DOE/EIA–0216(98)

Distribution Category UC–950

U.S. Crude Oil, Natural Gas,

and Natural Gas Liquids Reserves

1998 Annual Report

December 1999

Energy Information Administration

Office of Oil and Gas

U.S. Department of Energy

Washington, DC 20585

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

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

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

of the Department of Energy or any other organization.
Preface

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

Liquids Reserves 1998 Annual Report is the 22nd

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, 1998, as well as production volumes

for the United States and selected States and State

subdivisions for the year 1998. 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 1998 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 1998; report

Table 1 converted to metric units; historical State

data; a summary of survey operations; a discussion

of statistical considerations; methods used to develop

the estimates provided in this report; maps of

selected State subdivisions; and examples of the

survey forms. A glossary of the terms used in this

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

provided to assist readers in more fully

understanding the data.

This annual reserves report was prepared by the

Reserves and Production Division (located in Dallas,

Texas), Office of Oil and Gas, Energy Information

Administration. General information regarding

preparation of the report may be obtained from

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

and John H. Wood, Director, Reserves and

Production Division (214.720.6160).

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

Rhonda S. Green. Technical contributions were made

by Rafi M. Zeinalpour and technical editing was

provided by David F. Morehouse.

Address questions on specific sections of the

publication to the following analyst/author:

 Executive Summary and Appendices F and G

John H. Wood

Phone: 214.720.6160

E–mail: jwood@eia.doe.gov

Fax: 214.720.6155

 Chapter 1, 2, 3, 4, 5

Steven G. Grape

Phone: 214.720.6174

E–mail: sgrape@eia.doe.gov

Fax: 214.720.6155

 Appendices A, B, C, D, E, H, and I

Rhonda S. Green

Phone: 214.720.6161

E–mail: rgreen@eia.doe.gov

Fax 214.720.6155

 Field-level Reserves Quality Assurance

Rafi M. Zeinalpour

Phone: 214.720.6191

E–mail: rzeinalp@eia.doe.gov

Fax 214.720.6155

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report iii
Energy Information Administration

iv U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Internet Site Services

Visit the Energy Information Administration web site: http://www.eia.doe.gov

The web site offers nearly all EIA publications. Users can view or download

selected pages or entire reports, search for information, download EIA data and

analysis applications, and find out about new EIA information products and

services.

EIA’s CD-ROM, Energy InfoDisc, contains most EIA publications and major

energy database applications. The Energy InfoDisc, produced quarterly, is

available for a fee from STAT-USA, Department of Commerce,

1-800-STAT-USA.

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 1998, DOE/EIA–0131(98), October 1999

Petroleum Supply Annual 19968, DOE/EIA–0340(98), June 1999

These annual reports provide comprehensive statistics on supply, disposition,

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

Natural Gas 1998: Issues and Trends, DOE/EIA–0560(98), August 1999

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: An Energy Profile, DOE/EIA–0545(99), July 1999

Explains in layman’s terms the major components and operations of the U.S.

Petroleum Industry.
Contents

Page

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Mergers and Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

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

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

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

International Perspective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

International Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

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

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

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

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

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

Gulf of Mexico Federal Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

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

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

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

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

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

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

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

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

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

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

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

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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report v
Page

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

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

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

Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

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

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

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

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

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

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

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

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

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

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

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

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

Gulf of Mexico Federal Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

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

Reserves in Nonproducing Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Lease Condensate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Reserves in Nonproducing Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

Appendices

A. Operator Data by Size Class . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

B. Top 100 Oil and Gas Fields for 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

C. Conversion to the Metric System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

D. Historical Reserves Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

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

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

G. Estimation of Reserves and Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123

H. Maps of Selected State Subdivisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

I. Annual Survey Forms for Domestic Oil and Gas Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . 143

Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151

Tables

1. U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids, 1988-1998 ............ 4

2. Reserves Changes, 1977-1998 ........................................... 9

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

Average Number of Active Rotary Drilling Rigs, 1970-1998 . . . . . . . . . . . . . . . . . . . . . . . . . . 10

4. U.S. Exploratory and Development Well Completions, 1970-1998 . . . . . . . . . . . . . . . . . . . . . . . . . 12

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vi U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
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5. International Oil and Natural Gas Reserves as of December 31, 1998 . . . . . . . . . . . . . . . . . . . . . . . 16

6. Crude Oil Proved Reserves, Reserves Changes, and Production, 1998 . . . . . . . . . . . . . . . . . . . . . . 20

7. Reported Indicated Additional Crude Oil Reserves, 1998. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 1998 . . . . . . . . . . . . . . . . . . 28

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

Wet After Lease Separation, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

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

Wet After Lease Separation, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

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

Wet After Lease Separation, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

12. U.S. Coalbed Methane Proved Reserves and Production, 1991-1998 . . . . . . . . . . . . . . . . . . . . . . . 35

13. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 1998 . . . . . . . . . . . . . . . . 38

14. Natural Gas Plant Liquids Proved Reserves and Production, 1998. . . . . . . . . . . . . . . . . . . . . . . . . 39

15. Lease Condensate Proved Reserves and Production, 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Figures

1. U.S. Crude Oil Proved Reserves, 1988-1998 .................................... 5

2. Components of Reserves Changes for Crude Oil, 1988-1998 ........................... 5

3. U.S. Dry Natural Gas Proved Reserves, 1988-1998 ................................ 6

4. Components of Reserves Changes for Dry Natural Gas, 1988-1998 ........................ 6

5. U.S. Natural Gas Liquids Proved Reserves, 1988-1998 .............................. 8

6. Components of Reserves Changes for Natural Gas Liquids, 1988-1998 ...................... 8

7. U.S. Exploratory Gas Well Completions, 1977-1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

8. U.S. Exploratory Oil Well Completions, 1977-1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

9. U.S. Total Discoveries of Dry Natural Gas per Exploratory Gas Well Completion, 1977-1998 . . . . . . . . . . . 13

10. U.S. Total Discoveries of Crude Oil per Exploratory Oil Well Completion, 1977-1998 . . . . . . . . . . . . . . . 13

11. Reserves-to-Production Ratios for Crude Oil, 1945-1998. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

12. Reserves-to-Production Ratios for Wet Natural Gas, 1945-1998 . . . . . . . . . . . . . . . . . . . . . . . . . . 15

13. Components of Ultimate Recovery for Crude Oil and Lease Condensate, 1977-1998 . . . . . . . . . . . . . . . 15

14. Components of Ultimate Recovery for Wet Natural Gas, 1977-1998 . . . . . . . . . . . . . . . . . . . . . . . . 15

15 Reserve Additions Replace Only 24 Percent of U.S. Oil Production in 1998 . . . . . . . . . . . . . . . . . . . . 19

16. 1998 Crude Oil Proved Reserves by Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

17. Changes in Crude Oil Proved Reserves by Area, 1997 to 1998 . . . . . . . . . . . . . . . . . . . . . . . . . . 21

18. Reserve Additions Replace Only 83 Percent of 1998 U.S. Dry Gas Production . . . . . . . . . . . . . . . . . . 27

19. 1998 Dry Natural Gas Proved Reserves by Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

20. Changes in Dry Natural Gas Proved Reserves by Area, 1997 to 1998 . . . . . . . . . . . . . . . . . . . . . . . 29

21. Coalbed Methane Proved Reserves, 1989-1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report vii
Executive Summary

It was a down year for U.S. proved reserves in 1998,

particularly crude oil reserves. U.S. proved reserves

of crude oil fell 7 percent in 1998, the largest

percentage decline in 53 years. Inflation adjusted

crude oil prices, which began a decline in 1997,

plunged by December 1998 to levels last seen in 1935.

Falling crude prices led to a drop of almost 60

percent in rigs drilling for oil during 1998, followed

by a decline in the number of new and producing oil

wells, which was followed by the drop in oil

reserves. Only 24 percent of 1998 oil production was

replaced by proved reserve additions.

U.S. dry natural gas reserves declined 2 percent in

1998. This decline broke a 4-year string of annual

increases, and offset two-thirds of the gain in the

prior 4 years. Natural gas reserve additions in 1998

replaced only 83 percent of gas production.

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 1998 U.S. proved

reserves of crude oil, natural gas, and natural gas

liquids is the 22nd in the annual series prepared by

the Energy Information Administration.

Crude Oil

Price matters. Crude oil reserve additions were less

than a fifth of those in 1997. Additions would have

been even smaller in the absence of a few large,

long-term development projects that were continued

by their operators in the face of low oil prices. Large

revisions associated with property acquisitions and

development in some of California’s old and heavy

oil fields helped that State’s reserves to increase.

Changes in proved reserves are impacted by price in

several ways. Low prices imply poor economics for

oil producers, and poor economics leads to low

drilling levels. Only twice in over 100 years have

fewer oil wells been drilled than in 1998.

The onshore lower 48 States is a mature exploration

and development area where, in the absence of

enough exploratory and development wells drilled, it

is next to impossible to add sufficient new fields,

new reservoirs, and positive revisions to replace

production. In the few less mature frontier areas not

subject to drilling moratoria, it is still possible to drill

very prolific wells that can be profitable even at

moderately low prices. But, in 1998, even offshore

and Alaskan North Slope projects were canceled or

delayed.

Use of the December 1998 oil prices to evaluate oil

field economics forced many companies to write

down proved reserves in some fields, even in the

offshore. The December 1998 price ($8.05 per barrel)

was much tougher on smaller and marginal oil well

operators as thousands of wells were shut in because

they could not meet their direct operating costs,

much less turn a profit. As a result, oil production

and proved reserves dropped sharply in most lower

48 States areas. Texas’ proved oil reserves fell 13

percent in 1998, which for the first time in a decade

placed Texas second to Alaska in oil reserves.

In a sharp reversal from several years of increases,

oil reserve additions dropped to less than a fifth of

those in 1997. Reserve additions are the sum of total

discoveries and revisions and adjustments. For crude oil,

revisions and adjustments are usually larger than total

discoveries, but they were a negative 120 million

barrels in 1998. This was the first time in 22 years

that revisions and adjustments did not make a positive

contribution to oil reserve additions.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report ix

As of December 31, 1998 proved reserves were:

Crude Oil (million barrels)

1997 22,546

1998 21,034

Decrease -6.7%

Dry Natural Gas (billion cubic feet)

1997 167,223

1998 164,041

Decrease -1.9%

Natural Gas Liquids (million barrels)

1997 7,973

1998 7,524

Decrease -5.6%
Total discoveries of crude oil were 599 million barrels

in 1998, well under the prior 10-year average and

less than half those of 1997. The Gulf of Mexico

Federal Offshore and Alaska accounted for over 50

percent of them. Total discoveries, which equaled only

30 percent of 1998 oil production, are those reserves

attributable to field extensions, new field discoveries,

and new reservoir discoveries in old fields. They result

from drilling exploratory wells.

 In a major reversal from 1997, new field discoveries

were only 152 million barrels, less than a quarter

of the 1997 level and well under the prior 10-year

average. Most of the new field discoveries were

in Alaska and the Gulf of Mexico Federal

Offshore. Over half of the proved reserves of oil

in the Gulf of Mexico are now located in deep

water (water depths greater than 200 meters.)

 New reservoir discoveries in old fields were 120

million barrels, about the same as in 1997 but less

than the prior 10-year average.

 Field extensions, down in 1998, added 327 million

barrels of proved oil reserves.

Other 1998 crude oil events of note:

 The annual average domestic first purchase price

for crude oil declined 37 percent for 1998 to

$10.88 per barrel.

 Exploratory oil completions were down about 30

percent at 303. Total oil well completions were

down 32 percent at 7,064.

 Total discoveries per exploratory oil well were

down 31 percent to an average of 1.98 million

barrels per new exploratory well in 1998.

Looking ahead to 1999 on a more positive note for oil

production and reserves:

 U.S. crude oil prices at the wellhead began

increasing in March 1999, reached $20 per barrel

in September, and continue to rise. But oil

drilling has not rebounded. Nevertheless, higher

oil prices in December 1999 will bring back some

of the oil reserves that became uneconomic in

1998.

Indicated additional reserves of crude oil decreased 1

percent to 3,160 million barrels in 1998. These are

crude oil volumes that may become economically

recoverable from known reservoirs through the

application of improved recovery techniques using

current technology. The presence of large indicated

additional reserves in north Alaska, California,

Texas, and Louisiana implies that significant upward

revisions to crude oil proved reserves can occur in

the future.

Natural Gas

The four-year increasing trend for U.S. natural gas

proved reserves came to an end in 1998. Lower 48

States dry natural gas reserves also declined about 2

percent from the 1997 level. Even the Gulf of Mexico

Federal Offshore proved reserves were down in

1998—dry gas reserves in the Gulf of Mexico Federal

Offshore declined 5 percent in 1998. The reserve

additions of natural gas were lower in 1998 because

total discoveries were lower. The other component,

revisions and adjustments (4,105 billion cubic feet) was

about the same as in 1997.

U.S. total discoveries of dry gas reserves were 11,433

billion cubic feet in 1998, down 27 percent from 1997.

 New field discoveries were 1,074 billion cubic feet,

less than half of the new field volume discovered

in 1997 and 30 percent less than the prior 10-year

average.

 Field extensions were 8,197 billion cubic feet,

down from 1997 but still 19 percent above the

prior 10-year average.

 New reservoir discoveries in old fields were 2,162

billion cubic feet, down 9 percent from 1997 and

7 percent less than the prior 10-year average.

Coalbed methane reserves and production continued

to grow in 1998, despite the decline in reserves and

production of conventional natural gas. Coalbed

methane reserves accounted for 7 percent of 1998’s

proved dry gas reserves. Coalbed methane

production in 1998 was 6 percent of the U.S. total dry

gas production.

Other 1998 natural gas events of note:

 Exploratory gas well completions and total gas

well completions both increased 7 percent in

1998.

 Although the number of wells increased, the

average of total discoveries per exploratory gas

well was 32 percent less in 1998.

 Natural gas prices at the wellhead fell 16 percent

in 1998 to an annual average of $1.94 per

thousand cubic feet.

 U.S. gas production was also down in 1998, in

keeping with lower natural gas demand.

Natural Gas Liquids

U.S. natural gas liquids proved reserves decreased 6

percent to 7,524 million barrels in 1998. A

reassessment of natural gas liquids reserves in

Alaska represents the bulk of the 1998 change.

Energy Information Administration

x U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
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 28,558 million

barrels in 1998, a 6 percent decrease from the 1997

level. Natural gas liquids represented 26 percent of

total liquid hydrocarbon proved reserves in 1998.

Data

These estimates are based upon analysis of data from

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

Gas Reserves,” filed by 2,739 operators of oil and gas

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

Origin of Natural Gas Liquids Production,” filed by

operators of 605 active natural gas processing plants.

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

natural gas are associated with sampling errors of

less than 1 percent.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 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 1998. It is based on data filed by large

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

Survey of Domestic Oil and Gas Reserves,” and by

operators of all natural gas processing plants on Form

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

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

proved reserves estimates are associated with

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

confidence level.

Form EIA-23

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

organization or person responsible for the

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

gas wells. This definition eliminates responses from

royalty owners, working interest owners (unless they

are also operators), and others not directly responsible

for oil and gas production operations.

Operator size categories are based upon their annual

production as indicated in various Federal, State, and

commercial records. Large operators are those that

produced at least 1.5 million barrels of crude oil or 15

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

report year. Intermediate operators produced less than

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

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

operators are those that produced less than

intermediate operators. All data are reported on a total

operated basis, encompassing all proved reserves and

production associated with wells operated by an

individual operator. This concept is also called the

“gross operated” or “8/8ths” basis.

Large operators and most intermediate size operators

report reserves balance data on Form EIA-23 to show

how and why reserves components changed during

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

operators who do not keep reserves data were not

asked to provide estimates of reserves at the beginning

of the year or annual changes to proved reserves by

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

new discoveries. These volumes were estimated by

applying an algebraic allocation scheme that preserved

the relative relationships between these items within

each State or State subdivision, as reported by large and

intermediate operators.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 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 23,620 probable active operators and the

Form EIA-64A plant frame contained 621 probable

active natural gas processing plants in the United

States when the 1998 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 1998.

For the report year 1998, EIA mailed 598 EIA-23 forms

to all known large and intermediate size oil and gas

well operators that were believed to be active during

1998. Of these, 26 were found to be nonoperators that

did not have successor operators in 1998. Data were

received from 588 operators, an overall response rate of

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

survey. EIA mailed 621 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 605 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 1998,

the Form EIA-23 National production estimates were 5

percent lower than the comparable Petroleum Supply

Annual (PSA) 1998 volumes for crude oil and lease

condensate combined, and were 0.5 percent lower than

the comparable Natural Gas Annual 1998 volume for

1998 dry natural gas. For report year 1998, the Form

EIA-64A National estimates were 8 percent lower than

the PSA 1998 volume for natural gas plant liquids

production.

Accuracy in reserves reporting is EIA’s first and

foremost goal for this report. Estimates of production

within this report may be lower than those made

specifically to estimate oil or gas production like those

in the PSA. There were over a thousand significant oil

and gas field sales in 1998 reviewed by EIA as part of

our quality assurance program. Often, new operators

of a field acquired through purchase correctly reported

their new proved reserves on Form EIA-23, but then

reported only their 1998 production since assuming

ownership – which may leave out several months of

production from their reported annual total for a field.

The net effect of this was a larger than usual difference

between the total oil production reported on Form

EIA-23 and the annual production reported in the PSA

1998.

Energy Information Administration

2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 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, 1998:

 Crude Oil — 21,034 million barrels

 Dry Natural Gas — 164,041 billion cubic feet

 Natural Gas Liquids — 7,524 million barrels.

This Overview summarizes the 1998 proved reserves

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

liquids on a National level and provides historical

comparisons between 1998 and years past.

Table 1 lists the estimated annual reserve balances

since 1988. From 1997 to 1998, proved reserves of crude

oil decreased by 7 percent—the largest percentage

decline in 53 years. Proved reserves of dry natural gas

decreased by 2 percent, ending a 4-year increasing

trend in gas reserves. Natural gas liquids reserves

declined 6 percent.

Crude Oil

Proved reserves of crude oil decreased by 1,512 million

barrels in 1998. Figure 1 shows the crude oil proved

reserves levels by major region and Figure 2 shows the

components of reserves changes from 1988 through

1998.

As shown in Figure 2, total reserve additions (the

positive side of the scale) were down substantially in

1998, as operators reacted to a significant drop in oil

prices in the last months of 1998. Net revisions and

adjustments were negative for the first time since EIA

began recording these data in 1977. Production of

crude oil (the negative side of the scale of Figure 2)

declined slightly for the seventh year in a row.

Total discoveries are those reserves attributable to field

extensions, new field discoveries, and new reservoir

discoveries in old fields. There were 599 million barrels of

total discoveries of crude oil proved reserves in 1998.

This is less than half of what was discovered in 1997.

Extensions added 327 million barrels of proved

reserves. This is 31 percent less than in 1997 (477

million barrels) and 25 percent less than the average

extensions in the prior 10 years (435 million barrels).

New field discoveries were 152 million barrels,

substantially less than the 1997 level and 14 percent less

than the average volume discovered in the prior 10

years (176 million barrels). New field discoveries in

Alaska and the Gulf of Mexico Federal Offshore (143

million barrels) made up 94 percent of the 1998 volume

of new field discoveries.

New reservoir discoveries in old fields added 120 million

barrels of proved reserves. This is more than the 1997

level (119 million barrels) but less than the prior 10-year

average for the United States (135 million barrels).

Revisions and adjustments deducted 120 million barrels

of proved reserves. This is the first negative total for net

revisions and adjustments for crude oil since EIA began

collecting this data in 1977. In the past 10 years, net

revisions and adjustments have added an average of

1,181 million barrels of crude oil proved reserves each

year, but this was not the case in 1998. Poor oil

economics due to very low oil prices caused many

operators to shut-in production and revise their crude

oil proved reserves downward.

Production removed an estimated 1,991 million barrels

of proved reserves from the National total. Production

was down 7 percent from 1997’s level (2,138 million

barrels), and down 17 percent from the prior 10-year

average (2,399 million barrels). Reserves additions in

1998 replaced only 24 percent of production.

Natural Gas

U.S. proved reserves of dry natural gas decreased,

ending a four-year increasing trend. Reserves of dry

natural gas declined 2 percent from 1997’s level to a

total of 164,041 billion cubic feet. Dry natural gas

reserves declined by 2,547 billion cubic feet in the

Lower 48 States, and in Alaska declined by 635 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 1988 through

1998. Dry natural gas production declined almost 3

percent from 1997 to 1998. Operators were only able to

replace 83 percent of 1998’s dry gas production with

new reserves.

For 1998, U.S. total discoveries of dry gas reserves were

11,433 billion cubic feet, down 27 percent from 1997,

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 3
Energy Information Administration

4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table 1. Total U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids, 1988-1998

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)

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

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

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

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

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

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

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

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

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

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

1998 -638 2,752 2,234 -120 327 152 120 599 1,991 21,034 -1,512

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

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

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

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

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

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

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

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

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

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

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

1998 -1,635 28,003 22,263 4,105 8,197 1,074 2,162 11,433 18,720 164,041 -3,182

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

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

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

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

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

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

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

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

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

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

1997 -15 1,199 910 274 535 114 90 739 864 7,973 +150

1998 -361 1,302 1,094 -153 383 66 88 537 833 7,524 -449

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

1998 contained in the Petroleum Supply Annual 1998, DOE/EIA-0340(98) and the Natural Gas Annual 1998, DOE/EIA-0131(98).

Sources: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1988 through 1998 annual reports, DOE/EIA-0216.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 5

Figure 1. U.S. Crude Oil Proved Reserves, 1988-1998

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1988-1998 annual reports, DOE/EIA-0216.{11-21}

-5

-4

-3

-2

-1

0

1

2

3

4

5

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Crude Oil, Billion Barrels

-5

-4

-3

-2

-1

0

1

2

3

4

5

New Fields New Reservoirs Extensions

Production Revisions & Adjustments Net Reserves Changes

0

5

10

15

20

25

30

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Crude Oil, Billions of Barrels

0

5

10

15

20

25

30

U.S. Total

Lower 48 Onshore

Lower 48 Offshore

Alaska

Figure 2. Components of Reserves Changes for Crude Oil, 1988-1998
Energy Information Administration

6 U.S. Crude Oil, NaturalGas, and Natural Gas Liquids Reserves 1998 Annual Report

Figure 4. Components of Reserves Changes for Dry Natural Gas, 1988-1998

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1988-1998 annual reports, DOE/EIA-0216.{11-21}

Figure 3. U.S. Dry Natural Gas Proved Reserves, 1988-1998

0

20

40

60

80

100

120

140

160

180

200

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Dry Natural Gas, Trillion Cubic Feet

0

20

40

60

80

100

120

140

160

180

200

U.S. Total

Lower 48 Onshore

Lower 48 Offshore

Alaska

-30

-20

-10

0

10

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30

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Dry Natural Gas, Trillion Cubic Feet

-30

-20

-10

0

10

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30

New Fields New Reservoirs Extensions

Production Revisions & Adjustments Net Reserves Changes
but 6 percent greater than the average annual volume

discovered in the past 10 years. Total discoveries were 74

percent of all reserve additions in 1998, while revisions

and adjustments provided the remaining 26 percent.

Extensions added 8,197 billion cubic feet of proved

reserves. This is 23 percent less than 1997’s extensions

but 19 percent more than the average of extensions in

the prior 10 years (6,909 billion cubic feet).

New field discoveries added 1,074 billion cubic feet of

proved reserves. This is 40 percent of what was

discovered in 1997 and 29 percent lower than the

average volume discovered in the prior 10 years (1,518

billion cubic feet).

New reservoir discoveries in old fields added 2,162 billion

cubic feet of proved reserves. This is 9 percent less than

the volume discovered in 1997, and 7 percent lower

than the prior 10-year average (2,318 billion cubic feet).

Revisions and Adjustments added 4,105 billion cubic feet

of proved reserves. This is 5 percent less than 1997’s

revisions and adjustments and 18 percent less than the

prior 10-year average (5,022 billion cubic feet).

Production removed an estimated 18,720 billion cubic

feet of proved reserves from the National total. Gas

production decreased almost 3 percent compared to

1997.

Coalbed methane gas production and reserves are

included in the 1998 totals. However, EIA separately

tracks these reserves in order to record the

development and performance of this gas source.

Coalbed methane reserves increased in 1998 to a

volume of 12,179 billion cubic feet. Coalbed methane

accounted for 7 percent of 1998 U.S. dry natural gas

reserves and 6 percent of 1998 U.S. dry gas production.

No Federal tax incentives for new coalbed methane

wells have been available for 5 years.

Natural Gas Liquids

Proved reserves of natural gas liquids decreased 449

million barrels to 7,524 million barrels during 1998— a

6 percent decrease from 1997 levels. A reassessment of

the natural gas liquids reserves of Alaska represents

the bulk of the 1998 change. Figure 5 shows the natural

gas liquids proved reserves levels by major region and

Figure 6 shows the components of reserves changes

from 1988 through 1998.

Operators replaced 46 percent of their 1998 natural gas

liquids production with reserve additions. Total

discoveries added 537 million barrels, but net revisions

and adjustments took away 153 million barrels.

Total proved reserves of liquid hydrocarbons (crude oil

plus natural gas liquids) were 28,558 million barrels in

1998—a 6 percent decrease from the 1997 level. Natural

gas liquids represented 26 percent of total liquid

hydrocarbon proved reserves in 1998.

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 1978 through 1998. Table 2

contains two sections, one for the lower 48 States and

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

contribution). Annual averages for each component of

reserves changes are also listed, along with the

percentage of that particular component's impact on

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

these averages to the 1998 proved reserves estimates as

a means of gauging the past year against history.

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

 discovered an average of 803 million barrels per

year of new reserves

 revised and adjusted their proved reserves

upward by an average of 1,295 million barrels

per year from revisions and adjustments

 ended each year with an average net reduction

in U.S. proved reserves of 567 million barrels

(the difference between post-1976 average

annual production and post-1976 average

annual reserve additions) because production

has outpaced reserve additions.

Since 1977, crude oil reserves have been primarily

sustained by the extension and development of

existing fields (called field growth, reserves growth, or

the EIA preferred term: proved ultimate recovery

appreciation. See the Proved Ultimate Recovery section

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

oil fields. Only 8 percent of reserves additions since

1976 were booked as new field discoveries. Proved

ultimate recovery appreciation is the sum of net

revisions and adjustments, extensions, and new

reservoirs in old fields. Since 1977, the largest

component of proved ultimate recovery appreciation

for crude oil is upward revisions and adjustments, which

accounted for 62 percent of all crude oil reserves

additions. The 17,668 million barrels of total discoveries

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 7
Energy Information Administration

8 U.S. Crude Oil, NaturalGas, and Natural Gas Liquids Reserves 1998 Annual Report

Figure 5. U.S. Natural Gas Liquids Proved Reserves, 1988-1998

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1988-1998 annual reports, DOE/EIA-0216.{11-21}

0

1

2

3

4

5

6

7

8

9

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Natural Gas Liquids, Billion Barrels

0

1

2

3

4

5

6

7

8

9

U.S. Total

Lower 48 Onshore

Lower 48 Offshore

Alaska

-2

-1.5

-1

-0.5

0

0.5

1

1.5

2

1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Natural Gas Liquids, Billion Barrels

-2

-1.5

-1

-0.5

0

0.5

1

1.5

2

New Fields New Reservoirs Extensions

Production Revisions & Adjustments Net Reserves Changes

Figure 6. Components of Reserves Changes for Natural Gas Liquids, 1988-1998
accounted for the remaining 38 percent of reserves

additions.

Compared to the average reserves changes since 1977,

1998 was a down year for crude oil discoveries. 1998’s

total discoveries of crude oil (599 million barrels) were 25

percent less the post-1976 U.S. average, and net

revisions and adjustments were negative for the first time

since EIA began publishing this data in 1977. The cause

of this large decline in net revisions was poor oil

economics, as explained in the Economics and Drilling

section of this chapter.

No components of total discoveries in 1998 exceeded the

post-1976 averages for crude oil.

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

 discovered an average of 12,026 billion cubic

feet per year of new reserves

 revised and adjusted their proved reserves

upward by an average 3,414 billion cubic feet

per year

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

2,238 billion cubic feet per year.

Like crude oil reserves, natural gas reserves have been

sustained primarily by proved ultimate recovery

appreciation since 1977. However, extensions rather

than net revisions and adjustments is the largest

component. Extensions account for 49 percent while

revisions and adjustments account for only 22 percent of

all reserve additions since 1977. In recent years, the

percentage of net revisions and adjustments has been as

high as 39 percent. In 1998,extensions were 53 percent of

all reserves additions while net revisions and

adjustments were 26 percent.

Compared to the average reserves changes since 1977,

1998 was a below average year for natural gas reserve

additions from total discoveries. U.S. total dry natural

gas reserves decreased 2 percent, ending a 4-year

increasing trend. Operators reported 11,433 billion

cubic feet of total discoveries of dry natural gas proved

reserves—5 percent less than the post-1976 average

(12,026 billion cubic feet). However, compared to the

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 9

Table 2. Reserves Changes, 1977-1998

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 ........... 3,043 138 8.2 3,634 165 7.9

New Reservoir Discoveries in Old Fields . . 2,999 136 8.1 3,029 138 6.6

Extensions ................ 9,856 448 26.7 11,005 500 23.8

Total Discoveries ............. 15,898 723 43.1 17,668 803 38.3

Revisions and Adjustments ........ 21,024 956 56.9 28,500 1,295 61.7

Total Reserve Additions .......... 36,922 1,678 100.0 46,168 2,099 100.0

Production ................ 45,868 2,085 124.2 58,636 2,665 127.0

Net Reserve Change............ -8,946 -407 -24.2 -12,468 -567 -27.0

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

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

New Field Discoveries ........... 42,637 1,938 12.0 42,729 1,942 12.6

New Reservoir Discoveries in Old Fields . . 56,300 2,559 15.9 56,665 2,576 16.7

Extensions ................ 164,255 7,466 46.3 165,172 7,508 48.6

Total Discoveries ............. 263,192 11,963 74.2 264,566 12,026 77.9

Revisions and Adjustments ........ 91,507 4,159 25.8 75,114 3,414 22.1

Total Reserve Additions .......... 354,699 16,123 100.0 339,680 15,440 100.0

Production ................ 381,423 17,337 107.5 388,917 17,678 114.5

Net Reserve Change............ -26,724 -1,215 -7.5 -49,237 -2,238 -14.5

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1977-1998 annual reports, DOE/EIA-0216.{1-21}
post-1976 U.S. average, net revisions and adjustments

were 20 percent higher in 1998 (4,105 billion cubic feet).

Economics and Drilling

Economics: Poor oil economics, caused by low crude

oil prices, had a strong negative impact on domestic

U.S. proved reserves in 1998. A direct consequence of

the low oil prices was reduced 1998 drilling levels. This

section describes the drastic price behavior in 1998 and

the following section addresses drilling.

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 1998.

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

North Slope) started at an average of $13.48 per barrel

in January 1998, but declined to $10.00 per barrel by

June. Prices increased slightly to $11.32 by October

1998, but then fell below the $10 mark to $8.05 per

barrel in December. The average U.S. crude oil first

purchase price (less the Alaskan North Slope) declined

from an average $17.23 in 1997 to $10.88 per barrel in

1998.

Energy Information Administration

10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 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, 1970-1998

Crude Oil Natural Gas

Year Current 1998 Constant Current 1998 Constant

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

1970 3.18 11.71 0.17 0.63 1,028

1971 3.39 11.87 0.18 0.63 976

1972 3.39 11.40 0.19 0.64 1,107

1973 3.89 12.38 0.22 0.70 1,194

1974 6.87 20.11 0.30 0.88 1,472

1975 7.67 20.48 0.44 1.18 1,660

1976 8.19 20.70 0.58 1.47 1,658

1977 8.57 20.38 0.79 1.88 2,001

1978 9.00 19.89 0.91 2.01 2,259

1979 12.64 25.76 1.18 2.40 2,177

1980 21.59 40.28 1.59 2.97 2,909

1981 31.77 54.33 1.98 3.39 3,970

1982 28.52 45.85 2.46 3.95 3,105

1983 26.19 40.38 2.59 3.99 2,232

1984 25.88 38.43 2.66 3.95 2,428

1985 24.09 34.54 2.51 3.60 1,980

1986 12.51 17.49 1.94 2.71 964

1987 15.40 20.89 1.67 2.26 936

1988 12.58 16.47 1.69 2.21 936

1989 15.86 19.93 1.69 2.12 869

1990 20.03 24.12 1.71 2.06 1,010

1991 16.54 19.16 1.64 1.90 860

1992 15.99 18.02 1.74 1.96 721

1993 14.25 15.65 2.04 2.24 754

1994 13.19 14.14 1.85 1.98 775

1995 14.62 15.33 1.55 1.62 723

1996 R18.46 19.00 2.17 2.23 779

1997 R17.23 17.40 R2.32 2.34 943

1998 10.88 10.88 1.96 1.96 827

R=Revised data.

Sources: Current dollars and number of rigs: Monthly Energy Review November 1999, DOE/EIA-0035(99/11). 1998 constant dollars:

U.S. Department of Commerce, Bureau of Economic Analysis, Gross Domestic Product Implicit Price Deflators, June 1999.
Oil prices vary by region. In Texas the average 1998

crude oil first purchase price was $12.28 per barrel,

while in California it was $9.61 per barrel, and only

$8.49 per barrel on the Alaskan North Slope. The lowest

average crude oil first purchase price in 1998 was for

Federal Offshore California oil—$6.98 per barrel.{22}

The average annual wellhead natural gas price

decreased from $2.32 in 1997 to $1.96 per thousand

cubic feet in 1998. Gas prices started at $1.99 per

thousand cubic feet in January 1998 and rose to $2.22

per thousand cubic feet by April 1998 (the highest

average price of the year). In June, prices dipped to

$1.97 but crept up to $2.08 in July. After July, prices

hovered around $1.85 per thousand cubic feet, and

then declined in December to $1.73 per thousand cubic

feet—the lowest average price for the year.{23}

Drilling: From 1997 to 1998, the annual average active

rig count decreased from 943 to 827 (Table 3). The rig

count remains well below the peak activity level of 1981

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

comparison of only the bulk number of wells drilled is

not representative of drilling’s impact on reserves

levels over time. Operators are now using significantly

improved drilling and seismic exploration technology

to dramatically increase their drilling success rate.

Looking first at exploratory wells, there were 2,691

exploratory wells drilled in 1998 (Table 4). Of these, 11

percent were oil wells, 21 percent were gas wells, and

67 percent were dry holes. The total (which includes

dry holes) was 12 percent less than in 1997.

The number of active rigs decreased in 1998, resulting

in 12 percent fewer successful exploratory wells than in

1997. There were 7 percent more exploratory gas wells

(Figure 7) and 29 percent fewer exploratory oil wells

(Figure 8) than in 1997. The number of successful

development wells decreased 32 percent for oil and

increased 7 percent for gas from 1997.

Figures 9 and 10 show the average volume of

discoveries per exploratory well for dry natural gas

and oil, respectively, since 1977. Both the average

volume of gas discoveries per exploratory well and the

average volume of oil discoveries per exploratory well

in 1998 decreased to levels closer to those of 1996.

Altogether there were an estimated 24,083 exploratory

and development wells drilled in 1998, 12 percent less

than in 1997 and 8 percent less than the average

number of wells drilled annually in the prior 10 years

(26,143).

For the sixth year in a row, the number of gas well

completions exceeded the number of oil well

completions in both the exploratory and development

categories.

Mergers and Acquisitions

Not all the notable activity in 1998 occurred in frontier

drilling areas, some occurred around the boardroom

tables of major oil and gas corporations. Over 1,400

major field ownership transactions, mergers, and

acquisitions were announced in 1998. The following

large mergers were announced in 1998, and are

expected to have a major impact on the energy industry

in the future:

On August 11, 1998, British Petroleum announced that

it would acquire Amoco for $48.2 billion in stock, the

largest oil industry merger and the largest foreign

take-over of a U.S. company to date. The company will

be known as BP Amoco, and it will be the world’s

third-largest multinational oil company in terms of net

income behind Exxon and Royal Dutch/Shell

Group.{24}

On December 2, 1998, Exxon Corporation agreed to

buy Mobil Corporation for approximately $75.4 billion,

making the company the largest corporation in the U.S.

The company will be known as Exxon Mobil, and said

they expect to cut about 9,000 jobs from their combined

worldwide workforce of 122,700 and to close offices,

saving $730 million. The merger comes in the context of

low oil prices, which have hurt profits at many oil

companies.{25}

On December 30, 1998, U.S. federal regulators

approved the proposed purchase of Amoco by British

Petroleum P.L.C. after extracting a handful of antitrust

concessions from the new company. With a market

capitalization of about $140 billion, BP Amoco would

rank third in the global oil industry behind the

proposed Exxon-Mobil merger and Royal

Dutch/Shell.{26}

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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 11
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:

 category of operator

 geology and economics

 number and size of new discoveries

 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.

Energy Information Administration

12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table 4. U.S. Exploratory and Development Well Completions,a 1970-1998

Exploratoryb Total Exploratory and Developmentb

Year Oil Gas Dry Total Oil Gas Dry Total

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

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

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

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

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

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

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

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

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

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

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

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

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

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

1984 2,198 1,521 11,278 14,997 42,605 17,127 25,681 85,413

1985 1,679 1,190 8,924 11,793 35,118 14,168 21,056 70,342

1986 1,084 793 5,549 7,426 19,097 8,516 12,678 40,291

1987 925 754 5,049 6,728 16,164 8,055 11,112 35,331

1988 855 732 4,693 6,280 13,636 8,555 10,041 32,232

1989 607 705 3,924 5,236 10,204 9,539 8,188 27,931

1990 654 689 3,715 5,058 12,198 11,044 8,313 31,555

1991 592 534 3,314 4,440 11,770 9,526 7,596 28,892

1992 493 423 2,513 3,429 8,757 8,209 6,118 23,084

1993 502 548 2,469 3,519 8,407 10,017 6,328 24,752

1994 570 726 2,405 3,701 6,721 9,538 5,307 21,566

1995 542 570 2,198 3,310 7,627 8,354 5,075 21,056

1996 483 570 2,136 3,189 8,314 9,302 5,282 22,898

1997 428 536 2,110 3,074 10,436 11,327 5,702 27,465

1998 303 572 1,816 2,691 7,064 12,106 4,913 24,083

aExcludes service wells and stratigraphic and core testing.

bAll drilling counts for the years 1973-1997 have been revised.

Notes: Estimates are based on well completions taken from American Petroleum Institute data tapes through October 1999. 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 1973-1998: Monthly Energy Review

November 1999, DOE/EIA-0035(99/11).
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 13

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

0

500

1,000

1,500

2,000

2,500

3,000

77 79 81 83 85 87 89 91 93 95 97

Wells

0

5

10

15

20

25

30

35

77 79 81 83 85 87 89 91 93 95 97

Billion Cubic Feet per Well

0

500

1,000

1,500

2,000

2,500

3,000

77 79 81 83 85 87 89 91 93 95 97

Wells

0

0.5

1

1.5

2

2.5

3

3.5

77 79 81 83 85 87 89 91 93 95 97

Million Barrels per Well

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

1977-1998

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

Exploratory Gas Well Completion, 1977-1998

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

1977-1998

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

Exploratory Oil Well Completion, 1977-1998
In 1998, both U.S. crude oil proved reserves and oil

production decreased—resulting in no significant

change in the National average R/P ratio (10.6).

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

since 1945. After World War II, increased drilling and

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

drilling found fewer reserves than were produced, the

ratio became smaller. R/P ratios also vary

geographically. Less developed areas of the country,

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

crude oil than the 1998 National average of 10.6-to-1.

Other areas with relatively high R/P ratios are the

Permian Basin of Texas and New Mexico, and

California, where enhanced oil recovery techniques

such as carbon dioxide (CO2) injection or

steamflooding have improved recoverability of oil in

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

ratios, like the Mid-Continent region, usually have

many older fields. There, new technologies such as

horizontal drilling have helped add reserves

equivalent to the annual production, keeping the

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

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

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

since the interstate pipeline infrastructure was not well

developed. The market for and production of natural

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

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

increased in 1998, as reserves decreased, but not more

than the decline in production.

Different marketing, transportation, and production

characteristics for gas are seen when looking at

regional average R/P ratios, compared to the 1998 U.S.

average R/P ratio of about 8.8-to-1. The areas with the

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

productive areas of the country, such as the Pacific

offshore and the Rockies, and also include areas such as

Alabama and Colorado where considerable booking of

coalbed methane reserves has recently occurred.

Several major gas producing areas have R/P ratios

below the National average, particularly Texas, the

Gulf of Mexico Federal Offshore, and Oklahoma. The

R/P ratio of these three areas combined increased from

6.8-to-1 in 1997 to 6.9-to-1 in 1998, and is below the

National 1998 average.

Proved Ultimate Recovery

EIA has in past reports defined Ultimate Recovery as

the sum of proved reserves and cumulative

production. However, despite EIA’s clear definition,

the volume presented by EIA has often been misused

or misinterpreted as the maximum recoverable volume

of resources for an area. This neglects the addition of

proved reserves over time through ultimate recovery

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

and has led some to make overly-pessimistic resource

assessments for the United States. EIA is therefore

introducing a new term, Proved Ultimate Recovery:

Proved Ultimate Recovery is the sum of

proved reserves and cumulative production. It is

expected to change over time for any field, group

of fields, State, or Country. Proved Ultimate

Recovery does not represent the maximum

recoverable volume of resources for an area. It is

instead a gauge of how much has already been

produced plus proved reserves. Proved reserves

of crude oil or natural gas are the estimated

quantities of petroleum which geological and

engineering data demonstrate with reasonable

certainty to be recoverable in future years from

known reservoirs under existing economic and

operating conditions. When deterministic proved

reserves estimation methods are used, the term

reasonable certainty is intended to express a high

degree of confidence that the estimated quantities

will be recovered. When probabilistic methods are

used there should be at least a 90 percent

probability that the actual quantities recovered

will exceed the estimate.

Figures 13 and 14 show successive estimates of proved

ultimate recovery and its components, proved reserves

and cumulative production, for crude oil plus lease

condensate, and wet natural gas, from 1977 through

1998. They illustrate the continued appreciation

(growth) of proved ultimate recovery over time.

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

reserves were 33,615 million barrels. Cumulative

production of crude oil and lease condensate for 1977

through 1998 was 59,205 million barrels. This

substantially exceeds the 1977 proved reserves, but at

the end of 1998 there were still 22,370 million barrels of

crude oil and lease condensate proved reserves.

Therefore, the Nation’s estimated proved ultimate

recovery of crude oil was fundamentally increased

during this period owing to the proved ultimate recovery

appreciation process (continued development of old

fields). In fact, only 8 percent of proved reserves

additions of crude oil were booked as new field

discoveries from 1976 through 1998. The rest was from

proved reserves categories included in the proved

ultimate recovery appreciation process (new reservoir

discoveries in old fields, extensions, and revisions and

Energy Information Administration

14 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 15

Sources: Annual reserves and production - American Petroleum Institute and American Gas Association (1945–1976){27} and Energy

Information Administration, Office of Oil and Gas (1977–1998){1-21}. Cumulative production: U.S. Oil and Gas Reserves by Year of Field

Discovery (1977-1988).{28}

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

0

50

100

150

200

250

77 79 81 83 85 87 89 91 93 95 97

Billions of Barrels

Cumulative Production

Proved Reserves

Ultimate Recovery

0

200

400

600

800

1,000

1,200

77 79 81 83 85 87 89 91 93 95 97

Trillions of Cubic Feet

Cumulative Production

Proved Reserves

Ultimate Recovery

Figure 11. Reserves-to-Production Ratios for

Crude Oil, 1945-1998

Figure 13. Components of Proved Ultimate Recovery for

Crude Oil and Lease Condensate, 1977-1998

Figure 12. Reserves-to-Production Ratios for

Wet Natural Gas, 1945-1998

Figure 14. Components of Proved Ultimate Recovery

for Wet Natural Gas, 1977-1998
Table 5. International Oil and Natural Gas Reserves as of December 31, 1998

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 d261,425 1 Former U.S.S.R........ 1,977,000 1,904,350

2 Iraqc ............... 112,500 98,975 2 Iranc ................ 812,300 812,238

3 Kuwaitc ............. d96,500 d94,680 3 Qatarc .............. 300,000 395,000

4 Iranc ............... 89,700 92,870 4 United Arab Emiratesc . . 212,500 202,550

5 United Arab Emiratesc . 97,800 63,505 5 Saudi Arabiac......... d204,500 d208,000

6 Former U.S.S.R. ...... 57,000 66,641 6 United States ........ e167,223 167,772

7 Venezuelac .......... 72,600 45,500 7 Venezuelac .......... 142,500 146,571

8 Mexico ............. 47,822 28,399 8 Algeriac ............. 130,300 137,500

9 China .............. 24,000 33,520 9 Nigeriac ............. 124,000 124,000

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

Top 10 Total.............. 888,724 810,090 Top 10 Total .............. 4,179,823 4,210,581

11 Nigeriac

............. 22,500 22,500 11 Malaysia............. 81,700 85,831

12 United States........ e22,546 22,013 12 Indonesiac ........... 72,268 77,066

13 Norway ............. 10,913 11,901 13 Canada.............. 63,874 63,555

14 Algeriac............. 9,200 13,000 14 Netherlands .......... 63,107 62,516

15 Brazil............... 7,106 7,500 15 Kuwaitc.............. d52,200 d56,350

16 Indonesiac .......... 4,980 8,637 16 Mexico .............. 63,456 30,300

17 Oman .............. 5,283 5,564 17 Libyac............... 46,400 46,300

18 Canada ............. 4,931 5,582 18 China ............... 48,300 42,360

19 United Kingdom ...... 5,191 5,153 19 Norway.............. 41,424 43,627

20 Angola ............. 5,412 4,030 20 Australia ............. 44,638 28,410

21 Qatarc .............. 3,700 5,338 21 Egypt ............... 31,500 37,205

22 Malaysia ............ 3,900 4,645 22 Oman ............... 28,416 29,100

23 Egypt .............. 3,500 3,710 23 United Kingdom ....... 27,016 26,652

24 India ............... 3,972 3,027 24 Argentina ............ 24,148 24,247

25 Yemen ............. 4,000 1,850 25 Pakistan ............. 21,600 21,600

Top 25 Total.............. 1,006,056 931,988 Top 25 Total .............. 4,889,670 4,881,700

OPEC Total .............. 800,480 733,330 OPEC Total ............... 2,206,768 2,318,175

World Total .............. 1,034,667 968,513 World Total ............... 5,144,736 5,148,978

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, 1997 were published by the Oil & Gas Journal as its estimates as

of December 31, 1998.

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 28, 1998, pp. 38-39. Gulf Publishing Company, World Oil,

August, 1999, pp. 28-29.

Energy Information Administration

16 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
adjustments.) A significant part of the total proved

ultimate recovery appreciation came from the proved

ultimate recovery appreciation of those new fields

discovered between 1976 and 1998.

Similarly, the 1977 dry natural gas proved reserves

were 213,278 billion cubic feet, and cumulative dry gas

production from 1977 through 1998 was 388,917 billion

cubic feet. Cumulative dry gas production exceeded

the 1977 reserves, but at the end of 1998 there were still

164,041 billion cubic feet of dry natural gas proved

reserves, for the same reasons. Only 13 percent of

proved reserve additions of natural gas were booked as

new field discoveries from 1976 through 1998.

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 12th in the world for proved

reserves of crude oil and 6th for natural gas in 1998. 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 1998. There are sometimes substantial

differences between the estimates from these sources.

The Oil & Gas Journal reported oil reserves for the

United Arab Emirates at about 98 billion barrels. This is

about 50 percent higher than the World Oil estimate of

64 billion. One reason (among many) for these

differences is that condensate is often included in

foreign oil reserve estimates.

The Oil & Gas Journal{29} estimate for world oil reserves

increased 1 percent in 1998, while the World Oil{30}

estimate decreased less than 1 percent. For world gas

reserves, the Oil & Gas Journal reported a 6 percent

increase, while World Oil reported a 1 percent increase.

The Oil & Gas Journal’s estimates were boosted mostly

by increases in their estimate of gas reserves for

Australia, Nigeria, and Saudi Arabia, but also because

EIA proved reserves as of December 31, 1997 were

published by the Oil & Gas Journal as its estimates as of

December 31, 1998.

Several foreign countries have oil reserves

considerably larger than those of the United States.

Saudi Arabian oil reserves are the largest in the world,

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

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

almost triple and Mexico has around 81 percent more

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

of the World Oil and Oil & Gas Journal estimates).

Petroleum Consumption

The United States is the world's largest energy

consumer. The EIA estimates energy consumption and

publishes it in its Annual Energy Review.{31} In 1998:

 The U.S. consumed 94,231,275,000,000,000 Btu of

energy (94.23 quadrillion Btu).

 62 percent of U.S. energy consumption was

provided by petroleum and natural gas—crude

oil and natural gas liquids combined (39

percent), and natural gas (23 percent).

 U.S. petroleum consumption was about 18.7

million barrels of oil and natural gas liquids

and 58.3 billion cubic feet of dry gas per day.

Dependence on Imports

The United States remains heavily dependent on

imported oil and gas to satisfy its ever-increasing

appetite for energy. In 1998, the U.S. was dependent on

net petroleum imports for 51 percent of energy

consumption.

Net gas imports increased slightly in 1998 to 3 trillion

cubic feet, which is approximately 14 percent of

consumption. Almost all of this gas was pipelined from

Canada, some came from Mexico, though Mexico

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

liquefied natural gas was imported from Algeria and

Australia.

Venezuela, Canada, Saudi Arabia, Mexico, and Nigeria

were the primary foreign suppliers of petroleum to the

United States.{32}

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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 17
operators from the small and presents reserves data

according to operator production size classes.

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

have the most reserves and production in the United

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

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

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

U.S. crude oil proved reserves.

Appendix C: Conversion to the Metric System - To

simplify international comparisons, a summary of U.S.

Crude Oil, Natural Gas, and Natural Gas Liquids

Reserves expressed in metric units is included as

Appendix C.

Appendix D: Historical Reserves Statistics -

Appendix D contains selected historical reserves data

presented at the State and National level. Readers

interested in a historical look at one specific State or

region can review these tables. We have again included

Table D9, Deepwater Production and Proved Reserves

of the Gulf of Mexico Federal Offshore 1992-1998, due

to expressed interest from the industry regarding this

area. Table D9 contains the production and proved

reserves for 1992-1998 for the Gulf of Mexico Federal

Offshore region by water depths greater than 200

meters, and less than 200 meters.

Appendix E: Summary of Data Collection

Operations - This report is based on two EIA surveys.

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

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

liquids production data is collected annually from U.S.

natural gas plant operators on Form EIA-64A.

Appendix E describes survey designs, response

statistics, reporting requirements, and sampling frame

maintainance.

Appendix F: Statistical Considerations - The EIA

strives to maintain or improve the accuracy of its

reports. Since complete coverage of all oil and gas

operators is impractical, the EIA has adopted sound

statistical methods to impute data for those operators

not sampled and for those data elements that smaller

operators are not required to file. These methods are

described in Appendix F.

Appendix G: Estimation of Reserves and Resources -

Reserves are not measured directly. Reserves are

estimated on the basis of the best geological,

engineering, and economic data available to the

estimator. Appendix G describes reserve estimation

techniques commonly used by oil and gas field

operators and EIA personnel when in the field

performing quality assurance checks. A discussion of

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

resources is also included.

Appendix H: Maps of Selected State Subdivisions -

Certain large producing States have been subdivided

into smaller regions to allow more specific reporting of

reserves data. Maps of these States identifying the

smaller regions are provided in Appendix H.

Appendix I: Annual Survey Forms of Domestic Oil

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

EIA-64A are presented in Appendix I.

Glossary - Contains definitions of many of the

technical terms used in this report.

Energy Information Administration

18 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
3. Crude Oil Statistics

The United States had 21,034 million barrels of crude

oil proved reserves as of December 31, 1998. This is 7

percent (-1,512 million barrels) less than in 1997, and is

the largest percentage decline in oil reserves in 53

years. Reserves additions of crude oil were less than a

fifth of those in 1997—operators only replaced 24

percent of 1998 oil production (Figure 15). Crude oil

prices, which began a decline in 1997, fell dramatically

during 1998 to levels last seen in 1935 by December.

Low prices curtailed new drilling and imposed

negative revisions on producing oil fields, which

resulted in the large drop in crude oil proved reserves

in 1998.

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

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

per year. However, less new reserve additions and

more negative revisions made the decline much more

severe in 1998. As of December 1999, prices have

rebounded—yet oil well drilling has yet to resume at

the pace observed in the last decade. If drilling

resumes, it is expected that the 2 percent declining

trend will reestablish itself in the future. In the absence

of that needed drilling, declines will be higher as the

reserves base depletes through production.

Proved Reserves

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

as of December 31, 1998, by selected States and State

subdivisions.

Figure 16 maps 1998 crude oil proved reserves by area.

The following four areas account for 79 percent of U.S.

crude oil proved reserves:

Percent of

Area U.S. Oil Reserves

Alaska 24

Texas 23

California 18

Gulf of Mexico Federal Offshore 13

Area Total 79

Of these four areas, California increased its reserves in

1998, while Alaska, the Gulf of Mexico, and Texas all

had decreases in crude oil proved reserves.

Discussion of Reserves Changes

Figure 17 maps the change in crude oil proved reserves

from 1997 to 1998 by area. Here’s how the top four

areas fared compared to the total United States:

Change in

U.S. Oil Reserves

Area (million barrels)

Texas -760

Alaska -109

California +93

Gulf of Mexico Federal Offshore -156

Area Total -932

U.S. Total -1,512

Figure 2 in Chapter 2 shows the components of the

changes in crude oil proved reserves for 1998 and the

preceding 10 years.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 19

37%

62%

66%

78%

85%

125%

24%

95%

0%

20%

40%

60%

80%

100%

120%

140%

1991 1992 1993 1994 1995 1996 1997 1998

Percentage of U.S. Oil Production Replaced

Figure 15. Reserve Additions Replace Only 24

Percent of U.S. Oil Production in 1998

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

20 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table 6. Crude Oil Proved Reserves, Reserves Changes, and Production, 1998

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 1998

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/97 (+,-) (+) (--) (+) (+) (+) (-) 12/31/98

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

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

Reserves.” They may differ from the official Energy Information Administration production data for crude oil for 1998 contained in the Petroleum

Supply Annual 1998, DOE/EIA-0340(98).

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

Alaska....................... 5,161 1 267 64 28 96 0 437 5,052

Lower 48 States .............. 17,385 -639 2,485 2,170 299 56 120 1,554 15,982

Alabama . . . . . . . . . . . . . . . . . . . . . 47 2 6 9 0 0 0 7 39

Arkansas . . . . . . . . . . . . . . . . . . . . 45 -1 24 14 0 0 0 7 47

California .................... 3,750 -131 789 336 23 0 18 270 3,843

Coastal Region Onshore . . . . . . 430 -33 62 86 0 0 0 19 354

Los Angeles Basin Onshore . . . 268 -39 19 42 0 0 18 17 207

San Joaquin Basin Onshore . . . 2,871 -58 708 204 23 0 0 213 3,127

State Offshore . . . . . . . . . . . . . . 181 -1 0 4 0 0 0 21 155

Colorado. . . . . . . . . . . . . . . . . . . . . 198 17 37 21 1 0 0 20 212

Florida . . . . . . . . . . . . . . . . . . . . . . 91 -1 0 13 0 0 0 6 71

Illinois . . . . . . . . . . . . . . . . . . . . . . . 92 -25 56 32 0 0 0 10 81

Indiana . . . . . . . . . . . . . . . . . . . . . . 10 -4 12 4 0 0 0 b1 b13

Kansas . . . . . . . . . . . . . . . . . . . . . . 238 28 85 77 5 1 0 34 b246

Kentucky. . . . . . . . . . . . . . . . . . . . . 20 9 0 4 0 0 0 2 23

Louisiana . . . . . . . . . . . . . . . . . . . . 714 -81 180 208 17 3 9 83 551

North . . . . . . . . . . . . . . . . . . . . . 136 11 31 62 3 0 0 18 101

South Onshore. . . . . . . . . . . . . . 427 -58 139 129 14 2 6 48 353

State Offshore . . . . . . . . . . . . . . 151 -34 10 17 0 1 3 17 97

Michigan. . . . . . . . . . . . . . . . . . . . . 68 -5 8 19 0 0 0 8 44

Mississippi . . . . . . . . . . . . . . . . . . . 183 20 13 65 9 0 0 19 141

Montana . . . . . . . . . . . . . . . . . . . . . 159 -11 30 13 15 1 0 14 167

Nebraska . . . . . . . . . . . . . . . . . . . . 21 2 4 6 0 0 0 3 18

New Mexico . . . . . . . . . . . . . . . . . . 735 -36 79 126 23 0 4 59 620

East . . . . . . . . . . . . . . . . . . . . . . 719 -33 78 123 23 0 4 58 610

West. . . . . . . . . . . . . . . . . . . . . . 16 -3 1 3 0 0 0 1 10

North Dakota . . . . . . . . . . . . . . . . . 279 -29 33 21 16 0 0 33 245

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 43 0 9 6 0 0 0 6 40

Oklahoma. . . . . . . . . . . . . . . . . . . . 605 -62 207 106 16 1 0 62 599

Pennsylvania . . . . . . . . . . . . . . . . . 17 -2 1 2 2 0 0 1 15

Texas ....................... 5,687 -295 514 621 48 2 9 417 4,927

RRC District 1 . . . . . . . . . . . . . . 83 -18 35 32 1 0 0 8 b61

RRC District 2 Onshore . . . . . . 66 -22 16 8 0 0 0 7 45

RRC District 3 Onshore . . . . . . . 259 -11 45 56 9 0 0 35 211

RRC District 4 Onshore . . . . . . . 70 -23 6 7 0 0 0 6 40

RRC District 5 . . . . . . . . . . . . . . 54 -23 19 8 1 0 5 8 40

RRC District 6 . . . . . . . . . . . . . . 348 -13 19 15 1 0 0 32 308

RRC District 7B . . . . . . . . . . . . . 155 -21 16 21 1 0 0 15 115

RRC District 7C . . . . . . . . . . . . . 227 -37 19 22 3 1 0 18 173

RRC District 8 .............. 2,100 -58 129 192 20 1 3 138 1,865

RRC District 8A ............. 2,098 -40 173 219 10 0 0 127 1,895

RRC District 9 . . . . . . . . . . . . . . 144 -25 21 15 1 0 1 16 111

RRC District 10 . . . . . . . . . . . . . 79 -1 15 25 1 0 0 b7 b62

State Offshore . . . . . . . . . . . . . . 4 -3 1 1 0 0 0 0 1

Utah . . . . . . . . . . . . . . . . . . . . . . . . 234 -9 10 21 1 0 0 14 201

West Virginia . . . . . . . . . . . . . . . . . 26 0 1 9 0 0 0 1 17

Wyoming . . . . . . . . . . . . . . . . . . . . 627 -2 46 98 31 1 0 58 547

Federal Offshore .............. 3,477 -22 340 336 92 47 80 417 3,261

Pacific (California) . . . . . . . . . . . 528 -16 33 42 5 0 5 45 468

Gulf of Mexico (Louisiana) ..... 2,587 15 275 263 84 47 74 336 2,483

Gulf of Mexico (Texas). . . . . . . . 362 -21 32 31 3 0 1 36 310

Miscellaneousa. . . . . . . . . . . . . . . . 19 -1 1 3 0 0 0 2 14

U.S. Total.................... 22,546 -638 2,752 2,234 327 152 120 1,991 21,034
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 21

Figure 17. Changes in Crude Oil Proved Reserves by Area, 1997 to 1998

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

Figure 16. 1998 Crude Oil Proved Reserves by Area

5,052

468

3,843

167 245

547

201 212

620

18

599

4,927

246

551

47

141

39

2,793 71

15

23

40

44

81 13

17

Crude Oil Proved Reserves

1998, Millions of Barrels

1000 to 5060 (4)

100 to 1000 (11)

1 to 100 (16)

0 to 0 (21)

Four Areas Contain

79 Percent of U.S.

Crude Oil Proved Reserves

U.S. TOTAL:

21.034 Billion Barrels

-109

-60

93

-3

-115

-33

-80

-34 8

14 8

-760

-163

-6 2

-42

-156

-8

-20

3

-24

-9

-3 -2 -11 3

Changes in Crude Oil Proved Reserves by Area

1997 to 1998, Millions of Barrels

1 to 100 (8)

0 to 0 (21)

-100 to 0 (18)

-760 to -100 (5)

Crude Oil Proved Reserves Decline Significantly

In Major Oil Producing States, Except California.

Total U.S. Decrease: - 1,512 Million Barrels.
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 599 million barrels in

1998, less than half those of 1997. Only five areas had

total discoveries exceeding 30 million barrels:

 The Gulf of Mexico Federal Offshore had 209

million barrels of total discoveries, 35 percent of

the National total.

 Alaska had 124 million barrels of total discoveries,

21 percent of the National total.

 Texas had 59 million barrels of total discoveries,

10 percent of the National total.

 California had 41 million barrels of total

discoveries, 7 percent of the National total.

 Wyoming had 32 million barrels of total

discoveries, 5 percent of the National total.

The United States discovered an average of 747 million

barrels of new crude oil proved reserves per year in the

prior 10 years (1988 through 1997). Total discoveries in

1998 were 20 percent less than that average.

Extensions

Operators reported 327 million barrels of extensions in

1998. The highest volume of extensions was reported in

the Gulf of Mexico Federal Offshore (87 million barrels

of extensions.) Operators in Texas reported 48 million

barrels of extensions. Wyoming was third with 31

million barrels, followed by Alaska with 28 million

barrels.

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

average of 435 million barrels of extensions per year.

The 1998 extensions were 25 percent less than that

average.

New Field Discoveries

There were 152 million barrels of new field discoveries

reported in 1998. Only eight areas in the United States

reported any new field discoveries, and only two

contributed more than 2 percent to the total:

 Alaska (63 percent; 96 million barrels)

 Gulf of Mexico Federal Offshore (31 percent; 47

million barrels).

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

average of 176 million barrels of reserves from new field

discoveries per year. Reserves from new field discoveries

in 1998 were 14 percent less than that average volume.

New Reservoir Discoveries in Old Fields

Operators in the United States reported 120 million

barrels of crude oil reserves from new reservoir

discoveries in old fields in 1998. As with new field

discoveries, the most significant portion of the new

reservoir discoveries in old fields came from the Gulf of

Mexico Federal Offshore—75 million barrels or 63

percent of the total. California had 18 million barrels

(15 percent), and Louisiana and Texas each had 9

million barrels (8 percent each). In the prior 10 years,

U.S. operators reported an average of 135 million

barrels of reserves from new reservoir discoveries in old

fields per year. Reserves from new reservoir discoveries in

old fields in 1998 were 89 percent of that average.

Revisions and Adjustments

Thousands of positive and negative revisions to proved

reserves occur each year as infill wells are drilled, well

performance is analyzed, new technology is applied, or

economic conditions change. Adjustments are the

annual changes in the published reserve estimates that

cannot be directly attributed to the estimates for other

reserve change categories because of the survey and

statistical estimation methods employed.

There were -120 million barrels of net revisions and

adjustments for crude oil in 1998. This was the first time

in 22 years that revisions and adjustments did not make

a positive contribution to oil reserve additions.

Average revisions and adjustments for the prior 10 years

were 1,181 million barrels.

Production

U.S. production of crude oil in 1998 was 1,991 million

barrels. This was 7 percent lower than 1997’s total of

2,138 million barrels. U.S. crude oil production has

declined in 12 of the last 13 years. Alaska and Texas are

still the largest producers of crude oil in the United

States with 22 percent and 21 percent of the total,

respectively. The Gulf of Mexico Federal Offshore is

third with 19 percent, and California has 14 percent.

In 1998, the Form EIA-23 National production

estimates were 5 percent lower than the comparable

Petroleum Supply Annual (PSA) 1998 volumes for crude

Energy Information Administration

22 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
oil and lease condensate combined. There were over a

thousand significant oil and gas field sales in 1998

reviewed by EIA as part of our quality assurance

program. Often, new operators of a field acquired

through purchase correctly reported their new proved

reserves on Form EIA-23, but then reported only their

1998 production since assuming ownership – which

may leave out several months of production from their

reported annual total for a field. The net effect of this

was a larger than usual difference between the total oil

production reported on Form EIA-23 and the annual

production reported in the PSA 1998.

Areas of Note: Large Discoveries

and Reserves Additions

The following State and area discussions summarize

notable activities during 1998 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 1998.

California

California’s proved oil reserves increased by 93 million

barrels in 1998. The largest increase was from revisions

and adjustments in the San Joaquin Basin Onshore,

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

reserves increased by 256 million barrels. California’s

production declined by about 5 percent from 1997’s

level of 285 million barrels. Reserves additions would

have been even smaller in the U.S., had not certain

operators (particularly those in California) continued

to develop large, long-term projects despite low oil

prices.

On February 5, 1998, following a ruling by a federal

judge denying a request from environmentalists and

Native Americans seeking to block the sale of the Elk

Hills Naval Petroleum Reserve, the U.S. Department of

Energy formally transferred ownership of the reserve

to Occidental Petroleum Corporation. Occidental

purchased a 78 percent interest in the field for $3.65

billion. Chevron Corporation currently holds the

remaining 22 percent.{33}

Colorado

Colorado had the second highest net increase in crude

oil proved reserves in 1998, an increase of 14 million

barrels. Operators in Colorado, through acquisitions or

field development, revised their crude oil proved

reserves upward, and when combined with

adjustments the total volume exceeded production in

1998. Colorado had an estimated 20 million barrels of

oil production in 1998, which is 5 percent lower than

1997’s production (21 million barrels).

Alaska

Alaska reported 124 million barrels of total discoveries of

crude oil proved reserves in 1998—the second highest

total discoveries in the United States (following the

Gulf of Mexico Federal Offshore). Alaska led the nation

in new field discoveries with a volume of 96 million

barrels. The new field discoveries were made on the

North Slope in “satellite fields”, meaning that they are

located next to large, existing Alaskan North Slope

fields and can be developed economically by extending

facilities from the existing production sites to reach

them.

For example, in 1998, BP Exporation (now BP Amoco)

began commercial production from Badami, a “satellite

field” discovery on the North Slope. Badami is located

on the shore of Mikkelsen Bay about 35 miles east of

Prudhoe Bay. BP Exploration and its partner,

PetroFina S.A. (Fina) developed this field. Badami

leases lie both onshore and offshore in a sandstone

reservoir at a depth of about 10,000 feet. The oil pay

zone thickness is estimated to be 65-115 feet. Badami

was developed as a single, onshore drill site with 40

wells and stand-alone processing facilities for handling

35,000 barrels per day. Crude oil is sent to the Endicott

sales oil pipeline, which delivers it to the trans-Alaska

pipeline. No road was built to Badami— access is by

barge, aircraft and helicopter, and in winter by ice road.

Production was briefly halted at Badami in early 1999

due to challenging reservoir conditions. Production

was resumed on May 1, 1999. {34}

Gulf of Mexico Federal Offshore

Despite the net loss of reserves in 1998, the Gulf of

Mexico still holds much promise for future

development and reserves additions, especially in

deep water. In 1998, this area had the most reserves

additions ofextensions and new reservoir discoveries in old

fields.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 23
 Tanzanite: On July 29, 1998 Anadarko

Petroleum announced that it had discovered oil

and natural gas at the Eugene Island South

Addition Block 346 in the Gulf of Mexico,

located approximately 75 miles offshore

Louisiana. Anadarko estimates that the

Tanzanite prospect contains reserves of at least

140 million barrels of oil equivalent. On

September 14, 1998, Anadarko reported its

Tanzanite No. 1 well tested 21,917 barrels oer

day of oil and 29.7 million cubic feet per day of

natural gas.{35}

 Angus, Europa, Macaroni: On March 19, 1998,

Shell Exploration and Production Company

announced it would spend $1 billion developing

the Angus, Europa, and Macaroni oil and gas

discoveries located in the Gulf of Mexico. Shell

expects the Angus development can yield 40,000

barrels of oil per day and 60 million cubic feet of

gas per day by the end of 1999. The Europa

development is expected to produce 60,000

barrels of oil per day and 45 million cubic feet of

gas per day by early 2001. The Macaroni

development is anticipated to yield 35,000

barrels of oil per day and 65 million cubic feet of

gas per day by late 1999. Shell expects these

three discoveries could add 300 million barrels

of oil equivalent to the Gulf of Mexico’s deep

water inventory.{36}

 Hoover and Diana: On April 8, 1998, Exxon

Corporation and British Petroleum (now BP

Amoco) announced that they will spend $1.2

billion developing the Hoover and Diana oil and

gas fields, located south of Galveston, Texas, in

the Gulf of Mexico. Exxon estimates the fields

could contain recoverable reserves of more than

300 million oil-equivalent barrels, and

production is estimated to begin by 2000. Exxon

holds a 66.7 percent operating interest in the

project, with British Petroleum holding the

remaining 33.3 percent interest.{37}

Other Gain Areas

Montana: Montana’s proved oil reserves increased by

5 percent (8 million barrels).

Kansas: Kansas’ proved oil reserves increased by 3

percent (8 million barrels).

Areas of Note:

Large Reserves Declines

The following areas had large declines in crude oil

proved reserves due to downward revisions or

unreplaced production.

Texas

Texas’ proved oil reserves declined by 760 million

barrels in 1998, the largest decline for any State. Crude

oil proved reserves in this State were revised and

adjusted downward by 402 million barrels in 1998.

Texas’ production also declined about 12 percent from

1997 levels.

Of Texas’ many districts, the largest reserves decline

(235 million barrels) was in RRC District 8. Ironically,

RRC District 8 is also where the most total discoveries of

crude oil proved reserves were made in Texas in 1998

(24 million barrels)—but this volume was meager

compared to the negative double-whammy of a net

downward revision of 121 million barrels and

production of another 138 million barrels. Other areas

where oil reserves significantly decreased were RRC

District 8A (203 million barrels) and RRC District 7C

(54 million barrels). Not one RRC District in Texas

reported an increase in crude oil proved reserves in

1998.

Louisiana

Louisiana’s proved oil reserves decreased by 163

million barrels. The South Onshore region of Lousiana

reported almost half of the loss. Louisiana’s production

also decreased 17 percent from 1997’s level.

Gulf of Mexico Federal Offshore

There was a net loss of 156 million barrels of crude oil

proved reserves from the Gulf of Mexico Federal

Offshore in 1998. Gulf oil reserves had been increasing

for 6 years in a row—1998’s decline interrupts this

trend. It is expected that development and exploration

in the Gulf of Mexico Federal Offshore will continue to

add future reserves, making 1998’s decline merely an

economic “pothole” in the road of developing the

Gulf’s great resource base.

The Gulf of Mexico produced about 372 million barrels

of crude oil in 1998, an increase of 9 percent (30 million

barrels) over 1997’s production. However, there were

only 216 million barrels of total reserves additions

Energy Information Administration

24 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
(which includes adjustments, net revisions, and total

discoveries) in this area, which replaced just 58 percent

of production from this area.

New Mexico

New Mexico’s proved oil reserves decreased by 115

million barrels. The East region of New Mexico

reported the bulk of the loss. New Mexico’s production

also decreased 7 percent from 1997’s level.

Alaska

Alaska’s crude oil proved reserves declined 109 million

barrels in 1998, slightly less than the loss reported in

1997 (113 million barrels). Alaska had the most volume

of new field discoveries (96 million barrels) of any State in

1998. It also had the second highest volume of net

revisions and adjustments (204 million barrels). But

these did not offset Alaska’s oil production—an

estimated 437 million barrels in 1998. Alaska’s

production declined 8 percent from its 1997 level.

Other Decline Areas

In the following areas of the United States,

development of existing or new oil fields was outpaced

by crude oil production.

Wyoming: Proved oil reserves decreased

by 13 percent (80 million barrels).

Pacific Federal Offshore: Proved oil

reserves decreased by 11 percent (60

million barrels). On June 12, 1998, President

Clinton extended by 10 years the ban on

offshore drilling for much of the United

States. The extended ban prevents drilling

for oil and natural gas in most parts of the

Atlantic and Pacific coasts until 2012.{38}

Mississippi: Proved oil reserves decreased

by 23 percent (42 million barrels).

Reserves in

Nonproducing Reservoirs

Not all proved reserves of crude oil were contained in

reservoirs that were producing. Operators reported

4,147 million barrels of proved reserves in

nonproducing reservoirs, 10 percent more than

reported in 1997 (3,755 million barrels).

Nonproducing reserves are those waiting for well

workovers, drilling additional development or

replacement wells, installing production or pipeline

facilities, and awaiting depletion of other zones or

reservoirs before recompletion in reservoirs not

currently open to production.

Indicated Additional Reserves

In addition to proved reserves of crude oil, Category I

and Category II operators estimate the quantities of

crude oil, other than proved reserves, that may become

economically recoverable from known reservoirs

through the application of improved recovery

techniques using currently available technology. The

1998 volume, 3,160 million barrels, is about 1 percent

less than what was reported in 1997 (3,207 million

barrels).

Table 7 lists the indicated additional reserves by

selected States and State subdivisions. The presence of

large indicated additional reserves in Alaska,

California, south Louisiana and west Texas implies that

significant upward revisions to proved crude oil

reserves could occur in the future.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 25
Energy Information Administration

26 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table 7. Reported Indicated Additional Crude Oil Reserves,a 1998

(Million Barrels of 42 U.S. Gallons)

Indicated Indicated

Additional Additional

State and Subdivision Reserves State and Subdivision Reserves

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

Lower 48 States............................. 2,328

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

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

California .................................. 1,297

Coastal Region Onshore . . . . . . . . . . . . . . . . . . . 40

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

San Joaquin Basin Onshore................. 1,257

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

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

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

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

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

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

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

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 309

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

South Onshore . . . . . . . . . . . . . . . . . . . . . . . . . . . 307

State Offshore............................ 2

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

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

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

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

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168

East. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 168

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

North Dakota ............................... 1

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

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

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

Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 400

RRC District 1............................ 0

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

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

RRC District 4 Onshore .................... 0

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

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

RRC District 7B........................... 0

RRC District 7C .......................... 1

RRC District 8. . . . . . . . . . . . . . . . . . . . . . . . . . . . 272

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

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

RRC District 10........................... 0

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

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

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

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Federal Offshore ............................ 7

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

Gulf of Mexico (Louisiana) .................. 7

Gulf of Mexico (Texas) ..................... 0

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

U.S. Total ................................. 3,160

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,” 1998.
4. Natural Gas Statistics

Dry Natural Gas

Proved Reserves

The Nation’s 1998 proved reserves of dry natural gas

were 164,041 billion cubic feet, 2 percent (3,182 billion

cubic feet) less than in 1997 (Table 8). The four-year

increasing trend for U.S. dry natural gas proved

reserves came to an end in 1998.

Additions to dry gas reserves in 1998 were down 22

percent compared to 1997 (19,960 billion cubic feet) and

replaced only 83 percent of gas production (Figure 18).

Upward revisions of gas reserves in Colorado and Utah

were outweighed by declines in reserves in other

gas-producing States. U.S. total discoveries of dry

natural gas reserves were 11,433 billion cubic feet in

1998, down 27 percent from 1997 (15,648 billion cubic

feet). All components of total discoveries for gas

(extensions, new field discoveries, and new reservoir

discoveries in old fields) were down in 1998 compared

to 1997.

Proved reserves by State are shown on the map in

Figure 19. Seven areas account for 76 percent of the

Nation’s dry natural gas proved reserves:

Percent of

Area U.S. Gas Reserves

Texas 23

Gulf of Mexico Federal Offshore 16

New Mexico 9

Wyoming 8

Oklahoma 8

Alaska 6

Louisiana 6

Area Total 76

Of these seven areas, Wyoming and Oklahoma had

increased reserves in 1998, while the other 5 had

decreases in dry natural gas proved reserves.

Discussion of Reserves Changes

Figure 20 maps the change in dry gas proved reserves

from 1997 to 1998 by area. Here’s how the top seven

areas fared, compared to the total United States:

Change in

U.S. Gas Reserves

Area (billion cubic feet)

Texas -177

Gulf of Mexico Federal Offshore -1,500

New Mexico -527

Wyoming +88

Oklahoma +206

Alaska -635

Louisiana -526

Area Total -3,071

U.S. Total -3,182

Figure 4 in Chapter 2 shows the components of the

changes in dry natural gas proved reserves for 1998

and the preceding 10 years.

Revisions and Adjustments

Revisions and adjustments declined to 4,105 billion cubic

feet in 1998, down 5 percent compared to 1997’s level

(4,312 billion cubic feet). Colorado had the largest

increase in revisions and adjustments (1,368 billion cubic

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 27

Figure 18. Reserve Additions Replace only 83% of

1998 U.S. Dry Natural Gas Production.

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

87% 88%

85%

108% 107% 107%

104%

83%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

120%

1991 1992 1993 1994 1995 1996 1997 1998

Percentage of U.S. Gas Production Replaced
Energy Information Administration

28 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table 8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 1998

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

Changes in Reserves During 1998

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/97 (+,-) (+) (-) (+) (+) (+) (-) 12/31/98

Alaska....................... 10,562 -172 169 125 2 4 0 513 9,927

Lower 48 States .............. 156,661 -1,463 27,834 22,138 8,195 1,070 2,162 18,207 154,114

Alabama ..................... 4,968 5 309 313 19 10 0 394 4,604

Arkansas .................... 1,475 -1 596 653 45 0 36 170 1,328

California .................... 2,273 -88 574 328 47 0 12 246 2,244

Coastal Region Onshore . . . . . . 164 -42 44 48 0 0 0 12 106

Los Angeles Basin Onshore . . . 141 -10 39 24 1 0 11 9 149

San Joaquin Basin Onshore . . . 1,912 -44 491 244 46 0 1 217 1,945

State Offshore . . . . . . . . . . . . . . 56 8 0 12 0 0 0 8 44

Colorado..................... 6,828 -93 1,898 437 361 0 0 676 7,881

Florida . . . . . . . . . . . . . . . . . . . . . . 96 -3 0 0 0 0 0 5 88

Kansas ...................... 6,989 -265 501 300 23 1 1 548 6,402

Kentucky..................... 1,364 -93 14 41 20 0 21 63 1,222

Louisiana .................... 9,673 -261 2,173 2,034 631 57 311 1,403 9,147

North ..................... 3,093 -31 833 725 128 0 0 400 2,898

South Onshore.............. 5,855 -145 1,243 1,199 498 45 276 875 5,698

State Offshore . . . . . . . . . . . . . . 725 -85 97 110 5 12 35 128 551

Michigan..................... 2,195 105 538 288 12 6 0 240 2,328

Mississippi . . . . . . . . . . . . . . . . . . . 582 -19 177 112 109 0 0 79 658

Montana . . . . . . . . . . . . . . . . . . . . . 762 -12 119 43 6 1 0 51 782

New Mexico .................. 15,514 -48 2,040 1,882 805 1 6 1,449 14,987

East ...................... 2,642 12 623 439 275 1 6 427 2,693

West...................... 12,872 -60 1,417 1,443 530 0 0 1,022 12,294

New York . . . . . . . . . . . . . . . . . . . . 224 -26 18 7 0 0 25 16 218

North Dakota . . . . . . . . . . . . . . . . . 479 -31 47 27 25 0 0 46 447

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 985 -179 276 118 1 0 19 94 890

Oklahoma.................... 13,439 106 2,995 1,997 600 4 42 1,544 13,645

Pennsylvania ................. 1,852 -9 218 114 19 1 4 131 1,840

Texas ....................... 37,761 -712 7,584 6,334 3,365 249 526 4,855 37,584

RRC District 1 . . . . . . . . . . . . . . 953 138 174 168 108 7 5 113 1,104

RRC District 2 Onshore ....... 1,634 -97 231 257 184 3 135 219 1,614

RRC District 3 Onshore ....... 4,172 -250 1,079 773 378 43 93 781 3,961

RRC District 4 Onshore ....... 8,099 -353 1,601 1,562 1,705 43 219 1,323 8,429

RRC District 5 .............. 1,710 29 689 557 276 17 13 224 1,953

RRC District 6 .............. 5,887 -78 1,439 1,019 313 1 0 594 5,949

RRC District 7B . . . . . . . . . . . . . 478 -47 28 81 0 124 0 60 442

RRC District 7C ............. 3,407 -108 401 304 70 3 0 356 3,113

RRC District 8 .............. 5,397 -133 767 790 121 5 31 541 4,857

RRC District 8A . . . . . . . . . . . . . 847 29 100 106 3 0 0 66 807

RRC District 9 . . . . . . . . . . . . . . 794 -5 100 80 26 0 0 101 734

RRC District 10 ............. 4,094 141 834 560 179 3 0 418 4,273

State Offshore . . . . . . . . . . . . . . 289 22 141 77 2 0 30 59 348

Utah ........................ 1,839 97 645 110 133 0 0 216 2,388

Virginia ...................... 2,446 -495 111 79 45 0 6 61 1,973

West Virginia ................. 2,846 -11 297 180 15 0 71 170 2,868

Wyoming .................... 13,562 -76 1,918 1,774 839 7 12 838 13,650

Federal Offshorea ............. 28,466 663 4,770 4,966 1,075 733 1,070 4,909 26,902

Pacific (California) . . . . . . . . . . . 544 -10 19 43 1 0 6 37 480

Gulf of Mexico (Louisiana)a .... 21,934 598 3,193 3,543 847 583 890 3,728 20,774

Gulf of Mexico (Texas)........ 5,988 75 1,558 1,380 227 150 174 1,144 5,648

Miscellaneousb. . . . . . . . . . . . . . . . 43 -17 16 1 0 0 0 3 38

U.S. Total.................... 167,223 -1,635 28,003 22,263 8,197 1,074 2,162 18,720 164,041

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 1998 contained in the Natural Gas Annual 1998, DOE/EIA-0131(98).

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 29

9,927

2,244

2,388

480

6,402

13,650

14,987

37,584

7,881

782 447

13,645

658

26,422

9,147

1,328

88

2,328

1,222

4,604

890

2,868

1,973

1,840

218

Dry Gas Proved Reserves

1998, Billions of Cubic Feet

10,000 to 37,600 (5)

1,000 to 10,000 (13)

1 to 1,000 (13)

0 to 0 (21)

Five Areas Contain

65 Percent of U.S.

Dry Natural Gas Proved Reserves

U.S. TOTAL:

164.041 Trillion Cubic Feet

Figure 20. Changes in Dry Natural Gas Proved Reserves by Area, 1997 to 1998

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

Figure 19. 1998 Dry Natural Gas Proved Reserves by Area

549

-635

-29

-64

20

206

-32

-177

-527

-587

88

1,053

-142

133

-364

-147

-526

76

-1,500

-12 -95

-6

-8

-473

22

Changes in Dry Natural Gas Reserves by Area

1997 to 1998, Billions of Cubic Feet

100 to 1,060 (4)

1 to 100 (5)

0 to 0 (22)

-100 to 0 (11)

-1,590 to -100 (10)

Dry Gas Reserves Increase Significantly in

Colorado and Utah, but Gains are Outweighed by

Declines in Many Areas, particularly the Gulf of Mexico.

Total U.S. Decline: -3,182 Billion Cubic Feet.
feet). Oklahoma had the second largest with 1,104

billion cubic feet of net revisions and adjustments.

Discoveries

Total discoveries are those reserves attributable to field

extensions, new field discoveries, and new reservoir

discoveries in old fields; they result from drilling

exploratory wells. Total discoveries of dry natural gas

reserves were 11,433 billion cubic feet in 1998, a 27

percent decrease from the level reported in 1997 and

equivalent to 61 percent of 1998 gas production. About

61 percent of the total discoveries were in the Gulf of

Mexico Federal Offshore and Texas.

Extensions were 8,197 billion cubic feet, 23 percent

lower than in 1997. Areas with the largest extensions

and their percentage of total extensions were:

 Texas (41 percent)

 Gulf of Mexico Federal Offshore (13 percent)

 New Mexico (10 percent)

 Wyoming (10 percent)

 Louisiana (8 percent)

 Oklahoma (7 percent).

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

average of 6,909 billion cubic feet of reserves from

extensions per year. Reserves from extensions in 1998

were 19 percent higher than that average volume.

New field discoveries were only 1,074 billion cubic feet in

1998—60 percent lower than in 1997. Those areas with

the largest new field discoveries were the Gulf of Mexico

Federal Offshore (with 68 percent of the total) and

Texas (23 percent). In the prior 10 years, U.S. operators

reported an average of 1,518 billion cubic feet of

reserves from new field discoveries per year. Reserves

from new field discoveries in 1998 were 29 percent lower

than that average.

New reservoir discoveries in old fields were 2,162 billion

cubic feet, 9 percent lower than 1997. Among the areas

with the largest new reservoir discoveries in old fields and

their percentage of the total were:

 Gulf of Mexico Federal Offshore (49 percent)

 Texas (24 percent)

 Louisiana (14 percent).

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

average of 2,318 billion cubic feet of reserves from new

reservoirs discovered in old fields per year. Reserves from

new reservoirs discovered in old fields in 1998 were 7

percent lower than that average volume.

Production

Dry natural gas production decreased 3 percent in 1998

(Table 8). As in 1997, the Gulf of Mexico Federal

Offshore and the State of Texas were the leading

producers of dry natural gas in 1998, each with over

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

combined, Oklahoma (8 percent), New Mexico (8

percent), and Louisiana (7 percent), added almost

another one-fourth of the production.

Wet Natural Gas

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

December 31, 1998, were 172,443 billion cubic feet, a 2

percent decrease from the volume reported in 1997

(Table 9). At year-end 1998 proved wet natural gas

reserves for the lower 48 States had decreased by 2

percent (2,648 billion cubic feet) compared to 1997,

while those of Alaska had decreased by 6 percent (630

billion cubic feet).

The volumetric differences between the estimates

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

the removal of natural gas liquids at natural gas

processing plants. A discussion of the methodology

used to generate wet and dry natural gas reserves

tables in this report is found in Appendix F. All natural

gas proved reserves data shown in this report exclude

natural gas held in underground storage.

Nonassociated Natural Gas

Proved Reserves

Proved reserves of nonassociated (NA) natural gas, wet

after lease separation, in the United States decreased by

1 percent (1,556 billion cubic feet) in 1998 to 141,783

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

wet natural gas proved reserves decreased by 1 percent

to a level of 139,015 billion cubic feet, while Alaska

declined 6 percent to a level of 2,768 billion cubic feet of

NA wet natural gas proved reserves in 1998. Those

areas with the largest increases in NA wet natural gas

reserves were Colorado, Utah, Texas RRC District 4

Onshore, Texas RRC District 5, and Michigan. There

were large decreases in NA wet natural gas reserves in

Energy Information Administration

30 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 31

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

1998 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 1998 Proved Reserves 12/31/98

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 12/31/97 (+,–) (+) (–) (+) (+) (+) (–) Total Gas Gas Gas

Alaska ..................... 10,673 -163 170 125 2 4 0 518 10,043 2,768 7,275

Lower 48 States ............. 165,048 -1,461 29,231 23,294 8,628 1,112 2,240 19,104 162,400 139,015 23,385

Alabama.................... 5,013 4 312 316 19 10 0 399 4,643 4,615 28

Arkansas ................... 1,479 0 597 655 45 0 36 170 1,332 1,294 38

California ................... 2,390 -117 598 345 48 0 13 255 2,332 453 1,879

Coastal Region Onshore . . . . 176 -40 49 54 0 0 0 13 118 2 116

Los Angeles Basin Onshore . 146 -11 40 25 1 0 12 9 154 1 153

San Joaquin Basin Onshore . 2,012 -74 509 254 47 0 1 225 2,016 445 1,571

State Offshore . . . . . . . . . . . . 56 8 0 12 0 0 0 8 44 5 39

Colorado ................... 7,160 -162 2,006 461 366 0 0 701 8,208 7,436 772

Florida . . . . . . . . . . . . . . . . . . . . . 112 0 0 0 0 0 0 6 106 0 106

Kansas..................... 7,328 -120 537 322 24 1 2 588 6,862 6,802 60

Kentucky ................... 1,429 -83 15 43 21 0 23 67 1,295 1,275 20

Louisiana ................... 10,036 -287 2,250 2,105 656 59 326 1,455 9,480 8,569 911

North ................... 3,156 -48 847 736 130 0 0 406 2,943 2,760 183

South Onshore............ 6,137 -159 1,302 1,255 521 47 289 916 5,966 5,336 630

State Offshore . . . . . . . . . . . . 743 -80 101 114 5 12 37 133 571 473 98

Michigan ................... 2,256 100 552 294 12 6 0 246 2,386 2,158 228

Mississippi . . . . . . . . . . . . . . . . . . 583 -18 178 112 110 0 0 79 662 615 47

Montana. . . . . . . . . . . . . . . . . . . . 769 -12 120 44 6 1 0 51 789 737 52

New Mexico ................. 16,700 77 2,200 2,067 896 1 7 1,555 16,259 14,816 1,443

East .................... 3,008 -15 703 495 311 1 7 481 3,039 1,694 1,345

West.................... 13,692 92 1,497 1,572 585 0 0 1,074 13,220 13,122 98

New York . . . . . . . . . . . . . . . . . . . 224 -26 18 7 0 0 25 16 218 217 1

North Dakota . . . . . . . . . . . . . . . . 531 -29 52 30 28 0 0 51 501 240 261

Ohio . . . . . . . . . . . . . . . . . . . . . . . 985 -178 276 118 1 0 19 95 890 548 342

Oklahoma .................. 14,311 99 3,187 2,125 638 5 44 1,642 14,517 13,321 1,196

Pennsylvania ................ 1,861 -11 219 115 20 1 4 131 1,848 1,769 79

Texas ...................... 41,108 -790 8,150 6,824 3,561 273 557 5,242 40,793 33,429 7,364

RRC District 1 ............ 1,018 120 181 175 113 7 5 117 1,152 1,101 51

RRC District 2 Onshore ..... 1,732 -93 246 274 196 3 144 234 1,720 1,516 204

RRC District 3 Onshore ..... 4,418 -256 1,145 820 402 45 100 829 4,205 3,275 930

RRC District 4 Onshore ..... 8,483 -371 1,676 1,636 1,784 45 229 1,386 8,824 8,430 394

RRC District 5 ............ 1,749 26 704 568 282 17 13 228 1,995 1,906 89

RRC District 6 ............ 6,194 -73 1,517 1,074 331 1 1 626 6,271 5,691 580

RRC District 7B . . . . . . . . . . . 559 -62 33 94 0 143 0 69 510 306 204

RRC District 7C ........... 3,843 -139 450 341 79 4 0 400 3,496 2,939 557

RRC District 8 ............ 6,030 -15 875 902 137 5 35 618 5,547 2,727 2,820

RRC District 8A ........... 1,247 -35 137 147 5 0 0 92 1,115 18 1,097

RRC District 9 . . . . . . . . . . . . 932 -5 118 93 31 0 0 119 864 665 199

RRC District 10 ........... 4,613 90 926 622 199 3 0 465 4,744 4,510 234

State Offshore . . . . . . . . . . . . 290 23 142 78 2 0 30 59 350 345 5

Utah ....................... 2,005 29 674 117 139 0 0 228 2,502 2,293 209

Virginia..................... 2,446 -495 111 79 45 0 6 61 1,973 1,973 0

West Virginia ................ 2,946 -12 307 186 16 0 73 176 2,968 2,925 43

Wyoming ................... 14,321 -104 2,006 1,869 880 7 13 883 14,371 13,577 794

Federal Offshorea ............ 29,011 691 4,850 5,059 1,097 748 1,092 5,004 27,426 19,931 7,495

Pacific (California) . . . . . . . . . 556 -12 19 44 1 0 6 37 489 52 437

Gulf of Mexico (Louisiana)a . . 22,428 637 3,265 3,629 868 598 911 3,817 21,261 15,427 5,834

Gulf of Mexico (Texas)...... 6,027 66 1,566 1,386 228 150 175 1,150 5,676 4,452 1,224

Miscellaneous . . . . . . . . . . . . . . . 44 -17 16 1 0 0 0 3 39 22 17

U.S. Total .................. 175,721 -1,624 29,401 23,419 8,630 1,116 2,240 19,622 172,443 141,783 30,660

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 1998 contained in the Natural Gas Annual 1998, DOE/EIA-0131(98).

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

32 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

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

Lease Separation, 1998

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

Changes in Reserves During 1998

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/97 (+,-) (+) (-) (+) (+) (+) (-) 12/31/98

Alaska....................... 2,957 -14 105 77 1 0 0 204 2,768

Lower 48 States .............. 140,382 -904 24,291 19,405 7,902 1,009 2,022 16,282 139,015

Alabama ..................... 4,983 1 301 308 19 10 0 391 4,615

Arkansas .................... 1,423 3 582 638 45 0 36 157 1,294

California . . . . . . . . . . . . . . . . . . . . 570 -43 73 102 5 0 1 51 453

Coastal Region Onshore . . . . . . 47 -46 1 0 0 0 0 0 2

Los Angeles Basin Onshore . . . 3 0 0 3 1 0 0 0 1

San Joaquin Basin Onshore . . . 518 -1 72 99 4 0 1 50 445

State Offshore .............. 2 4 0 0 0 0 0 1 5

Colorado..................... 6,627 -159 1,658 404 361 0 0 647 7,436

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

Kansas ...................... 7,277 -118 509 313 21 1 2 577 6,802

Kentucky..................... 1,403 -82 15 40 21 0 23 65 1,275

Louisiana .................... 9,020 -278 1,868 1,718 621 43 298 1,285 8,569

North ..................... 2,869 -129 774 525 116 0 0 345 2,760

South Onshore.............. 5,538 -91 1,010 1,094 500 36 264 827 5,336

State Offshore . . . . . . . . . . . . . . 613 -58 84 99 5 7 34 113 473

Michigan..................... 1,975 94 506 218 10 6 0 215 2,158

Mississippi . . . . . . . . . . . . . . . . . . . 532 -12 157 100 110 0 0 72 615

Montana . . . . . . . . . . . . . . . . . . . . . 727 -13 106 37 0 0 0 46 737

New Mexico .................. 15,280 57 1,824 1,818 809 1 2 1,339 14,816

East ...................... 1,694 -3 340 290 225 1 2 275 1,694

West...................... 13,586 60 1,484 1,528 584 0 0 1,064 13,122

New York . . . . . . . . . . . . . . . . . . . . 223 -26 18 7 0 0 25 16 217

North Dakota . . . . . . . . . . . . . . . . . 274 -17 10 10 0 0 0 17 240

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 594 -164 221 78 1 0 16 42 548

Oklahoma.................... 13,296 -27 2,808 1,899 603 5 41 1,506 13,321

Pennsylvania ................. 1,769 -2 213 105 12 1 4 123 1,769

Texas ....................... 33,322 -739 6,783 5,672 3,337 268 526 4,396 33,429

RRC District 1 . . . . . . . . . . . . . . 950 114 173 151 113 7 5 110 1,101

RRC District 2 Onshore ....... 1,497 -72 220 257 191 3 144 210 1,516

RRC District 3 Onshore ....... 3,539 -211 816 727 354 43 97 636 3,275

RRC District 4 Onshore ....... 8,115 -357 1,584 1,616 1,734 45 229 1,304 8,430

RRC District 5 .............. 1,681 40 657 563 282 17 9 217 1,906

RRC District 6 .............. 5,616 -127 1,465 994 323 1 1 594 5,691

RRC District 7B . . . . . . . . . . . . . 299 -35 14 69 0 143 0 46 306

RRC District 7C ............. 3,247 -126 339 264 70 2 0 329 2,939

RRC District 8 .............. 2,886 -38 486 317 44 4 11 349 2,727

RRC District 8A . . . . . . . . . . . . . 41 -28 16 3 0 0 0 8 18

RRC District 9 . . . . . . . . . . . . . . 785 -4 34 84 29 0 0 95 665

RRC District 10 ............. 4,386 81 841 557 195 3 0 439 4,510

State Offshore . . . . . . . . . . . . . . 280 24 138 70 2 0 30 59 345

Utah ........................ 1,695 31 664 31 138 0 0 204 2,293

Virginia ...................... 1,923 28 111 79 45 0 6 61 1,973

West Virginia ................. 2,887 -8 305 176 16 0 73 172 2,925

Wyoming .................... 13,471 -133 1,930 1,739 832 1 8 793 13,577

Federal Offshorea ............. 21,098 698 3,623 3,913 896 673 961 4,105 19,931

Pacific (California) . . . . . . . . . . . 58 0 1 6 0 0 1 2 52

Gulf of Mexico (Louisiana)a .... 16,241 533 2,479 2,762 681 523 786 3,054 15,427

Gulf of Mexico (Texas)........ 4,799 165 1,143 1,145 215 150 174 1,049 4,452

Miscellaneous. . . . . . . . . . . . . . . . . 13 5 6 0 0 0 0 2 22

U.S. Total.................... 143,339 -918 24,396 19,482 7,903 1,009 2,022 16,486 141,783

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 1998 contained in the

Natural Gas Annual 1998, DOE/EIA-0131(98).

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 33

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

Wet After Lease Separation, 1998

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

Changes in Reserves During 1998

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/97 (+,-) (+) (-) (+) (+) (+) (-) 12/31/98

Alaska....................... 7,716 -149 65 48 1 4 0 314 7,275

Lower 48 States .............. 24,666 -557 4,940 3,889 726 103 218 2,822 23,385

Alabama . . . . . . . . . . . . . . . . . . . . . 30 3 11 8 0 0 0 8 28

Arkansas . . . . . . . . . . . . . . . . . . . . 56 -3 15 17 0 0 0 13 38

California .................... 1,820 -74 525 243 43 0 12 204 1,879

Coastal Region Onshore . . . . . . 129 6 48 54 0 0 0 13 116

Los Angeles Basin Onshore . . . 143 -11 40 22 0 0 12 9 153

San Joaquin Basin Onshore . . . 1,494 -73 437 155 43 0 0 175 1,571

State Offshore . . . . . . . . . . . . . . 54 4 0 12 0 0 0 7 39

Colorado. . . . . . . . . . . . . . . . . . . . . 533 -3 348 57 5 0 0 54 772

Florida . . . . . . . . . . . . . . . . . . . . . . 112 0 0 0 0 0 0 6 106

Kansas . . . . . . . . . . . . . . . . . . . . . . 51 -2 28 9 3 0 0 11 60

Kentucky. . . . . . . . . . . . . . . . . . . . . 26 -1 0 3 0 0 0 2 20

Louisiana .................... 1,016 -9 382 387 35 16 28 170 911

North . . . . . . . . . . . . . . . . . . . . . 287 81 73 211 14 0 0 61 183

South Onshore. . . . . . . . . . . . . . 599 -68 292 161 21 11 25 89 630

State Offshore . . . . . . . . . . . . . . 130 -22 17 15 0 5 3 20 98

Michigan. . . . . . . . . . . . . . . . . . . . . 281 6 46 76 2 0 0 31 228

Mississippi . . . . . . . . . . . . . . . . . . . 51 -6 21 12 0 0 0 7 47

Montana . . . . . . . . . . . . . . . . . . . . . 42 1 14 7 6 1 0 5 52

New Mexico .................. 1,420 20 376 249 87 0 5 216 1,443

East ...................... 1,314 -12 363 205 86 0 5 206 1,345

West. . . . . . . . . . . . . . . . . . . . . . 106 32 13 44 1 0 0 10 98

New York .................... 1 0 0 0 0 0 0 0 1

North Dakota . . . . . . . . . . . . . . . . . 257 -12 42 20 28 0 0 34 261

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 391 -14 55 40 0 0 3 53 342

Oklahoma.................... 1,015 126 379 226 35 0 3 136 1,196

Pennsylvania . . . . . . . . . . . . . . . . . 92 -9 6 10 8 0 0 8 79

Texas ....................... 7,786 -51 1,367 1,152 224 5 31 846 7,364

RRC District 1 . . . . . . . . . . . . . . 68 6 8 24 0 0 0 7 51

RRC District 2 Onshore . . . . . . . 235 -21 26 17 5 0 0 24 204

RRC District 3 Onshore . . . . . . . 879 -45 329 93 48 2 3 193 930

RRC District 4 Onshore . . . . . . . 368 -14 92 20 50 0 0 82 394

RRC District 5 . . . . . . . . . . . . . . 68 -14 47 5 0 0 4 11 89

RC District 6. . . . . . . . . . . . . . . . 578 54 52 80 8 0 0 32 580

RRC District 7B . . . . . . . . . . . . . 260 -27 19 25 0 0 0 23 204

RRC District 7C . . . . . . . . . . . . . 596 -13 111 77 9 2 0 71 557

RRC District 8 .............. 3,144 23 389 585 93 1 24 269 2,820

RRC District 8A ............. 1,206 -7 121 144 5 0 0 84 1,097

RRC District 9 . . . . . . . . . . . . . . 147 -1 84 9 2 0 0 24 199

RRC District 10 . . . . . . . . . . . . . 227 9 85 65 4 0 0 26 234

State Offshore . . . . . . . . . . . . . . 10 -1 4 8 0 0 0 0 5

Utah . . . . . . . . . . . . . . . . . . . . . . . . 310 -2 10 86 1 0 0 24 209

Virginia . . . . . . . . . . . . . . . . . . . . . . 523 -523 0 0 0 0 0 0 0

West Virginia . . . . . . . . . . . . . . . . . 59 -4 2 10 0 0 0 4 43

Wyoming . . . . . . . . . . . . . . . . . . . . 850 29 76 130 48 6 5 90 794

Federal Offshorea ............. 7,913 -7 1,227 1,146 201 75 131 899 7,495

Pacific (California) . . . . . . . . . . . 498 -12 18 38 1 0 5 35 437

Gulf of Mexico (Louisiana)a .... 6,187 104 786 867 187 75 125 763 5,834

Gulf of Mexico (Texas)........ 1,228 -99 423 241 13 0 1 101 1,224

Miscellaneousb. . . . . . . . . . . . . . . . 31 -22 10 1 0 0 0 1 17

U.S. Total.................... 32,382 -706 5,005 3,937 727 107 218 3,136 30,660

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 1998 contained in the

Natural Gas Annual 1998, DOE/EIA-0131(98).

Source: Energy Information Administration, Office of Oil and Gas.
the Gulf of Mexico Federal Offshore, Kansas, New

Mexico, Louisiana, and Alabama.

Discoveries

NA wet natural gas total discoveries of 10,934 billion

cubic feet decreased 20 percent (2,784 billion cubic feet)

in 1998. Texas, the Gulf of Mexico Federal Offshore,

Louisiana, Wyoming, and New Mexico and accounted

for 9,275 billion cubic feet or 85 percent of U.S. NA wet

natural gas total discoveries in 1998.

Production

U.S. production of NA wet natural gas decreased by 4

percent (626 billion cubic feet) in 1998 (Table 10). The

five leading producing areas, Texas, the Gulf of Mexico

Federal Offshore, Oklahoma, New Mexico and

Louisiana, all reported production declines in 1998. As

in 1997, Texas (with 27 percent of 1998 U.S. NA gas

production) and the Gulf of Mexico Federal Offshore

(with 25 percent) were the leading producers of NA

wet natural gas in 1998.

Associated-Dissolved Natural Gas

Proved Reserves

Proved reserves of associated-dissolved (AD) natural

gas, wet after lease separation, in the United States

decreased by 5 percent (1,722 billion cubic feet) to

30,660 billion cubic feet in 1998 (Table 11). Proved

reserves of AD wet natural gas in the lower 48 States

decreased by 5 percent (1,281 billion cubic feet) to

23,385 billion cubic feet, and Alaska declined 6 percent

to 7,275 billion cubic feet in 1998. Those areas of the

country with the largest AD wet natural gas reserves

and their percentage of the total were:

 Texas (24 percent)

 Alaska (24 percent)

 Gulf of Mexico Federal Offshore (23 percent)

 California (6 percent)

 New Mexico (5 percent).

These areas logically correspond to the areas of the

country with the largest volumes of crude oil reserves.

Production

U.S. production of AD wet natural gas increased by 4

percent in 1998 (Table 11), and production of AD wet

natural gas in the lower 48 States increased by 3 percent

(70 billion cubic feet). Those areas of the country with

the largest AD wet natural gas production and their

percentage of the total were:

 Gulf of Mexico Federal Offshore (28 percent)

 Texas (27 percent)

 Alaska (10 percent)

 New Mexico (7 percent)

 California (7 percent).

Again, these areas logically correspond to the areas of

the country with the largest volumes of crude oil

production.

Coalbed Methane

Proved Reserves

In 1998, reserves of coalbed methane increased 6

percent to 12,179 billion cubic feet from 1997’s level

(11,462 billion cubic feet), and now account for 7

percent of all 1998 dry natural gas reserves (Table 12).

Federal tax incentives for new coalbed methane wells

expired at the end of 1992. The EIA estimates that the

1998 proved gas reserves of fields identified as having

Energy Information Administration

34 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

U.S. Coalbed Methane Reserves

0

2

4

6

8

10

12

14

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998

Trillion Cubic Feet

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

Figure 21. Coalbed Methane Proved Reserves

1989-1998
coalbed methane are now more than triple the volume

reported in 1989 (Figure 21). Coalbed methane proved

reserves are principally located in New Mexico,

Colorado, and Alabama. Estimates of proved coalbed

methane reserves increased in Colorado and Alabama,

but decreased slightly in New Mexico in 1998.

Production

Coalbed methane production grew by about 10 percent

in 1998 to 1,194 billion cubic feet—about 6 percent of

U.S. dry gas production. Most of the 1998 production

increase (104 billion cubic feet) occurred in Colorado

(the San Juan Basin).

Areas of Note:

Large Discoveries and

Reserves Additions

The following State or area discussions summarize

notable activities during the year concerning expected

new field reserves, development plans, and possible

production rates as extracted from various trade

publications and company reports. The citations do not

necessarily reflect EIA’s concurrence, but are

considered important enough to be brought to the

reader’s attention.

Colorado

Colorado had a net increase of 1,053 billion cubic feet of

dry natural gas proved reserves in 1998. The largest net

gas reserves increase of all States in 1998, it was mostly

from net revisions.

Development of existing fields in the Piceance and

Denver - Julesburg Basins - mostly done through less

expensive recompletions, rather than more expensive

new wells—boosted the reserves additions for this

State.

Utah

Utah had a net increase of 549 billion cubic feet of dry

natural gas proved reserves in 1998. This was the result

of development of large existing coalbed methane

fields and gas fields within the Uinta Basin.

Texas

Although the State of Texas had a net decline in dry

natural gas proved reserves in 1998, the largest volume

of new discoveries in 1998 was nevertheless made

there.

South Texas: As in 1997, operators remain active in the

Lobo Trend in the lower Rio Grande Valley of south

Texas (RRC District 4). The trend occurs primarily in

Webb and Zapata counties and contains the four

producing horizons, Wilcox, Expanded Wilcox, Frio,

and Lobo. Unlike some other parts of the country, one

or two fields do not dominate the area. RRC District 4

increased its dry natural gas reserves by 330 billion

cubic feet in 1998. Operators in RRC District 4 reported

more extensions (51 percent of the State total) than any

other district in Texas. This district accounts for 22

percent of all of the reserves of dry natural gas in the

State and leads the State in gas production (27 percent

of the State total). RRC District 4’s dry gas production

increased 2 percent in 1998.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 35

Table 12. U.S. Coalbed Methane Proved Reserves and Production, 1991-1998

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

Alabama Colorado New Mexico Othersa Total

Year Reserves Production Reserves Production Reserves Production Reserves Production Reserves Production

1991 1,714 68 2,076 48 4,206 229 167 3 8,163 348

1992 1,968 89 2,716 82 4,724 358 626 10 10,034 539

1993 1,237 103 3,107 125 4,775 486 1,065 18 10,184 752

1994 976 108 2,913 179 4,137 530 1,686 34 9,712 851

1995 972 109 3,461 226 4,299 574 1,767 47 10,499 956

1996 823 98 3,711 274 4,180 575 1,852 56 10,566 1,003

1997 1,077 111 3,890 312 4,351 597 2,144 70 11,462 1,090

1998 1,029 123 4,211 401 4,232 571 2,707 99 12,179 1,194

aIncludes Oklahoma, Pennsylvania, Utah, Virginia, West Virginia, and Wyoming.

Source: Energy Information Administration, Office of Oil and Gas.
Similarly, RRC District 5 had an increase in dry natural

gas reserves of 243 billion cubic feet in 1998—mostly

from extensions of existing gas fields and revisions. RRC

District 5’s dry gas production increased 2 percent in

1998.

Oklahoma

Oklahoma had a net increase of 206 billion cubic feet of

dry natural gas proved reserves in 1998. It was third

overall in State total dry gas reserves additions. About

two-thirds of Oklahoma’s gain was from net revisions

and adjustments of existing fields, but a large volume

of reported extensions also boosted Oklahoma’s total in

1998.

Areas of Note:

Large Reserves Declines

The following areas had large declines in dry natural

gas proved reserves due to downward revisions or

unreplaced production.

Gulf of Mexico Federal Offshore

This area’s proved dry natural gas reserves decreased

by 5 percent (1,500 billion cubic feet) in 1998. Dry gas

production from the Gulf of Mexico Federal Offshore

declined by 5 percent (261 billion cubic feet) from 1997

to 1998.

Alaska

This State’s proved dry natural gas reserves decreased

by 6 percent (635 billion cubic feet) in 1998.

Kansas

This State’s proved dry natural gas reserves decreased

by 8 percent (587 billion cubic feet) in 1998.

New Mexico

This State’s proved dry natural gas reserves decreased

by 3 percent (527 billion cubic feet) in 1998.

Reserves in

Nonproducing Reservoirs

Nonproducing proved natural gas reserves (wet after

lease separation) of 36,047 billion cubic feet were

reported in 1998 (Appendix D, Table D10). This was 9

percent (2,923 billion cubic feet) more gas than in 1997.

About 33 percent of the reserves in nonproducing

reservoirs are located in the Gulf of Mexico Federal

Offshore area. Much of the new deepwater reserves are

in the nonproducing category. Wells or reservoirs are

nonproducing due to any of several operational

reasons. These include:

 waiting for well workovers

 waiting for additional development or

replacement wells to be drilled

 production or pipeline facilities not yet installed

 awaiting depletion of other zones or reservoirs

before recompletion in reservoirs not currently

open to production (called “behind pipe”

reserves).

Energy Information Administration

36 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
5. Natural Gas Liquids Statistics

Natural Gas Liquids

Proved Reserves

U.S. natural gas liquids proved reserves decreased 6

percent to 7,524 million barrels in 1998 (Table 13). A

reassessment of natural gas liquids in Alaska

represents the bulk of the 1998 change. Reserve

additions replaced only 46 percent of 1998 natural gas

liquids production.

The reserves of six areas account for 81 percent of the

Nation’s natural gas liquids proved reserves.

Percent of

Area U.S. NGL Reserves

Texas 34

Gulf of Mexico Federal Offshore 12

New Mexico 12

Utah-Wyoming 9

Oklahoma 9

Louisiana 5

Area Total 81

The volumes of natural gas liquids proved reserves and

production shown in Table 13 are the sum of the

natural gas plant liquid volumes listed in Table 14 and

the lease condensate volumes listed in Table 15.

Discoveries

Total discoveries of natural gas liquids reserves

decreased by 27 percent from 1997 to 1998. Areas with

the largest total discoveries were:

 Texas (39 percent)

 Gulf of Mexico Federal Offshore (21 percent)

 New Mexico (13 percent)

 Louisiana (11 percent)

 Utah and Wyoming (7 percent)

 Oklahoma (6 percent).

New field discoveries in 1998 (66 million barrels) were 42

percent lower than in 1997. Areas with the largest new

field discoveries were the Gulf of Mexico Federal

Offshore (56 percent of 1998 new field discoveries) and

Texas (32 percent).

New reservoir discoveries in old fields (88 million barrels)

were 2 percent less than what they were in 1997. Areas

with the largest new reservoir discoveries in old fields were

the Gulf of Mexico Federal Offshore (44 percent of 1998

new reservoir discoveries in old fields), Texas (28

percent), and Louisiana (20 percent).

Extensions were 383 million barrels, a decrease of 28

percent from 1997 to 1998. Areas with the largest

extensions were Texas (43 percent of 1998 extensions),

New Mexico (18 percent), Utah-Wyoming (10 percent),

and the Gulf of Mexico Federal Offshore (10 percent).

Production

Natural gas liquids production was an estimated 833

million barrels in 1998. Alaska production decreased 31

percent to 24 million barrels in 1998, while lower 48

States production decreased 2 percent to 809 million

barrels in 1998.

Six areas accounted for about 87 percent of the Nation’s

natural gas liquids production.

 Texas (38 percent)

 Gulf of Mexico Federal Offshore (17 percent)

 New Mexico (9 percent)

 Oklahoma (9 percent)

 Louisiana (8 percent)

 Utah-Wyoming (6 percent).

Natural Gas Plant Liquids

Proved Reserves

Natural gas plant liquids proved reserves decreased 7

percent in 1998 to 6,188 million barrels (Table 14). Six

areas accounted for about 82 percent of the Nation’s

natural gas plant liquids proved reserves:

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 37
Energy Information Administration

38 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table 13. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 1998

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 1998

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/97 (+,-) (+) (-) (+) (+) (+) (-) 12/31/98

Alaska. . . . . . . . . . . . . . . . . . . . . . . 631 -287 1 1 0 0 0 24 320

Lower 48 States .............. 7,342 -74 1,301 1,093 383 66 88 809 7,204

Alabama . . . . . . . . . . . . . . . . . . . . . 93 0 4 8 0 0 0 8 81

Arkansas .................... 7 0 1 3 0 0 0 0 5

California . . . . . . . . . . . . . . . . . . . . 95 -20 20 17 1 0 0 7 72

Coastal Region Onshore ...... 9 1 4 4 0 0 0 1 9

Los Angeles Basin Onshore . . . 4 1 1 1 0 0 0 0 5

San Joaquin Basin Onshore . . . 82 -22 15 12 1 0 0 6 58

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

Colorado. . . . . . . . . . . . . . . . . . . . . 264 -54 86 20 4 0 0 20 260

Florida . . . . . . . . . . . . . . . . . . . . . . 17 2 0 0 0 0 0 1 18

Kansas . . . . . . . . . . . . . . . . . . . . . . 271 81 27 18 1 0 0 28 334

Kentucky. . . . . . . . . . . . . . . . . . . . . 48 8 1 2 1 0 1 3 54

Louisiana . . . . . . . . . . . . . . . . . . . . 437 -36 103 85 33 7 18 66 411

North . . . . . . . . . . . . . . . . . . . . . 80 -24 22 15 2 0 0 8 57

South Onshore. . . . . . . . . . . . . . 333 -12 69 66 31 6 17 53 325

State Offshore . . . . . . . . . . . . . . 24 0 12 4 0 1 1 5 29

Michigan. . . . . . . . . . . . . . . . . . . . . 50 -1 13 7 0 1 0 5 51

Mississippi ................... 6 4 2 4 1 0 0 1 8

Montana . . . . . . . . . . . . . . . . . . . . . 5 -1 1 0 0 0 0 0 5

New Mexico . . . . . . . . . . . . . . . . . . 869 84 121 135 68 0 1 79 929

East . . . . . . . . . . . . . . . . . . . . . . 273 -18 63 43 28 0 1 42 262

West. . . . . . . . . . . . . . . . . . . . . . 596 102 58 92 40 0 0 37 667

North Dakota . . . . . . . . . . . . . . . . . 47 1 4 2 2 0 0 4 48

Oklahoma. . . . . . . . . . . . . . . . . . . . 685 1 166 109 32 0 2 79 698

Texas ....................... 2,687 -90 479 425 163 21 25 316 2,544

RRC District 1 . . . . . . . . . . . . . . 54 -15 6 6 3 0 0 4 38

RRC District 2 Onshore . . . . . . . 87 -1 13 15 9 0 6 14 85

RRC District 3 Onshore . . . . . . . 286 -18 64 66 20 3 6 49 246

RRC District 4 Onshore . . . . . . . 347 -17 75 69 71 2 10 56 363

RRC District 5 . . . . . . . . . . . . . . 35 -4 13 10 5 0 0 4 35

RRC District 6 . . . . . . . . . . . . . . 260 7 72 51 16 0 0 28 276

RRC District 7B . . . . . . . . . . . . . 59 -11 3 10 0 16 0 6 51

RRC District 7C . . . . . . . . . . . . . 327 -27 38 29 7 0 0 34 282

RRC District 8 . . . . . . . . . . . . . . 459 72 79 80 13 0 3 55 491

RRC District 8A . . . . . . . . . . . . . 290 -44 28 30 1 0 0 19 226

RRC District 9 . . . . . . . . . . . . . . 98 2 13 10 3 0 0 13 93

RRC District 10 . . . . . . . . . . . . . 382 -32 71 48 15 0 0 34 354

State Offshore . . . . . . . . . . . . . . 3 -2 4 1 0 0 0 0 4

Utah and Wyoming. . . . . . . . . . . . . 761 -85 99 91 39 0 0 48 675

West Virginia . . . . . . . . . . . . . . . . . 71 0 7 4 0 0 2 4 72

Federal Offshorea . . . . . . . . . . . . . 920 35 165 163 38 37 39 140 931

Pacific (California) . . . . . . . . . . . 14 0 0 1 0 0 0 1 12

Gulf of Mexico (Louisiana)a . . . . 785 17 132 130 31 34 27 120 776

Gulf of Mexico (Texas). . . . . . . . 121 18 33 32 7 3 12 19 143

Miscellaneousb. . . . . . . . . . . . . . . . 9 -3 2 0 0 0 0 0 8

U.S. Total.................... 7,973 -361 1,302 1,094 383 66 88 833 7,524

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 1998 contained in the publications Petroleum Supply

Annual 1998, DOE/EIA-0340(98) and Natural Gas Annual 1998 DOE/EIA-0131(98).

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 39

Table 14. Natural Gas Plant Liquids Proved Reserves and Production, 1998

(Million Barrels of 42 U.S. Gallons)

1998 1998 1998 1998

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska . . . . . . . . . . . . . . . . . . . . . . 320 24

Lower 48 States.............. 5,868 631

Alabama . . . . . . . . . . . . . . . . . . . . 31 4

Arkansas .................... 3 0

California. . . . . . . . . . . . . . . . . . . . 71 7

Coastal Region Onshore ..... 9 1

Los Angeles Basin Onshore . . . 5 0

San Joaquin Basin Onshore. . . 57 6

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

Colorado . . . . . . . . . . . . . . . . . . . . 235 18

Florida . . . . . . . . . . . . . . . . . . . . . . 18 1

Kansas . . . . . . . . . . . . . . . . . . . . . 331 28

Kentucky . . . . . . . . . . . . . . . . . . . . 53 3

Louisiana. . . . . . . . . . . . . . . . . . . . 234 37

North. . . . . . . . . . . . . . . . . . . . . 34 5

South Onshore . . . . . . . . . . . . . 187 29

State Offshore. . . . . . . . . . . . . . 13 3

Michigan . . . . . . . . . . . . . . . . . . . . 43 4

Mississippi................... 3 0

Montana .................... 5 0

New Mexico . . . . . . . . . . . . . . . . . 876 74

East . . . . . . . . . . . . . . . . . . . . . 243 39

West . . . . . . . . . . . . . . . . . . . . . 633 35

North Dakota. . . . . . . . . . . . . . . . . 41 4

Oklahoma . . . . . . . . . . . . . . . . . . . 613 69

Texas ...................... 2,262 270

RRC District 1. . . . . . . . . . . . . . 32 5

RRC District 2 Onshore . . . . . . 75 10

RRC District 3 Onshore . . . . . . 169 33

RRC District 4 Onshore . . . . . . 267 42

RRC District 5. . . . . . . . . . . . . . 31 4

RRC District 6. . . . . . . . . . . . . . 235 23

RRC District 7B. . . . . . . . . . . . . 48 6

RRC District 7C . . . . . . . . . . . . 266 31

RRC District 8. . . . . . . . . . . . . . 479 53

RRC District 8A. . . . . . . . . . . . . 226 19

RRC District 9. . . . . . . . . . . . . . 91 13

RRC District 10. . . . . . . . . . . . . 342 33

State Offshore.............. 1 0

Utah and Wyoming . . . . . . . . . . . . 600 40

West Virginia. . . . . . . . . . . . . . . . . 71 4

Federal Offshorea . . . . . . . . . . . . . 370 68

Pacific (California)........... 8 1

Gulf of Mexico (Louisiana)a . . . 341 63

Gulf of Mexico (Texas) . . . . . . . 21 4

Miscellaneousb ............... 8 0

U.S. Total ................... 6,188 655

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 1998 contained in the publications Petroleum Supply Annual 1998,

DOE/EIA-0340(98) and Natural Gas Annual 1998, DOE/EIA-0131(98).

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

40 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table 15. Lease Condensate Proved Reserves and Production, 1998

(Million Barrels of 42 U.S. Gallons)

1998 1998 1998 1998

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska ...................... 0 0

Lower 48 States.............. 1,336 178

Alabama . . . . . . . . . . . . . . . . . . . . 50 4

Arkansas .................... 2 0

California.................... 1 0

Coastal Region Onshore ..... 0 0

Los Angeles Basin Onshore . . . 0 0

San Joaquin Basin Onshore. . . 1 0

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

Colorado . . . . . . . . . . . . . . . . . . . . 25 2

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

Kansas ..................... 3 0

Kentucky .................... 1 0

Louisiana. . . . . . . . . . . . . . . . . . . . 177 29

North. . . . . . . . . . . . . . . . . . . . . 23 3

South Onshore . . . . . . . . . . . . . 138 24

State Offshore. . . . . . . . . . . . . . 16 2

Michigan .................... 8 1

Mississippi................... 5 1

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

New Mexico . . . . . . . . . . . . . . . . . 53 5

East . . . . . . . . . . . . . . . . . . . . . 19 3

West . . . . . . . . . . . . . . . . . . . . . 34 2

North Dakota................. 7 0

Oklahoma . . . . . . . . . . . . . . . . . . . 85 10

Texas . . . . . . . . . . . . . . . . . . . . . . 282 46

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

RRC District 2 Onshore . . . . . . 10 4

RRC District 3 Onshore . . . . . . 77 16

RRC District 4 Onshore . . . . . . 96 14

RRC District 5.............. 4 0

RRC District 6. . . . . . . . . . . . . . 41 5

RRC District 7B............. 3 0

RRC District 7C . . . . . . . . . . . . 16 3

RRC District 8. . . . . . . . . . . . . . 12 2

RRC District 8A............. 0 0

RRC District 9.............. 2 0

RRC District 10. . . . . . . . . . . . . 12 1

State Offshore.............. 3 0

Utah and Wyoming . . . . . . . . . . . . 75 8

West Virginia................. 1 0

Federal Offshorea . . . . . . . . . . . . . 561 72

Pacific (California)........... 4 0

Gulf of Mexico (Louisiana)a . . . 435 57

Gulf of Mexico (Texas) . . . . . . . 122 15

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

U.S. Total ................... 1,336 178

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” 1998.

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

Area U.S. Gas Plant Liquids

Texas 37

New Mexico 14

Utah-Wyoming 10

Oklahoma 10

Gulf of Mexico Federal Offshore 6

Kansas 5

Area Total 82

Production

Natural gas plant liquids production decreased 5

percent in 1998—from 690 million barrels in 1997 to 655

million barrels of production (Table 14). The top six

areas for proved reserves of natural gas plant liquids

accounted for about 83 percent of the Nation’s natural

gas plant liquids production:

 Texas (41 percent)

 New Mexico (11 percent)

 Oklahoma (11 percent)

 Gulf of Mexico Federal Offshore (10 percent)

 Utah and Wyoming (6 percent)

 Kansas (4 percent).

Natural gas processing plants are usually located in the

same general area where the natural gas is produced.

Table E4 in Appendix E lists the volumes of natural gas

produced and processed in the same State, and the

volumes of liquids extracted.

Lease Condensate

Proved Reserves

Proved reserves of lease condensate in the United

States were 1,336 million barrels in 1998 (Table 15).

This was less than 1 percent less than the volume

reported in 1997. The reserves of five areas account for

about 88 percent of the Nation’s lease condensate

proved reserves.

Percent of U.S.

Area Condensate Reserves

Gulf of Mexico Federal Offshore 42

Texas 21

Louisiana 13

Oklahoma 6

Utah-Wyoming 6

Area Total 88

Production

Production of lease condensate was 178 million barrels,

an increase of 4 million barrels, or 2 percent, in 1998.

The production of five areas account for about 92

percent of the Nation’s lease condensate production.

 Gulf of Mexico Federal Offshore (40 percent)

 Texas (26 percent)

 Louisiana (16 percent)

 Oklahoma (6 percent)

 Utah-Wyoming (4 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 1998. Proved reserves of 530 million

barrels of lease condensate, an increase of 6 percent

from 1997, were reported in nonproducing reservoirs

in 1998 (Appendix D, Table D10). 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 1998 Annual Report 41
References

1. Energy Information Administration. February

1980. U.S. Crude Oil and Natural Gas Reserves 1977

Annual Report. DOE/EIA-0216(77). Washington,

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Washington, DC.

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Reserves 1986 Annual Report. DOE/EIA-0216(86).

Washington, DC.

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Washington, DC.

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1991. U.S. Crude Oil, Natural Gas, and Natural Gas

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1992. U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves 1991 Annual Report.

DOE/EIA-0216(91). Washington, DC.

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

Reserves 1992 Annual Report. DOE/EIA-0216(92).

Washington, DC.

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

Reserves 1993 Annual Report. DOE/EIA-0216(93).

Washington, DC.

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

Reserves 1994 Annual Report. DOE/EIA-0216(94).

Washington, DC.

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1996. U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves 1995 Annual Report.

DOE/EIA-0216(95). Washington, DC.

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1997. U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves 1996 Annual Report.

DOE/EIA-0216(96). Washington, DC.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 43
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1998. U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves 1997 Annual Report.

DOE/EIA-0216(97). Washington, DC.

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Petroleum Marketing Monthly. DOE/EIA0380(98/10). Washington, DC.

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Natural Gas Monthly. DOE/EIA-0130(98/10).

Washington, DC, pg. 16.

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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.

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U.S. Oil and Gas Reserves by Year of Field Discovery.

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Look and Reserves and Production”. Vol. 96, No.

52. Tulsa, OK.

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TX, p. 32.

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1998 Annual Energy Review. DOE/EIA-0384(98).

Washington, DC, Table 5.16.

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1998 Annual Energy Review. DOE/EIA-0384(98).

Washington, DC, Table 6.8.

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Badami Factsheet. Downloaded from

http://www.bpamoco.com.

35. Anadarko Petroleum Corporation. Houston, TX.

Press Releases, July 29 and September 14, 1998.

36. Shell Exploration and Production Company.

Houston, TX. Press Release, March 19, 1998.

37. Exxon Corporation. Irving, TX. Press Release,

April 8, 1998.

38. Washington Post. June 12, 1998.

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15, No. 8. Washington, DC, August 1992. p. 13.

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Assessment of the United States Oil and Gas Resources.

U.S. Geological Survey Circular 1118. Denver, CO,

pp. 5-6.

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and Gas Reserves, Gulf of Mexico, December 31, 1994.

OCS Report MMS 94-0045. New Orleans, LA, pp.

5-6.

Energy Information Administration

44 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
Appendix A

Operator Data by Size Class
Appendix A

Operator Data by Size Class

To remain competitive in the domestic oil and gas

industry, companies have to reduce costs and look for

areas of profitable growth. Over the past few years, we

have seen companies restructure to focus on their core

areas of profit. This restructuring has taken many

forms, for example, mega-mergers, 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

1993 through 1998 for oil and gas well operators. The

tables show the volumetric change and percent change

from the previous year and from 1993. In addition they

show the 1998 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 23,120 small operators. We

estimate production and reserves for small operators

each year from a sample of approximately 8 percent or

less of these operators.

Class 1–10 contains the 10 highest producing

companies each year on a barrel oil equivalent basis.

These companies are not necessarily the same 10

companies each year.

We also include statistics for operator Category sizes at

the bottom portion of tables in this appendix. These are

the categories used by EIA in processing and assessing

reserves surveys and are presented here as additional

perspective. For further explanation of categories sizes

see definitions and descriptions in Appendix E.

Natural Gas

Proved Reserves

The wet natural gas proved reserves reported for 1993

through 1998 have changed from 170.5 trillion cubic

feet to 172.4 trillion cubic feet (Table A1). These proved

reserves are highly concentrated in the larger

companies. In 1998, the top 20 operators (Class 1–10

and Class 11–20) producing companies had 54 percent

of the proved reserves of natural gas. The next two size

classes contain 80 and 400 companies and account for

27 and 14 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 1993 to 1998. While the rest of the operators in

(Class 21–100, Class 101–500, and Class Other) had an

increase of 13 percent in their reserves. In 1998, the top

20 operators’ natural gas reserves increased by 4

percent from 1997.

Production

Wet natural gas production has decreased from 20.1

trillion cubic feet to 19.6 trillion cubic feet in 1998 (Table

A2). In 1998, the top 20 producing companies had 52

percent of the production of wet natural gas, while

having 54 percent of the proved reserves. The next two

size classes have 29 and 14 percent of the wet natural

gas production, respectively. The top 20 operators had

an increase of 6 percent in their wet natural gas

production from 1993 to 1998. The rest of the operators

had an increase of 4 percent from 1993 to 1998. The top

20 operators’ wet natural gas production had a

decrease of 2 percent in 1998, while the rest of the

operators had a decrease of 3 percent.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 47
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

1998 had 68 percent of U.S. proved reserves of crude oil

(Table A3), in contrast to wet natural gas where these

same companies operated only 54 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 decreased 7 percent in

1998. The top 20 producing companies remained

essentially the same in their domestic proved reserves

of crude oil during 1998. The top 20 class had a decline

of 17 percent in their crude oil proved reserves from

1993 to 1998. The class “other” had a 34 percent

decrease from 1993 to 1998. During the 1993–1998

period, many operators were continuing to actively

buy, sell, and restructure their oil property positions.

Production

Crude oil production reported for 1993 through 1998

has decreased from 2.3 billion barrels to 2.0 billion

barrels (Table A4). The 20 largest oil and gas producing

companies had 64 percent of U.S. production of crude

oil in 1998, while in 1993 they accounted for 68 percent

of production. This is in contrast to wet natural gas

where these same companies produced only 52 percent

of the total. U.S. production of crude oil declined by 15

percent from 1993 to 1998. The top 20 operators had a

decline of 19 percent in their oil production during the

same period. U.S. production of crude oil declined by 7

percent from 1997 to 1998, while the top 20 operators

production decreased by 2 percent. The next two size

classes account for 17 and 10 percent of the U.S. crude

oil pr oduction, respectively.

Fields

The number of fields in which Category I and Category

II operators were active dropped significantly during

the 1993–1998 period (Table A5). From 1993 through

1998, the number of fields in which the top 20 operators

were active in dropped by 2,292 (35 percent), while in

1998 the number dropped 526 (11 percent) from 1997.

Energy Information Administration

48 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 49

Class 1–10 77,552 76,665 75,856 72,606 68,876 64,336 -4,540 -13,216 6,433.577

Percent of Total 45.5% 44.6% 43.7% 41.5% 39.2% 37.3% -6.6% -17.0%

Class 11–20 22,467 22,691 24,648 25,416 27,705 28,338 633 5,871 2,833.802

Percent of Total 13.2% 13.2% 14.2% 14.5% 15.8% 16.4% 2.3% 26.1%

Class 21–100 39,135 40,566 42,604 43,300 45,593 47,009 1,416 7,874 587.617

Percent of Total 23.0% 23.6% 24.6% 24.7% 25.9% 27.3% 3.1% 20.1%

Class 101–500 19,870 20,608 20,150 22,483 23,338 24,471 1,133 4,601 61.176

Percent of Total 11.7% 12.0% 11.6% 12.8% 13.3% 14.2% 4.9% 23.2%

Class Other (23,120) 11,466 11,409 10,218 11,342 10,209 8,289 -1,920 -3,177 0.360

Percent of Total 6.7% 6.6% 5.9% 6.5% 5.8% 4.8% -18.8% -27.7%

Category I (170) 142,892 143,703 148,233 146,601 147,491 146,458 -1,033 3,566 861.520

Percent of Total 83.8% 83.6% 85.4% 83.7% 83.9% 84.9% -0.7% 2.5%

Category II (418) 17,305 18,158 15,828 18,382 17,764 18,033 269 728 43.140

Percent of Total 10.2% 10.6% 9.1% 10.5% 10.1% 10.5% 1.5% 4.2%

Category III (23,032) 10,292 10,078 9,416 10,164 10,466 7,952 -2,515 -2,340 0.345

Percent of Total 6.0% 5.9% 5.4% 5.8% 6.0% 4.6% -24.0% -22.7%

Total Published 170,490 171,939 173,476 175,147 175,721 172,443 -3,278 1,953 7.301

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.00% -1.9% 1.1%

Table A1. Natural Gas Proved Reserves, Wet After Lease Separation, by Operator Production Size Class,

1993–1998

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

1997–1998 1993–1998 1998

Volume and Volume and Average

Percent Percent Reserves

Size Class 1993 1994 1995 1996 1997 1998 Change Change per Operator

Note: There were 23,032 active Category III operators in the 1998 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 2,136 Category III operators (Table E2). The “other” size class represents 23,120 operators in the

1998 frame (23,620 active operators minus the 500 largest operators).

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

50 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Class 1–10 6,801 7,216 7,174 7,448 7,178 6,954 -224 153 695.409

Percent of Total 36.5% 37.6% 38.0% 37.5% 35.7% 35.4% -3.1% 2.2%

Class 11–20 2,861 3,083 3,101 3,002 3,286 3,317 31 456 331.668

Percent of Total 15.3% 16.0% 16.4% 15.1% 16.3% 16.9% 0.9% 15.9%

Class 21–100 4,894 4,878 4,871 5,316 5,729 5,595 -134 701 69.941

Percent of Total 26.3% 25.4% 25.8% 26.7% 28.4% 28.5% -2.3% 14.3%

Class 101–500 2,597 2,552 2,477 2,623 2,665 2,721 56 124 6.802

Percent of Total 13.9% 13.3% 13.1% 13.2% 13.2% 13.9% 2.1% 4.8%

Class Other (23,120) 1,488 1,481 1,251 1,484 1,276 1,035 -241 -453 0.045

Percent of Total 8.0% 7.7% 6.6% 7.5% 6.3% 5.3% -18.9% -30.4%

Category I (170) 15,122 15,656 15,800 16,381 16,897 16,619 -278 1,497 97.761

Percent of Total 81.1% 81.5% 83.7% 82.4% 83.9% 84.7% -1.6% 9.9%

Category II (418) 2,159 2,221 1,923 2,128 1,979 2,019 40 -140 4.830

Percent of Total 11.6% 11.6% 10.2% 10.7% 9.8% 10.3% 2.0% -6.5%

Category III (23,032) 1,360 1,333 1,151 1,364 1,258 984 -274 -376 0.043

Percent of Total 7.3% 6.9% 6.1% 6.9% 6.2% 5.0% -21.8% -27.6%

Total Published 18,641 19,210 18,874 19,873 20,134 19,622 -512 981 0.831

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -2.5% 5.3%

Table A2. Natural Gas Production, Wet After Lease Separation, by Operator Production Size Class,

1993–1998

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

1997–1998 1993–1998 1998

Volume and Volume and Average

Percent Percent Production

Size Class 1993 1994 1995 1996 1997 1998 Change Change per Operator

Note: There were 23,032 active Category III operators in the 1998 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 2,136 Category III operators (Table E2). The “other” size class represents 23,120 operators in the

1998 frame (23,620 active operators minus the 500 largest operators).

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 51

Class 1–10 14,894 14,351 13,891 13,362 11,434 11,501 67 -3,393 1,150.102

Percent of Total 64.9% 63.9% 62.1% 60.7% 50.7% 54.7% 0.6% -22.8%

Class 11–20 2,389 2,276 2,422 2,013 2,977 2,894 -83 505 289.401

Percent of Total 10.4% 10.1% 10.8% 9.1% 13.2% 13.8% -2.8% 21.1%

Class 21–100 2,401 2,607 2,623 3,155 4,384 3,677 -707 1,276 45.963

Percent of Total 10.5% 11.6% 11.7% 14.3% 19.4% 17.50% -16.1% 53.1%

Class 101–500 1,440 1,512 1,793 1,838 2,111 1,754 -357 314 4.385

Percent of Total 6.3% 6.7% 8.0% 8.3% 9.4% 8.3% -16.9% 21.8%

Class Other (23,120) 1,833 1,711 1,622 1,649 1,640 1,208 -432 -625 0.052

Percent of Total 8.0% 7.6% 7.3% 7.5% 7.3% 5.7% -26.3% -34.1%

Category I (170) 20,090 19,648 19,647 19,312 19,461 18,819 -642 -1,271 110.702

Percent of Total 87.5% 87.5% 87.9% 87.7% 86.3 89.5% -3.3% -6.3%

Category II (418) 1,131 1,142 1,103 1,117 1,400 1,018 -381 -113 2.435

Percent of Total 4.9% 5.1% 4.9% 5.1% 6.2 4.8% -27.2% -10.0%

Category III (23,032) 1,737 1,668 1,600 1,588 1,685 1,197 -489 -540 0.052

Percent of Total 7.6% 7.4% 7.2% 7.2% 7.5 5.7% -29.0% -31.1%

Total Published 22,957 22,457 22,351 22,017 22,546 21,034 -1,512 -1,923 0.891

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -6.7% -8.4%

Table A3. Crude Oil Proved Reserves by Operator Production Size Class, 1993–1998

(Million Barrels of 42 U.S. Gallons)

1997–1998 1993–1998 1998

Volume and Volume and Average

Percent Percent Reserves

Size Class 1993 1994 1995 1996 1997 1998 Change Change per Operator

Note: There were 23,032 active Category III operators in the 1998 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 2,136 Category III operators (Table E2). The “other” size class represents 23,120 operators in the

1998 frame (23,620 active operators minus the 500 largest operators).

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

52 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Class 1–10 1,346 1,310 1,270 1,220 1,047 1,025 -22 -321 102.506

Percent of Total 57.5% 57.8% 57.4% 56.1% 49.0% 51.5% -2.1% -23.8%

Class 11–20 236 224 221 185 262 255 -7 19 25.549

Percent of Total 10.1% 9.9% 10.0% 8.5% 12.3% 12.8% -2.7% 8.1%

Class 21–100 276 287 276 307 373 342 -31 66 4.280

Percent of Total 11.8% 12.7% 12.5% 14.1% 17.4% 17.2% -8.3% 23.9%

Class 101–500 202 200 214 213 237 206 -31 4 0.514

Percent of Total 8.6% 8.8% 9.7% 9.8% 11.1% 10.3% -13.1% 2.0%

Class Other (23,120) 279 247 232 248 219 163 -56 -116 0.007

Percent of Total% 11.9% 10.9% 10.5% 11.4% 10.2% 8.2% -25.6% -41.6%

Category I (170) 1,922 1,879 1,844 1,791 1,760 1,714 -46 -208 10.080

Percent of Total 82.2% 82.8% 83.3% 82.4% 82.3% 86.1% -2.6% -10.8%

Category II (418) 153 150 139 143 157 118 -39 -35 0.283

Percent of Total 6.5% 6.6% 6.3% 6.6% 7.3% 5.9% -24.8% -22.9%

Category III (23,032) 264 239 230 239 221 159 -62 -105 0.007

Percent of Total 11.3% 10.5% 10.4% 11.0% 10.3% 8.0% -28.1% -39.8%

Total Published 2,339 2,268 2,213 2,173 2,138 1,991 -147 -348 0.084

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -6.9% -14.9%

Table A4. Crude Oil Production by Operator Production Size Class, 1993–1998

(Million Barrels of 42 U.S. Gallons)

1997–1998 1993–1998 1998

Volume and Volume and Average

Percent Percent Production

Size Class 1993 1994 1995 1996 1997 1998 Change Change per Operator

Note: There were 23,032 active Category III operators in the 1998 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 2,136 Category III operators (Table E2). The “other” size class represents 23,120 operators in the

1998 frame (23,620 active operators minus the 500 largest operators).

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 53

Class 1–10 3,591 3,258 3,113 2,800 2,566 2,475 -91 -1,116 247.500

Percent of Total 13.2% 12.2% 11.9% 10.7% 10.4% 9.5% -3.5% -31.1%

Class 11–20 2,998 2,795 2,772 2,441 2,257 1,822 -435 -1,176 182.200

Percent of Total 11.1% 10.5% 10.6% 9.3% 9.1% 7.0% -19.3% -39.2%

Class 21–100 7,600 7,752 7,569 7,526 7,159 7,526 -43 -630 94.075

Percent of Total 28.0% 29.1% 28.9% 28.7% 28.9% 29.0% -0.6% -7.7%

Class 101–500 11,881 11,878 11,886 12,492 12,878 12,817 -61 936 32.043

Percent of Total 43.8% 44.6% 45.4% 47.7% 52.0% 49.4% -0.5% 7.9%

Rest 1,715 1,897 1,601 a952 1,332 1,524 603 365 14.796

Percent of Total 6.3% 7.1% 6.1% a

3.6% 5.4% 5.9% 65.5% 31.5%

Category I 16,603 16,161 16,256 15,635 15,232 15,666 434 -937 92.153

Percent of Total 61.2% 60.7% 62.1% 59.7% 58.2% 60.4% 2.8% -5.6%

Category II 10,516 10,452 9,939 10,576 R9,530 10,271 741 -245 24.572

Percent of Total 38.8% 39.3% 37.9% 40.3% 41.8% 39.6% 7.8% -2.3%

Total Reported 27,119 26,613 26,195 26,211 R24,762 25,937 1,175 -1,182 40.717

Percent Change 100.0% 100.0% 100.0% 100.0% 100.0% 100.00% 4.7% -4.4%

aThe reduced 1996 survey had fewer operators and fields in the “rest” class.

R = Revised

Note: Includes only data from Category I and Category II operators. In 1998, there were 170 Category I operators and 418 Category II

operators. The “rest” size class had 88 operators in 1998.

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

Table A5. Operator Field Count by Operator Production Size Class, 1993–1998

1997–1998 1993–1998 1998 Average

Number and Number and Number of

Percent Percent Fields per

Size Class 1993 1994 1995 1996 1997 1998 Change Change Operator
Appendix B

Top 100 Oil and Gas Fields for 1998
Appendix B

Top 100 Oil and Gas Fields for 1998

This appendix presents estimates of the proved

reserves and production of the top 100 oil and gas

fields. The oil field production and reserve data include

both crude oil and lease condensate. The gas field

production and reserve data is total wet natural gas

(associated-dissolved natural gas and nonassociated

natural gas, wet after lease separation).

Table B1. Top 100 Oil Fields for 1998

The top 100 oil fields in the United States as of

December 31, 1998, had 14,886 million barrels of

proved reserves accounting for 67 percent of the total

United States (Table 6 and Table 16). Although there is

considerable grouping of field–level statistics within

the tables, rough orders of magnitude can be estimated

for the proved reserves and production of most fields.

Many of the fields in the top 100 group 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 1998 there are three fields,

Mississippi Canyon Block 807 (Mars), Green Canyon

Block 244 (Troika), and Mississippi Canyon Block 854

(Ursa) which are in the deep water of the Gulf of

Mexico Federal Offshore.

The top 100 oil fields in the United States as of

December 31, 1998, had 1,143 million barrels of

production, or 53 percent of the total (Table 6 and

Table 15). Many of the oil fields in the top 100 are very

old, 50 oil fields were discovered prior to 1950. The

oldest, Coalinga in California, was discovered in 1887.

The newest, Garden Banks Block 602, in the Gulf of

Mexico Federal Offshore was only discovered in 1998.

The oil fields with newer discovery dates are typically

located in the Gulf of Mexico Offshore and Alaska. Of

the top 100 oil fields 50 percent are equally in the Gulf

of Mexico Offshore and Texas, an additional 29 percent

are in California and Alaska. There were 15 different

fields in this year’s tabulation than in last years.

Table B2. Top 100 Gas Fields for 1998

The top 100 gas fields in the United States as of

December 31, 1998, had 81,628 billion cubic feet of wet

natural gas proved reserves, or 47 percent of the total

(Table 9).

The top 100 gas fields in the United States as of

December 31, 1998, had 6,574 billion cubic feet of

production, or 34 percent of the total (Table 9). Fewer

of the gas fields in the top 100 are as old as the top100 oil

fields. There were 20 gas fields that were discovered

prior to 1946. Gas fields in the top 100 are newer than

the oil fields, 51 gas fields were discovered after

1967.The oldest, Big Sandy in Kentucky, was

discovered in 1881. The newest, Mississippi Canyon

Block 810, in the Gulf of Mexico Federal Offshore was

only discovered in 1996.

The gas fields with newer discovery dates are located

in the Gulf of Mexico Offshore, south Texas and

Virginia. Several of the same fields are in both tables. Of

the top 100 gas fields 28 percent are in Texas, 15 percent

in the Gulf of Mexico Offshore, an additional 26 percent

are in Oklahoma and Wyoming. There were 9 different

fields in this year’s tabulation than in last year’s table.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 57
Energy Information Administration

58 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table B1. Top 100 U.S. Fields Ranked by Oila Proved Reserves, from Reported 1998 Field Level Data

(Million Barrels of 42 U.S. Gallons)

Discovery Proved Reserves Reported Production

Field Name Location Year Rank Group Rank Group

Prudhoe Bay AK 1967 1-10 222.0

Midway-Sunset CA 1901 1-10 49.6

Kuparuk River AK 1969 1-10 91.8

Belridge South CA 1911 1-10 44.9

Yates TX 1926 1-10 19.3

Kern River CA 1899 1-10 46.8

Wasson TX 1937 1-10 16.3

Elk Hills CA 1919 1-10 19.3

Mississippi Canyon Block 807 GF 1989 1-10 43.2

Milne Point AK 1982 1-10 20.4

Top 10 Volume Subtotal 8,084.0 573.7

Top 10 Percentage of U.S. Total 36.1% 26.4%

Slaughter TX 1937 11-20 14.9

Hondo CA 1969 11-20 13.9

Spraberry Trend Area TX 1950 11-20 20.1

Endicott AK 1978 11-20 17.0

Point McIntyre AK 1988 11-20 47.6

Alpine AK 1994 11-20 0.0

Levelland TX 1945 11-20 9.3

Green Canyon Block 244 GF 1994 11-20 20.2

Mississippi Canyon Block 810 GF 1992 11-20 0.0

San Ardo CA 1947 11-20 4.5

Top 20 Volume Subtotal 10,094.3 147.4

Top 20 Percentage of U.S. Total 45.1% 33.2%

Cymric CA 1916 21-50 17.7

Cowden North TX 1930 21-50 7.1

Wilmington CA 1932 21-50 19.0

Lost Hills CA 1910 21-50 11.5

Pescado CA 1970 21-50 11.1

Sho-Vel-Tum OK 1905 21-50 9.3

Vacuum NM 1929 21-50 7.6

East Texas TX 1930 21-50 13.8

Greater Aneth Area UT 1956 21-50 6.2

Alaminos Canyon Block 25 GF 1997 21-50 0.0

Rangely CO 1902 21-50 6.8

Green Canyon Block 205 GF 1988 21-50 0.0

Coalinga CA 1887 21-50 8.9

Fullerton TX 1942 21-50 6.4

Seminole TX 1936 21-50 11.5

Hawkins TX 1940 21-50 3.4

Mississippi Canyon Block 935 GF 1994 21-50 0.0

Garden Banks Block 260 GF 1995 21-50 0.5

Ventura CA 1916 21-50 4.9

Garden Banks Block 426 GF 1987 21-50 26.5

Salt Creek TX 1942 21-50 8.5

Wasson 72 TX 1940 21-50 1.2

Badami AK 1990 21-50 0.7

Niakuk AK 1984 21-50 18.5

McElroy TX 1926 21-50 6.5

Howard-Glasscock TX 1925 21-50 3.5

Robertson North TX 1956 21-50 3.3

Jay FL & AL 1970 21-50 4.6

Wattenberg CO 1970 21-50 5.1

Viosca Knoll Block 990 GF 1981 21-50 18.6

Top 50 Volume Subtotal 12,896.3 963.8

Top 50 Percentage of U.S. Total 57.7% 44.4%
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 59

Bay Marchand Block 2 GF & LA 1949 51-100 5.6

Monument NM & UT 1935 51-100 3.1

Green Canyon Block 158 GF 1992 51-100 0.0

Viosca Knoll Block 956 GF 1985 51-100 16.5

Green Canyon Block 112 GF 1992 51-100 0.0

West Delta Block 30 GF 1949 51-100 8.9

Goldsmith TX 1935 51-100 4.1

Eugene Island SA Block 330 GF 1971 51-100 10.2

West Sak AK 1969 51-100 0.6

Giddings TX 1960 51-100 16.7

Ewing Bank Block 873 GF 1991 51-100 18.1

Beverly Hills CA 1900 51-100 1.6

Bluebell-Altamont UT 1949 51-100 3.6

Jo-Mill TX 1953 51-100 2.4

Garden Banks Block 602 GF 1998 51-100 0.0

Ewing Bank Block 921 GF 1993 51-100 1.1

Huntington Beach CA 1920 51-100 3.8

Dollarhide TX & NM 1945 51-100 3.6

T X L TX 1944 51-100 2.5

Eunice Monument NM 1929 51-100 1.3

Main Pass SA Block 299 GF 1967 51-100 5.1

Viosca Knoll Block 915 GF 1993 51-100 0.0

Cedar Hills ND 1995 51-100 5.6

Kern Front CA 1925 51-100 2.0

Viosca Knoll Block 786 GF 1996 51-100 0.0

Brea-Olinda CA 1897 51-100 1.4

Oregon Basin WY 1912 51-100 4.0

Lisburne AK 1967 51-100 2.5

Fitts East OK 1944 51-100 0.7

Hartzog Draw WY 1976 51-100 2.1

Tarn AK 1991 51-100 3.5

Cogdell TX 1949 51-100 0.3

Pennel MT 1955 51-100 1.8

Ship Shoal Block 169 GF 1961 51-100 4.9

Viosca Knoll Block 825 GF 1988 51-100 7.8

Grayburg-Jackson NM 1929 51-100 3.7

Hobbs NM 1928 51-100 1.7

Arroyo Grande CA 1906 51-100 0.5

Foster TX 1932 51-100 1.8

Lake Washington LA 1931 51-100 1.6

Welch TX 1942 51-100 2.1

Beta CA 1976 51-100 2.9

Painter Reservoir East WY 1979 51-100 3.8

Hamilton Dome WY 1918 51-100 1.7

South Pass Block 61 GF 1955 51-100 7.0

Justis NM 1957 51-100 0.8

Golden Trend OK 1945 51-100 2.3

Cedar Lake TX 1939 51-100 2.3

Postle OK 1958 51-100 1.8

Green Canyon Block 254 GF 1994 51-100 0.0

Top 100 Volume Subtotal 14,886.3 1,143.1

Top 100 Percentage of U.S. Total 66.5% 52.7%

Table B1. Top 100 U.S. Fields Ranked by Oila Proved Reserves, from Reported 1998 Field Level Data

(Continued)

(Million Barrels of 42 U.S. Gallons)

Discovery Proved Reserves Reported Production

Field Name Location Year Rank Group Rank Group

aIncludes lease condensate.

Notes: The U.S. total production estimate of 2,169 million barrels and the U.S. total reserves estimate of 22,370 million barrels, used to

calculate the percentages in this table, are from the combined totals of Table 6 and Table 15 in this publication. Column totals may not add

due to independent rounding.

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

60 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table B2. Top 100 U.S. Fields Ranked by Gasa Proved Reserves, from Reported 1998 Field Level Data

(Billion Cubic Feet)

Discovery Proved Reserves Reported Production

Field Name Location Year Rank Group Rank Group

Blanco / Ignacio-Blanco NM & CO 1927 1-10 718.1

Basin NM 1947 1-10 662.6

Hugoton Gas Area KS & OK & TX 1922 1-10 468.6

Prudhoe Bay AK 1967 1-10 252.7

Madden WY 1968 1-10 55.1

Carthage TX 1936 1-10 222.7

Mobile Bay AL 1979 1-10 149.4

Big Piney-Labarge WY 1924 1-10 39.1

Oakwood VA 1990 1-10 32.1

Wattenburg CO 1970 1-10 100.9

Top 10 Volume Subtotal 39,974.0 2,701.4

Top 10 Percentage of U.S. Total 23.2% 13.8%

Antrim MI 1965 11-20 136.0

Panhandle West TX 1918 11-20 123.2

Fogarty Creek WY 1975 11-20 30.8

Big Sandy KY 1881 11-20 48.7

Giddings TX 1960 11-20 225.6

Natural Buttes UT 1940 11-20 55.4

Red-Oak Norris OK 1910 11-20 64.6

Cook Inlet North AK 1962 11-20 53.7

Panoma Gas Area KS 1956 11-20 92.7

Beluga River AK 1962 11-20 33.2

Top 20 Volume Subtotal 50,448.6 863.8

Top 20 Percentage of U.S. Total 29.3% 18.2%

Elk Hills CA 1919 21-50 98.0

Spraberry Trend Area TX 1953 21-50 69.2

Oak Hill TX 1967 21-50 66.5

Lake Ridge WY 1981 21-50 15.2

Whitney Canyon-Carter Creek WY 1978 21-50 76.2

Gomez TX 1963 21-50 63.5

Strong City District OK 1972 21-50 70.5

East Breaks Block 945 TX 1994 21-50 0.0

Mocane-Laverne Gas Area OK & KS & TX 1947 21-50 66.3

Lower Mobile Bay-Mary Ann AL 1979 21-50 35.8

Mobile Block 823 GF 1983 21-50 54.2

Sawyer TX 1960 21-50 48.6

Golden Trend OK 1946 21-50 41.9

Mississippi Canyon Block 731 GF 1987 21-50 43.9

Mississippi Canyon Block 810 GF 1996 21-50 0.0

Vaquillas Ranch TX 1978 21-50 71.6

Viosca Knoll Block 956 GF 1985 21-50 74.6

Knox OK 1916 21-50 51.3

Wasson TX 1937 21-50 8.4

Ozona TX 1953 21-50 48.9

Watonga-Chickasha Trend OK 1948 21-50 64.6

Judge Digby LA 1977 21-50 21.9

McArthur River AK 1968 21-50 72.5

Bruff WY 1969 21-50 47.7

Bob West TX 1990 21-50 74.3

Garden Banks Block 426 GF 1987 21-50 92.8

Wilburton OK 1941 21-50 52.3

Drunkards Wash UT 1989 21-50 30.1

Raton CO 1994 21-50 10.0

Viosca Knoll Block 915 GF 1993 21-50 0.0

Top 50 Volume Subtotal 67,420.2 5,036.0

Top 50 Percentage of U.S. Total 39.1% 25.7%
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 61

Table B2. Top 100 U.S. Fields Ranked by Gasa Proved Reserves, from Reported 1998 Field Level Data

(Continued)

(Billion Cubic Feet)

Discovery Proved Reserves Reported Production

Field Name Location Year Rank Group Rank Group

Anschutz Ranch East UT & WY 1980 51-100 80.1

McAllen Ranch TX 1960 51-100 84.7

Indian Basin NM 1963 51-100 73.4

Mississippi Canyon Block 807 GF 1989 51-100 44.5

Kuparuk River AK 1969 51-100 28.1

Elk City OK 1947 51-100 38.8

Wamsutter WY 1958 51-100 28.2

Kinta OK 1914 51-100 42.9

Fairway AL 1986 51-100 29.6

Nora VA 1949 51-100 23.6

A W P TX 1987 51-100 24.7

Garden Banks Block 260 GF 1992 51-100 2.8

Painter Reservoir East WY 1979 51-100 34.1

Viosca Knoll Block 783 GF 1985 51-100 54.8

Rulison CO 1956 51-100 21.3

Waltman WY 1959 51-100 56.6

South Pass SA Block 89 GF 1969 51-100 34.1

Grand Valley CO 1985 51-100 15.6

Hondo CA 1969 51-100 21.3

Tip Top WY 1928 51-100 18.3

Belridge South CA 1911 51-100 17.4

Mississippi Canyon Block 354 GF 1977 51-100 37.1

Standard Draw WY 1979 51-100 23.0

Pegasus TX 1949 51-100 24.4

Green Canyon Block 244 GF 1994 51-100 31.8

Newark East TX 1981 51-100 30.7

Verden OK 1961 51-100 36.1

Willow Springs TX 1938 51-100 25.6

Matagorda Island Block 623 GF 1980 51-100 100.3

Sarita East TX 1967 51-100 36.6

Lake Arthur South LA 1955 51-100 25.7

Moorewood NE OK 1979 51-100 30.2

Double A Wells TX 1980 51-100 36.0

Cedar Cove Coal Degas AL 1983 51-100 31.1

Sugg Ranch TX 1985 51-100 9.7

Boonsville TX 1945 51-100 30.4

Jeffress NE TX 1975 51-100 28.8

Trawick TX 1949 51-100 22.1

Endicott AK 1978 51-100 9.1

Mississippi Canyon Block 194 GF 1975 51-100 35.3

Stratton TX 1937 51-100 15.2

Lost Hills CA 1910 51-100 17.9

Cochranton PA 1980 51-100 9.4

Blanco South NM 1951 51-100 15.9

Kenai AK 1959 51-100 9.0

Mississippi Canyon Block 292 GF 1996 51-100 0.0

Monte Christo TX 1953 51-100 9.5

Sho-Vel-Tum OK 1912 51-100 23.1

Carpenter OK 1951 51-100 23.1

Puckett TX 1952 51-100 35.9

Top 100 Volume Subtotal 81,628.0 6,573.8

Top 100 Percentage of U.S. Total 47.3% 33.5%

aTotal wet gas after lease separation.

Note: The U.S. total production estimate of 19,622 billion cubic feet and the U.S. total reserves estimate of 172,443 billion cubic feet, used

to calculate the percentages in this table, are from Table 9 in this publication. Column totals may not add due to independent rounding.

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

Conversion to the Metric System
Appendix C

Conversion to the Metric System

Public Law 100–418, the Omnibus Trade and

Competitiveness Act of 1988, states: “It is the

declared policy of the United States—

(1) to designate the metric system of measurement as

the preferred system of weights and measures for

United States trade and commerce....

(2) to require that each Federal agency, by the end of

Fiscal Year 1992, use the metric system of

measurement in its procurements, grants, and other

business–related activities."{39}

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 1998 Annual Report 65
Energy Information Administration

66 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table C1. U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids,

in Metric Units, 1988 – 1998

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)

1988 57.8 426.7 194.1 290.4 56.4 11.3 20.2 87.9 446.9 4,264.8 –68.6

1989 33.9 428.9 217.0 245.8 81.7 17.8 14.3 113.8 411.1 4,213.3 –51.5

1990 13.7 394.8 159.0 249.5 72.5 15.6 21.5 109.6 398.3 4,174.1 –39.2

1991 25.9 333.4 297.9 61.4 58.0 15.4 14.6 88.0 399.4 3,924.1 –250.0

1992 46.2 286.8 170.0 163.0 62.2 1.3 13.5 77.0 388.9 3,775.2 –148.9

1993 43.1 319.7 241.0 121.8 56.6 50.7 17.5 124.8 371.9 3,649.9 –125.3

1994 30.1 375.8 215.7 190.2 63.1 10.2 17.6 90.9 360.6 3,570.4 –79.5

1995 19.4 289.8 126.4 182.8 79.5 18.1 54.5 152.1 351.8 3,553.5 –16.9

1996 28.0 273.9 156.8 145.1 86.3 38.6 22.4 147.3 345.5 3,500.4 –53.1

1997 82.7 317.7 172.3 228.0 75.8 101.3 18.9 196.0 339.9 3,584.2 83.8

1998 –101.5 437.5 355.2 –19.2 52.0 24.2 19.1 95.3 316.5 3,344.1 –240.4

Dry Natural Gas (billion cubic meters)

1988 62.09 661.68 d1,088.13 –364.36 192.64 46.38 54.06 293.08 472.04 d4,757.91 –543.32

1989 85.33 755.30 669.50 171.13 179.50 41.06 63.51 284.07 480.91 4,732.20 –25.71

1990 44.08 537.48 380.66 200.90 225.18 56.75 68.30 350.23 487.98 4,795.35 63.15

1991 83.82 563.22 438.17 208.87 144.13 24.01 45.42 213.56 487.11 4,730.67 –64.68

1992 63.29 511.26 338.73 235.82 132.38 18.38 48.82 199.58 493.36 4,672.71 –57.96

1993 27.51 498.29 346.82 178.98 172.82 25.46 52.84 251.12 503.73 4,599.08 –73.63

1994 55.08 604.99 449.70 210.37 196.55 53.63 98.54 348.72 518.82 4,639.35 40.27

1995 16.42 579.50 360.50 235.42 193.77 47.18 69.43 310.38 508.74 4,676.41 37.06

1996 107.18 485.12 369.42 222.88 219.65 41.09 88.07 348.81 534.08 4,714.02 37.61

1997 –16.70 613.28 474.47 122.10 299.73 75.92 67.45 443.10 544.00 4,735.22 21.22

1998 –46.30 792.96 630.42 116.24 232.11 30.41 61.22 323.74 530.09 4,645.12 –90.11

Natural Gas Liquids (million cubic meters)

1988 1.8 185.7 113.7 73.8 42.6 6.5 11.4 60.5 119.9 1,309.7 14.4

1989 –44.0 181.7 162.2 –24.5 41.2 13.2 11.8 66.2 116.2 1,235.2 –74.5

1990 –13.2 131.5 96.3 22.0 47.5 6.2 11.6 65.3 116.4 1,206.1 –29.1

1991 37.1 131.2 110.5 57.8 30.0 4.0 8.7 42.7 119.9 1,186.7 –19.4

1992 35.7 128.1 86.6 77.2 30.2 3.2 10.2 43.6 122.9 1,184.6 –2.1

1993 16.2 121.5 101.8 35.9 39.0 3.8 10.2 53.0 125.3 1,148.2 –36.4

1994 6.9 138.8 107.5 38.2 49.9 8.6 20.8 79.3 125.8 1,139.9 –8.3

1995 30.5 153.9 109.9 74.5 68.7 8.3 10.7 87.7 125.8 1,176.3 36.4

1996 75.5 134.2 106.4 103.3 71.7 10.3 17.3 99.3 135.1 1,243.8 67.5

1997 –2.4 190.6 144.7 43.6 85.1 18.1 14.3 117.5 137.4 1,267.6 23.8

1998 –57.4 207.0 173.9 -24.3 60.9 10.5 14.0 85.4 132.4 1,196.2 –71.4

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, 1988–1998 annual reports, DOE/EIA–0216.{12–21}
Appendix D

Historical Reserves Statistics
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 69

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 1998 of the EIA publication U.S. Crude Oil, Natural

Gas, and Natural Gas Liquids Reserves, DOE EIA-0216.{1-21}

Liquid volumes are in million barrels of 42 U.S. gallons. Gas volumes are in billion cubic feet (Bcf), at 14.73 psia and

60° Fahrenheit. NA appears in this appendix wherever data are not available or are withheld to avoid disclosure of

data which may be proprietary. An asterisk (*) marks those estimates associated with sampling errors (95 percent

confidence interval) greater than 20 percent of the value estimated.

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Alabama

1977 85 0 530 NA

1978 *74 0 514 NA

1979 45 NA 652 213

1980 54 NA 636 226

1981 55 NA 648 192

1982 54 NA a648 193

1983 51 NA a785 216

1984 *68 NA a961 200

1985 69 NA a821 182

1986 55 20 b951 177

1987 55 20 b842 166

1988 54 20 b809 166

1989 43 20 b819 168

1990 44 <1 c4,125 170

1991 43 <1 c5,414 145

1992 41 0 c5,802 171

1993 41 0 c5,140 158

1994 44 0 c4,830 142

1995 43 0 c4,868 120

1996 45 0 c5,033 119

1997 47 0 c4,968 93

1998 39 0 c4,604 81

aOnshore only; offshore included in Louisiana. bOnshore only; offshore included in Federal Offshore - Gulf of

Mexico (Louisiana). cIncludes State Offshore: 2,519 Bcf in 1990; 3,191 Bcf in 1991;

3,233 Bcf in 1992; 3,364 Bcf in 1993; 3,297 Bcf in 1994; 3,432 Bcf

in 1995; 3,509 Bcf in 1996; 3,422 Bcf in 1997; 3,144 Bcf in 1998.

Alaska

1977 8,413 846 32,243 NA

1978 9,384 398 32,045 NA

1979 8,875 398 32,259 23

1980 8,751 0 33,382 11

1981 8,283 0 33,037 10

1982 7,406 60 34,990 9

1983 7,307 576 34,283 8

1984 7,563 369 34,476 19

1985 7,056 379 33,847 383

1986 6,875 902 32,664 381

1987 7,378 566 33,225 418

1988 6,959 431 9,078 401

1989 6,674 750 8,939 380

1990 6,524 969 9,300 340

1991 6,083 1,456 9,553 360

1992 6,022 1,331 9,638 347

1993 5,775 1,161 9,907 321

1994 5,767 1,022 9,733 301

1995 5,580 582 9,497 306

1996 5,274 952 9,294 337

1997 5,161 832 10,562 631

1998 5,052 832 9,927 320

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

70 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Arkansas

1977 116 17 1,660 NA

1978 111 8 1,681 NA

1979 107 8 1,703 17

1980 107 11 1,774 16

1981 113 11 1,801 16

1982 107 4 1,958 15

1983 120 4 2,069 11

1984 114 6 2,227 12

1985 97 11 2,019 11

1986 88 9 1,992 16

1987 82 0 1,997 16

1988 77 <1 1,986 13

1989 66 1 1,772 9

1990 60 1 1,731 9

1991 *70 0 1,669 5

1992 58 <1 1,750 4

1993 65 0 1,552 4

1994 51 0 1,607 6

1995 48 0 1,563 6

1996 58 0 1,470 4

1997 45 0 1,475 7

1998 47 0 1,328 5

California - Total

1977 5,005 1,047 4,737 NA

1978 4,974 968 4,947 NA

1979 5,265 960 5,022 111

1980 5,470 891 5,414 120

1981 5,441 660 5,617 82

1982 5,405 616 5,552 154

1983 5,348 576 5,781 151

1984 5,707 674 5,554 141

1985 d4,810 590 d4,325 d146

1986 d4,734 d616 d3,928 d134

1987 d4,709 d1,493 d3,740 d130

1988 d4,879 d1,440 d3,519 d123

1989 d4,816 d1,608 d3,374 d113

1990 d4,658 d1,425 d3,185 d105

1991 d4,217 d1,471 d3,004 d92

1992 d3,893 d1,299 d2,778 d99

1993 d3,764 d965 d2,682 d104

1994 d3,573 d835 d2,402 d92

1995 d3,462 d823 d2,243 d92

1996 d3,437 d905 d2,082 d92

1997 d3,750 d1,264 d2,273 d95

1998 d3,843 d1,297 d2,244 d72

dExcludes Federal offshore; now included in Federal OffshorePacific (California).

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

California - Coastal Region Onshore

1977 679 NA 334 NA

1978 602 NA 350 NA

1979 578 NA 365 22

1980 652 NA 299 23

1981 621 NA 306 14

1982 580 NA 362 16

1983 559 NA 381 17

1984 628 140 265 15

1985 631 152 256 16

1986 592 164 255 15

1987 625 298 238 13

1988 576 299 215 13

1989 731 361 224 11

1990 588 310 217 12

1991 554 327 216 12

1992 522 317 203 10

1993 528 313 189 12

1994 480 238 194 11

1995 456 234 153 8

1996 425 261 156 9

1997 430 43 164 9

1998 354 40 106 9

California - Los Angeles Basin Onshore

1977 910 NA 255 NA

1978 493 NA 178 NA

1979 513 NA 163 10

1980 454 NA 193 15

1981 412 NA 154 6

1982 370 NA 96 6

1983 343 NA 107 6

1984 373 126 156 5

1985 420 86 181 6

1986 330 66 142 8

1987 361 105 148 8

1988 391 106 151 7

1989 342 32 137 4

1990 316 3 106 5

1991 272 4 115 4

1992 236 4 97 5

1993 238 4 102 6

1994 221 4 103 5

1995 227 4 111 4

1996 234 0 109 3

1997 268 0 141 4

1998 207 0 149 5
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 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

California - San Joaquin Basin Onshore

1977 2,965 NA 3,784 NA

1978 3,099 NA 3,960 NA

1979 3,294 NA 3,941 77

1980 3,360 NA 4,344 81

1981 3,225 NA 4,163 57

1982 3,081 NA 3,901 124

1983 3,032 NA 3,819 117

1984 3,197 384 3,685 105

1985 3,258 350 3,574 120

1986 3,270 368 3,277 109

1987 3,208 1,070 3,102 107

1988 3,439 1,029 2,912 101

1989 3,301 1,210 2,782 95

1990 3,334 1,109 2,670 86

1991 3,126 1,139 2,614 75

1992 2,898 977 2,415 83

1993 2,772 648 2,327 85

1994 2,647 593 2,044 75

1995 2,577 585 1,920 80

1996 2,597 644 1,768 80

1997 2,871 1,221 1,912 82

1998 3,127 1,257 1,945 58

California-State and Federal Offshore

1977 451 NA 364 NA

1978 780 NA 457 NA

1979 880 NA 553 2

1980 1,004 NA 578 1

1981 1,183 NA 994 5

1982 1,374 NA 1,193 8

1983 1,414 NA 1,474 11

1984 1,509 25 1,448 16

1985 1,492 2 1,433 16

1986 1,516 19 1,579 17

1987 1,552 20 1,704 19

1988 1,497 6 1,793 23

1989 1,429 5 1,727 28

1990 1,382 3 1,646 20

1991 1,050 1 1,221 19

1992 971 1 1,181 21

1993 899 0 1,163 26

1994 878 0 1,231 22

1995 773 0 1,324 25

1996 699 0 1,293 23

1997 709 0 600 14

1998 623 0 524 12

California - State Offshore

1977 181 NA 114 NA

1978 519 NA 213 NA

1979 632 NA 231 2

1980 604 NA 164 1

1981 NA NA NA NA

1982 NA NA NA NA

1983 NA NA NA NA

1984 NA 25 NA NA

1985 501 0 314 4

1986 542 18 254 2

1987 515 18 252 2

1988 473 6 241 2

1989 442 5 231 3

1990 420 3 192 2

1991 265 1 59 1

1992 237 1 63 1

1993 226 0 64 1

1994 225 0 61 1

1995 202 0 59 0

1996 181 0 49 0

1997 181 0 56 0

1998 155 0 44 0

California - Federal Offshore

1977 270 NA 250 NA

1978 261 NA 246 NA

1979 248 NA 322 0

1980 400 NA 414 0

1981 NA NA NA NA

1982 NA NA NA NA

1983 NA NA NA NA

1984 NA 0 NA NA

1985 991 2 1,119 12

1986 974 1 1,325 15

1987 1,037 2 1,452 17

1988 1,024 0 1,552 21

1989 987 0 1,496 25

1990 962 0 1,454 18

1991 785 0 1,162 18

1992 734 <1 1,118 20

1993 673 0 1,099 25

1994 653 0 1,170 21

1995 571 0 1,265 25

1996 518 0 1,244 23

1997 528 0 544 14

1998 468 0 480 12
Energy Information Administration

72 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Colorado

1977 230 73 2,512 NA

1978 194 75 2,765 NA

1979 159 43 2,608 177

1980 *183 46 2,922 194

1981 147 47 2,961 204

1982 169 100 3,314 186

1983 186 113 3,148 183

1984 198 119 *2,943 155

1985 198 119 2,881 173

1986 207 95 3,027 148

1987 272 67 2,942 166

1988 257 67 3,535 181

1989 359 8 4,274 209

1990 305 8 4,555 169

1991 329 33 5,767 197

1992 304 34 6,198 226

1993 284 22 6,722 214

1994 271 22 6,753 248

1995 252 24 7,256 273

1996 231 22 7,710 287

1997 198 22 6,828 264

1998 212 21 7,881 260

Florida

1977 213 1 151 NA

1978 168 1 119 NA

1979 128 1 77 21

1980 134 1 84 27

1981 109 1 69 NA

1982 97 1 64 17

1983 78 4 49 11

1984 82 2 65 17

1985 77 2 55 17

1986 67 2 49 14

1987 61 0 49 9

1988 59 0 51 16

1989 50 0 46 10

1990 42 0 45 8

1991 37 0 38 7

1992 36 0 47 8

1993 40 0 50 9

1994 71 0 98 18

1995 71 0 92 17

1996 97 0 96 22

1997 91 0 96 17

1998 71 0 88 18

Illinois

1977 *150 1 NA NA

1978 *158 1 NA NA

1979 *136 1 NA NA

1980 113 2 NA NA

1981 129 1 NA NA

1982 150 1 NA NA

1983 135 1 NA NA

1984 153 1 NA NA

1985 136 1 NA NA

1986 135 1 NA NA

1987 153 5 NA NA

1988 143 <1 NA NA

1989 123 <1 NA NA

1990 131 0 NA NA

1991 128 52 NA NA

1992 138 0 NA NA

1993 116 0 NA NA

1994 117 0 NA NA

1995 119 0 NA NA

1996 94 0 NA NA

1997 92 0 NA NA

1998 81 0 NA NA

Indiana

1977 *20 0 NA NA

1978 *29 0 NA NA

1979 *40 0 NA NA

1980 23 0 NA NA

1981 23 0 NA NA

1982 28 1 NA NA

1983 34 3 NA NA

1984 *33 2 NA NA

1985 *35 2 NA NA

1986 *32 2 NA NA

1987 23 2 NA NA

1988 *22 0 NA NA

1989 *16 0 NA NA

1990 12 0 NA NA

1991 *16 0 NA NA

1992 17 0 NA NA

1993 15 0 NA NA

1994 15 0 NA NA

1995 13 0 NA NA

1996 11 0 NA NA

1997 *10 0 NA NA

1998 13 0 NA NA
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 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

Kansas

1977 *349 3 11,457 NA

1978 303 3 10,992 NA

1979 *377 3 10,243 402

1980 310 2 9,508 389

1981 371 2 9,860 409

1982 378 13 9,724 302

1983 344 13 9,553 443

1984 377 2 9,387 424

1985 423 <1 9,337 373

1986 312 <1 10,509 440

1987 357 <1 10,494 462

1988 327 <1 10,104 345

1989 338 3 10,091 329

1990 321 <1 9,614 313

1991 300 <1 9,358 428

1992 310 0 9,681 444

1993 271 0 9,348 380

1994 260 0 9,156 398

1995 275 <1 8,571 369

1996 266 <1 7,694 338

1997 238 0 6,989 271

1998 246 0 6,402 334

Kentucky

1977 30 0 451 NA

1978 *40 0 545 NA

1979 25 0 468 26

1980 *35 12 508 25

1981 29 13 530 25

1982 *36 13 551 35

1983 35 12 554 31

1984 *41 0 613 24

1985 *42 0 766 27

1986 *31 0 841 29

1987 25 0 909 23

1988 *34 0 923 24

1989 33 0 992 16

1990 33 0 1,016 25

1991 *31 0 1,155 24

1992 34 0 1,084 32

1993 26 0 1,003 26

1994 26 0 969 39

1995 24 0 1,044 43

1996 21 0 983 46

1997 *20 0 1,364 48

1998 23 0 1,222 54

Louisiana - Total

1977 3,600 139 57,010 NA

1978 3,448 143 55,725 NA

1979 2,780 76 50,042 1,424

1980 2,751 62 47,325 1,346

1981 2,985 50 47,377 1,327

1982 2,728 49 e44,916 1,295

1983 2,707 45 e42,561 1,332

1984 2,661 55 e41,399 1,188

1985 f883 35 f14,038 f546

1986 f826 f47 f12,930 f524

1987 f807 f56 f12,430 f525

1988 f800 f69 f12,224 f517

1989 f745 f63 f12,516 f522

1990 f705 f22 f11,728 f538

1991 f679 f44 f10,912 f526

1992 f668 f35 f9,780 f495

1993 f639 f338 f9,174 f421

1994 f649 f340 f9,748 f434

1995 f637 f475 f9,274 f601

1996 f658 f331 f9,543 f543

1997 f714 f313 f9,673 f437

1998 f551 f316 f9,147 f411

eIncludes State and Federal offshore Alabama. f

Excludes Federal offshore; now included in Federal OffshoreGulf of Mexico (Louisiana).

Louisiana - North

1977 244 78 3,135 NA

1978 255 78 3,203 NA

1979 216 NA 2,798 96

1980 248 NA 3,076 95

1981 *317 NA 3,270 99

1982 *240 NA 2,912 85

1983 223 NA 2,939 74

1984 165 9 2,494 57

1985 196 5 2,587 65

1986 160 7 2,515 57

1987 175 3 2,306 50

1988 154 23 2,398 56

1989 123 22 2,652 60

1990 120 <1 2,588 58

1991 127 <1 2,384 59

1992 125 <1 2,311 60

1993 108 0 2,325 57

1994 108 0 2,537 69

1995 108 0 2,788 79

1996 128 0 3,105 85

1997 136 <1 3,093 80

1998 101 0 2,898 57
Energy Information Administration

74 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Louisiana - South Onshore

1977 1,382 46 18,580 NA

1978 1,242 38 17,755 NA

1979 682 NA 13,994 676

1980 682 NA 13,026 540

1981 642 NA 12,645 544

1982 611 NA 11,801 501

1983 569 NA 11,142 527

1984 585 20 10,331 454

1985 565 16 9,808 442

1986 547 30 9,103 428

1987 505 22 8,693 429

1988 511 35 8,654 421

1989 479 30 8,645 411

1990 435 11 8,171 431

1991 408 33 7,504 417

1992 417 26 6,693 380

1993 382 329 5,932 334

1994 391 331 6,251 337

1995 387 324 5,648 495

1996 382 322 5,704 411

1997 427 309 5,855 333

1998 353 307 5,698 325

Louisiana - State Offshore

1977 1,974 15 35,295 NA

1978 1,951 27 34,767 NA

1979 1,882 14 33,250 652

1980 1,821 13 31,223 711

1981 2,026 16 31,462 684

1982 1,877 21 e30,203 709

1983 1,915 15 e28,480 731

1984 1,911 27 e28,574 677

1985 f122 2 f1,643 f39

1986 f119 f10 f1,312 f39

1987 f127 f22 f1,431 f46

1988 f135 f11 f1,172 f40

1989 f143 f11 f1,219 f51

1990 f150 f11 f969 f49

1991 f144 f11 f1,024 f50

1992 f126 f9 f776 f55

1993 f149 f9 f917 f30

1994 f150 f9 f960 f28

1995 f142 f151 f838 f27

1996 f148 f9 f734 f47

1997 f151 f4 f725 f24

1998 f97 f2 f551 f29

eIncludes State and Federal offshore Alabama. f

Excludes Federal offshore; now included in Federal OffshoreGulf of Mexico (Louisiana).

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Michigan

1977 *233 0 *1,386 NA

1978 *220 9 *1,422 NA

1979 159 23 1,204 112

1980 *205 14 *1,406 112

1981 *240 17 1,118 102

1982 184 34 1,084 97

1983 209 48 1,219 105

1984 180 46 1,112 84

1985 191 37 985 67

1986 146 34 1,139 88

1987 151 27 1,451 111

1988 132 27 1,323 99

1989 128 8 1,342 97

1990 124 3 1,243 81

1991 119 0 1,334 72

1992 102 0 1,223 68

1993 90 0 1,160 57

1994 91 1 1,323 54

1995 76 1 1,294 45

1996 74 0 2,061 53

1997 68 2 2,195 50

1998 44 0 2,328 51

Mississippi

1977 241 9 1,437 NA

1978 *250 27 1,635 NA

1979 238 24 1,504 16

1980 202 36 1,769 20

1981 209 93 2,035 18

1982 223 85 1,796 18

1983 205 77 1,596 19

1984 201 50 1,491 15

1985 184 53 1,360 12

1986 199 16 1,300 11

1987 202 12 1,220 11

1988 221 10 1,143 12

1989 218 6 1,104 12

1990 227 8 1,126 11

1991 194 8 1,057 10

1992 165 7 869 9

1993 133 44 797 11

1994 151 40 650 9

1995 140 6 663 8

1996 164 6 631 7

1997 183 0 582 6

1998 141 0 658 8
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 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

Montana

1977 175 27 *887 NA

1978 158 27 926 NA

1979 152 38 825 10

1980 179 13 *1,287 16

1981 186 11 *1,321 11

1982 216 6 847 18

1983 234 8 896 19

1984 224 4 802 18

1985 232 3 857 21

1986 248 27 803 16

1987 246 <1 780 16

1988 241 0 819 11

1989 225 <1 867 16

1990 221 0 899 15

1991 201 0 831 14

1992 193 0 859 12

1993 171 0 673 8

1994 175 0 717 8

1995 178 0 782 8

1996 168 0 796 7

1997 159 1 762 5

1998 167 0 782 5

Nebraska

1977 22 0 NA NA

1978 30 1 NA NA

1979 25 0 NA NA

1980 *46 0 NA NA

1981 41 0 NA NA

1982 *32 0 NA NA

1983 44 0 NA NA

1984 *46 0 NA NA

1985 42 0 NA NA

1986 *45 7 NA NA

1987 33 0 NA NA

1988 42 0 NA NA

1989 32 0 NA NA

1990 26 0 NA NA

1991 26 0 NA NA

1992 26 0 NA NA

1993 20 0 NA NA

1994 22 0 NA NA

1995 25 0 NA NA

1996 28 0 NA NA

1997 *21 0 NA NA

1998 18 0 NA NA

New Mexico - Total

1977 605 97 12,000 NA

1978 579 90 12,688 NA

1979 563 77 13,724 530

1980 547 58 13,287 541

1981 555 93 13,870 560

1982 563 76 12,418 531

1983 576 75 11,676 551

1984 660 87 11,364 511

1985 688 99 10,900 445

1986 644 225 11,808 577

1987 654 235 11,620 771

1988 661 241 17,166 1,023

1989 665 256 15,434 933

1990 687 256 17,260 990

1991 721 275 18,539 908

1992 757 293 18,998 1,066

1993 707 211 18,619 996

1994 718 215 17,228 1,011

1995 732 185 17,491 943

1996 744 148 16,485 1,059

1997 735 146 15,514 869

1998 620 168 14,987 929

New Mexico - East

1977 576 95 3,848 NA

1978 554 88 3,889 NA

1979 542 77 4,031 209

1980 518 58 3,530 209

1981 522 93 3,598 214

1982 537 76 3,432 209

1983 542 75 3,230 232

1984 625 87 3,197 221

1985 643 98 3,034 209

1986 593 225 2,694 217

1987 608 230 2,881 192

1988 621 235 2,945 208

1989 619 252 3,075 196

1990 633 253 3,256 222

1991 694 275 3,206 205

1992 731 293 3,130 223

1993 688 211 3,034 233

1994 702 215 3,021 234

1995 713 185 2,867 247

1996 731 148 2,790 299

1997 719 146 2,642 273

1998 610 168 2,693 262
Energy Information Administration

76 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

New Mexico - West

1977 *29 2 8,152 NA

1978 *25 2 8,799 NA

1979 21 0 9,693 321

1980 *29 0 9,757 332

1981 *33 0 10,272 346

1982 26 0 8,986 322

1983 34 0 8,446 319

1984 35 0 8,167 290

1985 45 1 7,866 236

1986 51 0 9,114 360

1987 46 5 8,739 579

1988 40 6 14,221 815

1989 46 4 12,359 737

1990 54 3 14,004 768

1991 27 0 15,333 703

1992 26 0 15,868 843

1993 19 0 15,585 763

1994 16 0 14,207 777

1995 19 0 14,624 696

1996 13 0 13,695 760

1997 16 0 12,872 596

1998 10 0 12,294 667

New York

1977 NA NA 165 NA

1978 NA NA 193 NA

1979 NA NA 211 0

1980 NA NA 208 0

1981 NA NA *264 0

1982 NA NA 229 NA

1983 NA NA 295 NA

1984 NA NA 389 NA

1985 NA NA *369 NA

1986 NA NA *457 NA

1987 NA NA 410 NA

1988 NA NA 351 NA

1989 NA NA 368 NA

1990 NA NA 354 NA

1991 NA NA 331 NA

1992 NA NA 329 NA

1993 NA NA *264 NA

1994 NA NA 242 NA

1995 NA NA 197 NA

1996 NA NA 232 NA

1997 NA NA *224 NA

1998 NA NA 218 NA

North Dakota

1977 155 10 361 NA

1978 162 4 374 NA

1979 211 6 439 47

1980 214 6 537 61

1981 223 8 581 68

1982 237 8 629 71

1983 258 53 600 69

1984 260 54 566 73

1985 255 34 569 74

1986 218 35 541 69

1987 215 33 508 67

1988 216 39 541 52

1989 246 31 561 59

1990 285 0 586 60

1991 232 4 472 56

1992 237 3 496 64

1993 226 7 525 55

1994 226 2 507 55

1995 233 6 463 53

1996 248 6 462 48

1997 279 6 479 47

1998 245 1 447 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

1997 *43 0 985 NA

1998 40 0 890 NA
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 77

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Oklahoma

1977 1,109 69 13,889 NA

1978 979 33 14,417 NA

1979 1,014 35 13,816 583

1980 930 27 13,138 604

1981 950 43 14,699 631

1982 971 25 16,207 745

1983 931 27 16,211 829

1984 940 40 16,126 769

1985 935 37 16,040 826

1986 874 35 16,685 857

1987 788 56 16,711 781

1988 796 79 16,495 765

1989 789 63 15,916 654

1990 734 37 16,151 657

1991 700 54 14,725 628

1992 698 54 13,926 629

1993 680 40 13,289 643

1994 689 47 13,487 652

1995 676 48 13,438 674

1996 632 43 13,074 684

1997 605 20 13,439 685

1998 599 59 13,645 698

Pennsylvania

1977 *57 0 769 NA

1978 27 0 899 NA

1979 33 0 *1,515 1

1980 35 0 951 0

1981 32 0 *1,264 0

1982 37 0 1,429 NA

1983 41 0 1,882 NA

1984 *40 0 1,575 NA

1985 *38 0 *1,617 NA

1986 *26 0 *1,560 1

1987 26 0 1,647 NA

1988 *27 0 2,072 NA

1989 26 0 1,642 NA

1990 22 0 1,720 NA

1991 15 0 1,629 NA

1992 16 0 1,528 NA

1993 14 0 1,717 NA

1994 15 0 1,800 NA

1995 11 0 1,482 NA

1996 10 0 1,696 NA

1997 17 0 1,852 NA

1998 15 0 1,840 NA

Texas - Total

1977 9,751 637 56,422 NA

1978 8,911 533 55,583 NA

1979 8,284 471 53,021 2,482

1980 8,206 384 50,287 2,452

1981 8,093 459 50,469 2,646

1982 7,616 377 49,757 2,771

1983 7,539 421 50,052 3,038

1984 7,557 735 49,883 3,048

1985 g7,782 609 g41,775 g2,981

1986 g7,152 1,270 g40,574 g2,964

1987 g7,112 1,028 g38,711 g2,822

1988 g7,043 1,099 g38,167 g2,617

1989 g6,966 805 g38,381 g2,563

1990 g7,106 618 g38,192 g2,575

1991 g6,797 756 g36,174 g2,493

1992 g6,441 g612 g35,093 g2,402

1993 g6,171 g581 g34,718 g2,469

1994 g5,847 g491 g35,974 g2,414

1995 g5,743 g395 g36,542 g2,524

1996 g5,736 g358 g38,270 g2,606

1997 g5,687 g479 g37,761 g2,687

1998 g4,927 g400 g37,584 g2,544

gExcludes Federal offshore; now included in Federal OffshoreGulf of Mexico (Texas).

Texas - RRC District 1

1977 *174 0 1,319 NA

1978 111 2 986 NA

1979 110 0 919 23

1980 *150 0 829 24

1981 127 5 *1,022 26

1982 129 6 892 29

1983 165 6 1,087 43

1984 173 4 838 39

1985 177 8 967 40

1986 144 1 913 35

1987 143 1 812 27

1988 136 1 1,173 30

1989 139 1 1,267 25

1990 252 0 1,048 26

1991 227 0 1,030 28

1992 185 0 933 27

1993 133 0 698 26

1994 100 1 703 26

1995 90 6 712 26

1996 86 1 906 46

1997 83 <1 953 54

1998 61 0 1,104 38
Energy Information Administration

78 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Texas - RRC District 2 Onshore

1977 395 80 3,162 NA

1978 334 1 2,976 NA

1979 292 1 2,974 64

1980 252 1 2,502 64

1981 229 1 2,629 88

1982 206 0 2,493 75

1983 192 0 2,534 99

1984 192 <1 2,512 103

1985 168 0 2,358 100

1986 148 <1 2,180 89

1987 137 0 2,273 102

1988 117 0 2,037 92

1989 107 0 1,770 72

1990 91 0 1,737 80

1991 90 0 1,393 75

1992 86 0 1,389 80

1993 77 0 1,321 86

1994 74 0 1,360 86

1995 61 0 1,251 93

1996 63 <1 1,322 93

1997 66 0 1,634 87

1998 45 <1 1,614 85

Texas - RRC District 3 Onshore

1977 937 33 7,518 NA

1978 794 22 7,186 NA

1979 630 32 6,315 231

1980 581 11 5,531 216

1981 552 11 5,292 230

1982 509 22 4,756 265

1983 517 27 4,680 285

1984 522 25 4,708 270

1985 471 6 4,180 260

1986 420 3 3,753 237

1987 386 4 3,632 241

1988 360 16 3,422 208

1989 307 11 3,233 213

1990 275 13 2,894 181

1991 300 28 2,885 208

1992 304 27 2,684 211

1993 327 31 2,972 253

1994 330 61 3,366 254

1995 267 27 3,866 272

1996 281 27 4,349 289

1997 259 28 4,172 286

1998 211 28 3,961 246

Texas - RRC District 4 Onshore

1977 145 7 9,621 NA

1978 123 3 9,031 NA

1979 113 4 8,326 248

1980 96 3 8,130 252

1981 97 6 8,004 260

1982 87 7 8,410 289

1983 96 3 8,316 292

1984 99 3 8,525 295

1985 98 2 8,250 269

1986 87 2 8,274 281

1987 80 2 7,490 277

1988 65 1 7,029 260

1989 77 <1 7,111 260

1990 67 <1 7,475 279

1991 52 <1 7,048 273

1992 50 <1 6,739 272

1993 59 <1 7,038 278

1994 41 <1 7,547 290

1995 50 <1 7,709 287

1996 51 0 7,769 323

1997 70 <1 8,099 347

1998 40 0 8,429 363

Texas - RRC District 5

1977 68 0 931 NA

1978 *68 0 *1,298 NA

1979 55 1 1,155 34

1980 52 0 1,147 44

1981 49 0 1,250 49

1982 45 0 1,308 53

1983 42 0 1,448 73

1984 36 <1 1,874 74

1985 *59 1 2,058 77

1986 *53 1 2,141 86

1987 54 0 2,119 88

1988 48 0 1,996 81

1989 46 0 1,845 80

1990 47 0 1,875 81

1991 46 0 1,863 71

1992 56 0 1,747 71

1993 52 0 1,867 64

1994 49 0 2,011 59

1995 34 0 1,862 54

1996 29 0 2,079 54

1997 54 0 1,710 35

1998 40 0 1.953 35
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 79

Texas - RRC District 6

1977 1,568 12 3,214 NA

1978 1,444 3 3,240 NA

1979 1,177 6 3,258 272

1980 1,115 6 4,230 321

1981 1,040 7 4,177 308

1982 947 6 4,326 278

1983 918 5 4,857 342

1984 889 5 4,703 298

1985 851 4 4,822 293

1986 750 2 4,854 277

1987 733 3 4,682 264

1988 685 5 4,961 263

1989 631 4 5,614 266

1990 605 6 5,753 247

1991 504 7 5,233 243

1992 442 7 5,317 251

1993 406 <1 5,508 248

1994 424 <1 5,381 265

1995 409 1 5,726 271

1996 359 1 5,899 290

1997 348 1 5,887 260

1998 308 0 5,949 276

Texas - RRC District 7B

1977 250 NA 699 NA

1978 190 NA 743 NA

1979 208 NA *751 64

1980 196 NA *745 85

1981 254 NA 804 102

1982 199 NA 805 105

1983 217 NA 1,027 133

1984 218 62 794 106

1985 239 63 708 104

1986 193 64 684 109

1987 200 46 697 92

1988 205 42 704 98

1989 204 11 459 73

1990 198 8 522 76

1991 184 8 423 82

1992 163 11 455 68

1993 *171 7 477 79

1994 145 5 425 62

1995 126 4 440 70

1996 136 4 520 65

1997 155 3 478 59

1998 115 0 442 51

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Texas - RRC District 7C

1977 191 NA 2,831 NA

1978 202 NA 2,821 NA

1979 206 NA 2,842 182

1980 207 NA 2,378 135

1981 230 NA 2,503 186

1982 229 NA 2,659 199

1983 228 NA 2,568 219

1984 240 24 2,866 233

1985 243 21 2,914 256

1986 213 22 2,721 246

1987 220 25 2,708 243

1988 212 31 2,781 238

1989 247 16 3,180 238

1990 274 8 3,514 256

1991 253 9 3,291 241

1992 255 33 3,239 289

1993 199 15 3,215 273

1994 221 14 3,316 265

1995 204 8 3,107 274

1996 219 5 3,655 303

1997 227 4 3,407 327

1998 173 1 3,113 282

Texas - RRC District 8

1977 2,915 127 11,728 NA

1978 2,795 102 11,093 NA

1979 2,686 88 10,077 505

1980 2,597 86 9,144 498

1981 2,503 105 8,546 537

1982 2,312 75 8,196 588

1983 2,350 99 8,156 681

1984 2,342 363 7,343 691

1985 2,333 325 7,330 665

1986 2,183 592 7,333 717

1987 2,108 399 6,999 640

1988 2,107 412 7,058 547

1989 2,151 366 6,753 554

1990 2,152 282 6,614 558

1991 2,114 328 6,133 477

1992 2,013 260 5,924 444

1993 2,057 262 5,516 439

1994 2,002 256 5,442 414

1995 2,032 187 5,441 444

1996 2,079 217 5,452 429

1997 2,100 308 5,397 459

1998 1,865 272 4,857 491
Energy Information Administration

80 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Texas - RRC District 8A

1977 2,626 291 1,630 NA

1978 2,439 330 1,473 NA

1979 2,371 270 1,055 351

1980 2,504 196 1,057 290

1981 2,538 247 1,071 335

1982 2,481 200 1,041 296

1983 2,366 203 966 262

1984 2,413 217 907 282

1985 2,711 147 958 283

1986 2,618 559 845 331

1987 2,735 525 876 307

1988 2,800 569 832 326

1989 2,754 377 1,074 332

1990 2,847 285 1,036 354

1991 2,763 363 1,073 333

1992 2,599 273 1,239 257

1993 2,435 264 1,043 298

1994 2,223 154 1,219 267

1995 2,233 156 941 284

1996 2,207 99 931 262

1997 2,098 131 847 290

1998 1,895 99 807 226

Texas - RRC District 9

1977 260 28 724 NA

1978 190 27 *908 NA

1979 200 30 *700 79

1980 218 37 649 92

1981 225 34 953 86

1982 219 17 *1,103 119

1983 220 18 932 121

1984 214 25 900 119

1985 285 27 892 111

1986 237 19 868 119

1987 206 21 834 115

1988 202 18 783 106

1989 200 16 703 94

1990 193 12 776 104

1991 162 11 738 101

1992 176 1 670 92

1993 168 2 688 92

1994 159 <1 728 98

1995 149 <1 738 94

1996 144 0 705 119

1997 144 0 794 98

1998 111 0 734 93

Texas - RRC District 10

1977 *120 4 7,744 NA

1978 90 0 7,406 NA

1979 97 2 6,784 375

1980 89 2 6,435 369

1981 107 2 6,229 364

1982 112 2 6,210 391

1983 105 6 5,919 413

1984 108 6 5,461 440

1985 *140 5 5,469 433

1986 *104 5 5,276 428

1987 102 2 4,962 417

1988 99 4 4,830 363

1989 97 3 4,767 342

1990 99 3 4,490 328

1991 95 2 4,589 356

1992 89 <1 4,409 336

1993 83 <1 4,040 329

1994 75 <1 4,246 326

1995 80 6 4,436 353

1996 74 4 4,391 332

1997 79 4 4,094 382

1998 62 0 4,273 354

Texas - State and Federal Offshore

1977 102 0 5,301 NA

1978 131 1 6,422 NA

1979 139 0 7,865 54

1980 149 0 7,510 62

1981 142 0 7,989 75

1982 141 0 7,558 84

1983 123 0 7,562 75

1984 111 0 8,452 98

1985 119 0 8,129 90

1986 103 0 8,176 109

1987 96 0 7,846 98

1988 85 0 7,802 94

1989 75 0 7,573 84

1990 77 0 7,758 87

1991 67 0 7,150 84

1992 197 0 7,344 122

1993 196 0 6,996 119

1994 209 10 6,613 105

1995 257 16 6,838 136

1996 218 5 6,288 133

1997 366 5 6,277 124

1998 311 0 5,996 147
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 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

Texas - State Offshore

1977 NA NA NA NA

1978 NA NA NA NA

1979 NA NA NA NA

1980 NA NA NA 12

1981 NA NA NA 13

1982 NA NA NA 18

1983 NA NA NA 11

1984 NA NA NA 10

1985 7 0 869 10

1986 2 0 732 9

1987 8 0 627 9

1988 7 0 561 5

1989 6 0 605 6

1990 6 0 458 5

1991 7 0 475 5

1992 5 0 348 4

1993 4 0 335 4

1994 4 0 230 2

1995 8 0 313 2

1996 8 0 292 1

1997 4 0 289 3

1998 1 0 348 4

Utah

1977 252 6 877 NA

1978 188 7 925 NA

1979 201 NA 948 59

1980 198 NA 1,201 127

1981 190 NA 1,912 277

1982 173 NA 2,161 (h)

1983 187 NA 2,333 (h)

1984 172 8 2,080 (h)

1985 276 13 1,999 (h)

1986 269 14 1,895 (h)

1987 284 22 1,947 (h)

1988 260 21 1,298 (h)

1989 246 50 1,507 (h)

1990 249 44 1,510 (h)

1991 233 66 1,702 (h)

1992 217 65 1,830 (h)

1993 228 54 2,040 (h)

1994 231 70 1,789 (h)

1995 216 50 1,580 (h)

1996 237 46 1,633 (h)

1997 234 70 1,839 (h)

1998 201 56 2,388 (h)

hIncluded with Wyoming.

Virginia

1977 NA NA NA NA

1978 NA NA NA NA

1979 NA NA NA NA

1980 NA NA NA NA

1981 NA NA 118 NA

1982 NA NA 122 NA

1983 NA NA 175 NA

1984 NA NA 216 NA

1985 NA NA 235 NA

1986 NA NA 253 NA

1987 NA NA 248 NA

1988 NA NA 230 NA

1989 NA NA 217 NA

1990 NA NA 138 NA

1991 NA NA 225 NA

1992 NA NA 904 NA

1993 NA NA 1,322 NA

1994 NA NA 1,833 NA

1995 NA NA 1,836 NA

1996 NA NA 1,930 NA

1997 NA NA 2,446 NA

1998 NA NA 1,973 NA

West Virginia

1977 21 0 1,567 NA

1978 *30 0 1,634 NA

1979 *48 0 1,558 74

1980 30 8 *2,422 97

1981 30 8 1,834 85

1982 48 8 2,148 79

1983 49 0 2,194 91

1984 *76 0 2,136 80

1985 40 0 2,058 85

1986 37 0 2,148 87

1987 34 0 2,242 87

1988 33 0 2,306 92

1989 30 0 2,201 100

1990 *31 0 2,207 86

1991 26 0 2,528 103

1992 27 0 2,356 97

1993 24 0 2,439 108

1994 25 0 2,565 93

1995 28 0 2,499 62

1996 25 0 2,703 61

1997 26 0 2,846 71

1998 17 0 2,868 72
Energy Information Administration

82 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Wyoming

1977 851 31 6,305 NA

1978 845 36 7,211 NA

1979 841 40 7,526 285

1980 928 28 9,100 341

1981 840 53 9,307 384

1982 856 58 9,758 i681

1983 957 61 10,227 i789

1984 954 71 10,482 i860

1985 951 18 10,617 i949

1986 849 126 9,756 i950

1987 854 27 10,023 i924

1988 815 35 10,308 i1,154

1989 825 46 10,744 i 896

1990 794 42 9,944 i812

1991 757 24 9,941 i748

1992 689 18 10,826 i660

1993 624 12 10,933 i600

1994 565 13 10,879 i564

1995 605 12 12,166 i593

1996 603 14 12,320 i727

1997 627 11 13,562 i761

1998 547 10 13,650 i675

i

Utah and Wyoming are combined.

Federal Offshore - Total

1985 2,862 11 j34,492 702

1986 2,715 16 j34,223 681

1987 2,639 21 j31,931 638

1988 2,629 21 j32,264 622

1989 2,747 32 j32,651 678

1990 2,805 49 31,433 619

1991 2,620 18 29,448 640

1992 2,569 31 27,767 610

1993 2,745 18 27,143 630

1994 2,780 53 28,388 624

1995 3,089 62 29,182 655

1996 3,085 45 29,096 776

1997 3,477 41 28,466 920

1998 3,261 0 26,902 931

j

Includes State offshore Alabama.

Note: Data not tabulated for years 1977-1984.

Federal Offshore - Pacific (California)

1985 991 NA 1,119 12

1986 974 2 1,325 15

1987 1,037 2 1,452 17

1988 1,024 0 1,552 21

1989 987 0 1,496 25

1990 962 0 1,454 18

1991 785 0 1,162 16

1992 734 0 1,118 20

1993 673 0 1,099 25

1994 653 0 1,170 21

1995 571 0 1,265 25

1996 518 0 1,244 23

1997 528 0 544 14

1998 468 0 480 12

Note: Data not tabulated for years 1977-1984.

Federal Offshore - Gulf of Mexico (Louisiana)

1985 1,759 11 f26,113 610

1986 1,640 14 f25,454 566

1987 1,514 19 f23,260 532

1988 1,527 21 f23,471 512

1989 1,691 32 f24,187 575

1990 1,772 49 k22,679 k519

1991 1,775 18 k21,611 k545

1992 1,643 31 k19,653 k472

1993 1,880 18 k19,383 k490

1994 1,922 43 k20,835 k500

1995 2,269 46 k21,392 k496

1996 2,357 40 k21,856 k621

1997 2,587 36 k21,934 k785

1998 2,483 7 k20,774 k776

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 1998 Annual Report 83

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Dry Natural

Crude Oil Natural Gas

Crude Oil Indicated Gas Liquids

Proved Additional Proved Proved

Year Reserves Reserves Reserves Reserves

Federal Offshore - Gulf of Mexico (Texas)

1985 112 0 7,260 80

1986 101 0 7,444 100

1987 88 0 7,219 89

1988 78 0 7,241 89

1989 69 0 6,968 78

1990 71 0 7,300 82

1991 60 0 6,675 79

1992 192 0 6,996 118

1993 192 0 6,661 115

1994 205 10 6,383 103

1995 249 16 6,525 134

1996 210 5 5,996 132

1997 362 5 5,988 121

1998 310 0 5,648 143

Note: Data not tabulated for years 1977- 1984.

Miscellaneous

1977 23 0 102 NA

1978 24 0 109 NA

1979 22 1 *153 2

1980 *38 0 176 3

1981 40 7 191 21

1982 33 0 69 4

1983 30 8 78 5

1984 23 0 75 5

1985 35 0 76 3

1986 33 0 133 2

1987 30 0 65 4

1988 34 0 83 5

1989 39 0 83 5

1990 43 1 *70 3

1991 42 5 75 8

1992 29 0 92 8

1993 34 0 94 8

1994 20 0 65 8

1995 *22 0 *69 7

1996 18 0 67 7

1997 19 0 *43 9

1998 14 0 38 8

Note: States included may vary for different report years and

hydrocarbon types.

Lower 48 States

1977 23,367 2,168 175,170 NA

1978 21,971 1,964 175,988 NA

1979 20,935 1,878 168,738 6,592

1980 21,054 1,622 165,639 6,717

1981 21,143 1,594 168,693 7,058

1982 20,452 1,478 166,522 7,212

1983 20,428 1,548 165,964 7,893

1984 20,883 1,956 162,987 7,624

1985 21,360 1,662 159,522 7,561

1986 20,014 2,597 158,922 7,784

1987 19,878 3,084 153,986 7,729

1988 19,866 3,169 158,946 7,837

1989 19,827 2,999 158,177 7,389

1990 19,730 2,514 160,046 7,246

1991 18,599 2,810 157,509 7,104

1992 17,723 2,451 155,377 7,104

1993 17,182 2,292 152,508 6,901

1994 16,690 2,129 154,104 6,869

1995 16,771 2,087 155,649 7,093

1996 16,743 1,924 157,180 7,486

1997 17,385 2,375 156,661 7,342

1998 15,982 2,328 154,114 7,204

U.S. Total

1977 31,780 3,014 207,413 NA

1978 31,355 2,362 208,033 NA

1979 29,810 2,276 200,997 6,615

1980 29,805 1,622 199,021 6,728

1981 29,426 1,594 201,730 7,068

1982 27,858 1,478 201,512 7,221

1983 27,735 2,124 200,247 7,901

1984 28,446 2,325 197,463 7,643

1985 28,416 2,041 193,369 7,944

1986 26,889 3,499 191,586 8,165

1987 27,256 3,649 187,211 8,147

1988 26,825 3,600 168,024 8,238

1989 26,501 3,749 167,116 7,769

1990 26,254 3,483 169,346 7,586

1991 24,682 4,266 167,062 7,464

1992 23,745 3,782 165,015 7,451

1993 22,957 3,453 162,415 7,222

1994 22,457 3,151 163,837 7,170

1995 22,351 2,669 165,146 7,399

1996 22,017 2,876 166,474 7,823

1997 22,546 3,207 167,223 7,973

1998 21,034 3,160 164,041 7,524
Energy Information Administration

84 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table D1. U.S. Proved Reserves of Crude Oil, 1976–1998

(Million Barrels of 42 U.S. Gallons)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1976 – – – – – – – – – e33,502 –

1977 f–40 1,503 1,117 346 496 168 130 794 2,862 31,780 –1,722

1978 366 2,799 1,409 1,756 444 267 116 827 3,008 31,355 –425

1979 337 2,438 2,001 774 424 108 104 636 2,955 29,810 –1,545

1980 219 2,883 994 2,108 572 143 147 862 2,975 29,805 –5

1981 138 2,151 880 1,409 750 254 157 1,161 2,949 29,426 –379

1982 –83 2,245 1,811 351 634 204 193 1,031 2,950 27,858 –1,568

1983 462 2,810 1,299 1,973 629 105 190 924 3,020 27,735 –123

1984 159 3,672 1,227 2,604 744 242 158 1,144 3,037 28,446 +711

1985 429 3,037 1,439 2,027 742 84 169 995 3,052 28,416 –30

1986 57 2,724 1,869 912 405 48 81 534 2,973 26,889 –1,527

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

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

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

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

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

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

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

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

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

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

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

1998 –638 2,752 2,234 –120 327 152 120 599 1,991 21,034 –1,512

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 1998 annual reports, DOE/EIA-0216.{1-21}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 85

Table D2. U.S. Lower 48 Proved Reserves of Crude Oil, 1976–1998

(Million Barrels of 42 U.S. Gallons)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1976 – – – – – – – – – e24,928 –

1977 f–40 1,499 1,116 343 496 168 130 794 2,698 23,367 –1,561

1978 –48 1,909 1,400 461 444 142 116 702 2,559 21,971 –1,396

1979 342 2,404 1,975 771 424 108 104 636 2,443 20,935 –1,036

1980 210 2,505 981 1,734 479 143 147 769 2,384 21,054 +119

1981 276 1,887 878 1,285 750 254 157 1,161 2,357 21,143 +89

1982 –82 2,146 1,462 602 633 204 193 1,030 2,323 20,452 –691

1983 462 2,247 1,298 1,411 625 105 190 920 2,355 20,428 –24

1984 160 2,801 1,214 1,747 742 207 158 1,107 2,399 20,883 +455

1985 361 2,864 1,197 2,028 581 84 169 834 2,385 21,360 +477

1986 70 2,001 1,642 429 399 48 81 528 2,303 20,014 –1,346

1987 233 2,566 1,213 1,586 294 38 101 433 2,155 19,878 –136

1988 359 2,399 1,218 1,540 340 43 127 510 2,062 19,866 –12

1989 214 2,438 1,325 1,327 342 108 87 537 1,903 19,827 –39

1990 151 1,997 996 1,152 371 98 135 604 1,853 19,730 –97

1991 164 1,898 1,848 214 327 97 87 511 1,856 18,599 –1,131

1992 297 1,343 1,066 574 279 8 84 371 1,821 17,723 –876

1993 250 1,712 1,514 448 343 319 109 771 1,760 17,182 –541

1994 187 1,873 1,346 714 316 64 111 491 1,697 16,690 –492

1995 117 1,521 765 873 434 114 333 881 1,673 16,771 +81

1996 172 1,654 926 900 479 115 141 735 1,663 16,743 –28

1997 514 1,724 1,029 1,209 459 520 119 1,098 1,665 17,385 +642

1998 –639 2,485 2,170 –324 299 56 120 475 1,554 15,982 –1,403

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 1998 annual reports, DOE/EIA-0216.{1-21}
Energy Information Administration

86 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table D3. U.S. Proved Reserves of Dry Natural Gas, 1976–1998

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

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1976 – – – – – – – – – e213,278 –

1977 f–20 13,691 15,296 –1,625 8,129 3,173 3,301 14,603 18,843 207,413 –5,865

1978 2,429 14,969 15,994 1,404 9,582 3,860 4,579 18,021 18,805 208,033 +620

1979 –2,264 16,410 16,629 –2,483 8,950 3,188 2,566 14,704 19,257 200,997 –7,036

1980 1,201 16,972 15,923 2,250 9,357 2,539 2,577 14,473 18,699 199,021 –1,976

1981 1,627 16,412 13,813 4,226 10,491 3,731 2,998 17,220 18,737 201,730 +2,709

1982 2,378 19,795 19,340 2,833 8,349 2,687 3,419 14,455 17,506 201,512 –218

1983 3,090 17,602 17,617 3,075 6,909 1,574 2,965 11,448 15,788 200,247 –1,265

1984 –2,241 17,841 14,712 888 8,299 2,536 2,686 13,521 17,193 197,463 –2,784

1985 –1,708 18,775 16,304 763 7,169 999 2,960 11,128 15,985 193,369 –4,094

1986 1,320 21,269 17,697 4,892 6,065 1,099 1,771 8,935 15,610 191,586 –1,783

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

1988 2,193 23,367 38,427 –12,867 6,803 1,638 1,909 10,350 16,670 g168,024 –19,187

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

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

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

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

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

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

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

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

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

1998 –1,635 28,003 22,263 4,105 8,197 1,074 2,162 11,433 18,720 164,041 –3,182

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 1998 annual reports, DOE/EIA-0216.{1-21}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 87

Table D4. U.S. Lower 48 Proved Reserves of Dry Natural Gas, 1976–1998

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

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1976 – – – – – – – – – e180,838 –

1977 f–21 13,689 15,229 –1,561 8,056 3,173 3,301 14,530 18,637 175,170 –5,668

1978 2,446 13,912 14,670 1,688 9,582 3,860 4,277 17,719 18,589 175,988 818

1979 –2,202 15,691 16,398 –2,909 8,949 3,173 2,566 14,688 19,029 168,738 –7,250

1980 1,163 15,881 15,819 1,225 9,046 2,539 2,577 14,162 18,486 165,639 –3,099

1981 1,840 16,258 13,752 4,346 10,485 3,731 2,994 17,210 18,502 168,693 3,054

1982 2,367 17,570 19,318 619 8,349 2,687 3,419 14,455 17,245 166,522 –2,171

1983 3,089 17,296 16,875 3,510 6,908 1,574 2,965 11,447 15,515 165,964 –558

1984 –2,245 16,934 14,317 372 8,298 2,536 2,686 13,520 16,869 162,987 –2,977

1985 –1,349 18,252 15,752 1,151 7,098 999 2,960 11,057 15,673 159,522 –3,465

1986 1,618 21,084 16,940 5,762 6,064 1,099 1,761 8,924 15,286 158,922 –600

1987 1,066 16,809 14,164 3,711 4,542 1,077 1,499 7,118 15,765 153,986 –4,936

1988 2,017 22,571 13,676 10,912 6,771 1,638 1,909 10,318 16,270 158,946 4,960

1989 2,997 26,446 23,507 5,936 6,184 1,450 2,243 9,877 16,582 158,177 –769

1990 1,877 17,916 13,344 6,449 7,898 2,004 2,412 12,314 16,894 160,046 +1,869

1991 2,967 19,095 15,235 6,827 5,074 848 1,563 7,485 16,849 157,509 –2,537

1992 1,946 17,878 11,941 7,883 4,621 649 1,724 6,994 17,009 155,377 –2,132

1993 915 16,918 12,139 5,694 6,076 899 1,858 8,833 17,396 152,508 –2,869

1994 1,896 21,121 15,832 7,185 6,936 1,894 3,480 12,310 17,899 154,104 +1596

1995 973 19,903 12,680 8,196 6,801 1,666 2,452 10,919 17,570 155,649 +1,545

1996 3,640 16,930 12,875 7,695 7,751 1,390 3,110 12,251 18,415 157,180 +1,531

1997 –609 19,849 16,657 2,583 10,571 2,681 2,382 15,634 18,734 156,661 –519

1998 –1,463 27,834 22,138 4,233 8,195 1,070 2,162 11,427 18,207 154,114 –2,547

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 1998 annual reports, DOE/EIA-0216.{1-21}
Energy Information Administration

88 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table D5. U.S. Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–1998

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

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1978 – – – – – – – – – e208,033 –

1979 5,356 17,077 17,300 5,133 9,332 3,279 2,637 15,248 20,079 208,335 +302

1980 1,253 17,668 16,531 2,390 9,757 2,629 2,648 15,034 19,500 206,259 –2,076

1981 2,057 17,156 14,413 4,800 10,979 3,870 3,080 17,929 19,554 209,434 +3,175

1982 2,598 20,596 20,141 3,053 8,754 2,785 3,520 15,059 18,292 209,254 –180

1983 4,363 18,442 18,385 4,420 7,263 1,628 3,071 11,962 16,590 209,046 –208

1984 –2,413 18,751 15,418 920 8,688 2,584 2,778 14,050 18,032 205,984 –3,062

1985 –1,299 19,732 17,045 1,388 7,535 1,040 3,053 11,628 16,798 202,202 –3,782

1986 2,137 22,392 18,557 5,972 6,359 1,122 1,855 9,336 16,401 201,109 –1,093

1987 1,199 18,455 14,933 4,721 4,818 1,128 1,556 7,502 16,904 196,428 –4,681

1988 2,180 24,638 f39,569 –12,751 7,132 1,677 1,979 10,788 17,466 f176,999 –19,429

1989 2,537 27,844 24,624 5,757 6,623 1,488 2,313 10,424 17,752 175,428 –1,571

1990 1,494 19,861 14,024 7,331 8,287 2,041 2,492 12,820 18,003 177,576 +2,148

1991 3,368 20,758 16,189 7,937 5,298 871 1,655 7,824 18,012 175,325 –2,251

1992 2,543 18,906 12,532 8,917 4,895 668 1,773 7,336 18,269 173,309 –2,016

1993 1,048 18,394 12,853 6,589 6,376 927 1,930 9,233 18,641 170,490 –2,819

1994 1,977 22,345 16,509 7,813 7,299 1,941 3,606 12,846 19,210 171,939 +1,449

1995 889 21,548 13,457 8,980 7,204 1,709 2,518 11,431 18,874 173,476 +1,537

1996 4,288 18,034 13,757 8,565 8,189 1,491 3,209 12,889 19,783 175,147 +1,671

1997 –730 22,712 17,655 4,327 11,179 2,747 2,455 16,381 20,134 175,721 +574

1998 –3,256 28,281 21,019 4,006 8,591 1,176 2,234 12,001 19,619 172,109 –3,612

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 1998 annual reports, DOE/EIA-0216.{2-21}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 89

Table D6. U.S. Lower 48 Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–1998

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

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1978 – – – – – – – – – e175,988 –

1979 5,402 16,358 17,069 4,691 9,331 3,264 2,637 15,232 19,851 176,060 +72

1980 1,218 16,577 16,427 1,368 9,446 2,629 2,648 14,723 19,287 172,864 –3,196

1981 2,270 17,002 14,352 4,920 10,973 3,870 3,076 17,919 19,318 176,385 +3,521

1982 2,586 18,371 20,119 838 8,754 2,785 3,520 15,059 18,030 174,252 –2,133

1983 4,366 18,136 17,643 4,859 7,262 1,628 3,071 11,961 16,317 174,755 +503

1984 –2,409 17,844 15,023 412 8,687 2,584 2,778 14,049 17,708 171,508 –3,247

1985 –1,313 19,203 16,490 1,400 7,463 1,040 3,053 11,556 16,485 167,979 –3,529

1986 2,114 22,207 17,797 6,524 6,357 1,122 1,845 9,324 16,073 167,754 –225

1987 1,200 17,733 14,865 4,068 4,772 1,116 1,556 7,444 16,553 162,713 –5,041

1988 2,025 23,829 14,439 11,415 7,099 1,677 1,979 10,755 17,063 167,820 +5,107

1989 2,545 27,616 24,488 5,673 6,467 1,485 2,313 10,265 17,349 166,409 –1,411

1990 1,811 18,784 13,925 6,670 8,232 2,041 2,492 12,765 17,661 168,183 +1,774

1991 3,367 19,961 15,948 7,380 5,281 871 1,614 7,766 17,657 165,672 –2,511

1992 2,265 18,728 12,511 8,482 4,840 668 1,773 7,281 17,851 163,584 –2,088

1993 996 17,714 12,743 5,967 6,349 927 1,922 9,198 18,245 160,504 –3,080

1994 1,924 22,071 16,458 7,537 7,294 1,941 3,606 12,841 18,756 162,126 +1,622

1995 1,304 20,928 13,403 8,829 7,162 1,709 2,518 11,389 18,443 163,901 +1,775

1996 4,219 17,832 13,586 8,465 8,183 1,430 3,209 12,822 19,337 165,851 +1,950

1997 –835 20,878 17,556 2,497 11,165 2,747 2,455 16,367 19,657 165,048 –803

1998 –3,093 28,111 20,894 4,124 8,589 1,172 2,234 11,995 19,101 162,066 –2,982

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 1998 annual reports, DOE/EIA-0216.{2-21}
Energy Information Administration

90 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table D7. U.S. Proved Reserves of Natural Gas Liquids, 1978–1998

(Million Barrels of 42 U.S. Gallons)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1978 – – – – – – – – – e6,772 –

1979 f64 677 726 15 364 94 97 555 727 6,615 –157

1980 153 743 639 257 418 90 79 587 731 6,728 +113

1981 231 729 643 317 542 131 91 764 741 7,068 +340

1982 299 811 832 278 375 112 109 596 721 7,221 +153

1983 849 847 781 915 321 70 99 490 725 7,901 +680

1984 –123 866 724 19 348 55 96 499 776 7,643 –258

1985 426 906 744 588 337 44 85 466 753 7,944 +301

1986 367 1,030 807 590 263 34 72 369 738 8,165 +221

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

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

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

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

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

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

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

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

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

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

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

1998 –361 1,302 1,094 –153 383 66 88 537 833 7,524 –449

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 1998 annual reports, DOE/EIA-0216.{2-21}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 91

Table D8. U.S. Lower 48 Proved Reserves of Natural Gas Liquids, 1978–1998

(Million Barrels of 42 U.S. Gallons)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Reserves from

Adjustmentsa Increases Decreases Adjustments Extensions Discoveries in Old Fields Discoveries Production 12/31 Prior Year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1978 – – – – – – – – – e6,749 –

1979 f63 677 726 14 364 94 97 555 726 6,592 –157

1980 165 743 639 269 418 90 79 587 731 6,717 +125

1981 233 728 643 318 542 131 91 764 741 7,058 +341

1982 300 811 832 279 375 112 109 596 721 7,212 +154

1983 850 847 781 916 321 70 99 490 725 7,893 +681

1984 –115 847 724 8 348 55 96 499 776 7,624 –269

1985 70 883 731 222 334 44 85 463 748 7,561 –63

1986 363 1,030 804 589 263 34 72 369 735 7,784 +223

1987 179 846 655 370 212 39 55 306 731 7,729 –55

1988 10 1,167 715 462 267 41 72 380 734 7,837 +108

1989 –273 1,141 1,018 –150 259 83 74 416 714 7,389 –448

1990 –60 827 606 161 298 39 73 410 714 7,246 –143

1991 183 815 677 321 187 25 55 267 730 7,104 –142

1992 225 796 542 479 183 20 64 267 746 7,104 0

1993 101 755 631 225 245 24 64 333 761 6,901 –203

1994 38 872 676 234 314 54 131 499 765 6,869 –32

1995 204 918 688 434 432 52 67 551 761 7,093 +224

1996 417 832 654 595 450 56 109 615 817 7,486 +393

1997 –107 965 910 –52 533 114 90 737 829 7,342 –144

1998 –74 1,301 1,093 134 383 66 88 671 809 7,204 –138

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 1998 annual reports, DOE/EIA-0216.{2-21}
Energy Information Administration

92 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-1998

Gulf of Mexico Depth

Greater than Less than Deepwater

Year Total Louisianaa Texas 200 metersb 200 metersb Percentageb

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

Production

1992 267 253 14 46 221 17.2

1993 266 252 14 46 220 17.3

1994 265 245 20 53 212 20.1

1995 292 262 30 77 215 26.4

1996 303 265 38 90 213 29.7

1997 342 298 44 123 219 36.0

1998 372 336 36 171 201 46.0

Reserves

1992 1,835 1,643 192 557 1,278 30.4

1993 2,072 1,880 192 824 1,248 39.8

1994 2,127 1,922 205 877 1,250 41.2

1995 2,518 2,269 249 1,241 1,277 49.3

1996 2,567 2,357 210 1,311 1,256 51.1

1997 2,949 2,587 362 1,682 1,267 57.0

1998 2,793 2,483 310 1,611 1,182 57.8

Natural Gas, Wet After Lease Separation

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

Production

1992 4,576 3,292 1,284 166 4,410 3.6

1993 4,651 3,383 1,268 229 4,422 4.9

1994 4,797 3,505 1,292 294 4,503 6.1

1995 4,679 3,421 1,258 354 4,315 7.8

1996 5,045 3,752 1,293 549 4,496 10.9

1997 5,230 3,984 1,246 577 4,653 11.0

1998 4,967 3,817 1,150 724 4,243 14.6

Reserves

1992 27,050 20,006 7,044 3,273 23,777 12.1

1993 26,463 19,751 6,712 3,495 22,968 13.2

1994 27,626 21,208 6,418 4,772 22,854 17.3

1995 28,229 21,664 6,565 5,811 22,418 20.6

1996 28,153 22,119 6,034 6,389 21,764 22.7

1997 28,455 22,428 6,027 7,491 20,964 26.3

1998 26,937 21,261 5,676 7,575 19,362 28.1

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

Production

1992 91 76 15 4 87 4.4

1993 97 80 17 6 91 6.2

1994 98 83 15 6 92 6.1

1995 85 71 14 12 73 14.1

1996 101 84 17 13 88 12.9

1997 140 123 17 17 123 12.1

1998 139 120 19 26 113 18.7

Reserves

1992 590 472 118 91 499 15.4

1993 605 490 115 97 508 16.0

1994 603 500 103 110 493 18.2

1995 630 496 134 294 336 46.7

1996 753 621 132 300 453 39.8

1997 906 785 121 349 557 38.5

1998 919 776 143 387 532 42.1

aIncludes Federal Offshore Alabama.

bRevisions result from reclassing all field depths to match Minerals Management Service assignments.

Source: Based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves.”
Table D10. 1998 Reported Reserves in Nonproducing Reservoirs for Crude Oil, Lease Condensate, and

Natural Gasa

Lease Nonassociated Associated Total

Crude Oil Condensate Gas Dissolved Gas Gas

State and Subdivision (mbbls) (mbbls) (bcf) (bcf) (bcf)

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 806 - 497 70 567

Lower 48 States .......................... 3,341 530 30,073 5,407 35,480

Alabama . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 6 477 2 479

Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 - 96 3 99

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 937 - 120 311 431

Coastal Region Onshore . . . . . . . . . . . . . . . . 137 - 0 17 17

Los Angeles Basin Onshore . . . . . . . . . . . . . . 53 - 0 48 48

San Joaquin Basin Onshore . . . . . . . . . . . . . . 740 - 120 244 364

State Offshore ......................... 7 - 0 2 2

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 8 1,300 331 1,631

Florida ................................. 6 - - - -

Illinois................................... 4 - - - -

Indiana.................................. - - - - -

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 - 108 9 117

Kentucky . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - - 183 - 183

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 198 55 3,049 296 3,345

North . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 8 967 22 989

South Onshore . . . . . . . . . . . . . . . . . . . . . . . . 143 44 1,870 239 2,109

State Offshore . . . . . . . . . . . . . . . . . . . . . . . . . 37 3 212 35 247

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 - 68 6 74

Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49 1 117 9 126

Montana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 - 89 3 92

Nebraska ................................ - - - - -

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97 11 1,776 109 1,885

East . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97 4 261 105 366

West ................................ - 7 1,515 4 1,519

New York . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - - 12 - 12

North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 3 68 19 87

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - - 38 5 43

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 98 20 1,499 103 1,602

Pennsylvania . . . . . . . . . . . . . . . . . . . . . . . . . . . . - - 222 14 236

Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 448 74 6,453 599 7,052

RRC District 1 . . . . . . . . . . . . . . . . . . . . . . . . . . 4 3 297 3 300

RRC District 2 Onshore . . . . . . . . . . . . . . . . . 5 2 392 8 400

RRC District 3 Onshore . . . . . . . . . . . . . . . . . 24 23 884 62 946

RRC District 4 Onshore . . . . . . . . . . . . . . . . . 7 28 2,153 88 2,241

RRC District 5 . . . . . . . . . . . . . . . . . . . . . . . . . 5 1 575 3 578

RRC District 6 . . . . . . . . . . . . . . . . . . . . . . . . . 60 10 1,134 35 1,169

RRC District 7B . . . . . . . . . . . . . . . . . . . . . . . . 12 - 4 15 19

RRC District 7C . . . . . . . . . . . . . . . . . . . . . . . . 10 1 247 29 276

RRC District 8 . . . . . . . . . . . . . . . . . . . . . . . . . 168 1 310 281 591

RRC District 8A . . . . . . . . . . . . . . . . . . . . . . . . 143 - 5 52 57

RRC District 9 . . . . . . . . . . . . . . . . . . . . . . . . . 4 - 6 4 10

RRC District 10 . . . . . . . . . . . . . . . . . . . . . . . . 6 4 368 19 387

State Offshore . . . . . . . . . . . . . . . . . . . . . . . . . - 2 78 - 78

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 1 595 74 669

Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - - 878 - 878

West Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 - 439 1 440

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31 9 4,089 35 4,124

Federal Offshoreb

......................... 1,364 340 8,396 3,476 11,872

Pacific (California) . . . . . . . . . . . . . . . . . . . . . . . 21 4 47 18 65

Gulf of Mexico (Louisiana)b

................ 1,128 278 6,602 2,473 9,075

Gulf of Mexico (Texas) . . . . . . . . . . . . . . . . . . . . 215 58 1,747 985 2,732

Miscellaneousc

........................... 1 - 1 2 3

Total ............................... 4,147 530 30,570 5,477 36,047

aIncludes only those operators who produced during the report year 400,000 barrels of crude oil or 2 billion cubic feet of wet natural gas,

or more (Category I and Category II operators). bIncludes Federal offshore Alabama.

cIncludes Arizona, Maryland, Missouri, Nevada, Oregon, South Dakota and Tennessee.

Source: Form EIA-23, "Annual Survey of Domestic Oil and Gas Reserves," 1998.

Energy Information Administration 93

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
Appendix E

Summary of Data Collection Operations
Appendix E

Summary of Data Collection Operations

Form EIA-23 Survey Design

The data collected on Form EIA-23, “Annual Survey of

Domestic Oil and Gas Reserves,” were used to produce

this report. This section provides information

concerning the survey design, response statistics,

reporting requirements, and frame maintenance.

Form EIA-23 is mailed annually to all known large and

intermediate size operators, and a scientifically

selected sample of small operators. Operator size

categories were based upon their annual production as

indicated in various Federal, State, and commercial

records. The term State/subdivision refers to an

individual subdivision within a State or an individual

State that is not subdivided. Operators were divided

into the three size categories shown below.

 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.

 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.

 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 1998 by crude oil or

natural gas well operators who were active as of

December 31, 1998. 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 1991 and 1998, and depicts

the number of active operators, 1991 showing the

largest in the series. The 1998 sampling frame consisted

of 178 Category I, 420 Category II, 862 Category III

Certainty, and 22,160 Category III Noncertainty

operators, for a total of 23,620 active operators. The

survey sample consisted of 1,460 operators selected

with certainty that included all of the Category I and II

Certainty operators, the 862 smaller operators that

were selected with certainty because of their size in

relation to the area or areas in which they operated, and

1,459 Noncertainty operators selected as a systematic

random sample of the remaining operators.

Form EIA-23

Response Statistics

Each company and its parent company or subsidiaries

were required to file Form EIA-23 if they met the

survey specifications. Response to the 1998 survey is

summarized in Table E2. EIA makes a considerable

effort to gain responses from all operators. About 7

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 200 nonoperators, 5 had successor operators that

had taken over the production of the nonoperator.

These successor operators were subsequently sampled.

The overall response rate for the 1998 survey was 99.7

percent. This compares with a 99.8 percent overall

response rate for all operators in 1997.

Form EIA-23 Reporting

Requirements

The collection format for Form EIA-23 actually consists

of two forms. The form the respondent is required to

file is dependent upon the annual production levels of

crude oil, natural gas, and lease condensate. Category I

and Category II operators file a more detailed field

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 97
level data form. Category III operators file a summary

report which is aggregated at a State/subdivision level.

The cover page required of all respondents identifies

each operator by name and address (Figure I1,

Appendix I). The oil and gas producing industry

includes a large number of small enterprises. To

minimize reporting burden, only a sample of small

operators were required to file a summary report of

Form EIA-23 (Figures I2 and I3, Appendix I). Report

year production data were required by

State/subdivision areas for crude oil, natural gas, and

lease condensate. Proved reserves data for operators

were required only for those properties where

estimates existed in the respondent’s records.

All Category I and Category II operators were required

to file field level data on Schedule A, “Operated Proved

Reserves, Production, and Related Data by Field,” for

each oil and/or gas field in which the respondent

operated properties (Figure I4, Appendix I). All

Category I and those Category II operators who had

reserve estimates were required to file on a total

operated basis for crude oil, nonassociated natural gas,

associated-dissolved natural gas, and lease condensate.

The following data items were required to be filed:

proved reserves at the beginning and the end of the

report year, revision increases and revision decreases,

extensions, new field discoveries, new reservoirs in old

fields, production, indicated additional reserves of

crude oil, nonproducing reserves, field discovery year,

water depth, and field location information.

Energy Information Administration

98 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table E1. Comparison of the EIA-23 Sample and Sampling Frame, 1991-1998

Number of Operators

Operator Category 1991 1992 1993 1994 1995 1996 1997 1998

Certainty

Category I. . . . . . . . . . . . . 144 157 160 161 161 176 180 178

Category II . . . . . . . . . . . . 484 480 500 482 476 486 461 420

Category III............ 2,074 1,896 1,723 1,694 1,596 3 1,194 862

Sampled ............. 2,702 2,533 2,383 2,337 2,233 665 1,835 1,460

Percent Sampled . . . . . . . 100 100 100 100 100 100 100 100

Noncertainty

Sampled .............. 1,760 1,724 1,691 1,737 1,632 0 1,645 1,459

Percent Sampled ....... 8 8 8 8 8 0 8 7

Total

Active Operators........ R24,846 R24,173 R23,656 R24,222 22,766 23,410 22,678 23,620

Not Sampled .......... 20,384 19,916 19,791 20,148 18,901 22,745 19,198 20,701

Sampled .............. 4,462 4,257 4,074 4,074 3,865 665 3,480 2,919

Percent Sampled . . . . . . . 18 18 17 17 17 3 15 12

R=Revised data.

Note: Active operators in 1998 include 10 operators added after December 29, 1998 and not included in Table E3.

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

Table E2. Form EIA-23 Survey Response Statistics, 1998

Original Netb Responding Nonresponding

Sample Successora Category Non-c Adjustedd Operators Operators

Operator Category Selected Operators Changes operators Sample Number Percent Number Percent

Certainty

Category I . . . . . . . 178 0 -1 -7 170 170 100.0 0 0.0

Category II . . . . . . . 420 2 15 -19 418 418 100.0 0 0.0

Category III . . . . . . . 862 3 -14 -44 807 807 100.0 0 0.0

Subtotal......... 1,460 5 0 -70 1,395 1,395 100.0 0 0.0

Noncertainty ........ 1,459 0 0 -130 1,329 1,321 99.4 8 0.6

Total ............ 2,919 5 0 -200 2,724 2,716 99.7 8 0.3

aSuccessor operators are those, not initially sampled, that have taken over the production of a sampled operator.

bNet of recategorized operators in the sample (excluding nonoperators).

c

Includes former operators reporting that they were not operators during the report year and operators that could not be located who are treated as nonoperators. dAdjusted sample equals original sample plus successor operators plus net category changes minus nonoperators.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves” 1998.
Category II operators who did not have reserves

estimates were required to file the field location

information and report year production for the four

hydrocarbon types from properties where reserves

were not estimated. These respondents used Schedule

B, “Footnotes,” to provide clarification of reported data

items when required in the instructions, or electively to

provide narrative or detail to explain any data item

filed (Figure I5, Appendix I).

Crude oil and lease condensate volumes were reported

rounded to thousands of barrels of 42 U.S. gallons at

60 Fahrenheit, and natural gas volumes were reported

rounded to millions of cubic feet. All natural gas

volumes were requested to be reported at 60

Fahrenheit and a pressure base of 14.73 pounds per

square inch absolute. Other minor report preparation

standards were specified to assure that the filed data

could be readily processed.

Oil and Gas Field Coding

A major effort to create standardized codes for all

identified oil or gas fields throughout the United States

was implemented during the 1982 survey year.

Information from previous lists was reviewed and

reconciled with State lists and a consolidated list was

created. The publication of the Oil and Gas Field Code

Master List 1998, in January of 1999, was the 17th annual

report and reflected data collected through October

1998. 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 1998, Form EIA-23 National estimates of

production were 2,169 million barrels for crude oil and

lease condensate or 113 million barrels (5 percent)

lower than that reported in the Petroleum Supply Annual

1998 for crude oil and lease condensate. Form EIA-23

National estimates of production for dry natural gas

were 18,720 billion cubic feet or 90 billion cubic feet (.05

percent) lower than the Natural Gas Annual 1998 for

1998 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, is revised annually. In addition,

outside sources, such as State publications and

electronic data, and commercial information data bases

such as IHS Energy Group, 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 1998 survey

mailing. These changes resulted from all frame

maintenance activities.

The Form EIA-23 operator frame contained a total of

68,468 entries as of December 29, 1998. Of these, 23,392

were confirmed operators. These are operators who

have filed in the past or for whom the EIA has recent

production data from an outside source. The remaining

operators (including both definite and probable

nonoperators) exist as a pool of names and addresses

that may be added to the active list if review indicates

activity.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 99
Form EIA-64A Survey Design

The data for this report are also collected on Form

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

Liquids Production.” This section provides

information concerning the survey design, response

statistics, reporting requirements, and frame

maintenance for Form EIA-64A.

Form EIA-23 for report years 1977 and 1978 required

natural gas well operators to report their natural gas

data on a fully dry basis. It was discovered in the course

of those surveys that many operators had little or no

knowledge of the extraction of liquids from their

produced natural gas streams once custody transfer

had taken place. Therefore, these operators reverted to

reporting the only natural gas volume data they had in

their possession. These volume data were for dryer

natural gas than that which had passed through the

wellhead, but wetter than fully dry natural gas. With

reference to Figure E1, they reported their volumes

either at the wellhead or after removal of lease

condensate in their lease or field separation facilities.

Some of the larger operators, however, also owned or

operated natural gas processing plants. They reported

their volumes after removal of both lease condensate

and plant liquids, as required by Form EIA-23. The

aggregate volumes resulting from the 1977 and 1978

surveys, therefore, were neither fully dry (as was

intended) nor fully wet. They do appear to have been

more dry than wet simply because the operators who

reported fully dry volumes also operated properties

that contained the bulk of proved natural gas reserves.

The EIA recognized that its estimates of proved

reserves of natural gas liquids (NGL) had to reflect not

only those volumes extractable in the future under

current economic and operating conditions at the lease

or field (lease condensate), but also volumes (plant

liquids) extractable downstream at existing natural gas

processing plants. Form EIA-64, which already

canvassed these processing plants, did not request that

the plants’ production volumes be attributed to source

areas. Beginning with the 1979 survey, a new form to

collect plant liquids production according to the area or

areas where their input natural gas stream had been

produced was mailed to all of the operating plants. The

instructions for filing the Form EIA-23 were altered to

collect data from natural gas well operators that

reflected those volumes of natural gas dried only

through the lease or field separation facilities. The

reporting basis of these volumes are referred to as “wet

after lease separation.” The methodology used to

estimate NGL reserves by State and State subdivision is

provided in Appendix F.

Form EIA-64A

Response Statistics

EIA mailed EIA-64A forms to all known natural gas

processing plant operators as of February 1, 1999. In

addition, plant operators whose plants were shut down

or dismantled during 1998 were required to complete

forms for the portion of 1998 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

262 operators of 605 plants were sent forms. This

number included 1 new plant, 2 reactivated plants, and

18 successor plants identified after the initial 1998

survey mailing. A total of 29 plants were reported as

nonoperating according to the Form EIA-64A

definition. For the eleventh consecutive year the

response rate was 100 percent.

Form EIA-64A respondents were requested to report

natural gas liquids production data by area of origin.

Table E4 summarizes the responses by plant operators

of the volume and origin of natural gas delivered to the

Energy Information Administration

100 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table E3. Summary of the 1998 Operator Frame

Activity, Form EIA-23

Total 1997 Operator Frame............. 65,420

Operators....................... 22,668

Nonoperators.................... 42,752

Changes to 1997 Operator Status...... 2,354

From Nonoperator to Operator . . . . . . 236

From Operator to Nonoperator ...... 2,118

No Changes to 1997 Operator Status . . . 63,066

Operators....................... 20,550

Nonoperators.................... 42,516

Additions to 1997 Operator Frame ..... 3,048

Operator ....................... 2,842

Nonoperator. . . . . . . . . . . . . . . . . . . . . 206

Total 1998 Operator Frame............ 68,468

Operators....................... 23,392

Nonoperators.................... 45,076

Note: Includes operator frame activity through December 29, 1998.

Source: Energy Information Administration, Office of Oil and Gas.
processing plants and the volume of the natural gas

liquids extracted by the plants by State. The majority of

the plant operators reported only one area of origin for

the natural gas that was processed by a plant. The State

or area of origin reported is generally also the plant’s

location.

Form EIA-64A

Reporting Requirements

Form EIA-64A consisted of the reporting schedule

shown in Figure I6, Appendix I. The form identifies the

plant, its geographic location, the plant operator’s

name and address, and the parent company name. The

certification was signed by a responsible official of the

operating entity. The form pertains to the volume of

natural gas received and of natural gas liquids

produced at the plant, allocated to each area of origin.

Operators also filed the data pertaining to the amount

of natural gas shrinkage that resulted from extraction

of natural gas liquids at the plant, and the amount of

fuel used in processing.

Natural gas liquids volumes were reported rounded to

thousands of barrels of 42 U.S. gallons at 60

Fahrenheit, and natural gas volumes were reported

rounded to millions of cubic feet. All natural gas

volumes were requested to be reported at 60

Fahrenheit and a pressure base of 14.73 pounds per

square inch absolute. Other minor report preparation

standards were specified to assure that the filed data

could be readily processed.

Form EIA-64A Comparison

with Other Data Series

Form EIA-64A plant liquids production data were

compared with data collected on Form EIA-816,

“Monthly Natural Gas Liquids Report.” Aggregated

production from Form EIA-816 represents the net

volume of natural gas processing plant liquid output

less input for the report year. These data are published

in EIA’s Petroleum Supply Annual reports. The Form

EIA-64A annual responses reflect all corrections and

revisions to EIA’s monthly estimates. Differences,

when found, were reconciled in both sources. For 1998,

the Form EIA-64A National estimates were 1 percent

(13 million barrels) higher than the Petroleum Supply

Annual 1998 volume for natural gas plant liquids

production.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 101

W ellhead

Lease or Field

Separation

Facilities

Natural Gas

Processing Plant

Lease Condensate

Storage

Wet Gas after

Separation

Dry Gas

Plant Liquids

Production

Lease Condensate

Production

TOTAL

NATURAL GAS LIQUIDS

PRODUCTION

Wet Gas

Figure E1. Natural Gas Liquids Extraction Flows

Source: Energy Information Administration, Office of Oil and Gas.
Form EIA-64A

Frame Maintenance

The Form EIA-64A plant frame contains data on all

known active and inactive natural gas processing

plants in the United States. The 1998 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 28, 1998.

Energy Information Administration

102 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table E5. Form EIA-64A 1998 Plant Frame Activity

Frame as of 1997 survey mailing . . . . . . . 654

Additions . . . . . . . . . . . . . . . . . . . 88

Deletions ................... –121

Frame as of 1998 survey mailing . . . . . . . 621

Note: Includes operator frame activity through December 28, 1998.

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

Table E4. Natural Gas Processed and Liquids Extracted at Natural Gas Processing Plants, 1998

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 .............. 2,966,461 0 2,966,461 33,889

Lower 48 States....... 13,321,204 270,114 13,591,318 634,122

Alabama ............ 105,708 1,626 107,334 3,199

Arkansas ............ 198,148 0 198,148 365

California ............ 235,558 0 235,558 8,351

Colorado ............ 424,984 99 425,083 17,467

Florida .............. 5,037 3,137 8,174 1,559

Kansas.............. 600,453 132,375 732,828 32,853

Kentucky ............ 37,929 0 37,929 1,661

Louisiana ............ 4,520,288 90,681 4,610,969 101,358

Michigan ............ 83,052 0 83,052 4,399

Mississippi ........... 3,668 0 3,668 370

Montana............. 8,715 0 8,715 318

North Dakota ......... 52,777 0 52,777 4,234

New Mexico.......... 867,041 1,168 868,209 74,058

Oklahoma ........... 944,568 2,609 947,177 65,306

Texas............... 4,045,405 28,334 4,073,739 272,512

Utah................ 235,896 6,174 242,070 8,280

West Virginia ......... 70,488 153 70,641 5,158

Wyoming ............ 869,726 792 870,518 32,000

Miscellaneousa ....... 11,763 2,966 14,729 674

Total ............... 16,287,665 270,114 16,557,779 668,011

aIncludes Illinois, Nebraska, Ohio, Pennsylvania, and Tennessee.

Source: Form EIA-64A, “Annual Report of the Origin of Natural Gas Liquids Production,” 1998.
Appendix F

Statistical Considerations
Appendix F

Statistical Considerations

Survey Methodology

The Form EIA-23 survey is designed to provide reliable

estimates for reserves and production of crude oil,

natural gas, and lease condensate for the United States.

Operators of crude oil and natural gas wells were

selected as the appropriate respondent population

because they have access to the most current and

detailed information, and therefore, presumably have

better reserve estimates than do other possible classes

of respondents, such as working interest or royalty

owners.

While large operators are quite well known, they

comprise only a small portion of all operators. The

small operators are not well known and are difficult to

identify because they go into and out of business, alter

their corporate identities, and change addresses

frequently. As a result, EIA conducts extensive frame

maintenance activities each year to identify all current

operators of crude oil and natural gas wells in the

country.

Sampling Strategy

EIA publishes data on reserves and production for

crude oil, natural gas, and lease condensate by State for

most States, and by State subdivision for the States of

California, Louisiana, New Mexico, and Texas. To meet

the survey objectives, while minimizing respondent

burden, a random sampling strategy has been used

since 1977. Each operator reporting on the survey is

asked to report production for crude oil, natural gas,

and lease condensate for each State/subdivision in

which he operates. The term State/subdivision refers

to an individual subdivision within a State or an

individual State that is not subdivided.

The total volume of production varies among the

State/subdivisions. To meet the survey objectives

while controlling total respondent burden, EIA

selected the following target sampling error for the

1998 survey for each product class.

 1.0 percent for National estimates.

 1.0 percent for each of the 5 States having

subdivisions: Alaska, California, Louisiana,

New Mexico, and Texas. For selected

subdivisions within these States, targets of 1.0

percent or 1.5 percent as required to meet the

State target.

 2.5 percent for each State/subdivision having 1

percent or more of estimated U.S. reserves or

production in 1997 (lower 48 States) for any

product class.

 4 percent for each State/subdivision having less

than 1 percent of estimated U.S. reserves or

production in 1997 (lower 48 States) for all 3

product classes.

 8 percent for States not published separately.

The combined production from these States was

less than 0.2 percent of the U.S. total in 1997 for

crude oil and for natural gas.

The volume of production defining the Certainty

stratum, referred to as the cutoff, varies by product or

State/subdivision. The cutoff criteria and sampling

rates are shown in Table F1. The Certainty stratum,

therefore, has three components.

 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 1998.

 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

1998.

 Category III - Small Operators: Operators who

produced less than the Category II operators in

1998, but which were selected with certainty.

Category III operators were subdivided into

operators sampled with certainty (Certainty)

and operators that were randomly sampled

(Noncertainty).

 Certainty - A small operators who satisfied

any of the following criteria based upon their

production shown in the operator frame:

Operators with annual crude oil

production of 200 thousand barrels or

more, or reserves of 4 million barrels or

more; or annual natural gas production of

1 billion cubic feet or more, or reserves of

20 billion cubic feet or more.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 105
Table F1. 1998 EIA–23 Survey Initial Sample Criteria

Noncertainty Sample

Production Cutoffs Number of

Crude Oil Gas Certainty Single State Multi–State

State and Subdivision (mbbls) (mmcf) Operators Operators Operators

Alabama Onshore. . . . . . . . . . . . . . . . . . . . . 107 1,000 54 4 5

Alaska .............................. 0 0 7 0 0

Arkansas. . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 1,000 123 25 27

California Unspecified. . . . . . . . . . . . . . . . . . 17 88 2 2 0

California Coastal Region Onshore . . . . . . . 200 1,000 24 1 3

California Los Angeles Basin Onshore . . . . . 200 25 24 4 2

California San Joaquin Basin Onshore. . . . . 200 1,000 41 5 6

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 134 20 23

Florida Onshore . . . . . . . . . . . . . . . . . . . . . . 200 1,000 4 0 1

Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 27 26 18 19

Indiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 1 17 4 14

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85 1,000 205 140 40

Kentucky . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 1,000 21 15 11

Louisiana Unspecified. . . . . . . . . . . . . . . . . . 73 183 0 0 0

Louisiana North. . . . . . . . . . . . . . . . . . . . . . . 13 633 234 32 27

Louisiana South Onshore . . . . . . . . . . . . . . . 70 1,000 220 34 38

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 62 10 4

Mississippi Onshore . . . . . . . . . . . . . . . . . . . 200 1,000 111 2 17

Montana . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 117 15 16

Nebraska . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 2 35 5 15

New Mexico Unspecified . . . . . . . . . . . . . . . 10 13 26 1 13

New Mexico East . . . . . . . . . . . . . . . . . . . . . 200 1,000 157 0 6

New Mexico West . . . . . . . . . . . . . . . . . . . . . 21 1,000 58 2 1

New York ........................... 3 1,000 23 19 5

North Dakota. . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 103 7 10

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92 1,000 60 72 19

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . 143 1,000 350 252 65

Pennsylvania ........................ 4 1,000 40 23 13

Texas Unspecified . . . . . . . . . . . . . . . . . . . . 7 118 2 2 0

Texas-RRC District 1 . . . . . . . . . . . . . . . . . . 23 800 197 33 46

Texas-RRC District 2 Onshore . . . . . . . . . . . 200 1,000 213 17 52

Texas-RRC District 3 Onshore . . . . . . . . . . . 200 1,000 298 36 78

Texas-RRC District 4 Onshore . . . . . . . . . . . 91 1,000 213 21 44

Texas-RRC District 5 . . . . . . . . . . . . . . . . . . 38 630 139 5 26

Texas-RRC District 6 . . . . . . . . . . . . . . . . . . 200 1,000 244 33 50

Texas-RRC District 7B . . . . . . . . . . . . . . . . . 34 82 269 70 76

Texas-RRC District 7C . . . . . . . . . . . . . . . . . 200 1,000 214 10 76

Texas-RRC District 8 . . . . . . . . . . . . . . . . . . 200 1,000 257 9 76

Texas-RRC District 8A . . . . . . . . . . . . . . . . . 200 1,000 211 10 45

Texas-RRC District 9 . . . . . . . . . . . . . . . . . . 52 1,000 178 29 54

Texas-RRC District 10 . . . . . . . . . . . . . . . . . 200 1,000 172 3 16

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 63 4 10

Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 13 1 1

West Virginia......................... 5 1,000 48 46 17

Wyoming. . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 151 12 30

Offshore Areas . . . . . . . . . . . . . . . . . . . . . . . 0 0 267 1 7

Other Statesa . . . . . . . . . . . . . . . . . . . . . . . . 125 49 23 2 8

Total ............................... b1,459 1,056 b412

aIncludes Arizona, Connecticut, Delaware, Georgia, Idaho, Iowa, Massachusetts, Maryland, Minnesota, Missouri, North Carolina, New

Hampshire, Nevada, New Jersey, Oregon, Rhode Island, South Carolina, South Dakota, Tennessee, Washington, and Wisconsin. bNonduplicative count of operators by States.

Note: Sampling rate was 8 percent except in Alaska, Florida Onshore, Virginia, and Offshore areas where sampling rate was 100 percent.

— = Not applicable.

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

106 Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
All other operators with production or

reserves in a State/subdivision that

exceed selected cutoff levels for that

State/subdivision.

The largest operator in each

State/subdivision regardless of level of

production or reserves.

Operators with production or reserves of

oil or gas for six or more

State/subdivisions.

 Noncertainties - Small operators not in the

certainty stratum were classified in a

noncertainty stratum and sampled at a rate of

8 percent.

In each State/subdivision the balance between the

number of small certainty operators and the sample

size was determined in an iterative procedure designed

to minimize the number of total respondents. The

iteration for each State/subdivision began with only

the Category I and Category II operators in the

certainty stratum. The size of the sample of small

operators required to meet the target variance was

calculated based on the variance of the volumes of

those operators. For a number of State/subdivisions

with high correlations between frame values across

pairs of consecutive years, an adjusted target variance

was calculated, that utilized the information about the

correlations. This allowed the selection of a smaller

sample that still met the target sampling error criteria.

At each iteration a small operator, beginning with the

largest of the Category III operators, was added to the

certainty group and the required sample size was again

calculated. The procedure of adding one operator at a

time stopped when the proportion of operators to be

sampled at random dropped below 8 percent.

Independent samples of single location operators

(operators who, according to the sampling frame,

operate in only one State/subdivision) were selected

from each State/subdivision using systematic random

sampling.

An additional complexity is introduced because some

small operators selected for the sample in another

region or regions, sometimes report production

volumes in a region in which EIA has no previous

record of production.

State/subdivision volume estimates are calculated as

the sum of the certainty strata and all of the estimates

for the sampling strata in that region. The sampling

variance of the estimated total is the sum of the

sampling variances for the sampling strata. There is no

sampling error associated with the certainty stratum.

The square root of the sampling variance is the

standard error. It can be used to provide confidence

intervals for the State/subdivision totals.

For the States in which subdivision volume estimates

are published, the State total is the sum of the

individual volume estimates for the subdivisions. The

U.S. total is the sum of the State estimates. A sampling

variance is calculated for each State subdivision, State,

and for the U.S. total.

Total U.S. Reserve Estimates

Conceptually, the estimates of U.S. reserves and

production can be thought of as the sum of the

estimates for the individual States. Correspondingly,

the estimates for the four States for which estimates are

published separately by subdivision (California,

Louisiana, New Mexico, and Texas) can be thought of

as the sum of the estimates by subdivision. The

remaining States are not subdivided and may be

considered as a single subdivision.

The estimates of year-end proved reserves and annual

production for any State/subdivision is the sum of the

volumes in the State/subdivision reported by the

certainty stratum operators and an estimate of the total

volume in the State/subdivision by the noncertainty

stratum operators. Mathematically, this may be stated

as the following sum:

VV V  

s sc sr  

where

V

s = estimated total volume in the

State/subdivision

Vsc = total volume in the State/subdivision

reported by Certainty operators

V

sr = estimated total volume in the

State/subdivision of Noncertainty

operators.

The total volume of Certainty operators in the

State/subdivision is simply the sum of individual

operator's volumes:

V V sc

m

n

scm

sc

1

where

nsc = number of Certainty operators reporting

production in the State/subdivision

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 107
Vscm = volume reported by the m-th certainty

stratum operator in the State/subdivision.

The estimated total volume of Noncertainty operators

in the State/subdivision is the weighted sum of the

reports of the noncertainty sample operators:

V WV 

sr

m

n

srm srm

sr

1

where

nsr = number of Noncertainty operators

reporting production in the

State/subdivision

Vsrm = volume reported by the m-th

Noncertainty sample operator in the

State/subdivision

Wsrm = weight for the report by the m-th

Noncertainty sample operator reporting

production in the State/subdivision.

In many State/ subdivisions, the accuracy of the oil and

gas estimates was improved by using the probability

proportional to size procedure. This procedure took

advantage of the correlation between year-to-year

production reports. The weights used for estimating

the oil production for a State / subdivision were

different from the weights used for estimating the gas

production.

The weight used for the estimation is the reciprocal of

the probability of selection for the stratum from which

the sample operator was selected. In making estimates

for a State/ subdivision, separate weights are applied

as appropriate for noncertainty operators shown in the

frame as having had production in only the State/

subdivision, for those shown as having had production

in that State/subdivision and up to four other State/

subdivisions, and for operators with no previous

record of production in the State/subdivision.

National totals were then obtained by summation of

the component totals.

Imputation for Operator Nonresponse

The response rate for Noncertainty operators for the

1998 survey was 99.4 percent, therefore an imputation

was made for the production and reserves of the 8

nonresponding operators.

Imputation and Estimation for

Reserves Data

In order to estimate reserve balances for National and

State/subdivision levels, a series of imputation and

estimation steps at the operator level must be carried

out. Year-end reserves for operators who provided

production data only were imputed on the basis of

their production volumes. Imputation was also applied

to the small and intermediate operators as necessary to

provide data on each of the reserve balance categories

(i.e., revisions, extensions, or new discoveries). Finally,

an imputation was required for the natural gas data of

the small operators to estimate their volumes of

associated-dissolved and nonassociated natural gas.

The final manipulation of the data accounts for the

differences caused by different sample frames from

year to year. Each of these imputations generated only

a small percentage of the total estimates. The methods

used are discussed in the following sections.

The data reported by operator category by Form

EIA-23 respondents for the report year 1998 are

summarized in Tables F2, F3, F4, and F5. The reported

data in Table F2 shows that those responding

operators accounted for 97.9 percent of the published

production for natural gas shown in Table 9 and 93.9

percent of the reserves. Data shown in Table F3

indicate that those responding operators accounted for

95.3 percent of the nonassociated natural gas

production and 92.7 percent of the reserves published

in Table 10. The reported data shown in Table F4

indicate that those responding operators accounted for

96.7 percent of published crude oil production and 94.7

percent of the reserves shown in Table 6. Additionally,

Table F5 indicates that those responding operators

accounted for 100 percent of the published production

and 96 percent of the published proved reserves for

lease condensate shown in Table 16.

Imputation of Year-End Proved Reserves

Category I operators were required to submit year-end

estimates of proved reserves. Category II and Category

III operators were required to provide year-end

estimates of proved reserves only if such estimates

existed in their records. Some of these respondents

provided estimates for all of their operated properties,

others provided estimates for only a portion of their

properties, and still others provided no estimates for

any of their properties. All respondents did, however,

provide annual production data. The production

reported by Noncertainty sample operators and the

corresponding imputed reserves were weighted to

Energy Information Administration

108 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
Energy Information Administration 109

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table F2. Summary of Total Natural Gas, Wet After Lease Separation, Used in Estimation Process,

Form EIA-23 (Million Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

Operator Category

NonCertainty certainty

Level of Reporting I II III III Total

Field Level Reported and Imputed Data

Proved Reserves as of 12/31/97............. 149,878,595 11,753,022 23,033 - 161,654,650

(+) Revision Increases .................... 22,867,374 3,933,811 145,624 - 26,946,809

(–) Revision Decreases ................... 19,981,833 1,640,795 0 - 21,622,628

(+)Extensions .......................... 7,245,090 799,803 0 - 8,044,893

(+) New Field Discoveries ................. 835,143 147,710 0 - 982,853

(+) New Reservoirs in Old Fields ............ 1,982,423 92,763 14,235 - 2,089,421

(–) Production With Reserves in 1998 ........ 16,594,101 1,472,599 19,321 - 18,086,021

Proved Reserves Reported as of 12/31/98..... 146,291,686 13,615,360 163,571 - 160,070,617

Production Without Proved Reserves......... 25,269 531,885 46,974 - 604,128

Reserves Imputed for Production

Without Proved Reserves ................. 166,791 4,323,239 326,375 4,816,405

Subtotal Production ..................... 16,619,370 2,004,484 66,295 - 18,690,149

Subtotal Proved Reserves 1998 ........... 146,458,477 17,938,599 489,946 - 164,887,022

State Level Reported and Imputed Data

Production With Proved Reserves ........... 0 3,859 118,270 77,086 199,215

Production Without Proved Reserves......... 0 7,046 182,787 133,731 323,564

Subtotal Production....................... 0 10,905 301,057 210,817 522,779

Weighted Subtotal Production ............ 0 10,905 301,057 619,889 931,851

Proved Reserves Reported................. 0 21,475 1,085,344 713,771 1,820,590

Reserves Imputed for Reported Production

Without Proved Reserves ................. 0 21,482 1,372,175 1,368,707 2,762,364

Subtotal Proved Reserves ................. 0 42,957 2,457,519 2,082,478 4,582,954

Weighted Subtotal Proved Reserves ....... 0 42,957 2,457,519 5,055,502 7,555,978

Total Production in 1998 ................... 16,619,370 2,015,389 367,352 619,889 19,622,000

Total Proved Reserves as of 12/31/98 ......... 146,458,477 17,981,556 2,947,465 5,055,502 172,443,000

– = Not applicable.

Notes: Table 9 totals include imputed and estimated wet natural gas proved reserves rounded at the State/subdivision level. Field level

data are reported volumes and may not balance due to submission of incomplete reserve component records.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1998.
110 Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table F3. Summary of Nonassociated Natural Gas, Wet After Lease Separation, Used in

Estimation Process, Form EIA-23 (Million Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

Operator Category

NonCertainty certainty

Level of Reporting I II III III Total

Field Level Detail Report

Proved Reserves as of 12/31/97............. 121,784,153 10,230,055 13,678 - 132,027,886

(+) Revision Increases .................... 18,920,040 3,464,824 39,642 - 22,424,506

(–) Revision Decreases ................... 16,774,920 1,262,641 0 - 18,037,561

(+)Extensions .......................... 6,632,689 739,359 0 - 7,372,048

(+) New Field Discoveries ................. 731,321 145,942 0 - 877,263

(+) New Reservoirs in Old Fields ............ 1,792,251 73,297 14,235 - 1,879,783

(–) Production With Reserves in 1998 ........ 13,907,665 1,296,034 12,168 - 15,215,867

Proved Reserves Reported as of 12/31/98 . 119,234,863 12,097,445 55,387 - 131,387,695

Production Without Proved Reserves......... 25,048 423,209 43,778 - 492,035

Reserves Imputed for Production

Without Proved Reserves ................. 172,831 2,920,142 302,068 - 3,395,042

Subtotal Production ..................... 13,932,713 1,719,243 55,946 - 15,707,902

Subtotal Proved Reserves 1998 ........... 119,407,694 15,017,587 357,455 - 134,782,737

State Level Reported and Imputed Data

Production With Proved Reserves ........... — — — — —

Production Without Proved Reserves......... — — — — —

Subtotal Production....................... — — — — —

Weighted Subtotal Production ............ — — — — —

Proved Reserves Reported................. — — — — —

Reserves Imputed for Reported Production

Without Proved Reserves ................. — — — — —

Subtotal Proved Reserves ................. — — — — —

Weighted Subtotal Proved Reserves ....... — — —— —

Total Production in 1998 ................... 13,932,713 1,719,243 55,946 - 15,707,902

Total Proved Reserves as of 12/31/98 ......... 119,407,694 15,017,587 357,455 - 134,782,737

– = Not applicable.

Notes: Table 10 totals include imputed and estimated nonassociated wet natural gas proved reserves rounded at the State/subdivision

level. Field level data are reported volumes and may not balance due to submission of incomplete reserve component records.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1998.
Energy Information Administration 111

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table F4. Summary of Crude Oil Used in Estimation Process, Form EIA-23

(Thousand Barrels of 42 U.S. Gallons)

Operator Category

NonCertainty certainty

Level of Reporting I II III III Total

Field Level Detail Report

Proved Reserves as of 12/31/97............. 19,560,638 787,760 6,946 - 20,355,344

(+) Revision Increases .................... 2,163,945 202,379 41,405 - 2,407,729

(–) Revision Decreases ................... 1,720,906 183,522 7,144 - 1,911,572

(+)Extensions .......................... 281,464 15,010 0 - 296,474

New Field Discoveries ................. 148,004 2,142 0 - 150,146

(+) New Reservoirs in Old Fields ............ 97,672 19,104 0 - 116,776

(–) Production With Reserves in 1998 ........ 1,713,103 80,119 3,570 - 1,796,792

Proved Reserves Reported as of 12/31/98..... 18,816,152 762,761 37,684 - 19,616,597

Production Without Proved Reserves. . . . . . . . . 514 35,246 3,878 - 39,638

Reserves Imputed for Production

Without Proved Reserves ................. 3,189 230,810 26,092 260,091

Subtotal Production ..................... 1,713,617 115,365 7,448 - 1,836,430

Subtotal Proved Reserves 1998 ........... 18,819,341 993,571 63,776 - 19,876,688

State Level Reported and Imputed Data

Production With Proved Reserves . . . . . . . . . . . 0 893 19,482 13,832 34,207

Production Without Proved Reserves......... 0 1,308 30,879 22,733 54,920

Subtotal Production....................... 0 2,201 50,361 36,565 89,127

Weighted Subtotal Production ............ 0 2,201 50,361 102,008 154,570

Proved Reserves Reported................. 0 5,270 152,156 152,825 310,251

Reserves Imputed for Reported Production

Without Proved Reserves ................. 0 3,384 198,723 200,927 403,034

Subtotal Proved Reserves ................. 0 8,654 350,879 353,752 713,285

Weighted Subtotal Proved Reserves ....... 0 8,654 350,879 797,779 1,157,312

Total Production in 1998 ................... 1,713,617 117,566 57,809 102,008 1,991,000

Total Proved Reserves as of 12/31/98 ......... 18,819,341 1,002,225 414,655 797,779 21,034,000

– = Not applicable.

Notes: Table 6 totals include imputed and estimated crude oil proved reserves rounded at the State/subdivision level. Field level data are

reported volumes and may not balance due to submission of incomplete reserve component records.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1998.
112 Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table F5. Summary of Lease Condensate Used in Estimation Process, Form EIA-23

(Thousand Barrels of 42 U.S. Gallons)

Operator Category

NonCertainty certainty

Level of Reporting I II III III Total

Field Level Detail Report

Proved Reserves as of 12/31/97............. 1,178,325 88,274 21 - 1,266,620

(+) Revision Increases .................... 248,781 41,451 459 - 290,691

(–) Revision Decreases ................... 241,057 17,871 0 - 258,928

(+)Extensions .......................... 74,077 6,101 0 - 80,178

(+) New Field Discoveries ................. 32,310 3,753 0 - 36,063

(+) New Reservoirs in Old Fields ............ 34,272 533 251 - 35,056

(–) Production With Reserves in 1998 ........ 156,528 15,826 233 - 172,587

Proved Reserves Reported as of 12/31/98..... 1,170,704 105,963 498 - 1,277,165

Production Without Proved Reserves. . . . . . . . . 497 3,043 424 - 3,964

Reserves Imputed for Production

Without Proved Reserves ................. 3,081 19,270 2,638 24,989

Subtotal Production ..................... 157,025 18,869 657 - 176,551

Subtotal Proved Reserves 1998 ........... 1,173,785 125,233 3,136 - 1,302,154

State Level Reported and Imputed Data

Production With Proved Reserves . . . . . . . . . . . 0 0 452 202 654

Production Without Proved Reserves. . . . . . . . . 0 36 663 735 1,434

Subtotal Production. . . . . . . . . . . . . . . . . . . . . . . 0 36 1,115 937 2,088

Weighted Subtotal Production . . . . . . . . . . . . 0 36 1,115 1,298 2,449

Proved Reserves Reported................. 0 0 3,395 1,052 4,447

Reserves Imputed for Reported Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 0 223 6,962 5,426 12,611

Subtotal Proved Reserves . . . . . . . . . . . . . . . . . 0 223 10,357 6,478 17,058

Weighted Subtotal Proved Reserves . . . . . . . 0 223 10,357 23,266 33,846

Total Production in 1998 ................... 157,025 18,905 1,772 1,298 179,000

Total Proved Reserves as of 12/31/98 ......... 1,173,785 125,456 13,493 23,266 1,336,000

– = Not applicable.

Notes: Table 15 totals include imputed and estimated lease condensate proved reserves rounded at the State/subdivision level. Field

level data are reported volumes and may not balance due to submission of incomplete reserve component records.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1998.
estimate the full noncertainty stratum when calculating

reserves and production as previously described in the

section “Total U.S. Reserves Estimates” in this

appendix.

A year-end proved reserves estimate was imputed

from reported production data 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 F6)

characteristic of operators of similar size in the region

where the properties were located. The regional R/P

ratios in this report are averages calculated by dividing

the mean of reported reserves by the mean of reported

production for selected respondents of similar size who

did report estimated reserves. A cutoff level for each

region was determined based upon the largest

Certainty operator that reported production, but did

not provide a reserve estimate. Data from respondents

whose production in a region exceeded the regional

cutoff level was excluded from the R/P ratio

calculation for that region. In addition, operators that

had R/P ratios that exceeded 25 to 1 and Category I

operators were excluded from the respondents selected

to calculate the characteristic regional R/P ratio. All

other respondents who reported both production and

reserves were used to calculate the regional R/P ratio

characteristic.

The R/P ratio varied significantly from region to

region. This variation was presumably in response to

variation in geologic conditions and the degree of

development of crude oil and natural gas resources in

each area. The average R/P ratio was computed for

regional areas similar to the National Petroleum

Council regional units (Figure F1). These units

generally follow the boundaries of geologic provinces

wherein the stage of resource development tends to be

somewhat similar. Table F6 lists the R/P ratio

calculated for each region that required such

imputations and the number of observations on which

it was based.

The regional R/P ratio is determined primarily to

provide a factor that can be applied to the production

reported by operators without reserve estimates to

provide an estimate of the reserves of these operators

when aggregated to the regional level. The average

R/P ratio, when multiplied by each individual

production in the distribution of R,P pairs used to

calculate it, will exactly reproduce the sum of the

reported reserves in the distribution.

Imputation of Annual Changes to Proved

Reserves by Component of Change

Category II and Category III operators that do not keep

reserves data were not asked to provide estimates of

beginning-of-year reserves or annual changes to

proved reserves by component of change, i.e.,

revisions, extensions, and discoveries. When they did

not provide estimates, these volumes were estimated

by applying an algebraic allocation scheme which

preserved the relative relationships between these

items within each State/subdivision, as reported by

Category I and Category II operators, and also

preserved an exact annual reserves balance of the

following form:

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 113

Table F6. Statistical Parameters of Reserve Estimation Equation by Region for 1998

Number of Nonzero R/P Pairs Characteristic Multipliers

Region Lease Lease

Number Region Oil Gas Condensate Oil Gas Condensate

2 Pacific Coast States . . . . . . . . . . . 17 16 3 a6.6 a8.0 a6.1

3 Western Rocky Mountains . . . . . . . . 44 52 13 6.9 10.4 a6.1

4 Northern Rocky Mountains . . . . . . . . 88 67 6 6.7 8.8 a6.1

5 West Texas and East New Mexico . . . . 196 200 50 7.0 7.1 6.5

6 + 6A Western Gulf Basin and Gulf of Mexico . . 273 285 182 6.2 6.6 6.2

7 Mid-Continent . . . . . . . . . . . . . . 207 193 59 6.6 8.1 8.0

8 + 9 Michigan Basin and Eastern Interior . . . 58 43 6 5.8 9.7 a6.1

10 + 11 Appalachians . . . . . . . . . . . . . . 17 47 1 a6.6 13.5 a6.1

United States . . . . . . . . . . . . . . 900 903 320 6.6 8.0 6.1

aMultiplier of the U.S. national average is assumed. Effect of the multiplier on the related natural gas or lease condensate reserves esti- mate is negligible in these regions.

Source: Based on data filed on Form EIA-23,"Annual Survey of Domestic Oil and Gas Reserves, 1998".
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 Certainty and Noncertainty operators. These were

then added to the State/subdivision totals.

Imputation of Natural Gas Type Volumes

Operators in the State/subdivision certainty and

noncertainty strata were not asked to segregate their

natural gas volumes by type of natural gas, i.e.,

nonassociated natural gas (NA) and

associated-dissolved natural gas (AD). The total

estimated year-end proved reserves of natural gas and

the total annual production of natural gas reported by,

or imputed to, operators in the State/subdivision

certainty and noncertainty strata were, therefore,

subdivided into the NA and AD categories, by

State/subdivision, in the same proportion as was

reported by Category I and Category II operators in the

same area.

Energy Information Administration

114 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Figure F1. Form EIA-23 Regional Boundaries

Published Proved Reserves at End of Previous Report Year

+ Adjustments

+ Revision Increases

– Revision Decreases

+ Extensions

+ New Field Discoveries

+ New Reservoir Discoveries in Old Fields

– Report Year Production

= Published Proved Reserves at End of Report Year
Adjustments

The instructions for Schedule A of Form EIA-23 specify

that, when reporting reserves balance data, the

following arithmetic equation must hold:

Any remaining difference in the State/subdivision

annual reserves balance between the published

previous year-end proved reserves and current

year-end proved reserves not accounted for by the

imputed reserves changes was included in the

adjustments for the area. One of the primary reasons

that adjustments are necessary is the instability of the

Noncertainty operators sampled each year. About 24

percent of the Noncertainty stratum operators sampled

in 1997 were sampled again in 1998. There is no

guarantee that in the smaller producing

States/subdivision the same number of small

operators will be selected each year, or that the

operators selected will be of comparable sizes when

paired with operators selected in a prior year. Thus,

some instability of this stratum from year to year is

unavoidable, resulting in minor adjustments.

Some of the adjustments are, however, more

substantial, and could be required for any one or more

of the following reasons:

 The frame coverage may or may not have

improved between survey years, such that more

or fewer Certainty operators were included in

1998 than in 1997.

 One or more operators may have reported data

incorrectly on Schedule A in 1997 or 1998, but

not both, and the error was not detected by edit

processing.

 Operation of properties was transferred during

1998 from operators not in the frame or

Noncertainty operators not selected for the

sample to Certainty operators or Noncertainty

operators selected for the sample.

 Operations of properties was transferred

during 1998 to an operator with a different

evaluation of the proved reserves associated

with the properties than that of the 1997

operator.

 Respondent changed classification of natural

gas from NA to AD or vice versa.

 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.

 Noncertainty operators, who have grown

substantially in size since they were added to

the frame, occasionally cause a larger standard

error than expected.

 The Noncertainty sample for either year in a

state may have been an unusual one.

The causes of adjustments are known for some but not

all areas. The only problems whose effects cannot be

expected to balance over a period of several years are

those associated with an inadequate frame or those

associated with any actual trend in reserve changes for

small operators not being the same as those for large

operators. EIA continues to attempt to improve sources

of operator data to resolve problems in frame

completeness.

Sampling Reliability of the Estimates

The sample of Noncertainty operators selected is only

one of the large number of possible samples that could

have been selected and each would have resulted in

different estimates. The standard error or sampling

error of the estimates provides a measure of this

variability. When probability sampling methods are

used, as in the EIA-23 survey, the sampling error of

estimates can also be estimated from the survey data.

The estimated sampling error can be used to compute a

confidence interval around the survey estimate, with a

prescribed degree of confidence that the interval covers

the value that would have been obtained if all operators

in the frame had been surveyed. If the estimated

volume is denoted byV

s and its sampling error by S.E. (

V

s ), the confidence interval can be expressed as:

 . .(  V kSE V ) s s  

where k is a multiple selected to provide the desired

level of confidence. For this survey, k was taken equal

to 2. Then there is approximately 95 percent confidence

that the interval:

 . .(  V SE V ) s s  2

includes the universe value, for both the estimates of

reserves and production volumes. Correspondingly,

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 115

Proved Reserves at End of Previous Year

+ Revision Increases

– Revision Decreases

+ Extensions

+ New Field Discoveries

+ New Reservoir Discoveries in Old Fields

– Report Year Production

= Proved Reserves at End of Report Year
for approximately 95 percent of the estimates in this

report, the difference between the published estimate

and the value that would be found from a complete

survey of all operators is expected to be less than twice

the sampling error of the estimate. Tables F7, F8, F9,

and F10 provide estimates for 2S.E. (V

s ) by product.

These estimates are directly applicable for constructing

approximate 95 percent confidence intervals. For

example, the 95 percent confidence interval for dry

natural gas proved reserves is 165,146 575 billion

cubic feet. The sampling error of V

s is equal to the

sampling error of the noncertainty estimate V

sr ,

because the certainty total is not subject to sampling

error. The estimated sampling error of a noncertainty

estimate is the square root of its estimated sampling

variance.

Nonsampling Errors

Several sources of possible error, apart from sampling

error, are associated with the Form EIA-23 survey.

These include bias due to nonresponse of operators in

the sample, proved reserve estimation errors, and

reporting errors on the part of the respondents to the

survey. On the part of EIA, possible errors include

inadequate frame coverage, data processing error, and

errors associated with statistical estimates. Each of

these sources is discussed below. An estimate of the

bias from nonresponse is presented in the section on

adjustment for operator nonresponse.

Assessing the Accuracy of the

Reserve Data

The EIA maintains an evaluation program to assess the

accuracy and quality of proved reserve estimates

gathered on Form EIA-23. Field teams consisting of

petroleum engineers from EIA's Dallas Field Office

conduct technical reviews of reserve estimates and

independently estimate the proved reserves of a

statistically selected sample of operator properties. The

results of these reviews are used to evaluate the

accuracy of reported reserve estimates. Operators are

apprised of the team's findings to assist them in

completing future filings. The magnitude of errors due

to differences between reserve volumes submitted by

operators on the Form EIA-23 and those estimated by

EIA petroleum engineers on their field trips were

generally within accepted professional engineering

standards.

Respondent Estimation Errors

The principal data elements of the Form EIA-23 survey

consist of respondent estimates of proved reserves of

crude oil, natural gas, and lease condensate.

Unavoidably, the respondents are bound to make some

estimation errors, i.e., until a particular reservoir has

been fully produced to its economic limit and

abandoned, its reserves are not subject to direct

measurement but must be inferred from limited,

imperfect, or indirect evidence. A more complete

discussion of the several techniques of estimating

proved reserves, and the many problems inherent in

the task, appears in Appendix G.

Reporting Errors and

Data Processing Errors

Reporting errors on the part of respondents are of

definite concern in a survey of the magnitude and

complexity of the Form EIA-23 program. Several steps

were taken by EIA to minimize and detect such

problems. The survey instrument itself was carefully

developed, and included a detailed set of instructions

for filing data, subject to a common set of definitions

similar to those already used by the industry. Editing

software is continually developed to detect different

kinds of probable reporting errors and flag them for

resolution by analysts, either through confirmation of

the data by the respondent or through submission of

amendments to the filed data. Data processing errors,

consisting primarily of random keypunch errors, are

detected by the same software.

Imputation Errors

Some error, generally expected to be small, is an

inevitable result of the various estimations outlined.

These imputation errors have not yet been completely

addressed by EIA and it is possible that estimation

methods may be altered in future surveys. Nationally,

5.9 percent of the crude oil proved reserve estimates,

6.1 percent of the natural gas proved reserve estimates,

and 0.7 percent of the lease condensate proved reserve

estimates resulted from the imputation and estimation

of reserves for those Certainty and Noncertainty

operators who did not provide estimates for all of their

properties, in combination with the expansion of the

sample of Noncertainty operators to the full

population. Errors for the latter were quantitatively

calculated, as discussed in the previous section.

Standard errors, for the former, would tend to cancel

each other from operator to operator, and are,

therefore, expected to be negligible, especially at the

Energy Information Administration

116 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
Energy Information Administration 117

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table F7. Factors for Confidence Intervals (2S.E.) for Dry Natural Gas Proved Reserves and Production,

1998 (Billion Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

1998 1998 1998 1998

State and Subdivision Reserves Production State and Subdivision Reserves Production

United States .................. 1003 92

Alabama. . . . . . . . . . . . . . . . . . . . . . 18 3

Alaska ....................... 0 0

Arkansas . . . . . . . . . . . . . . . . . . . . . 14 2

California ..................... 0 0

Coastal Region Onshore....... 0 0

Los Angeles Basin Onshore .... 0 0

San Joaquin Basin Onshore . . . . 27 3

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

Colorado . . . . . . . . . . . . . . . . . . . . . 22 8

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

Kansas. . . . . . . . . . . . . . . . . . . . . . . 239 30

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

Louisiana . . . . . . . . . . . . . . . . . . . . . 10 2

North . . . . . . . . . . . . . . . . . . . . . . 11 2

South Onshore . . . . . . . . . . . . . . 10 1

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

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

Mississippi .................... 8 1

Montana...................... 3 0

New Mexico ................... 0 0

East....................... 0 0

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

New York . . . . . . . . . . . . . . . . . . . . . 15 1

North Dakota .................. 0 0

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . 104 11

Oklahoma . . . . . . . . . . . . . . . . . . . . 930 84

Pennsylvania . . . . . . . . . . . . . . . . . . 66 2

Texas . . . . . . . . . . . . . . . . . . . . . . . . 173 3

RRC District 1 . . . . . . . . . . . . . . . 186 17

RRC District 2 Onshore . . . . . . . 20 3

RRC District 3 Onshore . . . . . . . 65 8

RRC District 4 Onshore . . . . . . . 31 4

RRC District 5 . . . . . . . . . . . . . . . 12 1

RRC District 6 . . . . . . . . . . . . . . . 16 1

RRC District 7B. . . . . . . . . . . . . . 29 4

RRC District 7C. . . . . . . . . . . . . . 34 3

RRC District 8 . . . . . . . . . . . . . . . 36 5

RRC District 8A.............. 9 1

RRC District 9 . . . . . . . . . . . . . . . 37 5

RRC District 10 . . . . . . . . . . . . . . 212 4

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

Utah . . . . . . . . . . . . . . . . . . . . . . . . . 52 2

Virginia....................... 0 0

West Virginia . . . . . . . . . . . . . . . . . . 46 3

Wyoming . . . . . . . . . . . . . . . . . . . . . 23 3

Federal Offshorea .............. 0 0

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

Gulf of Mexico (Louisiana)a .... 0 0

Gulf of Mexico (Texas) ........ 0 0

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

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

Notes: Confidence intervals are associated with Table 8 reserves and production data. Factors for confidence intervals for each State

subdivision, State, and the United States are independently estimated and do not add.

Source: Factor estimates based on data filed on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1998 and Form

EIA-64A, “Annual Report of the Origin of Natural Gas Liquids Production,” 1998.

Table F8. Factors for Confidence Intervals (2S.E.) for Natural Gas Proved Reserves and Production,

Wet After Lease Separation, 1998 (Billion Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

1998 1998 1998 1998

State and Subdivision Reserves Production State and Subdivision Reserves Production

United States .................. 1068 98

Alabama. . . . . . . . . . . . . . . . . . . . . . 19 3

Alaska ....................... 0 0

Arkansas . . . . . . . . . . . . . . . . . . . . . 28 3

California . . . . . . . . . . . . . . . . . . . . . 50 12

Coastal Region Onshore....... 0 0

Los Angeles Basin Onshore .... 3 0

San Joaquin Basin Onshore . . . . 28 3

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

Colorado . . . . . . . . . . . . . . . . . . . . . 25 9

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

Kansas. . . . . . . . . . . . . . . . . . . . . . . 257 32

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

Louisiana . . . . . . . . . . . . . . . . . . . . . 11 2

North . . . . . . . . . . . . . . . . . . . . . . 11 2

South Onshore . . . . . . . . . . . . . . 11 2

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

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

Mississippi .................... 8 1

Montana...................... 3 0

New Mexico ................... 0 0

East....................... 0 0

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

New York . . . . . . . . . . . . . . . . . . . . . 15 1

North Dakota . . . . . . . . . . . . . . . . . . 12 1

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . 104 11

Oklahoma . . . . . . . . . . . . . . . . . . . . 990 89

Pennsylvania . . . . . . . . . . . . . . . . . . 66 2

Texas . . . . . . . . . . . . . . . . . . . . . . . . 192 3

RRC District 1 . . . . . . . . . . . . . . . 194 17

RRC District 2 Onshore . . . . . . . 21 4

RRC District 3 Onshore . . . . . . . 69 9

RRC District 4 Onshore . . . . . . . 32 4

RRC District 5 . . . . . . . . . . . . . . . 12 1

RRC District 6 . . . . . . . . . . . . . . . 17 1

RRC District 7B. . . . . . . . . . . . . . 34 5

RRC District 7C. . . . . . . . . . . . . . 38 3

RRC District 8 . . . . . . . . . . . . . . . 41 6

RRC District 8A. . . . . . . . . . . . . . 13 1

RRC District 9 . . . . . . . . . . . . . . . 44 6

RRC District 10 . . . . . . . . . . . . . . 235 4

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

Utah . . . . . . . . . . . . . . . . . . . . . . . . . 55 2

Virginia....................... 0 0

West Virginia . . . . . . . . . . . . . . . . . . 47 3

Wyoming . . . . . . . . . . . . . . . . . . . . . 24 3

Federal Offshorea .............. 0 0

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

Gulf of Mexico (Louisiana)a .... 0 0

Gulf of Mexico (Texas) ........ 0 0

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

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

Notes: Confidence intervals are associated with Table 9 reserves and production data. Factors for confidence intervals for each State

subdivision, State, and the United States are independently estimated and do not add.

Source: Factor estimates based on data filed on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1998.
118 Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Table F9. Factors for Confidence Intervals (2S.E.) for Crude Oil Proved Reserves and Production, 1998

(Million Barrels of 42 U.S. Gallons)

1998 1998 1998 1998

State and Subdivision Reserves Production State and Subdivision Reserves Production

United States . . . . . . . . . . . . . . . . . . 102 10

Alabama...................... 2 0

Alaska ....................... 0 0

Arkansas ..................... 1 0

California ..................... 0 0

Coastal Region Onshore....... 0 0

Los Angeles Basin Onshore .... 0 0

San Joaquin Basin Onshore .... 0 0

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

Colorado . . . . . . . . . . . . . . . . . . . . . 15 2

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

Illinois........................ 5 1

Indiana....................... 3 1

Kansas. . . . . . . . . . . . . . . . . . . . . . . 57 7

Kentucky . . . . . . . . . . . . . . . . . . . . . 11 0

Louisiana ..................... 7 1

North ...................... 7 1

South Onshore .............. 5 1

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

Michigan ..................... 1 0

Mississippi . . . . . . . . . . . . . . . . . . . . 11 1

Montana...................... 1 0

Nebraska ..................... 3 0

New Mexico ................... 0 0

East....................... 0 0

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

North Dakota .................. 1 0

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . 11 1

Oklahoma . . . . . . . . . . . . . . . . . . . . 47 7

Pennsylvania .................. 1 0

Texas . . . . . . . . . . . . . . . . . . . . . . . . 10 2

RRC District 1 . . . . . . . . . . . . . . . 14 1

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

RRC District 3 Onshore ....... 4 1

RRC District 4 Onshore ....... 1 0

RRC District 5 ............... 1 0

RRC District 6 ............... 4 1

RRC District 7B.............. 4 1

RRC District 7C.............. 3 0

RRC District 8 . . . . . . . . . . . . . . . 50 1

RRC District 8A. . . . . . . . . . . . . . 22 2

RRC District 9 . . . . . . . . . . . . . . . 10 1

RRC District 10 . . . . . . . . . . . . . . 13 2

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

Utah . . . . . . . . . . . . . . . . . . . . . . . . 13 0

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

Wyoming . . . . . . . . . . . . . . . . . . . . . 33 0

Federal Offshore ............... 0 0

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

Gulf of Mexico (Louisiana) ..... 0 0

Gulf of Mexico (Texas) ........ 0 0

Miscellaneousa ................ 3 0

aIncludes Arizona, Missouri, Nevada, New York, South Dakota, Tennessee, and Virginia.

Notes: Confidence intervals are associated with Table 6 reserves and production data. Factors for confidence intervals for each State

subdivision, State, and the United States are independently estimated and do not add.

Source: Factor estimates based on data filed on Form EI-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1998.

Table F10. Factors for Confidence Intervals (2S.E.) for Lease Condensate Proved Reserves and

Production, 1998 (Million Barrels of 42 U.S. Gallons)

1998 1998 1998 1998

State and Subdivision Reserves Production State and Subdivision Reserves Production

United States .................. 6 1

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

Alaska ....................... 0 0

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

California ..................... 0 0

Coastal Region Onshore....... 0 0

Los Angeles Basin Onshore .... 0 0

San Joaquin Basin Onshore .... 0 0

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

Colorado ..................... 0 0

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

Kansas....................... 1 0

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

Louisiana ..................... 0 0

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

South Onshore .............. 1 0

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

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

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

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

New Mexico ................... 0 0

East....................... 0 0

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

North Dakota .................. 0 0

Oklahoma .................... 5 1

Texas ........................ 1 0

RRC District 1 ............... 0 0

RRC District 2 Onshore ....... 1 0

RRC District 3 Onshore ....... 4 1

RRC District 4 Onshore ....... 1 0

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

RRC District 6 ............... 0 0

RRC District 7B.............. 0 0

RRC District 7C.............. 0 0

RRC District 8 ............... 0 0

RRC District 8A.............. 0 0

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

RRC District 10 .............. 1 0

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

Utah and Wyoming ............. 0 0

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

Federal Offshorea .............. 0 0

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

Gulf of Mexico (Louisiana)a .... 0 0

Gulf of Mexico (Texas) ........ 0 0

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

aIncludes Federal offshore Alabama. bIncludes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, New York, Ohio, Oregon, Pennsylvania, South Dakota,

Tennessee, and Virginia.

Notes: Confidence intervals are associated with Table 15 reserves and production data. Factors for confidence intervals for each State

subdivision, State, and the United States are independently estimated and do not add.

Source: Factor estimates based on data filed on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 1998.
National level of aggregation. In States where a large

share of total reserves is accounted for by Category III

and smaller Category II operators, the errors are

expected to be somewhat larger than in States where a

large share of total reserves is accounted for by

Category I and larger Category II operators.

Frame Coverage Errors

Of all the sources of controllable error connected with

the Form EIA-23 survey, errors in the operator frame

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 1998 survey is particularly likely to be deficient in

States where a large portion of total reserves and

production is accounted for by small operators. These

States are not likely to allocate sufficient resources to

keep track of all operators on a current basis. Some

undercoverage of this type seems to exist, particularly,

with reference to natural gas operators. EIA is

continuing to work to remedy the undercoverage

problem in those States where it occurred.

Calculation of Reserves of

Natural Gas Liquids and

Dry Natural Gas

Natural Gas Liquids Reserve Balance

The published reserves, production, and reserves

change statistics for crude oil, lease condensate, and

natural gas, wet after lease separation, were derived

from the data reported on Form EIA-23 and the

application of the imputation methods discussed

previously. The information collected on Form

EIA-64A was then utilized in converting the estimates

of the wet natural gas reserves into two components:

plant liquids reserve data and dry natural gas reserve

data. The total natural gas liquids reserve estimates

presented in Table 14 were computed as the sum of

plant liquids estimates (Table 15) and lease condensate

(Table 16) estimates.

To generate estimates for each element in the reserves

balance for plant liquids in a given producing area, the

first step was to group all natural gas processing plants

that reported this area as an area-of-origin on their

Form EIA-64A, and then sum the liquids production

attributed to this area over all respondents. Next, the

ratio of the liquids production to the total wet natural

gas production for the area was determined. This ratio

represented the percentage of the wet natural gas that

was recovered as natural gas liquids. Finally, it was

assumed that this ratio was applicable to the reserves

and each component of reserve changes (except

adjustments), as well as production. Therefore, each

element in the wet natural gas reserves balance was

multiplied by this recovery factor to yield the

corresponding estimate for plant liquids. Adjustments

of natural gas liquids were set equal to the difference

between the end of previous year reserve estimates,

based upon the current report year Form EIA-23 and

Form EIA-64A surveys, and the end of current year

reserve estimates published in the preceding year's

annual reserves report.

Natural Gas Reserve Balance

This procedure involved downward adjustments of the

natural gas data, wet after lease separation, in

estimating the volumes of natural gas on a fully dry

basis. These reductions were based on estimates of the

gaseous equivalents of the liquids removed (in the case

of production), or expected to be removed (in the case

of reserves), from the natural gas stream at natural gas

processing plants. Form EIA-64A collected the

volumetric reduction, or shrinkage, of the input

natural gas stream that resulted from the removal of

the NGL at each natural gas processing plant.

The shrinkage volume was then allocated to the plant's

reported area or areas of origin. Because shrinkage is,

by definition, roughly in proportion to the NGL

recovered, i.e. the NGL produced, the allocation was in

proportion to the reported NGL volumes for each area

of origin. However, these derived shrinkage volumes

were rejected if the ratio between the shrinkage and the

NGL production (gas equivalents ratio) fell outside

certain limits of physical accuracy. The ratio was

expected to range between 1,558 cubic feet per barrel

(where NGL consists primarily of ethane) and 900

cubic feet per barrel (where NGL consists primarily of

natural gasolines). When the computed gas equivalents

ratio fell outside these limits, an imputed ratio was

utilized to estimate the plant's natural gas shrinkage

allocation to each reported area of origin.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 119
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 1998 Form

EIA-64A survey, the national weighted average gas

equivalents ratio was computed to be 1,404 cubic feet of

natural gas shrinkage per barrel of NGL recovered. The

total shrinkage volume (reported plus imputed) for all

plants reporting a given area of origin was then

subtracted from the estimated value of natural gas

production, wet after lease separation, yielding dry

natural gas production for the area. The amount of the

reduction in the wet natural gas production was then

expressed as a percentage of the wet natural gas

production. Dry natural gas reserves and reserve

changes were determined by reducing the wet natural

gas reserves and reserve changes by the same

percentage reduction factor.

A further refinement of the estimation process was

used to generate an estimate of the natural gas liquids

reserves in those States with coalbed methane fields.

The States where this procedure was applied were

Alabama, Colorado, Kansas, New Mexico, Oklahoma,

Pennsylvania, Utah, Virginia, West Virginia, and

Wyoming. The first step in the process was to identify

all Form EIA-23 reported coalbed methane fields. The

assumption was made that coalbed methane fields

contained little or no extractable natural gas liquids.

Therefore, when the normal shrinkage procedure was

applied to the wet gas volume reserve components, the

estimate of State coalbed methane volumes were

excluded and were not reduced for liquid extraction.

Following the computation for shrinkage, each coalbed

field gas volume reserve components was added back

to each of the dry gas volume reserve components in a

State. The effect of this is that the large increases in

reserves in some States from coalbed methane fields

did not cause corresponding increases in the State

natural gas liquids proved reserves.

Adjustments of dry natural gas were set equal to the

difference between the end of previous year reserves

estimates, based upon the current report year Form

EIA-23 and Form EIA-64A surveys, and the end of

current year reserve estimates published in the

preceding year's annual reserves report.

Each estimate of end of year reserves and report year

production has associated with it an estimated

sampling error. The standard errors for dry natural gas

were computed by multiplying the wet natural gas

standard errors by these same percentage reduction

factors. Table F7 provides estimates for 2 times the

SE Vs . .(  ) for dry natural gas.

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120 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
Appendix G

Estimation of

Reserves and Resources
Appendix G

Estimation of Reserves and Resources

Oil and Gas Resource Base

Universally accepted definitions have not been

developed for the many terms used by geologists,

engineers, accountants and others to denote various

components of overall oil and gas resources. In part,

this is because most of these terms describe estimated

and therefore uncertain, rather than measured,

quantities. The lack of standardized terminology

sometimes leads to inaccurate understanding of the

meaning and/or import of estimates. Particularly

common is an apparently widespread lack of

understanding of the substantial difference between

the terms “reserves” and “resources”, as indicated by

the frequent misuse of either term in place of the other.

The total resource base of oil and gas is the entire

volume formed and trapped in–place within the Earth

before any production. The largest portion of this total

resource base is nonrecoverable by current or

foreseeable technology. Most of the nonrecoverable

volume occurs at very low concentrations throughout

the earth's crust and cannot be extracted short of

mining the rock or the application of some other

approach that would consume more energy than it

produced. An additional portion of the total resource

base cannot be recovered because currently available

production techniques cannot extract all of the in–place

oil and gas even when present in commercial

concentrations. The inability to recover all of the

in–place oil and gas from a producible deposit occurs

because of unfavorable economics, intractable physical

forces, or a combination of both. Recoverable

resources, the subset of the total resource base that is of

societal and economic interest, are defined so as to

exclude these nonrecoverable portions of the total

resource base.

The structure presented in Figure G1 outlines the total

resource base and its components. The total resource

base first consists of the recoverable and

nonrecoverable portions discussed above. The next

level down divides recoverable resources into

discovered and undiscovered segments. Discovered

resources are further separated into cumulative (i.e., all

past) production, and reserves. Reserves are

additionally subdivided into proved reserves and

“other reserves”.

Recoverable Resources

Discovered recoverable resources are those

economically recoverable quantities of oil and gas for

which specific locations are known. While the specific

locations of estimated undiscovered recoverable

resources are not yet known, they are believed to exist

in geologically favorable settings.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 123

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

Total Oil & Gas Resource Base

Undiscovered

Resources

Cumulative

Production

Possible

Reserves

Probable

Reserves

Proved Ultimate

Recovery

Proved

Developed

Producing

Economically

Unrecoverable

Resources

Economically Recoverable Resources

(Ultimate Recovery)

Discovered Resources

(Oil and Gas In-place)

Proved

Undeveloped

Proved

Non-Producing

Proved

Developed

Proved

Reserves

Form

EIA-23

Includes

Other Reserves *

(Not Proved)
Current estimates of undiscovered recoverable

resources merit discussion in order to provide a useful

sense of scale relative to proved reserves. The sources

of official estimates of domestic undiscovered

recoverable resources are two agencies of the

Department of the Interior (DOI), the United States

Geological Survey (USGS) for onshore areas and those

offshore waters subject to State jurisdiction, and the

Minerals Management Service (MMS) for those

offshore waters under Federal jurisdiction.

The USGS defines undiscovered recoverable

conventional resources as those expected to be resident

in accumulations of sufficient size and quality that they

could be produced using conventional recovery

technologies, without regard to present economic

viability. Therefore, only part of the USGS

undiscovered recoverable conventional resource is

economically recoverable now. The USGS also defines

a class of resources that occur in “continuous–type”

accumulations. Unlike conventional oil and gas

accumulations, continuous–type accumulations do not

occur in discrete reservoirs of limited areal extent. They

include accumulations in low–permeability (tight)

sandstones, shales, and chalks, and those in coal beds.

Again, only part of the continuous–type technically

recoverable resource is economically recoverable now.

In fact, only a small portion of the in–place

continuous–type resource accumulations are estimated

to be technically recoverable now. Table G1 presents

the latest available USGS and MMS estimates, along

with the EIA 1997 proved reserves estimates.

Technically recoverable resources of wet natural gas

(discovered, both proved and unproved, and

undiscovered) are estimated at 1,341 trillion cubic feet

(Table G1). Subtracting U.S. proved reserves of 175

trillion cubic feet yields an unproven technically

recoverable resource target of 1,166 trillion cubic feet.

This is about 61 times the 1997 gas production level.

Other organizations have also estimated unproven

technically recoverable gas resources. For example, the

Potential Gas Committee (PGC), an industry

sponsored group, provides detailed geology–based gas

resource estimates every 2 years. In 1996 the PGC mean

estimate of potential gas resources was 1,067 trillion

cubic feet, about 99 trillion cubic feet less than the DOI

estimates in Table G1. Another recent estimate was

made by the National Petroleum Council (NPC), an

industry–based group that serves in an advisory

capacity to the U.S. Secretary of Energy. The NPC's

estimate, based on data available at year–end 1990, was

1,135 trillion cubic feet, 111 trillion cubic feet less than

the DOI estimates summarized in Table G1. The

differences among these estimates are usually due to

the availability of newer data, the differences in

coverage or resource category definitions, and to

legitimate but differing data interpretations. The USGS

estimates of reserve growth in known fields are much

larger than previous estimates due to the utilization of

newer EIA reserves growth data.

While the estimation of undiscovered resources is

certainly a more imprecise endeavor than is the

estimation of proved reserves, it is clear that substantial

volumes of technically recoverable oil and gas

resources remain to be found and produced

domestically. Current estimates indicate that as much

domestic gas remains to be found and then produced

as has been to date. Of course, much effort, investment

and time will be required to bring this gas to market.

There is a perception that the oil resource base has been

more intensively developed than the gas resource base.

And in fact, more oil has been produced in the United

States than is estimated as remaining recoverable.

Nevertheless, the ratio of 1996 unproven technically

recoverable oil resources to oil production (Table G1)

was about 62 to 1, higher than the comparable gas ratio.

Discovered Resources

In addition to cumulative production, which is the sum

of current year production and the production in all

prior years, estimates of discovered recoverable

resources include estimates of reserves. Broadly,

reserves are those volumes that are believed to be

recoverable in the future from known deposits through

the eventual application of present or anticipated

technology.

Reserves

Reserves include both proved reserves and other

reserves. Several different reserve classification

systems are in use by different organizations, as

preferred for operational reasons. These systems utilize

and incorporate various definitions of terms such as

measured reserves, indicated reserves, inferred reserves,

probable reserves, and possible reserves. As used by the

different organizations, the definitions that attach to

these terms sometimes overlap, or the terms may

require a slightly different interpretation from one

organization to the next. Nevertheless, all kinds of

“other reserves” are generally less well known and

therefore less precisely quantifiable than proved

reserves, and their eventual recovery is less assured.

Energy Information Administration

124 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 125

Table G1. Estimated Oil and Gas Reserves and Mean Estimates of Technically Recoverable

Oil and Gas Resources

Natural Gas

Crude Oila Natural Gas (Dry) Liquids

Categories (million barrels) (billion cubic feet) (million barrels)

Lower 48 States

Discovered

Proved Reserves (EIA, 1998)............................... 15,982 b154,114 7,204

Reserve Growth - conventional, onshorec (USGS, 1991) ......... d47,000 290,000 12,900

Reserve Growth - conventional, Federal Offshore (MMS, 1995).... e2,238 e32,719 NE

Unproved Reserves, Federal Offshore (MMS, 1996) ............. 1,643 4,436 NE

Undiscovered, Technically Recoverable

Conventional, onshorec (USGS, 1993)........................ 21,810 190,280 6,080

Continuous-type - sandstone, shale, chalk; onshorec (USGS, 1993). 2,066 308,080 2,119

Continuous-type - coalbeds, onshorec (USGS, 1993) ............ NA 49,910 NA

Federal Offshore - conventional (MMS, 1994).................. 21,300 142,100 f<1,800

Subtotal .............................................. 112,039 1,171,639 NA

Alaska

Discovered

Proved Reserves (EIA, 1998)............................... 5,052 9,927 320

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 .............................................. 51,192 236,937 NA

Total Lower 48 States and Alaska............................. 163,231 1,408,576 32,043

Deductions for Production and Proved Reserves Changes,

1991-1998 ............................................. -10,778 -107,646 -5,251

U.S. Total, 1998 ............................................ 152,453 1,330,930 26,792

a Condensate is included with crude oil for MMS estimates in Federal Offshore regions. b Includes 12,179 billion cubic feet of coalbed methane (EIA, 1998). c Includes USGS estimates for all onshore plus State Offshore (near-shore and shallow-water areas under State jurisdiction). d Using USGS definition, 1,924 million barrels of indicated additional oil reserves in the lower 48 States were included (EIA, 1996). e Reserve growth in the Pacific Federal offshore is not included and was not estimated by the MMS. This volume is not dry gas, but wet,

after lease separation. f Total undiscovered natural gas liquids for Federal offshore are 1,800 million barrels; MMS source did not separate lower 48 and Alaska

estimates of undiscovered natural gas liquids (1986). g Using USGS definition, 952 million barrels of indicated additional oil reserves in Alaska were included (EIA, 1996).

NE = not estimated.

NA = not applicable.

Notes: Federal Offshore indicates MMS estimates for Federal Offshore jurisdictions (Outer Continental Shelf and deeper water areas

seaward of State Offshore). Energy Information Administration (EIA), onshore and offshore estimated reserves. U.S. Geological Survey

(USGS): 1995 National Assessment mean estimates as of the end of 1993 (onshore and State Offshore). Minerals Management Service

(MMS): 1996 National Assessment mean estimates as of the end of 1994. The MMS also has end-1994 estimates for economically

recoverable resources. Probable and Possible reserves are considered by USGS definition to be part of USGS Reserve Growth, but are

separately considered by the MMS as its Unproved Reserves term. The USGS did not set a time limit for the duration of Reserve Growth; the

MMS set the year 2020 as the time limit in its estimates of Reserve Growth in existing fields of the Gulf of Mexico. Excluded from the estimates

are undiscovered oil resources in tar deposits and oil shales, and undiscovered gas resources in geopressured brines and gas hydrates.

Sources: Energy Information Administration, Office of Oil and Gas; USGS and MMS - Estimates of Undiscovered Conventional Oil and Gas

Resources in the United States—A Part of the Nation's Energy Endowment (1989), U.S. Department of the Interior; 1995 National Assessment

of United States Oil and Gas Resources, USGS Circular 1118, U.S. Department of the Interior; and An Assessment of the Undiscovered

Hydrocarbon Potential of the Nation's Outer Continental Shelf (1996), U.S. Department of the Interior.
Measured reserves are defined by the USGS as that part

of the identified (i.e., discovered) economically

recoverable resource that is estimated from geologic

evidence and supported directly by engineering

data.{41} They are similarly defined by the MMS,

although its system also subdivides them by degree of

development and producing status.{42} Measured

reserves are demonstrated with reasonable certainty to

be recoverable in future years from known reservoirs

under existing economic and operating conditions, and

are essentially equivalent to proved reserves as defined

by the EIA. Effectively, estimates of proved reserves

may be thought of as reasonable estimates (as opposed

to exact measures) of “on–the–shelf inventory”.

Inferred reserves and indicated reserves, due to their

more uncertain economic or technical recoverability,

are included in the “other reserves” category. The

USGS defines inferred reserves as that part of the

identified economically recoverable resource, over and

above both measured and indicated (see below)

reserves, that will be added to proved reserves in the

future through extensions, revisions, and the discovery

of new pay zones in already discovered fields.{41}

Inferred reserves are considered equivalent to

“probable reserves” by many analysts, for example,

those of the PGC.

Indicated additional reserves, a separate category, are

defined by both the DOI and the EIA as quantities of

crude oil that may become economically recoverable in

the future from existing productive reservoirs through

the application of currently available but as–yet

uninstalled recovery technology. At such time as the

technology is successfully applied, indicated

additional reserves are reclassified to the proved

reserves category. Of all the various “other reserves”

categories, only indicated additional reserves are

estimated by the EIA and reported herein.

Proved Reserves

The EIA defines proved reserves as those volumes of

oil and gas that geological and engineering data

demonstrate with reasonable certainty to be

recoverable in future years from known reservoirs

under existing economic and operating conditions.

When deterministic proved reserves estimation

methods are used, the term reasonable certainty is

intended to express a high degree of confidence that the

estimated quantities will be recovered. When

probabilistic methods are used there should be at least

a 90 percent probability that the actual quantities

recovered will exceed the estimate.

Proved reserves are either proved producing or proved

nonproducing (i.e., resident in reservoirs that did not

produce during the report year). The latter may

represent a substantial fraction of total proved

reserves.

Reserve Estimation

Methodologies

The adoption of a standard definition of proved

reserves for each type of hydrocarbon surveyed by the

Form EIA–23 program provided a far more consistent

response from operators than if each operator had used

their own definition. Such standards, however, do not

guarantee that the resulting estimates themselves are

determinate. Regardless of the definition selected,

proved reserves cannot be measured directly. They are

estimated quantities that are inferred on the basis of the

best geological, engineering, and economic data

available to the estimator, who generally uses

considerable judgment in the analysis and

interpretation of the data. Consequently, the accuracy

of a given estimate varies with and depends on the

quality and quantity of raw data available, the

estimation method used, and the training and

experience of the estimator. The element of judgment

commonly accounts for the differences among

independent estimates for the same reservoir or field.

Data Used in Making

Reserve Estimates

The raw data used in estimating proved reserves

include the engineering and geological data for

reservoir rock and its fluid content. These data are

obtained from direct and indirect measurements. The

data available for a given reservoir vary in kind,

quality, and quantity. When a reservoir is first

discovered only data from a single well are available,

and prior to flow testing or actual production, proved

reserves can only be inferred. As development of the

reservoir proceeds, and flow tests are made or actual

production commences, more and more data become

available, enabling proved reserves estimates to

become more accurate.

Many different kinds of data are useful in making

reserves estimates. They may include: data on porosity,

permeability, and fluid saturations of the reservoir

Energy Information Administration

126 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
rocks (obtained directly from core analysis or from

various types of electrical measurements taken in a

well or several wells); data on the production of fluids

from a well or several wells; geologic maps of the areal

extent, thickness, and continuity of the reservoir rocks

(inferred from well logs, geophysical, and geological

data); and reservoir pressure and temperature data.

Also involved are economic data including the current

price of crude oil and natural gas, and various

developmental and operating costs.

Reserve Estimation Techniques

Depending on the kinds and amounts of data available,

and a judgment on the reliability of those data, the

estimator will select one of several methods of making

a proved reserves estimate. Methods based on

production performance data are generally more

accurate than those based strictly on inference from

geological and engineering data. Such methods include

the Production Decline method (for crude oil or natural

gas reservoirs), the Material Balance method (for crude

oil reservoirs), the Pressure Decline method (which is

actually a material balance, for natural gas reservoirs),

and the Reservoir Simulation method (for crude oil or

natural gas reservoirs). The reservoir type and

production mechanisms and the types and amounts of

reliable data available determine which of these

methods is more appropriate for a given reservoir.

These methods are of comparable accuracy.

Methods not based upon production data include the

Volumetric method (for crude oil or natural gas

reservoirs) and the Nominal method. Of these, the

Volumetric method is the more accurate. Both methods,

however, are less accurate than those based on

production data. Table G2 summarizes the various

methods.

Judgmental Factors

in Reserve Estimation

The determination of rock and hydrocarbon fluid

properties involves judgment and is subject to some

uncertainty; however, the construction of the geologic

maps and cross sections and the determination of the

size of the reservoir are the major judgmental steps in

the Volumetric method, and are subject to the greatest

uncertainty. Estimates made using the Material Balance

method, the Reservoir Simulation method, or the

Pressure Decline method are based on the estimator's

judgment that the type of reservoir drive mechanism

has been identified and on the specification of

abandonment conditions. Estimates based on the

Production Decline method are subject to judgment in

constructing the trend line, and are based on the

estimator's assumption of reservoir performance

through abandonment.

Contributing to the degree of uncertainty inherent in

the above methods for estimating reserves are other

factors associated with economic considerations and

the perceived reservoir limits, which together influence

the final reserves estimate. A brief discussion of these

other factors follows.

Economic considerations: There has been continuing

debate about the effects of prices on proved reserves.

Although no all–inclusive statement can be made on

the impact of price, the points at issue can be discussed

and some general remarks can be made about some

circumstances where price may be a factor.

 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

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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 127

Table G2. Reserve Estimation Techniques

Method Comments

Volumetric Applies to crude oil and natural gas reservoirs. Based on raw engineering and geologic data.

Material Balance Applies to crude oil and natural gas reservoirs. Is used in estimating reserves. Usually of more value in predicting reserves,

and reservoir performance.

Pressure Decline Applies to nonassociated and associated

gas reservoirs. The method is a special

case of material balance equation in the

absence of water influx.

Production Decline Applies to crude oil and natural gas reservoirs during production decline (usually in

the later stages of reservoir life).

Reservoir SimulationApplies to crude oil and natural gas reservoirs. Is used in estimating reserves. Usually of more value in predicting reservoir

performance. Accuracy increases when

matched with past pressure and production data.

Nominal Applied to crude oil and natural gas reservoirs. Based on rule of thumb or analogy

with another reservoir or reservoirs believed to be similar; least accurate of

methods used.
noneconomic hydrocarbon resources to the

category of proved reserves. In both nearly

depleted reservoirs and newly developed

reservoirs, the actual increase in the quantity of

proved reserves resulting from price rises is

generally limited in terms of national volumes

(even though the percentage increase for a given

reservoir may be great).

 Developed oil fields – In developed crude oil

reservoirs many of the same comments apply;

however, there is an additional consideration. If

the price is raised to a level sufficient to justify

initiation of an improved recovery project, and if

the improved recovery technique is effective,

then the addition to ultimate recovery from the

reservoir can be significant. Because of the

speculative nature of predicting prices and costs

many years into the future, proved reserves are

estimated on the basis of current prices, costs,

and operating practices in effect as of the date the

estimation was made.

 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.

 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.

 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.

 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.

 Infill drilling – Infill drilling (drilling of additional

wells within a field/reservoir) may result in a

higher recovery factor, and, therefore, be

economically justified. Predictions of whether

infill drilling will be justified under current

economic conditions are generally based on the

expected production behavior of the infill wells.

Reservoir limits: The initial proved reserves estimate

made from the discovery well is subject to significant

uncertainty because one well provides little

information on the size of the reservoir. The area

proved by a discovery well is frequently estimated on

the basis of experience in a given producing region.

Where there is continuity of the producing formation

over wide geographic areas, a relatively large proved

area may be assigned. In some cases where reliable

geophysical and geological data are available, a

reasonable estimate of the extent of the reservoir can be

made by drilling a relatively small number of

delineation wells. Conversely, a relatively small

proved area may be assigned when the producing

Energy Information Administration

128 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
formation is of limited continuity, owing to either

structural or lithological factors.

Additional wells provide more information and reduce

the uncertainty of the reserves estimate. As additional

wells are drilled, the geometry of the reservoir and,

consequently, its bulk volume, become more clearly

defined. This process accounts for the large extensions

to proved reserves typical of the early stages of most

reservoir development.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 129
Appendix H

Maps of Selected State Subdivisions
Appendix H

Figure H1. Subdivisions of Alaska

Source: After U.S. Geological Survey.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 133

Maps of Selected State Subdivisions

Fairbanks

Barrow

Juneau

Anchorage

Nome
Figure H2. Subdivisions of California

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

Energy Information Administration

134 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 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 1998 Annual Report 135

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

136 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 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 1998 Annual Report 137

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 Wheel- er

Randall Armstrong Donley

Bailey

Cochran

Castro

Swish- er 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
Figure H6. Western Planning Area, Gulf of Mexico Outer Continental Shelf Region

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

Energy Information Administration

138 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 100'

600'

2000'

100'

2000'

600'
Figure H7. Central Planning Area, Gulf of Mexico Outer Continental Shelf Region

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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 139

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

(Dashed lines indicate water depths in feet.)

Lake Charles

New Orleans

Mobile

SABINE

PASS
Figure H8. Eastern Planning Area, Gulf of Mexico Outer Continental Shelf Region

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

Energy Information Administration

140 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

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
Appendix I

Annual Survey Forms for

Domestic Oil and Gas Reserves
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 143

Source: Energy Information Administration, Offfice of Oil and Gas. OFFICIAL USE ONLY 1998 ANNUAL SURVEY OF DOMESTIC OIL AND GAS RESERVES U.S. DEPARTMENT OF ENERGY CALENDAR YEAR 1998 Form Approved OMB No. 1905-0057 Expires 12/2000 of Management and Budget, Washington, DC 20503. COVER PAGE IDENTIFICATION 1. Were you an operator (see definition of an operator, p.1) of one or more oil or gas wells on December 31, 1998? (1) ̈ No... Complete only items 3 through 22 below and return this page with a letter stating when operations ceased and 2. I.D. Code FOR DOE USE ONLY what became of the wells you operated to P.O. Box 1470 Rockville, MD 20849-1470 (2) ̈ Yes... Complete the attached forms and return them to P.O. Box 1470 Rockville, MD 20849-1470 000 0 If information to the left is incorrect or is missing, enter correct information below.

3 3 3 3 3. Name

4. Address5. City 6. State 7. Zip Code8. EIN Check if Attestor's  ̈

Social Security Number  ̈

3 3

9. Name of Contact Person

10. Telephone Number of Contact Person

Area Code ( ) ______- ___________

PARENT COMPANY IDENTIFICATION

11. Is there a parent company which exercises ultimate control over 12. Name

your company?

(1) ̈ No... Answer 18 thru 22

13. Address

(2) ̈ Yes... Answer 12 thru 22 14. City 15. State 16. Zip Code

17. Parent Company EIN

18. What is the total number of pages (including this page) submitted in this filing?

ATTESTATION

(This report must be attested to by a responsible official of the company.)

appended is true and complete.

19. Name of Attestor (Please print) 21. Signature20. Title 22. Date

Title 18 USC 1001 makes it a criminal offense for any person knowingly and willingly to make to any Agency or

FOR ASSISTANCE CALL 1-800-879-1470

SAMPLE

Figure I1. Form EIA-23, Cover Page
Energy Information Administration

144 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Figure I2. Form EIA-23, Summary Report – Page 1

Source: Energy Information Administration, Offfice of Oil and Gas. OFFICIAL USE ONLY 1998 ANNUAL SURVEY OF DOMESTIC OIL AND GAS RESERVES SUMMARY REPORT PAGE 1 OF 2 (Report All Volumes of Crude Oil and Lease Condensate in Thousands of Barrels [Mbbl]; Form Approved OMB No. 1905-0057 Expires 12/2000 1.0 OPERATOR AND REPORT IDENTIFICATION DATA Report All Volumes of Natural Gas in Millions of Cubic Feet [MMcf] at 14.73 psia and 60 F) 1.1 OPERATOR I.D. CODE 1.2 OPERATOR NAME REPORT DATE 1.3 ORIGINAL 1.4 AMENDED 12 31 98 2.0 PRODUCTION AND RESERVES DATA CRUDE OIL NATURAL GAS LEASE CONDENSATE STATE OR RESERVES 1998 PRODUCTION RESERVES 1998 PRODUCTION RESERVES 1998 PRODUCTION GEOGRAPHIC SUBDIVISION Proved Reserves Dec. 31, 1998 (Mbbl) (A) (From properties for which reserves were Estimated) (Mbbl) (B) (From properties for which reserves were Not Estimated) (Mbbl) (C) Proved Reserves Dec. 31, 1998 (MMcf) (D) (From properties for which reserves were Estimated) (MMcf) (E) (From properties for which reserves were Not Estimated (MMcf) (F) Proved Reserves Dec. 31, 1998 (Mbbl) (G) (From properties for which reserves were Estimated) (Mbbl) (H) (From properties for which reserves were Not Estimated) (Mbbl) (I) ALABAMA-ONSHORE AL ALABAMA-STATE OFFSHORE AL05 ALASKA-NORTH ONSHORE AND OFFSHORE AK50 ALASKA-SOUTH ONSHORE AK10 ALASKA-SOUTH STATE OFFSHORE AK05 ARIZONA AZ ARKANSAS AR CALIFORNIA-COASTAL REGION ONSHORE CA50

CALIFORNIA-LOS ANGELES BASIN ONSHORE CA90CALIFORNIA-SAN JOAQUIN BASIN ONSHORE CA10CALIFORNIA-STATE OFFSHORE CA05COLORADO COFLORIDA-ONSHORE FLFLORIDA-STATE OFFSHORE FL05ILLINOIS ILINDIANA INKANSAS KSKENTUCKY KYLOUISIANA-NORTH LA50LOUISIANA-SOUTH ONSHORE LA10LOUISIANA-SOUTH STATE OFFSHORE LA05MARYLAND MDMICHIGAN MIMISSISSIPPI-ONSHORE MSMISSISSIPPI-STATE OFFSHORE MS05MISSOURI MOMONTANA MTNEBRASKA NENEVADA NVNEW MEXICO-EAST NM10NEW MEXICO-WEST NM50NEW YORK NYNORTH DAKOTA NDOHIO OH

SAMPLE
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 145

Figure I3. Form EIA-23, Summary Report – Page 2

Source: Energy Information Administration, Offfice of Oil and Gas. OFFICIAL USE ONLY 1998 ANNUAL SURVEY OF DOMESTIC OIL AND GAS RESERVES SUMMARY REPORT PAGE 2 OF 2 (Report All Volumes of Crude Oil and Lease Condensate in Thousands of Barrels [Mbbl]; Form Approved OMB No. 1905-0057 Expires 12/2000 1.0 OPERATOR AND REPORT IDENTIFICATION DATA Report All Volumes of Natural Gas in Millions of Cubic Feet [MMcf] at 14.73 psia and 60 F) 1.1 OPERATOR I.D. CODE 1.2 OPERATOR NAME REPORT DATE 1.3 ORIGINAL 1.4 AMENDED 12 31 98 2.0 PRODUCTION AND RESERVES DATA CRUDE OIL NATURAL GAS LEASE CONDENSATE STATE OR RESERVES 1998 PRODUCTION RESERVES 1998 PRODUCTION RESERVES 1998 PRODUCTION GEOGRAPHIC SUBDIVISION Proved Reserves Dec. 31, 1998 (Mbbl) (A) (From properties for which reserves were Estimated) (Mbbl) (B) (From properties for which reserves were Not Estimated) (Mbbl) (C) Proved Reserves Dec. 31, 1998 (MMcf) (D) (From properties for which reserves were Estimated) (MMcf) (E) (From properties for which reserves were Not Estimated (MMcf) (F) Proved Reserves Dec. 31, 1998 (Mbbl) (G) (From properties for which reserves were Estimated) (Mbbl) (H) (From properties for which reserves were Not Estimated) (Mbbl) (I) OKLAHOMA OK PENNSYLVANIA PA SOUTH DAKOTA SD TENNESSEE TN TEXAS-RRC DISTRICT 1 TX10 TEXAS-RRC DISTRICT 2 ONSHORE TX20 TEXAS-RRC DISTRICT 3 ONSHORE TX30

TEXAS-RRC DISTRICT 4 ONSHORE TX40TEXAS-RRC DISTRICT 5 TX50TEXAS-RRC DISTRICT 6 TX60TEXAS-RRC DISTRICT 7B TX70TEXAS-RRC DISTRICT 7C TX75TEXAS-RRC DISTRICT 8 TX80TEXAS-RRC DISTRICT 8A TX85TEXAS-RRC DISTRICT 9 TX90TEXAS-RRC DISTRICT 10 TX95TEXAS-STATE OFFSHORE TX05UTAH UTVIRGINIA VAWEST VIRGINIA WVWYOMING WYFEDERAL OFFSHORE-GULF OF MEXICO (ALABAMA) AL00FEDERAL OFFSHORE-GULF OF MEXICO (FLORIDA) FL00FEDERAL OFFSHORE-GULF OF MEXICO (LOUISIANA) LA00FEDERAL OFFSHORE-GULF OF MEXICO (MISSISSIPPI) MS00FEDERAL OFFSHORE-GULF OF MEXICO (TEXAS) TX00FEDERAL OFFSHORE-PACIFIC (ALASKA) AK00FEDERAL OFFSHORE-PACIFIC (CALIFORNIA) CA00FEDERAL OFFSHORE-PACIFIC (OREGON) OR00OTHER STATE (SPECIFY)TOTAL (SUM EACH COLUMN) US

SAMPLE
Energy Information Administration

146 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Figure I4. Form EIA-23, Detail Report – Schedule A

Source: Energy Information Administration, Offfice of Oil and Gas. OFFICIAL USE ONLY 1998 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 Approved OMB No. 1905-0057 Expires 12/2000 1.0 OPERATOR AND REPORT IDENTIFICATION DATA 1.1 OPERATOR I.D. CODE 1.2 OPERATOR NAME REPORT DATE 1.3 ORIGINAL 1.4 AMENDED 1.5 PAGE FOR DOE USE ONLY 12 31 98 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 (M bbl) TYPE HYDROCARBON RESERVES (a) DECEMBER 31, 1997 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, 1998 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 (M bbl)

TYPE HYDROCARBON

RESERVES

(a) DECEMBER 31, 1997

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, 1998

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 (M bbl)

TYPE HYDROCARBON

RESERVES

(a) DECEMBER 31, 1997

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, 1998

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 (M bbl)

TYPE HYDROCARBON

RESERVES

(a) DECEMBER 31, 1997

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, 1998

NONPRODUCING

(i) RESERVES

12. CRUDE OIL (Mbbl)13. ASSOCIATED-DISSOLVED GAS(MMcf)14. NONASSOCIATED GAS (MMcf)15. LEASE CONDENSATE (Mbbl)

SAMPLE
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 147

Figure I5. Form EIA-23, Detail Report – Schedule B

Source: Energy Information Administration, Offfice of Oil and Gas. OFFICIAL USE ONLY 1998 ANNUAL SURVEY OF DOMESTIC OIL AND GAS RESERVES SCHEDULE B - FOOTNOTES Form Approved OMB No. 1905-0057 Expires 12/2000 1.0 OPERATOR AND REPORT IDENTIFICATION DATA 1.1 OPERATOR I.D. CODE 1.2 OPERATOR NAME REPORT DATE 1.3 ORIGINAL 1.4 AMENDED 1.5 PAGE FOR DOE USE ONLY 12 31 98 2.0 FOOTNOTE DATA Page Number (a) Item Number (b) Subitem Number (c) Column Desig- nation (d) Sequence Number (e) Notation (f) FOR DOE USE ONLY

SAMPLE
Energy Information Administration

148 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report

Figure I6. Form EIA-64A

EIA-64A (Revised 9/91)

OFFICIAL USE ONLY 1998 Energy Information Administration

U.S. DEPARTMENT OF ENERGY

Calendar Year 1998

Form Approved

OMB No. 1905-0057

Expires 12/31/2000

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, Statistics

and Methods Group EI-70, Washington, DC 20585; and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503.

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.

ENERGY INFORMATION ADMINISTRATION, EI-45

1000 INDEPENDENCE AVE, SW, MAIL STATION 2G-024

WASHINGTON, DC 20585

PLEASE COMPLETE THIS

FORM AND RETURN TO

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

SAMPLE
Glossary
Glossary

This glossary contains definitions of the technical terms used in this report and employed by respondents in

completing Form EIA--23, “Annual Survey of Domestic Oil and Gas Reserves,” or Form EIA--64A, “Annual

Report of the Origin of Natural Gas Liquids Production,” for the report year 1998.

Adjustments: The quantity which preserves an exact

annual reserves balance within each State or State

subdivision of the following form:

These adjustments are the yearly changes in the

published reserve estimates that cannot be attributed

to the estimates for other reserve change categories

because of the survey and statistical estimation

methods employed. For example, variations as a

result of changes in the operator frame, different

random samples or imputations for missing or

unreported reserve changes, could contribute to

adjustments.

Affiliated (Associated) Company: An “affiliate” of,

or a person “affiliated” with, a specific person is a

person that directly, or indirectly through one or

more intermediaries: controls; or is controlled by; or

is under common control with, the person specified.

(See Person and Control)

Control: The term “control” (including the terms

“controlling,” “controlled by,” and “under common

control with”) means the possession, direct or

indirect, of the power to direct or cause the direction

of the management and policies of a person, whether

through the ownership of voting shares, by contract,

or otherwise. (See Person)

Corrections: (See Revisions)

Crude Oil: A mixture of hydrocarbons that exists in

the liquid phase in natural underground reservoirs

and remains liquid at atmospheric pressure after

passing through surface separating facilities. Crude

oil may also include:

1. Small amounts of hydrocarbons that exist in the

gaseous phase in natural underground

reservoirs but are liquid at atmospheric

pressure after being recovered from oil well

(casinghead) gas in lease separators, and that

subsequently are comingled with the crude

stream without being separately measured

2. Small amounts of nonhydrocarbons produced

with the oil.

When a State regulatory agency specifies a definition

of crude oil which differs from that set forth above,

the State definition is to be followed and its use

footnoted on Schedule B of Form EIA--23.

Extensions: The reserves credited to a reservoir

because of enlargement of its proved area. Normally

the ultimate size of newly discovered fields, or newly

discovered reservoirs in old fields, is determined by

wells drilled in years subsequent to discovery. When

such wells add to the proved area of a previously

discovered reservoir, the increase in proved reserves

is classified as an extension.

Field: An area consisting of a single reservoir or

multiple reservoirs all grouped on, or related to, the

same individual geological structural feature and/or

stratigraphic condition. There may be two or more

reservoirs in a field that are separated vertically by

intervening impervious strata, or laterally by local

geologic barriers, or by both.

Field Area: A geographic area encompassing two or

more pools that have a common gathering and

metering system, the reserves of which are reported

as a single unit. This concept applies primarily to the

Appalachian region. (See Pool)

Field Discovery Year: The calendar year in which a

field was first recognized as containing economically

recoverable accumulations of oil and/or gas.

Field Separation Facility: A surface installation

designed to recover lease condensate from a

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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 151

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

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152 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
facilities, if any, and after exclusion of

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 Ownershi

p 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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 153
transferred to the storage category, are not

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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154 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report
information on fluid contacts, the lowest known

structural occurrence of hydrocarbons is considered

to be the lower proved limit of the reservoir.

Volumes of natural gas placed in underground

storage are not to be considered proved reserves.

For natural gas, wet after lease separation, an

appropriate reduction in the reservoir gas volume

has been made to cover the removal of the

liquefiable portions of the gas in lease and/or field

separation facilities and the exclusion of

nonhydrocarbon gases where they occur in sufficient

quantity to render the gas unmarketable.

For dry natural gas, an appropriate reduction in the

gas volume has been made to cover the removal of

the liquefiable portions of the gas in lease and/or

field separation facilities, and in natural gas

processing plants, and the exclusion of

nonhydrocarbon gases where they occur in sufficient

quantity to render the gas unmarketable.

It is not necessary that production, gathering, or

transportation facilities be installed or operative for a

reservoir to be considered proved. It is to be

assumed that compression will be initiated if and

when economically justified.

Proved Reserves of Natural Gas Liquids: Proved

reserves of natural gas liquids as of December 31 of

the report year are those volumes of natural gas

liquids (including lease condensate) demonstrated

with reasonable certainty to be separable in the

future from proved natural gas reserves, under

existing economic and operating conditions.

Proved Ultimate Recovery: The sum of proved

reserves and cumulative production. It is expected to

change over time for any field, group of fields, State,

or Country. Proved Ultimate Recovery does not

represent the maximum recoverable volume of

resources for an area. It is instead a gauge of how

much has already been produced plus proved

reserves. Proved reserves of crude oil or natural gas

are the estimated quantities of petroleum which

geological and engineering data demonstrate with

reasonable certainty to be recoverable in future years

from known reservoirs under existing economic and

operating conditions. When deterministic proved

reserves estimation methods are used, the term

reasonable certainty is intended to express a high

degree of confidence that the estimated quantities

will be recovered. When probabilistic methods are

used there should be at least a 90 percent probability

that the actual quantities recovered will exceed the

estimate.

Report Year: The calendar year to which data

reported in this publication pertain.

Reserves: (See Proved Reserves)

Reserve Additions: Consist of adjustments, net

revisions, extensions to old reservoirs, new reservoir

discoveries in old fields, and new field discoveries.

Reserves Changes: Positive and negative revisions,

extensions, new reservoir discoveries in old fields,

and new field discoveries, which occurred during the

report year.

Reservoir: A porous and permeable underground

formation containing an individual and separate

natural accumulation of producible hydrocarbons (oil

and/or gas) which is confined by impermeable rock

or water barriers and is characterized by a single

natural pressure system.

Revisions: Changes to prior year--end proved

reserves estimates, either positive or negative,

resulting from new information other than an

increase in proved acreage (extension). Revisions

include increases of proved reserves associated with

the installation of improved recovery techniques or

equipment. They also include correction of prior

report year arithmetical or clerical errors and

adjustments to prior year--end production volumes

to the extent that these alter reported prior year

reserves estimates.

Royalty (Including Overriding Royalty) Interests:

These interests entitle their owner(s) to a share of the

mineral production from a property or to a share of

the proceeds therefrom. They do not contain the

rights and obligations of operating the property, and

normally do not bear any of the costs of exploration,

development, and operation of the property.

Subdivision: A prescribed portion of a given State

or other geographical region defined in this

publication for statistical reporting purposes.

Subsidiary Company: A company which is

controlled through the ownership of voting stock, or

a corporate joint venture in which a corporation is

owned by a small group of businesses as a separate

and specific business or project for the mutual

benefit of the members of the group. (See Control)

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 155
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.

Energy Information Administration

156 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report