DOE/EIA–0216(96)

Distribution Category UC–950

U.S. Crude Oil, Natural Gas,

and Natural Gas Liquids Reserves

1996 Annual Report

November 1997

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.
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Preface

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

Liquids Reserves 1996 Annual Report is the 20th

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, 1996, as well as production volumes

for the United States and selected States and State

subdivisions for the year 1996. 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 1996 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 1996; 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, Paul Chapman, Steven

G. Grape, and Rhonda S. Green. Report quality

assurance was provided by Rafi M. Zeinalpour and

technical editing was provided by David F.

Morehouse. Supplemental contributions were made

by Jack S. Sanders, William L. Monroe, and Robert F.

King.

Address questions on specific sections of the

publication to the following analyst/author:

n Executive Summary and Appendix G

John H. Wood 214.720.6160

Fax: 214.720.6155 or E–mail: jwood@eia.doe.gov

n Chapter 2, 3, 4, 5 and Appendix F

Steven G. Grape 214.720.6174

Fax: 214.720.6155 or E–mail: sgrape@eia.doe.gov

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

Rhonda S. Green 214.720.6161

Fax 214.720.6155 or E–mail rgreen@eia.doe.gov

This is Paul Chapman’s 14th and last reserves report

as he prepares to retire at the end of the year. His

significant contributions to the reserves program will

be missed by report users and EIA staff.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report iii
Energy Information Administration

iv U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Other EIA Oil and Gas Publications

Other reports published by the Energy Information Administration (EIA) offer

additional information and analysis related to domestic oil and gas supply.

They may be obtained from the Government Printing Office in the same

manner as this oil and gas reserves report.

Natural Gas Annual 1996, DOE/EIA–0131(96), September 1997

Petroleum Supply Annual 1996, DOE/EIA–0340(96), June 1997

These annual reports provide comprehensive statistics on supply, disposition,

and prices of natural gas and petroleum in the United States.

Natural Gas 1996: Issues and Trends, DOE/EIA–0560(96), December 1996

Focuses on the increasing choices and challenges in the natural gas industry, as

regulatory requirements are increasingly removed from the sale and transport

of natural gas.

Petroleum 1996: Issues and Trends, DOE/EIA–0615, September 1996

Presents analyses of a broad spectrum of petroleum markets, ranging from the

drilling rig in the oil field to the pump at the local gasoline station.

EIA Electronic Documents

Computer users can access and download these electronic–format reports and

many other EIA Data and Analysis reports from EIA's Home Page on the World

Wide Web. Point your web browser to http://www.eia.doe.gov. In the future,

many products will only be available in electronic form.

Natural Gas Productive Capacity for the Lower 48 States 1986 Through 1998

Petroleum Marketing Annual 1996

Oil and Gas Field Code Master List 1996

Data archive of historical reserves estimates for U.S. Crude Oil, Natural Gas

and Natural Gas Liquids

Historical Natural Gas Annual - 1930 through 1996

Cost and Indices for Domestic Oil and Gas Field Equipment and Production

Operations 1993-1996
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Reserves Changes Since 1977 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

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

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

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

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

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

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

Petroleum Consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

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

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

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

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

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

Total Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

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

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Areas of Note: Large Discoveries and Reserve Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Alpine Field, Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

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

The Permian Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Chalk one up for Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Other Gain Areas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Areas of Note: Large Reserve Declines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Pacific Federal Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

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

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

Indicated Additional Reserves. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

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

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

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

Revisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Wet Natural Gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Nonassociated Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Associated-Dissolved Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report v
Page

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

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

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

Reserves in Nonproducing Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

5. Natural Gas Liquids Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Natural Gas Liquids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Natural Gas Plant Liquids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Lease Condensate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

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

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

Reserves in Nonproducing Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Appendices

A. Operator Data by Size Class . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

B. Top 100 Oil and Gas Fields for 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

C. Conversion to the Metric System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

D. Historical Reserves Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

E. Summary of Data Collection Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

F. Statistical Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

G. Estimation of Reserves and Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117

H. Maps of Selected State Subdivisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125

I. Annual Survey Forms for Domestic Oil and Gas Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135

Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141

Tables

1. U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids, 1986-1996 . . . . . . . . . . . . 4

2. Reserves Changes, 1977-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

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

Average Number of Active Rotary Drilling Rigs, 1970-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . 10

4. U.S. Exploratory and Development Well Completions, 1970-1996 . . . . . . . . . . . . . . . . . . . . . . . . . 12

5. International Oil and Natural Gas Reserves as of December 31, 1996 . . . . . . . . . . . . . . . . . . . . . . . 16

6. Crude Oil Proved Reserves, Reserves Changes, and Production, 1996 . . . . . . . . . . . . . . . . . . . . . . 20

7. Reported Indicated Additional Crude Oil Reserves, 1996. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 1996 . . . . . . . . . . . . . . . . . . 28

9. Natural Gas Proved Reserves, Reserves Changes, and Production,

Wet After Lease Separation, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

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

Wet After Lease Separation, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

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

Wet After Lease Separation, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

12. U.S. Coalbed Methane Proved Reserves and Production, 1993-1996 . . . . . . . . . . . . . . . . . . . . . . . 34

13. Reported Reserves of Natural Gas, Wet After Lease Separation, in Nonproducing Reservoirs, 1996 . . . . . . . 36

14. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 1996 . . . . . . . . . . . . . . . . 38

Energy Information Administration

vi U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
Page

15. Natural Gas Plant Liquids Proved Reserves and Production, 1996. . . . . . . . . . . . . . . . . . . . . . . . . 39

16. Lease Condensate Proved Reserves and Production, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Figures

1. U.S. Crude Oil Proved Reserves, 1986-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

2. Components of Reserves Changes for Crude Oil, 1986-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

3. U.S. Dry Natural Gas Proved Reserves, 1986-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

4. Components of Reserves Changes for Dry Natural Gas, 1986-1996 . . . . . . . . . . . . . . . . . . . . . . . . 7

5. U.S. Natural Gas Liquids Proved Reserves, 1986-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

6. Components of Reserves Changes for Natural Gas Liquids, 1986-1996 . . . . . . . . . . . . . . . . . . . . . . 8

7. U.S. Exploratory Gas Well Completions, 1977-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

8. U.S. Exploratory Oil Well Completions, 1977-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

9. U.S. Total Discoveries of Dry Natural Gas per Exploratory Gas Well Completion, 1977-1996 . . . . . . . . . . . 13

10. U.S. Total Discoveries of Crude Oil per Exploratory Oil Well Completion, 1977-1996 . . . . . . . . . . . . . . . 13

11. Reserves-to-Production Ratios for Crude Oil, 1945-1996. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

12. Reserves-to-Production Ratios for Wet Natural Gas, 1945-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . 15

13. Components of Ultimate Recovery for Crude Oil and Lease Condensate, 1977-1996 . . . . . . . . . . . . . . . 15

14. Components of Ultimate Recovery for Wet Natural Gas, 1977-1996 . . . . . . . . . . . . . . . . . . . . . . . . 15

15 Reserve Additions Nearly Replace U.S. Oil Production in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . 19

16. 1996 Crude Oil Proved Reserves by Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

17. Changes in Crude Oil Proved Reserves by Area, 1995 to 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . 21

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

19. 1996 Dry Natural Gas Proved Reserves by Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

20. Changes in Dry Natural Gas Proved Reserves by Area, 1995 to 1996 . . . . . . . . . . . . . . . . . . . . . . . 30

21. Coalbed Methane Proved Reserves, 1989-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report vii
Executive Summary

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

third year in a row, the first sustained uptrend since

1967. While gas reserves were up 1 percent, crude oil

reserves declined 1 percent in 1996. This was only

half the average decline in the last decade, but it

extends the oil proved reserves down trend to 9

consecutive years. Large oil and gas discoveries in

the Federal offshore—several in deep

water—continued to play a major role in increasing

gas reserves and preventing a larger decline in oil

reserves. Successful oil and gas well completions

were up as were oil and gas prices.

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 1996 U.S. proved

reserves of crude oil, natural gas, and natural gas

liquids is the 20th in the annual series prepared by

the Energy Information Administration.

Natural Gas

Gas reserves rose because reserve additions replaced

107 percent of gas production in 1996. U.S. natural

gas reserves began increasing after World War II,

peaking in 1967. A rapid decline ensued, interrupted

for one year, when the American Petroleum Institute

booked 26 trillion cubic feet of proved reserves for

the Prudhoe Bay Field on the Alaskan North Slope.

Most of this gas was removed from the proved

category in 1988 because lack of a market made it

uneconomic. The decline flattened out in 1977, but

persisted through 1993 at an average of 1 percent per

year. The current 3-year uptrend began in 1994.

For 1996, revisions and adjustments to reserves in

existing fields were down slightly. Total discoveries

were up from 1995, at almost the same level as the

high discovery year of 1990.

Improved exploration and deepwater production

technologies enhanced the ability to discover and

develop offshore fields. There were significant events

in the Gulf of Mexico, especially in deep waters.

Shell’s Mars Project in Mississippi Canyon Block 807

Field came on line, establishing a world water-depth

record of 2,940 feet for a permanent drilling and

production platform.

Oryx’s Neptune spar (a floating large-diameter

vertical cylinder supporting a deck and tethered to

the ocean floor) is an example of the use of

state-of-the-art engineering and technology that

lowers field development cost in deep water. The

Neptune spar allows the exploitation of fields in up

to 10,000 feet of water and can be moved to a new

site after developed reservoirs are depleted.

Coalbed methane reserves continued to grow,

accounting for over 6 percent of 1996 natural gas

reserves. Coalbed methane production increased to a

trillion cubic feet, over 5 percent of U.S. dry gas

production.

U.S. total discoveries of dry gas reserves were 12,318

billion cubic feet in 1996, up 12 percent from 1995.

Texas and the Gulf of Mexico Federal Offshore

accounted for over two-thirds of them. Total

discoveries, which equaled 65 percent of 1996 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 1,451 billion cubic

feet, down from 1995, but 10 percent higher

than the prior 10-year average.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report ix

As of December 31, proved reserves were:

Dry Natural Gas (billion cubic feet)

1995 165,146

1996 166,474

Increase +0.8%

Crude Oil (million barrels)

1995 22,351

1996 22,017

Decrease –1.5%

Natural Gas Liquids (million barrels)

1995 7,399

1996 7,823

Increase +5.7%
n Field extensions were 7,757 billion cubic feet, up

13 percent from 1995.

n New reservoir discoveries in old fields were 3,110

billion cubic feet, up 27 percent from 1995.

The net volume of revisions and adjustments to

reserves played a large role in increasing U.S. natural

gas proved reserves. It amounted to 7,871 billion

cubic feet in 1996. Texas, where proved gas reserves

increased in 1996, had the largest increase in revisions

and adjustments.

Other 1996 natural gas events of note:

n Exploratory gas well completions increased

again, reaching 1,011 in 1996.

n Total discoveries per exploratory gas well were

down in 1996, but roughly twice that of the

early 1980s.

n Natural gas prices at the wellhead increased

rapidly during the last half of the year, yielding

an annual average of $2.25 per thousand cubic

feet, a 45 percent increase.

Crude Oil

Crude oil reserve additions replaced 85 percent of

1996 oil production.

Total discoveries of crude oil were 927 million barrels

in 1996, nearly as high as last year and over 40

percent higher than the prior 10-year average for the

United States. The Gulf of Mexico Federal Offshore

accounted for 34 percent, Alaska for 21 percent, and

Texas for 18 percent.

n New reservoir discoveries in old fields were 141

million barrels, down sharply from 1995 but

still higher than the prior 10-year average.

n New field discoveries were 243 million barrels,

more than twice those of 1995 and the prior

10-year average. Alaska had 53 percent and the

Gulf of Mexico Federal Offshore 39 percent of

the new field discoveries.

n Field extensions added 543 million barrels of

proved oil reserves in 1996, more than in 1995.

Revisions and adjustments were 912 million barrels in

1996. They still account for 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. Alaska’s

reserves declined in 1996 despite substantial new field

discoveries because there were few revisions and

adjustments.

Other 1996 crude oil events of note:

n The annual average domestic first purchase

price for crude oil increased to $18.46 per barrel

in 1996, up 24 percent.

n Oil well completions increased to 8,568.

Indicated additional reserves of crude oil were 2,876

million barrels in 1996, an 8-percent increase over

1995. 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 the Alaskan North

Slope, California, Texas, and Louisiana implies that

significant upward revisions to crude oil proved

reserves can continue to occur in the future.

Improved technology has been an important factor in

the increase of oil production and proved reserves in

Alaska’s West Sak and Kuparuk River fields. It has

now made technically feasible projects economically

viable.

In the lower 48 States, smaller operators have been

successful in their acquisition of properties in

existing fields from larger operators. By expanding

their drilling programs they have added proved

reserves and production to the nation’s inventory. In

addition, there was an unexpected extension of the

Austin Chalk formation, as an oil play, into north

Louisiana.

Natural Gas Liquids

U.S. natural gas liquids proved reserves increased 6

percent to 7,823 million barrels in 1996. 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 29,840 million

barrels in 1996, a slight increase over the 1995 level.

Natural gas liquids were about a quarter of total

proved reserves of liquid hydrocarbon in 1996.

Energy Information Administration

x U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
Methodology Changes

Using the extensive statistical database of reserves

information it maintains, EIA has developed a new

method of analyzing reserves survey information.

Utilizing data submitted by large operators, the total

reserves for specific geographic areas are estimated.

This new method provides an estimate of National

oil and gas reserves that meets EIA’s stringent data

quality standards while surveying 84 percent fewer

operators than in previous years and lowering

survey costs. To maintain database quality, this new

method will only be applied every other year.

Data

These estimates are based upon analysis of data from

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

Gas Reserves,” filed by 568 operators of oil and gas

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

Origin of Natural Gas Liquids Production,” filed by

operators of 686 active natural gas processing plants.

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

natural gas are associated with expected errors of

less than 1 percent.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report xi
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 1996. 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 expected

errors of less than 1 percent.

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 1996 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 23,410 probable active operators and the

Form EIA-64A plant frame contained 710 probable

active natural gas processing plants in the United

States when the 1996 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 1996.

For the report year 1996, EIA mailed 665 EIA-23 forms

to all known large and intermediate size oil and gas

well operators that were believed to be active during

1996. Of these, 59 were found to be nonoperators that

did not have successor operators in 1996. Data were

received from 616 operators, an overall response rate of

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

survey. EIA mailed 725 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 686 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 1996,

the Form EIA-23 National production estimates were

1.3 percent lower than the comparable Petroleum Supply

Annual 1996 volumes for crude oil and lease

condensate combined, and were 0.4 percent higher

than the comparable Natural Gas Annual 1996 volume

for 1996 dry natural gas. For report year 1996, the Form

EIA-64A National estimates were 2.9 percent higher

than the Petroleum Supply Annual 1996 volume for

natural gas plant liquids production.

Energy Information Administration

2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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, 1996:

n Crude Oil — 22,017 million barrels

n Dry Natural Gas — 166,474 billion cubic feet

n Natural Gas Liquids — 7,823 million barrels.

This Overview section summarizes the 1996 proved

reserves balances of crude oil, dry natural gas, and

natural gas liquids on a National level, and provides

historical comparisons between 1996 and years past.

Table 1 lists the estimated annual reserve balances

since 1986. In 1996, the proved reserves of dry natural

gas increased by 1 percent over the 1995 level. This is

third consecutive year that gas reserves have increased.

Crude oil proved reserves declined in 1996—down less

than 2 percent from 1995's level, but the ninth

consecutive year of decline.

Crude Oil

Proved reserves of crude oil decreased by 334 million

barrels in 1996. The largest decline was in Alaska,

where reserves decreased 306 million barrels. The

largest increase occurred in the Federal Offshore areas

in the Gulf of Mexico, where 49 million barrels of crude

oil proved reserves were added to the National total.

Figure 1 shows the crude oil proved reserves levels by

major region and Figure 2 shows the components of

reserves changes from 1986 through 1996.

As shown in Figure 2, total reserve additions (the

positive side of the scale) decreased compared to 1995's

level but remained higher than 1994's level. Production

of crude oil declined slightly for the sixth year in a row.

However, production still exceeded the amount of

reserve additions, so U.S. crude oil proved reserves

declined slightly in 1996. Operators replaced 85 percent

of their 1996 oil production with reserve additions.

Total discoveries are those reserves attributable to field

extensions, new field discoveries, and new reservoir

discoveries in old fields. There were 927 million barrels of

total discoveries of crude oil proved reserves in 1996.

This is slightly less than the discoveries in 1995.

Extensions added 543 million barrels of proved

reserves. This is 9 percent more than in 1995 and 29

percent more than the average extensions in the prior 10

years (422 million barrels).

New field discoveries were 243 million barrels, more than

double the 1995 level. This is more than twice the

average volume discovered in the prior 10 years (103

million barrels).

New reservoir discoveries in old fields added 141 million

barrels of proved reserves. This is less than half of

1995's decade-high total of 343 million barrels, but is 9

percent higher than the prior 10-year average for the

United States (129 million barrels).

Revisions and adjustments added 912 million barrels of

proved reserves. This is 79 percent of 1995's volume

and 71 percent of the average volume of the prior 10

years (1,293 million barrels).

Crude oil reserves have been primarily sustained by

continuing upward revisions and adjustments to the

reserves of older fields. During the 1986–1995 decade,

revisions and adjustments accounted for an average of 66

percent of reserve additions. In 1996, revisions and

adjustments accounted for 50 percent of reserve

additions.

Production deducted an estimated 2,173 million barrels

of proved reserves from the National total. Production

was down almost 2 percent from 1995's level (2,213

million barrels) and at 85 percent of the prior 10-year

average (2,553 million barrels).

The overall 1996 United States reduction in crude oil

proved reserves was 334 million barrels. In the 10 years

prior to 1996, the United States had an average annual

reduction of 607 million barrels of crude oil proved

reserves. The 1996 decline is only 55 percent of that

average.

Natural Gas

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

the third year in a row in 1996—up 1 percent from

1995's level to a total of 166,474 billion cubic feet. Dry

natural gas reserves decreased by 203 billion cubic feet

in Alaska, but increased for the lower 48 States by 1,531

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 3
Energy Information Administration

4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table 1. U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids, 1986-1996

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)

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

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

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 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

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

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

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

1996 contained in the Petroleum Supply Annual 1996, DOE/EIA-0340(95) and the Natural Gas Annual 1996, DOE/EIA-0131(96).

Sources: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1986 through 1996 annual reports, DOE/EIA-0216.{1-10}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 5

Figure 1. U.S. Crude Oil Proved Reserves, 1986-1996

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1986-1995 annual reports, DOE/EIA-0216.{1-10}

-5

-4

-3

-2

-1

0

1

2

3

4

5

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

-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

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

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, 1986-1996
billion cubic feet. Figure 3 shows the dry natural gas

proved reserves levels by major region and Figure 4

shows the components of reserves changes from 1986

through 1996.

Operators were able to replace all of 1996's dry gas

production (estimated to be about 18,861 billion cubic

feet) with reserve additions, and then add 1,328 billion

cubic feet of dry natural gas to the proved reserves

total.

For 1996, U.S. total discoveries of dry gas reserves were

12,318 billion cubic feet, up 12 percent from 1995. Total

discoveries were 61 percent of all dry gas reserve

additions in 1996, while revisions and adjustments

provided the rest. Unlike crude oil, total discoveries of

dry natural gas proved reserves usually exceed the

revisions and adjustments—in the past decade, total

discoveries have accounted for an average of 67 percent

of all dry gas reserve additions.

Extensions added 7,757 billion cubic feet of proved

reserves. This is 13 percent more than 1995's extensions

and 126 percent of the average of extensions over the

prior 10 years (6,140 billion cubic feet).

New field discoveries added 1,451 billion cubic feet of

proved reserves. This is 13 percent less than what was

discovered in 1995, but 10 percent higher than the

average volume discovered in the prior 10 years (1,324

billion cubic feet).

New reservoir discoveries in old fields added 3,110 billion

cubic feet of proved reserves. This is 27 percent more

than the volume discovered in 1995, and 48 percent

higher than the prior 10-year average (2,096 billion

cubic feet).

Revisions and Adjustments added 7,871 billion cubic feet

of proved reserves. This is 95 percent of 1995's revisions

and adjustments.

Production deducted an estimated 18,861 billion cubic

feet of proved reserves from the National total. Gas

production increased 5 percent compared to 1995—to

the highest level recorded since 1979.

Coalbed methane gas production and reserves are

included in the 1996 totals. However, EIA separately

tracks these reserves in order to record the

development and performance of this gas source.

Coalbed methane gas reserves increased to 10,566

billion cubic feet in 1996, a slight increase over 1995's

level. Coalbed methane gas reserves account for 6

percent of 1996 U.S. dry natural gas reserves, and

coalbed methane production rose in 1996 to 1,003

billion cubic feet—5 percent of U.S. dry gas production.

No Federal tax incentives for new coalbed methane

wells have been available for 3 years.

Natural Gas Liquids

Proved reserves of natural gas liquids (NGL) increased

6 percent to 7,823 million barrels in 1996. An increase of

31 million barrels occurred in Alaska, while the lower

48 States' reserves increased by 393 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 1986 through

1996.

Operators replaced 150 percent of their 1996 natural

gas liquids production with reserve additions. Total

discoveries accounted for 49 percent of all NGL reserve

additions, while revisions and adjustments accounted for

the rest.

Total proved reserves of liquid hydrocarbons (crude oil

plus natural gas liquids) were 29,840 million barrels in

1996—a slight increase over the 1995 level. Natural gas

liquids represented about a quarter of total liquid

hydrocarbon proved reserves in 1996.

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 1996. 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 of each component of

reserves changes are also listed in Table 2, 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 1996 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 792 million barrels per

year of new reserves

n revised and adjusted their proved reserves

upward by an average of 1,359 million barrels

per year from revisions and adjustments

n reduced proved reserves by an average 574

million barrels per year (the difference between

post-1976 average annual production and

Energy Information Administration

6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 7

Figure 4. Components of Reserves Changes for Dry Natural Gas, 1986-1996

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1986-1995 annual reports, DOE/EIA-0216.{1-10}

Figure 3. U.S. Dry Natural Gas Proved Reserves, 1986-1996

0

20

40

60

80

100

120

140

160

180

200

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

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

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

Trillion Cubic Feet

-30

-20

-10

0

10

20

30

New Fields New Reservoirs Extensions

Production Revisions & Adjustments Net Reserves Changes
Energy Information Administration

8 U.S. Crude Oil, NaturalGas, and Natural Gas Liquids Reserves 1996 Annual Report

Figure 5. U.S. Natural Gas Liquids Proved Reserves, 1986-1996

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1986-1995 annual reports, DOE/EIA-0216.{1-10}

0

1

2

3

4

5

6

7

8

9

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

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

1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996

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, 1986-1996
post-1976 average annual reserve additions)

because production has outpaced reserve

additions.

Crude oil reserves have been primarily sustained by

continuing upward revisions and adjustments to the

reserves of older fields, not total discoveries. The bulk of

post-1976 crude oil reserves additions were the 27,186

million barrels of revisions and adjustments, which

accounted for 63 percent of all crude oil reserves

additions since 1977. The 15,836 million barrels of total

discoveries accounted for the remaining 37 percent of

reserves additions.

Compared to the average reserves changes since 1977,

1996 was another good year for crude oil discoveries,

even though the U.S. reserves total declined. 1996's total

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

average by 17 percent, while revisions and adjustments

were less than the post-1976 U.S. average.

In 1996, all three components of total discoveries (new

fields, new reservoir discoveries in old fields, and

extensions) exceeded the post-1976 averages, but the

most significant component was new field discoveries.

Since 1977, operators have found only an average of

142 million barrels of crude oil proved reserves per

year in new fields. In 1996, operators discovered 243

million barrels of proved reserves—71 percent more

than the post-1976 average.

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

n discovered an average of 11,874 billion cubic

feet per year of new reserves

n revised and adjusted their proved reserves

upward by an average 3,335 billion cubic feet

per year

n reduced reserves by an average 2,340 billion

cubic feet per year.

Unlike crude oil reserves, natural gas reserves have

been sustained primarily by total discoveries. Revisions

and adjustments account for only 22 percent of all

reserve additions since 1977. However, since 1986, the

contribution from revisions and adjustments has

increased substantially (39 percent in 1996).

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 9

Table 2. Reserves Changes, 1977-1996

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 ........... 2,467 123 7.2 2,845 142 6.6

New Reservoir Discoveries in Old Fields . . 2,760 138 8.0 2,790 140 6.5

Extensions ................ 9,098 455 26.4 10,201 510 23.7

Total Discoveries ............. 14,325 716 41.6 15,836 792 36.8

Revisions and Adjustments ........ 20,139 1,007 58.4 27,186 1,359 63.2

Total Reserve Additions .......... 34,464 1,723 100.0 43,022 2,151 100.0

Production ................ 42,649 2,132 123.7 54,507 2,725 126.7

Net Reserve Change............ -8,185 -409 -23.7 -11,485 -574 -26.7

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 ........... 38,886 1,944 12.1 38,974 1,949 12.8

New Reservoir Discoveries in Old Fields . . 51,756 2,588 16.1 52,121 2,606 17.1

Extensions ................ 145,489 7,274 45.3 146,390 7,320 48.1

Total Discoveries ............. 236,131 11,807 73.6 237,485 11,874 78.1

Revisions and Adjustments ........ 84,691 4,235 26.4 66,697 3,335 21.9

Total Reserve Additions .......... 320,822 16,041 100.0 304,182 15,209 100.0

Production ................ 344,480 17,224 107.4 350,986 17,549 115.4

Net Reserve Change............ -23,658 -1,183 -7.4 -46,804 -2,340 -15.4

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1977-1996 annual reports, DOE/EIA-0216.{1-19}
Compared to the average dry natural gas reserves

changes since 1977, 1996 had more total discoveries than

the average. Although 1996's new field discoveries were

lower than the average, there were more extensions and

more additions from new reservoir discoveries in old fields.

Also, as in 1995, there were substantially more gas

reserve additions from net revisions and adjustments

compared to the average. As a result, U.S. total dry

natural gas reserves increased for the third year in a

row. Operators reported 7,871 billion cubic feet of net

revisions and adjustments to their dry natural gas proved

reserves—136 percent higher than the post-1976

average (3,335 billion cubic feet).

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 1996.

The U.S. crude oil first purchase price started at an

average of $15.42 per barrel in January 1996, and rose to

$19.58 per barrel in April. Prices dipped briefly in May

and June, but rose steadily for the last half of 1996 to

peak at $21.32 per barrel in December 1996. The

average U.S. crude oil first purchase price rose from

$14.62 in 1995 to $18.46 per barrel in 1996.

Energy Information Administration

10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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, 1970-1996

Crude Oil Natural Gas

Year Current 1996 Constant Current 1996 Constant

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

1970 3.18 11.44 0.17 0.61 1,028

1971 3.39 11.61 0.18 0.62 976

1972 3.39 11.11 0.19 0.62 1,107

1973 3.89 12.08 0.22 0.68 1,194

1974 6.87 19.63 0.30 0.86 1,472

1975 7.67 19.97 0.44 1.15 1,660

1976 8.19 20.17 0.58 1.43 1,658

1977 8.57 19.84 0.79 1.83 2,001

1978 9.00 19.44 0.91 1.97 2,259

1979 12.64 25.13 1.18 2.35 2,177

1980 21.59 39.25 1.59 2.89 2,909

1981 31.77 52.86 1.98 3.29 3,970

1982 28.52 44.63 2.46 3.85 3,105

1983 26.19 39.32 2.59 3.89 2,232

1984 25.88 37.45 2.66 3.85 2,428

1985 24.09 33.69 2.51 3.51 1,980

1986 12.51 17.07 1.94 2.65 964

1987 15.40 20.37 1.67 2.21 936

1988 12.58 16.07 1.69 2.16 936

1989 15.86 19.44 1.69 2.07 869

1990 20.03 23.51 1.71 2.01 1,010

1991 16.54 18.69 1.64 1.85 860

1992 15.99 17.57 1.74 1.91 721

1993 14.25 15.26 2.04 2.18 754

1994 13.19 13.81 R1.85 1.94 775

1995 14.62 14.93 1.55 1.58 723

1996 18.46 18.46 2.25 2.25 779

R=Revised data.

Sources: Current dollars and number of rigs: Monthly Energy Review July 1997, DOE/EIA-0035(97/07). 1996 constant dollars: U.S.

Department of Commerce, Bureau of Economic Analysis, Gross Domestic Product Implicit Price Deflators, June 1997.
Oil prices vary by region. In Texas the average price

was $20.31 per barrel, while in California it was $16.71

per barrel, and $15.32 per barrel on the Alaskan North

Slope. The lowest average first purchase price for crude

oil in 1996 was $13.82 per barrel for Federal Offshore

California production.{20}

The average natural gas price at the wellhead increased

from $1.55 in 1995 to $2.25 per thousand cubic feet in

1996. Gas prices started at $2.08 per thousand cubic feet

in January 1996, and remained relatively level until

July when they rose to $2.33 per thousand cubic feet.

Prices dipped to $1.87 (the lowest average price of the

year) in September, but rapidly increased with the

onset of colder winter weather in the northeast and

northern central U.S.—rising to $3.53 per thousand

cubic feet in December 1996 which was the highest

average price of the year.{21}

Drilling: From 1995 to 1996, the average active rig

count increased from 723 to 779 rigs (Table 3). The rig

count remains well below the high activity level of 1981

(average 3,970 rigs), however, 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 success rate.

Looking first at exploratory wells, there were 4,123

exploratory wells drilled in 1996 (Table 4). Of these, 21

percent were oil wells, 25 percent were gas wells, and

54 percent were dry holes. The total (which includes

dry holes) was 4 percent less than in 1995.

The success rate for exploratory drilling increased from

45 percent in 1995 to 46 percent in 1996. There were 2

percent more exploratory gas wells (Figure 7) and 6

percent fewer exploratory oil wells (Figure 8) than in

1995.

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

new gas discoveries per exploratory well increased 10

percent in 1996 from the 1995 level. The average

volume of new oil discoveries per exploratory well in

1996 is 3 percent higher than last year's level.

There were an estimated 23,679 exploratory and

development wells drilled in 1996. This is 5 percent

more than in 1995 and is only 82 percent of the average

number of wells drilled annually over the prior 10

years (28,834).

Operators completed more oil and gas wells in 1996

than in 1995. For the fourth 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.

U.S. crude oil proved reserves decreased in 1996, but oil

production decreased as well—resulting in a slight

increase in the National average R/P ratio.

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 1996 National average of 10.1-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 1996 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, even use of new technologies

such as horizontal drilling have so far only helped to

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 1996, as reserves and production both

increased.

Different marketing, transportation, and production

characteristics for gas are seen when looking at

regional average R/P ratios, compared to the 1996 U.S.

average R/P ratio of about 8.9-to-1. The areas with the

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

of the country, such as the Pacific offshore and the

Rockies, and also include areas such as Alabama and

Colorado, where considerable booking of coalbed

Energy Information Administration

12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table 4. U.S. Exploratory and Development Well Completions,a 1970-1996

Exploratory Total Exploratory and Development

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 654 1,079 6,038 7,771 10,251 6,975 10,466 27,692

1974 870 1,205 6,894 8,969 13,664 7,170 12,205 33,039

1975 991 1,263 7,207 9,461 16,979 8,170 13,736 38,885

1976 1,100 1,362 6,854 9,316 17,697 9,438 13,805 40,940

1977 1,183 1,562 7,402 10,147 18,700 12,119 15,036 45,855

1978 1,191 1,792 8,054 11,037 19,065 14,405 16,591 50,061

1979 1,335 1,920 7,478 10,733 20,703 15,170 16,038 51,911

1980 1,781 2,094 9,035 12,910 32,278 17,223 20,337 69,838

1981 2,667 2,533 12,297 17,497 42,843 19,907 27,284 90,034

1982 2,470 2,168 11,346 15,984 39,142 18,944 26,382 84,468

1983 2,113 1,660 10,271 14,044 37,199 14,556 24,336 76,091

1984 2,335 1,599 11,482 15,416 42,585 17,012 25,797 85,394

1985 1,879 1,282 9,445 12,606 35,021 14,252 21,208 70,481

1986 988 733 5,511 7,232 18,701 8,135 12,766 39,602

1987 859 673 5,179 6,711 16,186 7,757 11,481 35,424

1988 792 663 4,766 6,221 13,322 8,238 10,242 31,802

1989 580 654 4,001 5,235 10,339 9,225 8,491 28,055

1990 628 641 3,855 5,124 12,150 10,705 8,612 31,467

1991 573 R542 3,393 R4,508 11,908 9,452 7,914 29,274

1992 506 R423 2,656 R3,585 9,023 8,091 R6,651 R23,765

1993 R487 R515 2,514 R3,516 8,729 9,864 6,728 25,321

1994 R615 R816 2,203 R3,634 R6,780 R9,057 R5,284 R21,121

1995 R942 R989 R2,386 R4,317 R8,387 R8,692 R5,426 R22,505

1996 884 1,011 2,228 4,123 8,568 9,648 5,463 23,679

aExcludes service wells and stratigraphic and core testing.

R=Revised data.

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 1973-1996: Monthly Energy Review July

1997, DOE/EIA-0035(97/07).
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96

Wells

0

5

10

15

20

25

77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96

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

Wells

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

1.8

77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96

Million Barrels per Well

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

1977-1996

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

Exploratory Gas Well Completion, 1977-1996

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

1977-1996

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

Exploratory Oil Well Completion, 1977-1996
methane reserves has recently occurred. Several major

gas producing areas have R/P ratios below the

National average—such as Texas, the Gulf of Mexico

Federal Offshore, and Oklahoma. The R/P ratio of

these three areas combined decreased from 7.2-to-1 in

1995 to 7.0-to-1 in 1996, and is below the National 1996

average.

Ultimate Recovery

Figures 13 and 14 show successive estimates of

ultimate recovery and its components, proved reserves

and cumulative production, for crude oil plus lease

condensate, and wet natural gas, from 1977 to 1996.

They illustrate the continued growth of estimated

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 1996 was 54,946 million

barrels. This substantially exceeds the 1977 proved

reserves, but at the end of 1996 there were still 23,324

million barrels of crude oil and lease condensate

proved reserves. Therefore, the estimated ultimate

recovery of crude oil significantly increased during this

period due to the continuing development of old fields

and new field discoveries.

Similarly, the 1977 wet natural gas proved reserves

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

production from 1977 through 1996 was 351,234 billion

cubic feet. Cumulative wet gas production exceeded

the 1977 reserves by 141,744 billion cubic feet, but at the

end of 1996 there were still 175,147 billion cubic feet of

wet natural gas proved reserves, for the same reasons.

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 1996,

unchanged from 1995. 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 1996. There

are sometimes substantial differences between the

estimates from these sources, and one reason (among

many) for this is that condensate is often included in

foreign oil reserve estimates.

The Oil & Gas Journal{24} estimate for world oil reserves

increased 1.1 percent in 1996, while the World Oil{25}

estimate increased only 0.7 percent. For world gas

reserves, the Oil & Gas Journal reported a 0.2 percent

increase, while World Oil reported a 2.3 percent

increase.

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 more

than 4 times U.S. reserves. Closer to home, Venezuela

has almost 3 times and Mexico has just over twice the

United States' oil reserves.

Proved reserve estimates for various countries differ

widely. For example, World Oilreported oil reserves for

the former Soviet Union (FSU) (combining both the

Russian Federation and others) of about 184 billion

barrels. This is more than 3 times the Oil & Gas Journal's

estimate. However, World Oil has included more than

proved reserves in its 1995 FSU estimate. EIA considers

World Oil's FSU estimate comparable to the proved

plus probable reserves classifications commonly used

in the United States. The U.S. oil reserve estimates

include only proved reserves.

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. In 1996:

n The U.S. consumed 93,810,000,000,000,000 Btu of

energy (93.81 quadrillion Btu).

n 63 percent of U.S. energy consumption was

provided by petroleum and natural gas—crude

oil and natural gas liquids combined (38

percent), and natural gas (24 percent).{26}

n U.S. petroleum consumption was about 18.3

million barrels of oil and natural gas liquids

and 60.2 billion cubic feet of dry gas per day.

Energy Information Administration

14 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 15

Sources: Annual reserves and production - American Petroleum Institute and American Gas Association (1945–1976){22} and Energy

Information Administration, Office of Oil and Gas (1977–1996){1-19}. Cumulative production: U.S. Oil and Gas Reserves by Year of Field

Discovery (1977-1988).{23}

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 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96

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

Trillions of Cubic Feet

Cumulative Production

Proved Reserves

Ultimate Recovery

Figure 11. Reserves-to-Production Ratios for

Crude Oil, 1945-1996

Figure 13. Components of Ultimate Recovery for

Crude Oil and Lease Condensate, 1977-1996

Figure 12. Reserves-to-Production Ratios for

Wet Natural Gas, 1945-1996

Figure 14. Components of Ultimate Recovery

for Wet Natural Gas, 1977-1996
Table 5. International Oil and Natural Gas Reserves as of December 31, 1996

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 d261,800 1 Former U.S.S.R.. . . . . . . 1,977,000 1,939,292

2 Former U.S.S.R. . . . . . . 57,000 183,831 2 Iranc . . . . . . . . . . . . . . . . 741,609 812,238

3 Iraqc . . . . . . . . . . . . . . . 112,000 112,000 3 Qatarc . . . . . . . . . . . . . . 250,000 244,815

4 Kuwaitc . . . . . . . . . . . . . d96,500 d94,700 4 Saudi Arabiac. . . . . . . . . d189,100 d195,500

5 Iranc . . . . . . . . . . . . . . . 93,000 90,500 5 United Arab Emiratesc . . 204,900 195,620

6 United Arab Emiratesc . 97,800 63,510 6 United States . . . . . . . . e165,146 167,050

7 Venezuelac . . . . . . . . . . 64,878 72,603 7 Venezuelac . . . . . . . . . . 141,600 142,951

8 Mexico . . . . . . . . . . . . . 48,796 48,472 8 Algeriac . . . . . . . . . . . . . 130,300 138,900

9 Libyac . . . . . . . . . . . . . . 29,500 29,500 9 Iraqc . . . . . . . . . . . . . . . . 118,000 118,500

10 China . . . . . . . . . . . . . . 24,000 34,055 10 Nigeriac . . . . . . . . . . . . . 104,717 109,700

Top 10 Total. . . . . . . . . . . . . . 884,974 990,971 Top 10 Total . . . . . . . . . . . . . . 4,022,372 4,064,566

11 United States. . . . . . . . e22,351 22,050 11 Indonesiac . . . . . . . . . . . 72,268 135,923

12 Norway . . . . . . . . . . . . . 11,234 26,874 12 Norway. . . . . . . . . . . . . . 47,745 123,303

13 Nigeriac. . . . . . . . . . . . . 15,521 20,800 13 Malaysia. . . . . . . . . . . . . 80,200 79,100

14 Algeriac. . . . . . . . . . . . . 9,200 12,960 14 Canada. . . . . . . . . . . . . . 68,118 68,100

15 Indonesiac . . . . . . . . . . 4,980 9,241 15 Mexico . . . . . . . . . . . . . . 67,668 63,913

16 Brazil. . . . . . . . . . . . . . . 4,800 6,970 16 Netherlands . . . . . . . . . . 64,096 62,304

17 Canada . . . . . . . . . . . . . 4,894 5,537 17 Kuwaitc. . . . . . . . . . . . . . d52,900 d56,725

18 United Kingdom . . . . . . 4,517 5,003 18 Australia . . . . . . . . . . . . . 19,429 83,500

19 India . . . . . . . . . . . . . . . 4,333 5,049 19 Libyac. . . . . . . . . . . . . . . 46,300 46,300

20 Malaysia . . . . . . . . . . . . 4,000 5,170 20 China . . . . . . . . . . . . . . . 41,357 39,600

21 Angola . . . . . . . . . . . . . 5,412 3,601 21 United Kingdom . . . . . . . 24,720 26,828

22 Oman . . . . . . . . . . . . . . 5,138 3,614 22 Oman . . . . . . . . . . . . . . . 30,000 21,100

23 Qatarc . . . . . . . . . . . . . . 3,700 3,916 23 Argentina . . . . . . . . . . . . 21,870 24,308

24 Egypt . . . . . . . . . . . . . . 3,696 3,700 24 India . . . . . . . . . . . . . . . . 24,200 19,502

25 Yemen . . . . . . . . . . . . . 4,000 3,100 25 Egypt . . . . . . . . . . . . . . . 20,356 20,400

Top 25 Total. . . . . . . . . . . . . . 992,749 1,128,556 Top 25 Total . . . . . . . . . . . . . . 4,703,599 4,935,472

OPEC Total . . . . . . . . . . . . . . 788,579 771,530 OPEC Total . . . . . . . . . . . . . . . 2,051,694 2,197,172

World Total . . . . . . . . . . . . . . 1,018,849 1,160,104 World Total . . . . . . . . . . . . . . . 4,945,362 5,177,179

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, 1995 were published by the Oil & Gas Journal as its estimates as

of December 31, 1996.

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 30, 1996, pp. 40-41. Gulf Publishing Company, World Oil,

August, 1997, p. 38.

Energy Information Administration

16 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
Dependence on Imports

The United States remains heavily dependent on

imported oil and gas to satisfy its ever-increasing

appetite for energy. In 1995, the U.S. was dependent on

petroleum net imports for 44 percent of energy

consumption. In 1996, it increased to a 19-year high of

46 percent.

Net gas imports declined slightly in 1996 to 2.7 trillion

cubic feet, which is approximately 12 percent of

consumption. Almost all of this gas was pipelined in

from Canada, some from Mexico, and a very small

amount of liquefied natural gas was imported from

Algeria.

Price-competitive Canadian gas exports continue to

capture an increasing share of the U.S. market.

Venezuela, Saudi Arabia, Canada, Mexico, and Nigeria

were the primary foreign suppliers of petroleum to the

United States.{27}

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. The top

20 producing companies had 58 percent of U.S. natural

gas proved reserves in 1995.

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 included a new

table, Table D9, Deepwater Production and Proved

Reserves of the Gulf of Mexico Federal Offshore

1992-1996. Table D9 contains the production and

proved reserves for 1992-1996 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 how the

sampling frames are maintained. Budget reductions at

EIA have reduced the scope and coverage of these

surveys. Read how the surveys have been modified

due to reduced resources.

Appendix F: Statistical Considerations - The EIA

strives to maintain or improve the accuracy of its

reports. Since complete coverage of all oil and gas

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. A new statistical imputation

process, implemented for this 1996 annual report, is

described.

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 17
3. Crude Oil Statistics

The United States had 22,017 million barrels of crude

oil proved reserves as of December 31, 1996. This is

about 2 percent less than in 1995 and it is the ninth

consecutive year that crude oil proved reserves have

declined. Reserve additions of crude oil (1,839 million

barrels) replaced 85 percent of 1996 oil production

(Figure 15).

Alaska, the state with the second largest crude oil

reserves in the United States, reported the largest

decline in 1996–a decrease of 5.5 percent from 1995's

level. In Alaska, reserve additions replaced only 40

percent of production in 1996. This large decline in

crude oil reserves had the most significant impact on

the National total in 1996.

In 1996, the largest net addition of new crude oil

proved reserves came from the Gulf of Mexico Federal

Offshore. The Gulf of Mexico Federal Offshore

reported a 2 percent increase (49 million barrels) in

crude oil proved reserves. This is the fourth

consecutive year that crude oil proved reserves have

increased in this area.

Lower-48 States crude oil proved reserves remained

essentially constant in 1996, with only a 0.2 percent

decline (28 million barrels) from 1995. Texas and

California reported declines in crude oil proved

reserves, but did not decline as severely as Alaska in

1996 because higher oil prices spurred activity in west

Texas and the San Joaquin Basin. Texas replaced 99

percent of its production with new reserves additions,

while California replaced 91 percent.

Over the previous 10 years, U.S. crude oil proved

reserves have generally been declining (Figure 1). Oil

reserves have declined an average of over 2 percent per

year. The 1996 decline is less than this average.

Proved Reserves

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

as of December 31, 1996, by selected States and State

subdivisions.

Figure 16 maps the U.S. 1996 crude oil proved reserves

by State. The following four areas account for 78

percent of U.S. crude oil proved reserves:

Area % of U.S. Oil Reserves

Texas 26

Alaska 24

California 16

Gulf of Mexico Federal Offshore 12

Total 78

Of these four areas, the top three all experienced a

decline in crude oil proved reserves during 1996, while

the Gulf of Mexico Federal Offshore had an increase.

Discussion of Reserves Changes

Figure 17 maps the change in crude oil proved reserves

from 1995 to 1996 by area. Here's how the top four areas

fared, compared to the total United States:

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 19

37%

62%

66%

78%

85%

95%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1991 1992 1993 1994 1995 1996

Percentage of U.S. Oil Production Replaced

Figure 15. Reserve Additions Replace 85 Percent

of U.S. Oil Production in 1996

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

20 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table 6. Crude Oil Proved Reserves, Reserves Changes, and Production, 1996

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 1996

Published New Reservoir

Proved Revision Revision New Field Discoveries Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/95 (+,-) (+) (--) (+) (+) (+) (-) 12/31/96

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.

cIndicates the estimate has an expected error greater than 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 1996 contained in the Petroleum

Supply Annual 1996, DOE/EIA-0340(96).

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

Alaska. . . . . . . . . . . . . . . . . . . . . . . 5,580 3 69 60 64 128 0 510 5,274

Lower 48 States . . . . . . . . . . . . . . 16,771 172 1,654 926 479 115 141 1,663 16,743

Alabama . . . . . . . . . . . . . . . . . . . . . 43 9 8 6 0 1 0 10 45

Arkansas . . . . . . . . . . . . . . . . . . . . 48 9 15 4 0 0 0 10 58

California . . . . . . . . . . . . . . . . . . . . 3,462 28 306 110 26 0 2 277 3,437

Coastal Region Onshore . . . . . . 456 21 14 57 10 0 0 19 425

Los Angeles Basin Onshore . . . 227 3 27 4 0 0 0 19 234

San Joaquin Basin Onshore . . . 2,577 3 263 45 16 0 2 219 2,597

State Offshore . . . . . . . . . . . . . . 202 1 2 4 0 0 0 20 181

Colorado. . . . . . . . . . . . . . . . . . . . . 252 –9 22 12 0 0 0 22 231

Florida . . . . . . . . . . . . . . . . . . . . . . 71 0 32 0 0 0 0 6 97

Illinois . . . . . . . . . . . . . . . . . . . . . . . 119 –2 11 23 1 0 0 12 94

Indiana . . . . . . . . . . . . . . . . . . . . . . 13 –2 2 0 0 0 0 2 11

Kansas . . . . . . . . . . . . . . . . . . . . . . 275 –3 54 30 11 0 2 43 266

Kentucky. . . . . . . . . . . . . . . . . . . . . 24 –1 1 0 0 0 0 3 21

Louisiana . . . . . . . . . . . . . . . . . . . . 637 –1 94 65 64 1 24 96 658

North . . . . . . . . . . . . . . . . . . . . . 108 –18 20 4 34 1 4 17 128

South Onshore. . . . . . . . . . . . . . 387 13 53 47 25 0 7 56 382

State Offshore . . . . . . . . . . . . . . 142 4 21 14 5 0 13 23 148

Michigan. . . . . . . . . . . . . . . . . . . . . 76 8 9 10 1 0 0 10 74

Mississippi . . . . . . . . . . . . . . . . . . . 140 12 23 5 10 0 2 18 164

Montana . . . . . . . . . . . . . . . . . . . . . 178 –8 10 3 5 0 0 14 168

Nebraska . . . . . . . . . . . . . . . . . . . . 25 4 7 3 0 0 0 5 28

New Mexico . . . . . . . . . . . . . . . . . . 732 –6 90 36 29 3 2 70 744

East . . . . . . . . . . . . . . . . . . . . . . 713 –4 88 32 29 3 2 68 731

West. . . . . . . . . . . . . . . . . . . . . . 19 –2 2 4 0 0 0 2 13

North Dakota . . . . . . . . . . . . . . . . . 233 8 27 19 21 9 0 31 248

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 53 0 6 0 0 0 2 8 53

Oklahoma. . . . . . . . . . . . . . . . . . . . 676 7 55 43 11 0 1 75 632

Pennsylvania . . . . . . . . . . . . . . . . . 11 –3 2 1 2 0 0 c1 10

Texas . . . . . . . . . . . . . . . . . . . . . . . 5,743 125 461 261 155 5 3 495 5,736

RRC District 1 . . . . . . . . . . . . . . 90 4 7 8 3 0 0 10 86

RRC District 2 Onshore . . . . . . . 61 7 7 3 1 0 0 10 63

RRC District 3 Onshore . . . . . . . 267 22 49 29 25 0 0 53 281

RRC District 4 Onshore . . . . . . . 50 0 12 5 1 0 0 7 51

RRC District 5 . . . . . . . . . . . . . . 34 1 3 6 2 0 0 5 29

RRC District 6 . . . . . . . . . . . . . . 409 –10 16 20 4 0 0 40 359

RRC District 7B . . . . . . . . . . . . . 126 19 11 6 3 1 0 18 136

RRC District 7C . . . . . . . . . . . . . 204 6 34 23 20 0 0 22 219

RRC District 8 . . . . . . . . . . . . . . 2,032 33 151 69 78 2 1 149 2,079

RRC District 8A . . . . . . . . . . . . . 2,233 20 141 52 12 2 0 149 2,207

RRC District 9 . . . . . . . . . . . . . . 149 27 20 34 1 0 2 21 144

RRC District 10 . . . . . . . . . . . . . 80 –2 7 6 5 0 0 10 74

State Offshore . . . . . . . . . . . . . . 8 –2 3 0 0 0 0 c1 8

Utah . . . . . . . . . . . . . . . . . . . . . . . . 216 13 33 13 4 0 0 16 237

West Virginia . . . . . . . . . . . . . . . . . 28 –2 2 2 1 0 0 2 25

Wyoming . . . . . . . . . . . . . . . . . . . . 605 –2 77 24 13 1 1 68 603

Federal Offshore . . . . . . . . . . . . . . 3,089 –4 302 256 125 95 102 368 3,085

Pacific (California) . . . . . . . . . . . 571 25 1 17 3 0 0 65 518

Gulf of Mexico (Louisiana) . . . . . 2,269 –28 285 213 120 90 99 265 2,357

Gulf of Mexico (Texas). . . . . . . . 249 –1 16 26 2 5 3 38 210

Miscellaneousa. . . . . . . . . . . . . . . . b22 –8 5 0 0 0 0 c1 18

U.S. Total. . . . . . . . . . . . . . . . . . . . 22,351 175 1,723 986 543 243 141 2,173 22,017
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 21

Figure 17. Changes in Crude Oil Proved Reserves by Area, 1995 to 1996

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

Figure 16. 1996 Crude Oil Proved Reserves by Area
Change in

U.S. Oil Reserves

Area (million barrels)

Texas -7

Alaska -306

California -25

Gulf of Mexico Federal Offshore +49

Area Subtotal -289

U.S. Total -334

Figure 2 in Chapter 2 shows the components of the

changes in crude oil proved reserves for 1996 and the

preceding 10 years. These components are discussed

below.

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.

Total discoveries of crude oil were 927 million barrels in

1996, 3 percent lower than in 1995. Only four areas had

total discoveries exceeding 35 million barrels:

n The Gulf of Mexico Federal Offshore had 319

million barrels of total discoveries, 34 percent of

the National total. The Gulf of Mexico Federal

Offshore (Louisiana) had 309 million barrels of

these total discoveries in 1996.

n Alaska had 192 million barrels of total discoveries,

21 percent of the National total.

n Texas had 163 million barrels of total discoveries,

18 percent of the National total. Half of this was

in Texas Railroad Commission (TXRRC) District

8 in west Texas.

n Louisiana had 89 million barrels of total

discoveries, 10 percent of the National total.

The United States discovered an average of 654 million

barrels of new crude oil proved reserves per year in the

prior 10 years (1986 through 1995). Total discoveries in

1996 were 142 percent of that average.

Extensions: Operators reported 543 million barrels of

extensions in 1996.

n The highest volume of extensions was reported in

Texas (155 million barrels) and 50 percent of

Texas’ extensions (78 million of 155 million

barrels total) were in west Texas (TX RRC

District 8).

n Second, 120 million barrels of extensions in the

Gulf of Mexico Federal Offshore (Louisiana).

n Alaska and Louisiana tied for third with 64

million barrels of extensions.

Despite its large share of U.S. oil reserves, only 26

million barrels of extensions were reported in

California, where production is dominated by large,

old fields and exploration has been restricted. Over half

of California’s 1996 extensions (16 million barrels) were

from the San Joaquin Basin Onshore region.

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

average of 422 million barrels of extensions per year.

The 1996 extensions were 129 percent of that average.

New Field Discoveries: There were 243 million barrels

of new field discoveriesreported in 1996. Only eight areas

in the United States reported any new field discoveries.

Of these, only four contributed more than 1 percent to

the total:

n Alaska (53 percent)

n Gulf of Mexico Federal Offshore (39 percent)

n North Dakota (4 percent)

n Texas (2 percent).

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

average of 103 million barrels of reserves from new field

discoveries per year. Reserves from new field discoveries

in 1996 were 236 percent of that average.

New Reservoir Discoveries in Old Fields: Operators

in the United States reported 141 million barrels of

crude oil reserves from new reservoir discoveries in old

fieldsin 1996. The most significant portion of these were

in the Gulf of Mexico Federal Offshore (Louisiana), 99

million barrels or 70 percent. Louisiana reported 24

million barrels (17 percent), and Texas reported 3

million barrels (2 percent). In the prior 10 years, U.S.

operators reported an average of 129 million barrels of

reserves from new reservoir discoveries in old fields per

year. Reserves from new reservoir discoveries in old fields

in 1996 were 109 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.

Energy Information Administration

22 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
There were 912 million barrels of net revisions and

adjustments for crude oil in 1996, less than the 1995 total

of 1,150 million barrels. Average revisions and

adjustments for the prior 10 years were 1,293 million

barrels, and those for 1996 were only 71 percent of this

average.

Production

U.S. production of crude oil in 1996 was 2,173 million

barrels. This was 2 percent lower than 1995's total of

2,213 million barrels. U.S. crude oil production has

declined in 10 of the last 11 years, at an average rate of 3

percent.

Areas of Note: Large Discoveries

and Reserves Additions

The following State and area discussions summarize

notable activities during 1996 concerning expected new

field reserves, development plans, and possible

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 1996.

Alpine Field, Alaska

Although Alaska's proved oil reserves declined 5.5

percent (306 million barrels), a large new field was

discovered in Alaska in 1996–the Alpine Field.

Operated by ARCO, the Alpine Field is located 34 miles

west of the Kuparuk River oil field on Alaska’s North

Slope.

The following paragraphs were excerpted from an

ARCO Press Release, May 7, 1997: “Estimates of peak

production have also been increased to 70,000 barrels

per day in the year 2001, up 10,000 b/d from the

previous estimate. Initial production of 40,000 barrels

per day is expected in 2000.

Alpine is 56%-owned by ARCO Alaska, Inc., a

subsidiary of Los Angeles-based ARCO, Anadarko

Petroleum Corp., and Union Texas Petroleum Alaska

Corporation.

Work is expected to begin in December, 1997, pending

co-owner approval and receipt of necessary permits.

Initial development plans call for the drilling of 50

wells and the installation of associated facilities. After

the field is put on production, additional wells

targeting the periphery of the field may be drilled.

ARCO and its partners announced plans to develop

Alpine in October, 1996 after completion of a

3-dimensional seismic survey and a six-well,

four-sidetrack delineation drilling program.

Four Alpine delineation wells were tested and on

separate tests flowed high-quality, low-impurity,

40-degree API gravity oil. An unstimulated rate of

2,380 barrels per day was achieved from the Alpine

reservoir, a sandstone discovered at a depth of

approximately 6,850 feet.”

Gulf of Mexico Federal Offshore

Projects in the Gulf of Mexico Federal Offshore

provided the largest net increase of crude oil proved

reserves in the United States from 1995’s level, 49

million barrels. The Gulf of Mexico produced about 303

million barrels of crude oil in 1996, an increase of 4

percent (11 million barrels) over 1995 production (292

million barrels).

Deepwater Production and Reserves: The Federal

Offshore is still an exciting frontier. The continuing

evolution of deepwater production systems has

facilitated the industry’s expansion into the deepwater

frontiers of the Federal Gulf of Mexico. The evolution of

technology from fixed to floating platforms, and using

subsea well completions, has allowed extension of

production activities into ever deeper water. Appendix

D, Historical Reserves Statistics, contains a new table,

Table D9, “Deepwater Production and Proved

Reserves of the Gulf of Mexico Federal Offshore,

1992-1996”. The table contains the production and

proved reserves for 1992-1996 for the Gulf of Mexico

Federal Offshore region by water depths greater than

200 meters and less than 200 meters. The rapid rise of

deepwater proved reserves and production listed in

Table D9 are a testament to the successful

implementation of the new technology.

Fields in the deepwater are currently producing crude

oil at almost twice the annual rate (97 million barrels)

that they were only four years earlier in 1992 when the

production was 54 million barrels. Fields in the

deepwater are currently producing natural gas at over

twice the rate (613 billion cubic feet) than they were

only five years ago in 1992 when the annual production

was 243 billion cubic feet.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 23
Proved reserves of oil and gas in deepwater have

roughly doubled in the last four years. In 1996, the

proved reserves of crude oil in water deeper than 200

meters exceeded the reserves in shallower water. While

crude oil proved reserves in water depths less than 200

meters have remained relatively constant since 1992,

the doubling of deepwater reserves has led to overall

increases of crude oil proved reserves in the Gulf of

Mexico Federal Offshore for four years in a row.

Natural gas reserves in the deepwater also increased

every year since 1992, and had nearly doubled by 1996.

They now account for one-fourth of the natural gas

reserves in the Gulf of Mexico Federal Offshore.

Natural gas liquids reserves tripled between 1992 and

1996. They now account for almost one-half the natural

gas liquids reserves in the Gulf of Mexico Federal

Offshore.

Activity on the OCS Prompts Record-Breaking Lease

Sales in 1996: Both the April 1996 Central Gulf Lease

Sale and the September 1996 Western Gulf Lease Sale

set records. The U.S. Department of the Interior's

Minerals Management Service (MMS) said it received

929 bids on 617 tracts for acreage offered in the Western

Gulf of Mexico offshore Texas and in deeper waters

offshore Louisiana.

“This is the first sale in the Western Gulf of Mexico, and

only the second sale overall, in which tracts receiving

bids in water depths of 200 meters or more are eligible

for consideration under provisions of the Deepwater

Royalty Relief Act signed by President Clinton this past

November,” said MMS Director Cynthia Quarterman.

“[The Western Gulf of Mexico Lease] Sale, along with

the record-breaking Central Gulf Sale earlier this year,

are clear indications that the Gulf of Mexico is

embarking on a new era for offshore energy

development.”

MMS officials said 433 tracts that received bids are in

water depths of 200 meters or more. The highest bid

was on a tract in High Island Block 545A. Each tract is

about nine square miles. The highest bid on each tract

will go through an evaluation process to assure the

American taxpayer receives fair market value. The

agency estimates recoverable hydrocarbons to be about

40 million barrels of oil and 0.65 trillion cubic feet of

natural gas.{28}

TLPs, Towers, and Spars: Operators in the Federal

Offshore waters of the Gulf of Mexico are bringing

production on-line using a variety of new production

facility systems.

n In May 1996, Shell Deepwater Development

repeated its success at the Auger and

Ram-Powell Projects with the installation of the

Mars Tension Leg Platform in Mississippi

Canyon Block 807 (2,958 feet water depth).{29}

n Texaco and partner Marathon Oil began

constructing a 1,870-foot Compliant Tower for

the drilling and production platform at its

Petronius Project in Viosca Knoll Block 786

(1,753 feet water depth). Texaco expects to bring

Petronius onstream in early 1999.{30}

n In September 1996, Oryx Energy Company

installed the first floating production spar

platform in the Gulf of Mexico at its Neptune

Project in Viosca Knoll Block 825 (cover photo)

in 1,861 feet of water depth.{31}

More Subsea Completions: Operators also plan to

develop more projects using subsea completions.

n British Borneo Exploration announced its plans

to develop the newly discovered Morpeth

Project in Ewing Bank Block 921 using subsea

completions and a SeaStar system (1,630 feet

water depth). A SeaStar system is a floating

mini-tension leg platform of relatively low cost

developed for the production of smaller

deepwater reserves which would be uneconomic

to produce using more conventional deepwater

systems.{32}

n Texaco and Marathon announced their

intentions in 1996 to develop the Arnold Project

in 1,749 feet of water using subsea completions

(the specific platform system is not yet

selected).{30}

n The deepest potential project announced to date

is the BAHA Project that Shell Deepwater

Development is considering in Alaminos

Canyon Block 600 in an estimated 7,620 feet of

water!{32}

The Permian Basin

Plenty of dry land potential was found in 1996. One of

the most active onshore areas was the Permian Basin.

The largest volume of extensions in the United States

was reported in Texas in 1996, and the lion’s share of

those occurred in the Permian Basin (TX RRC Districts

8 and 8A). Adding the extensions of eastern New

Mexico to those of TX RRC Districts 8 and 8A, the

extensions from these areas (all in the Permian Basin)

exceed those of the Gulf of Mexico Federal Offshore.

Energy Information Administration

24 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
Chalk one up for Louisiana

A commercially productive section of the Austin Chalk

formation was found to extend into Louisiana, one of

the reasons why Louisiana was second only to the Gulf

of Mexico Federal Offshore in the volume of new

reservoir discoveries in old fields in 1996. Besides the

chalk, operators discovered a significant volume (13

million barrels) of new reservoir discoveries in old fields in

the state offshore waters of Louisiana.

Other Gain Areas

Florida: Florida's proved oil reserves increased by 26

million barrels. Exxon, operator of the Jay Field (the

largest oil field in Florida), implemented a nitrogen

injection project to enhance oil recovery.

Mississippi: Mississippi's proved oil reserves

increased by 24 million barrels. The boost was

primarily due to extensions and revision increases.

Utah: Operators in Utah added 21 million more barrels

of proved crude oil reserves in 1996 through

exploration and acquisitions.

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 306 million

barrels in 1996, the greatest decline of any state in 1996.

Alaska replaced only 40 percent of its production with

new reserve additions.

Prudhoe Bay field: At Prudhoe Bay Field, the largest

producing oil field in the United States, aggressive

development drilling and surface optimization efforts

created an additional 63,000 barrels per day of

production in 1996. By original estimates, Prudhoe Bay

would have been producing only 520,000 barrels per

day in 1996. Instead, gross production levels averaged

855,000 barrels per day.{33}

Pacific Federal Offshore

Production from the Pacific Federal Offshore declined

to 65 million barrels in 1996 (from 1995’s level of 72

million). Also, reserve additions fell short of

production by a substantial amount. Proved crude oil

reserves declined 53 million barrels in this area in 1996.

Oklahoma

Oklahoma’s proved oil reserves decreased by 44

million barrels in 1996. Although net revisions and

adjustments and extensions were positive, they were

not enough to replace 1996 production. Oklahoma’s

production increased by 1 million barrels from 1995’s

level (74 million barrels).

Other Decline Areas

California: California's proved oil reserves decreased

by 25 million barrels. Revision decreases in the Coastal

Region Onshore and unreplaced production from the

State Offshore waters outpaced reserve additions in the

San Joaquin Basin and the Los Angeles Basin.

Illinois: This State’s proved oil reserves decreased by

21 percent (25 million barrels)

Colorado: This State's proved oil reserves decreased by

8 percent (21 million barrels).

Reserves in

Nonproducing Reservoirs

Not all proved reserves of crude oil were contained in

reservoirs that were producing in 1996. Operators

reported 3,474 million barrels of proved reserves in

nonproducing reservoirs. This is 2 percent less than

reported in 1995 (3,563 million barrels).

The reasons for the nonproducing status of these

proved reserves are not collected by the EIA. However,

previous surveys showed that most of the wells or

reservoirs were not producing 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.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 25
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 current technology. The 1996 volume,

2,876 million barrels, is about 8 percent more than was

reported in 1995 (2,669 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

26 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table 7. Reported Indicated Additional Crude Oil Reserves,a 1996

(Million Barrels of 42 U.S. Gallons)

Indicated Indicated

Additional Additional

State and Subdivision Reserves State and Subdivision Reserves

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 952

Lower 48 States. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,924

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

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

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 905

Coastal Region Onshore . . . . . . . . . . . . . . . . . . . 261

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

San Joaquin Basin Onshore. . . . . . . . . . . . . . . . . 644

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

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

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

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

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

Kansas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . <1

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

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 331

North. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

South Onshore . . . . . . . . . . . . . . . . . . . . . . . . . . . 322

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

Montana. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

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

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148

East. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148

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

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

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

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

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

Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 358

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

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

RRC District 3 Onshore . . . . . . . . . . . . . . . . . . . . 27

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

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

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

RRC District 7B. . . . . . . . . . . . . . . . . . . . . . . . . . . 4

RRC District 7C . . . . . . . . . . . . . . . . . . . . . . . . . . 5

RRC District 8. . . . . . . . . . . . . . . . . . . . . . . . . . . . 217

RRC District 8A. . . . . . . . . . . . . . . . . . . . . . . . . . . 99

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

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

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

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

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

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Federal Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

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

Gulf of Mexico (Louisiana) . . . . . . . . . . . . . . . . . . 40

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

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

U.S. Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,876

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,” 1996.
4. Natural Gas Statistics

Dry Natural Gas

Proved Reserves

The Nation's proved reserves of dry natural gas were

166,474 billion cubic feet, about 1 percent (1,328 billion

cubic feet) more than in 1995 (Table 8), continuing the

growth of the previous year. As a result of the

consecutive increases, gas reserves now stand about 4

trillion cubic feet above the 1993 total. Additions to

reserves (20,189 billion cubic feet) replaced 107 percent

of gas production in 1996 (Figure 18). These are

attributable, both to higher revisions and adjustments to

the reserve estimates of old fields, and to total

discoveries, including field extensions, new field

discoveries, and new reservoir discoveries in old fields. U.S.

proved reserves of dry natural gas increased in 1996,

for the third year in a row. Total discoveries were up and

equaled the highest level in the last 10 years. Over

two-thirds of the total discoveries were in Texas and in

the Gulf of Mexico Federal Offshore, where improved

exploration and deepwater production technologies

enhanced the ability to discover and develop offshore

fields. It is anticipated that technological advances will

continue to spur offshore development. The volumetric

differences between the estimates reported in Table 8

(dry) and Table 9 (wet) are due to the removal of

natural gas liquids at natural gas processing plants. All

natural gas proved reserves estimates, in this report,

exclude natural gas held in underground storage. The

top 5 areas for reserves, which account for 65 percent of

U.S. reserves, increased by about one-half of 1 percent,

while the entire country increased by about 1 percent.

Proved reserves by State are shown on the map in

Figure 19.

Percent of

Area U.S. Gas Reserves

Texas 23

Gulf of Mexico Federal Offshore 17

New Mexico 10

Oklahoma 8

Wyoming 7

Total 65

Changes to reserves in 1996 are shown by State on the

map in Figure 20. Notable increases are those that

occurred in Texas (1,728 billion cubic feet), Michigan

(767 billion cubic feet), Colorado (454 billion cubic feet),

and Louisiana (269 billion cubic feet). Lower 48 States

gas reserves had been generally declining since natural

gas prices peaked, in 1983. However, they increased by

1 percent in 1994 and 1995, and were again up 1 percent

(1,531 billion cubic feet) in 1996.

Revisions

Revisions and adjustments were down in 1996, but still

higher than the prior 10-year average. The net volume

of revisions and adjustments to reserves played a

significant role in increasing U.S. natural gas proved

reserves. It amounted to 7,871 billion cubic feet in 1996,

a 5 percent decrease from 1995. Large revisions were

attributed to new drilling programs, well performance,

higher gas prices, and acquistions.

Discoveries

Total discoveries were up in 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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 27

87% 88%

85%

108% 107% 107%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

120%

1991 1992 1993 1994 1995 1996

Percentage of U.S. Gas Production Replaced

Figure 18. Reserve Additions Exceed U.S. Natural

Gas Production 3 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 1996 Annual Report

Table 8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 1996

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

Changes in Reserves During 1996

Published New Reservoir

Proved Revision Revision New Field Discoveries Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/95 (+,-) (+) (-) (+) (+) (+) (-) 12/31/96

Alaska. . . . . . . . . . . . . . . . . . . . . . . 9,497 145 202 171 6 61 0 446 9,294

Lower 48 States . . . . . . . . . . . . . . 155,649 3,640 16,930 12,875 7,751 1,390 3,110 18,415 157,180

Alabama . . . . . . . . . . . . . . . . . . . . . 4,868 -44 502 97 177 0 0 373 5,033

Arkansas . . . . . . . . . . . . . . . . . . . . 1,563 33 96 108 57 2 27 200 1,470

California . . . . . . . . . . . . . . . . . . . . 2,243 -114 207 70 16 0 17 217 2,082

Coastal Region Onshore . . . . . . 153 8 16 9 1 0 0 13 156

Los Angeles Basin Onshore . . . 111 -3 16 5 0 0 0 10 109

San Joaquin Basin Onshore . . . 1,920 -119 174 53 15 0 17 186 1,768

State Offshore . . . . . . . . . . . . . . 59 0 1 3 0 0 0 8 49

Colorado. . . . . . . . . . . . . . . . . . . . . 7,256 479 802 398 106 0 5 540 7,710

Florida . . . . . . . . . . . . . . . . . . . . . . 92 -3 12 0 0 0 0 5 96

Kansas . . . . . . . . . . . . . . . . . . . . . . 8,571 339 377 953 59 0 3 702 7,694

Kentucky. . . . . . . . . . . . . . . . . . . . . 1,044 -55 43 12 10 1 10 58 983

Louisiana . . . . . . . . . . . . . . . . . . . . 9,274 626 1,111 975 575 13 440 1,521 9,543

North . . . . . . . . . . . . . . . . . . . . . 2,788 141 473 173 249 4 10 387 3,105

South Onshore. . . . . . . . . . . . . . 5,648 486 534 705 297 9 392 957 5,704

State Offshore . . . . . . . . . . . . . . 838 -1 104 97 29 0 38 177 734

Michigan. . . . . . . . . . . . . . . . . . . . . 1,294 581 453 152 17 76 0 208 2,061

Mississippi . . . . . . . . . . . . . . . . . . . 663 13 87 88 43 0 1 88 631

Montana . . . . . . . . . . . . . . . . . . . . . 782 16 59 12 2 0 1 52 796

New Mexico . . . . . . . . . . . . . . . . . . 17,491 -106 1,074 1,115 552 4 8 1,423 16,485

East . . . . . . . . . . . . . . . . . . . . . . 2,867 -45 440 191 139 4 8 432 2,790

West. . . . . . . . . . . . . . . . . . . . . . 14,624 -61 634 924 413 0 0 991 13,695

New York . . . . . . . . . . . . . . . . . . . . 197 20 36 12 3 0 9 21 232

North Dakota . . . . . . . . . . . . . . . . . 463 22 36 22 5 3 0 45 462

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 1,054 101 91 42 0 0 30 121 1,113

Oklahoma. . . . . . . . . . . . . . . . . . . . 13,438 122 1,886 1,602 714 30 66 1,580 13,074

Pennsylvania . . . . . . . . . . . . . . . . . 1,482 139 243 103 38 0 29 132 1,696

Texas . . . . . . . . . . . . . . . . . . . . . . . 36,542 1,081 4,649 3,456 3,204 516 623 4,889 38,270

RRC District 1 . . . . . . . . . . . . . . 712 -39 211 36 142 2 0 86 906

RRC District 2 Onshore . . . . . . . 1,251 127 175 210 132 0 37 190 1,322

RRC District 3 Onshore . . . . . . . 3,866 290 531 500 533 169 316 856 4,349

RRC District 4 Onshore . . . . . . . 7,709 94 1,073 1,139 979 95 221 1,263 7,769

RRC District 5 . . . . . . . . . . . . . . 1,862 69 144 132 91 226 6 187 2,079

RRC District 6 . . . . . . . . . . . . . . 5,726 128 610 272 285 0 5 583 5,899

RRC District 7B . . . . . . . . . . . . . 440 63 121 51 11 0 5 69 520

RRC District 7C . . . . . . . . . . . . . 3,107 51 585 159 430 0 11 370 3,655

RRC District 8 . . . . . . . . . . . . . . 5,441 323 547 544 245 14 9 583 5,452

RRC District 8A . . . . . . . . . . . . . 941 22 64 33 6 0 0 69 931

RRC District 9 . . . . . . . . . . . . . . 738 -29 53 25 72 0 0 104 705

RRC District 10 . . . . . . . . . . . . . 4,436 -4 499 335 235 10 7 457 4,391

State Offshore . . . . . . . . . . . . . . 313 -14 36 20 43 0 6 72 292

Utah . . . . . . . . . . . . . . . . . . . . . . . . 1,580 44 125 79 126 17 0 180 1,633

Virginia . . . . . . . . . . . . . . . . . . . . . . 1,836 109 46 6 0 0 0 55 1,930

West Virginia . . . . . . . . . . . . . . . . . 2,499 87 301 89 10 0 72 177 2,703

Wyoming . . . . . . . . . . . . . . . . . . . . 12,166 -122 1,193 569 411 0 23 782 12,320

Federal Offshorea . . . . . . . . . . . . . 29,182 275 3,491 2,912 1,626 728 1,746 5,040 29,096

Pacific (California) . . . . . . . . . . . 1,265 24 19 46 31 0 0 49 1,244

Gulf of Mexico (Louisiana)a . . . . 21,392 256 2,796 2,317 1,369 619 1,447 3,706 21,856

Gulf of Mexico (Texas). . . . . . . . 6,525 -5 676 549 226 109 299 1,285 5,996

Miscellaneousb. . . . . . . . . . . . . . . . c69 -3 10 3 0 0 0 6 67

U.S. Total. . . . . . . . . . . . . . . . . . . . 165,146 3,785 17,132 13,046 7,757 1,451 3,110 18,861 166,474

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 1996 contained in the Natural Gas Annual 1996, DOE/EIA-0131(96).

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 29

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

1996 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 1996 Proved Reserves 12/31/96

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 12/31/95 (+,–) (+) (–) (+) (+) (+) (–) Total Gas Gas Gas

Alaska . . . . . . . . . . . . . . . . . . . . . 9,575 69 202 171 6 61 0 446 9,296 3,216 6,080

Lower 48 States . . . . . . . . . . . . . 163,901 4,219 17,832 13,586 8,183 1,430 3,209 19,337 165,851 141,136 24,715

Alabama. . . . . . . . . . . . . . . . . . . . 4,930 –40 507 97 177 0 0 377 5,100 5,062 38

Arkansas . . . . . . . . . . . . . . . . . . . 1,566 32 97 108 57 2 27 201 1,472 1,383 89

California . . . . . . . . . . . . . . . . . . . 2,355 –111 217 74 16 0 18 228 2,193 610 1,583

Coastal Region Onshore . . . . 163 11 17 10 1 0 0 14 168 48 120

Los Angeles Basin Onshore . 115 –4 16 5 0 0 0 10 112 0 112

San Joaquin Basin Onshore . 2,018 –118 183 56 15 0 18 196 1,864 560 1,304

State Offshore . . . . . . . . . . . . 59 0 1 3 0 0 0 8 49 2 47

Colorado . . . . . . . . . . . . . . . . . . . 7,592 493 854 428 112 0 5 564 8,064 7,009 1,055

Florida . . . . . . . . . . . . . . . . . . . . . 110 0 15 0 0 0 0 6 119 0 119

Kansas. . . . . . . . . . . . . . . . . . . . . 9,093 340 399 1,008 62 0 3 744 8,145 8,063 82

Kentucky . . . . . . . . . . . . . . . . . . . 1,102 –49 45 12 11 1 10 62 1,046 1,022 24

Louisiana . . . . . . . . . . . . . . . . . . . 9,891 577 1,168 1,036 604 14 470 1,611 10,077 9,038 1,039

North . . . . . . . . . . . . . . . . . . . 2,863 145 486 178 256 4 10 397 3,189 2,934 255

South Onshore. . . . . . . . . . . . 6,166 401 572 755 317 10 419 1,025 6,105 5,478 627

State Offshore . . . . . . . . . . . . 862 31 110 103 31 0 41 189 783 626 157

Michigan . . . . . . . . . . . . . . . . . . . 1,344 589 467 156 18 78 0 215 2,125 1,778 347

Mississippi . . . . . . . . . . . . . . . . . . 667 13 87 89 43 0 1 88 634 587 47

Montana. . . . . . . . . . . . . . . . . . . . 792 17 59 12 2 0 1 53 806 755 51

New Mexico . . . . . . . . . . . . . . . . . 18,747 158 1,157 1,222 602 4 9 1,530 17,925 16,232 1,693

East . . . . . . . . . . . . . . . . . . . . 3,207 25 504 218 160 4 9 494 3,197 1,612 1,585

West. . . . . . . . . . . . . . . . . . . . 15,540 133 653 1,004 442 0 0 1,036 14,728 14,620 108

New York . . . . . . . . . . . . . . . . . . . 197 20 36 12 3 0 9 21 232 229 3

North Dakota . . . . . . . . . . . . . . . . 518 19 41 25 6 3 0 50 512 257 255

Ohio . . . . . . . . . . . . . . . . . . . . . . . 1,054 102 91 42 0 0 30 121 1,114 715 399

Oklahoma . . . . . . . . . . . . . . . . . . 14,295 176 2,013 1,710 762 32 70 1,686 13,952 12,929 1,023

Pennsylvania . . . . . . . . . . . . . . . . 1,488 138 244 103 38 0 29 132 1,702 1,655 47

Texas . . . . . . . . . . . . . . . . . . . . . . 39,736 1,175 5,037 3,719 3,445 543 662 5,287 41,592 33,432 8,160

RRC District 1 . . . . . . . . . . . . 746 –24 225 39 152 2 0 93 969 523 446

RRC District 2 Onshore . . . . . 1,371 120 189 227 143 0 40 206 1,430 1,178 252

RRC District 3 Onshore . . . . . 4,156 290 568 535 570 181 338 916 4,652 3,612 1,040

RRC District 4 Onshore . . . . . 8,021 138 1,123 1,191 1,023 99 231 1,321 8,123 7,877 246

RRC District 5 . . . . . . . . . . . . 1,923 66 148 136 94 233 6 193 2,141 2,088 53

RRC District 6 . . . . . . . . . . . . 6,036 166 647 287 303 0 5 618 6,252 5,690 562

RRC District 7B . . . . . . . . . . . 539 52 142 60 12 0 6 81 610 378 232

RRC District 7C . . . . . . . . . . . 3,468 45 649 176 477 0 12 412 4,063 3,371 692

RRC District 8 . . . . . . . . . . . . 6,052 342 606 603 272 16 11 646 6,050 3,069 2,981

RRC District 8A . . . . . . . . . . . 1,333 6 89 45 8 0 0 97 1,294 18 1,276

RRC District 9 . . . . . . . . . . . . 868 7 65 31 89 0 0 128 870 749 121

RRC District 10 . . . . . . . . . . . 4,910 –20 550 369 259 12 7 504 4,845 4,592 253

State Offshore . . . . . . . . . . . . 313 –13 36 20 43 0 6 72 293 287 6

Utah . . . . . . . . . . . . . . . . . . . . . . . 1,701 39 133 82 132 17 0 193 1,747 1,446 301

Virginia. . . . . . . . . . . . . . . . . . . . . 1,836 109 46 6 0 0 0 55 1,930 1,930 0

West Virginia . . . . . . . . . . . . . . . . 2,588 83 312 92 10 0 74 182 2,793 2,722 71

Wyoming . . . . . . . . . . . . . . . . . . . 12,712 79 1,267 605 437 0 24 830 13,084 12,260 824

Federal Offshorea . . . . . . . . . . . . 29,518 263 3,529 2,945 1,646 736 1,767 5,095 29,419 21,982 7,437

Pacific (California) . . . . . . . . . 1,289 24 19 47 31 0 0 50 1,266 115 1,151

Gulf of Mexico (Louisiana)a . . 21,664 243 2,830 2,346 1,388 626 1,466 3,752 22,119 16,627 5,492

Gulf of Mexico (Texas). . . . . . 6,565 –4 680 552 227 110 301 1,293 6,034 5,240 794

Miscellaneousb . . . . . . . . . . . . . . c69 –3 11 3 0 0 0 6 68 40 28

U.S. Total . . . . . . . . . . . . . . . . . . 173,476 4,288 18,034 13,757 8,189 1,491 3,209 19,783 175,147 144,352 30,795

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 1996 contained in the Natural Gas Annual 1996, DOE/EIA-0131(96).

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

30 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Figure 20. Changes in Dry Natural Gas Proved Reserves by Area, 1995 to 1996

Figure 19. 1996 Dry Natural Gas Proved Reserves by Area

Source: Energy Information Administration, Office of Oil and Gas.
of dry natural gas reserves were 12,318 billion cubic

feet, an increase of 12 percent (1,357 billion cubic feet)

from the level reported in 1995. These total discoveries

are equivalent to 65 percent of the level of 1996 gas

production. About one-third of the total discoveries were

in the Gulf of Mexico Federal Offshore. Other areas

with large volumes were Texas (35 percent or 4,343

billion cubic feet), particularly south Texas (10 percent),

Louisiana (8 percent or 1,028 billion cubic feet),

Oklahoma (7 percent or 810 billion cubic feet), and New

Mexico (5 percent or 564 billion cubic feet). New field

discoveries (1,451 billion cubic feet) were 13 percent

lower than in 1995. Those areas with the largest new

field discoveries were the Gulf of Mexico Federal

Offshore with 50 percent of them (728 billion cubic feet)

and Texas with 36 percent (516 billion cubic feet). New

reservoir discoveries in old fields were 3,110 billion cubic

feet, 27 percent higher than 1995. Among the areas with

the largest new reservoir discoveries in old fields were the

Gulf of Mexico Federal Offshore (56 percent or 1,746

billion cubic feet), Texas (20 percent), and Louisiana (14

percent). The Louisiana portion of the Gulf of Mexico

Federal Offshore accounted for 47 percent of the new

reservoir discoveries in old fields. Extensions were 7,757

billion cubic feet, 13 percent higher than in 1995. Areas

with the largest extensions were Texas (41 percent) and

the Gulf of Mexico Federal Offshore (21 percent).

of dry natural gas reserves were 12,318 billion cubic

feet, an increase of 12 percent (1,357 billion cubic feet)

from the level reported in 1995. These total discoveries

are equivalent to 65 percent of the level of 1996 gas

production. About one-third of the total discoveries were

in the Gulf of Mexico Federal Offshore. Other areas

with large volumes were Texas (35 percent or 4,343

billion cubic feet), particularly south Texas (10 percent),

Louisiana (8 percent or 1,028 billion cubic feet),

Oklahoma (7 percent or 810 billion cubic feet), and New

Mexico (5 percent or 564 billion cubic feet). New field

discoveries (1,451 billion cubic feet) were 13 percent

lower than in 1995. Those areas with the largest new

field discoveries were the Gulf of Mexico Federal

Offshore with 50 percent of them (728 billion cubic feet)

and Texas with 36 percent (516 billion cubic feet). New

reservoir discoveries in old fields were 3,110 billion cubic

feet, 27 percent higher than 1995. Among the areas with

the largest new reservoir discoveries in old fields were the

Gulf of Mexico Federal Offshore (56 percent or 1,746

billion cubic feet), Texas (20 percent), and Louisiana (14

percent). The Louisiana portion of the Gulf of Mexico

Federal Offshore accounted for 47 percent of the new

reservoir discoveries in old fields. Extensions were 7,757

billion cubic feet, 13 percent higher than in 1995. Areas

with the largest extensions were Texas (41 percent) and

the Gulf of Mexico Federal Offshore (21 percent).

of dry natural gas reserves were 12,318 billion cubic

feet, an increase of 12 percent (1,357 billion cubic feet)

from the level reported in 1995. These total discoveries

are equivalent to 65 percent of the level of 1996 gas

production. About one-third of the total discoveries were

in the Gulf of Mexico Federal Offshore. Other areas

with large volumes were Texas (35 percent or 4,343

billion cubic feet), particularly south Texas (10 percent),

Louisiana (8 percent or 1,028 billion cubic feet),

Oklahoma (7 percent or 810 billion cubic feet), and New

Mexico (5 percent or 564 billion cubic feet). New field

discoveries (1,451 billion cubic feet) were 13 percent

lower than in 1995. Those areas with the largest new

field discoveries were the Gulf of Mexico Federal

Offshore with 50 percent of them (728 billion cubic feet)

and Texas with 36 percent (516 billion cubic feet). New

reservoir discoveries in old fields were 3,110 billion cubic

feet, 27 percent higher than 1995. Among the areas with

the largest new reservoir discoveries in old fields were the

Gulf of Mexico Federal Offshore (56 percent or 1,746

billion cubic feet), Texas (20 percent), and Louisiana (14

percent). The Louisiana portion of the Gulf of Mexico

Federal Offshore accounted for 47 percent of the new

reservoir discoveries in old fields. Extensions were 7,757

billion cubic feet, 13 percent higher than in 1995. Areas

with the largest extensions were Texas (41 percent) and

the Gulf of Mexico Federal Offshore (21 percent).

of dry natural gas reserves were 12,318 billion cubic

feet, an increase of 12 percent (1,357 billion cubic feet)

from the level reported in 1995. These total discoveries

are equivalent to 65 percent of the level of 1996 gas

production. About one-third of the total discoveries were

in the Gulf of Mexico Federal Offshore. Other areas

with large volumes were Texas (35 percent or 4,343

billion cubic feet), particularly south Texas (10 percent),

Louisiana (8 percent or 1,028 billion cubic feet),

Oklahoma (7 percent or 810 billion cubic feet), and New

Mexico (5 percent or 564 billion cubic feet). New field

discoveries (1,451 billion cubic feet) were 13 percent

lower than in 1995. Those areas with the largest new

field discoveries were the Gulf of Mexico Federal

Offshore with 50 percent of them (728 billion cubic feet)

and Texas with 36 percent (516 billion cubic feet). New

reservoir discoveries in old fields were 3,110 billion cubic

feet, 27 percent higher than 1995. Among the areas with

the largest new reservoir discoveries in old fields were the

Gulf of Mexico Federal Offshore (56 percent or 1,746

billion cubic feet), Texas (20 percent), and Louisiana (14

percent). The Louisiana portion of the Gulf of Mexico

Federal Offshore accounted for 47 percent of the new

reservoir discoveries in old fields. Extensions were 7,757

billion cubic feet, 13 percent higher than in 1995. Areas

with the largest extensions were Texas (41 percent) and

the Gulf of Mexico Federal Offshore (21 percent).

Production

Dry natural gas production increased 5 percent in 1996

(Table 1). Of the five leading producing areas in 1996,

only New Mexico increased its production. This

increase was primarily the result of coalbed methane

production in the San Juan basin. As in 1995, the Gulf of

Mexico Federal Offshore and Texas were the leading

producers of dry natural gas in 1996, each with over

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

combined, Oklahoma, Louisiana, and New Mexico

(each with 8 percent) contributed another quarter of the

production.

Wet Natural Gas

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

December 31, 1996, were 175,147 billion cubic feet, an

increase of 1 percent (1,671 billion cubic feet) from that

reported in 1995 (Table 9). Proved wet natural gas

reserves for the lower 48 States were higher by 1

percent (1,950 billion cubic feet) than in 1995, while

those of Alaska decreased by 279 billion cubic feet. Dry

natural gas is a roughly 5 percent lower in volume than

wet gas because of the shrinkage that results from the

removal of liquids from the wet gas.

Nonassociated Natural Gas

Proved Reserves

U.S. proved reserves of nonassociated (NA) natural

gas, wet after lease separation, of 144,352 billion cubic

feet increased one percent (1,673 billion cubic feet) in

1996 (Table 10). This increase was the third in a row.

Lower 48 States NA wet natural gas proved reserves

increased by 1,767 billion cubic feet, or slightly over 1

percent. Those areas with the largest increases of NA

wet natural gas reserves were Texas, Michigan, and

Colorado. There were also large decreases of NA wet

natural gas reserves in Kansas and New Mexico.

Discoveries

NA wet natural gas total discoveries of 11,338 billion

cubic feet represented a increase of 17 percent (1,646

billion cubic feet) in 1996. The Gulf of Mexico Federal

Offshore, Texas, Louisiana, and Oklahoma accounted

for 9,400 billion cubic feet, or 83 percent of U.S. NA wet

natural gas total discoveries in 1996, percentage wise the

same percent as last year.

Production

U.S. production of NA wet natural gas increased by 5

percent (857 billion cubic feet) in 1996 (Table 10). As in

1995, the Gulf of Mexico Federal Offshore and Texas,

each with over one-fourth of the U.S. total, were the

leading producers of wet natural gas in 1996.

Associated-Dissolved

Natural Gas

Proved Reserves

U.S. proved reserves of associated-dissolved (AD)

natural gas, wet after lease separation, remained

virtually the same in 1996 at 30,795 billion cubic feet

(Table 11). Lower 48 States proved reserves of AD wet

natural gas increased by 183 billion cubic feet to 24,715

billion cubic feet, offsetting the Alaska decrease of 185

billion cubic feet. Those areas of the country with the

largest AD wet natural gas reserves were Texas (27

percent), the Gulf of Mexico Federal Offshore (20

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 31
Energy Information Administration

32 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table 10. Nonassociated Natural Gas Proved Reserves, Reserves Changes, and Production, Wet After

Lease Separation, 1996

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

Changes in Reserves During 1996

Published New Reservoir

Proved Revision Revision New Field Discoveries Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/95 (+,-) (+) (-) (+) (+) (+) (-) 12/31/96

Alaska. . . . . . . . . . . . . . . . . . . . . . . 3,310 66 115 64 0 0 0 211 3,216

Lower 48 States . . . . . . . . . . . . . . 139,369 4,058 14,685 11,680 7,198 1,269 2,871 16,634 141,136

Alabama . . . . . . . . . . . . . . . . . . . . . 4,886 –42 504 94 175 0 0 367 5,062

Arkansas . . . . . . . . . . . . . . . . . . . . 1,462 18 79 83 56 2 27 178 1,383

California . . . . . . . . . . . . . . . . . . . . 736 –111 90 44 3 0 17 81 610

Coastal Region Onshore . . . . . . 54 –4 8 5 0 0 0 5 48

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

San Joaquin Basin Onshore . . . 679 –107 82 39 3 0 17 75 560

State Offshore . . . . . . . . . . . . . . 3 0 0 0 0 0 0 1 2

Colorado. . . . . . . . . . . . . . . . . . . . . 6,520 507 611 252 112 0 5 494 7,009

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

Kansas . . . . . . . . . . . . . . . . . . . . . . 9,026 331 380 997 51 0 2 730 8,063

Kentucky. . . . . . . . . . . . . . . . . . . . . 1,075 –48 44 11 11 1 10 60 1,022

Louisiana . . . . . . . . . . . . . . . . . . . . 8,890 620 995 911 454 12 437 1,459 9,038

North . . . . . . . . . . . . . . . . . . . . . 2,730 146 449 172 149 2 1 371 2,934

South Onshore. . . . . . . . . . . . . . 5,446 447 464 654 279 10 411 925 5,478

State Offshore . . . . . . . . . . . . . . 714 27 82 85 26 0 25 163 626

Michigan. . . . . . . . . . . . . . . . . . . . . 1,018 580 403 139 17 78 0 179 1,778

Mississippi . . . . . . . . . . . . . . . . . . . 640 –7 74 74 34 0 1 81 587

Montana . . . . . . . . . . . . . . . . . . . . . 739 20 52 11 1 0 1 47 755

New Mexico . . . . . . . . . . . . . . . . . . 17,069 158 866 1,125 530 2 4 1,272 16,232

East . . . . . . . . . . . . . . . . . . . . . . 1,648 –3 246 127 88 2 4 246 1,612

West. . . . . . . . . . . . . . . . . . . . . . 15,421 161 620 998 442 0 0 1,026 14,620

New York . . . . . . . . . . . . . . . . . . . . 195 20 35 12 3 0 9 21 229

North Dakota . . . . . . . . . . . . . . . . . 255 4 14 1 0 3 0 18 257

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 699 51 34 35 0 0 23 57 715

Oklahoma. . . . . . . . . . . . . . . . . . . . 13,067 281 1,886 1,600 738 32 63 1,538 12,929

Pennsylvania . . . . . . . . . . . . . . . . . 1,452 135 230 103 38 0 29 126 1,655

Texas . . . . . . . . . . . . . . . . . . . . . . . 31,949 1,006 3,926 3,144 2,977 526 658 4,466 33,432

RRC District 1 . . . . . . . . . . . . . . 498 –9 79 30 51 2 0 68 523

RRC District 2 Onshore . . . . . . . 1,126 94 172 216 143 0 40 181 1,178

RRC District 3 Onshore . . . . . . . 3,196 233 355 446 499 176 338 739 3,612

RRC District 4 Onshore . . . . . . . 7,812 66 1,094 1,168 1,023 99 231 1,280 7,877

RRC District 5 . . . . . . . . . . . . . . 1,876 38 145 116 93 233 6 187 2,088

RRC District 6 . . . . . . . . . . . . . . 5,425 174 617 238 293 0 5 586 5,690

RRC District 7B . . . . . . . . . . . . . 263 95 115 49 1 0 6 53 378

RRC District 7C . . . . . . . . . . . . . 2,828 70 522 138 402 0 12 325 3,371

RRC District 8 . . . . . . . . . . . . . . 3,218 280 235 368 85 4 7 392 3,069

RRC District 8A . . . . . . . . . . . . . 15 –1 2 0 4 0 0 2 18

RRC District 9 . . . . . . . . . . . . . . 730 –3 53 12 89 0 0 108 749

RRC District 10 . . . . . . . . . . . . . 4,656 –19 502 343 251 12 7 474 4,592

State Offshore . . . . . . . . . . . . . . 306 –12 35 20 43 0 6 71 287

Utah . . . . . . . . . . . . . . . . . . . . . . . . 1,424 17 92 62 124 17 0 166 1,446

Virginia . . . . . . . . . . . . . . . . . . . . . . 1,836 109 46 6 0 0 0 55 1,930

West Virginia . . . . . . . . . . . . . . . . . 2,514 94 296 89 10 0 74 177 2,722

Wyoming . . . . . . . . . . . . . . . . . . . . 11,833 113 1,135 542 417 0 24 720 12,260

Federal Offshorea . . . . . . . . . . . . . 22,047 206 2,885 2,345 1,447 596 1,487 4,341 21,982

Pacific (California) . . . . . . . . . . . 94 1 1 0 27 0 0 8 115

Gulf of Mexico (Louisiana)a . . . . 16,279 214 2,241 1,824 1,202 495 1,191 3,171 16,627

Gulf of Mexico (Texas). . . . . . . . 5,674 –9 643 521 218 101 296 1,162 5,240

Miscellaneousb. . . . . . . . . . . . . . . . 37 –4 8 0 0 0 0 1 40

U.S. Total. . . . . . . . . . . . . . . . . . . . 142,679 4,124 14,800 11,744 7,198 1,269 2,871 16,845 144,352

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 1996 contained in the

Natural Gas Annual 1996, DOE/EIA-0131(96).

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 33

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

Wet After Lease Separation, 1996

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

Changes in Reserves During 1996

Published New Reservoir

Proved Revision Revision New Field Discoveries Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/95 (+,-) (+) (-) (+) (+) (+) (-) 12/31/96

Alaska. . . . . . . . . . . . . . . . . . . . . . . 6,265 3 87 107 6 61 0 235 6,080

Lower 48 States . . . . . . . . . . . . . . 24,532 161 3,147 1,906 985 161 338 2,703 24,715

Alabama . . . . . . . . . . . . . . . . . . . . . 44 2 3 3 2 0 0 10 38

Arkansas . . . . . . . . . . . . . . . . . . . . 104 14 18 25 1 0 0 23 89

California . . . . . . . . . . . . . . . . . . . . 1,619 0 127 30 13 0 1 147 1,583

Coastal Region Onshore . . . . . . 109 15 9 5 1 0 0 9 120

Los Angeles Basin Onshore . . . 115 -4 16 5 0 0 0 10 112

San Joaquin Basin Onshore . . . 1,339 -11 101 17 12 0 1 121 1,304

State Offshore . . . . . . . . . . . . . . 56 0 1 3 0 0 0 7 47

Colorado. . . . . . . . . . . . . . . . . . . . . 1,072 -14 243 176 0 0 0 70 1,055

Florida . . . . . . . . . . . . . . . . . . . . . . 110 0 15 0 0 0 0 6 119

Kansas . . . . . . . . . . . . . . . . . . . . . . 67 9 19 11 11 0 1 14 82

Kentucky. . . . . . . . . . . . . . . . . . . . . 27 -1 1 1 0 0 0 2 24

Louisiana . . . . . . . . . . . . . . . . . . . . 1,001 -43 173 125 150 2 33 152 1,039

North . . . . . . . . . . . . . . . . . . . . . 133 -1 37 6 107 2 9 26 255

South Onshore. . . . . . . . . . . . . . 720 -46 108 101 38 0 8 100 627

State Offshore . . . . . . . . . . . . . . 148 4 28 18 5 0 16 26 157

Michigan. . . . . . . . . . . . . . . . . . . . . 326 9 64 17 1 0 0 36 347

Mississippi . . . . . . . . . . . . . . . . . . . 27 20 13 15 9 0 0 7 47

Montana . . . . . . . . . . . . . . . . . . . . . 53 -3 7 1 1 0 0 6 51

New Mexico . . . . . . . . . . . . . . . . . . 1,678 0 291 97 72 2 5 258 1,693

East . . . . . . . . . . . . . . . . . . . . . . 1,559 28 258 91 72 2 5 248 1,585

West. . . . . . . . . . . . . . . . . . . . . . 119 -28 33 6 0 0 0 10 108

New York . . . . . . . . . . . . . . . . . . . . 2 0 1 0 0 0 0 0 3

North Dakota . . . . . . . . . . . . . . . . . 263 15 27 24 6 0 0 32 255

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 355 51 57 7 0 0 7 64 399

Oklahoma. . . . . . . . . . . . . . . . . . . . 1,228 -105 127 110 24 0 7 148 1,023

Pennsylvania . . . . . . . . . . . . . . . . . 36 3 14 0 0 0 0 6 47

Texas . . . . . . . . . . . . . . . . . . . . . . . 7,787 169 1,111 5 75 468 17 4 821 8,160

RRC District 1 . . . . . . . . . . . . . . 248 -15 146 9 101 0 0 25 446

RRC District 2 Onshore . . . . . . . 245 26 17 11 0 0 0 25 252

RRC District 3 Onshore . . . . . . . 960 57 213 89 71 5 0 177 1,040

RRC District 4 Onshore . . . . . . . 209 72 29 23 0 0 0 41 246

RRC District 5 . . . . . . . . . . . . . . 47 28 3 20 1 0 0 6 53

RRC District 6 . . . . . . . . . . . . . . 611 -8 30 49 10 0 0 32 562

RRC District 7B . . . . . . . . . . . . . 276 -43 27 11 11 0 0 28 232

RRC District 7C . . . . . . . . . . . . . 640 -25 127 38 75 0 0 87 692

RRC District 8 . . . . . . . . . . . . . . 2,834 62 371 235 187 12 4 254 2,981

RRC District 8A . . . . . . . . . . . . . 1,318 7 87 45 4 0 0 95 1,276

RRC District 9 . . . . . . . . . . . . . . 138 10 12 19 0 0 0 20 121

RRC District 10 . . . . . . . . . . . . . 254 -1 48 26 8 0 0 30 253

State Offshore . . . . . . . . . . . . . . 7 -1 1 0 0 0 0 1 6

Utah . . . . . . . . . . . . . . . . . . . . . . . . 277 22 41 20 8 0 0 27 301

Virginia . . . . . . . . . . . . . . . . . . . . . . 0 0 0 0 0 0 0 0 0

West Virginia . . . . . . . . . . . . . . . . . 74 -11 16 3 0 0 0 5 71

Wyoming . . . . . . . . . . . . . . . . . . . . 879 -34 132 63 20 0 0 110 824

Federal Offshorea . . . . . . . . . . . . . 7,471 57 644 600 199 140 280 754 7,437

Pacific (California) . . . . . . . . . . . 1,195 23 18 47 4 0 0 42 1,151

Gulf of Mexico (Louisiana)a . . . . 5,385 29 589 522 186 131 275 581 5,492

Gulf of Mexico (Texas). . . . . . . . 891 5 37 31 9 9 5 131 794

Miscellaneousb. . . . . . . . . . . . . . . . 32 1 3 3 0 0 0 5 28

U.S. Total. . . . . . . . . . . . . . . . . . . . 30,797 164 3,234 2,013 991 222 338 2,938 30,795

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 1996 contained in the

Natural Gas Annual 1996, DOE/EIA-0131(96).

Source: Energy Information Administration, Office of Oil and Gas.
percent), and Alaska (20 percent). These areas logically

correspond to those areas of the country with the

largest volumes of crude oil reserves and production.

Production

U.S. production of AD wet natural gas increased by 2

percent (52 billion cubic feet) in 1996 (Table 11). Those

areas of the country with the largest AD wet natural gas

production were Texas (28 percent) and the Gulf of

Mexico Federal Offshore (24 percent).

Coalbed Methane

Proved Reserves

Growth of reserves of coalbed methane resumed; they

continue to account for 6 percent of 1996 natural gas

reserves (Table 12). Reserves in coalbed methane fields

increased to 10,566 billion cubic feet, 1 percent more

than in 1995 (Figure 21). Coalbed methane proved

reserves are principally in New Mexico, Colorado,

Alabama, and Virginia. Estimates of proved coalbed

methane reserves increased in Colorado and Virginia

and decreased in Alabama and New Mexico in 1996.

The coalbed methane volumes are a subset of the

volumes reported in Tables 8, 9, 10, 11, and 13.

Production

Coalbed methane production grew by more than 5

percent in 1996. Most of the increase occurred in the

Basin and Ignacio-Blanco fields of the San Juan basin,

and in the Oakwood and Nora fields of southern

Virginia.

Energy Information Administration

34 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

0

2

4

6

8

10

12

1989 1990 1991 1992 1993 1994 1995 1996

TrillionCubicFeet

Figure 21. Coalbed Methane Proved Reserves

1989-1996

Table 12. U.S. Coalbed Methane Proved Reserves and Production, 1993-1996

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

1993 1993 1994 1994 1995 1995 1996 1996

State Reserves Production Reserves Production Reserves Production Reserves Production

Alabama . . . . . . . 1,237 103 976 108 972 109 823 98

Colorado . . . . . . . 3,107 125 2,913 179 3,461 226 3,711 274

New Mexico . . . . 4,775 486 4,137 530 4,299 574 4,180 575

Othersa . . . . . . . . 1,065 18 1,686 34 1,767 47 1,852 56

Total . . . . . . . . . . 10,184 732 9,712 851 10,499 956 10,566 1,003

aIncludes Kansas, Oklahoma, Pennsylvania, Utah, Virginia, West Virginia, and Wyoming.

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

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

Nonproducing Reservoirs

Proved natural gas reserves, wet after lease separation,

of 33,049 billion cubic feet were reported in

nonproducing reservoirs in 1996 (Table 13). This was

627 billion cubic feet, or about 2 percent, less than in

1995. Three areas, Louisiana, New Mexico, and the Gulf

of Mexico Federal Offshore, accounted for most of the

decrease, while Texas, Wyoming, Michigan, Utah,

Virginia, and West Virginia were states where there

was an increase. About 39 percent of the reserves in

nonproducing reservoirs are located in the Gulf of

Mexico Federal Offshore area. Much of the new

deepwater reserves are presently in the nonproducing

category. Proved reserves in nonproducing reservoirs

were reported by Category I and II operators, who

collectively account for about 93 percent of the

estimated total wet natural gas production in the

United States. Past surveys showed that most of the

wells or reservoirs were not producing 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.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 35
Energy Information Administration

36 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

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

1996a

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

AssociatedState and Subdivision Nonassociated Gas Dissolved Gas Total

Alaska . . . . . . . . . . . . . . . . . . . . 69 61 130

Lower 48 States . . . . . . . . . . . . . . . 27,691 5,228 32,919

Alabama . . . . . . . . . . . . . . . . . . . 452 4 456

Arkansas . . . . . . . . . . . . . . . . . . . 149 7 156

California . . . . . . . . . . . . . . . . . . . 31 125 156

Coastal RegionOnshore . . . . . . . . . . 3 41 44

Los Angeles Basin Onshore . . . . . . . . 0 24 24

San Joaquin Basin Onshore . . . . . . . . 28 59 87

State Offshore . . . . . . . . . . . . . . . 0 1 1

Colorado . . . . . . . . . . . . . . . . . . . 627 270 897

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

Kansas . . . . . . . . . . . . . . . . . . . . 178 7 185

Kentucky . . . . . . . . . . . . . . . . . . . 124 0 124

Louisiana . . . . . . . . . . . . . . . . . . . 2,357 349 2,706

North . . . . . . . . . . . . . . . . . . . . 639 96 735

South Onshore. . . . . . . . . . . . . . . 1,486 202 1,688

State Offshore . . . . . . . . . . . . . . . 232 51 283

Michigan . . . . . . . . . . . . . . . . . . . 197 20 217

Mississippi . . . . . . . . . . . . . . . . . . 54 6 60

Montana . . . . . . . . . . . . . . . . . . . 94 2 96

New Mexico. . . . . . . . . . . . . . . . . . 1,798 74 1,872

East . . . . . . . . . . . . . . . . . . . . 187 70 257

West . . . . . . . . . . . . . . . . . . . . 1,611 4 1,615

New York . . . . . . . . . . . . . . . . . . . 5 0 5

North Dakota . . . . . . . . . . . . . . . . . 118 10 128

Ohio. . . . . . . . . . . . . . . . . . . . . . 19 1 20

Oklahoma. . . . . . . . . . . . . . . . . . . 1,158 70 1,228

Pennsylvania . . . . . . . . . . . . . . . . . 57 0 57

Texas . . . . . . . . . . . . . . . . . . . . . 6,979 750 7,729

RRC District 1 . . . . . . . . . . . . . . . 75 129 204

RRC District 2 Onshore . . . . . . . . . . 244 69 313

RRC District 3 Onshore . . . . . . . . . . 500 62 562

RRC District 4 Onshore . . . . . . . . . . 2,517 83 2,600

RRC District 5 . . . . . . . . . . . . . . . 708 3 711

RRC District 6 . . . . . . . . . . . . . . . 1,538 28 1,566

RRC District 7B . . . . . . . . . . . . . . 5 4 9

RRC District 7C . . . . . . . . . . . . . . 419 57 476

RRC District 8 . . . . . . . . . . . . . . . 357 238 595

RRC District 8A . . . . . . . . . . . . . . 5 62 67

RRC District 9 . . . . . . . . . . . . . . . 7 2 9

RRC District 10 . . . . . . . . . . . . . . 478 9 487

State Offshore . . . . . . . . . . . . . . . 126 4 130

Utah. . . . . . . . . . . . . . . . . . . . . . 258 107 365

Virginia . . . . . . . . . . . . . . . . . . . . 101 0 101

West Virginia . . . . . . . . . . . . . . . . . 198 4 202

Wyoming . . . . . . . . . . . . . . . . . . . 2,983 24 3,007

Federal Offshoreb . . . . . . . . . . . . . . 9,753 3,382 13,135

Pacific (California) . . . . . . . . . . . . . 66 44 110

Gulf of Mexico (Louisiana)b . . . . . . . . 7,835 2,954 10,789

Gulf of Mexico (Texas). . . . . . . . . . . 1,852 384 2,236

Miscellaneousc . . . . . . . . . . . . . . . . 1 16 17

US Total . . . . . . . . . . . . . . . . . . . 27,760 5,289 33,049

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,” 1996.
5. Natural Gas Liquids Statistics

Natural Gas Liquids

Proved Reserves

U.S. natural gas liquids proved reserves increased 6

percent to 7,823 million barrels in 1996 (Table 14). The

424 million barrel increase occurred predominantly in

the lower 48 States, which increased to 7,486 million

barrels in 1996. This was the second increase in the

lower 48 States since 1988. Overall, reserve additions

replaced 150 percent of 1996 natural gas liquids

production. Reserve additions from Texas, Gulf of

Mexico Federal Offshore, and New Mexico accounted

for the majority of the reserve additions. The reserves

of three areas account for 56 percent of the Nation's

natural gas liquids proved reserves. Of these, Texas

had 33 percent, New Mexico had 14 percent, the Gulf of

Mexico Federal Offshore had 10 percent, and

Oklahoma and Utah–Wyoming each had 9 percent.

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. From

1986 through 1996, reserves of natural gas liquids have

declined 4 percent.

Discoveries

Total discoveries of natural gas liquids reserves

increased by 13 percent in 1996 to 625 million barrels,

the highest level since 1986. Areas with the largest total

discoveries were Texas (42 percent), the Gulf of Mexico

Federal Offshore (26 percent), Louisiana (10 percent),

Oklahoma (7 percent), and New Mexico (6 percent).

New field discoveries, at 65 million barrels, were 13

million barrels more than in 1995. Areas with the

largest new field discoveries were the Gulf of Mexico

Federal Offshore (45 percent), Texas (37 percent), and

Alaska (14 percent). New reservoir discoveries in old fields,

at 109 million barrels, were 63 percent more than they

were in 1995. Areas with the largest new reservoir

discoveries in old fields were the Gulf of Mexico Federal

Offshore (34 percent), Texas (33 percent), and

Louisiana (26 percent). Extensions were 451 million

barrels, an increase of 4 percent over 1995. Areas with

the largest extensions were Texas (44 percent), the Gulf

of Mexico Federal Offshore (22 percent), Oklahoma (9

percent), and New Mexico and Louisiana (8 percent

each).

Production

Natural gas liquids production increased 7 percent to

850 million barrels in 1996. Alaskan production

increased 10 percent to 33 million barrels in 1996, while

lower 48 States production increased 7 percent to 817

million barrels. Five areas accounted for about 79

percent of the Nation's natural gas liquids production.

Of these, Texas had 37 percent, the Gulf of Mexico

Federal Offshore had 12 percent, Louisiana had 11

percent, Oklahoma had 10 percent, and New Mexico

had 9 percent.

Natural Gas Plant Liquids

Proved Reserves

Natural gas plant liquids proved reserves increased 5

percent in 1996 to 6,516 million barrels (Table 15). Five

areas accounted for about 76 percent of the Nation's

natural gas plant liquids proved reserves: Texas (36

percent), New Mexico (15 percent), Utah–Wyoming (10

percent), Oklahoma (9 percent), and Louisiana (6

percent). The level of natural gas plant liquids reserves

depends on both the volume of natural gas reserves

and the amount of plant liquids that can be

economically extracted from them per unit volume. In

1996, more liquids were extracted per cubic foot of gas

production than in 1995. Therefore, the ratio of liquids

reserves to natural gas reserves increased, leading to a

larger percentage increase in the proved reserves of

natural gas plant liquids than in natural gas reserves.

Production

Natural gas plant liquids production increased 7

percent to 688 million barrels in 1996 (Table 15). Five

areas accounted for about 78 percent of the Nation's

natural gas plant liquids production: Texas (40

percent), New Mexico (11 percent), Oklahoma (11

percent), Louisiana (9 percent), and Utah–Wyoming (6

percent).

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 37
Energy Information Administration

38 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table 14. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 1996

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 1996

Published New Reservoir

Proved Revision Revision New Field Discoveries Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/95 (+,-) (+) (-) (+) (+) (+) (-) 12/31/96

Alaska. . . . . . . . . . . . . . . . . . . . . . . 306 57 12 15 1 9 0 33 337

Lower 48 States . . . . . . . . . . . . . . 7,093 417 832 654 450 56 109 817 7,486

Alabama . . . . . . . . . . . . . . . . . . . . . 120 5 7 2 0 0 0 11 119

Arkansas . . . . . . . . . . . . . . . . . . . . 6 -1 0 0 0 0 0 1 4

California . . . . . . . . . . . . . . . . . . . . 92 1 9 3 1 0 1 9 92

Coastal Region Onshore . . . . . . 8 2 1 1 0 0 0 1 9

Los Angeles Basin Onshore . . . 4 -1 0 0 0 0 0 0 3

San Joaquin Basin Onshore . . . 80 0 8 2 1 0 1 8 80

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

Colorado. . . . . . . . . . . . . . . . . . . . . 273 10 45 27 5 0 0 19 287

Florida . . . . . . . . . . . . . . . . . . . . . . 17 3 3 0 0 0 0 1 22

Kansas . . . . . . . . . . . . . . . . . . . . . . 369 23 16 42 3 0 0 31 338

Kentucky. . . . . . . . . . . . . . . . . . . . . 43 5 2 1 0 0 0 3 46

Louisiana . . . . . . . . . . . . . . . . . . . . 601 -18 62 69 34 0 28 95 543

North . . . . . . . . . . . . . . . . . . . . . 79 6 12 7 8 0 0 13 85

South Onshore. . . . . . . . . . . . . . 495 -50 43 55 25 0 24 71 411

State Offshore . . . . . . . . . . . . . . 27 26 7 7 1 0 4 11 47

Michigan. . . . . . . . . . . . . . . . . . . . . 45 5 13 6 0 2 0 6 53

Mississippi . . . . . . . . . . . . . . . . . . . 8 -1 1 1 1 0 0 1 7

Montana . . . . . . . . . . . . . . . . . . . . . 8 -2 1 0 0 0 0 0 7

New Mexico . . . . . . . . . . . . . . . . . . 943 177 63 83 37 0 1 79 1,059

East . . . . . . . . . . . . . . . . . . . . . . 247 56 48 23 16 0 1 46 299

West. . . . . . . . . . . . . . . . . . . . . . 696 121 15 60 21 0 0 33 760

North Dakota . . . . . . . . . . . . . . . . . 53 -2 3 2 0 0 0 4 48

Oklahoma. . . . . . . . . . . . . . . . . . . . 674 31 101 85 41 1 3 82 684

Texas . . . . . . . . . . . . . . . . . . . . . . . 2,524 43 317 221 200 24 36 317 2,606

RRC District 1 . . . . . . . . . . . . . . 26 9 10 2 7 0 0 4 46

RRC District 2 Onshore . . . . . . . 93 7 12 15 8 0 2 14 93

RRC District 3 Onshore . . . . . . . 272 -2 38 31 35 14 19 56 289

RRC District 4 Onshore . . . . . . . 287 26 49 46 43 3 12 51 323

RRC District 5 . . . . . . . . . . . . . . 54 -2 3 3 2 5 0 5 54

RRC District 6 . . . . . . . . . . . . . . 271 18 30 14 15 0 0 30 290

RRC District 7B . . . . . . . . . . . . . 70 -7 15 7 1 0 1 8 65

RRC District 7C . . . . . . . . . . . . . 274 -8 51 19 35 0 1 31 303

RRC District 8 . . . . . . . . . . . . . . 444 9 43 44 21 1 1 46 429

RRC District 8A . . . . . . . . . . . . . 284 -13 18 9 2 0 0 20 262

RRC District 9 . . . . . . . . . . . . . . 94 25 9 4 12 0 0 17 119

RRC District 10 . . . . . . . . . . . . . 353 -19 39 26 19 1 0 35 332

State Offshore . . . . . . . . . . . . . . 2 0 0 1 0 0 0 0 1

Utah and Wyoming. . . . . . . . . . . . . 593 123 72 39 29 0 1 52 727

West Virginia . . . . . . . . . . . . . . . . . 62 -4 7 2 0 0 2 4 61

Federal Offshorea . . . . . . . . . . . . . 655 20 109 71 99 29 37 102 776

Pacific (California) . . . . . . . . . . . 25 0 0 1 0 0 0 1 23

Gulf of Mexico (Louisiana)a . . . . 496 16 98 60 96 26 33 84 621

Gulf of Mexico (Texas). . . . . . . . 134 4 11 10 3 3 4 17 132

Miscellaneousb. . . . . . . . . . . . . . . . 7 -1 1 0 0 0 0 0 7

U.S. Total. . . . . . . . . . . . . . . . . . . . 7,399 474 844 669 451 65 109 850 7,823

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 1996 contained in the publications Petroleum Supply

Annual 1996, DOE/EIA-0340(96) and Natural Gas Annual 1996 DOE/EIA-0131(96).

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

Proved Reserves

Proved reserves of lease condensate in the United

States were 1,307 million barrels in 1996 (Table 16).

This was 110 million barrels or 9 percent higher than in

1995. The reserves of four areas account for about 80

percent of the Nation's lease condensate proved

reserves. Of these, the Gulf of Mexico Federal Offshore

had 40 percent, Texas had 21 percent, Louisiana had 12

percent, and Utah--Wyoming had 7 percent.

Production

Production of lease condensate was 162 million barrels,

an increase of 17 million barrels, or 12 percent, in 1996.

The production from four areas accounts for about 85

percent of the Nation's lease condensate production. Of

these, the Gulf of Mexico Federal Offshore had 37

percent, Texas had 25 percent, Louisiana had 19

percent, and Oklahoma had 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 1996. Proved reserves of 494 million

barrels of lease condensate, an increase of 12 percent

from 1995, were reported in nonproducing reservoirs

in 1996. 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 1996 Annual Report 39

Table 15. Natural Gas Plant Liquids Proved Reserves and Production, 1996

(Million Barrels of 42 U.S. Gallons)

1996 1996 1996 1996

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska . . . . . . . . . . . . . . . . . . . . . . 337 33

Lower 48 States. . . . . . . . . . . . . . 6,179 655

Alabama . . . . . . . . . . . . . . . . . . . . 52 4

Arkansas . . . . . . . . . . . . . . . . . . . . 2 0

California. . . . . . . . . . . . . . . . . . . . 89 9

Coastal Region Onshore . . . . . 9 1

Los Angeles Basin Onshore . . . 3 0

San Joaquin Basin Onshore. . . 77 8

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

Colorado . . . . . . . . . . . . . . . . . . . . 254 17

Florida . . . . . . . . . . . . . . . . . . . . . . 22 1

Kansas . . . . . . . . . . . . . . . . . . . . . 336 31

Kentucky . . . . . . . . . . . . . . . . . . . . 45 3

Louisiana. . . . . . . . . . . . . . . . . . . . 381 65

North. . . . . . . . . . . . . . . . . . . . . 61 8

South Onshore . . . . . . . . . . . . . 284 48

State Offshore. . . . . . . . . . . . . . 36 9

Michigan . . . . . . . . . . . . . . . . . . . . 48 5

Mississippi. . . . . . . . . . . . . . . . . . . 2 0

Montana . . . . . . . . . . . . . . . . . . . . 7 0

New Mexico . . . . . . . . . . . . . . . . . 998 75

East . . . . . . . . . . . . . . . . . . . . . 287 44

West . . . . . . . . . . . . . . . . . . . . . 711 31

North Dakota. . . . . . . . . . . . . . . . . 40 4

Oklahoma . . . . . . . . . . . . . . . . . . . 615 74

Texas . . . . . . . . . . . . . . . . . . . . . . 2,337 277

RRC District 1. . . . . . . . . . . . . . 44 4

RRC District 2 Onshore . . . . . . 85 12

RRC District 3 Onshore . . . . . . 210 41

RRC District 4 Onshore . . . . . . 241 39

RRC District 5. . . . . . . . . . . . . . 48 4

RRC District 6. . . . . . . . . . . . . . 242 24

RRC District 7B. . . . . . . . . . . . . 64 8

RRC District 7C . . . . . . . . . . . . 285 29

RRC District 8. . . . . . . . . . . . . . 417 45

RRC District 8A. . . . . . . . . . . . . 262 20

RRC District 9. . . . . . . . . . . . . . 116 17

RRC District 10. . . . . . . . . . . . . 323 34

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

Utah and Wyoming . . . . . . . . . . . . 639 44

West Virginia. . . . . . . . . . . . . . . . . 60 4

Federal Offshorea . . . . . . . . . . . . . 245 42

Pacific (California). . . . . . . . . . . 19 1

Gulf of Mexico (Louisiana)a . . . 199 35

Gulf of Mexico (Texas) . . . . . . . 27 6

Miscellaneousb . . . . . . . . . . . . . . . 7 0

U.S. Total . . . . . . . . . . . . . . . . . . . 6,516 688

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 1996 contained in the publications Petroleum Supply Annual 1996,

DOE/EIA-0340(96) and Natural Gas Annual 1996, DOE/EIA-0131(96).

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

40 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Alaska . . . . . . . . . . . . . . . . . . . . . . 0 0

Lower 48 States. . . . . . . . . . . . . . 1,307 162

Alabama . . . . . . . . . . . . . . . . . . . . 67 7

Arkansas . . . . . . . . . . . . . . . . . . . . 2 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 . . . . . . . . . . . . . . . . . . . . 33 2

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

Kansas . . . . . . . . . . . . . . . . . . . . . 2 0

Kentucky . . . . . . . . . . . . . . . . . . . . 1 0

Louisiana. . . . . . . . . . . . . . . . . . . . 162 30

North. . . . . . . . . . . . . . . . . . . . . 24 5

South Onshore . . . . . . . . . . . . . 127 23

State Offshore. . . . . . . . . . . . . . 11 2

Michigan . . . . . . . . . . . . . . . . . . . . 5 1

Mississippi. . . . . . . . . . . . . . . . . . . 5 1

Montana . . . . . . . . . . . . . . . . . . . . 0 0

New Mexico . . . . . . . . . . . . . . . . . 61 4

East . . . . . . . . . . . . . . . . . . . . . 12 2

West . . . . . . . . . . . . . . . . . . . . . 49 2

North Dakota. . . . . . . . . . . . . . . . . 8 0

Oklahoma . . . . . . . . . . . . . . . . . . . 69 8

Texas . . . . . . . . . . . . . . . . . . . . . . 269 40

RRC District 1. . . . . . . . . . . . . . 2 0

RRC District 2 Onshore . . . . . . 8 2

RRC District 3 Onshore . . . . . . 79 15

RRC District 4 Onshore . . . . . . 82 12

RRC District 5. . . . . . . . . . . . . . 6 1

RRC District 6. . . . . . . . . . . . . . 48 6

RRC District 7B. . . . . . . . . . . . . 1 0

RRC District 7C . . . . . . . . . . . . 18 2

RRC District 8. . . . . . . . . . . . . . 12 1

RRC District 8A. . . . . . . . . . . . . 0 0

RRC District 9. . . . . . . . . . . . . . 3 0

RRC District 10. . . . . . . . . . . . . 9 1

State Offshore. . . . . . . . . . . . . . 1 0

Utah and Wyoming . . . . . . . . . . . . 88 8

West Virginia. . . . . . . . . . . . . . . . . 1 0

Federal Offshorea . . . . . . . . . . . . . 531 60

Pacific (California). . . . . . . . . . . 4 0

Gulf of Mexico (Louisiana)a . . . 422 49

Gulf of Mexico (Texas) . . . . . . . 105 11

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

U.S. Total . . . . . . . . . . . . . . . . . . . 1,307 162

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” 1996.

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

Table 16. Lease Condensate Proved Reserves and Production, 1996

(Million Barrels of 42 U.S. Gallons)

1996 1996 1996 1996

State and Subdivision Reserves Production State and Subdivision Reserves Production
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Reserves 1985 Annual Report. DOE/EIA-0216(85).

Washington, DC.

20. Energy Information Administration. September

1997. Petroleum Marketing Monthly.

DOE/EIA-0380(97/09). Washington, DC, pp.

41-45.

21. Energy Information Administration. July 1997.

Natural Gas Monthly. DOE/EIA-0130(97/07).

Washington, DC, p.12.

22 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.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 41
23. Energy Information Administration, August 1990.

U.S. Oil and Gas Reserves by Year of Field Discovery.

DOE/EIA-0534. Washington, DC.

24. Oil & Gas Journal. December 30, 1996. “Worldwide

Look and Reserves and Production”. Vol. 93, No.

52. Tulsa, OK, p. 41.

25. World Oil. August 1997. “World Trends”. Houston,

TX, p. 38.

26. Energy Information Administration. July 1997.

1996 Annual Energy Review. DOE/EIA-0384(96).

Washington, DC, p. 5.

27. Energy Information Administration. July 1997.

1996 Annual Energy Review. DOE/EIA-0384(96).

Washington, DC, p. 182.

28. U.S. Department of the Interior, Minerals

Management Service, Gulf of Mexico OCS

Regional Office. Press Release, September 26, 1996.

29. Shell Oil Company, Houston, TX. Press Release,

August 8, 1996.

30. Texaco Incorporated, 1996 Annual Report, White

Plains, NY, p. 13.

31. Oryx Energy Company, Dallas, TX. Press Release,

September 12, 1996.

32. U.S. Department of the Interior, Minerals

Management Service, Gulf of Mexico OCS

Regional Office. “Announced Natural Gas and Oil

Deepwater Discoveries and Fields for Active

Leases in the Gulf of Mexico”, Electronic data table:

http://www.mms.gov/omm/gomr/homepg/off

shore/deepwatr/deeptbl2.html, updated August

25, 1997.

33. Atlantic Richfield Company, 1996 Annual Report,

Los Angeles, CA, p. 10.

34. U.S. Department of Energy. DOE This Month. Vol.

15, No. 8. Washington, DC, August 1992. p. 13.

35. 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.

36. 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

42 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
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 1991 through 1996

for the top oil and gas well operators. Because we

surveyed only the largest operators (665 operators) for

1996, the categories “501–2,500", and “other” were

combined into a single category of “other,” so that

comparisons between those categories are not possible

for 1996. Any additional category is comparable. The

tables show the volumetric change and percent change

from the previous year and from 1991. In addition they

show the 1996 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 22,910 small operators. We

estimated production and reserves of small operators

each year from a sample of approximately 8 percent of

these operators, however for 1996 we employed a

different methodology. (See Appendix F for details).

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. For example in 1995 an operator

moved from the 11–20 production size class to the 1–10

class, displacing an operator from the group that had

been there since 1991. Most of the apparent changes in

these two size classes resulted from the movement of

operators from size class to size class.

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 1991

through 1996 have changed from 175.3 trillion cubic

feet to 175.1 trillion cubic feet (Table A1). Reserves

have been increasing for the last three years in a row

and are back to the 1991 level. These proved reserves

are highly concentrated in the larger companies. In

1996, the top 20 (Class 1–10 and Class 11–20) producing

companies had 56 percent of the proved reserves of

natural gas. The next two size classes contain 80 and

400 companies and account for 25 and 13 percent of the

U.S. natural gas proved reserves, respectively. The top

20 operators had a decline of 7 percent in their natural

gas proved reserves from 1991 to 1996. While the rest of

the operators (Class 21–100, Class 101–500, and Class

Other) had an increase of 9 percent. In 1996, the top 20

operators' natural gas reserves decreased by 3 percent

from 1995. In addition in 1996, the rest of the operators

had an increase of 6 percent.

Production

Wet natural gas production has steadily increased from

18.0 trillion cubic feet to 19.9 trillion cubic feet from

1991 through 1996 (Table A2) an increase of 10 percent.

In 1996, the top 20 producing companies had 53 percent

of the production of natural gas, while having 56

percent of the proved reserves. The next two size

classes have 27 and 13 percent of the wet gas

production, respectively. The top 20 operators had an

increase of 8 percent in their natural gas production

from 1991 to 1996. The rest of the operators had an

increase of 14 percent from 1991 to 1996. The top 20

operators' wet natural gas production had an increase

of 2 percent in 1996, while the rest of the operators had

an increase of 10 percent, in 1996 from 1995.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 45
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

1996 had 70 percent of U.S. proved reserves of crude oil

(Table A3), in contrast to wet natural gas where these

same companies operated only 56 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 declined 1.5 percent in

1996. The top 20 producing companies had a decline of

6 percent in their domestic proved reserves of crude oil

during 1996. The top 20 class had a decline of 19 percent

in their crude oil proved reserves from 1991 to 1996.

The next two size classes account for 14 and 8 percent of

the U.S. crude oil proved reserves, respectively. The

rest of the operators had a 4 percent increase from 1991

to 1996. A portion of this increase came from property

acquisitions. During the 1991–1996 period, many

operators were continuing to actively buy, sell, and

restructure their oil property positions.

Production

Crude oil production reported for 1991 through 1996

has decreased from 2.5 billion barrels to 2.2 billion

barrels (Table A4). The 20 largest oil and gas producing

companies had 65 percent of U.S. production of crude

oil in 1996, while in 1991 they accounted for 70 percent

of production. This is in contrast to wet natural gas

where these same companies produced only 53 percent

of the total.

U.S. production of crude oil declined by 14 percent

from 1991 to 1996. The top 20 operators had a decline of

20 percent in their oil production during the same

period. U.S. production of crude oil declined by 2

percent from 1995 to 1996, while the top 20 operators

production decreased by 6 percent. The next two size

classes account for 14 and 10 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 1991–1996 period. From 1991 through 1996, fields in

which these large operators were active dropped by

3,348 or 11 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 1991 through 1996, the number

of fields in which the top 20 operators were active in

dropped by 3,172 or 38 percent, while in 1996 the

number dropped 11 percent from 1995.

Energy Information Administration

46 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 47

Class 1–10 79,028 74,350 77,552 76,665 75,856 72,606 –3,250 -6,422 7,260.616

Percent of Total 45.1% 42.9% 45.5% 44.6% 43.7% 41.5% –4.3% –8.1%

Class 11–20 25,763 28,442 22,467 22,691 24,648 25,416 768 –347 2,541.599

Percent of Total 14.7% 16.4% 13.2% 13.2% 14.2% 4.5% 3.1% –1.3%

Class 21–100 38,362 38,388 39,135 40,566 42,604 43,300 696 4,938 541.248

Percent of Total 21.9% 22.2% 23.0% 23.6% 24.6% 24.7% 1.6% 12.9%

Class 101–500 19,330 19,728 19,870 20,608 20,150 22,483 2,333 3,153 56.207

Percent of Total 11.0% 11.4% 11.7% 12.0% 11.6% 12.8% 11.6% 16.3%

Class Other 12,842 12,401 11,466 11,409 10,218 11,342 1,124 -1,500 0.597

Percent of Total 7.3% 7.2% 6.7% 6.6% 5.9% 6.5% 11.0% -11.7%

Category I 145,595 144,351 142,892 143,703 148,233 146,601 –1,632 1,006 828.255

Percent of Total 83.0% 83.3% 83.8% 83.6% 85.4% 83.7% –1.1% 0.7%

Category II 17,604 17,682 17,305 18,158 15,828 18,382 2,554 778 47.745

Percent of Total 10.0% 10.2% 10.2% 10.6% 9.1% 10.5% 16.1% 4.4%

Category III 12,126 11,276 10,292 10,078 9,416 10,164 748 –1,962 0.535

Percent of Total 6.9% 6.5% 6.0% 5.9% 5.4% 5.8% 7.9% –16.2%

Total Published 175,325 173,309 170,490 171,939 173,476 175,147 1,671 –178 284.330

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 1.0% –0.1%

Table A1. Natural Gas Proved Reserves, Wet After Lease Separation, by Operator Production Size Class,

1991–1996

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

1995–1996 1991–1996 1996

Volume and Volume and Average

Percent Percent Reserves

Size Class 1991 1992 1993 1994 1995 1996 Change Change per Operator

Note: There were 23,410 operators in the 1996 sample frame. A sample of 665 operators was drawn including 176 Category I, 385

Category II, and 3 Category III. The “other” size class represents 22,910 operators in 1996.

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

48 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Class 1–10 6,857 6,625 6,801 7,216 7,174 7,448 274 591 744.808

Percent of Total 38.1% 36.3% 36.5% 37.6% 38.0% 37.5% 3.8% 8.6%

Class 11–20 2,864 3,036 2,861 3,083 3,101 3,002 –99 138 300.233

Percent of Total 15.9% 16.6% 15.3% 16.0% 16.4% 15.1% –3.2% 4.8%

Class 21–100 4,367 4,592 4,894 4,878 4,871 5,316 445 949 66.445

Percent of Total 24.2% 25.1% 26.3% 25.4% 25.8% 26.7% 9.1% 21.7%

Class 101–500 2,348 2,411 2,597 2,552 2,477 2,623 146 275 6.557

Percent of Total 13.0% 13.2% 13.9% 13.3% 13.1% 13.2% 5.9% 11.7%

Class Other 1,576 1,605 1,488 1,481 1,251 1,484 233 –92 0.078

Percent of Total 8.7% 8.8% 8.0% 7.7% 6.6% 7.5% 18.6% –5.8%

Category I 14,464 14,767 15,122 15,656 15,800 16,381 581 1,917 92.548

Percent of Total 80.3% 80.8% 81.1% 81.5% 83.7% 82.4% 3.7% 13.3%

Category II 2,086 2,036 2,159 2,221 1,923 2,128 205 42 5.528

Percent of Total 11.6% 11.1% 11.6% 11.6% 10.2% 10.7% 10.7% 2.0%

Category III 1,462 1,467 1,360 1,333 1,151 1,364 213 –98 0.072

Percent of Total 8.1% 8.0% 7.3% 6.9% 6.1% 6.9% 18.5% –6.7%

Total Published 18,012 18,269 18,641 19,210 18,874 19,873 999 1,861 32.261

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 5.3% 10.3%

Table A2. Natural Gas Production, Wet After Lease Separation, by Operator Production Size Class,

1991–1996

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

1995–1996 1991–1996 1996

Volume and Volume and Average

Percent Percent Production

Size Class 1991 1992 1993 1994 1995 1996 Change Change per Operator

Note: There were 23,410 operators in the 1996 sample frame. A sample of 665 operators was drawn including 176 Category I, 385

Category II, and 3 Category III. The “other” size class represents 22,910 operators in 1996.

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 49

Class 1–10 16,825 15,733 14,894 14,351 13,891 13,362 –529 –3,463 1 ,336.246

Percent of Total 68.2% 66.3% 64.9% 63.9% 62.1% 60.7% –3.8% –20.6%

Class 11–20 2,247 2,250 2,389 2,276 2,422 2,013 –409 –234 201.349

Percent of Total 9.1% 9.5% 10.4% 10.1% 10.8% 9.1% –16.9% –10.4%

Class 21–100 2,270 2,370 2,401 2,607 2,623 3,155 532 885 39.439

Percent of Total 9.2% 10.0% 10.5% 11.6% 11.7% 14.3% 20.3% 39.0%

Class 101–500 1,415 1,463 1,440 1,512 1,793 1,838 45 423 4.595

Percent of Total 5.7% 6.2% 6.3% 6.7% 8.0% 8.3% 2.5% 29.9%

Class Other 1,925 1,929 1,833 1,711 1,622 1,649 27 –276 0.087

Percent of Total 7.8% 8.1% 8.0% 7.6% 7.3% 7.5% 1.7% –14.3%

Category I 21,714 20,767 20,090 19,648 19,647 19,312 –335 –2,402 109. 105

Percent of Total 88.0% 87.5% 87.5% 87.5% 87.9% 87.7% –1.7% –11.1%

Category II 1,088 1,150 1,131 1,142 1,103 1,117 14 29 2.903

Percent of Total 4.4% 4.8% 4.9% 5.1% 4.9% 5.1% 1.3% 2.7%

Category III 1,880 1,828 1,737 1,668 1,600 1,588 –12 –292 0.084

Percent of Total 7.6% 7.7% 7.6% 7.4% 7.2% 7.2% –0.8% –15.5%

Total Published 24,682 23,745 22,957 22,457 22,351 22,017 –334 –2,665 35.742

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% –1.5% –10. 8%

Table A3. Crude Oil Proved Reserves by Operator Production Size Class, 1991–1996

(Million Barrels of 42 U.S. Gallons)

1995–1996 1991–1996 1996

Volume and Volume and Average

Percent Percent Reserves

Size Class 1991 1992 1993 1994 1995 1996 Change Change per Operator

Note: There were 23,410 operators in the 1996 sample frame. A sample of 665 operators was drawn including 176 Category I, 385

Category II, and 3 Category III. The “other” size class represents 22,910 operators in 1996.

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

50 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Class 1–10 1,544 1,458 1,346 1,310 1,270 1,220 –50 –324 121.989

Percent of Total 61.5% 59.6% 57.5% 57.8% 57.4% 56.1% –3.9% –21.0%

Class 11–20 218 231 236 224 221 185 –36 –33 18.530

Percent of Total 8.7% 9.4% 10.1% 9.9% 10.0% 8.5% –16.3% –15.1%

Class 21–100 259 272 276 287 276 307 31 48 3.833

Percent of Total 10.3% 11.1% 11.8% 12.7% 12.5% 14.1% 11.2% 18.5%

Class 101–500 208 213 202 200 214 213 –1 5 0.533

Percent of Total 8.3% 8.7% 8.6% 8.8% 9.7% 9.8% –0.5% 2.4%

Class Other 283 272 279 247 232 248 16 –35 0.013

Percent of Total 11.3% 11.1% 11.9% 10.9% 10.5% 11.4% 6.9% –12.4%

Category I 2,068 2,022 1,922 1,879 1,844 1,791 –53 –277 10.118

Percent of Total 82.3% 82.7% 82.2% 82.8% 83.3% 82.4% –2.9% –13.4%

Category II 167 163 153 150 139 143 4 –24 0.372

Percent of Total 6.6% 6.7% 6.5% 6.6% 6.3% 6.6% 2.9% –14.4%

Category III 277 261 264 239 230 239 9 –38 0.013

Percent of Total 11.0% 10.7% 11.3% 10.5% 10.4% 11.0% 3.9% –13.7%

Total Published 2,512 2,446 2,339 2,268 2,213 2,173 –40 –339 3.528

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -1.8% –13.5%

Table A4. Crude Oil Production by Operator Production Size Class, 1991–1996

(Million Barrels of 42 U.S. Gallons)

1995–1996 1991–1996 1996

Volume and Volume and Average

Percent Percent Production

Size Class 1991 1992 1993 1994 1995 1996 Change Change per Operator

Note: There were 23,410 operators in the 1996 sample frame. A sample of 665 operators was drawn including 176 Category I, 385

Category II, and 3 Category III. The “other” size class represents 22,910 operators in 1996.

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 51

Class 1–10 4,947 4,189 3,591 3,258 3,113 2,800 –313 –2,147 280.000

Percent of Total 16.7% 14.7% 13.2% 12.2% 11.9% 10.7% –10.1% –43.4%

Class 11–20 3,466 3,432 2,998 2,795 2,772 2,441 –331 –1,025 244.100

Percent of Total 11.7% 12.1% 11.1% 10.5% 10.6% 9.3% –11.9% –29.6%

Class 21–100 8,156 8,003 7,600 7,752 7,569 7,526 –43 –630 94.075

Percent of Total 27.6% 28.2% 28.0% 29.1% 28.9% 28.7% –0.6% –7.7%

Class 101–500 11,824 11,896 11,881 11,878 11,886 12,492 606 668 31.230

Percent of Total 40.0% 41.9% 43.8% 44.6% 45.4% 47.7% 5.1% 5.6%

Rest 1,760 2,059 1,715 1,897 1,601 952 –649 –808 8.207

Percent of Total 6.0% 7.2% 6.3% 7.1% 6.1% 3.6% –40.5% –45.9%

Category I 18,189 17,620 16,603 16,161 16,256 15,635 –621 –2,554 88.333

Percent of Total 61.5% 62.0% 61.2% 60.7% 62.1% 59.7% –3.8% –14.0%

Category II 11,370 10,799 10,516 10,452 9,939 10,576 637 –794 27.470

Percent of Total 38.5% 38.0% 38.8% 39.3% 37.9% 40.3% 6.4% –7.0%

Total Published 29,559 28,419 27,119 26,613 26,195 26,211 16 –3,348 41.148

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 0.1% –11.3%

Note: Includes only data from Category I and Category II operators. In 1996, there were 176 Category I operators and 385 Category II

operators. The “rest” size class had 65 operators in 1996.

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

Table A5. Operator Field Count by Operator Production Size Class, 1991–1996

1995–1996 1991–1996 1996 Average

Number and Number and Number of

Percent Percent Fields per

Size Class 1991 1992 1993 1994 1995 1996 Change Change Operator
Appendix B

Top 100 Oil and Gas Fields for 1996

Appendix B has been changed this year to reflect the

reported data for production and proved reserves for

fields from the 1996 survey rather than the estimates

for total field levels. To give more up-to-date

information, the data in this appendix represents the

1996 survey results, using only the data provided by

the 568 responding operators of the 1996 survey. In the

past, the top 100 field lists usually lagged 1 year behind

the report data on which this publication focuses. A 1

year lag reflected the increased analysis time needed to

estimate field totals beyond that associated with

preparation of the annual reserves report.

Estimates of the proved reserves and production of the

top 100 oil and gas fields are contained in Tables B1

and B2 of this Appendix. The oil field production and

reserve data include both crude oil and lease

condensate. The gas field production and reserve data

is total (Associated-Dissolved and Nonassociated)

natural gas, wet after lease separation.

The top 100 oil fields in the United States as of

December 31, 1996, had 15,109 million barrels of

proved reserves accounting for 65 percent of the total

United States (Table B1). 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 1996 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.

Two of these three fields, Troika and Ursa, were not in

the previous tabulation, and along with Mars, reflect

the huge potential of the deep water in the Gulf. The

top 100 oil fields in the United States as of December 31,

1996, had 1,225 million barrels of production or 53

percent of the total (Table B1). These are

approximately the same percentages of reserves and

production as reported in the previous publication.

Many of the fields in the top 100 are very old, there

were 45 oil fields that were discovered prior to 1946.

The oldest, Coalinga in California, was discovered in

1887. However, since 1986, an additional 15 oil fields

have been added to the top 100 group, all were in the

Gulf of Mexico Federal Offshore or Alaska.

The top 100 gas fields in the United States as of

December 31, 1996, had 81,901 billion cubic feet of

proved reserves or 47 percent of the total (Table B2).

Unlike the oil fields, the top 100 gas fields show a lesser

degree of concentration. Many, but not all, of the same

fields are in both tables. As an example, the top three

gas fields, Basin, Hugoton Gas Area, and Blanco, are

not found in the oil table. The top 100 gas fields in the

United States as of December 31, 1996, had 6,381 billion

cubic feet of production or 32 percent of the total (Table

B2). For the top 100 gas fields, this is an increase of 7

percent from those reported in the previous

publication. Fewer of the gas fields in the top 100 are

very old, there were 22 gas fields that were discovered

prior to 1946. The oldest, Big Sandy in Kentucky, was

discovered in 1881. However, since 1986, an additional

9 gas fields have been added to the top 100 group, all

were in the Gulf of Mexico Federal Offshore, south

Texas, or Virginia.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 55
Energy Information Administration

56 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table B1. Top 100 U.S. Fields Ranked by Oila Production within Proved Reserves Group, from Reported

1996 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 1–10 286.5

Kuparuk River AK 1969 1–10 98.8

Midway–Sunset CA 1901 1–10 59.1

Kern River CA 1899 1–10 48.3

Belridge South CA 1911 1–10 40.7

Wasson TX 1937 1–10 25.2

Elk Hills CA 1919 1–10 21.6

Yates TX 1926 1–10 19.9

Milne Point AK 1982 1–10 14.1

Mississippi Canyon Blk 807 GF 1989 1–10 5.6

Top 10 Volume Subtotal 8,081.7 619.8

Top 10 Percentage of U.S. Total 34.6% 26.5%

Point McIntyre AK 1988 11–20 57.5

Endicott AK 1978 11–20 26.6

Wilmington CA 1932 11–20 19.5

Spraberry Trend Area TX 1950 11–20 17.3

Hondo PF 1969 11–20 16.4

Slaughter TX 1937 11–20 15.5

Levelland TX 1945 11–20 11.6

San Ardo CA 1947 11–20 4.3

Green Canyon Blk 244 GF 1994 11–20 0.0

Mississippi Canyon Blk 854 GF 1992 11–20 0.0

Top 20 Volume Subtotal 10,235.1 788.6

Top 20 Percentage of U.S. Total 43.9% 33.8%

Giddings TX 1960 21–50 24.0

Garden Banks Blk 426 GF 1987 21–50 21.7

East Texas TX 1930 21–50 19.7

Pescado PF 1970 21–50 18.5

Viosca Knoll Blk 990 GF 1981 21–50 13.5

Seminole TX 1936 21–50 12.6

Lost Hills CA 1910 21–50 12.2

Cymric CA 1916 21–50 11.5

Niakuk AK 1984 21–50 11.2

Sho–Vel–Tum OK 1905 21–50 11.2

Bay Marchand Blk 2 GF & LA 1949 21–50 10.1

Salt Creek TX 1942 21–50 9.7

Coalinga CA 1887 21–50 9.7

Cowden North TX 1930 21–50 9.6

Vacuum NM 1929 21–50 8.6

Rangely CO 1902 21–50 8.1

McElroy TX 1926 21–50 7.8

Fullerton TX 1942 21–50 6.3

Greater Aneth UT 1956 21–50 5.5

Wattenberg CO 1970 21–50 4.7

Ventura CA 1916 21–50 4.6

Jay FL & AL 1970 21–50 4.3

Robertson North TX 1956 21–50 3.9

Howard–Glasscock TX 1925 21–50 3.6

Hawkins TX 1940 21–50 3.5

Wasson 72 TX 1940 21–50 3.2

Eunice Monument NM 1929 21–50 1.3

Alpine AK 1996 21–50 0.0

Green Canyon Blk 205 GF 1988 21–50 0.0

Viosca Knoll Blk 956 GF 1985 21–50 0.0

Top 50 Volume Subtotal 13,229.3 1,049.2

Top 50 Percentage of U.S. Total 56.7% 44.9%
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 57

Point Arguello PF 1981 51–100 15.4

Ewing Bank Blk 873 GF 1991 51–100 13.4

Eugene Island SA Blk 330 GF 1971 51–100 12.3

South Pass SA Blk 89 GF 1969 51–100 7.9

South Pass Blk 61 GF 1955 51–100 7.8

Main Pass SA Blk 299 GF 1967 51–100 7.2

Mcarthur River AK 1965 51–100 6.1

West Delta Blk 30 GF 1949 51–100 6.0

Port Hudson LA 1980 51–100 5.4

South Pass Blk 24 GF & LA 1950 51–100 5.1

Ship Shoal Blk 169 GF 1961 51–100 4.9

Oregon Basin WY 1912 51–100 4.5

Means TX 1934 51–100 4.5

Goldsmith TX 1935 51–100 3.9

Grayburg–Jackson NM 1929 51–100 3.7

Dollarhide TX & NM 1945 51–100 3.6

Painter Reservoir East WY 1979 51–100 3.2

Beta PF 1976 51–100 3.2

Hobbs NM 1928 51–100 3.1

Hatters Pond AL 1974 51–100 3.1

Prentice TX 1950 51–100 3.0

Huntington Beach CA 1920 51–100 3.0

Dos Cuadras PF 1968 51–100 2.7

Stephens County Regular TX 1915 51–100 2.7

Panhandle TX 1910 51–100 2.6

Garden Banks Blk 387 GF 1990 51–100 2.4

Cedar Lake TX 1939 51–100 2.4

Mabee TX 1944 51–100 2.4

Elk Basin WY & MT 1915 51–100 2.4

Inglewood CA 1924 51–100 2.4

Bluebell UT 1949 51–100 2.3

Jo–Mill TX 1953 51–100 2.3

Welch TX 1942 51–100 2.3

Hartzog Draw WY 1976 51–100 2.2

Altamont UT 1952 51–100 2.2

Pennel MT 1955 51–100 2.2

Monument NM 1935 51–100 2.0

Sand Hills TX 1930 51–100 1.9

Kern Front CA 1925 51–100 1.8

Cowden South TX 1930 51–100 1.7

Cottonwood Creek WY 1953 51–100 1.6

Brea–Olinda CA 1897 51–100 1.4

Justis NM 1957 51–100 0.8

Crossett South TX 1956 51–100 0.8

Ewing Bank Blk 965 GF 1991 51–100 0.0

Garden Banks Blk 260 GF 1995 51–100 0.0

Viosca Knoll Blk 825 GF 1988 51–100 0.0

Green Canyon Blk 254 GF 1994 51–100 0.0

Viosca Knoll Blk 786 GF 1996 51–100 0.0

Ship Shoal SA Blk 349 GF 1994 51–100 0.0

Top 100 Volume Subtotal 15,108.9 1,224.9

Top 100 Percentage of U.S. Total 64.8% 52.5%

Table B1. Top 100 U.S. Fields Ranked by Oila Production within Proved Reserves Group, from Reported

1996 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 92 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 2,335 million barrels, used to calculate the percentages in this table, is 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

58 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table B2. Top 100 U.S. Fields Ranked by Gasa Production within Proved Reserves Group, from Reported

1996 Field Level Datab

(Billion Cubic Feet)

Discovery Proved Reserves Reported Production

Field Name Location Year Rank Group Rank Group

Basin NM 1947 1–10 668.8

Hugoton Gas Area KS & OK & TX 1922 1–10 558.0

Blanco NM & CO 1927 1–10 549.4

Carthage TX 1936 1–10 203.5

Prudhoe Bay AK 1967 1–10 189.3

Mobile Bay AL 1985 1–10 131.3

Panhandle West TX 1918 1–10 129.8

Wattenberg CO 1970 1–10 86.4

Whitney Canyon–Carter Crk WY 1978 1–10 81.2

Oakwood VA 1990 1–10 26.8

Top 10 Volume Subtotal 39,737.5 2,624.5

Top 10 Percentage of U.S. Total 22.7% 13.3%

Giddings TX 1960 11–20 386.0

Panoma Gas Area KS 1956 11–20 112.7

Antrim MI 1965 11–20 88.4

Red Oak–Norris OK 1910 11–20 75.2

Cook Inlet North AK 1962 11–20 55.7

Beluga River AK 1962 11–20 36.5

Madden WY 1968 11–20 32.1

Fogarty Creek WY 1975 11–20 31.7

Big Piney–LaBarge WY 1964 11–20 19.3

Lake Ridge WY 1981 11–20 14.7

Top 20 Volume Subtotal 49,911.5 3,476.8

Top 20 Percentage of U.S. Total 28.5% 17.6%

Bob West TX 1990 21–50 119.8

Green Canyon Blk 116 GF 1983 21–50 92.1

Anschutz Ranch East UT & WY 1979 21–50 84.2

Mocane–Laverne Gas Area OK & KS & TX 1946 21–50 80.6

Strong City District OK 1966 21–50 75.2

Matagorda Island Blk 623 GF 1980 21–50 72.7

Mobile Blk 823 GF 1983 21–50 70.6

Watonga–Chickasha Trend OK 1948 21–50 69.4

McArthur River AK 1965 21–50 63.7

Wilburton OK 1941 21–50 62.7

Gomez TX 1963 21–50 61.1

Spraberry Trend Area TX 1950 21–50 59.4

Kinta OK 1914 21–50 55.5

Sawyer TX 1960 21–50 55.5

Garden Banks Blk 426 GF 1987 21–50 54.9

Bruff WY 1974 21–50 52.1

Golden Trend OK 1945 21–50 49.9

Oak Hill TX 1958 21–50 48.2

Natural Buttes UT 1940 21–50 45.5

Elk Hills CA 1919 21–50 43.4

Ozona TX 1953 21–50 43.2

Fairway AL 1986 21–50 42.1

Big Sandy KY 1881 21–50 40.4

Lower Mobile Bay–Mary Ann AL 1979 21–50 33.1

Tip Top WY 1928 21–50 25.3

Hondo PF 1969 21–50 19.3

Wasson TX 1937 21–50 10.6

Mississippi Canyon Blk 731 GF 1987 21–50 0.0

Mississippi Canyon Blk 854 GF 1992 21–50 0.0

Viosca Knoll Blk 956 GF 1985 21–50 0.0

Top 50 Volume Subtotal 67,472.5 5,007.3

Top 50 Percentage of U.S. Total 38.5% 25.3%
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 59

Table B2. Top 100 U.S. Fields Ranked by Gasa Production within Proved Reserves Group, from Reported

1996 Field Level Datab (Continued)

(Billion Cubic Feet)

Discovery Proved Reserves Reported Production

Field Name Location Year Rank Group Rank Group

Indian Basin NM 1963 51–100 69.0

McAllen Ranch TX 1960 51–100 66.6

High Island SA Blk A573 GF 1973 51–100 55.8

Lake Arthur South LA 1955 51–100 54.9

Tordilla TX 1963 51–100 48.3

Elk City OK 1947 51–100 47.2

Port Hudson LA 1977 51–100 47.1

South Pass SA Blk 89 GF 1969 51–100 43.6

Mississippi Canyon Blk 194 GF 1975 51–100 43.3

Puckett TX 1952 51–100 38.9

Knox OK 1916 51–100 38.2

Brown–Bassett TX 1953 51–100 37.9

Boonsville TX 1945 51–100 36.6

Double A Wells TX 1980 51–100 36.4

Moorewood NE OK 1979 51–100 36.2

Eumont NM 1929 51–100 35.8

Sibley LA 1949 51–100 35.2

Painter Reservoir East WY 1979 51–100 34.3

South Timbalier Blk 176 GF 1965 51–100 33.4

Waltman WY 1959 51–100 32.6

Main Pass Blk 41 GF 1956 51–100 32.2

Jeffress NE TX 1975 51–100 31.3

Mississippi Canyon Blk 354 GF 1977 51–100 25.4

Pegasus TX 1949 51–100 25.1

Big Piney WY 1964 51–100 24.2

Newark East TX 1981 51–100 24.1

Conger TX 1973 51–100 24.0

Standard Draw WY 1979 51–100 24.0

Willow Springs TX 1938 51–100 23.8

Cedar Cove Coal Degas AL 1983 51–100 23.8

Nora VA 1949 51–100 22.2

Keystone TX 1935 51–100 21.7

Kuparuk River AK 1969 51–100 20.1

A W P TX 1987 51–100 18.8

Blanco South NM 1951 51–100 17.7

Trawick TX 1949 51–100 17.4

Sonora TX 1954 51–100 15.1

Sugg Ranch TX 1985 51–100 15.0

Viosca Knoll Blk 783 GF 1985 51–100 13.9

Rulison CO 1958 51–100 13.8

Mobile Blk 864 GF 1983 51–100 13.7

Kenai AK 1959 51–100 13.1

Opelika TX 1937 51–100 12.8

Treasure Isle TX 1993 51–100 6.7

Mississippi Canyon Blk 807 GF 1989 51–100 6.2

Hawkins TX 1940 51–100 5.9

Whelan TX 1937 51–100 4.8

Tri–Cities TX 1941 51–100 4.7

Brady WY 1972 51–100 1.1

Green Canyon Blk 244 GF 1994 51–100 0.0

Top 100 Volume Subtotal 81,900.7 6,381.1

Top 100 Percentage of U.S. Total 46.8% 32.3%

aWet after lease separation. bOnly 92 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 19,783 billion cubic feet, used to calculate the percentages in this table, is 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

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."{34}

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 1996 Annual Report 63
Energy Information Administration

64 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table C1. U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids,

in Metric Units, 1986 – 1996

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)

1986 9.0 433.1 297.1 145.0 64.4 7.6 12.9 84.9 472.7 4,275.0 –242.8

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

Dry Natural Gas (billion cubic meters)

1986 37.38 602.27 501.12 138.53 171.74 31.12 50.15 253.01 442.03 5,425.11 –50.49

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

Natural Gas Liquids (million cubic meters)

1985 67.8 144.0 118.3 93.5 53.6 7.0 13.5 74.1 119.7 1,263.0 47.9

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

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, 1986–1995 annual reports, DOE/EIA–0216.{1–10}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 67

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 1995 of the EIA publication U.S. Crude Oil, Natural

Gas, and Natural Gas Liquids Reserves, DOE EIA-0216.{1-19}

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 4,868 120

1996 45 0 5,033 119

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.

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

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

68 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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

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

dExcludes Federal offshore; now included in Federal

Offshore- Pacific (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

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
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 69

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

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

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

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
Energy Information Administration

70 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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

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

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

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
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 71

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

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

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

eIncludes State and Federal offshore Alabama. f

Excludes Federal offshore; now included in Federal

Offshore- Gulf 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
Energy Information Administration

72 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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

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

eIncludes State and Federal offshore Alabama. f

Excludes Federal offshore; now included in Federal

Offshore- Gulf 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

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
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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

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

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

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

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
Energy Information Administration

74 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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

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

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

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
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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

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

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

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

gExcludes Federal offshore; now included in Federal

Offshore- Gulf 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
Energy Information Administration

76 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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

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

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

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
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 77

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

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

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

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
Energy Information Administration

78 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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

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

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

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
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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

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

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)

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

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
Energy Information Administration

80 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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

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 29,448 642

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

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 18

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

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

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 1996 Annual Report 81

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

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

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 7,106

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

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 7,466

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
Energy Information Administration

82 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table D1. U.S. Proved Reserves of Crude Oil, 1976–1996

(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

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 1995 annual reports, DOE/EIA-0216.{1-19}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 83

Table D2. U.S. Lower 48 Proved Reserves of Crude Oil, 1976–1996

(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

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 1995 annual reports, DOE/EIA-0216.{1-19}
Energy Information Administration

84 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table D3. U.S. Proved Reserves of Dry Natural Gas, 1976–1996

(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

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 1995 annual reports, DOE/EIA-0216.{1-19}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 85

Table D4. U.S. Lower 48 Proved Reserves of Dry Natural Gas, 1976–1996

(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

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 1995 annual reports, DOE/EIA-0216.{1-19}
Energy Information Administration

86 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table D5. U.S. Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–1996

(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

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 1995 annual reports, DOE/EIA-0216.{1-10,12-19}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 87

Table D6. U.S. Lower 48 Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–1996

(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

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 1995 annual reports, DOE/EIA-0216.{1-10,12-19}
Energy Information Administration

88 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table D7. U.S. Proved Reserves of Natural Gas Liquids, 1978–1996

(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

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 1995annual reports, DOE/EIA-0216.{1-10,12-19}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 89

Table D8. U.S. Lower 48 Proved Reserves of Natural Gas Liquids, 1978–1996

(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

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 1995 annual reports, DOE/EIA-0216.{1-10,12-19}
Energy Information Administration

90 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-1996

Gulf of Mexico Depth

Greater than Less than Deepwater

Year Total LouisianaaTexas 200 metersb200 meters Percentage

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

Production

1992 267 253 14 54 213 20.2

1993 266 252 14 52 214 19.5

1994 265 245 20 60 205 22.6

1995 292 262 30 83 209 28.4

1996 303 265 38 97 206 32.0

Reserves

1992 1,835 1,643 192 582 1,253 31.7

1993 2,072 1,880 192 849 1,223 41.0

1994 2,127 1,922 205 908 1,219 42.7

1995 2,518 2,269 249 1,261 1,257 50.1

1996 2,567 2,357 210 1,346 1,221 52.4

Natural Gas, Wet After Lease Separation

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

Production

1992 4,576 3,292 1,284 243 4,333 5.3

1993 4,651 3,383 1,268 316 4,335 6.8

1994 4,797 3,505 1,292 393 4,404 8.2

1995 4,679 3,421 1,258 418 4,261 8.9

1996 5,045 3,752 1,293 613 4,432 12.2

Reserves

1992 27,050 20,006 7,044 3,731 23,319 13.8

1993 26,463 19,751 6,712 3,848 22,615 14.5

1994 27,626 21,208 6,418 5,137 22,489 18.6

1995 28,229 21,664 6,565 6,159 22,070 21.8

1996 28,153 22,119 6,034 6,877 21,276 24.4

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

Production

1992 91 76 15 5 86 5.5

1993 97 80 17 8 89 8.2

1994 98 83 15 9 89 9.2

1995 85 71 14 7 78 8.2

1996 101 84 17 15 86 14.9

Reserves

1992 590 472 118 107 483 18.1

1993 605 490 115 111 494 18.3

1994 603 500 103 130 473 21.6

1995 630 496 134 232 398 36.8

1996 753 621 132 334 419 44.4

aIncludes Federal Offshore Alabama.

bBlocks in Atwater Valley, Ewing Bank, Green Canyon, Mississippi Canyon, Walker Ridge, Alaminos Canyon, Corpus Christi, East

Breaks, Garden Banks, Keathley Canyon, Port Isabel are included. In addition, blocks 737-742, 779-786, 817-830, 859-874, 901-918,

943-962, and 987-1006 in Viosca Knoll are included.

Source: Based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves.”
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 1996 by crude oil or

natural gas well operators who were active as of

December 31, 1996. 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 1989 and 1996, and depicts

the number of active operators, 1989 showing the

largest in the series. The 1996 sampling frame consisted

of 176 Category I, 486 Category II, 3 Category III

Certainty, and 22,745 Category III Noncertainty

operators, for a total of 23,410 active operators. The

survey sample consisted of 665 operators selected with

certainty that included all of the Category I and II

Certainty operators and the 3 smaller operators that

were selected with certainty because of their size in

relation to the area or areas in which they operated.

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 1996 survey is

summarized in Table E2. EIA makes a considerable

effort to gain responses from all operators. About 9

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 59 nonoperators, 10 had successor operators that

had taken over the production of the nonoperator.

These successor operators were subsequently sampled.

The overall response rate for the 1996 survey was 100

percent.

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

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. Report

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 93
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 I2, 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.

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

Energy Information Administration

94 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table E1. Comparison of the EIA-23 Active Operator Sample and Sampling Frame, 1989-1996

Number of Operators

Operator Category 1989 1990 1991 1992 1993 1994 1995 1996

Certainty Frame 3,570 2,928 2,702 2,533 2,383 2,337 2,233 665

Category I 134 144 144 157 160 161 161 176

Category II 500 468 484 480 500 482 476 486

Category III 2,936 2,316 2,074 1,896 1,723 1,694 1,596 3

Sampled 3,570 2,928 2,702 2,533 2,383 2,337 2,233 665

Percent Sampled 100 100 100 100 100 100 100 100

Noncertainty Frame 24,062 24,628 22,144 21,640 21,273 21,885 20,533 22,745

Sampled 1,325 1,431 1,760 1,724 1,691 1,737 1,632 0

Percent Sampled 66888880

Total Frame 27,632 27,556 24,846 24,173 23,656 24,222 22,766 23,410

Not Sampled 22,737 23,196 20,384 19,916 19,791 20,148 18,901 22,745

Sampled 4,895 4,360 4,462 4,257 4,074 4,074 3,865 665

Percent Sampled 18 16 18 18 17 17 17 3

Note: The three operators sampled as Category III in 1996 are operating in the Federal Offshore and the Federal Offshore is sampled

with Certainty.

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

Table E2. Form EIA–23 Survey Response Statistics, 1996

Netb Responding Nonresponding

Sample Successora Category Non–c Total Operators Operators

Operator Category Selected Operators Changes operators Operators Number Percent Number Percent

Certainty

Category I . . . . . . . 176 2 15 –16 177 177 100.0 0 0.0

Category II . . . . . . . 486 7 –65 –43 385 385 100.0 0 0.0

Category III . . . . . . . 3 1 50 0 54 54 100.0 0 0.0

Subtotal. . . . . . . . . 665 10 0 –59 616 616 100.0 0 0.0

Noncertainty . . . . . . . . 0 0 0 0 0 0 0 0 0.0

Total . . . . . . . . . . . . 665 10 0 –59 616 616 100.0 0 0.0

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.

Notes: Data from 568 operators were used to estimate proved reserves for 1996. Data from 48 onshore operators that changed to

Category III size class from Category II were not used to make the 1996 proved reserves estimates. In order to have complete coverage in the

Federal Offshore, six Category III operators that were operating in the Federal Offshore in 1996 were used to estimate proved reserves. Three

of these operators changed size class from Category II to Category III.

Source: Form EIA–23, “Annual Survey of Domestic Oil and Gas Reserves” 1996.
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 I3, 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 1996, in December of 1996, was the 14th

annual report and reflected data collected through

October 1996. 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 1996, Form EIA-23 National estimates of

production were 2,335 million barrels for crude oil and

lease condensate or 31 million barrels (1.3 percent)

lower than that reported in the Petroleum Supply Annual

1996 for crude oil and lease condensate. Form EIA-23

National estimates of production for dry natural gas

were 18,861 billion cubic feet or 68 billion cubic feet (0.4

percent) higher than the Natural Gas Annual 1996 for

1996 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 Petroleum Information/Dwight's LLC

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 1996 survey

mailing. These changes resulted from all frame

maintenance activities.

The Form EIA-23 operator frame contained a total of

64,172 entries as of December 27, 1996. Of these, 23,410

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.

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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 95
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 14, 1996. In

addition, plant operators whose plants were shut down

or dismantled during 1996 were required to complete

forms for the portion of 1996 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

265 operators of 725 plants were sent forms. This

number included 6 new plants and 9 successor plants

identified after the initial 1996 survey mailing. A total

of 39 plants were reported as nonoperating according

to the Form EIA-64A definition. The response rate was

again 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

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.

Energy Information Administration

96 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table E3. Summary of the 1996 Operator Frame

Activity, Form EIA–23

Total 1995 Operator Frame. . . . . . . . . . . . . 64,049

Operators. . . . . . . . . . . . . . . . . . . . . . . 22,695

Nonoperators. . . . . . . . . . . . . . . . . . . . 41,354

Changes to 1995 Operator Statusa . . . . . 603

From Nonoperator to Operator . . . . . . 598

From Operator to Nonoperator . . . . . . 5

No Changes to 1995 Operator Status . . . 63,446

Operators. . . . . . . . . . . . . . . . . . . . . . . 22,113

Nonoperators. . . . . . . . . . . . . . . . . . . . 41,333

Additions to 1995 Operator Framea . . . . 123

Operator . . . . . . . . . . . . . . . . . . . . . . . 122

Nonoperator. . . . . . . . . . . . . . . . . . . . . 1

Total 1996 Operator Frame. . . . . . . . . . . . 64,172

Operators. . . . . . . . . . . . . . . . . . . . . . . 23,410

Nonoperators. . . . . . . . . . . . . . . . . . . . 40,762

aRelatively few changes were made as frames maintenance was

curtailed because only large operators were surveyed in 1996.

Note: Includes operator frame activity through December 27, 1996.

Source: Energy Information Administration, Office of Oil and Gas.
Form EIA-64A

Reporting Requirements

Form EIA-64A consisted of the reporting schedule

shown in Figure I4, 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 1996,

the Form EIA-64A National estimates were 2.9 percent

(19 million barrels) higher than the Petroleum Supply

Annual 1996 volume for natural gas plant liquids

production.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 97

W ellhead

Lease or Field

Separation

Facilities

Natural Gas

Processing Plant

Lease Condensate

Storage

W et Gas after

Separation

D ry Gas

Plant Liquids

Production

Lease Condensate

Production

TOTAL NATURAL GAS

LIQUIDS PRODUCTIO N

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 1996 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 16, 1996.

Energy Information Administration

98 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table E4. Natural Gas Processed and Liquids Extracted at Natural Gas Processing Plants, 1996

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 . . . . . . . . . . . . . . 2,987,364 0 2,987,364 33,346

Lower 48 States . . . . . . 14,112,574 370,721 14,483,295 655,968

Alabama . . . . . . . . . . . . 111,656 1,212 112,868 4,009

Arkansas . . . . . . . . . . . . 214,868 4,609 219,477 383

California . . . . . . . . . . . . 240,566 0 240,566 9,798

Colorado . . . . . . . . . . . . 493,748 215 493,963 16,735

Florida . . . . . . . . . . . . . . 5,900 2,614 8,514 1,630

Kansas. . . . . . . . . . . . . . 825,825 144,338 970,163 35,285

Kentucky . . . . . . . . . . . . 44,151 1,864 46,015 1,692

Louisiana . . . . . . . . . . . . 4,496,445 156,232 4,652,677 101,716

Michigan . . . . . . . . . . . . 117,119 0 117,119 4,810

Mississippi . . . . . . . . . . . 4,521 0 4,521 254

Montana. . . . . . . . . . . . . 10,106 35 10,141 431

North Dakota . . . . . . . . . 47,942 0 47,942 3,860

New Mexico. . . . . . . . . . 1,129,523 75 1,129,598 75,476

Oklahoma . . . . . . . . . . . 1,052,170 1,953 1,054,123 70,165

Texas. . . . . . . . . . . . . . . 4,139,267 40,795 4,180,062 279,650

Utah. . . . . . . . . . . . . . . . 252,781 12,765 265,546 9,547

West Virginia . . . . . . . . . 70,552 157 70,709 4,849

Wyoming . . . . . . . . . . . . 844,009 1,244 845,253 35,093

Miscellaneous* . . . . . . . 11,425 2,613 14,038 585

Total . . . . . . . . . . . . . . . 17,099,938 370,721 17,470,659 689,314

aIncludes Illinois, Nebraska, Ohio, Pennsylvania, and Tennessee.

Source: Form EIA–64A, “Annual Report of the Origin of Natural Gas Liquids Production,” 1996.

Table E5. Summary of the 1996 Plant Frame

Activity, Form EIA-64A

Frame as of 1995 survey mailing . . . . . . . . . . 759

Additions . . . . . . . . . . . . . . . . . . . . . . 131

Deletions . . . . . . . . . . . . . . . . . . . . . . –180

Frame as of 1996 survey mailing . . . . . . . . . . 710

Note: Includes operator frame activity through December 16, 1996.

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

extensive frame maintenance activities each year to

identify all current operators of crude oil and natural

gas wells in the country. This was not done for small

operators in 1996 because a reduced survey was carried

out (see Procedural Change section below).

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

each year since 1977, except for 1996. 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.

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 1995.

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

1995.

n Category III – Small Operators: Operators who

produced less than the Category II operators in

1995.

State/subdivision volume estimates are calculated as

the sum of the certainty strata (Category I and Category

II) and in 1996, all modeled Category III volumes in that

region. An expected error was calculated for each

State/subdivision.

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. An expected

error was 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 modeled

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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 101
Vsc = total volume in the State/subdivision

reported by Certainty operators

V$

sr = modeled total volume in the

State/subdivision for Category III

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 = volume reported by the m–th certainty

stratum operator in the State/subdivision.

Procedural Change

Required by Budget Reduction

This year, as in all past years, EIA’s objective was to

estimate the total proved reserves of the United States

within 1 percent error or less. In the past this was done

by EIA’s standard procedure: surveying all major

(Category I and Category II) operators by field, any

Category III operators large enough to be selected with

certainty, plus an 8 percent random sample of the

considerably more numerous smaller Category III

operators by State or State subdivision. EIA then

statistically estimated and imputed the nonreported

reserves by State and State subdivision. A budget

reduction imposed in 1995 did not allow continued use

of this procedure in 1996.

To maintain its practice of producing annual reserves

estimates and retain its accuracy objective, EIA decided

that the sample of the Category III operators could only

be processed every other year. This in turn required

that a sufficiently accurate estimate would have to be

made of all Category III reserves every two years

starting with report year 1996. The following

paragraphs will describe the model used to make the

estimate in report year 1996.

The New Statistical Model

Used To Estimate All Category III

Year-End 1996 Reserves

Relying on EIA’s accumulated knowledge of the

characteristics of Category III operators’ reserves, it

was believed that a one-year-beyond-history estimate

of the Category III proved reserves could be modeled,

based on the historical reserves estimates for the States

and State subdivisions and correlative current and

historical oil and gas price data. The model estimate

could then be added to the Category I and Category II

operators’ data (collected as usual on Form EIA-23), to

get an estimate of the total proved reserves of the

United States. The model had to be designed so that the

total estimate of proved reserves met EIA’s current

quality standards.

The starting point for development of the new

Category III estimation methodology was EIA’s

19-year data base of detailed reserves data and oil and

gas price data. It was recognized that the statistical

model had to honor the fundamental causes of reserves

change:

n drilling and development activity add new

proved reserves;

n operators revise their reserves due to new

information or economics and prices;

n production reduces the reserves level.

Last, since each State and State subdivision behaves

somewhat differently from the others, an individual

model for each of them had to be generated, with the

combined results yielding the estimated volume of

Category III reserves for the United States.

Several “trial” models were created, all of which were

founded on the following knowledge about Category

III reserves and their behavior:

n In the absence of major inter-year economic

changes, Category III reserves do not change

drastically from year to year. However, they

often exhibit a downward or upward trend.

Consequently, a one-year-extended

least-squares estimate (time series trend) based

solely on the history of Category III reserves

levels for a specific State or State subdivision

should be accurate within plus or minus 10 to 15

percent.

n The primary predictable cause of departure of

Category III reserves levels from the established

time-series trend is economics, i.e., the reserves

level reacts to changes in the prices of oil and

gas (see Economics section below). Thus, an

estimation methodology modified to account

for changes in oil and gas prices would be more

accurate than one based solely on a time series

trend.

Energy Information Administration

102 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
n There are limits to the effect on reserve levels

that a given price change can produce in one

year’s time.

The trial models were then tested against the historic

Category III proved reserves and price data in order to

select the best one. The statistical model selected for use

in preparing the 1996 report was:

( )

( )

$ $ , , ,, /

,, ,

V V

ARRC

A SP HP

BP P

st st

s

st st s

st st st

3 3 1

1

= +

+ −

-

- /SPs t, - é

ëê ùûú





















1

where

$V3s t, = estimated volume of the Category III

reserves of State or State subdivision s in

t, the estimation year

$V3s t, - 1= estimate of Category III reserves of area

s in the year prior to the estimation year

ARRCs= a constant reflecting the average annual

rate of reserves change for State or State

subdivison s

As, Bs = coefficients related to effects of price

change on the reserves for State or State

subdivision s, with A ≥ 0 and 0.1 ≥ B ≥

0.3 (see below for more information)

Ps,t = annual average oil or gas price in State

or State subdivision s in year t

HPs = annual average oil or gas price in State

or State subdivision s over the entire

history

SPs,t = (Pricet / 2)+(Pricet-1 / 2), i.e., the 2-year

average annual oil or gas price for State

or State subdivision s in year t

SPs,t-1 = (Pricet-1 / 2)+(Pricet-2 / 2), i.e., the

previous year’s 2-year average annual oil

or gas price for State or State subdivision

s.

The coefficients of this equation (i.e., ARRCs, As, Bs,

V$ 3s 0) were simultaneously solved for such that the sum

of the squared differences between the estimated

quantities and the observed reserves levels was

minimized. The algorithm was allowed to choose its

own initial reserves volume,V$ 3s 0, which was solved for

along with the coefficients.

Explanation of the Economic Terms

The purpose of the term containing coefficient As is to

capture the effect of “boom or bust” in drilling activity.

EIA’s data indicated that when the price of oil or gas

was significantly higher than the average historical

price in an area, exploration and development activity

often increased in that region - adding more proved

reserves. Likewise, when the price declined

significantly below the historical average price of an

area, reserves declined because drilling activity

decreased and less reserves were added and/or fewer

infill wells were drilled, less well stimulation work was

performed, or less application of enhanced recovery

methods occurred, reducing both production and

proved reserves.

The purpose of the term containing coefficient Bs is to

capture the effect of changes in price on annual

revisions. Price changes can alter economic limit

production rates which, in the case of lower prices, will

cause some wells to be shut-in or abandoned. Since

prices are more volatile than reserves levels, coefficient

Bs was constrained to fall in a range of 0.1 to 0.3.

Results Analysis: Expected Error

To evaluate the accuracy of the selected statistical

model in 1996, the model was applied separately to the

five preceding years, 1991 through 1995, and the

difference between the model estimate and the historic

reserves was determined. Only the historical data

through 1990 was used to redetermine the model

coefficients in order to estimate the reserves in 1991, up

to 1991 historic data to estimate 1992, and so on.

The expected error in 1996 was the determined by taking

the average of the absolute percentage difference

between the model estimates and the published proved

reserves value for the five year period, 1991-1995. The

percentage error in the years 1991 through 1995 are

shown in Table F1. These errors, and the expected error

in 1996, all met EIA’s estimation accuracy objective.

Figure F1 and Figure F2 show the difference between

the model estimates and the historical U.S. proved

reserves level for crude oil and wet natural gas,

respectively. The expected error in 1996 is shown by

State/subdivision in Table F2 and Table F3.

Production Estimates

Production was estimated at the State/Subdivision

level for Category III operators using a model with the

same functional form as for Category III reserves

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 103
Energy Information Administration

104 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Crude Oil (Million Barrels)

Lower 48 Onshore Lower 48 Onshore Percent Change in Percent Error Percent Error

U.S. Crude Oil Category III Reserves Category III Reserves Difference Category III Model vs. Historical Model vs. Historical

Year Reserves Historical Model Estimate Model-Historical from Prior Year Category III Reserves U.S. Crude Oil Reserves

1990 26,254 1,914.98 -- -- -- -- --

1991 24,682 1,823.13 1,938.16 115.03 -4.80% 6.31% 0.47%

1992 23,745 1,789.22 1,783.68 -5.54 -1.86% -0.31% -0.02%

1993 22,957 1,680.21 1,664.61 -15.60 -6.09% -0.93% -0.07%

1994 22,457 1,594.48 1,586.10 -8.38 -5.10% -0.53% -0.04%

1995 22,351 1,515.93 1,582.58 66.65 -4.93% 4.40% 0.30%

1996 22,017 -- 1,589.27 -- -- -- --

Average Absolute Percentage Change in Reserves Per Year 4.56%

1996 Expected Error* * -- average of absolute value of errors of 5 previous years 2.49% 0.18%

Wet Natural Gas (Billion Cubic Feet)

Lower 48 Onshore Lower 48 Onshore Percent Change in Percent Error Percent Error

U.S. Wet Gas Category III Reserves Category III Reserves Difference Category III Model vs. Historical Model vs. Historical

Year Reserves Historical Model Estimate Model-Historical from Prior Year Category III Reserves U.S. Wet Gas Reserves

1990 177,576 12,422 -- -- -- -- --

1991 175,325 12,055 12,494 439 -2.95% 3.64% 0.25%

1992 173,309 11,078 12,624 1,546 -8.10% 13.96% 0.89%

1993 170,490 10,150 11,755 1,605 -8.38% 15.81% 0.94%

1994 171,939 10,400 9,969 -431 2.46% -4.14% -0.25%

1995 173,476 9,333 9,346 13 -10.26% 0.14% 0.01%

1996 175,147 -- 10,035 -- -- -- --

Average Absolute Percentage Change in Reserves Per Year 6.43%

1996 Expected Error* * -- average of absolute value of errors of 5 previous years 7.54% 0.47%

Table F1. Error Statistics for the Category III Reserves Model

Figure F1. Modeled vs. Published U.S. Crude Oil

Proved Reserves, 1991-1995.

Figure F2. Modeled vs. Published U.S. Wet Natural

Gas Proved Reserves, 1991-1995.

0

5

10

15

20

25

30

1990 1991 1992 1993 1994 1995 1996

Billions of Barrels

Crude Oil Reserves

Oil Model Estimates

0

25

50

75

100

125

150

175

200

225

1990 1991 1992 1993 1994 1995 1996

Trillion Cubic Feet

Wet Natural Gas Reserves

Gas Model Estimates
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 105

Table F3. Expected Errors for Natural Gas Proved Reserves and Production, Wet After Lease Separation,

1996 (Billion Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

1996 1996

State and Subdivision Reserves State and Subdivision Reserves

United States . . . . . . . . . . . . . . . . . . 807

Alabama. . . . . . . . . . . . . . . . . . . . . . 337

Alaska . . . . . . . . . . . . . . . . . . . . . . . 0

Arkansas . . . . . . . . . . . . . . . . . . . . . 35

California . . . . . . . . . . . . . . . . . . . . . 50

Coastal Region Onshore. . . . . . . 16

Los Angeles Basin Onshore . . . . 5

San Joaquin Basin Onshore . . . . 42

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

Colorado . . . . . . . . . . . . . . . . . . . . . 276

Florida . . . . . . . . . . . . . . . . . . . . . . . 1

Kansas. . . . . . . . . . . . . . . . . . . . . . . 107

Kentucky . . . . . . . . . . . . . . . . . . . . . 161

Louisiana . . . . . . . . . . . . . . . . . . . . . 157

North . . . . . . . . . . . . . . . . . . . . . . 43

South Onshore . . . . . . . . . . . . . . 129

State Offshore. . . . . . . . . . . . . . . 28

Michigan . . . . . . . . . . . . . . . . . . . . . 79

Mississippi . . . . . . . . . . . . . . . . . . . . 38

Montana. . . . . . . . . . . . . . . . . . . . . . 56

New Mexico . . . . . . . . . . . . . . . . . . . 90

East. . . . . . . . . . . . . . . . . . . . . . . 51

West . . . . . . . . . . . . . . . . . . . . . . 42

New York . . . . . . . . . . . . . . . . . . . . . 27

North Dakota . . . . . . . . . . . . . . . . . . 19

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . 60

Oklahoma . . . . . . . . . . . . . . . . . . . . 297

Pennsylvania . . . . . . . . . . . . . . . . . . 75

Texas. . . . . . . . . . . . . . . . . . . . . . . . 260

RRC District 1 . . . . . . . . . . . . . . . 83

RRC District 2 Onshore . . . . . . . 54

RRC District 3 Onshore . . . . . . . 138

RRC District 4 Onshore . . . . . . . 85

RRC District 5 . . . . . . . . . . . . . . . 28

RRC District 6 . . . . . . . . . . . . . . . 88

RRC District 7B. . . . . . . . . . . . . . 60

RRC District 7C. . . . . . . . . . . . . . 72

RRC District 8 . . . . . . . . . . . . . . . 58

RRC District 8A. . . . . . . . . . . . . . 23

RRC District 9 . . . . . . . . . . . . . . . 26

RRC District 10 . . . . . . . . . . . . . . 112

State Offshore. . . . . . . . . . . . . . . 13

Utah . . . . . . . . . . . . . . . . . . . . . . . . . 35

Virginia. . . . . . . . . . . . . . . . . . . . . . . 6

West Virginia . . . . . . . . . . . . . . . . . . 93

Wyoming . . . . . . . . . . . . . . . . . . . . . 70

Federal Offshorea . . . . . . . . . . . . . . 0

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

Gulf of Mexico (Louisiana)a . . . . 0

Gulf of Mexico (Texas) . . . . . . . . 0

Miscellaneousb . . . . . . . . . . . . . . . . 3

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

Notes: The expected errors are associated with Table 9 reserves estimates. Expected error for each State/subdivision and the United

States are independently estimated and do not add.

Source: EIA modeled Category III reserves estimates.

Table F2. Expected Errors for Crude Oil Proved Reserves and Production, 1996

(Million Barrels of 42 U.S. Gallons)

1996 1996

State and Subdivision Reserves State and Subdivision Reserves

United States . . . . . . . . . . . . . . . . . . 42

Alabama. . . . . . . . . . . . . . . . . . . . . . 3

Alaska . . . . . . . . . . . . . . . . . . . . . . . 0

Arkansas . . . . . . . . . . . . . . . . . . . . . 7

California . . . . . . . . . . . . . . . . . . . . . 20

Coastal Region Onshore. . . . . . . 7

Los Angeles Basin Onshore . . . . 11

San Joaquin Basin Onshore . . . . 11

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

Colorado . . . . . . . . . . . . . . . . . . . . . 13

Florida . . . . . . . . . . . . . . . . . . . . . . . 1

Illinois. . . . . . . . . . . . . . . . . . . . . . . . 10

Indiana. . . . . . . . . . . . . . . . . . . . . . . 2

Kansas. . . . . . . . . . . . . . . . . . . . . . . 13

Kentucky . . . . . . . . . . . . . . . . . . . . . 2

Louisiana . . . . . . . . . . . . . . . . . . . . . 10

North . . . . . . . . . . . . . . . . . . . . . . 4

South Onshore . . . . . . . . . . . . . . 7

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

Michigan . . . . . . . . . . . . . . . . . . . . . 9

Mississippi . . . . . . . . . . . . . . . . . . . . 8

Montana. . . . . . . . . . . . . . . . . . . . . . 6

Nebraska . . . . . . . . . . . . . . . . . . . . . 3

New Mexico . . . . . . . . . . . . . . . . . . . 11

East. . . . . . . . . . . . . . . . . . . . . . . 7

West . . . . . . . . . . . . . . . . . . . . . . 6

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

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . 10

Oklahoma . . . . . . . . . . . . . . . . . . . . 18

Pennsylvania . . . . . . . . . . . . . . . . . . 2

Texas. . . . . . . . . . . . . . . . . . . . . . . . 30

RRC District 1 . . . . . . . . . . . . . . . 7

RRC District 2 Onshore . . . . . . . 4

RRC District 3 Onshore . . . . . . . 25

RRC District 4 Onshore . . . . . . . 6

RRC District 5 . . . . . . . . . . . . . . . 2

RRC District 6 . . . . . . . . . . . . . . . 11

RRC District 7B. . . . . . . . . . . . . . 14

RRC District 7C. . . . . . . . . . . . . . 11

RRC District 8 . . . . . . . . . . . . . . . 5

RRC District 8A. . . . . . . . . . . . . . 10

RRC District 9 . . . . . . . . . . . . . . . 10

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

State Offshore. . . . . . . . . . . . . . . 1

Utah . . . . . . . . . . . . . . . . . . . . . . . . 5

West Virginia . . . . . . . . . . . . . . . . . . 2

Wyoming . . . . . . . . . . . . . . . . . . . . . 6

Federal Offshore . . . . . . . . . . . . . . . 0

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

Gulf of Mexico (Louisiana) . . . . . 0

Gulf of Mexico (Texas) . . . . . . . . 0

Miscellaneousa . . . . . . . . . . . . . . . . 6

aIncludes Arizona, Missouri, Nevada, New York, South Dakota, Tennessee, and Virginia.

Notes: The expected errors are associated with Table 6 reserves estimates. Expected error for each State/subdivision and the United

States are independently estimated and do not add.

Source: EIA modeled Category III reserves estimates.
estimates. A least squares fit with historical production

data was used to determine the appropriate

coefficients.

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 intermediate operators and modeled Category III

volumes 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 modeled Category III

volumes to estimate their volumes of

associated–dissolved and nonassociated natural gas. A

final adjustment 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 1996 are

summarized in Tables F4, F5, F6 and F7. The

differences between these sums and the total estimates

shown in Tables 9, 10, 6 and 16 in the main text

represent the aggregate result of statistical estimation

and imputation performed by EIA. The modeled

reserves data in Table F4 accounted for 6.5 percent of

the published production for natural gas shown in

Table 9 and 5.8 percent of the reserves. Data shown in

Table F5 indicate that the modeled operators

accounted for 6.3 percent of the nonassociated natural

gas production and 5.8 percent of the reserves

published in Table 10. The reported data shown in

Table F6 indicate that the modeled operators

accounted for 11 percent of published crude oil

production and 7.2 percent of the reserves shown in

Table 6. Additionally, Table F7 indicates that the

modeled operators accounted for 3.1 percent of the

published production and 2.5 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.

A year–end proved reserves estimate was imputed in

each case where an estimate was not provided by the

respondent. The reported annual production was

multiplied by a reserves–to–production (R/P) ratio

(Table F8) 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 modeled Category III

operator reserves by the modeled Category III

production.

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 F3). These units

generally follow the boundaries of geologic provinces

wherein the stage of resource development tends to be

somewhat similar. Table F8 lists the R/P ratio

calculated for each region.

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.

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:

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106 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 107

Table F4. Summary of Total Natural Gas, Wet After Lease Separation, Used in Estimation Process,

Form EIA-23, 1996 (Million Cubic Feet at 14.73 psia and 60° Fahrenheit)

Operator Category

Data Detail I II Modeled Total

Field Level Reported and Imputed Data

Proved Reserves as of 12/31/95 . . . . . . . . . . . . . . . . . . . 149,398,437 13,283,835 – 162,682,272

(+) Revision Increases. . . . . . . . . . . . . . . . . . . . . . . . . . 14,256,280 1,929,050 – 16,185,330

(–) Revision Decreases . . . . . . . . . . . . . . . . . . . . . . . . . 11,266,713 1,240,463 – 12,507,176

(+)Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,893,696 551,934 – 7,445,630

(+) New Field Discoveries . . . . . . . . . . . . . . . . . . . . . . . 1,230,150 158,396 – 1,388,546

(+) New Reservoirs in Old Fields. . . . . . . . . . . . . . . . . . 2,332,927 642,667 – 2,975,594

(–) Production in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . 16,364,448 1,553,801 – 17,918,249

Proved Reserves as of 12/31/96 . . . . . . . . . . . . . . . . . . . 146,480,700 13,771,630 – 160,252,330

Production Reported Without Proved Reserves . . . . . . . 16,588 574,360 – 590,948

Reserves Imputed for Production

Reported Without Proved Reservesa . . . . . . . . . . . . . . 120,346 4,609,357 – 4,729,703

State Level Modeled Data

Production in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – 1,277,992 1,277,992

Proved Reserves as of 12/31/96 . . . . . . . . . . . . . . . . . . . – – 10,165,837 10,165,837

Total Production in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . 16,381,036 2,128,161 1,277,992 19,787,189

Total Proved Reserves as of 12/31/96b . . . . . . . . . . . . . . 146,601,046 18,380,987 10,165,837 175,147,870

aImputed using regional R/P factors (Table F6). bMay not equal Table 9 totals (production = 19,783 billion cubic feet; reserves = 175,147 billion cubic feet) that are the sum of data

independently rounded at the State/subdivision level.

– = Not applicable.

Note: Field level data are reported volumes and may not balance due to submission of incomplete records.

Source: Based on data filed on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves”.

Table F5. Summary of Nonassociated Natural Gas, Wet After Lease Separation, Used in Estimation

Process, Form EIA-23, 1996 (Million Cubic Feet at 14.73 psia and 60° Fahrenheit)

Operator Category

Data Detail I II Modeled Total

Field Level Reported and Imputed Data

Proved Reserves as of 12/31/95 . . . . . . . . . . . . . . . . . . . 122,675,828 11,511,727 – 134,187,555

(+) Revision Increases. . . . . . . . . . . . . . . . . . . . . . . . . . 11,691,533 1,618,765 – 13,310,298

(–) Revision Decreases . . . . . . . . . . . . . . . . . . . . . . . . . 9,614,529 1,058,456 – 10,672,985

(+)Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,047,928 513,998 – 6,561,926

(+) New Field Discoveries . . . . . . . . . . . . . . . . . . . . . . . 1,062,486 106,884 – 1,169,370

(+) New Reservoirs in Old Fields. . . . . . . . . . . . . . . . . . 2,032,911 615,554 – 2,648,465

(–) Production in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . 13,963,536 1,323,225 – 15,286,761

Proved Reserves as of 12/31/96 . . . . . . . . . . . . . . . . . . . 119,932,616 11,985,262 – 131,917,878

Production Reported Without Proved Reserves . . . . . . . 11,879 495,584 – 507,463

Reserves Imputed for Production

Reported Without Proved Reservesa . . . . . . . . . . . . . . 86,717 4,005,771 – 4,092,488

State Level Modeled Data

Production in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – 1,054,343 1,054,343

Proved Reserves as of 12/31/96 . . . . . . . . . . . . . . . . . . . – – 8,342,351 8,342,351

Total Production in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . 13,975,415 1,818,809 1,054,343 16,848,567

Total Proved Reserves as of 12/31/96b . . . . . . . . . . . . . . 120,019,333 15,991,033 8,342,351 144,352,717

aImputed using regional R/P factors (Table F6). bMay not equal Table 10 totals (production = 16,845 billion cubic feet; reserves = 144,352 billion cubic feet) that are the sum of data

independently rounded at the State/subdivision level.

– = Not applicable.

Note: Field level data are reported volumes and may not balance due to submission of incomplete records.

Source: Based on data filed on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves”.
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108 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Table F6. Summary of Crude Oil Used in Estimation Process, Form EIA-23, 1996

(Thousand Barrels of 42 U.S. Gallons)

Operator Category

Data Detail I II Modeled Total

Field Level Reported and Imputed Data

Proved Reserves as of 12/31/95 . . . . . . . . . . . . . . . . . . . 19,724,009 864,466 – 20,588,475

(+) Revision Increases. . . . . . . . . . . . . . . . . . . . . . . . . . 1,355,970 135,231 – 1,491,201

(–) Revision Decreases . . . . . . . . . . . . . . . . . . . . . . . . . 753,168 83,597 – 836,765

(+)Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 450,546 23,978 – 474,524

(+) New Field Discoveries . . . . . . . . . . . . . . . . . . . . . . . 195,843 42,971 – 238,814

(+) New Reservoirs in Old Fields. . . . . . . . . . . . . . . . . . 123,978 9,992 – 133,970

(–) Production in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . 1,790,229 107,863 – 1,898,092

Proved Reserves as of 12/31/96 . . . . . . . . . . . . . . . . . . . 19,306,935 885,196 – 20,192,131

Production Reported Without Proved Reserves . . . . . . . 701 35,202 – 35,903

Reserves Imputed for Production

Reported Without Proved Reservesa . . . . . . . . . . . . . . 4,664 226,490 – 231,154

State Level Modeled Data

Production in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – 239,834 239,834

Proved Reserves as of 12/31/96 . . . . . . . . . . . . . . . . . . . – – 1,589,268 1,589,268

Total Production in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . 1,790,930 143,065 239,834 2,173,829

Total Proved Reserves as of 12/31/96b . . . . . . . . . . . . . . 19,311,599 1,111,686 1,589,268 22,012,553

aImputed using regional R/P factors (Table F6). bMay not equal Table 6 totals (production = 2,173 million barrels; reserves = 22,017 million barrels) that are the sum of data independently

rounded at the State/subdivision level.

– = Not applicable.

Note: Field level data are reported volumes and may not balance due to submission of incomplete records.

Source: Based on data filed on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves”.

Table F7. Summary of Lease Condensate Used in Estimation Process, Form EIA-23, 1996

(Thousand Barrels of 42 U.S. Gallons)

Operator Category

Data Detail I II Modeled Total

Field Level Reported and Imputed Data

Proved Reserves as of 12/31/95 . . . . . . . . . . . . . . . . . . . 1,069,246 91,068 – 1,160,314

(+) Revision Increases. . . . . . . . . . . . . . . . . . . . . . . . . . 162,785 19,347 – 182,132

(–) Revision Decreases . . . . . . . . . . . . . . . . . . . . . . . . . 127,915 13,896 – 141,811

(+)Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135,825 4,721 – 140,546

(+) New Field Discoveries . . . . . . . . . . . . . . . . . . . . . . . 24,671 4,607 – 29,278

(+) New Reservoirs in Old Fields. . . . . . . . . . . . . . . . . . 31,032 4,967 – 35,999

(–) Production in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . 140,061 13,481 – 153,542

Proved Reserves as of 12/31/96 . . . . . . . . . . . . . . . . . . . 1,155,572 97,322 – 1,252,894

Production Reported Without Proved Reserves . . . . . . . 75 3,692 – 3,767

Reserves Imputed for Production

Reported Without Proved Reservesa . . . . . . . . . . . . . . 480 23,814 – 24,294

State Level Modeled Data

Production in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . – – 5,046 5,046

Proved Reserves as of 12/31/96 . . . . . . . . . . . . . . . . . . . – – 32,680 32,680

Total Production in 1996 . . . . . . . . . . . . . . . . . . . . . . . . . 140,136 17,173 5,046 162,355

Total Proved Reserves as of 12/31/96b . . . . . . . . . . . . . . 1,156,052 121,136 32,680 1,309,868

aImputed using regional R/P factors (Table F6). bMay not equal Table 16 totals (production = 162 million barrels; reserves = 1,307 million barrels) that are the sum of data independently

rounded at the State/subdivision level.

– = Not applicable.

Note: Field level data are reported volumes and may not balance due to submission of incomplete records.

Source: Based on data filed on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves”.
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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 109

Table F8. Reserve to Production Ratios by Region for 1996

Number Region Oil Gas Lease Condensate

2 Pacific Coast States . . . . . . . . . . . . . . . . 6.7 5.1 a6.5

3 Western Rocky Mountains . . . . . . . . . . . . . 5.8 12.7 a6.6

4 Northern Rocky Mountains . . . . . . . . . . . . . 7.0 6.1 a6.6

5 West Texas and East New Mexico . . . . . . . . . 7.1 7.9 a6.6

6 + 6A Western Gulf Basin and Gulf of Mexico . . . . . . . 6.5 7.3 6.4

7 Mid–Continent . . . . . . . . . . . . . . . . . . 6.2 6.6 6.9

8 + 9 Michigan Basin and Eastern Interior . . . . . . . . 6.3 8.5 a6.5

10 + 11 Appalachians ................... a6.6 11.7 a6.5

United States . . . . . . . . . . . . . . . . . . . 6.6 7.9 6.5

aMultiplier of the U.S. national average is used. Effect of the multiplier on the related natural gas or lease condensate reserves estimate is

negligible in these regions.

Source: Multipliers calculated from modeled Category III proved reserves and production based on data filed on Form EIA–23,"Annual

Survey of Domestic Oil and Gas Reserves".

Figure F3. Form EIA-23 Regional Boundaries
A ratio was calculated as the sum of the annual

production and year–end proved reserves of those

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 modeled for Category III operators. These were

then added to the State/subdivision totals.

Imputation of Natural Gas Type Volumes

Category III modeled volumes were not estimated 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 modeled Category III operators 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 historical

reasons that adjustments are necessary is that very few

of the same Noncertainty operators are sampled each

year and the characteristic R/P ratios change each year.

Less than 8 percent of the Noncertainty stratum

operators sampled in 1994 were sampled again in 1995,

and there was no guarantee that in the smaller

producing States/subdivision the same number of

small operators would be selected each year, or that the

operators selected would 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 to the U.S.

total.

Some of the adjustments were, 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

one year than in the previous year.

n One or more operators may have reported data

incorrectly on Schedule A in the prior year or

the current year, but not both, and the error was

not detected by edit processing.

n Operation of properties was transferred during

the survey year 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 the survey year to an operator with a

different evaluation of the proved reserves

associated with the properties than that of the

prior year’s 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.

Energy Information Administration

110 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

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

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
n A large net movement of prior year Category II

operators into Category III operator class

occurs.

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.

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 Reserves and

Production Division 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.

Frame Coverage Errors

Of all the sources of controllable error connected with

the Form EIA–23 survey, errors in the operator frame

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 1995 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. Yearly errors

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 111
resulting from lack of good frame coverage will impact

the overall reliability of the modeled reserves

estimates.

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

imputed in this manner. Based on the 1996 Form

EIA–64A survey, the national weighted average gas

equivalents ratio was computed to be 1,398 cubic feet of

natural gas shrinkage per barrel of NGL recovered, the

same as that in the 1995 survey. 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.

Energy Information Administration

112 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
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.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 113
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 1996 Annual Report 117

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 1996 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 59 times the 1996 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

118 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 119

Table G1. Estimated Oil and Gas Reserves and Mean Estimates of Technically Recoverable

Oil and Gas Resources

Natural Gas

Crude Oila Natural Gas (Wet) Liquids

Categories (million barrels) (billion cubic feet) (million barrels)

Lower 48 States

Discovered

Proved Reserves (EIA, 1996) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16,743 b165,851 7,486

Reserve Growth - conventional, onshorec (USGS, 1991) . . . . . . . . . d47,000 290,000 12,900

Reserve Growth - conventional, Federal Offshore (MMS, 1994). . . . e2,200 e32,700 NE

Unproved Reserves, Federal Offshore (MMS, 1994) . . . . . . . . . . . . . 1,500 5,500 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112,619 1,184,421 NA

Alaska

Discovered

Proved Reserves (EIA, 1996) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,274 9,296 337

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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51,414 236,306 NA

Total Lower 48 States and Alaska. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164,033 1,420,727 32,342

Deductions for Production and Proved Reserves Changes,

1991-1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -7,632 -79,898 -4,008

U.S. Total, 1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156,401 1,340,829 28,334

a Condensate is included with crude oil for MMS estimates in Federal Offshore regions.

b Includes 10,566 billion cubic feet of coalbed methane (EIA, 1996).

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.

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 Onshore 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.{35} They are similarly defined by the MMS,

although its system also subdivides them by degree of

development and producing status.{36} 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.{35}

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.

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

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.

Energy Information Administration

120 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
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

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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 121

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 be-
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

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

122 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report
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

126 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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 1996 Annual Report 127

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

128 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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 1996 Annual Report 129

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
Figure I1. Form EIA–23, Cover Page

Source: Energy Information Administration, Office of OIl and Gas.
OFFICIAL USE ONLY 1996 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 12/97

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 96

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, 1995

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, 1996

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, 1995

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, 1996

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, 1995

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, 1996

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, 1995

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, 1996

NONPRODUCING

(i) RESERVES

12. CRUDE OIL (Mbbl)13. ASSOCIATED-DISSOLVED GAS(MMcf)14. NONASSOCIATED GAS (MMcf)15. LEASE CONDENSATE (Mbbl)

Figure I2. Form EIA–23, Summary Report — Page 1

Source: Energy Information Administration, Office of Oil and Gas.
OFFICIAL USE ONLY 1996 ANNUAL SURVEY OF DOMESTIC OIL AND GAS RESERVES SCHEDULE B - FOOTNOTES Form Approved OMB No. 1905-0057 Expires 12/97

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 96

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

Figure I3. Form EIA–23, Summary Report — Page 2

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

138 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report

Figure I6. Form EIA-64A

EIA-64A (Revised 9/91)

OFFICIAL USE

ONLY 1996 Energy Information AdministrationU.S. DEPARTMENT OF ENERGY

Calendar Year 1996

Form Approved

OMB No. 1905-0057

Expires 12/97

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.
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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 141

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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142 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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 1996 Annual Report 143
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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144 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 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.

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)

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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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1996 Annual Report 145