

1984 25.88 38.05 2.66 3.91 2,428

1985 24.09 34.20 2.51 3.56 1,980

1986 12.51 17.32 1.94 2.69 964

1987 15.40 20.68 1.67 2.24 936

1988 12.58 16.31 1.69 2.19 936

1989 15.86 19.73 1.69 2.10 869

1990 20.03 23.88 1.71 2.04 1,010

1991 16.54 18.97 1.64 1.88 860

1992 15.99 17.84 1.74 1.94 721

1993 14.25 15.50 2.04 2.22 754

1994 13.19 14.01 1.85 1.96 775

1995 14.62 15.18 1.55 1.61 723

1996 R19.41 19.78 R2.17 2.21 779

1997 17.92 17.92 2.23 2.23 943

R=Revised data.

Sources: Current dollars and number of rigs: Monthly Energy Review September 1998, DOE/EIA-0035(98/09). 1997 constant dollars:

U.S. Department of Commerce, Bureau of Economic Analysis, Gross Domestic Product Implicit Price Deflators, June 1998.
$1.61 per thousand cubic feet by March 1997 (the lowest

average price of the year). In June, prices rose to $2.01,

but declined to $1.91 in July. In November, prices

reached $2.77 per thousand cubic feet, yet declined in

December to $2.17 per thousand cubic feet, more than a

dollar less than prices of December 1996.{22}

Drilling: From 1996 to 1997, the annual average active

rig count increased from 779 to 943 (Table 3). The rig

count remains well below the peak activity level of 1981

(average 3,970 rigs) but, it must be realized that a

comparison of only the bulk number of wells drilled is

not representative of drilling’s impact on reserves

levels over time. Operators are now using significantly

improved drilling and seismic exploration technology

to dramatically increase their drilling success rate.

Looking first at exploratory wells, there were 3,031

exploratory wells drilled in 1997 (Table 4). Of these, 14

percent were oil wells, 18 percent were gas wells, and

68 percent were dry holes. The total (which includes

dry holes) was 4 percent less than in 1996.

Although the number of active rigs increased in 1997,

there were fewer successful exploratory wells. There

were 5 percent less exploratory gas wells (Figure 7) and

13 percent fewer exploratory oil wells (Figure 8) than in

1996. On the other hand, as shown in Table 4, the

number of successful development wells increased for

both oil and gas.

Figures 9 and 10 show the average volume of

discoveries per exploratory well for dry natural gas

and oil, respectively, since 1977. The average volume of

gas discoveries per exploratory well increased 32

percent in 1997 from the 1996 level. The average

volume of oil discoveries per exploratory well in 1997 is

53 percent higher than 1996's level. There were an

estimated 27,007 exploratory and development wells

drilled in 1997, 19 percent more than in 1996 and

slightly higher the average number of wells drilled

annually in the prior 10 years (26,893).

Operators completed more oil and gas wells in 1997

than in 1996. For the fifth year in a row, the number of

gas well completions exceeded the number of oil well

completions in both the exploratory and development

categories.

Reserve-to-Production Ratio

and Ultimate Recovery

R/P Ratios

The relationship between proved reserves and

production levels, expressed as the ratio of reserves to

production (R/P ratio) is often used in analyses. For a

mature producing area, the R/P ratio tends to be

reasonably stable, so that the proved reserves at the end

of a year serve as a rough guide to the production level

that can be maintained during the following year.

Operators report data which yield R/P ratios that vary

widely by area depending upon:

n category of operator

n geology and economics

n number and size of new discoveries

n amount of drilling that has occurred.

R/P ratios are an indication of the state of development

in an area and, over time, the ratios change. For

example, when the Alaskan North Slope oil reserves

were booked, the U.S. R/P ratio for crude oil increased

because significant production from these reserves did

not begin until 7 years after booking due to the need to

first build the Trans Alaska pipeline. The U.S. R/P ratio

for crude oil decreased from 11.1-to-1 to 9.4-to-1

between 1977 and 1982, as Alaskan North Slope oil

production reached high levels.

In 1997, U.S. crude oil proved reserves increased and

oil production decreased—resulting in a slight increase

in the National average R/P ratio, from 10.1 to 10.6.

Figure 11 shows the U.S. R/P ratio trend for crude oil

since 1945. After World War II, increased drilling and

discoveries led to a greater R/P ratio. Later, when

drilling found fewer reserves than were produced, the

ratio became smaller. R/P Ratios also vary

geographically. Less developed areas of the country,

such as the Pacific offshore, have higher R/P ratios for

crude oil than the 1997 National average of 10.6-to-1.

Other areas with relatively high R/P ratios are the

Permian Basin of Texas and New Mexico, and

California, where enhanced oil recovery techniques

such as carbon dioxide (CO2) injection or

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 11
steamflooding have improved recoverability of oil in

old, mature fields. Areas that have the lowest R/P

ratios, like the Mid-Continent region, usually have

many older fields. There, new technologies such as

horizontal drilling have helped add reserves

equivalent to the annual production, keeping the

regional reserves and R/P ratio for oil relatively stable.

Figure 12 shows the historical R/P ratio for wet natural

gas since 1945. Prior to 1945, R/P ratios were very high

since the interstate pipeline infrastructure was not well

developed. The market for and production of natural

gas grew rapidly after World War II, lowering the R/P

ratio. The U.S. average R/P ratio for natural gas

decreased in 1997, as the proportional increase in

reserves was not as much as the increase in production.

Different marketing, transportation, and production

characteristics for gas are seen when looking at

regional average R/P ratios, compared to the 1997 U.S.

average R/P ratio of about 8.7-to-1. The areas with the

higher range of R/P ratios are the less developed or less

productive areas of the country, such as the Pacific

offshore and the Rockies, and also include areas such as

Energy Information Administration

12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table 4. U.S. Exploratory and Development Well Completions,a 1970-1997

Exploratoryb Total Exploratory and Developmentb

Year Oil Gas Dry Total Oil Gas Dry Total

1970 763 478 6,193 7,434 13,043 4,031 11,099 28,173

1971 664 472 5,995 7,131 11,903 3,983 10,382 26,268

1972 690 659 6,202 7,551 11,437 5,484 11,013 27,934

1973 642 1,067 5,952 7,661 10,167 6,933 10,320 27,420

1974 859 1,190 6,833 8,882 13,647 7,138 12,116 32,901

1975 982 1,248 7,129 9,359 16,948 8,127 13,646 38,721

1976 1,086 1,346 6,772 9,204 17,688 9,409 13,758 40,855

1977 1,164 1,548 7,283 9,995 18,745 12,122 14,985 45,852

1978 1,171 1,771 7,965 10,907 19,181 14,413 16,551 50,145

1979 1,321 1,907 7,437 10,665 20,851 15,254 16,099 52,204

1980 1,764 2,081 9,039 12,884 32,639 17,333 20,638 70,610

1981 2,636 2,514 12,349 17,499 43,598 20,166 27,789 91,553

1982 2,431 2,125 11,247 15,803 39,199 18,979 26,219 84,397

1983 2,023 1,593 10,148 13,764 37,120 14,564 24,153 75,837

1984 2,197 1,521 11,278 14,996 42,605 17,127 25,681 85,413

1985 1,679 1,189 8,924 11,792 35,118 14,168 21,056 70,342

1986 1,084 793 5,549 7,426 19,097 8,512 12,661 40,270

1987 925 753 5,049 6,727 16,164 8,055 11,101 35,320

1988 855 730 4,691 6,276 13,636 8,555 10,041 32,232

1989 607 707 3,924 5,238 10,204 9,539 8,188 27,931

1990 653 691 3,715 5,059 12,198 11,044 8,309 31,551

1991 593 538 3,312 4,443 11,770 9,526 7,599 28,895

1992 496 424 2,510 3,430 8,757 8,209 6,118 23,084

1993 500 544 2,470 3,514 8,365 10,005 6,295 24,665

1994 566 720 2,400 3,686 6,690 9,538 5,279 21,507

1995 541 567 2,198 3,306 7,627 8,337 5,075 21,039

1996 481 560 2,130 3,171 8,301 9,185 5,220 22,706

1997 418 534 2,079 3,031 10,268 11,245 5,494 27,007

aExcludes service wells and stratigraphic and core testing.

bAll drilling counts for the years 1973-1996 have been revised.

Notes: Estimates are based on well completions taken from American Petroleum Institute data tapes through June 1997. Due to the

method of estimation, data shown are frequently revised. Data are no longer rounded to nearest 10 wells.

Sources: Years 1970-1972: Energy Information Administration, Office of Oil and Gas.Years 1973-1997: Monthly Energy Review

September 1998, DOE/EIA-0035(98/09).
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 13

Source: Energy Information Administration, Office of Oil and Gas.

0

500

1,000

1,500

2,000

2,500

3,000

77 79 81 83 85 87 89 91 93 95 97

Wells

0

5

10

15

20

25

30

35

77 79 81 83 85 87 89 91 93 95 97

Billion Cubic Feet per Well

0

500

1,000

1,500

2,000

2,500

3,000

77 79 81 83 85 87 89 91 93 95 97

Wells

0

0.5

1

1.5

2

2.5

3

3.5

77 79 81 83 85 87 89 91 93 95 97

Million Barrels per Well

Figure 7. U.S. Exploratory Gas Well Completions,

1977-1997

Figure 9. U.S. Total Discoveries of Dry Natural Gas per

Exploratory Gas Well Completion, 1977-1997

Figure 8. U.S. Exploratory Oil Well Completions,

1977-1997

Figure 10. U.S. Total Discoveries of Crude Oil per

Exploratory Oil Well Completion, 1977-1997
Alabama and Colorado where considerable booking of

coalbed methane reserves has recently occurred.

Several major gas producing areas have R/P ratios

below the National average, particularly Texas, the

Gulf of Mexico Federal Offshore, and Oklahoma. The

R/P ratio of these three areas combined decreased from

7.0-to-1 in 1996 to 6.8-to-1 in 1997, and is below the

National 1997 average.

Proved Ultimate Recovery

EIA in past reports has defined Ultimate Recovery as

the sum of proved reserves and cumulative

production. However, despite EIA’s clear definition,

the volume presented by EIA has often been misused

or misinterpreted as the maximum recoverable volume

of resources for an area. This neglects the addition of

proved reserves over time through ultimate recovery

appreciation (a.k.a. reserves growth or field growth)

and has led some to make overly-pessimistic resource

assessments for the United States. EIA is therefore

introducing a new term, Proved Ultimate Recovery:

Proved Ultimate Recovery is the sum of

proved reserves and cumulative production. It is

expected to change over time for any field, group

of fields, State, or Country. Proved Ultimate

Recovery does not represent the maximum

recoverable volume of resources for an area. It is

instead a gauge of how much has already been

produced plus proved reserves. Proved reserves

of crude oil or natural gas are the estimated

quantities of petroleum which geological and

engineering data demonstrate with reasonable

certainty to be recoverable in future years from

known reservoirs under existing economic and

operating conditions. When deterministic proved

reserves estimation methods are used, the term

reasonable certainty is intended to express a high

degree of confidence that the estimated quantities

will be recovered. When probabilistic methods are

used there should be at least a 90 percent

probability that the actual quantities recovered

will exceed the estimate.

Figures 13 and 14 show successive estimates of proved

ultimate recovery and its components, proved reserves

and cumulative production, for crude oil plus lease

condensate, and wet natural gas, from 1977 through

1997. They illustrate the continued appreciation

(growth) of proved ultimate recovery over time.

In 1977, U.S. crude oil and lease condensate proved

reserves were 33,615 million barrels. Cumulative

production for 1977 through 1997 was 57,258 million

barrels. This substantially exceeds the 1977 proved

reserves, but at the end of 1997 there were still 23,887

million barrels of crude oil and lease condensate

proved reserves. Therefore, the Nation’s estimated

proved ultimate recovery of crude oil was

fundamentally increased during this period owing to

the proved ultimate recovery appreciation process

(continued development of old fields). In fact, only 7.6

percent of proved reserves additions of crude oil were

booked as new field discoveries from 1976 through 1997.

The rest was from proved reserves categories included

in the proved ultimate recovery appreciation process

(new reservoir discoveries in old fields, extensions, and

revisions and adjustments.) A significant part of the total

proved ultimate recovery appreciation came from the

proved ultimate recovery appreciation of those new

fields discovered between 1976 and 1997.

Similarly, the 1977 wet natural gas proved reserves

were 209,490 billion cubic feet, and cumulative wet gas

production from 1977 through 1997 was 371,368 billion

cubic feet. Cumulative wet gas production exceeded

the 1977 reserves by 161,878 billion cubic feet, but at the

end of 1997 there were still 175,721 billion cubic feet of

wet natural gas proved reserves, for the same reasons.

Only 12.9 percent of proved reserve additions of

natural gas were booked as new field discoveries from

1976 through 1997.

International Perspective

International Reserves

The EIA estimates domestic oil and gas reserves but

does not systematically estimate worldwide reserves.

As shown in Table 5, international reserves estimates

are presented in two widely circulated trade

publications. The world's total reserves are estimated

to be roughly 1 trillion barrels of oil and 5 quadrillion

cubic feet of gas.

The United States ranked 11th in the world for proved

reserves of crude oil and 6th for natural gas in 1997,

unchanged from 1996. A comparison of EIA's U.S.

proved reserves estimates with worldwide estimates

obtained from other sources shows that the United

States had about 2 percent of the world's total crude oil

proved reserves and over 3 percent of the world's total

natural gas proved reserves at the end of 1997. There

are sometimes substantial differences between the

estimates from these sources. The Oil & Gas Journal

reported oil reserves for the United Arab Emirates at

Energy Information Administration

14 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 15

Sources: Annual reserves and production - American Petroleum Institute and American Gas Association (1945–1976){23} and Energy

Information Administration, Office of Oil and Gas (1977–1997){1-20}. Cumulative production: U.S. Oil and Gas Reserves by Year of Field

Discovery (1977-1988).{24}

0

5

10

15

20

25

30

35

45 50 55 60 65 70 75 80 85 90 95

R/P Ratio

United States

Lower 48 States

0

5

10

15

20

25

30

35

45 50 55 60 65 70 75 80 85 90 95

R/P Ratio

United States

Lower 48 States

0

50

100

150

200

250

77 79 81 83 85 87 89 91 93 95 97

Billions of Barrels

Cumulative Production

Proved Reserves

Ultimate Recovery

0

200

400

600

800

1,000

1,200

77 79 81 83 85 87 89 91 93 95 97

Trillions of Cubic Feet

Cumulative Production

Proved Reserves

Ultimate Recovery

Figure 11. Reserves-to-Production Ratios for

Crude Oil, 1945-1997

Figure 13. Components of Proved Ultimate Recovery for

Crude Oil and Lease Condensate, 1977-1997

Figure 12. Reserves-to-Production Ratios for

Wet Natural Gas, 1945-1997

Figure 14. Components of Proved Ultimate Recovery

for Wet Natural Gas, 1977-1997
Table 5. International Oil and Natural Gas Reserves as of December 31, 1997

Oil

(million barrels)

Natural Gas

(billion cubic feet)

Oil & Gas World Oil & Gas World

Ranka Country Journal Oil Rankb Country Journal Oil

1 Saudi Arabiac . . . . . . . . d261,500 d263,800 1 Former U.S.S.R.. . . . . . . 1,977,000 1,891,308

2 Iraqc . . . . . . . . . . . . . . . 112,500 99,665 2 Iranc . . . . . . . . . . . . . . . . 810,000 812,239

3 Kuwaitc . . . . . . . . . . . . . d96,500 d93,480 3 Qatarc . . . . . . . . . . . . . . 300,000 270,000

4 Iranc . . . . . . . . . . . . . . . 93,000 89,700 4 Saudi Arabiac. . . . . . . . . d190,000 d230,363

5 United Arab Emiratesc . 97,800 63,642 5 United Arab Emiratesc . . 205,400 208,843

6 Former U.S.S.R. . . . . . . 57,000 63,065 6 United States . . . . . . . . e166,474 f

168,055

7 Venezuelac . . . . . . . . . . 71,669 45,500 7 Venezuelac . . . . . . . . . . 143,078 145,522

8 Mexico . . . . . . . . . . . . . 40,000 40,822 8 Algeriac . . . . . . . . . . . . . 130,600 139,500

9 China . . . . . . . . . . . . . . 24,000 34,030 9 Nigeriac . . . . . . . . . . . . . 114,852 109,200

10 Libyac . . . . . . . . . . . . . . 29,500 26,900 10 Iraqc . . . . . . . . . . . . . . . . 109,800 112,600

Top 10 Total. . . . . . . . . . . . . . 883,679 820,604 Top 10 Total . . . . . . . . . . . . . . 4,151,804 4,087,630

11 United States. . . . . . . . e22,217 f

21,685 11 Indonesiac . . . . . . . . . . . 72,268 137,794

12 Nigeriac. . . . . . . . . . . . . 16,786 21,225 12 Malaysia. . . . . . . . . . . . . 79,300 87,011

13 Algeriac. . . . . . . . . . . . . 9,200 13,800 13 Canada. . . . . . . . . . . . . . 65,020 67,500

14 Norway . . . . . . . . . . . . . 10,422 11,665 14 Mexico . . . . . . . . . . . . . . 63,900 63,456

15 Indonesiac . . . . . . . . . . 4,980 8,092 15 Netherlands . . . . . . . . . . 61,306 63,081

16 Brazil. . . . . . . . . . . . . . . 4,800 7,106 16 Kuwaitc. . . . . . . . . . . . . . d52,900 d66,725

17 Canada . . . . . . . . . . . . . 4,893 5,475 17 Norway. . . . . . . . . . . . . . 52,301 41,407

18 United Kingdom . . . . . . 5,003 5,191 18 Libyac. . . . . . . . . . . . . . . 46,300 45,500

19 Angola . . . . . . . . . . . . . 5,412 3,900 19 China . . . . . . . . . . . . . . . 41,000 42,360

20 Oman . . . . . . . . . . . . . . 5,238 3,760 20 Australia . . . . . . . . . . . . . 19,429 51,904

21 Malaysia . . . . . . . . . . . . 3,900 4,981 21 Egypt . . . . . . . . . . . . . . . 27,622 28,765

22 Qatarc . . . . . . . . . . . . . . 3,700 4,153 22 United Kingdom . . . . . . . 26,839 27,005

23 India . . . . . . . . . . . . . . . 4,340 3,511 23 Oman . . . . . . . . . . . . . . . 27,450 21,250

24 Egypt . . . . . . . . . . . . . . 3,835 3,720 24 Argentina . . . . . . . . . . . . 24,308 24,198

25 Yemen . . . . . . . . . . . . . 4,000 3,100 25 India . . . . . . . . . . . . . . . . 17,356 13,477

Top 25 Total. . . . . . . . . . . . . . 992,405 941,968 Top 25 Total . . . . . . . . . . . . . . 4,829,103 4,869,063

OPEC Total . . . . . . . . . . . . . . 797,135 729,957 OPEC Total . . . . . . . . . . . . . . . 2,175,198 2,278,286

World Total . . . . . . . . . . . . . . 1,019,546 974,179 World Total . . . . . . . . . . . . . . . 4,829,103 5,096,027

aRank is based on an average of oil reserves reported by Oil & Gas Journal and World Oil. bRank is based on an average of natural gas reserves reported by Oil & Gas Journal and World Oil. cMember of the Organization of Petroleum Exporting Countries (OPEC).

dIncludes one-half of the reserves in the Neutral Zone.

eEnergy Information Administration proved reserves as of December 31, 1996 were published by the Oil & Gas Journal as its estimates as

of December 31, 1997. f

World Oil estimate.

Note: The Energy Information Administration does not certify these international reserves data, but reproduces the information as a matter

of convenience for the reader.

Sources: PennWell Publishing Company, Oil and Gas Journal, December 29, 1997, pps. 38-39. Gulf Publishing Company, World Oil,

August, 1998, p. 29.

Energy Information Administration

16 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
about 98 billion barrels. This is about 50 percent higher

than the World Oil estimate of 64 billion. One reason

(among many) for these differences is that condensate

is often included in foreign oil reserve estimates.

The Oil & Gas Journal{25} estimate for world oil reserves

remained about the same in 1997, while the World

Oil{26} estimate decreased 16 percent, mostly due to

World Oil’s re-evaluation of Venezuela and the former

Soviet Union’s proved reserves.{27} For world gas

reserves, the Oil & Gas Journal reported a 3 percent

increase, while World Oilreported a 2 percent decrease.

Several foreign countries have oil reserves

considerably larger than those of the United States.

Saudi Arabian oil reserves are the largest in the world,

dwarfing U.S. oil reserves. Iraqi oil reserves are almost

5 times U.S. reserves. Closer to home, Venezuela has

more than double and Mexico has around 84 percent

more than the United States' oil reserves. (Based on

averages of the World Oil and Oil & Gas Journal

estimates).

Petroleum Consumption

The United States is the world's largest energy

consumer. The EIA estimates energy consumption and

publishes it in its Annual Energy Review.{28} In 1997:

n The U.S. consumed 94,209,000,000,000,000 Btu of

energy (94.21 quadrillion Btu).

n 63 percent of U.S. energy consumption was

provided by petroleum and natural gas—crude

oil and natural gas liquids combined (39

percent), and natural gas (24 percent).

n U.S. petroleum consumption was about 18.6

million barrels of oil and natural gas liquids

and 60.3 billion cubic feet of dry gas per day.

Dependence on Imports

The United States remains heavily dependent on

imported oil and gas to satisfy its ever-increasing

appetite for energy. In 1996, the U.S. was dependent on

net petroleum imports for 46 percent of energy

consumption. In 1997, it increased to a 20-year high of

53 percent.

Net gas imports increased slightly in 1997 to 2.8 trillion

cubic feet, which is approximately 13 percent of

consumption. Almost all of this gas was pipelined from

Canada, some came from Mexico, though Mexico

remains a net importer of natural gas from the U.S., and

a very small amount of liquefied natural gas was

imported from Algeria and Australia.

Venezuela, Saudi Arabia, Canada, Mexico, and Nigeria

were the primary foreign suppliers of petroleum to the

United States. Price-competitive Canadian gas exports

continue to capture an increasing share of the U.S.

market.{29}

List Of Appendices

Appendix A: Reserves by Operator Production Size

Class - How much of the National total of proved

reserves are owned and operated by the large oil and

gas corporations? Appendix A separates the large

operators from the small and presents reserves data

according to operator production size classes.

Appendix B: Top 100 Oil and Gas Fields - What fields

have the most reserves and production in the United

States? The top 100 fields for oil and natural gas out of

the inventory of more than 45,000 oil and gas fields are

listed in Appendix B. These fields hold two-thirds of

U.S. crude oil proved reserves.

Appendix C: Conversion to the Metric System - To

simplify international comparisons, a summary of U.S.

Crude Oil, Natural Gas, and Natural Gas Liquids

Reserves expressed in metric units is included as

Appendix C.

Appendix D: Historical Reserves Statistics -

Appendix D contains selected historical reserves data

presented at the State and National level. Readers

interested in a historical look at one specific State or

region can review these tables. We have again included

Table D9, Deepwater Production and Proved Reserves

of the Gulf of Mexico Federal Offshore 1992-1997, due

to expressed interest from the industry regarding this

area. Table D9 contains the production and proved

reserves for 1992-1997 for the Gulf of Mexico Federal

Offshore region by water depths greater than 200

meters, and less than 200 meters.

Appendix E: Summary of Data Collection

Operations - This report is based on two EIA surveys.

Proved reserves data is collected annually from U.S. oil

and gas field operators on Form EIA-23. Natural gas

liquids production data is collected annually from U.S.

natural gas plant operators on Form EIA-64A.

Appendix E describes survey designs, response

statistics, reporting requirements, and sampling frame

maintainance.

Appendix F: Statistical Considerations - The EIA

strives to maintain or improve the accuracy of its

reports. Since complete coverage of all oil and gas

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 17
operators is impractical, the EIA has adopted sound

statistical methods to impute data for those operators

not sampled and for those data elements that smaller

operators are not required to file. These methods are

described in Appendix F.

Appendix G: Estimation of Reserves and Resources -

Reserves are not measured directly. Reserves are

estimated on the basis of the best geological,

engineering, and economic data available to the

estimator. Appendix G describes reserve estimation

techniques commonly used by oil and gas field

operators and EIA personnel when in the field

performing quality assurance checks. A discussion of

the relationship of reserves to overall U.S. oil and gas

resources is also included.

Appendix H: Maps of Selected State Subdivisions -

Certain large producing States have been subdivided

into smaller regions to allow more specific reporting of

reserves data. Maps of these States identifying the

smaller regions are provided in Appendix H.

Appendix I: Annual Survey Forms of Domestic Oil

and Gas Reserves - Samples of Form EIA-23 and Form

EIA-64A are presented in Appendix I.

Glossary - Contains definitions of many of the

technical terms used in this report.

Energy Information Administration

18 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
3. Crude Oil Statistics

The United States had 22,546 million barrels of crude

oil proved reserves as of December 31, 1997. This is 2

percent (529 million barrels) more than in 1996 and is

the first time in 10 years that crude oil proved reserves

have increased. Reserves additions of crude oil replaced

125 percent of 1997 oil production (Figure 15).

Continued exploration and development in the Gulf of

Mexico Federal Offshore (especially in deep water),

field extensions in Texas, new field discoveries in

Alaska, and large upward revisions in California’s

heavy oil fields all combined in 1997 to create the first

increase in crude oil proved reserves in a decade.

Lower-48 States crude oil proved reserves increased

almost 4 percent (642 million barrels) in 1997.

Over the past decade, U.S. crude oil proved reserves

had been declining (Figure 1) an average of 2 percent

per year. The 1997 increase interrupts this trend,

although it remains to be seen if the application of new

technology can sustain this level of reserves additions.

It is expected that the declining trend will reestablish

itself in the future.

Proved Reserves

Table 6 presents the U.S. proved reserves of crude oil

as of December 31, 1997, by selected States and State

subdivisions.

Figure 16 maps 1997 crude oil proved reserves by area.

The following four areas account for 78 percent of U.S.

crude oil proved reserves:

Percent of

Area U.S. Oil Reserves

Texas 25

Alaska 23

California 17

Gulf of Mexico Federal Offshore 13

Area Total 78

Of these four areas, California and the Gulf of Mexico

Federal Offshore increased their reserves in 1997, while

Alaska and Texas had small decreases in crude oil

proved reserves.

Discussion of Reserves Changes

Figure 17 maps the change in crude oil proved reserves

from 1996 to 1997 by area. Here’s how the top four

areas fared compared to the total United States:

Change in

U.S. Oil Reserves

Area (million barrels)

Texas -49

Alaska -113

California +313

Gulf of Mexico Federal Offshore +382

Area Total +533

U.S. Total +529

Figure 2 in Chapter 2 shows the components of the

changes in crude oil proved reserves for 1997 and the

preceding 10 years.

Total Discoveries

Total discoveries are those new reserves attributable to

extensions of existing fields, new field discoveries, and new

reservoir discoveries in old fields. They result from the

drilling of exploratory wells.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 19

37%

62%

66%

78%

85%

125%

95%

0%

20%

40%

60%

80%

100%

120%

140%

1991 1992 1993 1994 1995 1996 1997

Percentage of U.S. Oil Production Replaced

Figure 15. Reserve Additions Replace 125 Percent

of U.S. Oil Production in 1997

Source: Energy Information Administration, Office of Oil and Gas.
Energy Information Administration

20 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table 6. Crude Oil Proved Reserves, Reserves Changes, and Production, 1997

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 1997

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/96 (+,-) (+) (--) (+) (+) (+) (-) 12/31/97

aIncludes Arizona, Missouri, Nevada, New York, South Dakota, Tennessee, and Virginia. bIndicates the estimate is associated with a sampling error (95 percent confidence interval) that exceeds 20 percent of the estimated value.

Note: The production estimates in this table are based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas

Reserves.” They may differ from the official Energy Information Administration production data for crude oil for 1997 contained in the Petroleum

Supply Annual 1997, DOE/EIA-0340(97).

Source: Energy Information Administration, Office of Oil and Gas.

Alaska. . . . . . . . . . . . . . . . . . . . . . . 5,274 6 274 55 18 117 0 473 5,161

Lower 48 States . . . . . . . . . . . . . . 16,743 514 1,724 1,029 459 520 119 1,665 17,385

Alabama . . . . . . . . . . . . . . . . . . . . . 45 0 16 4 0 0 0 10 47

Arkansas . . . . . . . . . . . . . . . . . . . . 58 -8 5 4 0 0 0 6 45

California . . . . . . . . . . . . . . . . . . . . 3,437 277 324 49 38 0 8 285 3,750

Coastal Region Onshore . . . . . . 425 21 5 15 16 0 1 23 430

Los Angeles Basin Onshore . . . 234 45 24 15 0 0 0 20 268

San Joaquin Basin Onshore . . . 2,597 203 282 19 22 0 7 221 2,871

State Offshore . . . . . . . . . . . . . . 181 8 13 0 0 0 0 21 181

Colorado. . . . . . . . . . . . . . . . . . . . . 231 13 9 37 3 0 0 21 198

Florida . . . . . . . . . . . . . . . . . . . . . . 97 -1 5 4 0 0 0 6 91

Illinois . . . . . . . . . . . . . . . . . . . . . . . 94 -9 24 6 0 0 0 11 92

Indiana . . . . . . . . . . . . . . . . . . . . . . 11 3 1 3 0 0 0 2 b10

Kansas . . . . . . . . . . . . . . . . . . . . . . 266 19 51 66 6 0 0 38 238

Kentucky. . . . . . . . . . . . . . . . . . . . . 21 0 2 1 0 0 0 2 b20

Louisiana . . . . . . . . . . . . . . . . . . . . 658 59 118 86 50 5 10 100 714

North . . . . . . . . . . . . . . . . . . . . . 128 -7 35 23 21 0 0 18 136

South Onshore. . . . . . . . . . . . . . 382 70 51 49 22 5 6 60 427

State Offshore . . . . . . . . . . . . . . 148 -4 32 14 7 0 4 22 151

Michigan. . . . . . . . . . . . . . . . . . . . . 74 5 6 15 7 0 1 10 68

Mississippi . . . . . . . . . . . . . . . . . . . 164 3 24 10 13 0 7 18 183

Montana . . . . . . . . . . . . . . . . . . . . . 168 -2 8 8 6 1 1 15 159

Nebraska . . . . . . . . . . . . . . . . . . . . 28 -3 2 3 0 0 0 3 b21

New Mexico . . . . . . . . . . . . . . . . . . 744 14 64 44 18 1 1 63 735

East . . . . . . . . . . . . . . . . . . . . . . 731 8 62 41 18 1 1 61 719

West. . . . . . . . . . . . . . . . . . . . . . 13 6 2 3 0 0 0 2 16

North Dakota . . . . . . . . . . . . . . . . . 248 -3 71 15 12 0 0 34 279

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 53 -3 4 6 1 0 0 6 b43

Oklahoma. . . . . . . . . . . . . . . . . . . . 632 -20 100 46 15 0 0 76 605

Pennsylvania . . . . . . . . . . . . . . . . . 10 0 0 1 9 0 0 1 17

Texas . . . . . . . . . . . . . . . . . . . . . . . 5,736 109 450 325 177 6 8 474 5,687

RRC District 1 . . . . . . . . . . . . . . 86 5 4 5 3 0 0 10 83

RRC District 2 Onshore . . . . . . . 63 12 4 4 0 0 0 9 66

RRC District 3 Onshore . . . . . . . 281 -27 36 24 39 0 0 46 259

RRC District 4 Onshore . . . . . . . 51 24 9 14 3 6 0 9 70

RRC District 5 . . . . . . . . . . . . . . 29 13 22 12 8 0 3 9 54

RRC District 6 . . . . . . . . . . . . . . 359 24 16 15 3 0 0 39 348

RRC District 7B . . . . . . . . . . . . . 136 6 26 6 11 0 0 18 155

RRC District 7C . . . . . . . . . . . . . 219 1 23 21 25 0 1 21 227

RRC District 8 . . . . . . . . . . . . . . 2,079 21 184 93 63 0 3 157 2,100

RRC District 8A . . . . . . . . . . . . . 2,207 12 95 103 14 0 0 127 2,098

RRC District 9 . . . . . . . . . . . . . . 144 12 16 15 5 0 1 19 144

RRC District 10 . . . . . . . . . . . . . 74 10 13 12 3 0 0 9 79

State Offshore . . . . . . . . . . . . . . 8 -4 2 1 0 0 0 1 4

Utah . . . . . . . . . . . . . . . . . . . . . . . . 237 -8 34 14 1 0 0 16 234

West Virginia . . . . . . . . . . . . . . . . . 25 4 1 3 1 0 0 2 26

Wyoming . . . . . . . . . . . . . . . . . . . . 603 54 54 28 11 0 0 67 627

Federal Offshore . . . . . . . . . . . . . . 3,085 4 351 246 90 507 83 397 3,477

Pacific (California) . . . . . . . . . . . 518 -24 128 42 2 1 0 55 528

Gulf of Mexico (Louisiana) . . . . . 2,357 26 197 176 82 318 81 298 2,587

Gulf of Mexico (Texas). . . . . . . . 210 2 26 28 6 188 2 44 362

Miscellaneousa. . . . . . . . . . . . . . . . 18 7 0 5 1 0 0 2 19

U.S. Total. . . . . . . . . . . . . . . . . . . . 22,017 520 1,998 1,084 477 637 119 2,138 22,546
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 21

Figure 17. Changes in Crude Oil Proved Reserves by Area, 1996 to 1997

Source: Energy Information Administration, Office of Oil and Gas.

Figure 16. 1997 Crude Oil Proved Reserves by Area
Total discoveries of crude oil were 1,233 million barrels

in 1997, the highest in a decade, and 33 percent higher

than in 1996. Only five areas had total discoveries

exceeding 35 million barrels:

n The Gulf of Mexico Federal Offshore had 677

million barrels of total discoveries, 55 percent of

the National total.

n Texas had 191 million barrels of total discoveries,

15 percent of the National total.

n Alaska had 135 million barrels of total discoveries,

11 percent of the National total.

n Louisiana had 65 million barrels of total

discoveries, 5 percent of the National total.

n California had 46 million barrels of total

discoveries, 4 percent of the National total.

The United States discovered an average of 693 million

barrels of new crude oil proved reserves per year in the

prior 10 years (1987 through 1996). Total discoveries in

1997 were 178 percent of that average.

Extensions

Operators reported 477 million barrels of extensions in

1997. The highest volume of extensions was reported in

Texas (177 million barrels). The Gulf of Mexico Federal

Offshore had 88 million barrels of extensions. Louisiana

was third with 50 million barrels, followed by

California with 38 million barrels.

In the prior 10 years, U.S. operators reported an

average of 436 million barrels of extensions per year.

The 1997 extensions were 109 percent of that average.

New Field Discoveries

There were 637 million barrels of new field discoveries

reported in 1997. Only eight areas in the United States

reported any new field discoveries, and only two

contributed more than 1 percent to the total:

n Gulf of Mexico Federal Offshore (79 percent; 506

million barrels))

n Alaska (18 percent; 117 million barrels).

In the prior 10 years, U.S. operators reported an

average of 122 million barrels of reserves from new field

discoveries per year. Reserves from new field discoveries

in 1997 were more than 5 times that average volume.

New Reservoir Discoveries in Old Fields

Operators in the United States reported 119 million

barrels of crude oil reserves from new reservoir

discoveries in old fields in 1997. As with new field

discoveries, the most significant portion of the new

reservoir discoveries in old fields came from the Gulf of

Mexico Federal Offshore—83 million barrels or 70

percent of the total. Louisiana had 10 million barrels (8

percent), and California and Texas each had 8 million

barrels (7 percent each). In the prior 10 years, U.S.

operators reported an average of 135 million barrels of

reserves from new reservoir discoveries in old fields per

year. Reserves from new reservoir discoveries in old fields

in 1997 were 88 percent of that average.

Revisions and Adjustments

Thousands of positive and negative revisions to proved

reserves occur each year as infill wells are drilled, well

performance is analyzed, new technology is applied, or

economic conditions change. Adjustments are the

annual changes in the published reserve estimates that

cannot be directly attributed to the estimates for other

reserve change categories because of the survey and

statistical estimation methods employed.

There were 1,434 million barrels of net revisions and

adjustments for crude oil in 1997, 57 percent more than

in 1996. California alone had 552 million barrels (38

percent) of net revisions and adjustments in 1997—466

million barrels of these were in the San Joaquin Basin

Area. Average revisions and adjustments for the prior 10

years were 1,293 million barrels, and those for 1997

were 11 percent higher than this average.

Production

U.S. production of crude oil in 1997 was 2,138 million

barrels. This was 2 percent lower than 1996’s total of

2,173 million barrels. U.S. crude oil production has

declined in 11 of the last 12 years. Texas and Alaska are

still the largest producers of crude oil in the United

States with 22 percent of the total each, the Gulf of

Mexico Federal Offshore is third with 16 percent, and

California has 13 percent.

Areas of Note: Large Discoveries

and Reserves Additions

The following State and area discussions summarize

notable activities during 1997 concerning expected new

field reserves, development plans, and possible

Energy Information Administration

22 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
production rates as reported in various trade

publications. The citations do not necessarily reflect

EIA’s concurrence, but are considered important

enough to be brought to the reader’s attention.

The following areas are the major success stories for

crude oil reserves and production for 1997.

Gulf of Mexico Federal Offshore

Projects in the Gulf of Mexico Federal Offshore were

the biggest success stories for oil exploration during

1997. Most of the United States’ crude oil reserve

additions from new field discoveries and from new

reservoir discoveries in old fields came from this area. The

net increase of crude oil proved reserves in the Gulf of

Mexico Federal Offshore was 382 million barrels. The

Gulf of Mexico produced about 342 million barrels of

crude oil in 1997, an increase of 13 percent (39 million

barrels) over 1996’s production.

Deepwater Production and Reserves: In 1997, just as in

1996, major U.S. operators continue to evaluate and

develop large prospects in the deepwater areas of the

Gulf of Mexico. An example of the newest deepwater

technology is shown on the cover of this year’s

report—an artist’s rendering of the installation of the

SeaStar platform planned for British-Borneo Petroleum

Inc.’s Morpeth Project. Notable fields in the Gulf of

Mexico Federal Offshore in 1997 include:

n Hoover-Diana: In the Gulf of Mexico Federal

Offshore (Texas), in East Breaks Block 945,

Exxon is developing the Hoover-Diana fields

using a deep-draft caisson vessel (EIA also refers

to caisson vessels as “spars”), which began

construction in Finland in 1997. In the year 2000,

Exxon plans to launch the 62,000 ton Hoover

caisson vessel and anchor it in 1,570 meters of

water. Exxon estimates that Hoover-Diana holds

400 million barrels of oil equivalent.{30}

n Europa: In the Gulf of Mexico Federal Offshore

(Louisiana), in Mississippi Canyon Block 935,

Shell is developing a new oil field in 3,900 feet

of water—the Europa Field. Shell and its

partners announced in March 1998 their plans to

develop Europa utilizing a subsea system

capable of accommodating eight wells, tied back

20 miles to the Mars Tension-Leg Platform in

Mississippi Canyon Block 807. Total

development costs are approximately $500

million, excluding lease costs. Production is

scheduled to begin in early 2000 and peak

production rates are anticipated to be 60,000

barrels of oil per day and 45 million cubic feet of

gas per day by early 2001. Total gross ultimate

recovery is estimated at about 160 million

barrels of oil equivalent.{31}

n Macaroni: In the Gulf of Mexico Federal

Offshore (Texas), in Garden Banks Block 602,

Shell is developing a new field in 3,700 feet of

water—the Macaroni Field. Shell announced in

March 1998 that it would develop Macaroni

using a subsea system of three satellite wells

clustered around a four-well subsea manifold,

tied back 12 miles to the Auger Tension-Leg

Platform in Garden Banks Block 426. Total

development cost is approximately $270 million,

excluding lease and exploration costs.

Production is scheduled to begin in mid-year

1999 and peak production rates are anticipated

to be 35,000 barrels of oil per day and 65 million

cubic feet of gas per day by late 1999. Total

gross ultimate recovery is estimated at about 78

million barrels of oil equivalent.{32}

n Marlin: In the Gulf of Mexico Federal Offshore

(Louisiana), in Viosca Knoll Block 915, Amoco is

developing the Marlin field in 3,240 feet of

water. Amoco and Shell Deepwater

Development Inc. announced in January 1997

plans to develop Marlin using a tension leg

platform (TLP). Total development cost is

approximately $500 million. Production is

scheduled to begin in mid-year 1999 and peak

production rates are anticipated to be 250

million cubic feet of gas and 40,000 barrels of oil

daily. Amoco is the operator and has a

75-percent working interest in the field which is

located some 100 miles south of Mobile,

Alabama. Construction of the TLP’s hull began

in 1997 in Taranto, Italy. It will be towed to

Corpus Christi, where the topside facilities are

being built. The hull will be fastened to the

seafloor with steel tendons.{33}

California

California’s proved oil reserves increased by 313

million barrels in 1997. The largest increase was from

revisions and adjustments in the San Joaquin Basin

Onshore, home of California’s “heavy oil” fields. This

area’s reserves increased by 274 million barrels.

California’s production also increased by about 3

percent from 1996’s level.

A key player in California’s heavy oil industry is

Texaco, Inc., which contributed to the surge of proved

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 23
reserves in California by acquiring Monterey

Resources, a California independent oil and gas

producer, in November 1997. Texaco expects that

application of the continuous-injection steam flood

process it used at its Kern River Field, in comparison to

Monterey’s less efficient cyclic steam flood process,

will raise production while simultaneously lowering

per-barrel production costs. Over the next 3 years,

Texaco’s strategic goal is to more than double

production from former Monterey Resources fields to

119,000 barrels of oil equivalent per day.{34}

Texas

Onshore in the lower 48 States, Texas had the most total

discoveries of crude oil proved reserves in 1997 (191

million barrels). Enhancements in drilling technology,

coupled with improved economics (due to reductions

in development well costs and higher oil prices),

caused increased operator activity.

Alaska

Alaska reported 135 million barrels of total discoveries of

crude oil proved reserves in 1997, third in the Nation

following the Gulf of Mexico Federal Offshore and

Texas. Most of Alaska’s total discoveries were from new

fields on the North Slope. These fields are “satellite

fields”, meaning that they are located next to large,

existing Alaskan North Slope fields and can be

developed economically by extending facilities from

the existing production sites to reach them.

In late December 1997, ARCO began commercial

production from West Sak, a heavy oil accumulation.

Commercial development of West Sak has become

feasible because of lower costs, new drilling

technologies, and a production facility sharing

agreement with the Kuparuk production facility. The

first phase of West Sak development has resulted in

proved gross reserves of 50 million barrels of oil (25 net

to ARCO). ARCO also had success drilling in a number

of satellite accumulations, including the Tarn field.{35}

Louisiana

Louisiana’s proved oil reserves increased by 56 million

barrels. The largest increase was from revisions and

adjustments in the South Onshore region. Louisiana’s

production also increased by about 4 percent from

1996’s level.

Other Gain Areas

North Dakota: North Dakota’s proved oil reserves

increased by 31 million barrels. There were 53 million

barrels of net revisions and adjustments in North Dakota

in 1997, plus 12 million barrels of extensions.

Wyoming: Wyoming’s proved oil reserves increased

by 24 million barrels. Although there were no new

fields reported, several operators increased their

reserves with extensions and revisions and adjustments.

Mississippi: Mississippi’s proved oil reserves

increased by 19 million barrels. The boost came from a

combination ofextensions, revisions and adjustments, and

new reservoirs discovered in old fields.

Areas of Note:

Large Reserves Declines

The following areas had large declines in crude oil

proved reserves due to downward revisions or

unreplaced production.

Alaska

Alaska’s proved oil reserves declined by 113 million

barrels in 1997—the greatest decline in any state. This is

because Alaska’s massive production rate far exceeds

its reserves replacement rate. Alaska’s 1997 production

was approximately 473 million barrels, 7 percent less

than what Alaska produced in 1996.

No Production Decline in 1999: In 1997, ARCO started

several projects and had several successes that it

believes will stop the decline in its Alaskan production

after 1999. The Prudhoe Bay Miscible Injection

Expansion (“MIX”) Project was approved by ARCO

and its partners. This $160 million expansion of the gas

handling facilities is expected to add 50 million gross

barrels of petroleum liquids and 20 thousand net

barrels of petroleum liquids per day to the field when it

becomes operational, targeted for 1999.{35}

Texas

Texas’ proved oil reserves declined by 49 million

barrels in 1997. Texas’ production also declined about 4

percent from 1996 levels. The largest reserves decline

(109 million barrels) was in RRC District 8A. In this

district, the net revisions and extensions were exceeded

by production. Other areas where oil reserves

significantly decreased were RRC District 3 Onshore

Energy Information Administration

24 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
(22 million barrels) and RRC District 6 (11 million

barrels).

These declines were counterbalanced somewhat by

reserves increases in other RRC Districts. In RRC

Districts 5 and 8, net positive reserves additions of 25

and 21 million barrels of proved reserves, respectively,

were added.

Other Decline Areas

In the following areas of the United States,

development of existing or new oil fields was outpaced

by crude oil production, which remained at roughly

the same level as the previous year.

Colorado: Proved oil reserves decreased by

14 percent (33 million barrels).

Kansas: Proved oil reserves decreased by

11 percent (28 million barrels).

Oklahoma: Proved oil reserves decreased

by 4 percent (27 million barrels).

Reserves in

Nonproducing Reservoirs

Not all proved reserves of crude oil were contained in

reservoirs that were producing. Operators reported

3,755 million barrels of proved reserves in

nonproducing reservoirs, 8 percent more than reported

in 1996 (3,474 million barrels).

The reasons for the nonproducing status of these

proved reserves are not collected by the EIA. However,

previous surveys showed that most were not being

produced for operational reasons. These included

waiting for well workovers, drilling additional

development or replacement wells, installing

production or pipeline facilities, and awaiting

depletion of other zones or reservoirs before

recompletion in reservoirs not currently open to

production.

Indicated Additional Reserves

In addition to proved reserves of crude oil, Category I

and Category II operators estimate the quantities of

crude oil, other than proved reserves, that may become

economically recoverable from known reservoirs

through the application of improved recovery

techniques using currently available technology. The

1997 volume, 3,207 million barrels, is about 12 percent

more than was reported in 1996 (2,876 million barrels).

Table 7 lists the indicated additional reserves by

selected States and State subdivisions. The presence of

large indicated additional reserves in Alaska,

California, south Louisiana and west Texas implies that

significant upward revisions to proved crude oil

reserves could occur in the future.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 25
Energy Information Administration

26 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table 7. Reported Indicated Additional Crude Oil Reserves,a 1997

(Million Barrels of 42 U.S. Gallons)

Indicated Indicated

Additional Additional

State and Subdivision Reserves State and Subdivision Reserves

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 832

Lower 48 States. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,375

Alabama . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,264

Coastal Region Onshore . . . . . . . . . . . . . . . . . . . 43

Los Angeles Basin Onshore . . . . . . . . . . . . . . . . . 0

San Joaquin Basin Onshore. . . . . . . . . . . . . . . . . 1,221

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Florida . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Illinois. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Indiana. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Kansas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Kentucky . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 313

North. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . <1

South Onshore . . . . . . . . . . . . . . . . . . . . . . . . . . . 309

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Montana. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Nebraska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146

East. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146

West . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Pennsylvania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 479

RRC District 1. . . . . . . . . . . . . . . . . . . . . . . . . . . . <1

RRC District 2 Onshore . . . . . . . . . . . . . . . . . . . . 0

RRC District 3 Onshore . . . . . . . . . . . . . . . . . . . . 28

RRC District 4 Onshore . . . . . . . . . . . . . . . . . . . . <1

RRC District 5. . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

RRC District 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

RRC District 7B. . . . . . . . . . . . . . . . . . . . . . . . . . . 3

RRC District 7C . . . . . . . . . . . . . . . . . . . . . . . . . . 4

RRC District 8. . . . . . . . . . . . . . . . . . . . . . . . . . . . 308

RRC District 8A. . . . . . . . . . . . . . . . . . . . . . . . . . . 131

RRC District 9. . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

RRC District 10. . . . . . . . . . . . . . . . . . . . . . . . . . . 4

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

West Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Federal Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Pacific (California). . . . . . . . . . . . . . . . . . . . . . . . . 0

Gulf of Mexico (Louisiana) . . . . . . . . . . . . . . . . . . 36

Gulf of Mexico (Texas) . . . . . . . . . . . . . . . . . . . . . 5

Miscellaneousb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

U.S. Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,207

aIncludes only those operators who produced 400,000 barrels of crude oil or 2 billion cubic feet of natural gas, or both, during the report year (Category I or Category II operators). bIncludes Arizona, Missouri, Nevada, New York, South Dakota, Tennessee, and Virginia.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1997.
4. Natural Gas Statistics

Dry Natural Gas

Proved Reserves

The Nation’s 1997 proved reserves of dry natural gas

were 167,223 billion cubic feet, 0.4 percent (749 billion

cubic feet) more than in 1996 (Table 8). This is the

fourth consecutive year that natural gas reserves have

increased. Gas production increased for the second

consecutive year.

Additions to reserves replaced 104 percent of gas

production in 1997 (Figure 18). New gas discoveries in

the Gulf of Mexico Federal Offshore, Texas, Wyoming,

and Louisiana, combined with upward revisions of gas

reserves in Alaska and Oklahoma, were responsible for

this. Lower 48 States gas reserves declined slightly in

1997 after increasing in 1995 and 1996. The decrease in

the Lower 48 in 1997 was more than made up for by the

Alaskan gas reserves additions.

Proved reserves by State are shown on the map in

Figure 19. Six areas account for 71 percent of the

Nation’s dry natural gas proved reserves:

Percent of

Area U.S. Gas Reserves

Texas 23

Gulf of Mexico Federal Offshore 17

New Mexico 9

Wyoming 8

Oklahoma 8

Alaska 6

Area Total 71

Of these six areas, the Gulf of Mexico Federal Offshore,

Alaska, Wyoming, and Oklahoma had increased

reserves in 1997, while Texas and New Mexico had

decreases in dry natural gas proved reserves.

Discussion of Reserves Changes

Figure 20 maps the change in dry gas proved reserves

from 1996 to 1997 by area. Here’s how the top six areas

fared, compared to the total United States:

Change in

U.S. Gas Reserves

Area (billion cubic feet)

Texas -509

Gulf of Mexico Federal Offshore +70

New Mexico -971

Wyoming +1,242

Oklahoma +365

Alaska +1,268

Area Total +1,465

U.S. Total +749

Figure 4 in Chapter 2 shows the components of the

changes in dry natural gas proved reserves for 1997

and the preceding 10 years.

Revisions and Adjustments

Revisions and adjustments declined 45 percent in 1997,

compared to 1996’s level. The net volume of revisions

and adjustments was 4,312 billion cubic feet. Alaska had

the largest increase in revisions and adjustments (1,729

billion cubic feet). Alaska actually has substantially

greater total resources of natural gas than proved

reserves, but no economic market presently exists for

Alaskan gas.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 27

87% 88%

85%

108% 107% 107%

104%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

120%

1991 1992 1993 1994 1995 1996 1997

Percentage of U.S. Gas Production Replaced

Figure 18. Reserve Additions Exceed U.S. Natural

Gas Production 4 Years in a Row

Source: Energy Information Administration, Office of Oil and Gas.
Energy Information Administration

28 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table 8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 1997

(Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 1997

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/96 (+,-) (+) (-) (+) (+) (+) (-) 12/31/97

Alaska. . . . . . . . . . . . . . . . . . . . . . . 9,294 19 1,809 99 14 0 0 475 10,562

Lower 48 States . . . . . . . . . . . . . . 157,180 -609 19,849 16,657 10,571 2,681 2,382 18,736 156,661

Alabama . . . . . . . . . . . . . . . . . . . . . 5,033 -31 348 54 34 0 14 376 4,968

Arkansas . . . . . . . . . . . . . . . . . . . . 1,470 -21 205 101 96 0 15 189 1,475

California . . . . . . . . . . . . . . . . . . . . 2,082 19 358 52 68 0 10 212 2,273

Coastal Region Onshore . . . . . . 156 18 10 19 15 0 1 17 164

Los Angeles Basin Onshore . . . 109 21 27 6 0 0 0 10 141

San Joaquin Basin Onshore . . . 1,768 -31 318 27 53 0 9 178 1,912

State Offshore . . . . . . . . . . . . . . 49 11 3 0 0 0 0 7 56

Colorado. . . . . . . . . . . . . . . . . . . . . 7,710 -563 959 826 108 2 0 562 6,828

Florida . . . . . . . . . . . . . . . . . . . . . . 96 5 1 0 0 0 0 6 96

Kansas . . . . . . . . . . . . . . . . . . . . . . 7,694 69 307 510 54 0 4 629 6,989

Kentucky. . . . . . . . . . . . . . . . . . . . . 983 321 107 3 18 0 17 79 1,364

Louisiana . . . . . . . . . . . . . . . . . . . . 9,543 203 1,606 1,360 754 11 412 1,496 9,673

North . . . . . . . . . . . . . . . . . . . . . 3,105 6 607 378 175 0 2 424 3,093

South Onshore. . . . . . . . . . . . . . 5,704 157 887 859 548 11 318 911 5,855

State Offshore . . . . . . . . . . . . . . 734 40 112 123 31 0 92 161 725

Michigan. . . . . . . . . . . . . . . . . . . . . 2,061 177 252 124 50 0 0 221 2,195

Mississippi . . . . . . . . . . . . . . . . . . . 631 -16 66 56 48 0 2 93 582

Montana . . . . . . . . . . . . . . . . . . . . . 796 33 99 133 22 0 0 55 762

New Mexico . . . . . . . . . . . . . . . . . . 16,485 -664 2,459 1,868 641 2 6 1,547 15,514

East . . . . . . . . . . . . . . . . . . . . . . 2,790 12 392 334 192 2 6 418 2,642

West. . . . . . . . . . . . . . . . . . . . . . 13,695 -676 2,067 1,534 449 0 0 1,129 12,872

New York . . . . . . . . . . . . . . . . . . . . 232 -12 60 42 0 0 4 c18 c224

North Dakota . . . . . . . . . . . . . . . . . 462 -2 57 17 25 0 0 46 479

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 1,113 -71 101 75 5 0 17 105 985

Oklahoma. . . . . . . . . . . . . . . . . . . . 13,074 82 2,396 1,282 638 2 84 1,555 13,439

Pennsylvania . . . . . . . . . . . . . . . . . 1,696 60 519 381 82 0 5 129 1,852

Texas . . . . . . . . . . . . . . . . . . . . . . . 38,270 -495 4,660 4,447 3,949 373 393 4,942 37,761

RRC District 1 . . . . . . . . . . . . . . 906 -85 118 55 149 25 0 105 953

RRC District 2 Onshore . . . . . . . 1,322 102 248 209 305 50 30 214 1,634

RRC District 3 Onshore . . . . . . . 4,349 -310 784 505 488 193 59 886 4,172

RRC District 4 Onshore . . . . . . . 7,769 57 1,155 1,179 1,452 32 105 1,292 8,099

RRC District 5 . . . . . . . . . . . . . . 2,079 68 163 636 69 25 152 210 1,710

RRC District 6 . . . . . . . . . . . . . . 5,899 112 503 592 553 0 11 599 5,887

RRC District 7B . . . . . . . . . . . . . 520 -110 106 40 46 23 0 67 478

RRC District 7C . . . . . . . . . . . . . 3,655 -87 305 356 248 4 10 372 3,407

RRC District 8 . . . . . . . . . . . . . . 5,452 -210 754 373 316 8 22 572 5,397

RRC District 8A . . . . . . . . . . . . . 931 -22 35 54 12 0 0 55 847

RRC District 9 . . . . . . . . . . . . . . 705 110 47 74 111 0 1 106 794

RRC District 10 . . . . . . . . . . . . . 4,391 -142 384 340 183 2 3 387 4,094

State Offshore . . . . . . . . . . . . . . 292 22 58 34 17 11 0 77 289

Utah . . . . . . . . . . . . . . . . . . . . . . . . 1,633 -40 293 34 164 0 0 177 1,839

Virginia . . . . . . . . . . . . . . . . . . . . . . 1,930 344 142 15 113 0 0 68 2,446

West Virginia . . . . . . . . . . . . . . . . . 2,703 182 156 80 12 0 40 167 2,846

Wyoming . . . . . . . . . . . . . . . . . . . . 12,320 207 1,191 1,368 2,047 39 17 891 13,562

Federal Offshorea . . . . . . . . . . . . . 29,096 -380 3,486 3,803 1,643 2,252 1,342 5,170 28,466

Pacific (California) . . . . . . . . . . . 1,244 -69 6 602 1 1 0 37 544

Gulf of Mexico (Louisiana)a . . . . 21,856 -390 2,705 2,250 1,246 1,511 1,151 3,895 21,934

Gulf of Mexico (Texas). . . . . . . . 5,996 79 775 951 396 740 191 1,238 5,988

Miscellaneousb. . . . . . . . . . . . . . . . 67 -16 21 26 0 0 0 c3 c43

U.S. Total. . . . . . . . . . . . . . . . . . . . 166,474 -590 21,658 16,756 10,585 2,681 2,382 19,211 167,223

aIncludes Federal offshore Alabama. bIncludes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, Oregon, South Dakota, and Tennessee.

cIndicates the estimate is associated with a sampling error (95 percent confidence interval) that exceeds 20 percent of the estimated value.

Note: The production estimates in this table are based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas

Reserves,” and Form EIA-64A, “Annual Report of the Origin of Natural Gas Liquids Production.” They may differ from the official Energy

Information Administration production data for natural gas for 1997 contained in the Natural Gas Annual 1997, DOE/EIA-0131(97).

Source: Energy Information Administration, Office of Oil and Gas.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 29

1,268

544

2,273

1,839

762 479

15,514

6,828 6,989

1,475

9,673

13,439

96

4,968

582

10

985

1,364

2,195 224

1,852

2,446

2,846

13,562

27,922

37,761

Figure 20. Changes in Dry Natural Gas Proved Reserves by Area, 1996 to 1997

Source: Energy Information Administration, Office of Oil and Gas.

Figure 19. 1997 Dry Natural Gas Proved Reserves by Area
Discoveries

Total discoveries were up from 1996. Total discoveries are

those reserves attributable to field extensions, new field

discoveries, and new reservoir discoveries in old fields; they

result from drilling exploratory wells. Total discoveries

of dry natural gas reserves were 15,648 billion cubic

feet, an increase of 27 percent from the level reported in

1996 and equivalent to 81 percent of 1997 gas

production. About 64 percent of the total discoveries

were in the Gulf of Mexico Federal Offshore and Texas.

Extensions were 10,585 billion cubic feet, 36 percent

higher than in 1996. Areas with the largest extensions

were:

n Texas (37 percent)

n Wyoming (19 percent)

n Gulf of Mexico Federal Offshore (16 percent)

n Louisiana (7 percent)

n New Mexico (6 percent)

n Oklahoma (6 percent).

In the prior 10 years, U.S. operators reported an

average of 6,309 billion cubic feet of reserves from

extensions per year. Reserves from extensions in 1997

were 68 percent higher than that average volume.

New field discoveries were 2,681 billion cubic feet—85

percent higher than in 1996. Those areas with the

largest new field discoveries were the Gulf of Mexico

Federal Offshore (with 84 percent of the total) and

Texas (14 percent). In the prior 10 years, U.S. operators

reported an average of 1,359 billion cubic feet of

reserves from new field discoveries per year. Reserves

from new field discoveriesin 1997 were almost twice that.

New reservoir discoveries in old fields were 2,382 billion

cubic feet, 23 percent lower than 1996. Among the areas

with the largest new reservoir discoveries in old fields

were:

n Gulf of Mexico Federal Offshore (56 percent)

n Louisiana (17 percent)

n Texas (16 percent).

In the prior 10 years, U.S. operators reported an

average of 2,230 billion cubic feet of reserves from new

reservoirs discovered in old fields per year. Reserves from

new reservoirs discovered in old fields in 1997 were 7

percent higher than that average volume.

Production

Dry natural gas production increased 2 percent in 1997

(Table 8). U.S. gas production has increased during 8 of

the last 10 years. As in 1996, the Gulf of Mexico Federal

Offshore and the State of Texas were the leading

producers of dry natural gas in 1997, each with over

one-fourth of the U.S. total. The next three States

combined, Oklahoma (8 percent), Louisiana (8

percent), and New Mexico (8 percent), added another

one-fourth of the production.

Wet Natural Gas

U. S. proved reserves of wet natural gas, as of

December 31, 1997, were 175,721 billion cubic feet, an

increase of 0.3 percent, or 574 billion cubic feet, from

that reported in 1996 (Table 9). At year-end 1997

proved wet natural gas reserves for the lower 48 States

had decreased by 0.5 percent (803 billion cubic feet)

compared to 1996, while those of Alaska had increased

by 15 percent (1,377 billion cubic feet).

The volumetric differences between the estimates

reported in Table 8 (dry) and Table 9 (wet) results from

the removal of natural gas liquids at natural gas

processing plants. A discussion of the methodology

used in this report is in found in Appendix F. All

natural gas proved reserves data shown in this report

exclude natural gas held in underground storage.

Nonassociated Natural Gas

Proved Reserves

Proved reserves of nonassociated (NA) natural gas, wet

after lease separation, in the United States decreased by

0.7 percent (1,013 billion cubic feet) in 1997 to 143,339

billion cubic feet (Table 10). The lower 48 States’ NA

wet natural gas proved reserves decreased by 0.5

percent (754 billion cubic feet). Those areas with the

largest increases in NA wet natural gas reserves were

Wyoming, Texas RRC District 1, and Kentucky. There

were large decreases in NA wet natural gas reserves in

New Mexico, the Gulf of Mexico Federal Offshore, and

Kansas.

Discoveries

NA wet natural gas total discoveries of 13,718 billion

cubic feet increased 21 percent (2,380 billion cubic feet)

in 1997. Texas, the Gulf of Mexico Federal Offshore,

Energy Information Administration

30 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 31

Table 9. Natural Gas Proved Reserves, Reserves Changes, and Production, Wet After Lease Separation,

1997 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 1997 Proved Reserves 12/31/97

Published New Reservoir

Proved Revision Revision New Field Discoveries Non- Associated

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production associated Dissolved

State and Subdivision 12/31/96 (+,–) (+) (–) (+) (+) (+) (–) Total Gas Gas Gas

aIncludes Federal offshore Alabama. bIncludes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, Oregon, South Dakota, and Tennessee.

cIndicates the estimate is associated with a sampling error (95 percent confidence interval) that exceeds 20 percent of the estimated value.

Note: The production estimates in this table are based on data reported on Form EIA-23. They may differ from the official Energy

Information Administration production data for natural gas for 1997 contained in the Natural Gas Annual 1997, DOE/EIA-0131(97).

Source: Energy Information Administration, Office of Oil and Gas.

Alaska ..................... 9,296 105 1,834 99 14 0 0 477 10,673 2,957 7,716

Lower 48 States............. 165,851 -835 20,878 17,556 11,165 2,747 2,455 19,657 165,048 140,382 24,666

Alabama.................... 5,100 -48 351 56 34 0 14 382 5,013 4,983 30

Arkansas ................... 1,472 -19 206 101 96 0 15 190 1,479 1,423 56

California ................... 2,193 17 377 56 72 0 10 223 2,390 570 1,820

Coastal Region Onshore . . . . 168 19 11 22 16 0 1 17 176 47 129

Los Angeles Basin Onshore . 112 22 29 6 0 0 0 11 146 3 143

San Joaquin Basin Onshore . 1,864 -35 334 28 56 0 9 188 2,012 518 1,494

State Offshore . . . . . . . . . . . . 49 11 3 0 0 0 0 7 56 2 54

Colorado ................... 8,064 -533 1,004 901 114 2 0 590 7,160 6,627 533

Florida . . . . . . . . . . . . . . . . . . . . . 119 -1 1 0 0 0 0 7 112 0 112

Kansas..................... 8,145 -5 322 535 57 0 4 660 7,328 7,277 51

Kentucky ................... 1,046 320 112 3 19 0 18 83 1,429 1,403 26

Louisiana ................... 10,077 29 1,665 1,410 785 11 430 1,551 10,036 9,020 1,016

North ................... 3,189 -17 620 385 179 0 2 432 3,156 2,869 287

South Onshore............ 6,105 37 930 900 575 11 334 955 6,137 5,538 599

State Offshore . . . . . . . . . . . . 783 9 115 125 31 0 94 164 743 613 130

Michigan ................... 2,125 174 259 127 52 0 0 227 2,256 1,975 281

Mississippi . . . . . . . . . . . . . . . . . . 634 -18 66 56 48 0 2 93 583 532 51

Montana. . . . . . . . . . . . . . . . . . . . 806 31 100 134 22 0 0 56 769 727 42

New Mexico ................. 17,925 -878 2,639 2,043 704 2 6 1,655 16,700 15,280 1,420

East .................... 3,197 -4 445 381 219 2 6 476 3,008 1,694 1,314

West.................... 14,728 -874 2,194 1,662 485 0 0 1,179 13,692 13,586 106

New York . . . . . . . . . . . . . . . . . . . 232 -12 60 42 0 0 4 c18 c224 223 1

North Dakota . . . . . . . . . . . . . . . . 512 -2 63 19 28 0 0 51 531 274 257

Ohio ....................... 1,114 -71 101 76 5 0 17 105 985 594 391

Oklahoma .................. 13,952 56 2,553 1,365 680 2 89 1,656 14,311 13,296 1,015

Pennsylvania ................ 1,702 63 5 22 383 82 0 5 130 1,861 1,769 92

Texas ...................... 41,592 -451 5,032 4,771 4,229 398 411 5,332 41,108 33,322 7,786

RRC District 1 . . . . . . . . . . . . 969 -93 126 59 160 27 0 112 1,018 950 68

RRC District 2 Onshore ..... 1,430 80 263 221 323 53 31 227 1,732 1,497 235

RRC District 3 Onshore ..... 4,652 -375 830 535 516 205 63 938 4,418 3,539 879

RRC District 4 Onshore ..... 8,123 75 1,210 1,235 1,520 33 110 1,353 8,483 8,115 368

RRC District 5 ............ 2,141 55 166 651 71 26 156 215 1,749 1,681 68

RRC District 6 ............ 6,252 73 529 622 582 0 11 631 6,194 5,616 578

RRC District 7B . . . . . . . . . . . 610 -130 124 46 54 26 0 79 559 299 260

RRC District 7C ........... 4,063 -39 344 401 279 5 11 419 3,843 3,247 596

RRC District 8 ............ 6,050 -194 842 416 354 9 24 639 6,030 2,886 3,144

RRC District 8A ........... 1,294 45 51 80 18 0 0 81 1,247 41 1,206

RRC District 9 . . . . . . . . . . . . 870 87 56 87 129 0 1 124 932 785 147

RRC District 10 ........... 4,845 -58 433 383 206 3 4 437 4,613 4,386 227

State Offshore . . . . . . . . . . . . 293 23 58 35 17 11 0 77 290 280 10

Utah ....................... 1,747 7 305 37 178 0 0 195 2,005 1,695 310

Virginia..................... 1,930 344 142 15 113 0 0 68 2,446 1,923 523

West Virginia ................ 2,793 192 162 82 13 0 41 173 2,946 2,887 59

Wyoming ................... 13,084 150 1,257 1,446 2,160 39 18 941 14,321 13,471 850

Federal Offshorea ............ 29,419 -162 3,556 3,872 1,674 2,293 1,371 5,268 29,011 21,098 7,913

Pacific (California) ......... 1,266 -66 6 614 1 1 0 38 556 58 498

Gulf of Mexico (Louisiana)a . . 22,119 -177 2,770 2,301 1,275 1,547 1,179 3,984 22,428 16,241 6,187

Gulf of Mexico (Texas)...... 6,034 81 780 957 398 745 192 1,246 6,027 4,799 1,228

Miscellaneousb . . . . . . . . . . . . . . 68 -18 23 26 0 0 0 3 44 13 31

U.S. Total .................. 175,147 -730 22,712 17,655 11,179 2,747 2,455 20,134 175,721 143,339 32,382
Energy Information Administration

32 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table 10. Nonassociated Natural Gas Proved Reserves, Reserves Changes, and Production, Wet After

Lease Separation, 1997

(Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 1997

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/96 (+,-) (+) (-) (+) (+) (+) (-) 12/31/97

Alaska. . . . . . . . . . . . . . . . . . . . . . . 3,216 -1 42 93 0 0 0 207 2,957

Lower 48 States . . . . . . . . . . . . . . 141,136 -991 17,745 14,321 10,063 1,387 2,268 16,905 140,382

Alabama . . . . . . . . . . . . . . . . . . . . . 5,062 -47 346 54 34 0 14 372 4,983

Arkansas . . . . . . . . . . . . . . . . . . . . 1,383 0 196 94 96 0 15 173 1,423

California . . . . . . . . . . . . . . . . . . . . 610 -8 41 28 11 0 9 65 570

Coastal Region Onshore . . . . . . 48 9 2 6 0 0 0 6 47

Los Angeles Basin Onshore . . . 0 3 1 0 0 0 0 1 3

San Joaquin Basin Onshore . . . 560 -21 38 22 11 0 9 57 518

State Offshore . . . . . . . . . . . . . . 2 1 0 0 0 0 0 1 2

Colorado. . . . . . . . . . . . . . . . . . . . . 7,009 -474 987 463 99 2 0 533 6,627

Florida . . . . . . . . . . . . . . . . . . . . . . 0 0 0 0 0 0 0 0 0

Kansas . . . . . . . . . . . . . . . . . . . . . . 8,063 -9 308 497 55 0 4 647 7,277

Kentucky. . . . . . . . . . . . . . . . . . . . . 1,022 319 109 2 18 0 18 81 1,403

Louisiana . . . . . . . . . . . . . . . . . . . . 9,038 -44 1,515 1,204 681 5 415 1,386 9,020

North . . . . . . . . . . . . . . . . . . . . . 2,934 -94 597 318 136 0 2 388 2,869

South Onshore. . . . . . . . . . . . . . 5,478 22 837 783 520 5 321 862 5,538

State Offshore . . . . . . . . . . . . . . 626 28 81 103 25 0 92 136 613

Michigan. . . . . . . . . . . . . . . . . . . . . 1,778 199 225 74 39 0 0 192 1,975

Mississippi . . . . . . . . . . . . . . . . . . . 587 -18 58 48 36 0 2 85 532

Montana . . . . . . . . . . . . . . . . . . . . . 755 36 96 130 21 0 0 51 727

New Mexico . . . . . . . . . . . . . . . . . . 16,232 -875 2,455 1,773 660 0 4 1,423 15,280

East . . . . . . . . . . . . . . . . . . . . . . 1,612 9 275 128 175 0 4 253 1,694

West. . . . . . . . . . . . . . . . . . . . . . 14,620 -884 2,180 1,645 485 0 0 1,170 13,586

New York . . . . . . . . . . . . . . . . . . . . 229 -11 60 41 0 0 4 18 223

North Dakota . . . . . . . . . . . . . . . . . 257 -7 23 4 25 0 0 20 274

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 715 -63 36 64 5 0 13 48 594

Oklahoma. . . . . . . . . . . . . . . . . . . . 12,929 148 2,348 1,268 589 2 80 1,532 13,296

Pennsylvania . . . . . . . . . . . . . . . . . 1,655 53 512 382 49 0 5 123 1,769

Texas . . . . . . . . . . . . . . . . . . . . . . . 33,432 -81 4,036 4,041 3,719 395 387 4,525 33,322

RRC District 1 . . . . . . . . . . . . . . 523 285 119 49 149 27 0 104 950

RRC District 2 Onshore . . . . . . . 1,178 51 252 184 317 53 31 201 1,497

RRC District 3 Onshore . . . . . . . 3,612 -226 643 430 467 205 63 795 3,539

RRC District 4 Onshore . . . . . . . 7,877 -47 1,193 1,207 1,448 32 110 1,291 8,115

RRC District 5 . . . . . . . . . . . . . . 2,088 50 134 637 69 26 155 204 1,681

RRC District 6 . . . . . . . . . . . . . . 5,690 -10 514 580 580 0 11 589 5,616

RRC District 7B . . . . . . . . . . . . . 378 -83 55 32 1 26 0 46 299

RRC District 7C . . . . . . . . . . . . . 3,371 -34 263 294 271 5 3 338 3,247

RRC District 8 . . . . . . . . . . . . . . 3,069 -119 355 155 82 7 10 363 2,886

RRC District 8A . . . . . . . . . . . . . 18 35 10 15 0 0 0 7 41

RRC District 9 . . . . . . . . . . . . . . 749 50 46 79 119 0 0 100 785

RRC District 10 . . . . . . . . . . . . . 4,592 -55 398 344 199 3 4 411 4,386

State Offshore . . . . . . . . . . . . . . 287 22 54 35 17 11 0 76 280

Utah . . . . . . . . . . . . . . . . . . . . . . . . 1,446 17 248 22 175 0 0 169 1,695

Virginia . . . . . . . . . . . . . . . . . . . . . . 1,930 -134 75 15 113 0 0 46 1,923

West Virginia . . . . . . . . . . . . . . . . . 2,722 193 159 73 13 0 41 168 2,887

Wyoming . . . . . . . . . . . . . . . . . . . . 12,260 96 1,171 1,404 2,145 39 18 854 13,471

Federal Offshorea . . . . . . . . . . . . . 21,982 -252 2,738 2,640 1,480 944 1,239 4,393 21,098

Pacific (California) . . . . . . . . . . . 115 -53 0 2 0 0 0 2 58

Gulf of Mexico (Louisiana)a . . . . 16,627 -365 2,075 1,751 1,089 797 1,056 3,287 16,241

Gulf of Mexico (Texas). . . . . . . . 5,240 166 663 887 391 147 183 1,104 4,799

Miscellaneousb. . . . . . . . . . . . . . . . 40 -29 3 0 0 0 0 1 13

U.S. Total. . . . . . . . . . . . . . . . . . . . 144,352 -992 17,787 14,414 10,063 1,387 2,268 17,112 143,339

aIncludes Federal offshore Alabama. bIncludes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, Oregon, South Dakota, and Tennessee.

Note: The production estimates in this table are based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas

Reserves.” They may differ from the official Energy Information Administration production data for natural gas for 1997 contained in the

Natural Gas Annual 1997, DOE/EIA-0131(97).

Source: Energy Information Administration, Office of Oil and Gas.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 33

Table 11. Associated-Dissolved Natural Gas Proved Reserves, Reserves Changes, and Production,

Wet After Lease Separation, 1997

(Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 1997

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/96 (+,-) (+) (-) (+) (+) (+) (-) 12/31/97

Alaska. . . . . . . . . . . . . . . . . . . . . . . 6,080 106 1,792 6 14 0 0 270 7,716

Lower 48 States . . . . . . . . . . . . . . 24,715 156 3,133 3,235 1,102 1,360 187 2,752 24,666

Alabama . . . . . . . . . . . . . . . . . . . . . 38 -1 5 2 0 0 0 10 30

Arkansas . . . . . . . . . . . . . . . . . . . . 89 -19 10 7 0 0 0 17 56

California . . . . . . . . . . . . . . . . . . . . 1,583 25 336 28 61 0 1 158 1,820

Coastal Region Onshore . . . . . . 120 10 9 16 16 0 1 11 129

Los Angeles Basin Onshore . . . 112 19 28 6 0 0 0 10 143

San Joaquin Basin Onshore . . . 1,304 -14 296 6 45 0 0 131 1,494

State Offshore . . . . . . . . . . . . . . 47 10 3 0 0 0 0 6 54

Colorado. . . . . . . . . . . . . . . . . . . . . 1,055 -59 17 438 15 0 0 57 533

Florida . . . . . . . . . . . . . . . . . . . . . . 119 -1 1 0 0 0 0 7 112

Kansas . . . . . . . . . . . . . . . . . . . . . . 82 4 14 38 2 0 0 13 51

Kentucky. . . . . . . . . . . . . . . . . . . . . 24 1 3 1 1 0 0 2 26

Louisiana . . . . . . . . . . . . . . . . . . . . 1,039 73 150 206 104 6 15 165 1,016

North . . . . . . . . . . . . . . . . . . . . . 255 77 23 67 43 0 0 44 287

South Onshore. . . . . . . . . . . . . . 627 15 93 117 55 6 13 93 599

State Offshore . . . . . . . . . . . . . . 157 -19 34 22 6 0 2 28 130

Michigan. . . . . . . . . . . . . . . . . . . . . 347 -25 34 53 13 0 0 35 281

Mississippi . . . . . . . . . . . . . . . . . . . 47 0 8 8 12 0 0 8 51

Montana . . . . . . . . . . . . . . . . . . . . . 51 -5 4 4 1 0 0 5 42

New Mexico . . . . . . . . . . . . . . . . . . 1,693 -3 184 270 44 2 2 232 1,420

East . . . . . . . . . . . . . . . . . . . . . . 1,585 -13 170 253 44 2 2 223 1,314

West. . . . . . . . . . . . . . . . . . . . . . 108 10 14 17 0 0 0 9 106

New York . . . . . . . . . . . . . . . . . . . . 3 -1 0 1 0 0 0 0 1

North Dakota . . . . . . . . . . . . . . . . . 255 5 40 15 3 0 0 31 257

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 399 -8 65 12 0 0 4 57 391

Oklahoma. . . . . . . . . . . . . . . . . . . . 1,023 -92 205 97 91 0 9 124 1,015

Pennsylvania . . . . . . . . . . . . . . . . . 47 10 10 1 33 0 0 7 92

Texas . . . . . . . . . . . . . . . . . . . . . . . 8,160 -370 996 730 510 3 24 807 7,786

RRC District 1 . . . . . . . . . . . . . . 446 -378 7 10 11 0 0 8 68

RRC District 2 Onshore . . . . . . . 252 29 11 37 6 0 0 26 235

RRC District 3 Onshore . . . . . . . 1,040 -149 187 105 49 0 0 143 879

RRC District 4 Onshore . . . . . . . 246 122 17 28 72 1 0 62 368

RRC District 5 . . . . . . . . . . . . . . 53 5 32 14 2 0 1 11 68

RRC District 6 . . . . . . . . . . . . . . 562 83 15 42 2 0 0 42 578

RRC District 7B . . . . . . . . . . . . . 232 -47 69 14 53 0 0 33 260

RRC District 7C . . . . . . . . . . . . . 692 -5 81 107 8 0 8 81 596

RRC District 8 . . . . . . . . . . . . . . 2,981 -75 487 261 272 2 14 276 3,144

RRC District 8A . . . . . . . . . . . . . 1,276 10 41 65 18 0 0 74 1,206

RRC District 9 . . . . . . . . . . . . . . 121 37 10 8 10 0 1 24 147

RRC District 10 . . . . . . . . . . . . . 253 -3 35 39 7 0 0 26 227

State Offshore . . . . . . . . . . . . . . 6 1 4 0 0 0 0 1 10

Utah . . . . . . . . . . . . . . . . . . . . . . . . 301 -10 57 15 3 0 0 26 310

Virginia . . . . . . . . . . . . . . . . . . . . . . 0 478 67 0 0 0 0 22 523

West Virginia . . . . . . . . . . . . . . . . . 71 -1 3 9 0 0 0 5 59

Wyoming . . . . . . . . . . . . . . . . . . . . 824 54 86 42 15 0 0 87 850

Federal Offshorea . . . . . . . . . . . . . 7,437 90 818 1,232 194 1,349 132 875 7,913

Pacific (California) . . . . . . . . . . . 1,151 -13 6 612 1 1 0 36 498

Gulf of Mexico (Louisiana)a . . . . 5,492 188 695 550 186 750 123 697 6,187

Gulf of Mexico (Texas). . . . . . . . 794 -85 117 70 7 598 9 142 1,228

Miscellaneousb. . . . . . . . . . . . . . . . 28 11 20 26 0 0 0 2 31

U.S. Total. . . . . . . . . . . . . . . . . . . . 30,795 262 4,925 3,241 1,116 1,360 187 3,022 32,382

aIncludes Federal offshore Alabama. bIncludes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, Oregon, South Dakota, and Tennessee.

Note: The production estimates in this table are based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas

Reserves.” They may differ from the official Energy Information Administration production data for natural gas for 1997 contained in the

Natural Gas Annual 1997, DOE/EIA-0131(97).

Source: Energy Information Administration, Office of Oil and Gas.
Wyoming, and Louisiana accounted for 11,467 billion

cubic feet or 84 percent of U.S. NA wet natural gas total

discoveries in 1997.

Production

U.S. production of NA wet natural gas increased by 2

percent (267 billion cubic feet) in 1997 (Table 10). Of the

five leading producing areas, Texas, the Gulf of Mexico

Federal Offshore, and New Mexico increased

production, while Louisiana and Oklahoma had slight

declines in production. As in 1996, the Gulf of Mexico

Federal Offshore and the State of Texas, each with over

one-fourth of the U.S. total, were the leading producers

of NA wet natural gas in 1997.

Associated-Dissolved Natural Gas

Proved Reserves

Proved reserves of associated-dissolved (AD) natural

gas, wet after lease separation, in the United States

increased by 5 percent (1,587 billion cubic feet) to 32,382

billion cubic feet in 1997 (Table 11). Proved reserves of

AD wet natural gas in the lower 48 States decreased by

49 billion cubic feet to 24,666 billion cubic feet. Those

areas of the country with the largest AD wet natural gas

reserves were:

n Texas (24 percent)

n Alaska (24 percent)

n Gulf of Mexico Federal Offshore (23 percent)

n California (6 percent)

n New Mexico (4 percent).

These areas logically correspond to the areas of the

country with the largest volumes of crude oil reserves.

Production

U.S. production of AD wet natural gas increased by 3

percent in 1997 (Table 11), and production of AD wet

natural gas in the lower 48 States increased by 2 percent

(49 billion cubic feet). Those areas of the country with

the largest AD wet natural gas production were:

n Gulf of Mexico Federal Offshore (28 percent)

n Texas (28 percent)

n Alaska (9 percent)

n New Mexico (8 percent)

n California (5 percent).

Again, these areas logically correspond to the areas of

the country with the largest volumes of crude oil

production.

Coalbed Methane

Proved Reserves

Reserves of coalbed methane increased in 1997 to

account for about 7 percent of 1997 dry natural gas

reserves (Table 12). Federal tax incentives for new

coalbed methane wells expired at the end of 1992.

Reserves in coalbed methane fields increased to 11,462

billion cubic feet, 8 percent more than in 1996. The EIA

estimates that the 1997 proved gas reserves of fields

identified as having coalbed methane are about double

those reported in 1990 (Figure 21). Coalbed methane

proved reserves are principally located in New Mexico,

Colorado, Alabama, and Virginia. Estimates of proved

coalbed methane reserves increased in all these States

in 1997.

Production

Coalbed methane production grew by about 9 percent

in 1997 to 1,090 billion cubic feet—about 6 percent of

U.S. dry gas production. Most of the 1997 production

increase (87 billion cubic feet) occurred in the San Juan

Basin of Colorado and New Mexico.

Energy Information Administration

34 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

0

2

4

6

8

10

12

14

1989 1990 1991 1992 1993 1994 1995 1996 1997

Trillion Cubic Feet

Source: Energy Information Administration, Office of Oil and Gas.

Figure 21. Coalbed Methane Proved Reserves

1989-1997
Areas of Note:

Large Discoveries and

Reserves Additions

The following State or area discussions summarize

notable activities during the year concerning expected

new field reserves, development plans, and possible

production rates as extracted from various trade

publications and company reports. The citations do not

necessarily reflect EIA’s concurrence, but are

considered important enough to be brought to the

reader’s attention.

Alaska

Alaska had a net increase of 1,268 billion cubic feet of

dry natural gas proved reserves in 1997. The largest net

gas reserves increase of all States in 1997, it was from

adjustments and net revisions.

Gulf of Mexico

Deep Water: Advances in 3-D seismic technology and

previous deepwater successes have encouraged the oil

and gas industry to search and drill for hydrocarbons

farther offshore. Drilling in the deepwater portions of

the Outer Continental Shelf (OCS) of the Gulf of Mexico

has greatly increased in the past few years, and is now

at an all-time high.

Mensa: Production began in July 1997 from the deepest

producing field in the Gulf of Mexico, the Mensa Field

in Mississippi Canyon Blocks 686, 687, 730 and 731.

Shell produces gas from a subsea system of three wells

connected to a subsea manifold five miles away, all in

5,300 feet of water. The subsea manifold is tied back to a

shallow water platform in West Delta Block 143 via a

63-mile 12-inch diameter flowline. This 68-mile tieback

is currently the longest in the world. Shell estimates

that the Mensa Field has an ultimate recovery of 720

billion cubic feet of gas and will have peak production

rates of 300 million cubic feet of gas per day in the third

quarter of 1998.{36}

Marlin: In the Gulf of Mexico Federal Offshore

(Louisiana), in Viosca Knoll Block 915, Amoco is

developing the Marlin Field in 3,240 feet of water.

Amoco plans in late 1998 to install a tension-leg

platform, five producing wells, and full on-deck

processing capacity for 40,000 barrels of oil, 250 million

cubic feet of gas, and 20,000 barrels of water, per day.

The development system will also include two

deepwater pipelines to transport the produced oil and

gas. Production is expected to begin in 1999.{33}

Gemini: At the Gemini Field in Mississippi Canyon

Block 292, Texaco applied sophisticated 3D imaging to

locate and drill into reservoirs that lie below a

2,900-foot-thick salt sheet which initially defied

scientific exploration. Texaco owns 60% of this subsalt

gas and condensate discovery. Texaco expects the

Gemini Field to reach a peak rate of about 180 million

cubic feet per day by mid-1999.{37}

Texas

Although the State of Texas had a net decline in dry

natural gas proved reserves in 1997, the second largest

volume of new discoveries in 1997 was nevertheless

made there.

South Texas: Operators remain active in the Lobo

Trend in the lower Rio Grande Valley of south Texas

(RRC District 4). The trend occurs primarily in Webb

and Zapata counties and contains the four producing

horizons, Wilcox, Expanded Wilcox, Frio, and Lobo.

Unlike some other parts of the country, one or two

fields do not dominate the area. RRC District 4

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 35

Table 12. U.S. Coalbed Methane Proved Reserves and Production, 1994-1997

(Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

1994 1994 1995 1995 1996 1996 1997 1997

State Reserves Production Reserves Production Reserves Production Reserves Production

Alabama . . . . . . . 976 108 972 109 823 98 1,077 111

Colorado . . . . . . . 2,913 179 3,461 226 3,711 274 3,890 312

New Mexico . . . . 4,137 530 4,299 574 4,180 575 4,351 597

Othersa . . . . . . . . 1,686 34 1,767 47 1,852 56 2,144 70

Total . . . . . . . . . . 9,712 851 10,499 956 10,566 1,003 11,462 1,090

aIncludes Oklahoma, Pennsylvania, Utah, Virginia, West Virginia, and Wyoming.

Source: Energy Information Administration, Office of Oil and Gas.
increased its dry natural gas reserves by 330 billion

cubic feet in 1997. Operators in RRC District 4 reported

more extensions (37 percent of the State total) than any

other district in Texas. This district accounts for 21

percent of all of the reserves of dry natural gas in the

State and leads the State in gas production (26 percent

of the State total). RRC District 4’s dry gas production

increased 2 percent in 1997.

Similarly, RRC District 2 had an increase in dry natural

gas reserves of 312 billion cubic feet in 1997—mostly

from extensions of existing gas fields. RRC District 2’s

dry gas production increased 13 percent in 1997.

Wyoming

In 1997, Burlington Resources acquired Louisiana Land

and Exploration Company, which consolidated

Burlington Resources’ holdings in the Madden Field in

Fremont County, Wyoming. On March 19, Louisiana

Land and Exploration Company (LL&E) announced a

major extension to the reserves of the Madden Field.

Open hole log analysis of the new Big Horn 4-36 well

indicated a gross gas column of 260 feet in the Madison

formation with no water and excellent reservoir

quality. As a result, LL&E increased its estimate of

proved and probable, recoverable natural gas reserves

in the Madison reservoir to more than one trillion cubic

feet. The Big Horn 4-36 well, with a total depth of 24,600

feet, was drilled to a location in the gas-bearing

Madison formation 1,000 feet downdip from the crest

of a subsurface structure which has a minimum areal

extent of 23 square miles.

The Big Horn 4-36 well was drilled as a step-out from

the Big Horn 1-5 and the Big Horn 2-3 wells. These

wells are currently completed in the Madison

formation and are together producing about 52 million

cubic feet a day into the Lost Cabin Gas Plant (the

current inlet capacity of the plant). Each well is capable

of sustained production levels in excess of 30 million

cubic feet a day. Carbon dioxide and hydrogen sulfide

are removed prior to the sale of the gas and residual gas

sales average approximately 34 million cubic feet a

day.{38}

Areas of Note:

Large Reserves Declines

The following areas had large declines in dry natural

gas proved reserves due to downward revisions or

unreplaced production.

New Mexico

This State’s proved dry natural gas reserves decreased

by 6 percent (971 billion cubic feet). Two fields (Basin

and Blanco) accounted for about one-fourth of the

production and about one-half of the total reserves of

gas in New Mexico.

Colorado

This State’s proved dry natural gas reserves decreased

by 11 percent (882 billion cubic feet). However, the

stage is set for a future increase in reserves due to a

strategic acquisition by operator HS Resources. Near

the end of 1997, HS Resources acquired Amoco’s

Denver- Julesburg Basin properties (in and

surrounding Colorado’s large Wattenberg field),

capping an effort that spanned many years. For HS

Resources, the compelling reason for the acquisition

was the extraordinary abundance of reserves that

could be unlocked by combining the Amoco properties

with its own. For example, in many instances HS

Resources owns the right to produce from formations

which are “behind pipe” in an Amoco producing well.

Bringing these reserves into production by

recompleting an existing well generates substantially

better economics than can be achieved by drilling a

new well. In other instances, Amoco owned the right to

produce from formations located deeper than horizons

from which HS Resources was already producing, and

deepening an existing well is substantially more

economic than drilling a new well. Without these

efficiencies, many potential proved reserves were

economically “stranded” because drilling a new well

could not be justified. The re-aggregation of reserves

and value created by the Amoco acquisition gives HS

Resources a substantial inventory of projects with

virtually no risk and exceptional rates of return.{39}

Energy Information Administration

36 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
Kansas

This State’s proved dry natural gas reserves decreased

by 9 percent (705 billion cubic feet).

Reserves in

Nonproducing Reservoirs

Nonproducing proved natural gas reserves (wet after

lease separation) of 33,124 billion cubic feet were

reported in 1997 (Table 13). This was 75 billion cubic

feet higher than in 1996. About 37 percent of the

reserves in nonproducing reservoirs are located in the

Gulf of Mexico Federal Offshore area. Much of the new

deepwater reserves are in the nonproducing category.

Wells or reservoirs are nonproducing due to any of

several operational reasons. These include:

n waiting for well workovers

n waiting for additional development or

replacement wells to be drilled

n production or pipeline facilities not yet installed

n awaiting depletion of other zones or reservoirs

before recompletion in reservoirs not currently

open to production (called “behind pipe”

reserves).

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 37
Energy Information Administration

38 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table 13. Reported Reserves of Natural Gas, Wet After Lease Separation, in Nonproducing Reservoirs,

1997a

(Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

AssociatedState and Subdivision Nonassociated Gas Dissolved Gas Total

Alaska . . . . . . . . . . . . . . . . . . . . 232 82 314

Lower 48 States . . . . . . . . . . . . . . . 27,294 5,549 32,843

Alabama . . . . . . . . . . . . . . . . . . . 359 4 363

Arkansas . . . . . . . . . . . . . . . . . . . 136 10 146

California . . . . . . . . . . . . . . . . . . . 103 130 233

Coastal Region Onshore . . . . . . . . . 2 7 9

Los Angeles Basin Onshore . . . . . . . . 0 34 34

San Joaquin Basin Onshore . . . . . . . . 101 89 190

State Offshore . . . . . . . . . . . . . . . 0 1 1

Colorado . . . . . . . . . . . . . . . . . . . 600 74 674

Florida . . . . . . . . . . . . . . . . . . . . 0 0 0

Kansas . . . . . . . . . . . . . . . . . . . . 144 2 146

Kentucky . . . . . . . . . . . . . . . . . . . 137 0 137

Louisiana . . . . . . . . . . . . . . . . . . . 2,946 362 3,308

North . . . . . . . . . . . . . . . . . . . . 896 86 982

South Onshore. . . . . . . . . . . . . . . 1,794 225 2,019

South State Offshore . . . . . . . . . . . 256 51 307

Michigan . . . . . . . . . . . . . . . . . . . 77 10 87

Mississippi . . . . . . . . . . . . . . . . . . 56 14 70

Montana . . . . . . . . . . . . . . . . . . . 41 2 43

New Mexico. . . . . . . . . . . . . . . . . . 1,700 66 1,766

East . . . . . . . . . . . . . . . . . . . . 236 63 299

West . . . . . . . . . . . . . . . . . . . . 1,464 3 1,467

New York . . . . . . . . . . . . . . . . . . . 2 0 2

North Dakota . . . . . . . . . . . . . . . . . 109 10 119

Ohio. . . . . . . . . . . . . . . . . . . . . . 6 0 6

Oklahoma. . . . . . . . . . . . . . . . . . . 1,219 107 1,326

Pennsylvania . . . . . . . . . . . . . . . . . 24 0 24

Texas . . . . . . . . . . . . . . . . . . . . . 5,734 712 6,446

RRC District 1 . . . . . . . . . . . . . . . 244 2 246

RRC District 2 Onshore . . . . . . . . . . 339 65 404

RRC District 3 Onshore . . . . . . . . . . 730 39 769

RRC District 4 Onshore . . . . . . . . . . 2,024 80 2,104

RRC District 5 . . . . . . . . . . . . . . . 323 3 326

RRC District 6 . . . . . . . . . . . . . . . 862 128 990

RRC District 7B . . . . . . . . . . . . . . 15 20 35

RRC District 7C . . . . . . . . . . . . . . 255 30 285

RRC District 8 . . . . . . . . . . . . . . . 398 261 659

RRC District 8A . . . . . . . . . . . . . . 0 74 74

RRC District 9 . . . . . . . . . . . . . . . 38 2 40

RRC District 10 . . . . . . . . . . . . . . 444 8 452

State Offshore . . . . . . . . . . . . . . . 62 0 62

Utah. . . . . . . . . . . . . . . . . . . . . . 347 94 441

Virginia . . . . . . . . . . . . . . . . . . . . 838 0 838

West Virginia . . . . . . . . . . . . . . . . . 375 4 379

Wyoming . . . . . . . . . . . . . . . . . . . 3,709 94 3,803

Federal Offshoreb . . . . . . . . . . . . . . 8,629 3,856 12,485

Pacific (California) . . . . . . . . . . . . . 47 19 66

Gulf of Mexico (Louisiana)b . . . . . . . . 6,809 2,960 9,769

Gulf of Mexico (Texas). . . . . . . . . . . 1,773 877 2,650

Miscellaneousc . . . . . . . . . . . . . . . . 1 2 3

U.S. Total. . . . . . . . . . . . . . . . . . . 27,526 5,631 33,157

aIncludes only those operators who produced 400,000 barrels of crude oil or 2 billion cubic feet of natural gas, or both, during the report

year (Category I or Category II operators).

bIncludes Federal Offshore Alabama.

cIncludes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, Oregon, South Dakota, and Tennessee.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1997.
5. Natural Gas Liquids Statistics

Natural Gas Liquids

Proved Reserves

U.S. natural gas liquids proved reserves increased 2

percent to 7,973 million barrels in 1997 (Table 14). This

was the third annual increase in a row. The 150 million

barrel increase was predominantly in Alaska, which

nearly doubled it natural gas liquids reserves level in

1997. Overall, reserve additions replaced 117 percent of

1997 natural gas liquids production.

The reserves of six areas account for 83 percent of the

Nation’s natural gas liquids proved reserves.

Percent of

Area U.S. NGL Reserves

Texas 34

Gulf of Mexico Federal Offshore 11

New Mexico 11

Utah-Wyoming 10

Oklahoma 9

Alaska 8

Area Total 83

The volumes of natural gas liquids proved reserves and

production shown in Table 14 are the sum of the

natural gas plant liquid volumes listed in Table 15 and

the lease condensate volumes listed in Table 16.

Discoveries

Total discoveries of natural gas liquids reserves

increased by 18 percent in 1997 to 739 million barrels,

the second highest level ever recorded by EIA. Areas

with the largest total discoveries were:

n Texas (44 percent)

n Gulf of Mexico Federal Offshore (22 percent)

n Utah and Wyoming (13 percent)

n Louisiana (7 percent)

n New Mexico (6 percent)

n Oklahoma (5 percent).

New field discoveriesin 1997 (114 million barrels) were 75

percent higher than in 1996. Areas with the largest new

field discoveries were the Gulf of Mexico Federal

Offshore (54 percent of 1997 new field discoveries) and

Texas (46 percent).

New reservoir discoveries in old fields (90 million barrels)

were 17 percent less than what they were in 1996. Areas

with the largest new reservoir discoveries in old fields were

the Gulf of Mexico Federal Offshore (53 percent of 1997

new reservoir discoveries in old fields), Louisiana (21

percent), and Texas (16 percent).

Extensions were 535 million barrels, an increase of 19

percent over 1996. Areas with the largest extensions

were Texas (48 percent of 1997 extensions),

Utah-Wyoming (18 percent), and the Gulf of Mexico

Federal Offshore (10 percent).

Production

Natural gas liquids production was an estimated 864

million barrels in 1997. Alaska production increased 6

percent to 35 million barrels in 1997, while lower 48

States production increased 1 percent to 829 million

barrels in 1997.

Seven areas accounted for about 90 percent of the

Nation’s natural gas liquids production.

n Texas (37 percent)

n Gulf of Mexico Federal Offshore (16 percent)

n New Mexico (9 percent)

n Oklahoma (9 percent)

n Louisiana (8 percent)

n Utah-Wyoming (7 percent)

n Alaska (4 percent).

Natural Gas Plant Liquids

Proved Reserves

Natural gas plant liquids proved reserves increased 2

percent in 1997 to 6,632 million barrels (Table 15). Six

areas accounted for about 83 percent of the Nation’s

natural gas plant liquids proved reserves:

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 39
Energy Information Administration

40 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table 14. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 1997

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 1997

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/96 (+,-) (+) (-) (+) (+) (+) (-) 12/31/97

Alaska. . . . . . . . . . . . . . . . . . . . . . . 337 93 234 0 2 0 0 35 631

Lower 48 States . . . . . . . . . . . . . . 7,486 -107 965 910 533 114 90 829 7,342

Alabama . . . . . . . . . . . . . . . . . . . . . 119 -13 3 6 0 0 0 10 93

Arkansas . . . . . . . . . . . . . . . . . . . . 4 2 2 0 0 0 0 1 7

California . . . . . . . . . . . . . . . . . . . . 92 -5 15 2 3 0 0 8 95

Coastal Region Onshore . . . . . . 9 0 1 1 1 0 0 1 9

Los Angeles Basin Onshore . . . 3 0 1 0 0 0 0 0 4

San Joaquin Basin Onshore . . . 80 -5 13 1 2 0 0 7 82

State Offshore . . . . . . . . . . . . . . 0 0 0 0 0 0 0 0 0

Colorado. . . . . . . . . . . . . . . . . . . . . 287 25 34 64 5 0 0 23 264

Florida . . . . . . . . . . . . . . . . . . . . . . 22 -4 0 0 0 0 0 1 17

Kansas . . . . . . . . . . . . . . . . . . . . . . 338 -39 16 21 2 0 0 25 271

Kentucky. . . . . . . . . . . . . . . . . . . . . 46 -1 4 0 1 0 1 3 48

Louisiana . . . . . . . . . . . . . . . . . . . . 543 -109 82 63 35 0 19 70 437

North . . . . . . . . . . . . . . . . . . . . . 85 -6 18 11 6 0 0 12 80

South Onshore. . . . . . . . . . . . . . 411 -81 57 45 28 0 16 53 333

State Offshore . . . . . . . . . . . . . . 47 -22 7 7 1 0 3 5 24

Michigan. . . . . . . . . . . . . . . . . . . . . 53 1 6 6 1 0 0 5 50

Mississippi . . . . . . . . . . . . . . . . . . . 7 0 0 1 1 0 0 1 6

Montana . . . . . . . . . . . . . . . . . . . . . 7 -2 1 1 0 0 0 0 5

New Mexico . . . . . . . . . . . . . . . . . . 1,059 -156 132 134 47 0 1 80 869

East . . . . . . . . . . . . . . . . . . . . . . 299 -11 42 36 21 0 1 43 273

West. . . . . . . . . . . . . . . . . . . . . . 760 -145 90 98 26 0 0 37 596

North Dakota . . . . . . . . . . . . . . . . . 48 -2 5 2 2 0 0 4 47

Oklahoma. . . . . . . . . . . . . . . . . . . . 684 -21 134 68 31 0 4 79 685

Texas . . . . . . . . . . . . . . . . . . . . . . . 2,606 81 336 341 255 53 14 317 2,687

RRC District 1 . . . . . . . . . . . . . . 46 0 7 3 9 1 0 6 54

RRC District 2 Onshore . . . . . . . 93 -15 14 12 16 2 1 12 87

RRC District 3 Onshore . . . . . . . 289 -32 47 37 24 45 3 53 286

RRC District 4 Onshore . . . . . . . 323 15 75 105 88 1 4 54 347

RRC District 5 . . . . . . . . . . . . . . 54 -7 3 15 1 0 3 4 35

RRC District 6 . . . . . . . . . . . . . . 290 -18 24 34 25 0 0 27 260

RRC District 7B . . . . . . . . . . . . . 65 -15 14 5 5 3 0 8 59

RRC District 7C . . . . . . . . . . . . . 303 39 33 36 23 0 1 36 327

RRC District 8 . . . . . . . . . . . . . . 429 17 63 33 29 1 2 49 459

RRC District 8A . . . . . . . . . . . . . 262 50 12 19 4 0 0 19 290

RRC District 9 . . . . . . . . . . . . . . 119 -18 6 9 13 0 0 13 98

RRC District 10 . . . . . . . . . . . . . 332 64 37 33 18 0 0 36 382

State Offshore . . . . . . . . . . . . . . 1 1 1 0 0 0 0 0 3

Utah and Wyoming. . . . . . . . . . . . . 727 -4 73 77 97 0 2 57 761

West Virginia . . . . . . . . . . . . . . . . . 61 11 4 2 0 0 1 4 71

Federal Offshorea . . . . . . . . . . . . . 776 128 116 121 53 61 48 141 920

Pacific (California) . . . . . . . . . . . 23 3 0 11 0 0 0 1 14

Gulf of Mexico (Louisiana)a . . . . 621 125 105 89 45 56 45 123 785

Gulf of Mexico (Texas). . . . . . . . 132 0 11 21 8 5 3 17 121

Miscellaneousb. . . . . . . . . . . . . . . . 7 1 2 1 0 0 0 0 9

U.S. Total. . . . . . . . . . . . . . . . . . . . 7,823 -14 1,199 910 535 114 90 864 7,973

aIncludes Federal offshore Alabama. bIncludes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, New York, Ohio, Oregon, Pennsylvania, South Dakota,

Tennessee, and Virginia.

Note: The production estimates in this table are based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas

Reserves,” and Form EIA-64A, “Annual Report of the Origin of Natural Gas Liquids Production.” They may differ from the official Energy

Information Administration production data for natural gas and natural gas liquids for 1997 contained in the publications Petroleum Supply

Annual 1997, DOE/EIA-0340(97) and Natural Gas Annual 1997 DOE/EIA-0131(97).

Source: Energy Information Administration, Office of Oil and Gas.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 41

Table 15. Natural Gas Plant Liquids Proved Reserves and Production, 1997

(Million Barrels of 42 U.S. Gallons)

1997 1997 1997 1997

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska . . . . . . . . . . . . . . . . . . . . . . 631 35

Lower 48 States. . . . . . . . . . . . . . 6,001 655

Alabama . . . . . . . . . . . . . . . . . . . . 34 4

Arkansas . . . . . . . . . . . . . . . . . . . . 3 0

California. . . . . . . . . . . . . . . . . . . . 92 8

Coastal Region Onshore . . . . . 9 1

Los Angeles Basin Onshore . . . 4 0

San Joaquin Basin Onshore. . . 79 7

State Offshore. . . . . . . . . . . . . . 0 0

Colorado . . . . . . . . . . . . . . . . . . . . 244 17

Florida . . . . . . . . . . . . . . . . . . . . . . 17 1

Kansas . . . . . . . . . . . . . . . . . . . . . 263 24

Kentucky . . . . . . . . . . . . . . . . . . . . 47 3

Louisiana. . . . . . . . . . . . . . . . . . . . 261 41

North. . . . . . . . . . . . . . . . . . . . . 50 7

South Onshore . . . . . . . . . . . . . 199 31

State Offshore. . . . . . . . . . . . . . 36 3

Michigan . . . . . . . . . . . . . . . . . . . . 12 4

Mississippi. . . . . . . . . . . . . . . . . . . 45 0

Montana . . . . . . . . . . . . . . . . . . . . 5 0

New Mexico . . . . . . . . . . . . . . . . . 814 75

East . . . . . . . . . . . . . . . . . . . . . 253 40

West . . . . . . . . . . . . . . . . . . . . . 561 35

North Dakota. . . . . . . . . . . . . . . . . 40 4

Oklahoma . . . . . . . . . . . . . . . . . . . 610 71

Texas . . . . . . . . . . . . . . . . . . . . . . 2,376 275

RRC District 1. . . . . . . . . . . . . . 46 5

RRC District 2 Onshore . . . . . . 75 10

RRC District 3 Onshore . . . . . . 170 36

RRC District 4 Onshore . . . . . . 261 42

RRC District 5. . . . . . . . . . . . . . 31 4

RRC District 6. . . . . . . . . . . . . . 221 22

RRC District 7B. . . . . . . . . . . . . 57 8

RRC District 7C . . . . . . . . . . . . 309 34

RRC District 8. . . . . . . . . . . . . . 447 47

RRC District 8A. . . . . . . . . . . . . 290 19

RRC District 9. . . . . . . . . . . . . . 96 13

RRC District 10. . . . . . . . . . . . . 372 35

State Offshore. . . . . . . . . . . . . . 1 0

Utah and Wyoming . . . . . . . . . . . . 680 49

West Virginia. . . . . . . . . . . . . . . . . 70 4

Federal Offshorea . . . . . . . . . . . . . 389 71

Pacific (California). . . . . . . . . . . 10 1

Gulf of Mexico (Louisiana)a . . . 352 64

Gulf of Mexico (Texas) . . . . . . . 27 6

Miscellaneousb . . . . . . . . . . . . . . . 9 0

U.S. Total . . . . . . . . . . . . . . . . . . . 6,632 690

aIncludes Federal Offshore Alabama. bIncludes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, New York, Ohio, Oregon, Pennsylvania, South Dakota,

Tennessee, and Virginia.

Note: The production estimates in this table are based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas

Reserves,” and Form EIA-64A, “Annual Report of the Origin of Natural Gas Liquids Production.” They may differ from the official Energy

Information Administration production data for natural gas plant liquids for 1997 contained in the publications Petroleum Supply Annual 1997,

DOE/EIA-0340(97) and Natural Gas Annual 1997, DOE/EIA-0131(97).

Source: Energy Information Administration, Office of Oil and Gas.
Energy Information Administration

42 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table 16. Lease Condensate Proved Reserves and Production, 1997

(Million Barrels of 42 U.S. Gallons)

1997 1997 1997 1997

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska . . . . . . . . . . . . . . . . . . . . . . 0 0

Lower 48 States. . . . . . . . . . . . . . 1,341 174

Alabama . . . . . . . . . . . . . . . . . . . . 59 6

Arkansas . . . . . . . . . . . . . . . . . . . . 4 1

California. . . . . . . . . . . . . . . . . . . . 3 0

Coastal Region Onshore . . . . . 0 0

Los Angeles Basin Onshore . . . 0 0

San Joaquin Basin Onshore. . . 3 0

State Offshore. . . . . . . . . . . . . . 0 0

Colorado . . . . . . . . . . . . . . . . . . . . 20 2

Florida . . . . . . . . . . . . . . . . . . . . . . 0 0

Kansas . . . . . . . . . . . . . . . . . . . . . 8 1

Kentucky . . . . . . . . . . . . . . . . . . . . 1 0

Louisiana. . . . . . . . . . . . . . . . . . . . 176 29

North. . . . . . . . . . . . . . . . . . . . . 30 5

South Onshore . . . . . . . . . . . . . 134 22

State Offshore. . . . . . . . . . . . . . 12 2

Michigan . . . . . . . . . . . . . . . . . . . . 5 1

Mississippi. . . . . . . . . . . . . . . . . . . 4 1

Montana . . . . . . . . . . . . . . . . . . . . 0 0

New Mexico . . . . . . . . . . . . . . . . . 55 5

East . . . . . . . . . . . . . . . . . . . . . 20 3

West . . . . . . . . . . . . . . . . . . . . . 35 2

North Dakota. . . . . . . . . . . . . . . . . 7 0

Oklahoma . . . . . . . . . . . . . . . . . . . 75 8

Texas . . . . . . . . . . . . . . . . . . . . . . 311 42

RRC District 1. . . . . . . . . . . . . . 8 1

RRC District 2 Onshore . . . . . . 12 2

RRC District 3 Onshore . . . . . . 116 17

RRC District 4 Onshore . . . . . . 86 12

RRC District 5. . . . . . . . . . . . . . 4 0

RRC District 6. . . . . . . . . . . . . . 39 5

RRC District 7B. . . . . . . . . . . . . 2 0

RRC District 7C . . . . . . . . . . . . 18 2

RRC District 8. . . . . . . . . . . . . . 12 2

RRC District 8A. . . . . . . . . . . . . 0 0

RRC District 9. . . . . . . . . . . . . . 2 0

RRC District 10. . . . . . . . . . . . . 10 1

State Offshore. . . . . . . . . . . . . . 2 0

Utah and Wyoming . . . . . . . . . . . . 81 8

West Virginia. . . . . . . . . . . . . . . . . 1 0

Federal Offshorea . . . . . . . . . . . . . 531 70

Pacific (California). . . . . . . . . . . 4 0

Gulf of Mexico (Louisiana)a . . . 433 59

Gulf of Mexico (Texas) . . . . . . . 94 11

Miscellaneousb . . . . . . . . . . . . . . . 0 0

U.S. Total . . . . . . . . . . . . . . . . . . . 1,341 174

aIncludes Federal Offshore Alabama. bIncludes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, New York, Ohio, Oregon, Pennsylvania, South Dakota,

Tennessee, and Virginia.

Note: The estimates in this table are based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves” 1997.

Source: Energy Information Administration, Office of Oil and Gas.
Percent of

Area U.S. Gas Plant Liquids

Texas 36

New Mexico 12

Utah-Wyoming 10

Alaska 10

Oklahoma 9

Gulf of Mexico Federal Offshore 6

Area Total 83

Production

Natural gas plant liquids production increased only

slightly in 1997—from 688 million barrels in 1996 to 690

million barrels of production (Table 15). The top six

areas for proved reserves of natural gas plant liquids

accounted for about 83 percent of the Nation’s natural

gas plant liquids production:

n Texas (40 percent)

n New Mexico (11 percent)

n Oklahoma (10 percent)

n Gulf of Mexico Federal Offshore (10 percent)

n Utah and Wyoming (7 percent)

n Alaska (5 percent).

Natural gas processing plants are usually located in the

same general area where the natural gas is produced.

Table E4 in Appendix E lists the volumes of natural gas

produced and processed in the same State, and the

volumes of liquids extracted.

Lease Condensate

Proved Reserves

Proved reserves of lease condensate in the United

States were 1,341 million barrels in 1997 (Table 16).

This was 34 million barrels or 3 percent higher than in

1996. The reserves of four areas account for about 81

percent of the Nation’s lease condensate proved

reserves.

Percent of U.S.

Area Condensate Reserves

Gulf of Mexico Federal Offshore 39

Texas 23

Louisiana 13

Utah-Wyoming 6

Area Total 81

Production

Production of lease condensate was 174 million barrels,

an increase of 12 million barrels, or 7 percent, in 1997.

The production of four areas account for about 86

percent of the Nation’s lease condensate production.

n Gulf of Mexico Federal Offshore (40 percent)

n Texas (24 percent)

n Louisiana (17 percent)

n Utah-Wyoming (5 percent).

Reserves in

Nonproducing Reservoirs

Like crude oil and natural gas, not all lease condensate

proved reserves were contained in reservoirs that were

producing during 1997. Proved reserves of 501 million

barrels of lease condensate, an increase of 1 percent

from 1996, were reported in nonproducing reservoirs

in 1997. These reserves were reported by Category I

and Category II operators who collectively accounted

for more than 97 percent of total lease condensate

production. About 63 percent of the nonproducing

lease condensate reserves were located in the Gulf of

Mexico Federal Offshore.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 43
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18. Energy Information Administration. October 1995.

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

Reserves 1994 Annual Report. DOE/EIA-0216(94).

Washington, DC.

19. Energy Information Administration. November

1996. U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves 1995 Annual Report.

DOE/EIA-0216(95). Washington, DC.

20. Energy Information Administration. December

1997. U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves 1996 Annual Report.

DOE/EIA-0216(96). Washington, DC.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 45
21. Energy Information Administration. October 1998.

Petroleum Marketing Monthly. DOE/EIA0380(98/10). Washington, DC.

22. Energy Information Administration. October 1998.

Natural Gas Monthly. DOE/EIA-0130(98/10).

Washington, DC, pg. 16.

23. American Petroleum Institute, American Gas

Association, and Canadian Petroleum Association.

Reserves of Crude Oil, Natural Gas Liquids, and

Natural Gas in the United States and Canada as of

December 31, 1979. Vol. 34. June 1980. Washington,

DC.

24. Energy Information Administration, August 1990.

U.S. Oil and Gas Reserves by Year of Field Discovery.

DOE/EIA-0534. Washington, DC.

25. Oil & Gas Journal. December 29, 1997. “Worldwide

Look and Reserves and Production”. Vol. 95, No.

52. Tulsa, OK, p. 24.

26. World Oil. August 1998. “World Trends”. Houston,

TX, p. 29.

27. World Oil. August 1998. “South America”.

Houston, TX, pp. 45-47.

28. Energy Information Administration. July 1998.

1997 Annual Energy Review. DOE/EIA-0384(97).

Washington, DC, p. 39.

29. Energy Information Administration. July 1998.

1997 Annual Energy Review. DOE/EIA-0384(97).

Washington, DC, p. 159.

30. Exxon Corporation, Irving, TX. Press Release,

April 8, 1997.

31. Shell Exploration and Production Company.

Houston, TX. Http://www.shellus.com,

download of Europa Fact Sheet.

32. Shell Exploration and Production Company.

Houston, TX. Http://www.shellus.com,

download of Macaroni Fact Sheet.

33. Amoco Corporation, Chicago, IL. Press Release,

January 29, 1997.

34. Texaco Incorporated. White Plains, NY. 1997

Annual Report. pp.14-15.

35. Atlantic Richfield Company. Los Angeles, CA.

1997 Annual Report. p. 5.

36. Shell Exploration and Production Company.

Houston, TX. Http://www.shellus.com,

download of Mensa Fact Sheet.

37. Texaco Incorporated. White Plains, NY. 1997

Annual Report. P.17.

38. Louisiana Land and Exploration Company, New

Orleans, LA. Press Release, March 19, 1997.

39. HS Resources, Incorpated. San Francisco, CA. 1997

Annual Report. P. 9.

40. U.S. Department of Energy. DOE This Month. Vol.

15, No. 8. Washington, DC, August 1992. p. 13.

41. U.S. Department of the Interior. 1995. National

Assessment of the United States Oil and Gas Resources.

U.S. Geological Survey Circular 1118. Denver, CO,

pp. 5-6.

42. U.S. Department of the Interior, Minerals

Management Service, Gulf of Mexico OCS

Regional Office. August 1995. Estimated Proved Oil

and Gas Reserves, Gulf of Mexico, December 31, 1994.

OCS Report MMS 94-0045. New Orleans, LA, pp.

5-6.

Energy Information Administration

46 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
Appendix A

Operator Data by Size Class
Appendix A

Operator Data by Size Class

To remain competitive in the domestic oil and gas

industry, companies have to reduce costs and look for

areas of profitable growth. Over the past few years, we

have seen companies restructure to focus on their core

areas of profit. This restructuring has taken many

forms, for example, laying off employees, early

retirements and buyouts, flattening management

structure, selective sales of marginally profitable

properties, and acquisitions. Documenting some of

these changes is important. Appendix A is a series of

tables of the proved reserves and production by

production size class for the years 1992 through 1997

for oil and gas well operators. The tables show the

volumetric change and percent change from the

previous year and from 1992. In addition they show the

1997 average per operator in each class. All companies

that reported to EIA were ranked by production size

for each of the 6 years. We computed company

production size classes as the sum of the barrel oil

equivalent of the crude oil production, lease

condensate production, and wet gas production for

each operator. The companies were then placed in the

following production size classes: 1–10, 11–20, 21–100,

101–500, and all “other” oil and gas operators. The

“other” category contains 22,178 small operators. We

estimate production and reserves for small operators

each year from a sample of approximately 8 percent of

these operators.

Class 1–10 contains the 10 highest producing

companies each year on a barrel oil equivalent basis.

These companies are not necessarily the same 10

companies each year.

We also include statistics for operator Category sizes at

the bottom portion of tables in this appendix. These are

the categories used by EIA in processing and assessing

reserves surveys and are presented here as additional

perspective. For further explanation of categories sizes

see definitions and descriptions in Appendix E.

Natural Gas

Proved Reserves

The wet natural gas proved reserves reported for 1992

through 1997 have changed from 173.3 trillion cubic

feet to 175.7 trillion cubic feet (Table A1). Reserves

have been increasing for the last five years in a row and

are above the 1992 level. These proved reserves are

highly concentrated in the larger companies. In 1997,

the top 20 (Class 1–10 and Class 11–20) producing

companies had 55 percent of the proved reserves of

natural gas. The next two size classes contain 80 and

400 companies and account for 26 and 13 percent of the

U.S. natural gas proved reserves, respectively. The top

20 operators had a decline of 6 percent in their natural

gas proved reserves from 1992 to 1997. While the rest of

the operators (Class 21–100, Class 101–500, and Class

Other) had an increase of 12 percent. In 1997, the top 20

operators' natural gas reserves increased by 15 percent

from 1996.

Production

Wet natural gas production has slightly increased from

19.9 trillion cubic feet to 20.1 trillion cubic feet in 1997

(Table A2). In 1997, the top 20 producing companies

had 52 percent of the production of wet natural gas,

while having 55 percent of the proved reserves. The

next two size classes have 28 and 13 percent of the wet

natural gas production, respectively. The top 20

operators had an increase of 8 percent in their wet

natural gas production from 1992 to 1997. The rest of

the operators had an increase of 12 percent from 1992 to

1997. The top 20 operators' wet natural gas production

had an decrease of 5 percent in 1997, while the rest of

the operators remained the same.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 49
Crude Oil

Proved Reserves

Proved reserves of crude oil are more highly

concentrated in a few companies than those of natural

gas. The 20 largest oil and gas producing companies in

1997 had 64 percent of U.S. proved reserves of crude oil

(Table A3), in contrast to wet natural gas where these

same companies operated only 55 percent of the total

proved reserves. These companies have tended in the

past few years to concentrate their domestic operations

in fewer fields and focus more of their resources on

their foreign operations.

U.S. proved reserves of crude oil increased 2.4 percent

in 1997. The top 20 producing companies had a decline

of 6 percent in their domestic proved reserves of crude

oil during 1997. The top 20 class had a decline of 20

percent in their crude oil proved reserves from 1992 to

1997. The next two size classes each account for 9

percent of the U.S. crude oil proved reserves. The class

“other” had a 15 percent decrease from 1992 to 1997.

During the 1992–1997 period, many operators were

continuing to actively buy, sell, and restructure their oil

property positions.

Production

Crude oil production reported for 1992 through 1997

has decreased from 2.4 billion barrels to 2.1 billion

barrels (Table A4). The 20 largest oil and gas producing

companies had 61 percent of U.S. production of crude

oil in 1997, while in 1992 they accounted for 69 percent

of production. This is in contrast to wet natural gas

where these same companies produced only 52 percent

of the total.

U.S. production of crude oil declined by 13 percent

from 1992 to 1997. The top 20 operators had a decline of

22 percent in their oil production during the same

period. U.S. production of crude oil declined by 2

percent from 1996 to 1997, while the top 20 operators

production decreased by 7 percent. The next two size

classes account for 17 and 11 percent of the U.S. crude

oil production, respectively.

Fields

The number of fields in which Category I and Category

II operators were active dropped significantly during

the 1992–1997 period. Fields in which these large

operators were active dropped by 2,227 or 8 percent

(Table A5). Most of the changes in operator field counts

resulted from the top 20 operators class concentrating

their effort in a diminishing number of fields. From

1992 through 1997, the number of fields in which the

top 20 operators were active in dropped by 2,798 or 37

percent, while in 1997 the number dropped 8 percent

from 1996.

Energy Information Administration

50 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 51

Class 1–10 74,350 77,552 76,665 75,856 72,606 68,876 -3,730 -5,474 6,887.600

Percent of Total 42.9% 45.5% 44.6% 43.7% 41.5% 39.2% -5.1% -7.4%

Class 11–20 28,442 22,467 22,691 24,648 25,416 27,705 2,289 -737 2,770.500

Percent of Total 16.4% 13.2% 13.2% 14.2% 14.5% 15.8% 9.0% -2.6%

Class 21–100 38,388 39,135 40,566 42,604 43,300 45,593 2,293 7,205 569.913

Percent of Total 22.2% 23.0% 23.6% 24.6% 24.7% 25.9% 5.3% 18.8%

Class 101–500 19,728 19,870 20,608 20,150 22,483 23,338 855 3,610 58.345

Percent of Total 11.4% 11.7% 12.0% 11.6% 12.8% 13.3% 3.8% 18.3%

Class Other (22,178) 12,401 11,466 11,409 10,218 11,342 10,209 -1,133 -2,192 0.460

Percent of Total 7.2% 6.7% 6.6% 5.9% 6.5% 5.8% -10.0% -17.7%

Category I (169) 144,351 142,892 143,703 148,233 146,601 147,491 890 3,140 872.728

Percent of Total 83.3% 83.8% 83.6% 85.4% 83.7% 83.9% 0.6% 2.2%

Category II (418) 17,682 17,305 18,158 15,828 18,382 17,764 -618 82 42.498

Percent of Total 10.2% 10.2% 10.6% 9.1% 10.5% 10.1% -3.4% 0.5%

Category III (22,037) 11,276 10,292 10,078 9,416 10,164 10,466 302 -810 0.475

Percent of Total 6.5% 6.0% 5.9% 5.4% 5.8% 6.0% 3.0% -7.2%

Total Published 173,309 170,490 171,939 173,476 175,147 175,721 574 2,412 7.749

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 0.3% 1.4%

Table A1. Natural Gas Proved Reserves, Wet After Lease Separation, by Operator Production Size Class,

1992–1997

(Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

1996–1997 1992–1997 1997

Volume and Volume and Average

Percent Percent Reserves

Size Class 1992 1993 1994 1995 1996 1997 Change Change per Operator

Note: There were 22,037 active Category III operators in the 1997 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 2,494 Category III operators (Table E2). The “other” size class represents 22,178 operators in the

1997 frame (22,678 active operators minus the 500 largest operators).

Source: Energy Information Administration, Office of Oil and Gas.
Energy Information Administration

52 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Class 1–10 6,625 6,801 7,216 7,174 7,448 7,178 -270 553 717.800

Percent of Total 36.3% 36.5% 37.6% 38.0% 37.5% 35.7% -3.6% 8.3%

Class 11–20 3,036 2,861 3,083 3,101 3,002 3,286 284 250 328.600

Percent of Total 16.6% 15.3% 16.0% 16.4% 15.1% 16.3% 9.5% 8.2%

Class 21–100 4,592 4,894 4,878 4,871 5,316 5,729 413 1,137 71.613

Percent of Total 25.1% 26.3% 25.4% 25.8% 26.7% 28.4% 7.8% 24.8%

Class 101–500 2,411 2,597 2,552 2,477 2,623 2,665 42 254 6.663

Percent of Total 13.2% 13.9% 13.3% 13.1% 13.2% 13.2% 1.6% 10.5%

Class Other (22,178) 1,605 1,488 1,481 1,251 1,484 1,276 -208 -329 0.058

Percent of Total 8.8% 8.0% 7.7% 6.6% 7.5% 6.3% -14.0% -20.5%

Category I (169) 14,767 15,122 15,656 15,800 16,381 16,897 516 2,130 99.982

Percent of Total 80.8% 81.1% 81.5% 83.7% 82.4% 83.9% 3.1% 14.4%

Category II (418) 2,036 2,159 2,221 1,923 2,128 1,979 -149 -57 4.734

Percent of Total 11.1% 11.6% 11.6% 10.2% 10.7% 9.8% -7.0% -2.8%

Category III (22,037) 1,466 1,360 1,333 1,151 1,364 1,258 -106 -208 0.057

Percent of Total 8.0% 7.3% 6.9% 6.1% 6.9% 6.2% -7.8–% -14.2%

Total Published 18,269 18,641 19,210 18,874 19,873 20,134 261 1,865 0.888

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 1.3% 10.2%

Table A2. Natural Gas Production, Wet After Lease Separation, by Operator Production Size Class,

1992–1997

(Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

1996–1997 1992–1997 1997

Volume and Volume and Average

Percent Percent Production

Size Class 1992 1993 1994 1995 1996 1997 Change Change per Operator

Note: There were 22,037 active Category III operators in the 1997 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 2,494 Category III operators (Table E2). The “other” size class represents 22,178 operators in the

1997 frame (22,678 active operators minus the 500 largest operators).

Source: Energy Information Administration, Office of Oil and Gas.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 53

Class 1–10 15,733 14,894 14,351 13,891 13,362 11,434 -1,928 -4,299 1,143.400

Percent of Total 66.3% 64.9% 63.9% 62.1% 60.7% 50.7% -14.4% -27.3%

Class 11–20 2,250 2,389 2,276 2,422 2,013 2,977 964 727 297.700

Percent of Total 9.5% 10.4% 10.1% 10.8% 9.1% 13.2% 47.9% 32.3%

Class 21–100 2,370 2,401 2,607 2,623 3,155 4,384 1,229 2,014 54.800

Percent of Total 10.0% 10.5% 11.6% 11.7% 14.3% 19.4% 39.0% 85.0%

Class 101–500 1,463 1,440 1,512 1,793 1,838 2,111 273 648 5.278

Percent of Total 6.2% 6.3% 6.7% 8.0% 8.3% 9.4% 14.9% 44.3%

Class Other (22,178) 1,929 1,833 1,711 1,622 1,649 1,640 -9 -289 0.074

Percent of Total 8.1% 8.0% 7.6% 7.3% 7.5% 7.3% -0.5% -15.0%

Category I (169) 20,767 20,090 19,648 19,647 19,312 19,461 149 -1,306 115.154

Percent of Total 87.5% 87.5% 87.5% 87.9% 87.7% 86.3 0.8% -6.3%

Category II (418) 1,150 1,131 1,142 1,103 1,117 1,400 283 250 3.349

Percent of Total 4.8% 4.9% 5.1% 4.9% 5.1% 6.2 25.3% 21.7%

Category III (22,037) 1,828 1,737 1,668 1,600 1,588 1,685 97 -959 0.076

Percent of Total 7.7% 7.6% 7.4% 7.2% 7.2% 7.5 6.1% -5.0%

Total Published 23,745 22,957 22,457 22,351 22,017 22,546 529 -1,199 0.994

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 2.4% -5.0%

Table A3. Crude Oil Proved Reserves by Operator Production Size Class, 1992–1997

(Million Barrels of 42 U.S. Gallons)

1996–1997 1992–1997 1997

Volume and Volume and Average

Percent Percent Reserves

Size Class 1992 1993 1994 1995 1996 1997 Change Change per Operator

Note: There were 22,037 active Category III operators in the 1997 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 2,494 Category III operators (Table E2). The “other” size class represents 22,178 operators in the

1997 frame (22,678 active operators minus the 500 largest operators).

Source: Energy Information Administration, Office of Oil and Gas.
Energy Information Administration

54 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Class 1–10 1,458 1,346 1,310 1,270 1,220 1,047 -173 -411 104.700

Percent of Total 59.6% 57.5% 57.8% 57.4% 56.1% 49.0% -14.2% -28.2%

Class 11–20 231 236 224 221 185 262 77 31 26.200

Percent of Total 9.4% 10.1% 9.9% 10.0% 8.5% 12.3% 41.6% 13.4%

Class 21–100 272 276 287 276 307 373 66 101 4.663

Percent of Total 11.1% 11.8% 12.7% 12.5% 14.1% 17.4% 21.5% 37.1%

Class 101–500 213 202 200 214 213 237 24 24 0.593

Percent of Total 8.7% 8.6% 8.8% 9.7% 9.8% 11.1% 11.3% 11.3%

Class Other (22,178) 272 279 247 232 248 219 -29 -53 0.010

Percent of Total 11.1% 11.9% 10.9% 10.5% 11.4% 10.2% -11.7% -19.5%

Category I (169) 2,022 1,922 1,879 1,844 1,791 1,760 -31 -262 10.414

Percent of Total 82.7% 82.2% 82.8% 83.3% 82.4% 82.3% -1.7% -13.0%

Category II (418) 163 153 150 139 143 157 14 –6 0.376

Percent of Total 6.7% 6.5% 6.6% 6.3% 6.6% 7.3% 9.8% -3.7%

Category III (22,037) 261 264 239 230 239 221 -18 -40 0.010

Percent of Total 10.7% 11.3% 10.5% 10.4% 11.0% 10.3% -7.5% -15.3%

Total Published 2,446 2,339 2,268 2,213 2,173 2,138 -35 -308 0.094

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -1.6% -12.6%

Table A4. Crude Oil Production by Operator Production Size Class, 1992–1997

(Million Barrels of 42 U.S. Gallons)

1996–1997 1992–1997 1997

Volume and Volume and Average

Percent Percent Production

Size Class 1992 1993 1994 1995 1996 1997 Change Change per Operator

Note: There were 22,037 active Category III operators in the 1997 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 2,494 Category III operators (Table E2). The “other” size class represents 22,178 operators in the

1997 frame (22,678 active operators minus the 500 largest operators).

Source: Energy Information Administration, Office of Oil and Gas.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 55

Class 1–10 4,189 3,591 3,258 3,113 2,800 2,566 -234 -1,623 257

Percent of Total 14.7% 13.2% 12.2% 11.9% 10.7% 10.4% -8.4% -38.7%

Class 11–20 3,432 2,998 2,795 2,772 2,441 2,257 -184 -1,175 226

Percent of Total 12.1% 11.1% 10.5% 10.6% 9.3% 9.1% -7.5% -34.2%

Class 21–100 8,003 7,600 7,752 7,569 7,526 7,159 -367 -844 89

Percent of Total 28.2% 28.0% 29.1% 28.9% 28.7% 28.9% -4.9% -10.5%

Class 101–500 11,896 11,881 11,878 11,886 12,492 12,878 386 982 32

Percent of Total 41.9% 43.8% 44.6% 45.4% 47.7% 52.0% 3.1% 8.3%

Rest 2,059 1,715 1,897 1,601 a952 1,332 380 -727 15

Percent of Total 7.2% 6.3% 7.1% 6.1% a

3.6% 5.4% 39.9% -35.3%

Category I 17,620 16,603 16,161 16,256 15,635 15,232 -403 -2,388 90

Percent of Total 62.0% 61.2% 60.7% 62.1% 59.7% 58.2% -2.6% -13.6%

Category II 10,799 10,516 10,452 9,939 10,576 10,960 384 161 22

Percent of Total 38.0% 38.8% 39.3% 37.9% 40.3% 41.8% 3.6% 1.5%

Total Reported 28,419 27,119 26,613 26,195 26,211 26,192 -19 -2,227 39

Percent Change 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -0.1% -7.8%

aThe reduced 1996 survey had fewer operators and fields in the “rest” class.

Note: Includes only data from Category I and Category II operators. In 1997, there were 169 Category I operators and 418 Category II

operators. The “rest” size class had 87 operators in 1997.

Source: Energy Information Administration, Office of Oil and Gas.

Table A5. Operator Field Count by Operator Production Size Class, 1992–1997

1996–1997 1992–1997 1997 Average

Number and Number and Number of

Percent Percent Fields per

Size Class 1992 1993 1994 1995 1996 1997 Change Change Operator
Appendix B

Top 100 Oil and Gas Fields for 1997
Appendix B

Top 100 Oil and Gas Fields for 1997

This appendix presents estimates of the proved

reserves and production of the top 100 oil and gas

fields. The oil field production and reserve data include

both crude oil and lease condensate. The gas field

production and reserve data is total wet natural gas

(associated-dissolved plus nonassociated, wet after

lease separation).

The top 100 oil fields in the United States as of

December 31, 1997, had 14,940 million barrels of

proved reserves (Table B1) accounting for 63 percent of

the total United States (Table 6 and Table 16).

Although there is considerable grouping of field–level

statistics within the tables, rough orders of magnitude

can be estimated for the proved reserves and

production of most fields. Many fields in the top 100

groups are operated by only one or two operators,

therefore, the totals for proved reserves are grouped as

top 10, top 20, top 50, and top 100 to avoid revealing

company proprietary data. In the top 20 oil fields for

1997 there are three fields, Mississippi Canyon Blk 807

(Mars), Green Canyon Blk 244 (Troika), and

Mississippi Canyon Blk 854 (Ursa) in the deep water of

the Gulf of Mexico Federal Offshore. The top 100 oil

fields in the United States as of December 31, 1997, had

1,176 million barrels of production (Table B1) or 51

percent of the total (Table 6 and Table 16). Many of the

oil fields in the top 100 are very old, 47 oil fields were

discovered prior to 1946. The oldest, Coalinga in

California, was discovered in 1887. The fields with

newer discovery dates are located in the Gulf of Mexico

Offshore and Alaska.

The top 100 gas fields in the United States as of

December 31, 1997, had 80,698 billion cubic feet of

proved reserves (Table B2) or 46 percent of the total

(Table 9). The top 100 gas fields in the United States as

of December 31, 1997, had 6,563 billion cubic feet of

production (Table B2) or 33 percent of the total (Table

9). Fewer of the gas fields in the top 100 are very old.

There were 19 gas fields that were discovered prior to

1946. The oldest, Big Sandy in Kentucky, was

discovered in 1881. The fields with newer discovery

dates are located in the Gulf of Mexico Offshore, south

Texas and Virginia. Several of the same fields are in

both tables.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 59
Energy Information Administration

60 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table B1. Top 100 U.S. Fields Ranked by Oila Production within Proved Reserves Group, from Reported

1997 Field Level Datab

(Million Barrels of 42 U.S. Gallons)

Discovery Proved Reserves Reported Production

Field Name Location Year Rank Group Rank Group

Prudhoe Bay AK 1967 1-10 252.3

Kuparuk River AK 1969 1-10 96.1

Midway-Sunset CA 1901 1-10 61.6

Kern River CA 1899 1-10 48.8

Belridge South CA 1911 1-10 41.1

Mississippi Canyon Blk 807 GF 1989 1-10 31.9

Yates TX 1926 1-10 20.9

Elk Hills CA 1919 1-10 20.5

Milne Point AK 1982 1-10 19.0

Wasson TX 1937 1-10 15.0

Top 10 Volume Subtotal 8,001.3 607.1

Top 10 Percentage of U.S. Total 33.5% 26.3%

Point Mcintyre AK 1988 11-20 58.8

Spraberry Trend Area TX 1950 11-20 22.1

Endicott AK 1978 11-20 21.4

Wilmington CA 1932 11-20 19.5

Hondo PF 1969 11-20 16.3

Slaughter TX 1937 11-20 14.5

Levelland TX 1945 11-20 9.4

San Ardo CA 1947 11-20 4.2

Green Canyon Blk 244 GF 1994 11-20 1.1

Mississippi Canyon Blk 854 GF 1992 11-20 0.0

Top 20 Volume Subtotal 10,140.9 774.5

Top 20 Percentage of U.S. Total 42.5% 33.5%

Garden Banks Blk 426 GF 1987 21-50 28.2

Giddings TX 1960 21-50 20.7

East Texas TX 1930 21-50 17.1

Viosca Knoll Blk 990 GF 1981 21-50 16.4

Pescado PF 1970 21-50 15.0

Cymric CA 1916 21-50 14.0

Seminole TX 1936 21-50 11.9

Niakuk AK 1984 21-50 10.6

Lost Hills CA 1910 21-50 10.2

Coalinga CA 1887 21-50 9.6

Salt Creek TX 1942 21-50 9.4

Cowden North TX 1930 21-50 9.2

Bay Marchand Blk 2 GF & LA 1949 21-50 8.6

Vacuum NM 1929 21-50 8.0

Sho-Vel-Tum OK 1905 21-50 7.4

Rangely CO 1902 21-50 7.4

Mcelroy TX 1926 21-50 7.3

Fullerton TX 1942 21-50 7.0

Greater Aneth UT 1956 21-50 6.0

Ventura CA 1916 21-50 5.3

Goldsmith TX 1935 21-50 4.3

Robertson North TX 1956 21-50 3.6

Hawkins TX 1940 21-50 3.2

Howard-Glasscock TX 1925 21-50 2.9

Eunice Monument NM 1929 21-50 1.3

Viosca Knoll Blk 956 GF 1985 21-50 0.9

Wasson 72 TX 1940 21-50 0.0

East Breaks Blk 945 GF 1994 21-50 0.0

Green Canyon Blk 205 GF 1988 21-50 0.0

Mississippi Canyon Blk 935 GF 1994 21-50 0.0

Top 50 Volume Subtotal 12,989.7 1,019.9

Top 50 Percentage of U.S. Total 54.3% 44.1%
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 61

Ewing Bank Blk 873 GF 1991 51-100 12.1

Eugene Island Sa Blk 330 GF 1971 51-100 9.5

Ship Shoal Blk 169 GF 1961 51-100 7.2

Main Pass Sa Blk 299 GF 1967 51-100 6.6

West Delta Blk 30 GF 1949 51-100 6.5

South Pass Blk 61 GF 1955 51-100 6.5

Cedar Hills ND 1995 51-100 6.1

Jay FL & AL 1970 51-100 5.8

Wattenberg CO 1970 51-100 5.6

South Timbalier Blk 52 GF 1950 51-100 5.4

Viosca Knoll Blk 825 GF 1988 51-100 5.3

Oregon Basin WY 1912 51-100 4.4

Means TX 1934 51-100 4.2

Grayburg-Jackson NM 1929 51-100 4.0

Huntington Beach CA 1920 51-100 3.6

Painter Reservoir East WY 1979 51-100 3.5

Dollarhide TX & NM 1945 51-100 3.5

Ship Shoal Sa Blk 349 GF 1994 51-100 3.3

Beta PF 1976 51-100 3.2

T X L TX 1944 51-100 3.2

Monument NM & UT 1935 51-100 2.8

Bluebell UT 1949 51-100 2.7

Cedar Lake TX 1939 51-100 2.7

Dos Cuadras PF 1968 51-100 2.6

Stephens County Regular TX 1915 51-100 2.5

Jo-Mill TX 1953 51-100 2.5

Inglewood CA 1924 51-100 2.5

Mabee TX 1944 51-100 2.4

Elk Basin WY & MT 1915 51-100 2.3

Hamilton Dome WY 1918 51-100 2.2

Sand Hills TX 1930 51-100 2.1

Welch TX 1942 51-100 2.1

Hartzog Draw WY 1976 51-100 2.1

Pennel MT 1955 51-100 2.0

Postle OK 1958 51-100 1.8

Cowden South TX 1930 51-100 1.7

Kern Front CA 1925 51-100 1.7

Cottonwood Creek WY 1953 51-100 1.5

Beverly Hills CA 1900 51-100 1.4

Brea-Olinda CA 1897 51-100 1.4

Hobbs NM 1928 51-100 1.1

Justis NM 1957 51-100 1.0

Cote Blanche Bay West LA 1940 51-100 0.6

Crossett South TX 1956 51-100 0.5

Green Canyon Blk 254 GF 1994 51-100 0.0

Green Canyon Blk 158 GF 1992 51-100 0.0

Viosca Knoll Blk 915 GF 1993 51-100 0.0

Viosca Knoll Blk 786 GF 1996 51-100 0.0

Garden Banks Blk 260 GF 1995 51-100 0.0

Ewing Bank Blk 921 GF 1993 51-100 0.0

Top 100 Volume Subtotal 14,939.6 1,175.5

Top 100 Percentage of U.S. Total 62.5 % 50.8%

Table B1. Top 100 U.S. Fields Ranked by Oila Production within Proved Reserves Group, from Reported

1997 Field Level Datab (Continued)

(Million Barrels of 42 U.S. Gallons)

Discovery Proved Reserves Reported Production

Field Name Location Year Rank Group Rank Group

aIncludes lease condensate. bOnly 87 percent of the estimated reserves were surveyed by EIA at the field level from large and intermediate operators.

Notes: Fields are grouped in “proved reserves rank groups” and then listed within that group in descending order by annual production

rank. The U.S. total production estimate of 2,312 million barrels and the U.S. total reserves estimate of 23,887 million barrels, used to

calculate the percentages in this table, are from the combined totals of Table 6 and Table 16 in this publication. Column totals may not add

due to independent rounding.

Source: Energy Information Administration, Office of Oil and Gas.
Energy Information Administration

62 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table B2. Top 100 U.S. Fields Ranked by Gasa Production within Proved Reserves Group, from Reported

1997 Field Level Datab

(Billion Cubic Feet)

Discovery Proved Reserves Reported Production

Field Name Location Year Rank Group Rank Group

Basin NM 1947 1-10 787.2

Blanco NM & CO 1927 1-10 605.9

Hugoton Gas Area KS & OK & TX 1922 1-10 507.5

Carthage TX 1936 1-10 211.7

Prudhoe Bay AK 1967 1-10 207.8

Mobile Bay AL 1985 1-10 132.9

Panhandle West TX 1918 1-10 114.3

Madden WY 1968 1-10 41.1

Oakwood VA 1990 1-10 25.5

Big Piney-Labarge WY 1964 1-10 9.7

Top 10 Volume Subtotal 37,405.0 2,643.6

Top 10 Percentage of U.S. Total 21.3% 13.1%

Giddings TX 1960 1-20 383.2

Antrim MI 1965 1-20 122.8

Panoma Gas Area KS 1956 1-20 100.2

Wattenberg CO 1970 1-20 94.9

Spraberry Trend Area TX 1950 1-20 70.8

Red Oak-Norris OK 1910 1-20 66.5

Cook Inlet North AK 1962 1-20 52.0

Big Sandy KY 1881 1-20 49.0

Fogarty Creek WY 1975 1-20 32.5

Lake Ridge WY 1981 1-20 14.0

Top 20 Volume Subtotal 47,596.9 3,629.5

Top 20 Percentage of U.S. Total 27.1% 18.0%

Bob West TX 1990 21-50 106.6

Anschutz Ranch East UT & WY 1979 21-50 79.1

Strong City District OK 1966 21-50 73.4

Whitney Canyon-Carter Creek WY 1978 21-50 73.0

Mocane-Laverne Gas Area OK & KS & TX 1946 21-50 69.6

Watonga-Chickasha Trend OK 1948 21-50 67.8

Mcarthur River AK 1965 21-50 64.4

Gomez TX 1963 21-50 64.3

Knox OK 1916 21-50 61.0

Wilburton OK 1941 21-50 58.6

Elk Hills CA 1919 21-50 56.5

Bruff WY 1974 21-50 53.9

Ozona TX 1953 21-50 53.7

Golden Trend OK 1945 21-50 52.4

Mobile Blk 823 GF 1983 21-50 52.0

Oak Hill TX 1958 21-50 48.7

Kinta OK 1914 21-50 46.4

Natural Buttes UT 1940 21-50 44.8

Sawyer TX 1960 21-50 43.1

Nora VA 1949 21-50 38.8

Lower Mobile Bay-Mary Ann AL 1979 21-50 36.3

Brady WY 1972 21-50 35.5

Beluga River AK 1962 21-50 34.8

Mobile Blk 864 GF 1983 21-50 31.4

Mississippi Canyon Blk 731 GF 1987 21-50 16.8

Judge Digby LA 1977 21-50 12.2

Viosca Knoll Blk 956 GF 1985 21-50 8.1

Wasson TX 1937 21-50 2.5

Mississippi Canyon Blk 854 GF 1992 21-50 0

East Breaks Blk 945 GF 1994 21-50 0

Top 50 Volume Subtotal 65,643.7 5,015.2

Top 50 Percentage of U.S. Total 37.4% 24.9%
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 63

Table B2. Top 100 U.S. Fields Ranked by Gasa Production within Proved Reserves Group, from Reported

1997 Field Level Datab (Continued)

(Billion Cubic Feet)

Discovery Proved Reserves Reported Production

Field Name Location Year Rank Group Rank Group

Garden Banks Blk 426 GF 1987 51-100 81.5

Matagorda Island Blk 623 GF 1980 51-100 78.3

Indian Basin NM 1963 51-100 71.7

Mcallen Ranch TX 1960 51-100 65.1

South Timbalier Blk 176 GF 1965 51-100 53.6

Jeffress Ne TX 1975 51-100 52.5

Double A Wells TX 1980 51-100 50.9

Waltman WY 1959 51-100 45.4

Sibley LA 1929 51-100 45.2

Elk City OK 1947 51-100 43.2

Port Hudson LA 1977 51-100 43.0

South Pass Sa Blk 89 GF 1969 51-100 42.4

Mississippi Canyon Blk 354 GF 1977 51-100 40.7

Viosca Knoll Blk 783 GF 1985 51-100 39.8

Boonsville TX 1945 51-100 39.0

Verden OK 1948 51-100 38.6

Lake Arthur South LA 1955 51-100 36.5

Fairway AL 1986 51-100 34.9

Moorewood Ne OK 1979 51-100 34.5

Mississippi Canyon Blk 807 GF 1989 51-100 33.7

Puckett TX 1952 51-100 33.5

Brown-Bassett TX 1953 51-100 33.2

Painter Reservoir East WY 1979 51-100 32.7

Big Piney WY 1964 51-100 32.2

Main Pass Blk 41 GF 1956 51-100 30.9

Mississippi Canyon Blk 194 GF 1975 51-100 29.0

Kuparuk River AK 1969 51-100 28.5

A W P TX 1987 51-100 25.6

Newark East TX 1981 51-100 25.0

Wamsutter WY 1958 51-100 23.3

Cedar Cove Coal Degas AL 1983 51-100 22.6

Tip Top WY 1928 51-100 22.1

Drunkards Wash UT 1989 51-100 21.3

Lost Hills CA 1910 51-100 21.2

Standard Draw WY 1979 51-100 20.5

Hondo PF 1969 51-100 20.4

Trawick TX 1949 51-100 19.8

Stratton TX 1937 51-100 19.0

Rulison CO 1958 51-100 16.2

Blanco South NM 1951 51-100 16.0

Belridge South CA 1911 51-100 15.3

Sarita East TX 1967 51-100 14.9

Kenai AK 1959 51-100 12.7

Grand Valley CO 1985 51-100 12.3

Sugg Ranch TX 1985 51-100 12.3

Endicott AK 1978 51-100 9.5

Cochranton PA 1980 51-100 5.6

Green Canyon Blk 244 GF 1994 51-100 1.4

Viosca Knoll Blk 915 GF 1993 51-100 0.0

Mississippi Canyon Blk 292 GF 1996 51-100 0.0

Top 100 Volume Subtotal 80,698.1 6,562.7

Top 100 Percentage of U.S. Total 45.9% 32.6%

aWet after lease separation. bOnly 87 percent of the estimated reserves were surveyed by EIA at the field level from large and intermediate operators.

– = Not Applicable.

Note: Fields are grouped in “proved reserves rank groups” and then listed within that group in descending order by annual production

rank. The U.S. total production estimate of 20,134 billion cubic feet and the U.S. total reserves estimate of 175,721 billion cubic feet, used to

calculate the percentages in this table, are from Table 9 in this publication. Column totals may not add due to independent rounding.

Source: Energy Information Administration, Office of Oil and Gas.
Appendix C

Conversion to the Metric System
Appendix C

Conversion to the Metric System

Public Law 100–418, the Omnibus Trade and

Competitiveness Act of 1988, states: “It is the

declared policy of the United States—

(1) to designate the metric system of measurement as

the preferred system of weights and measures for

United States trade and commerce. . . .

(2) to require that each Federal agency, by the end of

Fiscal Year 1992, use the metric system of

measurement in its procurements, grants, and other

business–related activities."{40}

Table C1 is in keeping with the spirit of this law.

The petroleum industry in the United States is slowly

moving in the direction prescribed by this law and

the data collected by EIA are collected in the units

that are still common to the U.S. petroleum industry,

namely barrels and cubic feet. Standard metric

conversion factors were used to convert the National

level volumes in Table 1 to the metric equivalents in

Table C1. Barrels were multiplied by 0.1589873 to

convert to cubic meters and cubic feet were

multiplied by 0.02831685 to convert to cubic meters.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 67
Energy Information Administration

68 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table C1. U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids,

in Metric Units, 1987 – 1997

Revisionsa New Reservoir Provedc Change Revision Revision and New Field Discoveries Totalb Reserves from

Adjustments Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

Crude Oil (million cubic meters)

1987 37.2 586.2 218.0 405.4 76.9 15.3 17.6 109.8 456.8 4,333.4 58.4

1988 57.8 426.7 194.1 290.4 56.4 11.3 20.2 87.9 446.9 4,264.8 –68.6

1989 33.9 428.9 217.0 245.8 81.7 17.8 14.3 113.8 411.1 4,213.3 –51.5

1990 13.7 394.8 159.0 249.5 72.5 15.6 21.5 109.6 398.3 4,174.1 –39.2

1991 25.9 333.4 297.9 61.4 58.0 15.4 14.6 88.0 399.4 3,924.1 –250.0

1992 46.2 286.8 170.0 163.0 62.2 1.3 13.5 77.0 388.9 3,775.2 –148.9

1993 43.1 319.7 241.0 121.8 56.6 50.7 17.5 124.8 371.9 3,649.9 –125.3

1994 30.1 375.8 215.7 190.2 63.1 10.2 17.6 90.9 360.6 3,570.4 –79.5

1995 19.4 289.8 126.4 182.8 79.5 18.1 54.5 152.1 351.8 3,553.5 –16.9

1996 28.0 273.9 156.8 145.1 86.3 38.6 22.4 147.3 345.5 3,500.4 –53.1

1997 82.7 317.7 172.3 228.0 75.8 101.3 18.9 196.0 339.9 3,584.2 83.8

Dry Natural Gas (billion cubic meters)

1987 35.91 496.31 402.98 129.24 129.89 30.84 42.45 203.18 456.30 5,301.23 –123.88

1988 62.09 661.68 d1,088.13 –364.36 192.64 46.38 54.06 293.08 472.04 d4,757.91 –543.32

1989 85.33 755.30 669.50 171.13 179.50 41.06 63.51 284.07 480.91 4,732.20 –25.71

1990 44.08 537.48 380.66 200.90 225.18 56.75 68.30 350.23 487.98 4,795.35 63.15

1991 83.82 563.22 438.17 208.87 144.13 24.01 45.42 213.56 487.11 4,730.67 –64.68

1992 63.29 511.26 338.73 235.82 132.38 18.38 48.82 199.58 493.36 4,672.71 –57.96

1993 27.51 498.29 346.82 178.98 172.82 25.46 52.84 251.12 503.73 4,599.08 –73.63

1994 55.08 604.99 449.70 210.37 196.55 53.63 98.54 348.72 518.82 4,639.35 40.27

1995 16.42 579.50 360.50 235.42 193.77 47.18 69.43 310.38 508.74 4,676.41 37.06

1996 107.18 485.12 369.42 222.88 219.65 41.09 88.07 348.81 534.08 4,714.02 37.61

1997 –16.70 613.28 474.47 122.10 299.73 75.92 67.45 443.10 544.00 4,735.22 21.22

Natural Gas Liquids (million cubic meters)

1987 36.8 134.7 104.3 67.2 33.9 6.2 8.7 48.8 118.8 1,295.3 –2.8

1988 1.8 185.7 113.7 73.8 42.6 6.5 11.4 60.5 119.9 1,309.7 14.4

1989 –44.0 181.7 162.2 –24.5 41.2 13.2 11.8 66.2 116.2 1,235.2 –74.5

1990 –13.2 131.5 96.3 22.0 47.5 6.2 11.6 65.3 116.4 1,206.1 –29.1

1991 37.1 131.2 110.5 57.8 30.0 4.0 8.7 42.7 119.9 1,186.7 –19.4

1992 35.7 128.1 86.6 77.2 30.2 3.2 10.2 43.6 122.9 1,184.6 –2.1

1993 16.2 121.5 101.8 35.9 39.0 3.8 10.2 53.0 125.3 1,148.2 –36.4

1994 6.9 138.8 107.5 38.2 49.9 8.6 20.8 79.3 125.8 1,139.9 –8.3

1995 30.5 153.9 109.9 74.5 68.7 8.3 10.7 87.7 125.8 1,176.3 36.4

1996 75.5 134.2 106.4 103.3 71.7 10.3 17.3 99.3 135.1 1,243.8 67.5

1997 –2.4 190.6 144.7 43.6 85.1 18.1 14.3 117.5 137.4 1,267.6 23.8

aRevisions and adjustments = Col. 1 + Col. 2 – Col. 3.

bTotal discoveries = Col. 5 + Col. 6 + Col. 7.

cProved reserves = Col. 10 from prior year + Col. 4 + Col. 8 – Col. 9.

dAn unusually large revision decrease to North Slope dry natural gas reserves was made in 1988. It recognizes some 696.59 billion

cubic meters of downward revisions reported during prior years by operators because of economic and market conditions. EIA in previous

years carried these reserves in the proved category.

Notes: Old means discovered in a prior year. New means discovered during the report year. The production estimates in this table are

based on data reported on Form EIA–23, “Annual Survey of Domestic Oil and Gas Reserves” and Form EIA–64A, “Annual Report of the

Origin of Natural Gas Liquids Production.” The following conversion factors were used to convert data in Columns 2, 3, 5, 6, 7, 9, and 10:

barrels = 0.1589873 per cublic meter, cubic feet = 0.02831685 per cublc meter. Number of decimal digits varies in order to accurately

reproduce corresponding equivalents shown on Table 1 in Chapter 2.

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1987–1997 annual reports, DOE/EIA–0216.{10–20}
Appendix D

Historical Reserves Statistics
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 71

Appendix D

Historical Reserves Statistics

These are selected historical data presented at the State and National level. All historical statistics included have

previously been published in the annual reports of 1977 through 1997 of the EIA publication U.S. Crude Oil, Natural

Gas, and Natural Gas Liquids Reserves, DOE EIA-0216.{1-20}

Liquid volumes are in million barrels of 42 U.S. gallons. Gas volumes are in billion cubic feet (Bcf), at 14.73 psia and

60° Fahrenheit. NA appears in this appendix wherever data are not available or are withheld to avoid disclosure of

data which may be proprietary. An asterisk (*) marks those estimates associated with sampling errors (95 percent

confidence interval) greater than 20 percent of the value estimated.

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Alabama

1977 85 0 530 NA

1978 *74 0 514 NA

1979 45 NA 652 213

1980 54 NA 636 226

1981 55 NA 648 192

1982 54 NA a648 193

1983 51 NA a785 216

1984 *68 NA a961 200

1985 69 NA a821 182

1986 55 20 b951 177

1987 55 20 b842 166

1988 54 20 b809 166

1989 43 20 b819 168

1990 44 <1 c4,125 170

1991 43 <1 c5,414 145

1992 41 0 c5,802 171

1993 41 0 c5,140 158

1994 44 0 c4,830 142

1995 43 0 c4,868 120

1996 45 0 c5,033 119

1997 47 0 c4,968 93

aOnshore only; offshore included in Louisiana. bOnshore only; offshore included in Federal Offshore - Gulf of

Mexico (Louisiana). cIncludes State Offshore: 2,519 Bcf in 1990; 3,191 Bcf in 1991;

3,233 Bcf in 1992; 3,364 Bcf in 1993; 3,297 Bcf in 1994; 3,432 Bcf

in 1995; 3,509 Bcf in 1996; 3,422 Bcf in 1997.

Alaska

1977 8,413 846 32,243 NA

1978 9,384 398 32,045 NA

1979 8,875 398 32,259 23

1980 8,751 0 33,382 11

1981 8,283 0 33,037 10

1982 7,406 60 34,990 9

1983 7,307 576 34,283 8

1984 7,563 369 34,476 19

1985 7,056 379 33,847 383

1986 6,875 902 32,664 381

1987 7,378 566 33,225 418

1988 6,959 431 9,078 401

1989 6,674 750 8,939 380

1990 6,524 969 9,300 340

1991 6,083 1,456 9,553 360

1992 6,022 1,331 9,638 347

1993 5,775 1,161 9,907 321

1994 5,767 1,022 9,733 301

1995 5,580 582 9,497 306

1996 5,274 952 9,294 337

1997 5,161 832 10,562 631

Note: See 1988 Chapter 4 discussion “Alaskan North Slope

Natural Gas Reserves”.

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves
Energy Information Administration

72 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Arkansas

1977 116 17 1,660 NA

1978 111 8 1,681 NA

1979 107 8 1,703 17

1980 107 11 1,774 16

1981 113 11 1,801 16

1982 107 4 1,958 15

1983 120 4 2,069 11

1984 114 6 2,227 12

1985 97 11 2,019 11

1986 88 9 1,992 16

1987 82 0 1,997 16

1988 77 <1 1,986 13

1989 66 1 1,772 9

1990 60 1 1,731 9

1991 *70 0 1,669 5

1992 58 <1 1,750 4

1993 65 0 1,552 4

1994 51 0 1,607 6

1995 48 0 1,563 6

1996 58 0 1,470 4

1997 45 0 1,475 7

California - Total

1977 5,005 1,047 4,737 NA

1978 4,974 968 4,947 NA

1979 5,265 960 5,022 111

1980 5,470 891 5,414 120

1981 5,441 660 5,617 82

1982 5,405 616 5,552 154

1983 5,348 576 5,781 151

1984 5,707 674 5,554 141

1985 d4,810 590 d4,325 d146

1986 d4,734 d616 d3,928 d134

1987 d4,709 d1,493 d3,740 d130

1988 d4,879 d1,440 d3,519 d123

1989 d4,816 d1,608 d3,374 d113

1990 d4,658 d1,425 d3,185 d105

1991 d4,217 d1,471 d3,004 d92

1992 d3,893 d1,299 d2,778 d99

1993 d3,764 d965 d2,682 d104

1994 d3,573 d835 d2,402 d92

1995 d3,462 d823 d2,243 d92

1996 d3,437 d905 d2,082 d92

1997 d3,750 d1,264 d2,273 d95

dExcludes Federal offshore; now included in Federal OffshorePacific (California).

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

California - Coastal Region Onshore

1977 679 NA 334 NA

1978 602 NA 350 NA

1979 578 NA 365 22

1980 652 NA 299 23

1981 621 NA 306 14

1982 580 NA 362 16

1983 559 NA 381 17

1984 628 140 265 15

1985 631 152 256 16

1986 592 164 255 15

1987 625 298 238 13

1988 576 299 215 13

1989 731 361 224 11

1990 588 310 217 12

1991 554 327 216 12

1992 522 317 203 10

1993 528 313 189 12

1994 480 238 194 11

1995 456 234 153 8

1996 425 261 156 9

1997 430 43 164 9

California - Los Angeles Basin Onshore

1977 910 NA 255 NA

1978 493 NA 178 NA

1979 513 NA 163 10

1980 454 NA 193 15

1981 412 NA 154 6

1982 370 NA 96 6

1983 343 NA 107 6

1984 373 126 156 5

1985 420 86 181 6

1986 330 66 142 8

1987 361 105 148 8

1988 391 106 151 7

1989 342 32 137 4

1990 316 3 106 5

1991 272 4 115 4

1992 236 4 97 5

1993 238 4 102 6

1994 221 4 103 5

1995 227 4 111 4

1996 234 0 109 3

1997 268 0 141 4
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 73

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

California - San Joaquin Basin Onshore

1977 2,965 NA 3,784 NA

1978 3,099 NA 3,960 NA

1979 3,294 NA 3,941 77

1980 3,360 NA 4,344 81

1981 3,225 NA 4,163 57

1982 3,081 NA 3,901 124

1983 3,032 NA 3,819 117

1984 3,197 384 3,685 105

1985 3,258 350 3,574 120

1986 3,270 368 3,277 109

1987 3,208 1,070 3,102 107

1988 3,439 1,029 2,912 101

1989 3,301 1,210 2,782 95

1990 3,334 1,109 2,670 86

1991 3,126 1,139 2,614 75

1992 2,898 977 2,415 83

1993 2,772 648 2,327 85

1994 2,647 593 2,044 75

1995 2,577 585 1,920 80

1996 2,597 644 1,768 80

1997 2,871 1,221 1,912 82

California-State and Federal Offshore

1977 451 NA 364 NA

1978 780 NA 457 NA

1979 880 NA 553 2

1980 1,004 NA 578 1

1981 1,183 NA 994 5

1982 1,374 NA 1,193 8

1983 1,414 NA 1,474 11

1984 1,509 25 1,448 16

1985 1,492 2 1,433 16

1986 1,516 19 1,579 17

1987 1,552 20 1,704 19

1988 1,497 6 1,793 23

1989 1,429 5 1,727 28

1990 1,382 3 1,646 20

1991 1,050 1 1,221 19

1992 971 1 1,181 21

1993 899 0 1,163 26

1994 878 0 1,231 22

1995 773 0 1,324 25

1996 699 0 1,293 23

1997 709 0 600 14

California - State Offshore

1977 181 NA 114 NA

1978 519 NA 213 NA

1979 632 NA 231 2

1980 604 NA 164 1

1981 NA NA NA NA

1982 NA NA NA NA

1983 NA NA NA NA

1984 NA 25 NA NA

1985 501 0 314 4

1986 542 18 254 2

1987 515 18 252 2

1988 473 6 241 2

1989 442 5 231 3

1990 420 3 192 2

1991 265 1 59 1

1992 237 1 63 1

1993 226 0 64 1

1994 225 0 61 1

1995 202 0 59 0

1996 181 0 49 0

1997 181 0 56 0

California - Federal Offshore

1977 270 NA 250 NA

1978 261 NA 246 NA

1979 248 NA 322 0

1980 400 NA 414 0

1981 NA NA NA NA

1982 NA NA NA NA

1983 NA NA NA NA

1984 NA 0 NA NA

1985 991 2 1,119 12

1986 974 1 1,325 15

1987 1,037 2 1,452 17

1988 1,024 0 1,552 21

1989 987 0 1,496 25

1990 962 0 1,454 18

1991 785 0 1,162 18

1992 734 <1 1,118 20

1993 673 0 1,099 25

1994 653 0 1,170 21

1995 571 0 1,265 25

1996 518 0 1,244 23

1997 528 0 544 14
Energy Information Administration

74 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Colorado

1977 230 73 2,512 NA

1978 194 75 2,765 NA

1979 159 43 2,608 177

1980 *183 46 2,922 194

1981 147 47 2,961 204

1982 169 100 3,314 186

1983 186 113 3,148 183

1984 198 119 *2,943 155

1985 198 119 2,881 173

1986 207 95 3,027 148

1987 272 67 2,942 166

1988 257 67 3,535 181

1989 359 8 4,274 209

1990 305 8 4,555 169

1991 329 33 5,767 197

1992 304 34 6,198 226

1993 284 22 6,722 214

1994 271 22 6,753 248

1995 252 24 7,256 273

1996 231 22 7,710 287

1997 198 22 6,828 264

Florida

1977 213 1 151 NA

1978 168 1 119 NA

1979 128 1 77 21

1980 134 1 84 27

1981 109 1 69 NA

1982 97 1 64 17

1983 78 4 49 11

1984 82 2 65 17

1985 77 2 55 17

1986 67 2 49 14

1987 61 0 49 9

1988 59 0 51 16

1989 50 0 46 10

1990 42 0 45 8

1991 37 0 38 7

1992 36 0 47 8

1993 40 0 50 9

1994 71 0 98 18

1995 71 0 92 17

1996 97 0 96 22

1997 91 0 96 17

Illinois

1977 *150 1 NA NA

1978 *158 1 NA NA

1979 *136 1 NA NA

1980 113 2 NA NA

1981 129 1 NA NA

1982 150 1 NA NA

1983 135 1 NA NA

1984 153 1 NA NA

1985 136 1 NA NA

1986 135 1 NA NA

1987 153 5 NA NA

1988 143 <1 NA NA

1989 123 <1 NA NA

1990 131 0 NA NA

1991 128 52 NA NA

1992 138 0 NA NA

1993 116 0 NA NA

1994 117 0 NA NA

1995 119 0 NA NA

1996 94 0 NA NA

1997 92 0 NA NA

Indiana

1977 *20 0 NA NA

1978 *29 0 NA NA

1979 *40 0 NA NA

1980 23 0 NA NA

1981 23 0 NA NA

1982 28 1 NA NA

1983 34 3 NA NA

1984 *33 2 NA NA

1985 *35 2 NA NA

1986 *32 2 NA NA

1987 23 2 NA NA

1988 *22 0 NA NA

1989 *16 0 NA NA

1990 12 0 NA NA

1991 *16 0 NA NA

1992 17 0 NA NA

1993 15 0 NA NA

1994 15 0 NA NA

1995 13 0 NA NA

1996 11 0 NA NA

1997 *10 0 NA NA
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 75

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Kansas

1977 *349 3 11,457 NA

1978 303 3 10,992 NA

1979 *377 3 10,243 402

1980 310 2 9,508 389

1981 371 2 9,860 409

1982 378 13 9,724 302

1983 344 13 9,553 443

1984 377 2 9,387 424

1985 423 <1 9,337 373

1986 312 <1 10,509 440

1987 357 <1 10,494 462

1988 327 <1 10,104 345

1989 338 3 10,091 329

1990 321 <1 9,614 313

1991 300 <1 9,358 428

1992 310 0 9,681 444

1993 271 0 9,348 380

1994 260 0 9,156 398

1995 275 <1 8,571 369

1996 266 <1 7,694 338

1997 238 0 6,989 271

Kentucky

1977 30 0 451 NA

1978 *40 0 545 NA

1979 25 0 468 26

1980 *35 12 508 25

1981 29 13 530 25

1982 *36 13 551 35

1983 35 12 554 31

1984 *41 0 613 24

1985 *42 0 766 27

1986 *31 0 841 29

1987 25 0 909 23

1988 *34 0 923 24

1989 33 0 992 16

1990 33 0 1,016 25

1991 *31 0 1,155 24

1992 34 0 1,084 32

1993 26 0 1,003 26

1994 26 0 969 39

1995 24 0 1,044 43

1996 21 0 983 46

1997 *20 0 1,364 48

Louisiana - Total

1977 3,600 139 57,010 NA

1978 3,448 143 55,725 NA

1979 2,780 76 50,042 1,424

1980 2,751 62 47,325 1,346

1981 2,985 50 47,377 1,327

1982 2,728 49 e44,916 1,295

1983 2,707 45 e42,561 1,332

1984 2,661 55 e41,399 1,188

1985 f883 35 f14,038 f546

1986 f826 f47 f12,930 f524

1987 f807 f56 f12,430 f525

1988 f800 f69 f12,224 f517

1989 f745 f63 f12,516 f522

1990 f705 f22 f11,728 f538

1991 f679 f44 f10,912 f526

1992 f668 f35 f9,780 f495

1993 f639 f338 f9,174 f421

1994 f649 f340 f9,748 f434

1995 f637 f475 f9,274 f601

1996 f658 f331 f9,543 f543

1997 f714 f313 f9,673 f437

eIncludes State and Federal offshore Alabama. f

Excludes Federal offshore; now included in Federal OffshoreGulf of Mexico (Louisiana).

Louisiana - North

1977 244 78 3,135 NA

1978 255 78 3,203 NA

1979 216 NA 2,798 96

1980 248 NA 3,076 95

1981 *317 NA 3,270 99

1982 *240 NA 2,912 85

1983 223 NA 2,939 74

1984 165 9 2,494 57

1985 196 5 2,587 65

1986 160 7 2,515 57

1987 175 3 2,306 50

1988 154 23 2,398 56

1989 123 22 2,652 60

1990 120 <1 2,588 58

1991 127 <1 2,384 59

1992 125 <1 2,311 60

1993 108 0 2,325 57

1994 108 0 2,537 69

1995 108 0 2,788 79

1996 128 0 3,105 85

1997 136 <1 3,093 80
Energy Information Administration

76 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Louisiana - South Onshore

1977 1,382 46 18,580 NA

1978 1,242 38 17,755 NA

1979 682 NA 13,994 676

1980 682 NA 13,026 540

1981 642 NA 12,645 544

1982 611 NA 11,801 501

1983 569 NA 11,142 527

1984 585 20 10,331 454

1985 565 16 9,808 442

1986 547 30 9,103 428

1987 505 22 8,693 429

1988 511 35 8,654 421

1989 479 30 8,645 411

1990 435 11 8,171 431

1991 408 33 7,504 417

1992 417 26 6,693 380

1993 382 329 5,932 334

1994 391 331 6,251 337

1995 387 324 5,648 495

1996 382 322 5,704 411

1997 427 309 5,855 333

Louisiana - State Offshore

1977 1,974 15 35,295 NA

1978 1,951 27 34,767 NA

1979 1,882 14 33,250 652

1980 1,821 13 31,223 711

1981 2,026 16 31,462 684

1982 1,877 21 e30,203 709

1983 1,915 15 e28,480 731

1984 1,911 27 e28,574 677

1985 f122 2 f1,643 f39

1986 f119 f10 f1,312 f39

1987 f127 f22 f1,431 f46

1988 f135 f11 f1,172 f40

1989 f143 f11 f1,219 f51

1990 f150 f11 f969 f49

1991 f144 f11 f1,024 f50

1992 f126 f9 f776 f55

1993 f149 f9 f917 f30

1994 f150 f9 f960 f28

1995 f142 f151 f838 f27

1996 f148 f9 f734 f47

1997 f151 f4 f725 f24

eIncludes State and Federal offshore Alabama. f

Excludes Federal offshore; now included in Federal OffshoreGulf of Mexico (Louisiana).

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Michigan

1977 *233 0 *1,386 NA

1978 *220 9 *1,422 NA

1979 159 23 1,204 112

1980 *205 14 *1,406 112

1981 *240 17 1,118 102

1982 184 34 1,084 97

1983 209 48 1,219 105

1984 180 46 1,112 84

1985 191 37 985 67

1986 146 34 1,139 88

1987 151 27 1,451 111

1988 132 27 1,323 99

1989 128 8 1,342 97

1990 124 3 1,243 81

1991 119 0 1,334 72

1992 102 0 1,223 68

1993 90 0 1,160 57

1994 91 1 1,323 54

1995 76 1 1,294 45

1996 74 0 2,061 53

1997 68 2 2,195 50

Mississippi

1977 241 9 1,437 NA

1978 *250 27 1,635 NA

1979 238 24 1,504 16

1980 202 36 1,769 20

1981 209 93 2,035 18

1982 223 85 1,796 18

1983 205 77 1,596 19

1984 201 50 1,491 15

1985 184 53 1,360 12

1986 199 16 1,300 11

1987 202 12 1,220 11

1988 221 10 1,143 12

1989 218 6 1,104 12

1990 227 8 1,126 11

1991 194 8 1,057 10

1992 165 7 869 9

1993 133 44 797 11

1994 151 40 650 9

1995 140 6 663 8

1996 164 6 631 7

1997 183 0 582 6
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 77

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Montana

1977 175 27 *887 NA

1978 158 27 926 NA

1979 152 38 825 10

1980 179 13 *1,287 16

1981 186 11 *1,321 11

1982 216 6 847 18

1983 234 8 896 19

1984 224 4 802 18

1985 232 3 857 21

1986 248 27 803 16

1987 246 <1 780 16

1988 241 0 819 11

1989 225 <1 867 16

1990 221 0 899 15

1991 201 0 831 14

1992 193 0 859 12

1993 171 0 673 8

1994 175 0 717 8

1995 178 0 782 8

1996 168 0 796 7

1997 159 1 762 5

Nebraska

1977 22 0 NA NA

1978 30 1 NA NA

1979 25 0 NA NA

1980 *46 0 NA NA

1981 41 0 NA NA

1982 *32 0 NA NA

1983 44 0 NA NA

1984 *46 0 NA NA

1985 42 0 NA NA

1986 *45 7 NA NA

1987 33 0 NA NA

1988 42 0 NA NA

1989 32 0 NA NA

1990 26 0 NA NA

1991 26 0 NA NA

1992 26 0 NA NA

1993 20 0 NA NA

1994 22 0 NA NA

1995 25 0 NA NA

1996 28 0 NA NA

1997 *21 0 NA NA

New Mexico - Total

1977 605 97 12,000 NA

1978 579 90 12,688 NA

1979 563 77 13,724 530

1980 547 58 13,287 541

1981 555 93 13,870 560

1982 563 76 12,418 531

1983 576 75 11,676 551

1984 660 87 11,364 511

1985 688 99 10,900 445

1986 644 225 11,808 577

1987 654 235 11,620 771

1988 661 241 17,166 1,023

1989 665 256 15,434 933

1990 687 256 17,260 990

1991 721 275 18,539 908

1992 757 293 18,998 1,066

1993 707 211 18,619 996

1994 718 215 17,228 1,011

1995 732 185 17,491 943

1996 744 148 16,485 1,059

1997 735 146 15,514 869

New Mexico - East

1977 576 95 3,848 NA

1978 554 88 3,889 NA

1979 542 77 4,031 209

1980 518 58 3,530 209

1981 522 93 3,598 214

1982 537 76 3,432 209

1983 542 75 3,230 232

1984 625 87 3,197 221

1985 643 98 3,034 209

1986 593 225 2,694 217

1987 608 230 2,881 192

1988 621 235 2,945 208

1989 619 252 3,075 196

1990 633 253 3,256 222

1991 694 275 3,206 205

1992 731 293 3,130 223

1993 688 211 3,034 233

1994 702 215 3,021 234

1995 713 185 2,867 247

1996 731 148 2,790 299

1997 719 146 2,642 273
Energy Information Administration

78 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

New Mexico - West

1977 *29 2 8,152 NA

1978 *25 2 8,799 NA

1979 21 0 9,693 321

1980 *29 0 9,757 332

1981 *33 0 10,272 346

1982 26 0 8,986 322

1983 34 0 8,446 319

1984 35 0 8,167 290

1985 45 1 7,866 236

1986 51 0 9,114 360

1987 46 5 8,739 579

1988 40 6 14,221 815

1989 46 4 12,359 737

1990 54 3 14,004 768

1991 27 0 15,333 703

1992 26 0 15,868 843

1993 19 0 15,585 763

1994 16 0 14,207 777

1995 19 0 14,624 696

1996 13 0 13,695 760

1997 16 0 12,872 596

New York

1977 NA NA 165 NA

1978 NA NA 193 NA

1979 NA NA 211 0

1980 NA NA 208 0

1981 NA NA *264 0

1982 NA NA 229 NA

1983 NA NA 295 NA

1984 NA NA 389 NA

1985 NA NA *369 NA

1986 NA NA *457 NA

1987 NA NA 410 NA

1988 NA NA 351 NA

1989 NA NA 368 NA

1990 NA NA 354 NA

1991 NA NA 331 NA

1992 NA NA 329 NA

1993 NA NA *264 NA

1994 NA NA 242 NA

1995 NA NA 197 NA

1996 NA NA 232 NA

1997 NA NA *224 NA

North Dakota

1977 155 10 361 NA

1978 162 4 374 NA

1979 211 6 439 47

1980 214 6 537 61

1981 223 8 581 68

1982 237 8 629 71

1983 258 53 600 69

1984 260 54 566 73

1985 255 34 569 74

1986 218 35 541 69

1987 215 33 508 67

1988 216 39 541 52

1989 246 31 561 59

1990 285 0 586 60

1991 232 4 472 56

1992 237 3 496 64

1993 226 7 525 55

1994 226 2 507 55

1995 233 6 463 53

1996 248 6 462 48

1997 279 6 479 47

Ohio

1977 *74 0 495 NA

1978 69 0 684 NA

1979 *82 0 *1,479 0

1980 *116 0 *1,699 0

1981 *112 0 965 0

1982 111 0 1,141 NA

1983 130 0 2,030 NA

1984 *116 0 1,541 NA

1985 79 0 1,331 NA

1986 72 0 1,420 NA

1987 66 0 1,069 NA

1988 64 0 1,229 NA

1989 56 0 1,275 NA

1990 65 0 1,214 NA

1991 66 0 1,181 NA

1992 58 0 1,161 NA

1993 54 0 1,104 NA

1994 58 0 1,094 NA

1995 53 0 1,054 NA

1996 53 0 1,113 NA

1997 *43 0 985 NA
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 79

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Oklahoma

1977 1,109 69 13,889 NA

1978 979 33 14,417 NA

1979 1,014 35 13,816 583

1980 930 27 13,138 604

1981 950 43 14,699 631

1982 971 25 16,207 745

1983 931 27 16,211 829

1984 940 40 16,126 769

1985 935 37 16,040 826

1986 874 35 16,685 857

1987 788 56 16,711 781

1988 796 79 16,495 765

1989 789 63 15,916 654

1990 734 37 16,151 657

1991 700 54 14,725 628

1992 698 54 13,926 629

1993 680 40 13,289 643

1994 689 47 13,487 652

1995 676 48 13,438 674

1996 632 43 13,074 684

1997 605 20 13,439 685

Pennsylvania

1977 *57 0 769 NA

1978 27 0 899 NA

1979 33 0 *1,515 1

1980 35 0 951 0

1981 32 0 *1,264 0

1982 37 0 1,429 NA

1983 41 0 1,882 NA

1984 *40 0 1,575 NA

1985 *38 0 *1,617 NA

1986 *26 0 *1,560 1

1987 26 0 1,647 NA

1988 *27 0 2,072 NA

1989 26 0 1,642 NA

1990 22 0 1,720 NA

1991 15 0 1,629 NA

1992 16 0 1,528 NA

1993 14 0 1,717 NA

1994 15 0 1,800 NA

1995 11 0 1,482 NA

1996 10 0 1,696 NA

1997 17 0 1,852 NA

Texas - Total

1977 9,751 637 56,422 NA

1978 8,911 533 55,583 NA

1979 8,284 471 53,021 2,482

1980 8,206 384 50,287 2,452

1981 8,093 459 50,469 2,646

1982 7,616 377 49,757 2,771

1983 7,539 421 50,052 3,038

1984 7,557 735 49,883 3,048

1985 g7,782 609 g41,775 g2,981

1986 g7,152 1,270 g40,574 g2,964

1987 g7,112 1,028 g38,711 g2,822

1988 g7,043 1,099 g38,167 g2,617

1989 g6,966 805 g38,381 g2,563

1990 g7,106 618 g38,192 g2,575

1991 g6,797 756 g36,174 g2,493

1992 g6,441 g612 g35,093 g2,402

1993 g6,171 g581 g34,718 g2,469

1994 g5,847 g491 g35,974 g2,414

1995 g5,743 g395 g36,542 g2,524

1996 g5,736 g358 g38,270 g2,606

1997 g5,687 g479 g37,761 g2,687

gExcludes Federal offshore; now included in Federal OffshoreGulf of Mexico (Texas).

Texas - RRC District 1

1977 *174 0 1,319 NA

1978 111 2 986 NA

1979 110 0 919 23

1980 *150 0 829 24

1981 127 5 *1,022 26

1982 129 6 892 29

1983 165 6 1,087 43

1984 173 4 838 39

1985 177 8 967 40

1986 144 1 913 35

1987 143 1 812 27

1988 136 1 1,173 30

1989 139 1 1,267 25

1990 252 0 1,048 26

1991 227 0 1,030 28

1992 185 0 933 27

1993 133 0 698 26

1994 100 1 703 26

1995 90 6 712 26

1996 86 1 906 46

1997 83 <1 953 54
Energy Information Administration

80 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Texas - RRC District 2 Onshore

1977 395 80 3,162 NA

1978 334 1 2,976 NA

1979 292 1 2,974 64

1980 252 1 2,502 64

1981 229 1 2,629 88

1982 206 0 2,493 75

1983 192 0 2,534 99

1984 192 <1 2,512 103

1985 168 0 2,358 100

1986 148 <1 2,180 89

1987 137 0 2,273 102

1988 117 0 2,037 92

1989 107 0 1,770 72

1990 91 0 1,737 80

1991 90 0 1,393 75

1992 86 0 1,389 80

1993 77 0 1,321 86

1994 74 0 1,360 86

1995 61 0 1,251 93

1996 63 <1 1,322 93

1997 66 0 1,634 87

Texas - RRC District 3 Onshore

1977 937 33 7,518 NA

1978 794 22 7,186 NA

1979 630 32 6,315 231

1980 581 11 5,531 216

1981 552 11 5,292 230

1982 509 22 4,756 265

1983 517 27 4,680 285

1984 522 25 4,708 270

1985 471 6 4,180 260

1986 420 3 3,753 237

1987 386 4 3,632 241

1988 360 16 3,422 208

1989 307 11 3,233 213

1990 275 13 2,894 181

1991 300 28 2,885 208

1992 304 27 2,684 211

1993 327 31 2,972 253

1994 330 61 3,366 254

1995 267 27 3,866 272

1996 281 27 4,349 289

1997 259 28 4,172 286

Texas - RRC District 4 Onshore

1977 145 7 9,621 NA

1978 123 3 9,031 NA

1979 113 4 8,326 248

1980 96 3 8,130 252

1981 97 6 8,004 260

1982 87 7 8,410 289

1983 96 3 8,316 292

1984 99 3 8,525 295

1985 98 2 8,250 269

1986 87 2 8,274 281

1987 80 2 7,490 277

1988 65 1 7,029 260

1989 77 <1 7,111 260

1990 67 <1 7,475 279

1991 52 <1 7,048 273

1992 50 <1 6,739 272

1993 59 <1 7,038 278

1994 41 <1 7,547 290

1995 50 <1 7,709 287

1996 51 0 7,769 323

1997 70 <1 8,099 347

Texas - RRC District 5

1977 68 0 931 NA

1978 *68 0 *1,298 NA

1979 55 1 1,155 34

1980 52 0 1,147 44

1981 49 0 1,250 49

1982 45 0 1,308 53

1983 42 0 1,448 73

1984 36 <1 1,874 74

1985 *59 1 2,058 77

1986 *53 1 2,141 86

1987 54 0 2,119 88

1988 48 0 1,996 81

1989 46 0 1,845 80

1990 47 0 1,875 81

1991 46 0 1,863 71

1992 56 0 1,747 71

1993 52 0 1,867 64

1994 49 0 2,011 59

1995 34 0 1,862 54

1996 29 0 2,079 54

1997 54 0 1,710 35
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 81

Texas - RRC District 6

1977 1,568 12 3,214 NA

1978 1,444 3 3,240 NA

1979 1,177 6 3,258 272

1980 1,115 6 4,230 321

1981 1,040 7 4,177 308

1982 947 6 4,326 278

1983 918 5 4,857 342

1984 889 5 4,703 298

1985 851 4 4,822 293

1986 750 2 4,854 277

1987 733 3 4,682 264

1988 685 5 4,961 263

1989 631 4 5,614 266

1990 605 6 5,753 247

1991 504 7 5,233 243

1992 442 7 5,317 251

1993 406 <1 5,508 248

1994 424 <1 5,381 265

1995 409 1 5,726 271

1996 359 1 5,899 290

1997 348 1 5,887 260

Texas - RRC District 7B

1977 250 NA 699 NA

1978 190 NA 743 NA

1979 208 NA *751 64

1980 196 NA *745 85

1981 254 NA 804 102

1982 199 NA 805 105

1983 217 NA 1,027 133

1984 218 62 794 106

1985 239 63 708 104

1986 193 64 684 109

1987 200 46 697 92

1988 205 42 704 98

1989 204 11 459 73

1990 198 8 522 76

1991 184 8 423 82

1992 163 11 455 68

1993 *171 7 477 79

1994 145 5 425 62

1995 126 4 440 70

1996 136 4 520 65

1997 155 3 478 59

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Texas - RRC District 7C

1977 191 NA 2,831 NA

1978 202 NA 2,821 NA

1979 206 NA 2,842 182

1980 207 NA 2,378 135

1981 230 NA 2,503 186

1982 229 NA 2,659 199

1983 228 NA 2,568 219

1984 240 24 2,866 233

1985 243 21 2,914 256

1986 213 22 2,721 246

1987 220 25 2,708 243

1988 212 31 2,781 238

1989 247 16 3,180 238

1990 274 8 3,514 256

1991 253 9 3,291 241

1992 255 33 3,239 289

1993 199 15 3,215 273

1994 221 14 3,316 265

1995 204 8 3,107 274

1996 219 5 3,655 303

1997 227 4 3,407 327

Texas - RRC District 8

1977 2,915 127 11,728 NA

1978 2,795 102 11,093 NA

1979 2,686 88 10,077 505

1980 2,597 86 9,144 498

1981 2,503 105 8,546 537

1982 2,312 75 8,196 588

1983 2,350 99 8,156 681

1984 2,342 363 7,343 691

1985 2,333 325 7,330 665

1986 2,183 592 7,333 717

1987 2,108 399 6,999 640

1988 2,107 412 7,058 547

1989 2,151 366 6,753 554

1990 2,152 282 6,614 558

1991 2,114 328 6,133 477

1992 2,013 260 5,924 444

1993 2,057 262 5,516 439

1994 2,002 256 5,442 414

1995 2,032 187 5,441 444

1996 2,079 217 5,452 429

1997 2,100 308 5,397 459
Energy Information Administration

82 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Texas - RRC District 8A

1977 2,626 291 1,630 NA

1978 2,439 330 1,473 NA

1979 2,371 270 1,055 351

1980 2,504 196 1,057 290

1981 2,538 247 1,071 335

1982 2,481 200 1,041 296

1983 2,366 203 966 262

1984 2,413 217 907 282

1985 2,711 147 958 283

1986 2,618 559 845 331

1987 2,735 525 876 307

1988 2,800 569 832 326

1989 2,754 377 1,074 332

1990 2,847 285 1,036 354

1991 2,763 363 1,073 333

1992 2,599 273 1,239 257

1993 2,435 264 1,043 298

1994 2,223 154 1,219 267

1995 2,233 156 941 284

1996 2,207 99 931 262

1997 2,098 131 847 290

Texas - RRC District 9

1977 260 28 724 NA

1978 190 27 *908 NA

1979 200 30 *700 79

1980 218 37 649 92

1981 225 34 953 86

1982 219 17 *1,103 119

1983 220 18 932 121

1984 214 25 900 119

1985 285 27 892 111

1986 237 19 868 119

1987 206 21 834 115

1988 202 18 783 106

1989 200 16 703 94

1990 193 12 776 104

1991 162 11 738 101

1992 176 1 670 92

1993 168 2 688 92

1994 159 <1 728 98

1995 149 <1 738 94

1996 144 0 705 119

1997 144 0 794 98

Texas - RRC District 10

1977 *120 4 7,744 NA

1978 90 0 7,406 NA

1979 97 2 6,784 375

1980 89 2 6,435 369

1981 107 2 6,229 364

1982 112 2 6,210 391

1983 105 6 5,919 413

1984 108 6 5,461 440

1985 *140 5 5,469 433

1986 *104 5 5,276 428

1987 102 2 4,962 417

1988 99 4 4,830 363

1989 97 3 4,767 342

1990 99 3 4,490 328

1991 95 2 4,589 356

1992 89 <1 4,409 336

1993 83 <1 4,040 329

1994 75 <1 4,246 326

1995 80 6 4,436 353

1996 74 4 4,391 332

1997 79 4 4,094 382

Texas - State and Federal Offshore

1977 102 0 5,301 NA

1978 131 1 6,422 NA

1979 139 0 7,865 54

1980 149 0 7,510 62

1981 142 0 7,989 75

1982 141 0 7,558 84

1983 123 0 7,562 75

1984 111 0 8,452 98

1985 119 0 8,129 90

1986 103 0 8,176 109

1987 96 0 7,846 98

1988 85 0 7,802 94

1989 75 0 7,573 84

1990 77 0 7,758 87

1991 67 0 7,150 84

1992 197 0 7,344 122

1993 196 0 6,996 119

1994 209 10 6,613 105

1995 257 16 6,838 136

1996 218 5 6,288 133

1997 366 5 6,277 124
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 83

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Texas - State Offshore

1977 NA NA NA NA

1978 NA NA NA NA

1979 NA NA NA NA

1980 NA NA NA 12

1981 NA NA NA 13

1982 NA NA NA 18

1983 NA NA NA 11

1984 NA NA NA 10

1985 7 0 869 10

1986 2 0 732 9

1987 8 0 627 9

1988 7 0 561 5

1989 6 0 605 6

1990 6 0 458 5

1991 7 0 475 5

1992 5 0 348 4

1993 4 0 335 4

1994 4 0 230 2

1995 8 0 313 2

1996 8 0 292 1

1997 4 0 289 3

Utah

1977 252 6 877 NA

1978 188 7 925 NA

1979 201 NA 948 59

1980 198 NA 1,201 127

1981 190 NA 1,912 277

1982 173 NA 2,161 (h)

1983 187 NA 2,333 (h)

1984 172 8 2,080 (h)

1985 276 13 1,999 (h)

1986 269 14 1,895 (h)

1987 284 22 1,947 (h)

1988 260 21 1,298 (h)

1989 246 50 1,507 (h)

1990 249 44 1,510 (h)

1991 233 66 1,702 (h)

1992 217 65 1,830 (h)

1993 228 54 2,040 (h)

1994 231 70 1,789 (h)

1995 216 50 1,580 (h)

1996 237 46 1,633 (h)

1997 234 70 1,839 (h)

hIncluded with Wyoming.

Virginia

1977 NA NA NA NA

1978 NA NA NA NA

1979 NA NA NA NA

1980 NA NA NA NA

1981 NA NA 118 NA

1982 NA NA 122 NA

1983 NA NA 175 NA

1984 NA NA 216 NA

1985 NA NA 235 NA

1986 NA NA 253 NA

1987 NA NA 248 NA

1988 NA NA 230 NA

1989 NA NA 217 NA

1990 NA NA 138 NA

1991 NA NA 225 NA

1992 NA NA 904 NA

1993 NA NA 1,322 NA

1994 NA NA 1,833 NA

1995 NA NA 1,836 NA

1996 NA NA 1,930 NA

1997 NA NA 2,446 NA

West Virginia

1977 21 0 1,567 NA

1978 *30 0 1,634 NA

1979 *48 0 1,558 74

1980 30 8 *2,422 97

1981 30 8 1,834 85

1982 48 8 2,148 79

1983 49 0 2,194 91

1984 *76 0 2,136 80

1985 40 0 2,058 85

1986 37 0 2,148 87

1987 34 0 2,242 87

1988 33 0 2,306 92

1989 30 0 2,201 100

1990 *31 0 2,207 86

1991 26 0 2,528 103

1992 27 0 2,356 97

1993 24 0 2,439 108

1994 25 0 2,565 93

1995 28 0 2,499 62

1996 25 0 2,703 61

1997 26 0 2,846 71
Energy Information Administration

84 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Wyoming

1977 851 31 6,305 NA

1978 845 36 7,211 NA

1979 841 40 7,526 285

1980 928 28 9,100 341

1981 840 53 9,307 384

1982 856 58 9,758 i681

1983 957 61 10,227 i789

1984 954 71 10,482 i860

1985 951 18 10,617 i949

1986 849 126 9,756 i950

1987 854 27 10,023 i924

1988 815 35 10,308 i1,154

1989 825 46 10,744 i 896

1990 794 42 9,944 i812

1991 757 24 9,941 i748

1992 689 18 10,826 i660

1993 624 12 10,933 i600

1994 565 13 10,879 i564

1995 605 12 12,166 i593

1996 603 14 12,320 i727

1997 627 11 13,562 i761

i

Utah and Wyoming are combined.

Federal Offshore - Total

1985 2,862 11 j34,492 702

1986 2,715 16 j34,223 681

1987 2,639 21 j31,931 638

1988 2,629 21 j32,264 622

1989 2,747 32 j32,651 678

1990 2,805 49 31,433 619

1991 2,620 18 29,448 640

1992 2,569 31 27,767 610

1993 2,745 18 27,143 630

1994 2,780 53 28,388 624

1995 3,089 62 29,182 655

1996 3,085 45 29,096 776

1997 3,477 41 28,466 920

j

Includes State offshore Alabama.

Note: Data not tabulated for years 1977-1984.

Federal Offshore - Pacific (California)

1985 991 NA 1,119 12

1986 974 2 1,325 15

1987 1,037 2 1,452 17

1988 1,024 0 1,552 21

1989 987 0 1,496 25

1990 962 0 1,454 18

1991 785 0 1,162 16

1992 734 0 1,118 20

1993 673 0 1,099 25

1994 653 0 1,170 21

1995 571 0 1,265 25

1996 518 0 1,244 23

1997 528 0 544 14

Note: Data not tabulated for years 1977-1984.

Federal Offshore - Gulf of Mexico (Louisiana)

1985 1,759 11 f26,113 610

1986 1,640 14 f25,454 566

1987 1,514 19 f23,260 532

1988 1,527 21 f23,471 512

1989 1,691 32 f24,187 575

1990 1,772 49 k22,679 k519

1991 1,775 18 k21,611 k545

1992 1,643 31 k19,653 k472

1993 1,880 18 k19,383 k490

1994 1,922 43 k20,835 k500

1995 2,269 46 k21,392 k496

1996 2,357 40 k21,856 k621

1997 2,587 36 k21,934 k785

f

Includes State and Federal offshore Alabama. kIncludes Federal offshore Alabama.

Note: Data not tabulated for years 1977-1984.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 85

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Federal Offshore - Gulf of Mexico (Texas)

1985 112 0 7,260 80

1986 101 0 7,444 100

1987 88 0 7,219 89

1988 78 0 7,241 89

1989 69 0 6,968 78

1990 71 0 7,300 82

1991 60 0 6,675 79

1992 192 0 6,996 118

1993 192 0 6,661 115

1994 205 10 6,383 103

1995 249 16 6,525 134

1996 210 5 5,996 132

1997 362 5 5,988 121

Note: Data not tabulated for years 1977- 1984.

Miscellaneous

1977 23 0 102 NA

1978 24 0 109 NA

1979 22 1 *153 2

1980 *38 0 176 3

1981 40 7 191 21

1982 33 0 69 4

1983 30 8 78 5

1984 23 0 75 5

1985 35 0 76 3

1986 33 0 133 2

1987 30 0 65 4

1988 34 0 83 5

1989 39 0 83 5

1990 43 1 *70 3

1991 42 5 75 8

1992 29 0 92 8

1993 34 0 94 8

1994 20 0 65 8

1995 *22 0 *69 7

1996 18 0 67 7

1997 19 0 *43 9

Note: States included may vary for different report years and

hydrocarbon types.

Lower 48 States

1977 23,367 2,168 175,170 NA

1978 21,971 1,964 175,988 NA

1979 20,935 1,878 168,738 6,592

1980 21,054 1,622 165,639 6,717

1981 21,143 1,594 168,693 7,058

1982 20,452 1,478 166,522 7,212

1983 20,428 1,548 165,964 7,893

1984 20,883 1,956 162,987 7,624

1985 21,360 1,662 159,522 7,561

1986 20,014 2,597 158,922 7,784

1987 19,878 3,084 153,986 7,729

1988 19,866 3,169 158,946 7,837

1989 19,827 2,999 158,177 7,389

1990 19,730 2,514 160,046 7,246

1991 18,599 2,810 157,509 7,104

1992 17,723 2,451 155,377 7,104

1993 17,182 2,292 152,508 6,901

1994 16,690 2,129 154,104 6,869

1995 16,771 2,087 155,649 7,093

1996 16,743 1,924 157,180 7,486

1997 17,385 2,375 156,661 7,342

U.S. Total

1977 31,780 3,014 207,413 NA

1978 31,355 2,362 208,033 NA

1979 29,810 2,276 200,997 6,615

1980 29,805 1,622 199,021 6,728

1981 29,426 1,594 201,730 7,068

1982 27,858 1,478 201,512 7,221

1983 27,735 2,124 200,247 7,901

1984 28,446 2,325 197,463 7,643

1985 28,416 2,041 193,369 7,944

1986 26,889 3,499 191,586 8,165

1987 27,256 3,649 187,211 8,147

1988 26,825 3,600 168,024 8,238

1989 26,501 3,749 167,116 7,769

1990 26,254 3,483 169,346 7,586

1991 24,682 4,266 167,062 7,464

1992 23,745 3,782 165,015 7,451

1993 22,957 3,453 162,415 7,222

1994 22,457 3,151 163,837 7,170

1995 22,351 2,669 165,146 7,399

1996 22,017 2,876 166,474 7,823

1997 22,546 3,207 167,223 7,973
Energy Information Administration

86 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table D1. U.S. Proved Reserves of Crude Oil, 1976–1997

(Million Barrels of 42 U.S. Gallons)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1976 – – – – – – – – – e33,502 –

1977 f–40 1,503 1,117 346 496 168 130 794 2,862 31,780 –1,722

1978 366 2,799 1,409 1,756 444 267 116 827 3,008 31,355 –425

1979 337 2,438 2,001 774 424 108 104 636 2,955 29,810 –1,545

1980 219 2,883 994 2,108 572 143 147 862 2,975 29,805 –5

1981 138 2,151 880 1,409 750 254 157 1,161 2,949 29,426 –379

1982 –83 2,245 1,811 351 634 204 193 1,031 2,950 27,858 –1,568

1983 462 2,810 1,299 1,973 629 105 190 924 3,020 27,735 –123

1984 159 3,672 1,227 2,604 744 242 158 1,144 3,037 28,446 +711

1985 429 3,037 1,439 2,027 742 84 169 995 3,052 28,416 –30

1986 57 2,724 1,869 912 405 48 81 534 2,973 26,889 –1,527

1987 233 3,687 1,371 2,549 484 96 111 691 2,873 27,256 +367

1988 364 2,684 1,221 1,827 355 71 127 553 2,811 26,825 –431

1989 213 2,698 1,365 1,546 514 112 90 716 2,586 26,501 –324

1990 86 2,483 1,000 1,569 456 98 135 689 2,505 26,254 –247

1991 163 2,097 1,874 386 365 97 92 554 2,512 24,682 –1,572

1992 290 1,804 1,069 1,025 391 8 85 484 2,446 23,745 –937

1993 271 2,011 1,516 766 356 319 110 785 2,339 22,957 –788

1994 189 2,364 1,357 1,196 397 64 111 572 2,268 22,457 –500

1995 122 1,823 795 1,150 500 114 343 957 2,213 22,351 –106

1996 175 1,723 986 912 543 243 141 927 2,173 22,017 –334

1997 520 1,998 1,084 1,434 477 637 119 1,233 2,138 22,546 +529

aIncludes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

b

Revisions and adjustments = Col. 1 + Col. 2 - Col. 3.

c

Total discoveries = Col. 5 + Col. 6 + Col. 7.

d

Proved reserves = Col. 10 from prior year + Col. 4 + Col. 8 - Col. 9.

e

Based on following year data only.

f

Consists only of operator reported corrections and no other adjustments.

– = Not applicable.

Notes: Old means discovered in a prior year. New means discovered during the report year. The production estimates in this table are

based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves”. They may differ from the official Energy

Information Administration production data for crude oil contained in the Petroleum Supply Annual, DOE/EIA-0340.

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1977 through 1997 annual reports, DOE/EIA-0216.{1-20}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 87

Table D2. U.S. Lower 48 Proved Reserves of Crude Oil, 1976–1997

(Million Barrels of 42 U.S. Gallons)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1976 – – – – – – – – – e24,928 –

1977 f–40 1,499 1,116 343 496 168 130 794 2,698 23,367 –1,561

1978 –48 1,909 1,400 461 444 142 116 702 2,559 21,971 –1,396

1979 342 2,404 1,975 771 424 108 104 636 2,443 20,935 –1,036

1980 210 2,505 981 1,734 479 143 147 769 2,384 21,054 +119

1981 276 1,887 878 1,285 750 254 157 1,161 2,357 21,143 +89

1982 –82 2,146 1,462 602 633 204 193 1,030 2,323 20,452 –691

1983 462 2,247 1,298 1,411 625 105 190 920 2,355 20,428 –24

1984 160 2,801 1,214 1,747 742 207 158 1,107 2,399 20,883 +455

1985 361 2,864 1,197 2,028 581 84 169 834 2,385 21,360 +477

1986 70 2,001 1,642 429 399 48 81 528 2,303 20,014 –1,346

1987 233 2,566 1,213 1,586 294 38 101 433 2,155 19,878 –136

1988 359 2,399 1,218 1,540 340 43 127 510 2,062 19,866 –12

1989 214 2,438 1,325 1,327 342 108 87 537 1,903 19,827 –39

1990 151 1,997 996 1,152 371 98 135 604 1,853 19,730 –97

1991 164 1,898 1,848 214 327 97 87 511 1,856 18,599 –1,131

1992 297 1,343 1,066 574 279 8 84 371 1,821 17,723 –876

1993 250 1,712 1,514 448 343 319 109 771 1,760 17,182 –541

1994 187 1,873 1,346 714 316 64 111 491 1,697 16,690 –492

1995 117 1,521 765 873 434 114 333 881 1,673 16,771 +81

1996 172 1,654 926 900 479 115 141 735 1,663 16,743 –28

1997 514 1,724 1,029 1,209 459 520 119 1,098 1,665 17,385 +642

aIncludes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

b

Revisions and adjustments = Col. 1 + Col. 2 - Col. 3.

c

Total discoveries = Col. 5 + Col. 6 + Col. 7.

d

Proved reserves = Col. 10 from prior year + Col. 4 + Col. 8 - Col. 9.

e

Based on following year data only.

f

Consists only of operator reported corrections and no other adjustments.

– = Not applicable.

Notes: Old means discovered in a prior year. New means discovered during the report year. The production estimates in this table are

based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves”. They may differ from the official Energy

Information Administration production data for crude oil contained in the Petroleum Supply Annual, DOE/EIA-0340.

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1977 through 1997 annual reports, DOE/EIA-0216.{1-20}
Energy Information Administration

88 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table D3. U.S. Proved Reserves of Dry Natural Gas, 1976–1997

(Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1976 – – – – – – – – – e213,278 –

1977 f–20 13,691 15,296 –1,625 8,129 3,173 3,301 14,603 18,843 207,413 –5,865

1978 2,429 14,969 15,994 1,404 9,582 3,860 4,579 18,021 18,805 208,033 +620

1979 –2,264 16,410 16,629 –2,483 8,950 3,188 2,566 14,704 19,257 200,997 –7,036

1980 1,201 16,972 15,923 2,250 9,357 2,539 2,577 14,473 18,699 199,021 –1,976

1981 1,627 16,412 13,813 4,226 10,491 3,731 2,998 17,220 18,737 201,730 +2,709

1982 2,378 19,795 19,340 2,833 8,349 2,687 3,419 14,455 17,506 201,512 –218

1983 3,090 17,602 17,617 3,075 6,909 1,574 2,965 11,448 15,788 200,247 –1,265

1984 –2,241 17,841 14,712 888 8,299 2,536 2,686 13,521 17,193 197,463 –2,784

1985 –1,708 18,775 16,304 763 7,169 999 2,960 11,128 15,985 193,369 –4,094

1986 1,320 21,269 17,697 4,892 6,065 1,099 1,771 8,935 15,610 191,586 –1,783

1987 1,268 17,527 14,231 4,564 4,587 1,089 1,499 7,175 16,114 187,211 –4,375

1988 2,193 23,367 38,427 –12,867 6,803 1,638 1,909 10,350 16,670 g168,024 –19,187

1989 3,013 26,673 23,643 6,043 6,339 1,450 2,243 10,032 16,983 167,116 –908

1990 1,557 18,981 13,443 7,095 7,952 2,004 2,412 12,368 17,233 169,346 +2,230

1991 2,960 19,890 15,474 7,376 5,090 848 1,604 7,542 17,202 167,062 –2,284

1992 2,235 18,055 11,962 8,328 4,675 649 1,724 7,048 17,423 165,015 –2,047

1993 972 17,597 12,248 6,321 6,103 899 1,866 8,868 17,789 162,415 –2,600

1994 1,945 21,365 15,881 7,429 6,941 1,894 3,480 12,315 18,322 163,837 +1,422

1995 580 20,465 12,731 8,314 6,843 1,666 2,452 10,961 17,966 165,146 +1,309

1996 3,785 17,132 13,046 7,871 7,757 1,451 3,110 12,318 18,861 166,474 +1,328

1997 –590 21,658 16,756 4,312 10,585 2,681 2,382 15,648 19,211 167,223 +749

aIncludes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

b

Revisions and adjustments = Col. 1 + Col. 2 - Col. 3.

c

Total discoveries = Col. 5 + Col. 6 + Col. 7.

d

Proved reserves = Col. 10 from prior year + Col. 4 + Col. 8 - Col. 9.

e

Based on following year data only.

f

Consists only of operator reported corrections and no other adjustments.

g

An unusually large revision decrease to North Slope dry natural gas reserves was made in 1988. It recognizes some 24.6 trillion cubic

feet of downward revisions reported during the last few years by operators because of economic and market conditions. EIA in previous years

carried these reserves in the proved category.

– = Not applicable.

Notes: Old means discovered in a prior year. New means discovered during the report year. The production estimates in this table are

based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” and Form EIA-64A, “Annual Report of the Origin

of Natural Gas Liquids Production”. They may differ from the official Energy Information Administration production data for natural gas

contained in the Natural Gas Annual, DOE/EIA-0131.

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1977 through 1997 annual reports, DOE/EIA-0216.{1-20}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 89

Table D4. U.S. Lower 48 Proved Reserves of Dry Natural Gas, 1976–1997

(Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1976 – – – – – – – – – e180,838 –

1977 f–21 13,689 15,229 –1,561 8,056 3,173 3,301 14,530 18,637 175,170 –5,668

1978 2,446 13,912 14,670 1,688 9,582 3,860 4,277 17,719 18,589 175,988 818

1979 –2,202 15,691 16,398 –2,909 8,949 3,173 2,566 14,688 19,029 168,738 –7,250

1980 1,163 15,881 15,819 1,225 9,046 2,539 2,577 14,162 18,486 165,639 –3,099

1981 1,840 16,258 13,752 4,346 10,485 3,731 2,994 17,210 18,502 168,693 3,054

1982 2,367 17,570 19,318 619 8,349 2,687 3,419 14,455 17,245 166,522 –2,171

1983 3,089 17,296 16,875 3,510 6,908 1,574 2,965 11,447 15,515 165,964 –558

1984 –2,245 16,934 14,317 372 8,298 2,536 2,686 13,520 16,869 162,987 –2,977

1985 –1,349 18,252 15,752 1,151 7,098 999 2,960 11,057 15,673 159,522 –3,465

1986 1,618 21,084 16,940 5,762 6,064 1,099 1,761 8,924 15,286 158,922 –600

1987 1,066 16,809 14,164 3,711 4,542 1,077 1,499 7,118 15,765 153,986 –4,936

1988 2,017 22,571 13,676 10,912 6,771 1,638 1,909 10,318 16,270 158,946 4,960

1989 2,997 26,446 23,507 5,936 6,184 1,450 2,243 9,877 16,582 158,177 –769

1990 1,877 17,916 13,344 6,449 7,898 2,004 2,412 12,314 16,894 160,046 +1,869

1991 2,967 19,095 15,235 6,827 5,074 848 1,563 7,485 16,849 157,509 –2,537

1992 1,946 17,878 11,941 7,883 4,621 649 1,724 6,994 17,009 155,377 –2,132

1993 915 16,918 12,139 5,694 6,076 899 1,858 8,833 17,396 152,508 –2,869

1994 1,896 21,121 15,832 7,185 6,936 1,894 3,480 12,310 17,899 154,104 +1596

1995 973 19,903 12,680 8,196 6,801 1,666 2,452 10,919 17,570 155,649 +1,545

1996 3,640 16,930 12,875 7,695 7,751 1,390 3,110 12,251 18,415 157,180 +1,531

1997 –609 19,849 16,657 2,583 10,571 2,681 2,382 15,634 18,734 156,661 –519

aIncludes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

b

Revisions and adjustments = Col. 1 + Col. 2 - Col. 3.

c

Total discoveries = Col. 5 + Col. 6 + Col. 7.

d

Proved reserves = Col. 10 from prior year + Col. 4 + Col. 8 - Col. 9.

e

Based on following year data only.

f

Consists only of operator reported corrections and no other adjustments.

– = Not applicable.

Notes: Old means discovered in a prior year. New means discovered during the report year. The production estimates in this table are

based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” and Form EIA-64A, “Annual Report of the Origin

of Natural Gas Liquids Production”. They may differ from the official Energy Information Administration production data for natural gas

contained in the Natural Gas Annual, DOE/EIA-0131.

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1977 through 1997 annual reports, DOE/EIA-0216.{1-20}
Energy Information Administration

90 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table D5. U.S. Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–1997

(Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1978 – – – – – – – – – e208,033 –

1979 5,356 17,077 17,300 5,133 9,332 3,279 2,637 15,248 20,079 208,335 +302

1980 1,253 17,668 16,531 2,390 9,757 2,629 2,648 15,034 19,500 206,259 –2,076

1981 2,057 17,156 14,413 4,800 10,979 3,870 3,080 17,929 19,554 209,434 +3,175

1982 2,598 20,596 20,141 3,053 8,754 2,785 3,520 15,059 18,292 209,254 –180

1983 4,363 18,442 18,385 4,420 7,263 1,628 3,071 11,962 16,590 209,046 –208

1984 –2,413 18,751 15,418 920 8,688 2,584 2,778 14,050 18,032 205,984 –3,062

1985 –1,299 19,732 17,045 1,388 7,535 1,040 3,053 11,628 16,798 202,202 –3,782

1986 2,137 22,392 18,557 5,972 6,359 1,122 1,855 9,336 16,401 201,109 –1,093

1987 1,199 18,455 14,933 4,721 4,818 1,128 1,556 7,502 16,904 196,428 –4,681

1988 2,180 24,638 f39,569 –12,751 7,132 1,677 1,979 10,788 17,466 f176,999 –19,429

1989 2,537 27,844 24,624 5,757 6,623 1,488 2,313 10,424 17,752 175,428 –1,571

1990 1,494 19,861 14,024 7,331 8,287 2,041 2,492 12,820 18,003 177,576 +2,148

1991 3,368 20,758 16,189 7,937 5,298 871 1,655 7,824 18,012 175,325 –2,251

1992 2,543 18,906 12,532 8,917 4,895 668 1,773 7,336 18,269 173,309 –2,016

1993 1,048 18,394 12,853 6,589 6,376 927 1,930 9,233 18,641 170,490 –2,819

1994 1,977 22,345 16,509 7,813 7,299 1,941 3,606 12,846 19,210 171,939 +1,449

1995 889 21,548 13,457 8,980 7,204 1,709 2,518 11,431 18,874 173,476 +1,537

1996 4,288 18,034 13,757 8,565 8,189 1,491 3,209 12,889 19,783 175,147 +1,671

1997 –730 22,712 17,655 4,327 11,179 2,747 2,455 16,381 20,134 175,721 +574

aIncludes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

b

Revisions and adjustments = Col. 1 + Col. 2 - Col. 3.

c

Total discoveries = Col. 5 + Col. 6 + Col. 7.

d

Proved reserves = Col. 10 from prior year + Col. 4 + Col. 8 - Col. 9.

e

Based on following year data only.

f

An unusually large revision decrease to North Slope wet natural gas reserves was made in 1988. It recognizes some 25 trillion cubic feet

of downward revisions reported during the last few years by operators because of economic and market conditions. EIA in previous years

carried these reserves in the proved category.

– = Not applicable.

Notes: Old means discovered in a prior year. New means discovered during the report year. The production estimates in this table are

based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves”. They may differ from the official Energy

Information Administration production data for natural gas contained in the Natural Gas Annual, DOE/EIA-013.

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1979 through 1997 annual reports, DOE/EIA-0216.{2-20}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 91

Table D6. U.S. Lower 48 Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–1997

(Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1978 – – – – – – – – – e175,988 –

1979 5,402 16,358 17,069 4,691 9,331 3,264 2,637 15,232 19,851 176,060 +72

1980 1,218 16,577 16,427 1,368 9,446 2,629 2,648 14,723 19,287 172,864 –3,196

1981 2,270 17,002 14,352 4,920 10,973 3,870 3,076 17,919 19,318 176,385 +3,521

1982 2,586 18,371 20,119 838 8,754 2,785 3,520 15,059 18,030 174,252 –2,133

1983 4,366 18,136 17,643 4,859 7,262 1,628 3,071 11,961 16,317 174,755 +503

1984 –2,409 17,844 15,023 412 8,687 2,584 2,778 14,049 17,708 171,508 –3,247

1985 –1,313 19,203 16,490 1,400 7,463 1,040 3,053 11,556 16,485 167,979 –3,529

1986 2,114 22,207 17,797 6,524 6,357 1,122 1,845 9,324 16,073 167,754 –225

1987 1,200 17,733 14,865 4,068 4,772 1,116 1,556 7,444 16,553 162,713 –5,041

1988 2,025 23,829 14,439 11,415 7,099 1,677 1,979 10,755 17,063 167,820 +5,107

1989 2,545 27,616 24,488 5,673 6,467 1,485 2,313 10,265 17,349 166,409 –1,411

1990 1,811 18,784 13,925 6,670 8,232 2,041 2,492 12,765 17,661 168,183 +1,774

1991 3,367 19,961 15,948 7,380 5,281 871 1,614 7,766 17,657 165,672 –2,511

1992 2,265 18,728 12,511 8,482 4,840 668 1,773 7,281 17,851 163,584 –2,088

1993 996 17,714 12,743 5,967 6,349 927 1,922 9,198 18,245 160,504 –3,080

1994 1,924 22,071 16,458 7,537 7,294 1,941 3,606 12,841 18,756 162,126 +1,622

1995 1,304 20,928 13,403 8,829 7,162 1,709 2,518 11,389 18,443 163,901 +1,775

1996 4,219 17,832 13,586 8,465 8,183 1,430 3,209 12,822 19,337 165,851 +1,950

1997 -835 20,878 17,556 2,497 11,165 2,747 2,455 16,367 19,657 165,048 –803

aIncludes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

b

Revisions and adjustments = Col. 1 + Col. 2 - Col. 3.

c

Total discoveries = Col. 5 + Col. 6 + Col. 7.

d

Proved reserves = Col. 10 from prior year + Col. 4 + Col. 8 - Col. 9.

e

Based on following year data only.

– = Not applicable.

Notes: Old means discovered in a prior year. New means discovered during the report year. The production estimates in this table are

based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves”. They may differ from the official Energy

Information Administration production data for natural gas contained in the Natural Gas Annual, DOE/EIA-0131.

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1979 through 1997 annual reports, DOE/EIA-0216.{2-20}
Energy Information Administration

92 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table D7. U.S. Proved Reserves of Natural Gas Liquids, 1978–1997

(Million Barrels of 42 U.S. Gallons)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1978 – – – – – – – – – e6,772 –

1979 f64 677 726 15 364 94 97 555 727 6,615 –157

1980 153 743 639 257 418 90 79 587 731 6,728 +113

1981 231 729 643 317 542 131 91 764 741 7,068 +340

1982 299 811 832 278 375 112 109 596 721 7,221 +153

1983 849 847 781 915 321 70 99 490 725 7,901 +680

1984 –123 866 724 19 348 55 96 499 776 7,643 –258

1985 426 906 744 588 337 44 85 466 753 7,944 +301

1986 367 1,030 807 590 263 34 72 369 738 8,165 +221

1987 231 847 656 422 213 39 55 307 747 8,147 –18

1988 11 1,168 715 464 268 41 72 381 754 8,238 +91

1989 –277 1,143 1,020 –154 259 83 74 416 731 7,769 –469

1990 –83 827 606 138 299 39 73 411 732 7,586 –183

1991 233 825 695 363 189 25 55 269 754 7,464 –122

1992 225 806 545 486 190 20 64 274 773 7,451 –13

1993 102 764 640 226 245 24 64 333 788 7,222 –229

1994 43 873 676 240 314 54 131 499 791 7,170 –52

1995 192 968 691 469 432 52 67 551 791 7,399 +229

1996 474 844 669 649 451 65 109 625 850 7,823 +424

1997 –14 1,199 910 275 535 114 90 739 864 7,973 +150

aIncludes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

b

Revisions and adjustments = Col. 1 + Col. 2 - Col. 3.

c

Total discoveries = Col. 5 + Col. 6 + Col. 7.

d

Proved reserves = Col. 10 from prior year + Col. 4 + Col. 8 - Col. 9.

e

Based on following year data only.

f

Consists only of operator reported corrections and no other adjustments.

– = Not applicable.

Notes: Old means discovered in a prior year. New means discovered during the report year. The production estimates in this table are

based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” and Form EIA-64A, “Annual Report of the Origin

of Natural Gas Liquids Production”. They may differ from the official Energy Information Administration production data for natural gas liquids

contained in the Natural Gas Annual, DOE/EIA-0131.

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1979 through 1997 annual reports, DOE/EIA-0216.{2-20}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 93

Table D8. U.S. Lower 48 Proved Reserves of Natural Gas Liquids, 1978–1997

(Million Barrels of 42 U.S. Gallons)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1978 – – – – – – – – – e6,749 –

1979 f63 677 726 14 364 94 97 555 726 6,592 –157

1980 165 743 639 269 418 90 79 587 731 6,717 +125

1981 233 728 643 318 542 131 91 764 741 7,058 +341

1982 300 811 832 279 375 112 109 596 721 7,212 +154

1983 850 847 781 916 321 70 99 490 725 7,893 +681

1984 –115 847 724 8 348 55 96 499 776 7,624 –269

1985 70 883 731 222 334 44 85 463 748 7,561 –63

1986 363 1,030 804 589 263 34 72 369 735 7,784 +223

1987 179 846 655 370 212 39 55 306 731 7,729 –55

1988 10 1,167 715 462 267 41 72 380 734 7,837 +108

1989 –273 1,141 1,018 –150 259 83 74 416 714 7,389 –448

1990 –60 827 606 161 298 39 73 410 714 7,246 –143

1991 183 815 677 321 187 25 55 267 730 7,104 –142

1992 225 796 542 479 183 20 64 267 746 7,104 0

1993 101 755 631 225 245 24 64 333 761 6,901 –203

1994 38 872 676 234 314 54 131 499 765 6,869 –32

1995 204 918 688 434 432 52 67 551 761 7,093 +224

1996 417 832 654 595 450 56 109 615 817 7,486 +393

1997 –107 965 910 –52 533 114 90 737 829 7,342 –144

aIncludes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

b

Revisions and adjustments = Col. 1 + Col. 2 - Col. 3.

c

Total discoveries = Col. 5 + Col. 6 + Col. 7.

d

Proved reserves = Col. 10 from prior year + Col. 4 + Col. 8 - Col. 9.

e

Based on following year data only.

f

Consists only of operator reported corrections and no other adjustments.

– = Not applicable.

Notes: Old means discovered in a prior year. New means discovered during the report year. The production estimates in this table are

based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” and Form EIA-64A, “Annual Report of the Origin

of Natural Gas Liquids Production”. They may differ from the official Energy Information Administration production natural gas liquids

contained in the Natural Gas Annual, DOE/EIA-0131.

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1979 through 1997 annual reports, DOE/EIA-0216.{2-20}
Energy Information Administration

94 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-1997

Gulf of Mexico Depth

Greater than Less than Deepwater

Year Total Louisianaa Texas 200 metersb 200 metersb Percentageb

Crude Oil (million barrels of 42 U.S. gallons)

Production

1992 267 253 14 R46 R221 R17.2

1993 266 252 14 R46 R220 R17.3

1994 265 245 20 R53 R212 R20.1

1995 292 262 30 R77 R215 R26.4

1996 303 265 38 R90 R213 R29.7

1997 342 298 44 123 219 36.0

Reserves

1992 1,835 1,643 192 R557 R1,278 R30.4

1993 2,072 1,880 192 R824 R1,248 R39.8

1994 2,127 1,922 205 R877 R1,250 R41.2

1995 2,518 2,269 249 R1,241 R1,277 R49.3

1996 2,567 2,357 210 R1,311 R1,256 R51.1

1997 2,949 2,587 362 1,682 1,267 57.0

Natural Gas, Wet After Lease Separation

(billion cubic feet at 14.73 psia and 60° Fahrenheit)

Production

1992 4,576 3,292 1,284 R166 R4,410 R3.6

1993 4,651 3,383 1,268 R229 R4,422 R4.9

1994 4,797 3,505 1,292 R294 R4,503 R6.1

1995 4,679 3,421 1,258 R354 R4,315 R7.8

1996 5,045 3,752 1,293 R549 R4,496 R10.9

1997 5,230 3,984 1,246 577 4,653 11.0

Reserves

1992 27,050 20,006 7,044 R3,273 R23,777 R12.1

1993 26,463 19,751 6,712 R3,495 R22,968 R13.2

1994 27,626 21,208 6,418 R4,772 R22,854 R17.3

1995 28,229 21,664 6,565 R5,811 R22,418 R20.6

1996 28,153 22,119 6,034 R6,389 R21,764 R22.7

1997 28,455 22,428 6,027 7,491 20,964 26.3

Natural Gas Liquids (million barrels of 42 U.S. gallons)

Production

1992 91 76 15 R4 R87 R4.4

1993 97 80 17 R6 R91 R6.2

1994 98 83 15 R6 R92 R6.1

1995 85 71 14 R12 R73 R14.1

1996 101 84 17 R13 R88 R12.9

1997 140 123 17 17 123 12.1

Reserves

1992 590 472 118 R91 R499 R15.4

1993 605 490 115 R97 R508 R16.0

1994 603 500 103 R110 R493 R18.2

1995 630 496 134 R294 R336 R46.7

1996 753 621 132 R300 R456 R39.8

1997 906 785 121 349 557 38.5

aIncludes Federal Offshore Alabama.

bRevisions result from reclassing all field depths to match Minerals Management Service assignments.

Source: Based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves.”
Appendix E

Summary of Data Collection Operations
Appendix E

Summary of Data Collection Operations

Form EIA-23 Survey Design

The data collected on Form EIA-23, “Annual Survey of

Domestic Oil and Gas Reserves,” were used to produce

this report. This section provides information

concerning the survey design, response statistics,

reporting requirements, and frame maintenance.

Form EIA-23 is mailed annually to all known large and

intermediate size operators, and a scientifically

selected sample of small operators. Operator size

categories were based upon their annual production as

indicated in various Federal, State, and commercial

records. The term State/subdivision refers to an

individual subdivision within a State or an individual

State that is not subdivided. Operators were divided

into the three size categories shown below.

n Category I - Large Operators: Operators who

produced 1.5 million barrels or more of crude oil,

or 15 billion cubic feet or more of natural gas, or

both.

n Category II - Intermediate Operators: Operators

who produced at least 400,000 barrels of crude

oil or 2 billion cubic feet of natural gas, or both,

but less than Category I operators.

n Category III - Small Operators: Operators who

produced less than the Category II operators.

Category III operators were further subdivided into

operators sampled with Certainty (Certainty) and

operators that were randomly sampled

(Noncertainty).

Data were filed for calendar year 1997 by crude oil or

natural gas well operators who were active as of

December 31, 1997. EIA defines an operator as an

organization or person responsible for the

management and day-to-day operation of crude oil or

natural gas wells. The purpose of this definition is to

eliminate responses from royalty owners, working

interest owners (unless they are also operators), and

others not directly responsible for operations. An

operator need not be a separately incorporated entity.

To minimize reporting burden, corporations are

permitted to report on the basis of operating units of

the company convenient for them. A large corporation

may be represented by a single form or by several

forms.

Table E1 shows a comparison of the EIA-23 sample and

sampling frame between 1990 and 1997, and depicts

the number of active operators, 1990 showing the

largest in the series. The 1997 sampling frame consisted

of 180 Category I, 461 Category II, 1,194 Category III

Certainty, and 20,843 Category III Noncertainty

operators, for a total of 22,678 active operators. The

survey sample consisted of 1,835 operators selected

with certainty that included all of the Category I and II

Certainty operators, the 1,194 smaller operators that

were selected with certainty because of their size in

relation to the area or areas in which they operated, and

1,645 Noncertainty operators selected as a systematic

random sample of the remaining operators.

Form EIA-23

Response Statistics

Each company and its parent company or subsidiaries

were required to file Form EIA-23 if they met the

survey specifications. Response to the 1997 survey is

summarized in Table E2. EIA makes a considerable

effort to gain responses from all operators. About 13

percent of those selected turned out to be nonoperators

(those that reported being nonoperators during the

report year and operators that could not be located). Of

the 442 nonoperators, 43 had successor operators that

had taken over the production of the nonoperator.

These successor operators were subsequently sampled.

The overall response rate for the 1997 survey was 99.8

percent. This compares with a 100 percent overall

response rate for all operators in 1996.

Form EIA-23 Reporting

Requirements

The collection format for Form EIA-23 actually consists

of two forms. The form the respondent is required to

file is dependent upon the annual production levels of

crude oil, natural gas, and lease condensate. Category I

and Category II operators file a more detailed field

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 97
level data form. Category III operators file a summary

report which is aggregated at a State/subdivision level.

The cover page required of all respondents identifies

each operator by name and address (Figure I1,

Appendix I). The oil and gas producing industry

includes a large number of small enterprises. To

minimize reporting burden, only a sample of small

operators were required to file a summary report of

Form EIA-23 (Figures I2 and I3, Appendix I). Report

year production data were required by

State/subdivision areas for crude oil, natural gas, and

lease condensate. Proved reserves data for operators

were required only for those properties where

estimates existed in the respondent’s records.

All Category I and Category II operators were required

to file field level data on Schedule A, “Operated Proved

Reserves, Production, and Related Data by Field,” for

each oil and/or gas field in which the respondent

operated properties (Figure I4, Appendix I). All

Category I and those Category II operators who had

reserve estimates were required to file on a total

operated basis for crude oil, nonassociated natural gas,

associated-dissolved natural gas, and lease condensate.

The following data items were required to be filed:

proved reserves at the beginning and the end of the

report year, revision increases and revision decreases,

extensions, new field discoveries, new reservoirs in old

fields, production, indicated additional reserves of

crude oil, nonproducing reserves, field discovery year,

water depth, and field location information.

Energy Information Administration

98 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table E1. Comparison of the EIA-23 Sample and Sampling Frame, 1990-1997

Number of Operators

Operator Categor 1990 1991 1992 1993 1994 1995 1996 1997

Certainty

Category I. . . . . . . . . . . . . 144 144 157 160 161 161 176 180

Category II . . . . . . . . . . . . 468 484 480 500 482 476 486 461

Category III. . . . . . . . . . . . 2,316 2,074 1,896 1,723 1,694 1,596 3 1,194

Sampled . . . . . . . . . . . . . 2,928 2,702 2,533 2,383 2,337 2,233 665 1,835

Percent Sampled . . . . . . . 100 100 100 100 100 100 100 100

Noncertainty

Sampled . . . . . . . . . . . . . . 1,431 1,760 1,724 1,691 1,737 1,632 0 1,645

Percent Sampled . . . . . . . 68888808

Total

Active Operators. . . . . . . . 27,556 R24,846 R24,173 R23,656 R24,222 22,766 23,410 22,678

Not Sampled . . . . . . . . . . 23,196 20,384 19,916 19,791 20,148 18,901 22,745 19,198

Sampled . . . . . . . . . . . . . . 4,360 4,462 4,257 4,074 4,074 3,865 665 3,480

Percent Sampled . . . . . . . 16 18 18 17 17 17 3 15

R=Revised data.

Note: Active operators in 1997 include 10 operators added after December 29, 1997 and not included in Table E3.

Source: Energy Information Administration, Office of Oil and Gas.

Table E2. Form EIA-23 Survey Response Statistics, 1997

Original Netb Responding Nonresponding

Sample Successora Category Non-c Adjustedd Operators Operators

Operator Category Selected Operators Changes operators Sample Number Percent Number Percent

Certainty

Category I . . . . . . . 180 3 0 -14 169 169 100.0 0 0.0

Category II . . . . . . . 461 5 -11 -37 418 418 100.0 0 0.0

Category III . . . . . . . 1,194 21 11 -80 1,146 1,146 100.0 0 0.0

Subtotal. . . . . . . . . 1,835 29 0 -131 1,733 1,733 100.0 0 0.0

Noncertainty . . . . . . . . 1,645 14 0 -311 1,348 1,342 99.6 6 0.4

Total . . . . . . . . . . . . 3,480 43 0 -442 3,081 3,075 99.8 6 0.2

aSuccessor operators are those, not initially sampled, that have taken over the production of a sampled operator.

bNet of recategorized operators in the sample (excluding nonoperators).

c

Includes former operators reporting that they were not operators during the report year and operators that could not be located who are treated as nonoperators. dAdjusted sample equals original sample plus successor operators plus net category changes minus nonoperators.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves” 1997.
Category II operators who did not have reserves

estimates were required to file the field location

information and report year production for the four

hydrocarbon types from properties where reserves

were not estimated. These respondents used Schedule

B, “Footnotes,” to provide clarification of reported data

items when required in the instructions, or electively to

provide narrative or detail to explain any data item

filed (Figure I5, Appendix I).

Crude oil and lease condensate volumes were reported

rounded to thousands of barrels of 42 U.S. gallons at

60° Fahrenheit, and natural gas volumes were reported

rounded to millions of cubic feet. All natural gas

volumes were requested to be reported at 60°

Fahrenheit and a pressure base of 14.73 pounds per

square inch absolute. Other minor report preparation

standards were specified to assure that the filed data

could be readily processed.

Oil and Gas Field Coding

A major effort to create standardized codes for all

identified oil or gas fields throughout the United States

was implemented during the 1982 survey year.

Information from previous lists was reviewed and

reconciled with State lists and a consolidated list was

created. The publication of the Oil and Gas Field Code

Master List 1997, in February of 1998, was the 16th

annual report and reflected data collected through

October 1997. This publication was mailed to operators

to assist in identifying the field code data necessary for

the preparation of Form EIA-23. A copy of this

publication may be purchased from the National

Energy Information Center (see inside cover page).

Form EIA-23 Comparison

with Other Data Series

Estimated crude oil, lease condensate, and natural gas

production volumes from Form EIA-23 were compared

with official EIA production data supplied by Federal

and State oil and natural gas regulatory agencies and

published in EIA’s monthly and annual reports.

Reports published by the Federal and State oil and

natural gas regulatory agencies were used to compare

specific operator production responses to these

agencies with Form EIA-23 responses. When

significant differences were found, responses were

researched to detect and reconcile possible reporting

errors.

For 1997, Form EIA-23 National estimates of

production were 2,312 million barrels for crude oil and

lease condensate or 43 million barrels (1.8 percent)

lower than that reported in the Petroleum Supply Annual

1997 for crude oil and lease condensate. Form EIA-23

National estimates of production for dry natural gas

were 19,211 billion cubic feet or 310 billion cubic feet

(1.6 percent) higher than the Natural Gas Annual 1997

for 1997 dry natural gas production.

Form EIA-23

Frame Maintenance

Operator frame maintenance is a major data quality

control effort. Extensive effort is expended to keep the

frame as current as possible. The Form EIA-23 frame

contains a listing of all crude oil and natural gas well

operators in the United States and must be maintained

and updated regularly in order to ensure an accurate

frame from which to draw the sample for the annual

crude oil and natural gas reserves survey. The original

frame, created in 1977, has been revised annually. In

addition, outside sources, such as State publications

and computer tapes, and commercial information data

bases such as Dwight’s Energydata and Petroleum

Information, are used to obtain information on

operator status and to update addresses for the frame

each year.

A maintenance procedure is utilized, using a postcard

form with prepaid return postage, to contact possible

active crude oil and natural gas well operators

presently listed on EIA’s master frame, but for whom

the listing had not been updated for 2 years. This

procedure identifies active operators and nonoperators

which improves the frame for future sample selections

for the survey. Table E3 provides a summary of

changes made to the Form EIA-23 frame of crude oil

and natural gas well operators for the 1995 survey

mailing. These changes resulted from all frame

maintenance activities.

The Form EIA-23 operator frame contained a total of

65,420 entries as of December 29, 1997. Of these, 22,668

were confirmed operators. These are operators who

have filed in the past or for whom the EIA has recent

production data from an outside source. The remaining

operators (including both definite and probable

nonoperators) exist as a pool of names and addresses

that may be added to the active list if review indicates

activity.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 99
Form EIA-64A Survey Design

The data for this report are also collected on Form

EIA-64A, “Annual Report of the Origin of Natural Gas

Liquids Production.” This section provides

information concerning the survey design, response

statistics, reporting requirements, and frame

maintenance for Form EIA-64A.

Form EIA-23 for report years 1977 and 1978 required

natural gas well operators to report their natural gas

data on a fully dry basis. It was discovered in the course

of those surveys that many operators had little or no

knowledge of the extraction of liquids from their

produced natural gas streams once custody transfer

had taken place. Therefore, these operators reverted to

reporting the only natural gas volume data they had in

their possession. These volume data were for dryer

natural gas than that which had passed through the

wellhead, but wetter than fully dry natural gas. With

reference to Figure E1, they reported their volumes

either at the wellhead or after removal of lease

condensate in their lease or field separation facilities.

Some of the larger operators, however, also owned or

operated natural gas processing plants. They reported

their volumes after removal of both lease condensate

and plant liquids, as required by Form EIA-23. The

aggregate volumes resulting from the 1977 and 1978

surveys, therefore, were neither fully dry (as was

intended) nor fully wet. They do appear to have been

more dry than wet simply because the operators who

reported fully dry volumes also operated properties

that contained the bulk of proved natural gas reserves.

The EIA recognized that its estimates of proved

reserves of natural gas liquids (NGL) had to reflect not

only those volumes extractable in the future under

current economic and operating conditions at the lease

or field (lease condensate), but also volumes (plant

liquids) extractable downstream at existing natural gas

processing plants. Form EIA-64, which already

canvassed these processing plants, did not request that

the plants’ production volumes be attributed to source

areas. Beginning with the 1979 survey, a new form to

collect plant liquids production according to the area or

areas where their input natural gas stream had been

produced was mailed to all of the operating plants. The

instructions for filing the Form EIA-23 were altered to

collect data from natural gas well operators that

reflected those volumes of natural gas dried only

through the lease or field separation facilities. The

reporting basis of these volumes are referred to as “wet

after lease separation.” The methodology used to

estimate NGL reserves by State and State subdivision is

provided in Appendix F.

Form EIA-64A

Response Statistics

EIA mailed EIA-64A forms to all known natural gas

processing plant operators as of January 10, 1998. In

addition, plant operators whose plants were shut down

or dismantled during 1997 were required to complete

forms for the portion of 1997 when the plants were in

operation.

Natural gas processing plant operators were requested

to file a Form EIA-64A for each of their plants. A total of

263 operators of 659 plants were sent forms. This

number included 4 new plants, 2 reactivated plants,

and 16 successor plants identified after the initial 1997

survey mailing. A total of 27 plants were reported as

nonoperating according to the Form EIA-64A

definition. For the eleventh consecutive year the

response rate was 100 percent.

Form EIA-64A respondents were requested to report

natural gas liquids production data by area of origin.

Table E4 summarizes the responses by plant operators

of the volume and origin of natural gas delivered to the

Energy Information Administration

100 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table E3. Summary of the 1997 Operator Frame

Activity, Form EIA-23

Total 1996 Operator Frame. . . . . . . . . . . . . 64,172

Operators. . . . . . . . . . . . . . . . . . . . . . . 22,240

Nonoperators. . . . . . . . . . . . . . . . . . . . 41,932

Changes to 1996 Operator Status. . . . . . 1,183

From Nonoperator to Operator . . . . . . 177

From Operator to Nonoperator . . . . . . 986

No Changes to 1996 Operator Status . . . 63,009

Operators. . . . . . . . . . . . . . . . . . . . . . . 21,254

Nonoperators. . . . . . . . . . . . . . . . . . . . 41,755

Additions to 1996 Operator Frame . . . . . 1,248

Operator . . . . . . . . . . . . . . . . . . . . . . . 1,237

Nonoperator. . . . . . . . . . . . . . . . . . . . . 11

Total 1997 Operator Frame. . . . . . . . . . . . 65,420

Operators. . . . . . . . . . . . . . . . . . . . . . . 22,668

Nonoperators. . . . . . . . . . . . . . . . . . . . 42,752

Note: Includes operator frame activity through December 29, 1997.

Source: Energy Information Administration, Office of Oil and Gas.
processing plants and the volume of the natural gas

liquids extracted by the plants by State. The majority of

the plant operators reported only one area of origin for

the natural gas that was processed by a plant. The State

or area of origin reported is generally also the plant’s

location.

Form EIA-64A

Reporting Requirements

Form EIA-64A consisted of the reporting schedule

shown in Figure I6, Appendix I. The form identifies the

plant, its geographic location, the plant operator’s

name and address, and the parent company name. The

certification was signed by a responsible official of the

operating entity. The form pertains to the volume of

natural gas received and of natural gas liquids

produced at the plant, allocated to each area of origin.

Operators also filed the data pertaining to the amount

of natural gas shrinkage that resulted from extraction

of natural gas liquids at the plant, and the amount of

fuel used in processing.

Natural gas liquids volumes were reported rounded to

thousands of barrels of 42 U.S. gallons at 60°

Fahrenheit, and natural gas volumes were reported

rounded to millions of cubic feet. All natural gas

volumes were requested to be reported at 60°

Fahrenheit and a pressure base of 14.73 pounds per

square inch absolute. Other minor report preparation

standards were specified to assure that the filed data

could be readily processed.

Form EIA-64A Comparison

with Other Data Series

Form EIA-64A plant liquids production data were

compared with data collected on Form EIA-816,

“Monthly Natural Gas Liquids Report.” Aggregated

production from Form EIA-816 represents the net

volume of natural gas processing plant liquid output

less input for the report year. These data are published

in EIA’s Petroleum Supply Annual reports. The Form

EIA-64A annual responses reflect all corrections and

revisions to EIA’s monthly estimates. Differences,

when found, were reconciled in both sources. For 1997,

the Form EIA-64A National estimates were 4.1 percent

(27 million barrels) higher than the Petroleum Supply

Annual 1997 volume for natural gas plant liquids

production.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 101

W ellhead

Lease or Field

Separation

Facilities

Natural Gas

Processing Plant

Lease Condensate

Storage

Wet Gas after

Separation

Dry Gas

Plant Liquids

Production

Lease Condensate

Production

TOTAL

NATURAL GAS LIQUIDS

PRODUCTION

Wet Gas

Figure E1. Natural Gas Liquids Extraction Flows

Source: Energy Information Administration, Office of Oil and Gas.
Form EIA-64A

Frame Maintenance

The Form EIA-64A plant frame contains data on all

known active and inactive natural gas processing

plants in the United States. The 1997 plant frame was

compared to listings of natural gas processing plants

from Form EIA-816, “Monthly Natural Gas Liquids

Report”; the LPG Almanac; and the Oil and Gas Journal.

A list of possible additions to the plant frame was

compiled. Table E5 summarizes the Form EIA-64A

plant frame changes made as a result of the

comparisons as of December 29, 1997.

Energy Information Administration

102 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table E5. Form EIA-64A 1997 Plant Frame Activity

Frame as of 1996 survey mailing . . . . . . . . . . 710

Additions . . . . . . . . . . . . . . . . . . . . . . 141

Deletions . . . . . . . . . . . . . . . . . . . . . . –197

Frame as of 1997 survey mailing . . . . . . . . . . 654

Note: Includes operator frame activity through December 29, 1997.

Source: Energy Information Administration, Office of Oil and Gas.

Table E4. Natural Gas Processed and Liquids Extracted at Natural Gas Processing Plants, 1997

Volume of Natural Gas Delivered to Processing Plants

State Out of State Natural Gas Total Liquids

Plant Location Production Production Processed Extracted

(million cubic feet) (thousand barrels)

Alaska . . . . . . . . . . . . . . 2,964,734 0 2,964,734 34,908

Lower 48 States. . . . . . . 13,500,713 371,664 13,872,377 656,091

Alabama . . . . . . . . . . . . 113,367 1,044 114,4 11 3,471

Arkansas . . . . . . . . . . . . 185,244 0 185,244 429

California . . . . . . . . . . . . 243,054 0 243,054 9,246

Colorado . . . . . . . . . . . . 374,570 158 374,728 20,659

Florida . . . . . . . . . . . . . . 5,700 2,664 8,364 1,596

Kansas. . . . . . . . . . . . . . 582,479 166,944 749,423 29,027

Kentucky . . . . . . . . . . . . 41,119 2,233 43,352 1,745

Louisiana . . . . . . . . . . . . 4,620,039 147,926 4,767,965 107,473

Michigan . . . . . . . . . . . . 86,564 0 86,564 4,484

Mississippi . . . . . . . . . . . 4,372 0 4,372 232

Montana. . . . . . . . . . . . . 8,851 8 8,859 324

NewMexico . . . . . . . . . . 851,305 0 851,305 74,970

North Dakota . . . . . . . . . 51,657 0 51,657 3,897

Oklahoma . . . . . . . . . . . 1,012,149 1,859 1,014,008 67,745

Texas. . . . . . . . . . . . . . . 4,139,591 32,376 4,171,967 275,315

Utah. . . . . . . . . . . . . . . . 237,345 12,585 249,930 13,757

West Virginia . . . . . . . . . 68,960 132 69,092 5,057

Wyoming . . . . . . . . . . . . 862,108 944 863,052 35,952

Miscellaneousa . . . . . . . 12,239 2,791 15,030 712

Total . . . . . . . . . . . . . . . 16,465,447 371,664 16,837,111 690,999

aIncludes Illinois, Nebraska, Ohio, Pennsylvania, and Tennessee.

Source: Form EIA-64A, “Annual Report of the Origin of Natural Gas Liquids Production,” 1997.
Appendix F

Statistical Considerations
Appendix F

Statistical Considerations

Survey Methodology

The Form EIA-23 survey is designed to provide reliable

estimates for reserves and production of crude oil,

natural gas, and lease condensate for the United States.

Operators of crude oil and natural gas wells were

selected as the appropriate respondent population

because they have access to the most current and

detailed information, and therefore, presumably have

better reserve estimates than do other possible classes

of respondents, such as working interest or royalty

owners.

While large operators are quite well known, they

comprise only a small portion of all operators. The

small operators are not well known and are difficult to

identify because they go into and out of business, alter

their corporate identities, and change addresses

frequently. As a result, EIA conducts extensive frame

maintenance activities each year to identify all current

operators of crude oil and natural gas wells in the

country.

Sampling Strategy

EIA publishes data on reserves and production for

crude oil, natural gas, and lease condensate by State for

most States, and by State subdivision for the States of

California, Louisiana, New Mexico, and Texas. To meet

the survey objectives, while minimizing respondent

burden, a random sampling strategy has been used

since 1977. Each operator reporting on the survey is

asked to report production for crude oil, natural gas,

and lease condensate for each State/subdivision in

which he operates. The term State/subdivision refers

to an individual subdivision within a State or an

individual State that is not subdivided.

The total volume of production varies among the

State/subdivisions. To meet the survey objectives

while controlling total respondent burden, EIA

selected the following target sampling error for the

1997 survey for each product class.

n 1.0 percent for National estimates.

n 1.0 percent for each of the 5 States having

subdivisions: Alaska, California, Louisiana,

New Mexico, and Texas. For selected

subdivisions within these States, targets of 1.0

percent or 1.5 percent as required to meet the

State target.

n 2.5 percent for each State/subdivision having 1

percent or more of estimated U.S. reserves or

production in 1994 (lower 48 States) for any

product class.

n 4 percent for each State/subdivision having less

than 1 percent of estimated U.S. reserves or

production in 1994 (lower 48 States) for all 3

product classes.

n 8 percent for States not published separately.

The combined production from these States was

less than 0.2 percent of the U.S. total in 1994 for

crude oil and for natural gas.

The volume of production defining the Certainty

stratum, referred to as the cutoff, varies by product or

State/subdivision. The cutoff criteria and sampling

rates are shown in Table F1. The Certainty stratum,

therefore, has three components.

n Category I - Large Operators: Operators who

produced a total of 1.5 million barrels or more of

crude, or 15 billion cubic feet or more of natural

gas, or both in 1994.

n Category II - Intermediate Operators: Operators

who produced a total of at least 400,000 barrels

of crude oil or 2 billion cubic feet of natural gas,

or both, but less than Category I operators in

1994.

n Category III - Small Operators: Operators who

produced less than the Category II operators in

1994, but which were selected with certainty.

Category III operators were subdivided into

operators sampled with certainty (Certainty)

and operators that were randomly sampled

(Noncertainty).

n Certainty - A small operators who satisfied

any of the following criteria based upon their

production shown in the operator frame:

- Operators with annual crude oil

production of 200 thousand barrels or

more, or reserves of 4 million barrels or

more; or annual natural gas production of

1 billion cubic feet or more, or reserves of

20 billion cubic feet or more.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 105
Table F1. 1997 EIA–23 Survey Initial Sample Criteria

Noncertainty Sample

Production Cutoffs Number of

Crude Oil Gas Certainty Single State Multi–State

State and Subdivision (mbbls) (mmcf) Operators Operators Operators

Alabama Onshore. . . . . . . . . . . . . . . . . . . . . 107 1,000 68 2 1

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 12 0 0

Arkansas. . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 1,000 127 20 3

California Unspecified. . . . . . . . . . . . . . . . . . 17 88 12 37 0

California Coastal Region Onshore . . . . . . . 200 1,000 24 1 0

California Los Angeles Basin Onshore . . . . . 200 25 31 2 0

California San Joaquin Basin Onshore. . . . . 200 1,000 46 3 0

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 133 26 7

Florida Onshore . . . . . . . . . . . . . . . . . . . . . . 200 1,000 6 2 0

Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 27 31 37 3

Indiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 1 46 12 2

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85 1,000 241 174 12

Kentucky . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 1,000 33 21 0

Louisiana Unspecified. . . . . . . . . . . . . . . . . . 73 183 3 18 0

Louisiana North. . . . . . . . . . . . . . . . . . . . . . . 13 633 293 40 7

Louisiana South Onshore . . . . . . . . . . . . . . . 70 1,000 256 16 2

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 42 12 2

Mississippi Onshore . . . . . . . . . . . . . . . . . . . 200 1,000 120 11 3

Montana . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 83 11 5

Nebraska . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 2 54 6 0

New Mexico Unspecified . . . . . . . . . . . . . . . 10 13 12 15 0

New Mexico East . . . . . . . . . . . . . . . . . . . . . 200 1,000 141 3 1

New Mexico West . . . . . . . . . . . . . . . . . . . . . 21 1,000 54 1 0

New York . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 1,000 32 48 0

North Dakota. . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 91 3 8

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92 1,000 44 189 3

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . 143 1,000 341 268 18

Pennsylvania . . . . . . . . . . . . . . . . . . . . . . . . 4 1,000 80 31 0

Texas Unspecified . . . . . . . . . . . . . . . . . . . . 7 118 36 257 1

Texas-RRC District 1 . . . . . . . . . . . . . . . . . . 23 800 196 44 8

Texas-RRC District 2 Onshore . . . . . . . . . . . 200 1,000 174 8 9

Texas-RRC District 3 Onshore . . . . . . . . . . . 200 1,000 252 34 12

Texas-RRC District 4 Onshore . . . . . . . . . . . 91 1,000 175 9 8

Texas-RRC District 5 . . . . . . . . . . . . . . . . . . 38 630 98 9 4

Texas-RRC District 6 . . . . . . . . . . . . . . . . . . 200 1,000 184 21 9

Texas-RRC District 7B . . . . . . . . . . . . . . . . . 34 82 223 72 11

Texas-RRC District 7C . . . . . . . . . . . . . . . . . 200 1,000 161 9 4

Texas-RRC District 8 . . . . . . . . . . . . . . . . . . 200 1,000 167 5 2

Texas-RRC District 8A . . . . . . . . . . . . . . . . . 200 1,000 141 2 2

Texas-RRC District 9 . . . . . . . . . . . . . . . . . . 52 1,000 114 12 1

Texas-RRC District 10 . . . . . . . . . . . . . . . . . 200 1,000 123 5 0

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 65 9 1

Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 12 2 0

West Virginia. . . . . . . . . . . . . . . . . . . . . . . . . 5 1,000 62 35 2

Wyoming. . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 152 17 6

Offshore Areas . . . . . . . . . . . . . . . . . . . . . . . 0 0 286 0 0

Other Statesa . . . . . . . . . . . . . . . . . . . . . . . . 125 49 32 24 0

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . b1,690 1,583 b72

aIncludes Arizona, Connecticut, Delaware, Georgia, Idaho, Iowa, Massachusetts, Maryland, Minnesota, Missouri, North Carolina, New

Hampshire, Nevada, New Jersey, Oregon, Rhode Island, South Carolina, South Dakota, Tennessee, Washington, and Wisconsin. bNonduplicative count of operators by States.

Note: Sampling rate was 8 percent except in Alaska, Florida Onshore, Virginia, and Offshore areas where sampling rate was 100 percent.

— = Not applicable.

Source: Energy Information Administration, Office of Oil and Gas.

106 Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
- All other operators with production or

reserves in a State/subdivision that

exceed selected cutoff levels for that

State/subdivision.

- The largest operator in each

State/subdivision regardless of level of

production or reserves.

- Operators with production or reserves of

oil or gas for six or more

State/subdivisions.

n Noncertainties - Small operators not in the

certainty stratum were classified in a

noncertainty stratum and sampled at a rate of

8 percent.

In each State/subdivision the balance between the

number of small certainty operators and the sample

size was determined in an iterative procedure designed

to minimize the number of total respondents. The

iteration for each State/subdivision began with only

the Category I and Category II operators in the

certainty stratum. The size of the sample of small

operators required to meet the target variance was

calculated based on the variance of the volumes of

those operators. For a number of State/subdivisions

with high correlations between frame values across

pairs of consecutive years, an adjusted target variance

was calculated, that utilized the information about the

correlations. This allowed the selection of a smaller

sample that still met the target sampling error criteria.

At each iteration a small operator, beginning with the

largest of the Category III operators, was added to the

certainty group and the required sample size was again

calculated. The procedure of adding one operator at a

time stopped when the proportion of operators to be

sampled at random dropped below 8 percent.

Independent samples of single location operators

(operators who, according to the sampling frame,

operate in only one State/subdivision) were selected

from each State/subdivision using systematic random

sampling.

An additional complexity is introduced because some

small operators selected for the sample in another

region or regions, sometimes report production

volumes in a region in which EIA has no previous

record of production.

State/subdivision volume estimates are calculated as

the sum of the certainty strata and all of the estimates

for the sampling strata in that region. The sampling

variance of the estimated total is the sum of the

sampling variances for the sampling strata. There is no

sampling error associated with the certainty stratum.

The square root of the sampling variance is the

standard error. It can be used to provide confidence

intervals for the State/subdivision totals.

For the States in which subdivision volume estimates

are published, the State total is the sum of the

individual volume estimates for the subdivisions. The

U.S. total is the sum of the State estimates. A sampling

variance is calculated for each State subdivision, State,

and for the U.S. total.

Total U.S. Reserve Estimates

Conceptually, the estimates of U.S. reserves and

production can be thought of as the sum of the

estimates for the individual States. Correspondingly,

the estimates for the four States for which estimates are

published separately by subdivision (California,

Louisiana, New Mexico, and Texas) can be thought of

as the sum of the estimates by subdivision. The

remaining States are not subdivided and may be

considered as a single subdivision.

The estimates of year-end proved reserves and annual

production for any State/subdivision is the sum of the

volumes in the State/subdivision reported by the

certainty stratum operators and an estimate of the total

volume in the State/subdivision by the noncertainty

stratum operators. Mathematically, this may be stated

as the following sum:

VV V $ $

s sc sr = +

where

V$

s = estimated total volume in the

State/subdivision

Vsc = total volume in the State/subdivision

reported by Certainty operators

V$

sr = estimated total volume in the

State/subdivision of Noncertainty

operators.

The total volume of Certainty operators in the

State/subdivision is simply the sum of individual

operator's volumes:

V V sc

m

n

scm

sc

= =

∑

1

where

nsc = number of Certainty operators reporting

production in the State/subdivision

Vscm =

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 107
volume reported by the m-th certainty

stratum operator in the State/subdivision.

The estimated total volume of Noncertainty operators

in the State/subdivision is the weighted sum of the

reports of the noncertainty sample operators:

V WV $

sr

m

n

srm srm

sr

= =

∑

1

where

nsr = number of Noncertainty operators

reporting production in the

State/subdivision

Vsrm = volume reported by the m-th

Noncertainty sample operator in the

State/subdivision

Wsrm = weight for the report by the m-th

Noncertainty sample operator reporting

production in the State/subdivision.

In many State/subdivisions, the accuracy of the oil and

gas estimates was improved by using a difference

estimator for many of the Noncertainty operators. This

difference estimator took advantage of the stability of

production reports from year-to-year in those

State/subdivisions. The difference estimator was only

applied to operators who had known production

greater than 1 thousand barrels of oil and/or 1 million

cubic feet of natural gas in the previous year. For those

State/subdivisions and operators the above formula

was modified with Vsrm replaced by V'srm:

V V kx X srm srm sr srm ' () =+−

where

k = 1 when estimating production volumes

k = regional R/P ratio (Table F6) when

estimating reserve volumes

Xsr = average production volume reported in

the State/subdivision for the preceding

year by all qualifying Noncertainty

operators

Xsrm = production volume reported by the m-th

Noncertainty sample operator in the

State/subdivision for the preceding year.

In selecting the Noncertainty sample, the number of

sample operators with production in a given

State/subdivision is not controlled to the number

expected based on the sampling rate, but is subject to

some variation. The weight used is the reciprocal of the

actual sampling rate that resulted for the stratum from

which the sample operator was selected, rather than

the reciprocal of the expected sampling rate. The

sample estimate with either set of weights is an

unbiased estimator of the noncertainty stratum total.

However, use of the actual sampling rates is expected

to lead to smaller sampling errors for the estimates. In

making estimates for a State/subdivision, separate

weights are applied as appropriate for Noncertainty

operators shown in the frame as having had

production in only the State/subdivision, for those

shown as having had production in that

State/subdivision and up to four other

States/subdivisions, and for operators with no

previous record of production in the

State/subdivision. National totals were then obtained

by summation of the component totals.

Imputation for Operator Nonresponse

The response rate for Certainty operators for the 1997

survey was 100 percent. Due to the 100 percent

response rate, imputation for the nonresponding

operators was not necessary.

Imputation and Estimation for

Reserves Data

In order to estimate reserve balances for National and

State/subdivision levels, a series of imputation and

estimation steps at the operator level must be carried

out. Year-end reserves for operators who provided

production data only were imputed on the basis of

their production volumes. Imputation was also applied

to the small and intermediate operators as necessary to

provide data on each of the reserve balance categories

(i.e., revisions, extensions, or new discoveries). Finally,

an imputation was required for the natural gas data of

the small operators to estimate their volumes of

associated-dissolved and nonassociated natural gas.

The final manipulation of the data accounts for the

differences caused by different sample frames from

year to year. Each of these imputations generated only

a small percentage of the total estimates. The methods

used are discussed in the following sections.

The actual data reported on an operated basis by Form

EIA-23 respondents for the report year 1997 are

summarized in Tables F2, F3, F4, and F5. The

differences between these sums and the total estimates

shown in Tables 9, 10, 6 and 16 in the main text

Energy Information Administration

108 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
Energy Information Administration 109

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table F2. Summary of Total Natural Gas, Wet After Lease Separation, Used in Estimation Process,

Form EIA-23 (Million Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

Operator Category

NonCertainty certainty

Level of Reporting I II III III Total

Field Level Reported and Imputed Data

Proved Reserves as of 12/31/96. . . . . . . . . . . . . 146,168,261 12,586,503 1,573,141 — 160,327,905

(+) Revision Increases . . . . . . . . . . . . . . . . . . . . 18,994,658 1,586,968 107,048 — 20,688,674

(–) Revision Decreases . . . . . . . . . . . . . . . . . . . 14,926,891 1,109,696 70,783 — 16,107,370

(+)Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . 9,444,366 602,264 201,554 — 10,248,184

(+) New Field Discoveries . . . . . . . . . . . . . . . . . 2,408,191 213,562 33,000 — 2,654,753

(+) New Reservoirs in Old Fields . . . . . . . . . . . . 2,118,852 167,369 28,831 — 2,315,052

(–) Production With Reserves in 1997 . . . . . . . . 16,897,056 1,318,388 155,808 — 18,371,252

Proved Reserves Reported as of 12/31/97. . . . . 147,490,429 12,729,154 1,716,983 — 161,936,566

Production Without Proved Reserves. . . . . . . . . 0 574,585 74,224 — 648,809

Reserves Imputed for Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 0 4,378,268 541,666 — 4,919,934

Subtotal Production . . . . . . . . . . . . . . . . . . . . . 16,897,056 1,892,973 230,032 — 19,020,061

Subtotal Proved Reserves 1997 . . . . . . . . . . . 147,490,429 17,107,422 2,258,649 — 166,856,500

State Level Reported and Imputed Data

Production With Proved Reserves . . . . . . . . . . . 63 47,819 141,080 12,410 201,372

Production Without Proved Reserves. . . . . . . . . 0 32,401 224,185 40,498 297,084

Subtotal Production. . . . . . . . . . . . . . . . . . . . . . . 63 80,220 365,265 52,908 498,456

Weighted Subtotal Production . . . . . . . . . . . . 63 80,220 365,265 678,980 1,124,528

Proved Reserves Reported. . . . . . . . . . . . . . . . . 397 376,683 1,335,723 93,647 1,806,450

Reserves Imputed for Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 0 227,663 1,685,552 311,987 2,225,202

Subtotal Proved Reserves . . . . . . . . . . . . . . . . . 397 604,346 3,021,205 405,634 4,031,582

Weighted Subtotal Proved Reserves . . . . . . . 397 604,346 3,021,205 5,244,768 8,870,716

Total Production in 1997 . . . . . . . . . . . . . . . . . . . 16,897,119 1,973,193 595,297 678,980 20,144,589

Total Proved Reserves as of 12/31/97 . . . . . . . . . 147,490,826 17,711,768 5,279,854 5,244,768 175,727,216

– = Not applicable.

Notes: Table 9 totals include imputed and estimated wet natural gas proved reserves rounded at the State/subdivision level. Field level

data are reported volumes and may not balance due to submission of incomplete reserve component records.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1997.
110 Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table F3. Summary of Nonassociated Natural Gas, Wet After Lease Separation, Used in

Estimation Process, Form EIA-23 (Million Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

Operator Category

NonCertainty certainty

Level of Reporting I II III III Total

Field Level Detail Report

Proved Reserves as of 12/31/96. . . . . . . . . . . . . 119,365,554 10,869,057 1,366,076 — 131,600,687

(+) Revision Increases . . . . . . . . . . . . . . . . . . . . 14,734,037 1,290,719 96,731 — 16,121,487

(–) Revision Decreases . . . . . . . . . . . . . . . . . . . 12,169,811 888,206 61,996 — 13,120,013

(+)Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . 8,589,214 553,532 122,047 — 9,264,793

(+) New Field Discoveries . . . . . . . . . . . . . . . . . 1,052,849 209,565 33,000 — 1,295,414

(+) New Reservoirs in Old Fields . . . . . . . . . . . . 1,950,622 163,303 21,298 — 2,135,223

(–) Production With Reserves in 1997 . . . . . . . . 14,381,927 1,123,137 118,786 — 15,623,850

Proved Reserves Reported as of 12/31/97. . . . . 119,140,568 11,075,137 1,458,370 — 131,674,075

Production Without Proved Reserves. . . . . . . . . 0 493,355 62,391 — 555,746

Reserves Imputed for Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 0 3,781,517 463,530 — 4,245,047

Subtotal Production . . . . . . . . . . . . . . . . . . . . . 14,381,927 1,616,492 181,177 — 16,179,596

Subtotal Proved Reserves 1997 . . . . . . . . . . . 119,140,568 14,856,654 1,921,900 — 135,919,122

State Level Reported and Imputed Data

Production With Proved Reserves . . . . . . . . . . . — — — — —

Production Without Proved Reserves. . . . . . . . . — — — — —

Subtotal Production. . . . . . . . . . . . . . . . . . . . . . . — — — — —

Weighted Subtotal Production . . . . . . . . . . . . — — — — —

Proved Reserves Reported. . . . . . . . . . . . . . . . . — — — — —

Reserves Imputed for Production

Without Proved Reserves . . . . . . . . . . . . . . . . . — — — — —

Subtotal Proved Reserves . . . . . . . . . . . . . . . . . — — — — —

Weighted Subtotal Proved Reserves . . . . . . . — — —— —

Total Production in 1997 . . . . . . . . . . . . . . . . . . . 14,381,927 1,616,492 181,177 — 16,179,596

Total Proved Reserves as of 12/31/97 . . . . . . . . . 119,140,568 14,856,654 1,921,900 — 135,919,122

– = Not applicable.

Notes: Table 10 totals include imputed and estimated wet natural gas proved reserves rounded at the State/subdivision level. Field level

data are reported volumes and may not balance due to submission of incomplete reserve component records.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1997.
Energy Information Administration 111

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table F4. Summary of Crude Oil Used in Estimation Process, Form EIA-23

(Thousand Barrels of 42 U.S. Gallons)

Operator Category

NonCertainty certainty

Level of Reporting I II III III Total

Field Level Detail Report

Proved Reserves as of 12/31/96. . . . . . . . . . . . . 19,347,430 1,071,988 156,225 — 20,575,643

(+) Revision Increases . . . . . . . . . . . . . . . . . . . . 1,567,972 168,843 10,543 — 1,747,358

(–) Revision Decreases . . . . . . . . . . . . . . . . . . . 799,058 83,813 11,890 — 894,761

(+)Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . 362,706 13,137 27,047 — 402,890

(+) New Field Discoveries . . . . . . . . . . . . . . . . . 630,774 2,092 0 — 632,866

(+) New Reservoirs in Old Fields . . . . . . . . . . . . 110,474 3,453 979 — 114,906

(–) Production With Reserves in 1997 . . . . . . . . 1,759,703 109,062 14,030 — 1,882,795

Proved Reserves Reported as of 12/31/97. . . . . 19,460,604 1,066,684 168,874 — 20,696,162

Production Without Proved Reserves. . . . . . . . . 0 36,491 10,243 — 46,734

Reserves Imputed for Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 0 248,886 72,202 — 321,088

Subtotal Production . . . . . . . . . . . . . . . . . . . . . 1,759,703 145,553 24,273 — 1,929,529

Subtotal Proved Reserves 1997 . . . . . . . . . . . 19,460,604 1,315,570 241,076 — 21,017,250

State Level Reported and Imputed Data

Production With Proved Reserves . . . . . . . . . . . 5 6,868 29,202 1,983 38,058

Production Without Proved Reserves. . . . . . . . . 0 4,332 46,865 7,583 58,780

Subtotal Production. . . . . . . . . . . . . . . . . . . . . . . 5 11,200 76,034 9,566 96,805

Weighted Subtotal Production . . . . . . . . . . . . 5 11,200 76,034 123,609 210,848

Proved Reserves Reported. . . . . . . . . . . . . . . . . 50 51,907 236,811 16,010 304,778

Reserves Imputed for Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 0 30,430 321,373 53,326 405,129

Subtotal Proved Reserves . . . . . . . . . . . . . . . . . 50 82,337 558,184 69,336 709,907

Weighted Subtotal Proved Reserves . . . . . . . 50 82,337 564,529 893,522 1,540,438

Total Production in 1997 . . . . . . . . . . . . . . . . . . . 1,759,708 156,753 100,307 123,609 2,140,377

Total Proved Reserves as of 12/31/97 . . . . . . . . . 19,460,654 1,397,907 805,605 893,522 22,557,688

– = Not applicable.

Notes: Table 6 totals include imputed and estimated wet natural gas proved reserves rounded at the State/subdivision level. Field level

data are reported volumes and may not balance due to submission of incomplete reserve component records.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1997.
112 Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table F5. Summary of Lease Condensate Used in Estimation Process, Form EIA-23

(Thousand Barrels of 42 U.S. Gallons)

Operator Category

NonCertainty certainty

Level of Reporting I II III III Total

Field Level Detail Report

Proved Reserves as of 12/31/96. . . . . . . . . . . . . 1,141,581 90,203 8,454 — 1,240,238

(+) Revision Increases . . . . . . . . . . . . . . . . . . . . 195,410 19,558 1,075 — 216,043

(–) Revision Decreases . . . . . . . . . . . . . . . . . . . 224,356 20,609 737 — 245,702

(+)Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . 97,051 7,660 317 — 105,028

(+) New Field Discoveries . . . . . . . . . . . . . . . . . 53,026 6,405 94 — 59,525

(+) New Reservoirs in Old Fields . . . . . . . . . . . . 35,245 692 1,104 — 37,041

(–) Production With Reserves in 1997 . . . . . . . . 148,778 12,536 1,021 — 162,335

Proved Reserves Reported as of 12/31/97. . . . . 1,149,187 91,387 9,286 — 1,249,860

Production Without Proved Reserves. . . . . . . . . 0 4,342 478 — 4,820

Reserves Imputed for Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 0 30,408 3,380 —

Subtotal Production . . . . . . . . . . . . . . . . . . . . . 148,778 16,878 1,499 — 167,155

Subtotal Proved Reserves 1997 . . . . . . . . . . . 1,149,187 121,795 12,666 — 1,283,648

State Level Reported and Imputed Data

Production With Proved Reserves . . . . . . . . . . . 0 293 1,293 61 1,647

Production Without Proved Reserves. . . . . . . . . 0 1,003 1,075 344 2,422

Subtotal Production. . . . . . . . . . . . . . . . . . . . . . . 0 1,296 2,368 405 4,069

Weighted Subtotal Production . . . . . . . . . . . . 0 1,296 2,368 5,435 9,099

Proved Reserves Reported. . . . . . . . . . . . . . . . . 1 2,747 7,758 273 10,779

Reserves Imputed for Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 0 7,557 7,623 2,383 17,563

Subtotal Proved Reserves . . . . . . . . . . . . . . . . . 1 10,304 15.381 2,656 28,342

Weighted Subtotal Proved Reserves . . . . . . . 1 10,304 15,381 35,635 61,321

Total Production in 1997 . . . . . . . . . . . . . . . . . . . 148,778 18,174 3,867 5,435 176,254

Total Proved Reserves as of 12/31/97 . . . . . . . . . 1,149,188 132,099 28,047 35,635 1,344,969

– = Not applicable.

Notes: Table 16 totals include imputed and estimated wet natural gas proved reserves rounded at the State/subdivision level. Field level

data are reported volumes and may not balance due to submission of incomplete reserve component records.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1997.
and imputation performed by EIA. The reported data

in Table F2 shows that those responding operators

accounted for 97.5 percent of the published production

for natural gas shown in Table 9 and 93.9 percent of the

reserves. Data shown in Table F3 indicate that those

responding operators accounted for 94.5 percent of the

nonassociated natural gas production and 92.5 percent

of the reserves published in Table 10. The reported

data shown in Table F4 indicate that those responding

operators accounted for 95.1 percent of published

crude oil production and 94.1 percent of the reserves

shown in Table 6. Additionally, Table F5 indicates that

those responding operators accounted for 99.4 percent

of the published production and 99.3 percent of the

published proved reserves for lease condensate shown

in Table 16.

Imputation of Year-End Proved Reserves

Category I operators were required to submit year-end

estimates of proved reserves. Category II and Category

III operators were required to provide year-end

estimates of proved reserves only if such estimates

existed in their records. Some of these respondents

provided estimates for all of their operated properties,

others provided estimates for only a portion of their

properties, and still others provided no estimates for

any of their properties. All respondents did, however,

provide annual production data. The production

reported by Noncertainty sample operators and the

corresponding reserves imputed were weighted to

estimate the full noncertainty stratum when calculating

reserves and production as previously described in the

section “Total U.S. Reserves Estimates” in this

appendix.

A year-end proved reserves estimate was imputed in

each case where an estimate was not provided by the

respondent. Reserves were imputed from reported

production data for all Noncertainty operators. The

reported annual production was multiplied by a

reserves-to-production (R/P) ratio (Table F6)

characteristic of operators of similar size in the region

where the properties were located. The regional R/P

ratios in this report are averages calculated by dividing

the mean of reported reserves by the mean of reported

production for selected respondents of similar size who

did report estimated reserves. A cutoff level for each

region was determined based upon the largest

Certainty operator that reported production, but did

not provide a reserve estimate. Data from respondents

whose production in a region exceeded the regional

cutoff level was excluded from the R/P ratio

calculation for that region. In addition, operators that

had R/P ratios that exceeded 25 to 1 and Category I

operators were excluded from the respondents selected

to calculate the characteristic regional R/P ratio. All

other respondents who reported both production and

reserves were used to calculate the regional R/P ratio

characteristic.

The R/P ratio varied significantly from region to

region. This variation was presumably in response to

variation in geologic conditions and the degree of

development of crude oil and natural gas resources in

each area. The average R/P ratio was computed for

regional areas similar to the National Petroleum

Council regional units (Figure F1). These units

generally follow the boundaries of geologic provinces

wherein the stage of resource development tends to be

somewhat similar. Table F6 lists the R/P ratio

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 113

Table F6. Statistical Parameters of Reserve Estimation Equation by Region for 1997

Number of Nonzero R/P Pairs Characteristic Multipliers

Region Lease Lease

Number Region Oil Gas Condensate Oil Gas Condensate

2 Pacific Coast States . . . . . . . . . . . 16 24 1 a6.9 5.5 a7.1

3 Western Rocky Mountains . . . . . . . . 48 51 14 7.3 9.6 a7.1

4 Northern Rocky Mountains . . . . . . . . 61 53 5 7.9 8.1 a7.1

5 West Texas and East New Mexico . . . . 194 185 43 7.5 7.0 a7.1

6 + 6A Western Gulf Basin and Gulf of Mexico . . 230 195 160 6.5 6.7 6.9

7 Mid-Continent . . . . . . . . . . . . . . 190 141 62 6.3 7.5 7.9

8 + 9 Michigan Basin and Eastern Interior . . . 44 26 7 6.7 8.7 a7.1

10 + 11 Appalachians . . . . . . . . . . . . . . 22 27 1 7.3 11.5 a7.1

United States . . . . . . . . . . . . . . 805 702 293 6.9 7.5 7.1

aMultiplier of the U.S. national average is assumed. Effect of the multiplier on the related natural gas or lease condensate reserves esti- mate is negligible in these regions.

Source: Based on data filed on Form EIA-23,"Annual Survey of Domestic Oil and Gas Reserves, 1997".
calculated for each region that required such

imputations and the number of observations on which

it was based.

The regional R/P ratio is determined primarily to

provide a factor that can be applied to the production

reported by operators without reserve estimates to

provide an estimate of the reserves of these operators

when aggregated to the regional level. The average

R/P ratio, when multiplied by each individual

production in the distribution of R,P pairs used to

calculate it, will exactly reproduce the sum of the

reported reserves in the distribution.

Imputation of Annual Changes to Proved

Reserves by Component of Change

Category II and Category III operators that do not keep

reserves data were not asked to provide estimates of

beginning-of-year reserves or annual changes to

proved reserves by component of change, i.e.,

revisions, extensions, and discoveries. When they did

not provide estimates, these volumes were estimated

by applying an algebraic allocation scheme which

preserved the relative relationships between these

items within each State/subdivision, as reported by

Category I and Category II operators, and also

preserved an exact annual reserves balance of the

following form:

A ratio was calculated as the sum of the annual

production and year-end proved reserves of those

Energy Information Administration

114 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Figure F1. Form EIA-23 Regional Boundaries

Published Proved Reserves at End of Previous Report Year

+ Adjustments

+ Revision Increases

– Revision Decreases

+ Extensions

+ New Field Discoveries

+ New Reservoir Discoveries in Old Fields

– Report Year Production

= Published Proved Reserves at End of Report Year
respondents who did not provide the reserves balance

components, divided by the sum of year-end proved

reserves and annual production of those respondents

of similar size who did provide these quantities. This

ratio was then multiplied by each of the reserves

balance components reported by Category I and some

Category II operators, to obtain imputed volumes for

the reserves balances of the other Category II operators

and Certainty and Noncertainty operators. These were

then added to the State/subdivision totals.

Imputation of Natural Gas Type Volumes

Operators in the State/subdivision certainty and

noncertainty strata were not asked to segregate their

natural gas volumes by type of natural gas, i.e.,

nonassociated natural gas (NA) and

associated-dissolved natural gas (AD). The total

estimated year-end proved reserves of natural gas and

the total annual production of natural gas reported by,

or imputed to, operators in the State/subdivision

certainty and noncertainty strata were, therefore,

subdivided into the NA and AD categories, by

State/subdivision, in the same proportion as was

reported by Category I and Category II operators in the

same area.

Adjustments

The instructions for Schedule A of Form EIA-23 specify

that, when reporting reserves balance data, the

following arithmetic equation must hold:

Any remaining difference in the State/subdivision

annual reserves balance between the published

previous year-end proved reserves and current

year-end proved reserves not accounted for by the

imputed reserves changes was included in the

adjustments for the area. One of the primary reasons

that adjustments are necessary is that very few of the

same Noncertainty operators are sampled each year.

Less than 8 percent of the Noncertainty stratum

operators sampled in 1995 were sampled again in 1997,

and there is no guarantee that in the smaller producing

States/subdivision the same number of small

operators will be selected each year, or that the

operators selected will be of comparable sizes when

paired with operators selected in a prior year. Thus,

some instability of this stratum from year to year is

unavoidable, resulting in minor adjustments.

Some of the adjustments are, however, more

substantial, and could be required for any one or more

of the following reasons:

n The frame coverage may or may not have

improved between survey years, such that more

or fewer Certainty operators were included in

1997 than in 1996.

n One or more operators may have reported data

incorrectly on Schedule A in 1996 or 1997, but

not both, and the error was not detected by edit

processing.

n Operation of properties was transferred during

1997 from operators not in the frame or

Noncertainty operators not selected for the

sample to Certainty operators or Noncertainty

operators selected for the sample.

n Operations of properties was transferred

during 1997 to an operator with a different

evaluation of the proved reserves associated

with the properties than that of the 1996

operator.

n Respondent changed classification of natural

gas from NA to AD or vice versa.

n The trend in reserve changes imputed for the

small operators, that was based on the trend

reported by the large operators, did not reflect

the actual trend for the small operators.

n Noncertainty operators, who have grown

substantially in size since they were added to

the frame, occasionally cause a larger standard

error than expected.

n The Noncertainty sample for either year in a

state may have been an unusual one.

The causes of adjustments are known for some but not

all areas. The only problems whose effects cannot be

expected to balance over a period of several years are

those associated with an inadequate frame or those

associated with any actual trend in reserve changes for

small operators not being the same as those for large

operators. EIA continues to attempt to improve sources

of operator data to resolve problems in frame

completeness.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 115

Proved Reserves at End of Previous Year

+ Revision Increases

– Revision Decreases

+ Extensions

+ New Field Discoveries

+ New Reservoir Discoveries in Old Fields

– Report Year Production

= Proved Reserves at End of Report Year
Sampling Reliability of the Estimates

The sample of Noncertainty operators selected is only

one of the large number of possible samples that could

have been selected and each would have resulted in

different estimates. The standard error or sampling

error of the estimates provides a measure of this

variability. When probability sampling methods are

used, as in the EIA-23 survey, the sampling error of

estimates can also be estimated from the survey data.

The estimated sampling error can be used to compute a

confidence interval around the survey estimate, with a

prescribed degree of confidence that the interval covers

the value that would have been obtained if all operators

in the frame had been surveyed. If the estimated

volume is denoted byV$

s and its sampling error by S.E. (

V$

s ), the confidence interval can be expressed as:

$ . .( $ V kSE V ) s s + −

where k is a multiple selected to provide the desired

level of confidence. For this survey, k was taken equal

to 2. Then there is approximately 95 percent confidence

that the interval:

$ . .( $ V SE V ) s s + − 2

includes the universe value, for both the estimates of

reserves and production volumes. Correspondingly,

for approximately 95 percent of the estimates in this

report, the difference between the published estimate

and the value that would be found from a complete

survey of all operators is expected to be less than twice

the sampling error of the estimate. Tables F7, F8, F9,

and F10 provide estimates for 2S.E. (V$

s ) by product.

These estimates are directly applicable for constructing

approximate 95 percent confidence intervals. For

example, the 95 percent confidence interval for dry

natural gas proved reserves is 165,146 ± 575 billion

cubic feet. The sampling error of V$

s is equal to the

sampling error of the noncertainty estimate V$

sr ,

because the certainty total is not subject to sampling

error. The estimated sampling error of a noncertainty

estimate is the square root of its estimated sampling

variance.

The noncertainty estimate for a given

State/subdivision had two separately weighted

components based on reports of:

n Type 1 Operators shown in the frame as having

had crude oil or natural gas production in the

State/subdivision.

n Type 2 Operators shown in the frame as having

had no crude oil or natural gas production in the

State/subdivision.

Correspondingly, the sampling variance had two

components associated with the estimated production

from each component:

Var V Var V Var V sr sr sr ( $ ) ( $ ) ( $ = + ) 1 2

The Var(Vsr) was estimated as the sum of the estimated

variances of the two component estimates. The

variance for any component, say component j, was

estimated from the formula:

Var V n

W

W srj srj S srj

srj

srj ( $ ) =  −



 





1

2

In general, V$

srj denotes the production estimate from

component j for each of the two types of operator, and

Var Vsrj (

^

) denotes its variance where

nsrj = number of operators in sample in

component j

wsrj = weight for operator reports in component j

S2

srj = variance between operator reports in

component j.

If the subscripts sr are dropped, S2

srj can be expressed

as:

S j

V ji V n

n

i

n

i

n

ji j

j

j j

2

2

2

1 =

′− ′ 



 





−

∑ ∑

where

V ji ′ = weighted production or reserves volume

for the i-th sample operator in the

component j.

The variance of the estimated total volume for a State

having subdivisions is the sum of corresponding Type

1 and Type 2 components where the classification of

operators by type is with regard to the State as a whole;

e.g., Type 2 operators at the State level are those that

were not shown in the sample frame as having

production anywhere in the State.

Energy Information Administration

116 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
Energy Information Administration 117

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table F7. Factors for Confidence Intervals (2S.E.) for Dry Natural Gas Proved Reserves and Production,

1997 (Billion Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

1997 1997 1997 1997

State and Subdivision Reserves Production State and Subdivision Reserves Production

United States . . . . . . . . . . . . . . . . . . 791 101

Alabama. . . . . . . . . . . . . . . . . . . . . . 19 3

Alaska . . . . . . . . . . . . . . . . . . . . . . . 0 0

Arkansas . . . . . . . . . . . . . . . . . . . . . 32 4

California . . . . . . . . . . . . . . . . . . . . . 47 11

Coastal Region Onshore. . . . . . . 0 0

Los Angeles Basin Onshore . . . . 3 0

San Joaquin Basin Onshore . . . . 95 20

State Offshore. . . . . . . . . . . . . . . 0 0

Colorado . . . . . . . . . . . . . . . . . . . . . 75 8

Florida . . . . . . . . . . . . . . . . . . . . . . . 0 0

Kansas. . . . . . . . . . . . . . . . . . . . . . . 138 18

Kentucky . . . . . . . . . . . . . . . . . . . . . 58 7

Louisiana . . . . . . . . . . . . . . . . . . . . . 119 18

North . . . . . . . . . . . . . . . . . . . . . . 43 6

South Onshore . . . . . . . . . . . . . . 103 15

State Offshore. . . . . . . . . . . . . . . 0 0

Michigan . . . . . . . . . . . . . . . . . . . . . 96 11

Mississippi . . . . . . . . . . . . . . . . . . . . 26 5

Montana. . . . . . . . . . . . . . . . . . . . . . 12 2

New Mexico . . . . . . . . . . . . . . . . . . . 125 14

East. . . . . . . . . . . . . . . . . . . . . . . 12 3

West . . . . . . . . . . . . . . . . . . . . . . 0 0

New York . . . . . . . . . . . . . . . . . . . . . 72 7

North Dakota . . . . . . . . . . . . . . . . . . 10 1

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . 141 15

Oklahoma . . . . . . . . . . . . . . . . . . . . 311 40

Pennsylvania . . . . . . . . . . . . . . . . . . 174 15

Texas. . . . . . . . . . . . . . . . . . . . . . . . 435 65

RRC District 1 . . . . . . . . . . . . . . . 17 3

RRC District 2 Onshore . . . . . . . 123 18

RRC District 3 Onshore . . . . . . . 86 13

RRC District 4 Onshore . . . . . . . 178 26

RRC District 5 . . . . . . . . . . . . . . . 9 3

RRC District 6 . . . . . . . . . . . . . . . 137 20

RRC District 7B. . . . . . . . . . . . . . 28 4

RRC District 7C. . . . . . . . . . . . . . 61 9

RRC District 8 . . . . . . . . . . . . . . . 13 2

RRC District 8A. . . . . . . . . . . . . . 0 0

RRC District 9 . . . . . . . . . . . . . . . 12 2

RRC District 10 . . . . . . . . . . . . . . 12 2

State Offshore. . . . . . . . . . . . . . . 0 0

Utah . . . . . . . . . . . . . . . . . . . . . . . . . 11 1

Virginia. . . . . . . . . . . . . . . . . . . . . . . 0 0

West Virginia . . . . . . . . . . . . . . . . . . 249 11

Wyoming . . . . . . . . . . . . . . . . . . . . . 287 35

Federal Offshorea . . . . . . . . . . . . . . 0 0

Pacific (California). . . . . . . . . . . . 0 0

Gulf of Mexico (Louisiana)a . . . . 0 0

Gulf of Mexico (Texas) . . . . . . . . 0 0

Miscellaneousb . . . . . . . . . . . . . . . . 10 1

aIncludes Federal offshore Alabama. bIncludes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, Oregon, South Dakota, and Tennessee.

Notes: Confidence intervals are associated with Table 8 reserves and production data. Factors for confidence intervals for each State

subdivision, State, and the United States are independently estimated and do not add.

Source: Factor estimates based on data filed on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1997 and Form

EIA-64A, “Annual Report of the Origin of Natural Gas Liquids Production,” 1997.

Table F8. Factors for Confidence Intervals (2S.E.) for Natural Gas Proved Reserves and Production,

Wet After Lease Separation, 1997 (Billion Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

1997 1997 1997 1997

State and Subdivision Reserves Production State and Subdivision Reserves Production

United States . . . . . . . . . . . . . . . . . . 836 107

Alabama. . . . . . . . . . . . . . . . . . . . . . 20 3

Alaska . . . . . . . . . . . . . . . . . . . . . . . 0 0

Arkansas . . . . . . . . . . . . . . . . . . . . . 32 4

California . . . . . . . . . . . . . . . . . . . . . 50 12

Coastal Region Onshore. . . . . . . 0 0

Los Angeles Basin Onshore . . . . 3 0

San Joaquin Basin Onshore . . . . 100 21

State Offshore. . . . . . . . . . . . . . . 0 0

Colorado . . . . . . . . . . . . . . . . . . . . . 84 9

Florida . . . . . . . . . . . . . . . . . . . . . . . 0 0

Kansas. . . . . . . . . . . . . . . . . . . . . . . 145 19

Kentucky . . . . . . . . . . . . . . . . . . . . . 60 8

Louisiana . . . . . . . . . . . . . . . . . . . . . 124 19

North . . . . . . . . . . . . . . . . . . . . . . 44 7

South Onshore . . . . . . . . . . . . . . 108 16

State Offshore. . . . . . . . . . . . . . . 0 0

Michigan . . . . . . . . . . . . . . . . . . . . . 98 11

Mississippi . . . . . . . . . . . . . . . . . . . . 26 5

Montana. . . . . . . . . . . . . . . . . . . . . . 12 2

New Mexico . . . . . . . . . . . . . . . . . . . 138 15

East. . . . . . . . . . . . . . . . . . . . . . . 14 3

West . . . . . . . . . . . . . . . . . . . . . . 0 0

New York . . . . . . . . . . . . . . . . . . . . . 72 7

North Dakota . . . . . . . . . . . . . . . . . . 12 1

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . 141 15

Oklahoma . . . . . . . . . . . . . . . . . . . . 332 42

Pennsylvania . . . . . . . . . . . . . . . . . . 175 15

Texas. . . . . . . . . . . . . . . . . . . . . . . . 465 70

RRC District 1 . . . . . . . . . . . . . . . 18 3

RRC District 2 Onshore . . . . . . . 131 19

RRC District 3 Onshore . . . . . . . 91 14

RRC District 4 Onshore . . . . . . . 187 27

RRC District 5 . . . . . . . . . . . . . . . 9 3

RRC District 6 . . . . . . . . . . . . . . . 144 21

RRC District 7B. . . . . . . . . . . . . . 32 5

RRC District 7C. . . . . . . . . . . . . . 69 10

RRC District 8 . . . . . . . . . . . . . . . 15 2

RRC District 8A. . . . . . . . . . . . . . 0 0

RRC District 9 . . . . . . . . . . . . . . . 15 2

RRC District 10 . . . . . . . . . . . . . . 13 2

State Offshore. . . . . . . . . . . . . . . 0 0

Utah . . . . . . . . . . . . . . . . . . . . . . . . . 13 1

Virginia. . . . . . . . . . . . . . . . . . . . . . . 0 0

West Virginia . . . . . . . . . . . . . . . . . . 257 12

Wyoming . . . . . . . . . . . . . . . . . . . . . 303 37

Federal Offshorea . . . . . . . . . . . . . . 0 0

Pacific (California). . . . . . . . . . . . 0 0

Gulf of Mexico (Louisiana)a . . . . 0 0

Gulf of Mexico (Texas) . . . . . . . . 0 0

Miscellaneousb . . . . . . . . . . . . . . . . 10 1

aIncludes Federal offshore Alabama. bIncludes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, Oregon, South Dakota, and Tennessee.

Notes: Confidence intervals are associated with Table 9 reserves and production data. Factors for confidence intervals for each State

subdivision, State, and the United States are independently estimated and do not add.

Source: Factor estimates based on data filed on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1997.
118 Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Table F9. Factors for Confidence Intervals (2S.E.) for Crude Oil Proved Reserves and Production, 1997

(Million Barrels of 42 U.S. Gallons)

1997 1997 1997 1997

State and Subdivision Reserves Production State and Subdivision Reserves Production

United States . . . . . . . . . . . . . . . . . . 108 13

Alabama. . . . . . . . . . . . . . . . . . . . . . 2 0

Alaska . . . . . . . . . . . . . . . . . . . . . . . 0 0

Arkansas . . . . . . . . . . . . . . . . . . . . . 3 1

California . . . . . . . . . . . . . . . . . . . . . 27 3

Coastal Region Onshore. . . . . . . 0 0

Los Angeles Basin Onshore . . . . 2 0

San Joaquin Basin Onshore . . . . 24 0

State Offshore. . . . . . . . . . . . . . . 0 0

Colorado . . . . . . . . . . . . . . . . . . . . . 11 1

Florida . . . . . . . . . . . . . . . . . . . . . . . 0 0

Illinois. . . . . . . . . . . . . . . . . . . . . . . . 12 2

Indiana. . . . . . . . . . . . . . . . . . . . . . . 2 0

Kansas. . . . . . . . . . . . . . . . . . . . . . . 18 3

Kentucky . . . . . . . . . . . . . . . . . . . . . 33 0

Louisiana . . . . . . . . . . . . . . . . . . . . . 17 2

North . . . . . . . . . . . . . . . . . . . . . . 2 0

South Onshore . . . . . . . . . . . . . . 12 2

State Offshore. . . . . . . . . . . . . . . 0 0

Michigan . . . . . . . . . . . . . . . . . . . . . 9 1

Mississippi . . . . . . . . . . . . . . . . . . . . 6 1

Montana. . . . . . . . . . . . . . . . . . . . . . 10 1

Nebraska . . . . . . . . . . . . . . . . . . . . . 6 0

New Mexico . . . . . . . . . . . . . . . . . . . 10 1

East. . . . . . . . . . . . . . . . . . . . . . . 10 1

West . . . . . . . . . . . . . . . . . . . . . . 0 0

North Dakota . . . . . . . . . . . . . . . . . . 10 1

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . 11 1

Oklahoma . . . . . . . . . . . . . . . . . . . . 38 5

Pennsylvania . . . . . . . . . . . . . . . . . . 1 0

Texas. . . . . . . . . . . . . . . . . . . . . . . . 70 9

RRC District 1 . . . . . . . . . . . . . . . 5 1

RRC District 2 Onshore . . . . . . . 5 1

RRC District 3 Onshore . . . . . . . 14 2

RRC District 4 Onshore . . . . . . . 5 1

RRC District 5 . . . . . . . . . . . . . . . 3 0

RRC District 6 . . . . . . . . . . . . . . . 12 2

RRC District 7B. . . . . . . . . . . . . . 10 1

RRC District 7C. . . . . . . . . . . . . . 8 1

RRC District 8 . . . . . . . . . . . . . . . 5 1

RRC District 8A. . . . . . . . . . . . . . 5 1

RRC District 9 . . . . . . . . . . . . . . . 4 0

RRC District 10 . . . . . . . . . . . . . . 3 0

State Offshore. . . . . . . . . . . . . . . 0 0

Utah . . . . . . . . . . . . . . . . . . . . . . . . 8 1

West Virginia . . . . . . . . . . . . . . . . . . 1 0

Wyoming . . . . . . . . . . . . . . . . . . . . . 29 4

Federal Offshore . . . . . . . . . . . . . . . 0 0

Pacific (California). . . . . . . . . . . . 0 0

Gulf of Mexico (Louisiana) . . . . . 0 0

Gulf of Mexico (Texas) . . . . . . . . 0 0

Miscellaneousa . . . . . . . . . . . . . . . . 2 0

aIncludes Arizona, Missouri, Nevada, New York, South Dakota, Tennessee, and Virginia.

Notes: Confidence intervals are associated with Table 6 reserves and production data. Factors for confidence intervals for each State

subdivision, State, and the United States are independently estimated and do not add.

Source: Factor estimates based on data filed on Form EI-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1997.

Table F10. Factors for Confidence Intervals (2S.E.) for Lease Condensate Proved Reserves and

Production, 1997 (Million Barrels of 42 U.S. Gallons)

1997 1997 1997 1997

State and Subdivision Reserves Production State and Subdivision Reserves Production

United States . . . . . . . . . . . . . . . . . . 36 5

Alabama. . . . . . . . . . . . . . . . . . . . . . 0 0

Alaska . . . . . . . . . . . . . . . . . . . . . . . 0 0

Arkansas . . . . . . . . . . . . . . . . . . . . . 0 0

California . . . . . . . . . . . . . . . . . . . . . 1 0

Coastal Region Onshore. . . . . . . 0 0

Los Angeles Basin Onshore . . . . 0 0

San Joaquin Basin Onshore . . . . 1 0

State Offshore. . . . . . . . . . . . . . . 0 0

Colorado . . . . . . . . . . . . . . . . . . . . . 0 0

Florida . . . . . . . . . . . . . . . . . . . . . . . 0 0

Kansas. . . . . . . . . . . . . . . . . . . . . . . 0 0

Kentucky . . . . . . . . . . . . . . . . . . . . . 0 0

Louisiana . . . . . . . . . . . . . . . . . . . . . 19 3

North . . . . . . . . . . . . . . . . . . . . . . 17 3

South Onshore . . . . . . . . . . . . . . 0 0

State Offshore. . . . . . . . . . . . . . . 0 0

Michigan . . . . . . . . . . . . . . . . . . . . . 0 0

Mississippi . . . . . . . . . . . . . . . . . . . . 0 0

Montana. . . . . . . . . . . . . . . . . . . . . . 0 0

New Mexico . . . . . . . . . . . . . . . . . . . 0 0

East. . . . . . . . . . . . . . . . . . . . . . . 0 0

West . . . . . . . . . . . . . . . . . . . . . . 0 0

North Dakota . . . . . . . . . . . . . . . . . . 0 0

Oklahoma . . . . . . . . . . . . . . . . . . . . 0 0

Texas. . . . . . . . . . . . . . . . . . . . . . . . 32 5

RRC District 1 . . . . . . . . . . . . . . . 0 0

RRC District 2 Onshore . . . . . . . 0 0

RRC District 3 Onshore . . . . . . . 32 5

RRC District 4 Onshore . . . . . . . 2 0

RRC District 5 . . . . . . . . . . . . . . . 0 0

RRC District 6 . . . . . . . . . . . . . . . 2 0

RRC District 7B. . . . . . . . . . . . . . 0 0

RRC District 7C. . . . . . . . . . . . . . 0 0

RRC District 8 . . . . . . . . . . . . . . . 0 0

RRC District 8A. . . . . . . . . . . . . . 0 0

RRC District 9 . . . . . . . . . . . . . . . 0 0

RRC District 10 . . . . . . . . . . . . . . 0 0

State Offshore. . . . . . . . . . . . . . . 0 0

Utah and Wyoming . . . . . . . . . . . . . 1 0

West Virginia . . . . . . . . . . . . . . . . . . 0 0

Federal Offshorea . . . . . . . . . . . . . . 0 0

Pacific (California). . . . . . . . . . . . 0 0

Gulf of Mexico (Louisiana)a . . . . 0 0

Gulf of Mexico (Texas) . . . . . . . . 0 0

Miscellaneousb . . . . . . . . . . . . . . . . 0 0

aIncludes Federal offshore Alabama. bIncludes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, New York, Ohio, Oregon, Pennsylvania, South Dakota,

Tennessee, and Virginia.

Notes: Confidence intervals are associated with Table 16 reserves and production data. Factors for confidence intervals for each State

subdivision, State, and the United States are independently estimated and do not add.

Source: Factor estimates based on data filed on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1997.
Since there are no operators in the frame who would be

classified as Type 2 at the U.S. level, there would be no

Type 2 components at the U.S. level. Therefore, at the

U.S. level, there was only one sample variance

component calculated for Type 1 operators.

Nonsampling Errors

Several sources of possible error, apart from sampling

error, are associated with the Form EIA-23 survey.

These include bias due to nonresponse of operators in

the sample, proved reserve estimation errors, and

reporting errors on the part of the respondents to the

survey. On the part of EIA, possible errors include

inadequate frame coverage, data processing error, and

errors associated with statistical estimates. Each of

these sources is discussed below. An estimate of the

bias from nonresponse is presented in the section on

adjustment for operator nonresponse.

Assessing the Accuracy of the

Reserve Data

The EIA maintains an evaluation program to assess the

accuracy and quality of proved reserve estimates

gathered on Form EIA-23. Field teams consisting of

petroleum engineers from EIA's Dallas Field Office

conduct technical reviews of reserve estimates and

independently estimate the proved reserves of a

statistically selected sample of operator properties. The

results of these reviews are used to evaluate the

accuracy of reported reserve estimates. Operators are

apprised of the team's findings to assist them in

completing future filings. The magnitude of errors due

to differences between reserve volumes submitted by

operators on the Form EIA-23 and those estimated by

EIA petroleum engineers on their field trips were

generally within accepted professional engineering

standards.

Respondent Estimation Errors

The principal data elements of the Form EIA-23 survey

consist of respondent estimates of proved reserves of

crude oil, natural gas, and lease condensate.

Unavoidably, the respondents are bound to make some

estimation errors, i.e., until a particular reservoir has

been fully produced to its economic limit and

abandoned, its reserves are not subject to direct

measurement but must be inferred from limited,

imperfect, or indirect evidence. A more complete

discussion of the several techniques of estimating

proved reserves, and the many problems inherent in

the task, appears in Appendix G.

Reporting Errors and

Data Processing Errors

Reporting errors on the part of respondents are of

definite concern in a survey of the magnitude and

complexity of the Form EIA-23 program. Several steps

were taken by EIA to minimize and detect such

problems. The survey instrument itself was carefully

developed, and included a detailed set of instructions

for filing data, subject to a common set of definitions

similar to those already used by the industry. Editing

software is continually developed to detect different

kinds of probable reporting errors and flag them for

resolution by analysts, either through confirmation of

the data by the respondent or through submission of

amendments to the filed data. Data processing errors,

consisting primarily of random keypunch errors, are

detected by the same software.

Imputation Errors

Some error, generally expected to be small, is an

inevitable result of the various estimations outlined.

These imputation errors have not yet been completely

addressed by EIA and it is possible that estimation

methods may be altered in future surveys. Nationally,

5.9 percent of the crude oil proved reserve estimates,

6.1 percent of the natural gas proved reserve estimates,

and 0.7 percent of the lease condensate proved reserve

estimates resulted from the imputation and estimation

of reserves for those Certainty and Noncertainty

operators who did not provide estimates for all of their

properties, in combination with the expansion of the

sample of Noncertainty operators to the full

population. Errors for the latter were quantitatively

calculated, as discussed in the previous section.

Standard errors, for the former, would tend to cancel

each other from operator to operator, and are,

therefore, expected to be negligible, especially at the

National level of aggregation. In States where a large

share of total reserves is accounted for by Category III

and smaller Category II operators, the errors are

expected to be somewhat larger than in States where a

large share of total reserves is accounted for by

Category I and larger Category II operators.

Frame Coverage Errors

Of all the sources of controllable error connected with

the Form EIA-23 survey, errors in the operator frame

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 119
were expected to be the most important. If the frame

does not list all operators in a given State, the sample

selected from the frame for the State will not represent

the entire operator population, a condition called

undercoverage. Undercoverage is a problem with

certain States, but it does not appear to be a problem

with respect to the National proved reserve estimates

for either crude oil or natural gas. While it is relatively

straightforward to use existing sources to identify large

operators and find addresses for them, such is not the

case for small operators. A frame such as that used in

the 1997 survey is particularly likely to be deficient in

States where a large portion of total reserves and

production is accounted for by small operators. These

States are not likely to allocate sufficient resources to

keep track of all operators on a current basis. Some

undercoverage of this type seems to exist, particularly,

with reference to natural gas operators. EIA is

continuing to work to remedy the undercoverage

problem in those States where it occurred.

Calculation of Reserves of

Natural Gas Liquids and

Dry Natural Gas

Natural Gas Liquids Reserve Balance

The published reserves, production, and reserves

change statistics for crude oil, lease condensate, and

natural gas, wet after lease separation, were derived

from the data reported on Form EIA-23 and the

application of the imputation methods discussed

previously. The information collected on Form

EIA-64A was then utilized in converting the estimates

of the wet natural gas reserves into two components:

plant liquids reserve data and dry natural gas reserve

data. The total natural gas liquids reserve estimates

presented in Table 14 were computed as the sum of

plant liquids estimates (Table 15) and lease condensate

(Table 16) estimates.

To generate estimates for each element in the reserves

balance for plant liquids in a given producing area, the

first step was to group all natural gas processing plants

that reported this area as an area-of-origin on their

Form EIA-64A, and then sum the liquids production

attributed to this area over all respondents. Next, the

ratio of the liquids production to the total wet natural

gas production for the area was determined. This ratio

represented the percentage of the wet natural gas that

was recovered as natural gas liquids. Finally, it was

assumed that this ratio was applicable to the reserves

and each component of reserve changes (except

adjustments), as well as production. Therefore, each

element in the wet natural gas reserves balance was

multiplied by this recovery factor to yield the

corresponding estimate for plant liquids. Adjustments

of natural gas liquids were set equal to the difference

between the end of previous year reserve estimates,

based upon the current report year Form EIA-23 and

Form EIA-64A surveys, and the end of current year

reserve estimates published in the preceding year's

annual reserves report.

Natural Gas Reserve Balance

This procedure involved downward adjustments of the

natural gas data, wet after lease separation, in

estimating the volumes of natural gas on a fully dry

basis. These reductions were based on estimates of the

gaseous equivalents of the liquids removed (in the case

of production), or expected to be removed (in the case

of reserves), from the natural gas stream at natural gas

processing plants. Form EIA-64A collected the

volumetric reduction, or shrinkage, of the input

natural gas stream that resulted from the removal of

the NGL at each natural gas processing plant.

The shrinkage volume was then allocated to the plant's

reported area or areas of origin. Because shrinkage is,

by definition, roughly in proportion to the NGL

recovered, i.e. the NGL produced, the allocation was in

proportion to the reported NGL volumes for each area

of origin. However, these derived shrinkage volumes

were rejected if the ratio between the shrinkage and the

NGL production (gas equivalents ratio) fell outside

certain limits of physical accuracy. The ratio was

expected to range between 1,558 cubic feet per barrel

(where NGL consists primarily of ethane) and 900

cubic feet per barrel (where NGL consists primarily of

natural gasolines). When the computed gas equivalents

ratio fell outside these limits, an imputed ratio was

utilized to estimate the plant's natural gas shrinkage

allocation to each reported area of origin.

This imputed ratio was that calculated for the

aggregate of all other plants reporting production and

shrinkage, and having a gas equivalent ratio within the

aforesaid limits, from the area in question. The

imputed area ratio was applied only if there were at

least five plants to base its computation on. If there

were less than five plants, the imputed ratio was

calculated based on all plants in the survey whose

individual gas equivalents ratio was within the

acceptable limits. Less than one percent of the liquids

production was associated with shrinkage volumes

Energy Information Administration

120 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
imputed in this manner. Based on the 1997 Form

EIA-64A survey, the national weighted average gas

equivalents ratio was computed to be 1,392 cubic feet of

natural gas shrinkage per barrel of NGL recovered. The

total shrinkage volume (reported plus imputed) for all

plants reporting a given area of origin was then

subtracted from the estimated value of natural gas

production, wet after lease separation, yielding dry

natural gas production for the area. The amount of the

reduction in the wet natural gas production was then

expressed as a percentage of the wet natural gas

production. Dry natural gas reserves and reserve

changes were determined by reducing the wet natural

gas reserves and reserve changes by the same

percentage reduction factor.

A further refinement of the estimation process was

used to generate an estimate of the natural gas liquids

reserves in those States with coalbed methane fields.

The States where this procedure was applied were

Alabama, Colorado, Kansas, New Mexico, Oklahoma,

Pennsylvania, Utah, Virginia, West Virginia, and

Wyoming. The first step in the process was to identify

all Form EIA-23 reported coalbed methane fields. The

assumption was made that coalbed methane fields

contained little or no extractable natural gas liquids.

Therefore, when the normal shrinkage procedure was

applied to the wet gas volume reserve components, the

estimate of State coalbed methane volumes were

excluded and were not reduced for liquid extraction.

Following the computation for shrinkage, each coalbed

field gas volume reserve components was added back

to each of the dry gas volume reserve components in a

State. The effect of this is that the large increases in

reserves in some States from coalbed methane fields

did not cause corresponding increases in the State

natural gas liquids proved reserves.

Adjustments of dry natural gas were set equal to the

difference between the end of previous year reserves

estimates, based upon the current report year Form

EIA-23 and Form EIA-64A surveys, and the end of

current year reserve estimates published in the

preceding year's annual reserves report.

Each estimate of end of year reserves and report year

production has associated with it an estimated

sampling error. The standard errors for dry natural gas

were computed by multiplying the wet natural gas

standard errors by these same percentage reduction

factors. Table F7 provides estimates for 2 times the

SE Vs . .( $ ) for dry natural gas.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 121
Appendix G

Estimation of

Reserves and Resources
Appendix G

Estimation of Reserves and Resources

Oil and Gas Resource Base

Universally accepted definitions have not been

developed for the many terms used by geologists,

engineers, accountants and others to denote various

components of overall oil and gas resources. In part,

this is because most of these terms describe estimated

and therefore uncertain, rather than measured,

quantities. The lack of standardized terminology

sometimes leads to inaccurate understanding of the

meaning and/or import of estimates. Particularly

common is an apparently widespread lack of

understanding of the substantial difference between

the terms “reserves” and “resources”, as indicated by

the frequent misuse of either term in place of the other.

The total resource base of oil and gas is the entire

volume formed and trapped in–place within the Earth

before any production. The largest portion of this total

resource base is nonrecoverable by current or

foreseeable technology. Most of the nonrecoverable

volume occurs at very low concentrations throughout

the earth's crust and cannot be extracted short of

mining the rock or the application of some other

approach that would consume more energy than it

produced. An additional portion of the total resource

base cannot be recovered because currently available

production techniques cannot extract all of the in–place

oil and gas even when present in commercial

concentrations. The inability to recover all of the

in–place oil and gas from a producible deposit occurs

because of unfavorable economics, intractable physical

forces, or a combination of both. Recoverable

resources, the subset of the total resource base that is of

societal and economic interest, are defined so as to

exclude these nonrecoverable portions of the total

resource base.

The structure presented in Figure G1 outlines the total

resource base and its components. The total resource

base first consists of the recoverable and

nonrecoverable portions discussed above. The next

level down divides recoverable resources into

discovered and undiscovered segments. Discovered

resources are further separated into cumulative (i.e., all

past) production, and reserves. Reserves are

additionally subdivided into proved reserves and

“other reserves”.

Recoverable Resources

Discovered recoverable resources are those

economically recoverable quantities of oil and gas for

which specific locations are known. While the specific

locations of estimated undiscovered recoverable

resources are not yet known, they are believed to exist

in geologically favorable settings.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 125

1

Of the numerous other reserve classifications, only “Indicated Additional” reserves are included in this report.

Source: Energy Information Administration, Office of Oil and Gas.

Figure G1. Components of the Oil and Gas

Resource Base
Current estimates of undiscovered recoverable

resources merit discussion in order to provide a useful

sense of scale relative to proved reserves. The sources

of official estimates of domestic undiscovered

recoverable resources are two agencies of the

Department of the Interior (DOI), the United States

Geological Survey (USGS) for onshore areas and those

offshore waters subject to State jurisdiction, and the

Minerals Management Service (MMS) for those

offshore waters under Federal jurisdiction.

The USGS defines undiscovered recoverable

conventional resources as those expected to be resident

in accumulations of sufficient size and quality that they

could be produced using conventional recovery

technologies, without regard to present economic

viability. Therefore, only part of the USGS

undiscovered recoverable conventional resource is

economically recoverable now. The USGS also defines

a class of resources that occur in “continuous–type”

accumulations. Unlike conventional oil and gas

accumulations, continuous–type accumulations do not

occur in discrete reservoirs of limited areal extent. They

include accumulations in low–permeability (tight)

sandstones, shales, and chalks, and those in coal beds.

Again, only part of the continuous–type technically

recoverable resource is economically recoverable now.

In fact, only a small portion of the in–place

continuous–type resource accumulations are estimated

to be technically recoverable now. Table G1 presents

the latest available USGS and MMS estimates, along

with the EIA 1997 proved reserves estimates.

Technically recoverable resources of wet natural gas

(discovered, both proved and unproved, and

undiscovered) are estimated at 1,341 trillion cubic feet

(Table G1). Subtracting U.S. proved reserves of 175

trillion cubic feet yields an unproven technically

recoverable resource target of 1,166 trillion cubic feet.

This is about 61 times the 1997 gas production level.

Other organizations have also estimated unproven

technically recoverable gas resources. For example, the

Potential Gas Committee (PGC), an industry

sponsored group, provides detailed geology–based gas

resource estimates every 2 years. In 1996 the PGC mean

estimate of potential gas resources was 1,067 trillion

cubic feet, about 99 trillion cubic feet less than the DOI

estimates in Table G1. Another recent estimate was

made by the National Petroleum Council (NPC), an

industry–based group that serves in an advisory

capacity to the U.S. Secretary of Energy. The NPC's

estimate, based on data available at year–end 1990, was

1,135 trillion cubic feet, 111 trillion cubic feet less than

the DOI estimates summarized in Table G1. The

differences among these estimates are usually due to

the availability of newer data, the differences in

coverage or resource category definitions, and to

legitimate but differing data interpretations. The USGS

estimates of reserve growth in known fields are much

larger than previous estimates due to the utilization of

newer EIA reserves growth data.

While the estimation of undiscovered resources is

certainly a more imprecise endeavor than is the

estimation of proved reserves, it is clear that substantial

volumes of technically recoverable oil and gas

resources remain to be found and produced

domestically. Current estimates indicate that as much

domestic gas remains to be found and then produced

as has been to date. Of course, much effort, investment

and time will be required to bring this gas to market.

There is a perception that the oil resource base has been

more intensively developed than the gas resource base.

And in fact, more oil has been produced in the United

States than is estimated as remaining recoverable.

Nevertheless, the ratio of 1996 unproven technically

recoverable oil resources to oil production (Table G1)

was about 62 to 1, higher than the comparable gas ratio.

Discovered Resources

In addition to cumulative production, which is the sum

of current year production and the production in all

prior years, estimates of discovered recoverable

resources include estimates of reserves. Broadly,

reserves are those volumes that are believed to be

recoverable in the future from known deposits through

the eventual application of present or anticipated

technology.

Reserves

Reserves include both proved reserves and other

reserves. Several different reserve classification

systems are in use by different organizations, as

preferred for operational reasons. These systems utilize

and incorporate various definitions of terms such as

measured reserves, indicated reserves, inferred reserves,

probable reserves, and possible reserves. As used by the

different organizations, the definitions that attach to

these terms sometimes overlap, or the terms may

require a slightly different interpretation from one

organization to the next. Nevertheless, all kinds of

“other reserves” are generally less well known and

therefore less precisely quantifiable than proved

reserves, and their eventual recovery is less assured.

Energy Information Administration

126 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 127

Table G1. Estimated Oil and Gas Reserves and Mean Estimates of Technically Recoverable

Oil and Gas Resources

Natural Gas

Crude Oila Natural Gas (Dry) Liquids

Categories (million barrels) (billion cubic feet) (million barrels)

Lower 48 States

Discovered

Proved Reserves (EIA, 1997) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,385 b156,661 7,342

Reserve Growth - conventional, onshorec (USGS, 1991) . . . . . . . . . d47,000 290,000 12,900

Reserve Growth - conventional, Federal Offshore (MMS, 1995). . . . e2,238 e32,719 NE

Unproved Reserves, Federal Offshore (MMS, 1996) . . . . . . . . . . . . . 1,643 4,436 NE

Undiscovered, Technically Recoverable

Conventional, onshorec (USGS, 1993). . . . . . . . . . . . . . . . . . . . . . . . 21,810 190,280 6,080

Continuous-type - sandstone, shale, chalk; onshorec (USGS, 1993). 2,066 308,080 2,119

Continuous-type - coalbeds, onshorec (USGS, 1993) . . . . . . . . . . . . NA 49,910 NA

Federal Offshore - conventional (MMS, 1994). . . . . . . . . . . . . . . . . . 21,300 142,100 f<1,800

Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113,442 1,174,186 NA

Alaska

Discovered

Proved Reserves (EIA, 1997) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,161 10,673 631

Reserve Growth - conventional, onshorec (USGS, 1991) . . . . . . . . . g13,000 32,000 500

Reserve Growth conventional, Federal Offshore (MMS, 1994). . . . . 0 0 NE

Unproved Reserves, Federal Offshore (MMS, 1994) . . . . . . . . . . . . . 400 700 NE

Undiscovered, Technically Recoverable

Conventional onshorec (USGS, 1993) . . . . . . . . . . . . . . . . . . . . . . . . 8,440 68,410 1,120

Continuous-type - sandstone, shale, chalk; onshorec (USGS, 1993). NE NE NE

Continuous-type - coalbeds, onshorec (USGS, 1993) . . . . . . . . . . . . NA NE NA

Federal Offshore - conventional (MMS, 1994) . . . . . . . . . . . . . . . . . . 24,300 125,900 f<1,800

Subtotal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51,301 237,683 NA

Total Lower 48 States and Alaska. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164,743 1,411,869 32,492

Deductions for Production and Proved Reserves Changes,

1991-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -10,299 -80,880 -4,014

U.S. Total, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 154,444 1,330,989 28,478

a Condensate is included with crude oil for MMS estimates in Federal Offshore regions. b Includes 11,462 billion cubic feet of coalbed methane (EIA, 1997). c Includes USGS estimates for all onshore plus State Offshore (near-shore and shallow-water areas under State jurisdiction). d Using USGS definition, 1,924 million barrels of indicated additional oil reserves in the lower 48 States were included (EIA, 1996). e Reserve growth in the Pacific Federal offshore is not included and was not estimated by the MMS. This volume is not dry gas, but wet,

after lease separation. f Total undiscovered natural gas liquids for Federal offshore are 1,800 million barrels; MMS source did not separate lower 48 and Alaska

estimates of undiscovered natural gas liquids (1986). g Using USGS definition, 952 million barrels of indicated additional oil reserves in Alaska were included (EIA, 1996).

NE = not estimated.

NA = not applicable.

Notes: Federal Offshore indicates MMS estimates for Federal Offshore jurisdictions (Outer Continental Shelf and deeper water areas

seaward of State Offshore). Energy Information Administration (EIA), onshore and offshore estimated reserves. U.S. Geological Survey

(USGS): 1995 National Assessment mean estimates as of the end of 1993 (onshore and State Offshore). Minerals Management Service

(MMS): 1996 National Assessment mean estimates as of the end of 1994. The MMS also has end-1994 estimates for economically

recoverable resources. Probable and Possible reserves are considered by USGS definition to be part of USGS Reserve Growth, but are

separately considered by the MMS as its Unproved Reserves term. The USGS did not set a time limit for the duration of Reserve Growth; the

MMS set the year 2020 as the time limit in its estimates of Reserve Growth in existing fields of the Gulf of Mexico. Excluded from the estimates

are undiscovered oil resources in tar deposits and oil shales, and undiscovered gas resources in geopressured brines and gas hydrates.

Sources: Energy Information Administration, Office of Oil and Gas; USGS and MMS - Estimates of Undiscovered Conventional Oil and Gas

Resources in the United States—A Part of the Nation's Energy Endowment (1989), U.S. Department of the Interior; 1995 National Assessment

of United States Oil and Gas Resources, USGS Circular 1118, U.S. Department of the Interior; and An Assessment of the Undiscovered

Hydrocarbon Potential of the Nation's Outer Continental Shelf (1996), U.S. Department of the Interior.
Measured reserves are defined by the USGS as that part

of the identified (i.e., discovered) economically

recoverable resource that is estimated from geologic

evidence and supported directly by engineering

data.{41} They are similarly defined by the MMS,

although its system also subdivides them by degree of

development and producing status.{42} Measured

reserves are demonstrated with reasonable certainty to

be recoverable in future years from known reservoirs

under existing economic and operating conditions, and

are essentially equivalent to proved reserves as defined

by the EIA. Effectively, estimates of proved reserves

may be thought of as reasonable estimates (as opposed

to exact measures) of “on–the–shelf inventory”.

Inferred reserves and indicated reserves, due to their

more uncertain economic or technical recoverability,

are included in the “other reserves” category. The

USGS defines inferred reserves as that part of the

identified economically recoverable resource, over and

above both measured and indicated (see below)

reserves, that will be added to proved reserves in the

future through extensions, revisions, and the discovery

of new pay zones in already discovered fields.{41}

Inferred reserves are considered equivalent to

“probable reserves” by many analysts, for example,

those of the PGC.

Indicated additional reserves, a separate category, are

defined by both the DOI and the EIA as quantities of

crude oil that may become economically recoverable in

the future from existing productive reservoirs through

the application of currently available but as–yet

uninstalled recovery technology. At such time as the

technology is successfully applied, indicated

additional reserves are reclassified to the proved

reserves category. Of all the various “other reserves”

categories, only indicated additional reserves are

estimated by the EIA and reported herein.

Proved Reserves

The EIA defines proved reserves as those volumes of

oil and gas that geological and engineering data

demonstrate with reasonable certainty to be

recoverable in future years from known reservoirs

under existing economic and operating conditions.

When deterministic proved reserves estimation

methods are used, the term reasonable certainty is

intended to express a high degree of confidence that the

estimated quantities will be recovered. When

probabilistic methods are used there should be at least

a 90 percent probability that the actual quantities

recovered will exceed the estimate.

Proved reserves are either proved producing or proved

nonproducing (i.e., resident in reservoirs that did not

produce during the report year). The latter may

represent a substantial fraction of total proved

reserves.

Reserve Estimation

Methodologies

The adoption of a standard definition of proved

reserves for each type of hydrocarbon surveyed by the

Form EIA–23 program provided a far more consistent

response from operators than if each operator had used

their own definition. Such standards, however, do not

guarantee that the resulting estimates themselves are

determinate. Regardless of the definition selected,

proved reserves cannot be measured directly. They are

estimated quantities that are inferred on the basis of the

best geological, engineering, and economic data

available to the estimator, who generally uses

considerable judgment in the analysis and

interpretation of the data. Consequently, the accuracy

of a given estimate varies with and depends on the

quality and quantity of raw data available, the

estimation method used, and the training and

experience of the estimator. The element of judgment

commonly accounts for the differences among

independent estimates for the same reservoir or field.

Data Used in Making

Reserve Estimates

The raw data used in estimating proved reserves

include the engineering and geological data for

reservoir rock and its fluid content. These data are

obtained from direct and indirect measurements. The

data available for a given reservoir vary in kind,

quality, and quantity. When a reservoir is first

discovered only data from a single well are available,

and prior to flow testing or actual production, proved

reserves can only be inferred. As development of the

reservoir proceeds, and flow tests are made or actual

production commences, more and more data become

available, enabling proved reserves estimates to

become more accurate.

Many different kinds of data are useful in making

reserves estimates. They may include: data on porosity,

permeability, and fluid saturations of the reservoir

Energy Information Administration

128 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
rocks (obtained directly from core analysis or from

various types of electrical measurements taken in a

well or several wells); data on the production of fluids

from a well or several wells; geologic maps of the areal

extent, thickness, and continuity of the reservoir rocks

(inferred from well logs, geophysical, and geological

data); and reservoir pressure and temperature data.

Also involved are economic data including the current

price of crude oil and natural gas, and various

developmental and operating costs.

Reserve Estimation Techniques

Depending on the kinds and amounts of data available,

and a judgment on the reliability of those data, the

estimator will select one of several methods of making

a proved reserves estimate. Methods based on

production performance data are generally more

accurate than those based strictly on inference from

geological and engineering data. Such methods include

the Production Decline method (for crude oil or natural

gas reservoirs), the Material Balance method (for crude

oil reservoirs), the Pressure Decline method (which is

actually a material balance, for natural gas reservoirs),

and the Reservoir Simulation method (for crude oil or

natural gas reservoirs). The reservoir type and

production mechanisms and the types and amounts of

reliable data available determine which of these

methods is more appropriate for a given reservoir.

These methods are of comparable accuracy.

Methods not based upon production data include the

Volumetric method (for crude oil or natural gas

reservoirs) and the Nominal method. Of these, the

Volumetric method is the more accurate. Both methods,

however, are less accurate than those based on

production data. Table G2 summarizes the various

methods.

Judgmental Factors

in Reserve Estimation

The determination of rock and hydrocarbon fluid

properties involves judgment and is subject to some

uncertainty; however, the construction of the geologic

maps and cross sections and the determination of the

size of the reservoir are the major judgmental steps in

the Volumetric method, and are subject to the greatest

uncertainty. Estimates made using the Material Balance

method, the Reservoir Simulation method, or the

Pressure Decline method are based on the estimator's

judgment that the type of reservoir drive mechanism

has been identified and on the specification of

abandonment conditions. Estimates based on the

Production Decline method are subject to judgment in

constructing the trend line, and are based on the

estimator's assumption of reservoir performance

through abandonment.

Contributing to the degree of uncertainty inherent in

the above methods for estimating reserves are other

factors associated with economic considerations and

the perceived reservoir limits, which together influence

the final reserves estimate. A brief discussion of these

other factors follows.

Economic considerations: There has been continuing

debate about the effects of prices on proved reserves.

Although no all–inclusive statement can be made on

the impact of price, the points at issue can be discussed

and some general remarks can be made about some

circumstances where price may be a factor.

n Developed gas fields – In a gas reservoir, price

affects the economic limit (i.e., the production

rate required to meet operating costs) and,

therefore, the abandonment pressure. Thus, price

change has some effect on the conversion of

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 129

Table G2. Reserve Estimation Techniques

Method Comments

Volumetric Applies to crude oil and natural gas reservoirs. Based on raw engineering and geologic data.

Material Balance Applies to crude oil and natural gas reservoirs. Is used in estimating reserves. Usually of more value in predicting reserves,

and reservoir performance.

Pressure Decline Applies to nonassociated and associated

gas reservoirs. The method is a special

case of material balance equation in the

absence of water influx.

Production Decline Applies to crude oil and natural gas reservoirs during production decline (usually in

the later stages of reservoir life).

Reservoir SimulationApplies to crude oil and natural gas reservoirs. Is used in estimating reserves. Usually of more value in predicting reservoir

performance. Accuracy increases when

matched with past pressure and production data.

Nominal Applied to crude oil and natural gas reservoirs. Based on rule of thumb or analogy

with another reservoir or reservoirs believed to be similar; least accurate of

methods used.
noneconomic hydrocarbon resources to the

category of proved reserves. In both nearly

depleted reservoirs and newly developed

reservoirs, the actual increase in the quantity of

proved reserves resulting from price rises is

generally limited in terms of national volumes

(even though the percentage increase for a given

reservoir may be great).

n Developed oil fields – In developed crude oil

reservoirs many of the same comments apply;

however, there is an additional consideration. If

the price is raised to a level sufficient to justify

initiation of an improved recovery project, and if

the improved recovery technique is effective,

then the addition to ultimate recovery from the

reservoir can be significant. Because of the

speculative nature of predicting prices and costs

many years into the future, proved reserves are

estimated on the basis of current prices, costs,

and operating practices in effect as of the date the

estimation was made.

n Successful exploration efforts – Price can have a

major impact on whether a new discovery is

produced or abandoned. For example, the

decision to set casing in a new onshore

discovery, or to install a platform as the result of

an offshore discovery, are both price–sensitive. If

the decision is made to set pipe or to install a

platform, the discoveries in both cases will add

to the proved reserves total. If such projects are

abandoned, they will make no contribution to

the proved reserves total.

Effect of operating conditions: Operating conditions

are subject to change caused by changes in economic

conditions, unforeseen production problems, new

production practices or methods, and the operator's

financial position. As with economic conditions,

operating conditions to be expected at the time of

abandonment are speculative. Thus, current operating

conditions are used in estimating proved reserves. In

considering the effect of operating conditions, a

distinction must be made between processes and

techniques that would normally be applied by a

prudent operator in producing his oil and gas, and

initiation of changes in operating conditions that

would require substantial new investment.

n Compression – Compression facilities are

normally installed when the productive capacity

or deliverability of a natural gas reservoir or its

individual wells declines. In other cases

compression is used in producing shallow,

low–pressure reservoirs or reservoirs in which

the pressure has declined to a level too low for

the gas to flow into a higher pressure pipeline.

The application of compression increases the

pressure and, when economical, is used to make

production into the higher pressure pipeline

possible. Compression facilities normally require

a significant investment and result in a change in

operating conditions. It increases the proved

reserves of a reservoir, and reasonably accurate

estimates of the increase can be made.

n Well stimulation – Procedures that increase

productive capacity (workovers, such as

acidizing or fracturing, and other types of

production practices) are routine field

operations. The procedures accelerate the rate of

production from the reservoir, or extend its life,

and they have only small effect on proved

reserves. Reasonable estimates of their

effectiveness can be made.

n Improved recovery techniques – These techniques

involve the injection of a fluid or fluids into a

reservoir to augment natural reservoir energy.

Because the response of a given reservoir to the

application of an improved recovery technique

cannot be accurately predicted, crude oil

production that may ultimately result from the

application of these techniques is classified as

“indicated additional reserves of crude oil”

rather than as proved reserves until response of

the reservoir to the technique has been

demonstrated. In addition, improved recovery

methods are not applicable to all crude oil

reservoirs. Initiation of improved recovery

techniques may require significant investment.

n Infill drilling – Infill drilling (drilling of additional

wells within a field/reservoir) may result in a

higher recovery factor, and, therefore, be

economically justified. Predictions of whether

infill drilling will be justified under current

economic conditions are generally based on the

expected production behavior of the infill wells.

Reservoir limits: The initial proved reserves estimate

made from the discovery well is subject to significant

uncertainty because one well provides little

information on the size of the reservoir. The area

proved by a discovery well is frequently estimated on

the basis of experience in a given producing region.

Where there is continuity of the producing formation

over wide geographic areas, a relatively large proved

area may be assigned. In some cases where reliable

geophysical and geological data are available, a

reasonable estimate of the extent of the reservoir can be

made by drilling a relatively small number of

delineation wells. Conversely, a relatively small

proved area may be assigned when the producing

Energy Information Administration

130 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
formation is of limited continuity, owing to either

structural or lithological factors.

Additional wells provide more information and reduce

the uncertainty of the reserves estimate. As additional

wells are drilled, the geometry of the reservoir and,

consequently, its bulk volume, become more clearly

defined. This process accounts for the large extensions

to proved reserves typical of the early stages of most

reservoir development.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 131
Appendix H

Maps of Selected State Subdivisions
Maps of Selected State Subdivisions

SOUTH OFFSHORE

PACIFIC OCEAN

GULF OF ALASKA

SOUTH

NORTH

(INCLUDES ALL OFFSHORE)

ARCTIC OCEAN

CHUKCHI SEA

BERING SEA

Middleton


Island

Blying


Sound

Icy Bay

Bering


Glacier

McCarthy

Nabesna

Tanacross

Eagle

Charley


River

Black


River

Coleen

Table


Mtn.

Demar-


cation


Point

Barter


Island

Mt. St. Elias

Valdez

Gulkana

Mt. Hayes

Big Delta

Circle

Fort


Yukon

Arctic

Christian

Mt


Michel-


son

Flaxman


Island

Anchorage

Talkeetna 


Mts.

Healy

Fairbanks

Livengood

Beaver

Chan-


dalar

Philip


Smith


Mts.

Beechey 


Pt.

Seldovia

Kenai

Tyonek

Talkeetna

Mt. 


McKinley

Kantishna


River

Tanana

Bettles

Wiseman

Chandler


Lake

Umiat

Kaguyak

Kodiak

Trinity


Islands

Karluk

Mt.


Katmai

Iliamna

Lake Clark

Lime Hills

McGrath

Medfra

Ruby

Melozitna

Hughes

Survey


Pass

Killik


River

Ikpikpuk


River

Tesh-


ekpuk

Barrow

Sutwik


Island

Uga-


shik

Nak-


nek

Dillingham

Taylor


Mts.

Sleetmute

Iditarod

Ophir

Nulato

Kateel 


River

Shungnak

Ambler


River

Howard


Pass

Lookout


Ridge

Meade 


River

Bristol


Bay

Goodnews

Bethel

Russian


Mission

Holy


Cross

Uralakleet

Norton


Bay

Candle

Selawik

Baird


Mts.

Utukok


River

Point


Lay

DeLong


Mts.

Kotz-


 ebue

Bende-


leben

Solomon

St. Michael

Kwiguk

Marshall

Baird


Inlet

Kuskokwim


Bay

Black

Hooper


Bay

Nunivak


Island

Cape


Mendenhall

Pribilof 


Islands

St. Matthew

Nome

Teller

Shish-


maref

Amukta

Umnak

Samalga


Island

Unalaska

Uni-


mak

False

Simeonof


Island

Cold


Bay

Port 


Moller

Attu

Kiska

Rat


Islands

Gareloi


Island

Adak

Atka Seguam

Atlin

Taku


River

Petersburg

Bradfield


Canal

Craig

Ketch-


ikan

Prince
 Dixon


Rupert Entrance

Fairbanks

Juneau

St. Lawrence

Barrow

Pass

Nushagak


Bay

Noatak

Skagway

Harrison


Bay

Afognak

Chignik

Hagemeister Island

Cordova

Seward

Sagavan-


irktok

Wain-


wright

Juneau

Sumdum

Anchorage

Point


Hope

Nome

Port


Alexander

Sitka

Mt.


Fairweather

Stepovak


Bay

Misheguk


Mtn.

Yakutat

Alaska - South State Offshore .............


Alaska - South Federal Offshore ......... 

Alaska - South Onshore ......................

 Offshore .................................

Alaska - North Onshore and

ALASKA


(1:250,000 - scale quadrangles)

AK 50

AK 10

AK 05

AK 00

Figure H1. Subdivisions of Alaska

Energy Information Administration/U.S. Crude Oil, Natural

Gas, and Natural Gas Liquids Reserves 1996 Annual Report 125
Figure H2. Subdivisions of California

Source: Energy Information Administration, Office of Oil and Gas.

Energy Information Administration

136 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

BASIN

OFFSHORE

BASIN

LOS ANGELES

Del

Norte

Modoc Siskiyou

Lassen Shasta Trinity Humboldt

Mendocino

Tehama

Butte

Plumas

Lake

Glenn

Sonoma

Colusa

Yolo

Sierra

Sutter

Solano

Napa

Nevada

Placer

El Dorado

Alpine

San

Joaquin

Sacramento

Contra

Costa

Alameda

Amador

Mono

Calaveras Tuolumne

Stanislaus Mariposa

Merced

Santa

Clara

Inyo

Tulare

Madera

Fresno

San

Benito

Kings

Monterey

San Luis

Obispo

Santa Barbara

Ventura

Kern

Orange Riverside

San Diego Imperial

Los Angeles

San Bernardino

San Fransisco

Santa

Cruz

Marin

San Mateo

SAN JOAQUIN

COASTAL REGION

Yuba

California - Coastal Region Onshore ................... CA 50

California - Los Angeles Basin Onshore ............. CA 90

California - San Joaquin Basin Onshore ............. CA 10

California - State Offshore ..................................... CA 05

California - Federal Offshore ................................. CA 00
Figure H3. Subdivisions of Louisiana

Source: Energy Information Administration, Office of Oil and Gas.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 137

OFFSHORE

Caddo

Bossier

Claiborne Union Morehouse

West

Carroll East

Carroll

De Soto Red River

Bienville

Lincoln

Ouachita Richland

Natchitoches

Sabine

Vernon

Beauregard

Calcasieu

Cameron

Jefferson

Davis

Allen Evangeline

St. Landry

Iberville

Pointe

Coupee

East

Feliciana

West

Feliciana

Vermilion

Acadia

Grant

Winn

Jackson

Caldwell Franklin

Madison

Tensas

St.

Helena

Tangipahoa

Washington

St. Tammany Livingston

East

Baton

Rouge

Iberia

St.

Martin

Terrebonne

Lafourche

St. Charles

Plaquemines

Assumption

Ascension

St.

James

Orleans

St. St. Bernard

Martin

St. Mary

Avoyelles

Rapides

La Salle

Catahoula

Concordia

West

Baton

Rouge

Jefferson

St. John

the

Baptist

NORTH

SOUTH

Webster

Lafayette

Louisiana - North ........................................ LA 50

Louisiana - South Onshore ....................... LA 10

Louisiana - South State Offshore ............. LA 05

Louisiana - South Federal Offshore ......... LA 00
Figure H4. Subdivisions of New Mexico

Source: Energy Information Administration, Office of Oil and Gas.

Energy Information Administration

138 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

EAST

WEST

San Juan

McKinley

Valencia

Catron

Grant

Hidalgo

Luna

Dona Ana

Otero

Lincoln

Eddy

Lea

Roosevelt

Curry

Quay

Harding

Colfax Union Taos

Rio Arriba

Sandoval

Bernalillo

Torrance

Socorro

Sierra

Chaves

Guadalupe

San Miguel

Santa Fe

Mora

Los

Alamos

De Baca

Cibola

New Mexico - East ............................NM 10

New Mexico - West ...........................NM 50
Figure H5. Subdivisions of Texas

Source: Energy Information Administration, Office of Oil and Gas.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 139

RAILROAD COMMISSION

DISTRICTS OFFSHORE

1

2

3

4

5

6

7B

8

8A 9

10

Brazoria

Matagorda

Ref San

Patricio

Nueces

Kleberg

Kenedy

Willacy

Hidalgo

Starr

Zapata Jim

Hogg

Webb Duval

Live

Oak

Bee

GoliadVictoria

Wharton

Fort

Bend

Harris

Colorado

Fayette

Lee

Burleson Montgomery

Walker

Trinity

Polk Tyler

Hardin

Liberty

Galveston

Dimmit

Maverick

La Salle McMullen

Frio Atascosa Zavala

Uvalde Medina

Bexar

Comal

Wilson

DeWitt

Lavaca

Hays

Travis

Williamson

Burnet Llano

Gillespie

Kimble

Bandera

Kerr

Real

Mason

Kinney

Val Verde

Terrell

Crockett

Edwards

Sutton

Menard

Irion

Tom

Green Concho

Brewster

Presidio

Jeff Davis Pecos

El Paso

Hudspeth

Culberson Reeves

Loving

Ward Crane Upton Reagan

Winkler Ector Midland

Glasscock Sterling

Andrews

Gaines

Martin

Borden Scurry Fisher Jones

Nolan Taylor Callahan

Eastland

Shackelford

Coke Runnels

Stephens

Palo

Pinto

Erath Somer- vell

Bell

Milam

Falls

Bosque

Lampasas

Blanco Washington

McCulloch

San

Jacinto

Jim

Wells

Dallam

Hartly

Oldham

Deaf

Smith

Sherman

Hansford Ochiltree

Lipscomb

Moore Hutchinson Roberts Hemphill

Potter Carson Gray Wheeler

Randall Armstrong Donley

Bailey

Cochran

Castro

Swisher Briscoe Hall Childress

Lamb Hale Floyd Motley Cottle

Crosby Dickens King

Terry Lynn Garza Kent Stonewall

Wil

Barger Wichita Clay

Montague Cooke

Foard

Knox Baylor Archer

Young

Bowie

Hockley

Lubbock

Dawson

Haskell

Throckmorton

ugio houn

CalGonzales

Jackson

Jack Wise Denton Collin

Parker Tarrant Dallas

Hood Johnson Ellis

Hill

Coryell

Navarro

Limestone

Freestone

Leon

Kaufman Van

Zandt

Henderson

Anderson

Houston

Cherokee

Hunt

Wood

Smith

Lamar Red

River

Hopkins Cass

Marion

Harrison

Panola

Shelby

Upshur

Camp

Franklin

Titus

Morris

Rusk

Angelina Jasper

Chambers

Jefferson

Brown

Comanche

Mills

San

Saba

Hamilton

Delta

Gregg

Grayson

Sabine

Newton

Orange

Grimes

Austin

Collingsworth

Coleman

Howard Mitchell

Brooks

Bastrop

Aransas

San

Augustine

Madison

Brazos

Robertson

Kendall

Guadalupe

Nacogdoches

ler

WalMcLennan

Caldwell

Karnes

Parmer

Yoakum

Cameron

Rockwall Rains

Hardeman

Fannin

7C Schleicher

Texas- Railroad Commission District 1 ............. TX 10

Texas- Railroad Commission District 2

Onshore ................................................. TX 20

Texas- Railroad Commission District 3

Onshore ................................................. TX 30

Texas- Railroad Commission District 4

Onshore .................................................. TX 40

Texas- Railroad Commission District 5 ............ TX 50

Texas- Railroad Commission District 6 ............ TX 60

Texas- Railroad Commission District 7B ......... TX 70

Texas- Railroad Commission District 7C ......... TX 75

Texas- Railroad Commission District 8 ........... TX 80

Texas- Railroad Commission District 8A ......... TX 85

Texas- Railroad Commission District 9 ........... TX 90

Texas- Railroad Commission District 10 ......... TX 95

Texas- State Offshore ....................................... TX 05

Texas- Federal Offshore ................................... TX 00
30°

29°

28°

27°

26°

25°

24°

98° 97° 96° 95° 94° 93° 92°

SABINE

PASS

GALVESTON

HIGH ISLAND

MATAGORDA

ISLAND

MUSTANG

ISLAND

PADRE

ISLAND

EAST BREAKS GARDEN BANKS

KEATHLEY CANYON

NG 15-8

ALAMINOS CANYON

Corpus Christi

CORPUS

CHRISTI

PORT

ISABEL

Galveston

T

E

X A S

N

100'

600'

2000'

100'

2000'

600'

GULF OF MEXICO

0 50 100

0 100 50 150

STATUTE MILES

KILOMETERS

(Dashed lines indicate water depths in feet.)

BRAZOS

Figure H6. Western Planning Area, Gulf of Mexico Outer Continental Shelf Region

Energy Information Administration/U.S. Crude Oil, Natural

130 Gas, and Natural Gas Liquids Reserves 1996 Annual Report
WEST CAMERON

EAST CAMERON

VERMILION

SOUTH MARSH ISLAND

EUGENE ISLAND

SHIP SHOAL

SOUTH PELTO

SOUTH

TIMBALIER

BAY

MARCHAND

GRAND

ISLE

WEST

DELTA

SOUTH PASS

MAIN

PASS

BRETON

SOUND

MOBILE

VIOSCA

KNOLL (SLOPE)

CHANDELEUR

EWING BANK

MISSISSIPPI CANYON

GREEN CANYON ATWATER VALLEY

VIOSCA

KNOLL

NG 15-9 NG 16-7

WALKER RIDGE LUND

N

GULF OF MEXICO

0 50 100

0 100 50 150

STATUTE MILES

KILOMETERS

(Dashed lines indicate water depths in feet.)

Lake Charles

New Orleans

Mobile

600'

100'

2000'

100'

2000'

600'

LOUISIANA MISS. ALA.

30°

29°

28°

27°

26°

25°

24°

94° 93° 92° 91° 90° 89° 88°

SABINE

PASS

Figure H7. Central Planning Area, Gulf of Mexico Outer Continental Shelf Region

Energy Information Administration/U.S. Crude Oil, Natural

Gas, and Natural Gas Liquids Reserves 1996 Annual Report 131
DESTIN DOME

DE SOTO CANYON

LLOYD RIDGE

HENDERSON

NG 16-8

NG 16-11

RANKIN

HOWELL HOOK

VERNON BASIN

THE ELBOW

FLORIDA MIDDLE GROUND

APALACHICOLA GAINESVILLE

TARPON

SPRINGS

SAINT

PETERSBURG

CHARLOTTE HARBOR

PULLEY RIDGE

DRY

TORTUGAS

KEY WEST

MIAMI

Tampa

PENSACOLA

Pensacola

NF 17-1

2000'

600'

100'

2000'

600'

100'

0 50 100

0 100 50 150

STATUTE MILES

KILOMETERS

(Dashed lines indicate water depths in feet.)

30°

29°

28°

27°

26°

25°

24°

N

87° 86° 85° 84° 83° 82°

GULF OF MEXICO

F L O

R

I

D

A

Figure H8. Eastern Planning Area, Gulf of Mexico Outer Continental Shelf Region

Energy Information Administration/U.S. Crude Oil, Natural

132 Gas, and Natural Gas Liquids Reserves 1996 Annual Report
Appendix I

Annual Survey Forms for

Domestic Oil and Gas Reserves
OFFICIAL USE ONLY 1997 ANNUAL SURVEY OF DOMESTIC OIL AND GAS RESERVES U.S. DEPARTMENT OF ENERGY CALENDAR YEAR 1997 

This report is mandatory under Public Law 93-275. Failure to comply may result in criminal fines, civil penalties and other sanctions as provided by law. For the sanctions and the provisions of information submitted on this form, see page 2 of the Instructions. Public reporting burden for this collection of information is estimated to average from 62 to 333 hours per response, incluinstructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden ethis collection of information, including suggestions for reducing this burden, to the Energy Information Administration, Office of Statistical Standards EI-73, Washington, DC 20585; and to the Regulatory Affairs, Office of Management and Budget, Washington, DC 20503.

COVER PAGE

IDENTIFICATION

1. Were you an operator (see definition of an operator, p.1) of one or more oil or gas wells on December 31, 1997?

(1) No... Complete only items 3 through 22 below and return this page with a letter stating when operations ceased and

 2. I.D. Co

what became of the wells you operated to P.O. Box 1470 Rockville, MD 20849-1470

(2) Yes... Complete the attached forms and return them to P.O. Box 1470 Rockville, MD 20849-1470 

If information to the left is incorrect or is missing, enter correct information below3. Name4. Address5. City 6. State 7. Zip 8. EIN 

Socia

9. Name of Contact Person10. Telephone Number of Contact Person Area Code ( ) ___

PARENT COMPANY IDENTIFICATION

11. Is there a parent company which exercises ultimate control over 12. Name

your company?(1) No... Answer 18 thru 22

13. Address

(2) Yes... Answer 12 thru 22 14. City 15. State 16

17. Parent Company EIN

18. What is the total number of pages (including this page) submitted in this filing?

ATTESTATION

(This report must be attested to by a responsible official of the company.)I hereby swear or affirm that I have read the report and am familiar with its contents, and that to the best of my knowledge, information, and belief, tappended is true and complete.

19. Name of Attestor (Please print) 21. Signature20. Title 22. Date

Title 18 USC 1001 makes it a criminal offense for any person knowingly and willingly to make to any Agency or

Department of the United States any false, fictitious or fraudulent statements as to any matter within its jurisdiction

FOR ASSISTANCE CALL 1-800-879-1470
OFFICIAL USE ONLY

ANNUAL SURVEY OF DOMESTIC OIL AND GAS RESERVES

SUMMARY REPORT

PAGE 1 OF 2

(Report All Volumes of Crude Oil and Lease Condensate in Thousands of Barrels [Mbbl];

Form ApprovedOMB No. 1905-0057Expires 12/98

1.0 OPERATOR AND REPORT IDENTIFICATION DATA Report All Volumes of Natural Gas in Millions of Cubic Feet [MMcf] at 14.73 psia and 60°F)1.1 OPERATOR I.D. CODE 1.2 OPERATOR NAME REPORT DATE 1.3 ORIGINAL 1.4 AMENDED

12 31 97

2.0 PRODUCTION AND RESERVES DATA

CRUDE OIL NATURAL GAS LEASE CONDENSATE

STATE OR RESERVES 1997 PRODUCTION RESERVES 1997 PRODUCTION RESERVES 1997 PRODUCTION

GEOGRAPHIC

SUBDIVISION

Proved

Reserves

Dec. 31, 1997

(Mbbl)

(A)

(From properties for

which reserves were

Estimated)

(Mbbl)

(B)

(From properties for

which reserves were

Not Estimated)

(Mbbl)

(C)

Proved

Reserves

Dec. 31, 1997

(MMcf)

(D)

(From properties for

which reserves were

Estimated)

(MMcf)

(E)

(From properties for

which reserves were

Not Estimated

(MMcf)

(F)

Proved

Reserves

Dec. 31, 1997

(Mbbl)

(G)

(From properties for

which reserves were

Estimated)

(Mbbl)

(H)

(From properties for

which reserves were

Not Estimated)

(Mbbl)

(I)

ALABAMA-ONSHORE ALALABAMA-STATE OFFSHORE AL05ALASKA-NORTH ONSHORE AND OFFSHORE AK50ALASKA-SOUTH ONSHORE AK10ALASKA-SOUTH STATE OFFSHORE AK05ARIZONA AZARKANSAS ARCALIFORNIA-COASTAL REGION ONSHORE CA50CALIFORNIA-LOS ANGELES BASIN ONSHORE CA90CALIFORNIA-SAN JOAQUIN BASIN ONSHORE CA10CALIFORNIA-STATE OFFSHORE CA05COLORADO COFLORIDA-ONSHORE FLFLORIDA-STATE OFFSHORE FL05ILLINOIS ILINDIANA INKANSAS KSKENTUCKY KYLOUISIANA-NORTH LA50LOUISIANA-SOUTH ONSHORE LA10LOUISIANA-SOUTH STATE ONSHORE LA05MARYLAND MDMICHIGAN MIMISSISSIPPI-ONSHORE MSMISSISSIPPI-STATE OFFSHORE MS05MISSOURI MOMONTANA MTNEBRASKA NENEVADA NVNEW MEXICO-EAST NM10NEW MEXICO-WEST NM50NEW YORK NYNORTH DAKOTA ND

Figure I2. Form EIA–23, Summary Report — Page 1

OHIO OH

Source: Energy Information Administration, Office of Oil and Gas.

SAMPLE
OFFICIAL USE ONLY

ANNUAL SURVEY OF DOMESTIC OIL AND GAS RESERVES

SUMMARY REPORT

PAGE 2 OF 2

(Report All Volumes of Crude Oil and Lease Condensate in Thousands of Barrels [Mbbl];

Form ApprovedOMB No. 1905-0057Expires 12/98

1.0 OPERATOR AND REPORT IDENTIFICATION DATA Report All Volumes of Natural Gas in Millions of Cubic Feet [MMcf] at 14.73 psia and 60°F)1.1 OPERATOR I.D. CODE 1.2 OPERATOR NAME REPORT DATE 1.3 ORIGINAL 1.4 AMENDED

12 31 97

2.0 PRODUCTION AND RESERVES DATA

CRUDE OIL NATURAL GAS LEASE CONDENSATE

STATE OR RESERVES 1997 PRODUCTION RESERVES 1997 PRODUCTION RESERVES 1997 PRODUCTION

GEOGRAPHIC

SUBDIVISION

Proved

Reserves

Dec. 31, 1997

(Mbbl)

(A)

(From properties for

which reserves were

Estimated)

(Mbbl)

(B)

(From properties for

which reserves were

Not Estimated)

(Mbbl)

(C)

Proved

Reserves

Dec. 31, 1997

(MMcf)

(D)

(From properties for

which reserves were

Estimated)

(MMcf)

(E)

(From properties for

which reserves were

Not Estimated

(MMcf)

(F)

Proved

Reserves

Dec. 31, 1997

(Mbbl)

(G)

(From properties for

which reserves were

Estimated)

(Mbbl)

(H)

(From properties for

which reserves were

Not Estimated)

(Mbbl)

(I)

OKLAHOMA OKPENNSYLVANIA PASOUTH DAKOTA SDTENNESSEE TNTEXAS-RRC DISTRICT 1 TX10TEXAS-RRC DISTRICT 2 ONSHORE TX20TEXAS-RRC DISTRICT 3 ONSHORE TX30TEXAS-RRC DISTRICT 4 ONSHORE TX40TEXAS-RRC DISTRICT 5 TX50TEXAS-RRC DISTRICT 6 TX60TEXAS-RRC DISTRICT 7B TX70TEXAS-RRC DISTRICT 7C TX75TEXAS-RRC DISTRICT 8 TX80TEXAS-RRC DISTRICT 8A TX85TEXAS-RRC DISTRICT 9 TX90TEXAS-RRC DISTRICT 10 TX95TEXAS-STATE OFFSHORE TX05UTAH UTVIRGINIA VAWEST VIRGINIA WVWYOMING WYFEDERAL OFFSHORE-GULF OF MEXICO (ALABAMA) AL00FEDERAL OFFSHORE-GULF OF MEXICO (FLORIDA) FL00FEDERAL OFFSHORE-GULF OF MEXICO (LOUISIANA) LA00FEDERAL OFFSHORE-GULF OF MEXICO (MISSISSIPPI) MS00FEDERAL OFFSHORE-GULF OF MEXICO (TEXAS) TX00FEDERAL OFFSHORE-PACIFIC (ALASKA) AK00FEDERAL OFFSHORE-PACIFIC (CALIFORNIA) CA00

Figure I3. Form EIA–23, Summary Report — Page 2

FEDERAL OFFSHORE-PACIFIC (OREGON) OR00OTHER STATE (SPECIFY)TOTAL (SUM EACH COLUMN) US

Source: Energy Information Administration, Office of Oil and Gas.

SAMPLE
OFFICIAL USE ONLY ANNUAL SURVEY OF DOMESTIC OIL AND GAS RESERVES

SCHEDULE A - OPERATED PROVED RESERVES, PRODUCTION, AND RELATED DATA BY FIELD

(Report All Liquid Volumes in Thousands of Barrels [Mbbl] at 60°F;

Report All Volumes of Natural Gas in Millions of Cubic Feet [MMcf] at 60°F and 14.73 psia)

Form ApprovedOMB No. 1905-0057Expires 12/2000

1.0 OPERATOR AND REPORT IDENTIFICATION DATA

1.1 OPERATOR I.D. CODE 1.2 OPERATOR NAME REPORT DATE 1.3 ORIGINAL 1.4 AMENDED 1.5 PAGE FOR DOE USE ONLY

12 31 97

2.0 FIELD DATA (OPERATED BASIS)

1. STATE

ABBR.

2. SUBDIV.

CODE

3. COUNTY

CODE

4. FIELD

CODE

5. OCS BLOCK

NUMBER 6. FIELD NAME 7. Calendar Year PRODUCTION From Properties For which RESERVES Were NOT ESTIMATED 8. FOOTNOTE

2.1 CRUDE OIL (a) (Mbbl) ASSOC-DISSOLVED (b) GAS (MMcf) NONASSOCIATED (c) GAS (MMcf) LEASE CON- (d) DENSATE (Mbbl)

9. WATER DEPTH 10. FIELD DISCOVERY YEAR 11. INDICATED ADDITIONAL RESERVES OF CRUDE OIL (Mbbl)

TYPE HYDROCARBON

RESERVES

(a) DECEMBER 31, 1996

REVISION

(b) INCREASES

REVISION

(c) DECREASES (d) EXTENSIONS

NEW FIELD

(e) DISCOVERIES

NEW RESERVOIRS

(f) IN OLD FIELDS

CALENDAR YEAR

(g) PRODUCTION

RESERVES

(h) DECEMBER 31, 1997

NONPRODUCING

(i) RESERVES

12. CRUDE OIL (Mbbl)13. ASSOCIATED-DISSOLVED GAS(MMcf)14. NONASSOCIATED GAS (MMcf)15. LEASE CONDENSATE (Mbbl)

1. STATE

ABBR.

2. SUBDIV.

CODE

3. COUNTY

CODE

4. FIELD

CODE

5. OCS BLOCK

NUMBER 6. FIELD NAME 7. Calendar Year PRODUCTION From Properties For which RESERVES Were NOT ESTIMATED 8. FOOTNOTE

2.2 CRUDE OIL (a) (Mbbl) ASSOC-DISSOLVED (b) GAS (MMcf) NONASSOCIATED (c) GAS (MMcf) LEASE CON- (d) DENSATE (Mbbl)

9. WATER DEPTH 10. FIELD DISCOVERY YEAR 11. INDICATED ADDITIONAL RESERVES OF CRUDE OIL (Mbbl)

TYPE HYDROCARBON

RESERVES

(a) DECEMBER 31, 1996

REVISION

(b) INCREASES

REVISION

(c) DECREASES (d) EXTENSIONS

NEW FIELD

(e) DISCOVERIES

NEW RESERVOIRS

(f) IN OLD FIELDS

CALENDAR YEAR

(g) PRODUCTION

RESERVES

(h) DECEMBER 31, 1997

NONPRODUCING

(i) RESERVES

12. CRUDE OIL (Mbbl)13. ASSOCIATED-DISSOLVED GAS(MMcf)14. NONASSOCIATED GAS (MMcf)15. LEASE CONDENSATE (Mbbl)

1. STATE

ABBR.

2. SUBDIV.

CODE

3. COUNTY

CODE

4. FIELD

CODE

5. OCS BLOCK

NUMBER 6. FIELD NAME 7. Calendar Year PRODUCTION From Properties For which RESERVES Were NOT ESTIMATED 8. FOOTNOTE 2.3 CRUDE OIL (a) (Mbbl) ASSOC-DISSOLVED (b) GAS (MMcf) NONASSOCIATED (c) GAS (MMcf) LEASE CON- (d) DENSATE (Mbbl)

9. WATER DEPTH 10. FIELD DISCOVERY YEAR 11. INDICATED ADDITIONAL RESERVES OF CRUDE OIL (Mbbl)

TYPE HYDROCARBON

RESERVES

(a) DECEMBER 31, 1996

REVISION

(b) INCREASES

REVISION

(c) DECREASES (d) EXTENSIONS

NEW FIELD

(e) DISCOVERIES

NEW RESERVOIRS

(f) IN OLD FIELDS

CALENDAR YEAR

(g) PRODUCTION

RESERVES

(h) DECEMBER 31, 1997

NONPRODUCING

(i) RESERVES

12. CRUDE OIL (Mbbl)13. ASSOCIATED-DISSOLVED GAS(MMcf)14. NONASSOCIATED GAS (MMcf)15. LEASE CONDENSATE (Mbbl)

1. STATE

ABBR.

2. SUBDIV.

CODE

3. COUNTY

CODE

4. FIELD

CODE

5. OCS BLOCK

NUMBER 6. FIELD NAME 7. Calendar Year PRODUCTION From Properties For which RESERVES Were NOT ESTIMATED 8. FOOTNOTE 2.4 CRUDE OIL (a) (Mbbl) ASSOC-DISSOLVED (b) GAS (MMcf) NONASSOCIATED (c) GAS (MMcf) LEASE CON- (d) DENSATE (Mbbl)

9. WATER DEPTH 10. FIELD DISCOVERY YEAR 11. INDICATED ADDITIONAL RESERVES OF CRUDE OIL (Mbbl)

TYPE HYDROCARBON

RESERVES

(a) DECEMBER 31, 1996

REVISION

(b) INCREASES

REVISION

(c) DECREASES (d) EXTENSIONS

NEW FIELD

(e) DISCOVERIES

NEW RESERVOIRS

(f) IN OLD FIELDS

CALENDAR YEAR

(g) PRODUCTION

RESERVES

(h) DECEMBER 31, 1997

NONPRODUCING

(i) RESERVES

Figure I4. Form EIA-23, Detail Report — Schedule A

12. CRUDE OIL (Mbbl)13. ASSOCIATED-DISSOLVED GAS(MMcf)14. NONASSOCIATED GAS (MMcf)15. LEASE CONDENSATE (Mbbl)

Source: Energy Information Administration, Office of Oil and Gas.

SAMPLE
Figure I5. Form EIA-23, Detail Report — Schedule B

OFFICIAL USE ONLY

ANNUAL SURVEY OF DOMESTIC OIL AND GAS RESERVES

SCHEDULE B - FOOTNOTES

Form ApprovedOMB No. 1905-0057Expires 12/98

1.0 OPERATOR AND REPORT IDENTIFICATION DATA

1.1 OPERATOR I.D. CODE 1.2 OPERATOR NAME REPORT DATE 1.3 ORIGINAL 1.4 AMENDED 1.5 PAGE FOR DOE USE ONLY

12 31 97

2.0 FOOTNOTE DATA

Page

Number

(a)

Item

Number

(b)

Subitem

Number

(c)

Column

Designation

(d)

Sequence

Number

(e)

Notation

(f)

FOR DOE

USE ONLY

Source: Energy Information Administration, Office of Oil and Gas.

SAMPLE
Energy Information Administration

150 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report

Figure I6. Form EIA-64A

EIA-64A (Revised 9/91)

OFFICIAL USE

ONLY 1997 Energy Information AdministrationU.S. DEPARTMENT OF ENERGY

Calendar Year 1997

Form Approved

OMB No. 1905-0057

Expires 12/98

ANNUAL REPORT OF THE ORIGIN OF NATURAL GAS LIQUIDS PRODUCTION

FORM EIA-64A

This report is mandatory under Public Law 93-275. Failure to comply may result in criminal fines, civil penalties and other sanctions as provided by law. For the sanctions and the provisions

concerning the confidentiality of information submitted on this form, see Page 2 of the Instructions. Public reporting burden for this collection of information is estimated to average 5.9 hours per

respondent, including the time of reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information.

Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden, to the Energy Information Administration, Office

of Statistical Standards EI-73, Washington, DC 20585; and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503.

PLEASE COMPLETE THIS

FORM AND RETURN TO

DOMESTIC OIL AND GAS RESERVES PROGRAM

PO BOX 1470

ROCKVILLE, MD 20849-1470

PLANT AND PRODUCTION REPORT IDENTIFICATION

1.0 Does this report reflect active natural gas processing at the facility for the entire year?  ̈ Yes  ̈ No

Months covered by this report____________ through ____________ (Include Explanatory Notes in Section 8.0 )

2.0 If label is incorrect or information is missing or no label is given, enter

correct information to the right 2.1 Plant Operator's Name

2.2 Contact Person's Name

2.3 Plant Name

2.4 Geographic Location (Use Area of Origin Codes, Page 6)

2.5 Mailing Address

2.6 City State Zip Code

2.7 Telephone Number ( )

3.0 Parent Company's Name 4.0 Submission Status ! Original ! Amended

5.0 Origin of Natural Gas Received and Natural Gas Liquids Produced

Line

Area of Origin

Code

(A)

Natural Gas

Received (MMcf)

(B)

Natural Gas Liquids

Production (Mbbl)

(C)

5.1

5.2

5.3

5.4

5.5

5.6

5.7

5.8

5.9

5.10

5.11

5.12

5.13

5.14

5.15

5.16 TOTAL

6.0 Gas Shrinkage Resulting from Natural Gas Liquids Extracted (MMcf)

7.0 Natural Gas Used as Fuel in Processing (MMcf)

8.0 Explanatory Notes

9.0 Certification: I certify that the information provided herein and appended hereto is true and accurate to the best of my knowledge.

Name (Please Print) Date

Signature Title

Title 18 USC 1001 makes it a criminal offense for any person knowingly

and willingly to make to any Agency or Department of the United States

any false, fictitious, or fraudulent statements as to any matter within its

jurisdiction.

FOR ASSISTANCE CALL 1-800-879-1470

Source: Energy Information Administration, Offfice of Oil and Gas.

SAMPLE
Glossary
Glossary

This glossary contains definitions of the technical terms used in this report and employed by respondents in

completing Form EIA--23, “Annual Survey of Domestic Oil and Gas Reserves,” or Form EIA--64A, “Annual

Report of the Origin of Natural Gas Liquids Production,” for the report year 1995.

Adjustments: The quantity which preserves an exact

annual reserves balance within each State or State

subdivision of the following form:

These adjustments are the yearly changes in the

published reserve estimates that cannot be attributed

to the estimates for other reserve change categories

because of the survey and statistical estimation

methods employed. For example, variations as a

result of changes in the operator frame, different

random samples or imputations for missing or

unreported reserve changes, could contribute to

adjustments.

Affiliated (Associated) Company: An “affiliate” of,

or a person “affiliated” with, a specific person is a

person that directly, or indirectly through one or

more intermediaries: controls; or is controlled by; or

is under common control with, the person specified.

(See Person and Control)

Control: The term “control” (including the terms

“controlling,” “controlled by,” and “under common

control with”) means the possession, direct or

indirect, of the power to direct or cause the direction

of the management and policies of a person, whether

through the ownership of voting shares, by contract,

or otherwise. (See Person)

Corrections: (See Revisions)

Crude Oil: A mixture of hydrocarbons that exists in

the liquid phase in natural underground reservoirs

and remains liquid at atmospheric pressure after

passing through surface separating facilities. Crude

oil may also include:

1. Small amounts of hydrocarbons that exist in the

gaseous phase in natural underground

reservoirs but are liquid at atmospheric

pressure after being recovered from oil well

(casinghead) gas in lease separators, and that

subsequently are comingled with the crude

stream without being separately measured

2. Small amounts of nonhydrocarbons produced

with the oil.

When a State regulatory agency specifies a definition

of crude oil which differs from that set forth above,

the State definition is to be followed and its use

footnoted on Schedule B of Form EIA--23.

Extensions: The reserves credited to a reservoir

because of enlargement of its proved area. Normally

the ultimate size of newly discovered fields, or newly

discovered reservoirs in old fields, is determined by

wells drilled in years subsequent to discovery. When

such wells add to the proved area of a previously

discovered reservoir, the increase in proved reserves

is classified as an extension.

Field: An area consisting of a single reservoir or

multiple reservoirs all grouped on, or related to, the

same individual geological structural feature and/or

stratigraphic condition. There may be two or more

reservoirs in a field that are separated vertically by

intervening impervious strata, or laterally by local

geologic barriers, or by both.

Field Area: A geographic area encompassing two or

more pools that have a common gathering and

metering system, the reserves of which are reported

as a single unit. This concept applies primarily to the

Appalachian region. (See Pool)

Field Discovery Year: The calendar year in which a

field was first recognized as containing economically

recoverable accumulations of oil and/or gas.

Field Separation Facility: A surface installation

designed to recover lease condensate from a

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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 153

Published Proved Reserves at End of Previous Report Year

+ Adjustments

+ Revision Increases

– Revision Decreases

+ Extensions

+ New Field Discoveries

+ New Reservoir Discoveries in Old Fields

+ Report Year Production

= Published Proved Reserves at End of Report Year
produced natural gas stream frequently originating

from more than one lease, and managed by the

operator of one or more of these leases. (See Lease

Condensate)

Gross Working Interest Ownership Basis: Gross

working interest ownership is the respondent's

working interest in a given property plus the

proportionate share of any royalty interest, including

overriding royalty interest, associated with the

working interest. (See Working Interest and Royalty

(including Overriding Royalty) Interest)

Indicated Additional Reserves of Crude Oil:

Quantities of crude oil (other than proved reserves)

which may become economically recoverable from

existing productive reservoirs through the

application of improved recovery techniques using

current technology. These recovery techniques may:

1. Already be installed in the reservoir, but their

effects are not yet known to the degree

necessary to classify the additional reserves as

proved

2. Be installed in another similar reservoir, where

the results of that installation can be used to

estimate the indicated additional reserves.

Indicated additional reserves are not included in

proved reserves due to their uncertain economic

recoverability. When economic recoverability is

demonstrated, the indicated additional reserves must

be transferred to proved reserves as positive

revisions.

Lease Condensate: A mixture consisting primarily of

pentanes and heavier hydrocarbons which is

recovered as a liquid from natural gas in lease or

field separation facilities, exclusive of products

recovered at natural gas processing plants or

facilities.

Lease Separator: A lease separator is a facility

installed at the surface for the purpose of (a)

separating gases from produced crude oil and water

at the temperature and pressure conditions of the

separator, and/or (b) separating gases from that

portion of the produced natural gas stream which

liquefies at the temperature and pressure conditions

of the separator.

Natural Gas: A mixture of hydrocarbon compounds

and small quantities of various nonhydrocarbons

existing in the gaseous phase or in solution with

crude oil in natural underground reservoirs at

reservoir conditions. The principal hydrocarbons

normally contained in the mixture are methane,

ethane, propane, butane, and pentanes. Typical

nonhydrocarbon gases which may be present in

reservoir natural gas are water vapor, carbon

dioxide, helium, hydrogen sulfide, and nitrogen.

Under reservoir conditions, natural gas and the

liquefiable portions occur either in a single gaseous

phase in the reservoir or in solution with crude oil,

and are not distinguishable at the time as separate

substances. (See Natural Gas, Associated--Dissolved

and Natural Gas, Nonassociated)

Natural Gas, Associated--Dissolved: The combined

volume of natural gas which occurs in crude oil

reservoirs either as free gas (associated) or as gas in

solution with crude oil (dissolved).

Natural Gas, “Dry”: The actual or calculated

volumes of natural gas which remain after:

1. The liquefiable hydrocarbon portion has been

removed from the gas stream (i.e., gas after

lease, field, and/or plant separation)

2. Any volumes of nonhydrocarbon gases have

been removed where they occur in sufficient

quantity to render the gas unmarketable.

Natural Gas, Nonassociated: Natural gas not in

contact with significant quantities of crude oil in a

reservoir.

Natural Gas Liquids: Those hydrocarbons in natural

gas which are separated from the gas through the

processes of absorption, condensation, adsorption, or

other methods in gas processing or cycling plants.

Generally such liquids consist of propane and

heavier hydrocarbons and are commonly referred to

as condensate, natural gasoline, or liquefied

petroleum gases. Where hydrocarbon components

lighter than propane are recovered as liquids, these

components are included with natural gas liquids.

Natural Gas Processing Plant: A facility designed to

recover natural gas liquids from a stream of natural

gas which may or may not have passed through

lease separators and/or field separation facilities.

Another function of the facility is to control the

quality of the processed natural gas stream. Cycling

plants are considered natural gas processing plants.

Natural Gas, Wet After Lease Separation: The

volume of natural gas remaining after removal of

lease condensate in lease and/or field separation

facilities, if any, and after exclusion of

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154 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
nonhydrocarbon gases where they occur in sufficient

quantity to render the gas unmarketable. Natural gas

liquids may be recovered from volumes of natural

gas, wet after lease separation, at natural gas

processing plants. (See Lease Condensate, Lease

Separator, and Field Separation Facility)

Net Revisions: (See Revisions)

New Field: A field discovered during the report

year.

New Field Discoveries: The volumes of proved

reserves of crude oil, natural gas and/or natural gas

liquids discovered in new fields during the report

year.

New Reservoir: A reservoir discovered during the

report year.

New Reservoir Discoveries in Old Fields: The

volumes of proved reserves of crude oil, natural gas,

and/or natural gas liquids discovered during the

report year in new reservoir(s) located in old fields.

Nonproducing Reservoirs: Reservoirs in which

proved liquid or gaseous hydrocarbon reserves have

been identified, but which did not produce during

the last calendar year regardless of the availability

and/or operation of production, gathering, or

transportation facilities.

Old Field: A field discovered prior to the report

year.

Old Reservoir: A reservoir discovered prior to the

report year.

Operator, Gas Plant: The person responsible for the

management and day--to--day operation of one or

more natural gas processing plants as of December

31 of the report year. The operator is generally a

working interest owner or a company under contract

to the working interest owner(s). Plants shut down

during the report year are also to be considered

“operated” as of December 31. (See Person)

Operator, Oil and/or Gas Well: The person

responsible for the management and day--to--day

operation of one or more crude oil and/or natural

gas wells as of December 31 of the report year. The

operator is generally a working interest owner or a

company under contract to the working interest

owner(s). Wells included are those which have

proved reserves of crude oil, natural gas, and/or

lease condensate in the reservoirs associated with

them, whether or not they are producing. Wells

abandoned during the report year are also to be

considered “operated” as of December 31. (See

Person, Proved Reserves of Crude Oil, Proved

Reserves of Natural Gas, Proved Reserves of Lease

Condensate, Report Year, and Reservoir)

Ownership: (See Gross Working Interest

Ownership Basis)

Parent Company: The parent company of a business

entity is an affiliated company which exercises

ultimate control over that entity, either directly or

indirectly through one or more intermediaries. (See

Affiliated (Associated) Company and Control)

Person: An individual, a corporation, a partnership,

an association, a joint--stock company, a business

trust, or an unincorporated organization.

Pool: In general, a reservoir. In certain situations a

pool may consist of more than one reservoir. (See

Field Area)

Plant Liquids: Those volumes of natural gas liquids

recovered in natural gas processing plants.

Production, Crude Oil: The volumes of crude oil

which are extracted from oil reservoirs during the

report year. These volumes are determined through

measurement of the volumes delivered from lease

storage tanks, (i.e., at the point of custody transfer)

with adjustment for (1) net differences between

opening and closing lease inventories, and for (2)

basic sediment and water. Oil used on the lease is

considered production.

Production, Lease Condensate: The volume of lease

condensate produced during the report year. Lease

condensate volumes include only those volumes

recovered from lease or field separation facilities.

(See Lease Condensate)

Production, Natural Gas, Dry: The volume of

natural gas withdrawn from reservoirs during the

report year less (1) the volume returned to such

reservoirs in cycling, repressuring of oil reservoirs

and conservation operations; less (2) shrinkage

resulting from the removal of lease condensate and

plant liquids; and less (3) nonhydrocarbon gases

where they occur in sufficient quantity to render the

gas unmarketable. Volumes of gas withdrawn from

gas storage reservoirs and native gas, which has been

transferred to the storage category, are not

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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 155
considered production. This is not the same as

marketed production, since the latter also excludes

vented and flared gas, but contains plant liquids.

Production, Natural Gas, Wet after Lease

Separation: The volume of natural gas withdrawn

from reservoirs during the report year less (1) the

volume returned to such reservoirs in cycling,

repressuring of oil reservoirs and conservation

operations; less (2) shrinkage resulting from the

removal of lease condensate; and less (3)

nonhydrocarbon gases where they occur in sufficient

quantity to render the gas unmarketable. Volumes of

gas withdrawn from gas storage reservoirs and

native gas, which has been transferred to the storage

category, are not considered production. This is not

the same as marketed production, since the latter

excludes vented and flared gas.

Production, Natural Gas Liquids: The volume of

natural gas liquids removed from natural gas in lease

separators, field facilities, gas processing plants or

cycling plants during the report year.

Production, Plant Liquids: The volume of liquids

removed from natural gas in natural gas processing

plants or cycling plants during the report year.

Proved Reserves of Crude Oil: Proved reserves of

crude oil as of December 31 of the report year are the

estimated quantities of all liquids defined as crude

oil, which geological and engineering data

demonstrate with reasonable certainty to be

recoverable in future years from known reservoirs

under existing economic and operating conditions.

Reservoirs are considered proved if economic

producibility is supported by actual production or

conclusive formation test (drill stem or wire line), or

if economic producibility is supported by core

analyses and/or electric or other log interpretations.

The area of an oil reservoir considered proved

includes (1) that portion delineated by drilling and

defined by gas--oil and/or oil--water contacts, if any;

and (2) the immediately adjoining portions not yet

drilled, but which can be reasonably judged as

economically productive on the basis of available

geological and engineering data. In the absence of

information on fluid contacts, the lowest known

structural occurrence of hydrocarbons is considered

to be the lower proved limit of the reservoir.

Volumes of crude oil placed in underground storage

are not to be considered proved reserves.

Reserves of crude oil which can be produced

economically through application of improved

recovery techniques (such as fluid injection) are

included in the “proved” classification when

successful testing by a pilot project, or the operation

of an installed program in the reservoir, provides

support for the engineering analysis on which the

project or program was based.

Estimates of proved crude oil reserves do not include

the following: (1) oil that may become available from

known reservoirs but is reported separately as

“indicated additional reserves”; (2) natural gas

liquids (including lease condensate); (3) oil, the

recovery of which is subject to reasonable doubt

because of uncertainty as to geology, reservoir

characteristics, or economic factors; (4) oil that may

occur in undrilled prospects; and (5) oil that may be

recovered from oil shales, coal, gilsonite, and other

such sources. It is not necessary that production,

gathering or transportation facilities be installed or

operative for a reservoir to be considered proved.

Proved Reserves of Lease Condensate: Proved

reserves of lease condensate as of December 31 of the

report year are the volumes of lease condensate

expected to be recovered in future years in

conjunction with the production of proved reserves

of natural gas as of December 31 of the report year,

based on the recovery efficiency of lease and/or field

separation facilities installed as of December 31 of

the report year. (See Lease Condensate and Proved

Reserves of Natural Gas)

Proved Reserves of Natural Gas: Proved reserves of

natural gas as of December 31 of the report year are

the estimated quantities which analysis of geological

and engineering data demonstrate with reasonable

certainty to be recoverable in future years from

known reservoirs under existing economic and

operating conditions.

Reservoirs are considered proved if economic

producibility is supported by actual production or

conclusive formation test (drill stem or wire line), or

if economic producibility is supported by core

analyses and/or electric or other log interpretations.

The area of a gas reservoir considered proved

includes: (1) that portion delineated by drilling and

defined by gas--oil and/or gas--water contacts, if

any; and (2) the immediately adjoining portions not

yet drilled, but which can be reasonably judged as

economically productive on the basis of available

geological and engineering data. In the absence of

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156 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report
information on fluid contacts, the lowest known

structural occurrence of hydrocarbons is considered

to be the lower proved limit of the reservoir.

Volumes of natural gas placed in underground

storage are not to be considered proved reserves.

For natural gas, wet after lease separation, an

appropriate reduction in the reservoir gas volume

has been made to cover the removal of the

liquefiable portions of the gas in lease and/or field

separation facilities and the exclusion of

nonhydrocarbon gases where they occur in sufficient

quantity to render the gas unmarketable.

For dry natural gas, an appropriate reduction in the

gas volume has been made to cover the removal of

the liquefiable portions of the gas in lease and/or

field separation facilities, and in natural gas

processing plants, and the exclusion of

nonhydrocarbon gases where they occur in sufficient

quantity to render the gas unmarketable.

It is not necessary that production, gathering, or

transportation facilities be installed or operative for a

reservoir to be considered proved. It is to be

assumed that compression will be initiated if and

when economically justified.

Proved Reserves of Natural Gas Liquids: Proved

reserves of natural gas liquids as of December 31 of

the report year are those volumes of natural gas

liquids (including lease condensate) demonstrated

with reasonable certainty to be separable in the

future from proved natural gas reserves, under

existing economic and operating conditions.

Proved Ultimate Recovery: The sum of proved

reserves and cumulative production. It is expected to

change over time for any field, group of fields, State,

or Country. Proved Ultimate Recovery does not

represent the maximum recoverable volume of

resources for an area. It is instead a gauge of how

much has already been produced plus proved

reserves. Proved reserves of crude oil or natural gas

are the estimated quantities of petroleum which

geological and engineering data demonstrate with

reasonable certainty to be recoverable in future years

from known reservoirs under existing economic and

operating conditions. When deterministic proved

reserves estimation methods are used, the term

reasonable certainty is intended to express a high

degree of confidence that the estimated quantities

will be recovered. When probabilistic methods are

used there should be at least a 90 percent probability

that the actual quantities recovered will exceed the

estimate.

Report Year: The calendar year to which data

reported in this publication pertain.

Reserves: (See Proved Reserves)

Reserve Additions: Consist of adjustments, net

revisions, extensions to old reservoirs, new reservoir

discoveries in old fields, and new field discoveries.

Reserves Changes: Positive and negative revisions,

extensions, new reservoir discoveries in old fields,

and new field discoveries, which occurred during the

report year.

Reservoir: A porous and permeable underground

formation containing an individual and separate

natural accumulation of producible hydrocarbons (oil

and/or gas) which is confined by impermeable rock

or water barriers and is characterized by a single

natural pressure system.

Revisions: Changes to prior year--end proved

reserves estimates, either positive or negative,

resulting from new information other than an

increase in proved acreage (extension). Revisions

include increases of proved reserves associated with

the installation of improved recovery techniques or

equipment. They also include correction of prior

report year arithmetical or clerical errors and

adjustments to prior year--end production volumes

to the extent that these alter reported prior year

reserves estimates.

Royalty (Including Overriding Royalty) Interests:

These interests entitle their owner(s) to a share of the

mineral production from a property or to a share of

the proceeds therefrom. They do not contain the

rights and obligations of operating the property, and

normally do not bear any of the costs of exploration,

development, and operation of the property.

Subdivision: A prescribed portion of a given State

or other geographical region defined in this

publication for statistical reporting purposes.

Subsidiary Company: A company which is

controlled through the ownership of voting stock, or

a corporate joint venture in which a corporation is

owned by a small group of businesses as a separate

and specific business or project for the mutual

benefit of the members of the group. (See Control)

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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report 157
Total Discoveries: The sum of extensions, new

reservoir discoveries in old fields, and new field

discoveries, which occurred during the report year.

Total Liquid Hydrocarbon Reserves: The sum of

crude oil and natural gas liquids reserves volumes.

Total Operated Basis: The total reserves or

production associated with the wells operated by an

individual operator. This is also commonly known as

the “gross operated” or “8/8ths” basis.

Working Interest: A working interest permits the

owner(s) to explore, develop and operate a property.

The working interest owner(s) bear(s) the costs of

exploration, development and operation of the

property, and in return is (are) entitled to a share of

the mineral production from the property or to a

share of the proceeds therefrom.

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158 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report