DOE/EIA–0216(99)

U.S. Crude Oil, Natural Gas,

and Natural Gas Liquids Reserves

1999 Annual Report

December 2000

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.

This publication is on the WEB at:

www.eia.doe.gov/oil_gas/natural_gas/data_publications/crude_oil_natural_gas reserves/cr99.html
Preface

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

Liquids Reserves 1999 Annual Report is the 23rd

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, 1999, as well as production volumes

for the United States and selected States and State

subdivisions for the year 1999. 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 1999 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 1999; 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 1999 Annual Report iii
Energy Information Administration

iv U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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 1999, DOE/EIA–0131(99), October 2000

Petroleum Supply Annual 1999, DOE/EIA–0340(99), June 2000

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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

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

Reserve-to-Production Ratios and Ultimate Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

R/P Ratios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

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

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

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

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

Dependence on Imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

List of Appendices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

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

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

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

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

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

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

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

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

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

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

Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

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

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

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

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

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

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

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

Other Decline Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Reserves in Nonproducing Reservoirs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Indicated Additional Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

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 1999 Annual Report v
Page

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Areas of Note: Large Reserves Declines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

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

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

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Appendices

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

B. Top 100 Oil and Gas Fields for 1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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, 1989-1999 . . . . . . . . . . . . 4

2. Reserves Changes, 1977-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

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

Average Number of Active Rotary Drilling Rigs, 1977-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . 10

4. U.S. Exploratory and Development Well Completions, 1970-1999 . . . . . . . . . . . . . . . . . . . . . . . . . 12

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vi U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report
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5. International Oil and Natural Gas Reserves as of December 31, 1999 . . . . . . . . . . . . . . . . . . . . . . . 16

6. Crude Oil Proved Reserves, Reserves Changes, and Production, 1999 . . . . . . . . . . . . . . . . . . . . . . 20

7. Reported Indicated Additional Crude Oil Reserves, 1999. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 1999 . . . . . . . . . . . . . . . . . . 28

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

Wet After Lease Separation, 1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

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

Wet After Lease Separation, 1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

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

Wet After Lease Separation, 1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

12. U.S. Coalbed Methane Proved Reserves and Production, 1989-1999 . . . . . . . . . . . . . . . . . . . . . . . 35

13. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 1999. . . . . . . . . . . . . . . . . 38

14. Natural Gas Plant Liquids Proved Reserves and Production, 1999. . . . . . . . . . . . . . . . . . . . . . . . . 39

15. Lease Condensate Proved Reserves and Production, 1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Figures

1. U.S. Crude Oil Proved Reserves, 1989-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

2. Components of Reserves Changes for Crude Oil, 1989-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

3. U.S. Dry Natural Gas Proved Reserves, 1989-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

4. Components of Reserves Changes for Dry Natural Gas, 1989-1999 . . . . . . . . . . . . . . . . . . . . . . . . 6

5. U.S. Natural Gas Liquids Proved Reserves, 1989-1999. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

6. Components of Reserves Changes for Natural Gas Liquids, 1989-1999 . . . . . . . . . . . . . . . . . . . . . . 8

7. U.S. Exploratory Gas Well Completions, 1977-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

8. U.S. Exploratory Oil Well Completions, 1977-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

9. U.S. Total Discoveries of Dry Natural Gas per Exploratory Gas Well Completion, 1977-1999 . . . . . . . . . . . 13

10. U.S. Total Discoveries of Crude Oil per Exploratory Oil Well Completion, 1977-1999 . . . . . . . . . . . . . . . 13

11. Reserves-to-Production Ratios for Crude Oil, 1945-1999. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

12. Reserves-to-Production Ratios for Wet Natural Gas, 1945-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . 15

13. Components of Ultimate Recovery for Crude Oil and Lease Condensate, 1977-1999 . . . . . . . . . . . . . . . 15

14. Components of Ultimate Recovery for Wet Natural Gas, 1977-1999 . . . . . . . . . . . . . . . . . . . . . . . . 15

15 Reserve Additions Replace 137 Percent of U.S. Oil Production in 1999 . . . . . . . . . . . . . . . . . . . . . . 19

16. 1999 Crude Oil Proved Reserves by Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

17. Changes in Crude Oil Proved Reserves by Area, 1998 to 1999 . . . . . . . . . . . . . . . . . . . . . . . . . . 21

18. Reserve Additions Replace 118 Percent of 1999 U.S. Dry Gas Production. . . . . . . . . . . . . . . . . . . . . 27

19. 1999 Dry Natural Gas Proved Reserves by Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

20. Changes in Dry Natural Gas Proved Reserves by Area, 1998 to 1999 . . . . . . . . . . . . . . . . . . . . . . . 29

21. Coalbed Methane Proved Reserves, 1989-1999 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report vii
Executive Summary

U.S. proved reserves of crude oil rebounded from

their unusually large 1998 decline, growing by about

3.5 percent in 1999 — the largest percentage increase

in the 23-year EIA reserves program. Over 137

percent of 1999 oil production was replaced by

proved reserve additions. This was not a result of

increased drilling, more successful exploratory

drilling, or dramatically improved technology. Crude

oil prices began slowly increasing from the

inflation-adjusted 53-year low of December 1998 and

then accelerated during the year, reaching $22.55 per

barrel in December 1999. The resurgent crude price

generated the largest positive net revisions to proved

reserves in over a decade.

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

1999, reversing the 2 percent decline of 1998. Natural

gas reserve additions in 1999 replaced 118 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 1999 U.S. proved

reserves of crude oil, natural gas, and natural gas

liquids is the 23rd in the annual series prepared by

the Energy Information Administration.

Crude Oil

Price matters. The 1999 rebound in crude oil reserves

was fundamentally driven by price increases just as

the unusually large oil reserve declines of 1998 had

been fundamentally driven by very low oil prices.

Changes in proved reserves are impacted by price in

several ways.

The attainment of higher prices from an initially very

low base level implies much better economics for oil

producers. The December 1999 oil price used to

evaluate oil field economics and estimate proved

reserves was roughly three times the December 1998

price; many operators reported that the reason for

their positive reserve revisions was the price

increase.

Further, the December 1999 price ($22.55 per barrel)

was relatively better for the smaller and marginal oil

well operators because they are usually operating

closer to their direct operating costs. Texas, like most

of the lower-48 States, is basically a stripper well

(less than 10 barrels per day per well) State. 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. But in 1999, Texas oil reserves

increased by over 8 percent while Alaskan reserves

dropped, returning Texas to its number one position.

Reserve additions are the sum of total discoveries and

revisions and adjustments. For crude oil, the net of

revisions and adjustments was the highest in over a

decade and replaced 100 percent of 1999 oil

production. This price-induced rebound followed

1998’s negative net revision and adjustment of 120

million barrels which marked the first time in 22 years

that the net of revisions and adjustments had not

made a positive contribution to oil reserve additions.

Total discoveries of crude oil were 725 million

barrels in 1999, about the prior 10-year average and

21 percent more than those in 1998. The Gulf of

Mexico Federal Offshore accounted for over half of

them. Total discoveries, which equaled only 37

percent of 1999 oil production, are those reserves

attributable to field extensions, new field discoveries,

and new reservoir discoveries in old fields. They

result from the drilling of exploratory wells. New

field discoveries of 321 million barrels were twice

those of 1998 and well above the prior 10-year

average. Almost all of them were in the Gulf of

Mexico Federal Offshore and Alaska. Well 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 145

million barrels, about the same as the prior 10-year

average. Field extensions were down in 1999 to 60

percent of the prior 10-year average, but still added

259 million barrels of proved oil reserves.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report ix

As of December 31, 1999 proved reserves were:

Crude Oil (million barrels)

1998 21,034

1999 21,765

Increase 3.5%

Dry Natural Gas (billion cubic feet)

1998 164,041

1999 167,406

Increase 2.1%

Natural Gas Liquids (million barrels)

1998 7,524

1999 7,906

Increase 5.1%
Other 1999 crude oil events of note:

 The annual average domestic first purchase price

for crude oil increased 43 percent from the 1998

level to $15.56 per barrel.

 Exploratory oil completions were down almost

50 percent at 148 and total oil well completions

were down about 40 percent at 3,853. For both,

the low drilling level reached in 1998 deepened

in 1999 and did not begin to ameliorate until

after mid-year inasmuch as oil prices did not

reach $15 per barrel until July 1999.

 Total discoveries per exploratory oil well were

much higher because most of the discoveries were

in the less maturely explored Gulf of Mexico and

Alaska and because the drilling level was also

down. Nevertheless, as we predicted in the 1998

report, higher oil prices in December 1999 brought

back some of the oil reserves that became

uneconomic in1998.

Indicated additional reserves of crude oil decreased 9

percent to 2,865 million barrels in 1999. 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

With the 1999 increase, U.S. natural gas proved

reserves have increased in 5 of the past 6 years. The

combined 1999 reserve increases in Texas, Colorado,

and Utah more than account for U.S. net proved

reserve additions. Oklahoma and the Gulf of Mexico

had significant gas reserve declines.

Proved reserves in the Gulf of Mexico Federal

Offshore declined in both 1998 and 1999, even

though deepwater Gulf of Mexico Federal Offshore

reserves were up substantially in both 1998 and 1999,

as was production. However, for those Gulf of

Mexico fields located in water less than 200 meters

deep, proved reserves declined by 5 percent and

production declined by 9 percent in 1999.

The reserve additions of natural gas were higher in

1999 because the net of revisions and adjustments to

reserves (11,486 billion cubic feet) was more than

twice as high as in 1998 and 70 percent higher than

the prior 10-year average. However, natural gas

prices were only up 7 percent in 1999 to $2.08 per

thousand cubic feet. The associated-dissolved gas

revisions related to oil reserve revisions underwent

larger percentage gains than did those for gas which

is not associated with crude oil in the reservoir

(nonassociated gas).

The other major component, total discoveries,

declined in 1999 to 10,807 billion cubic feet. New

field discoveries were 1,568 billion cubic feet, a little

more than the prior 10-year average. Field extensions

were 7,043 billion cubic feet, down from 1998 and

almost exactly at the prior 10-year average. New

reservoir discoveries in old fields were 2,196 billion

cubic feet, about the same as in 1998 and 6 percent

less than the prior 10-year average.

Coalbed methane reserves and production continued to

grow faster in 1999 than did the reserves and production

of conventional natural gas. Coalbed methane reserves

increased to 8 percent of proved dry gas reserves and

accounted for 7 percent of total dry gas production in

1999.

Other 1999 natural gas events of note:

 Exploratory gas well completions increased 13

percent in 1999 while development gas well

completions declined 15 percent.

 Although the number of exploratory wells

increased, the average of total discoveries per

exploratory gas well was 16 percent less in 1999.

 U.S. gas production was slightly higher in 1999

according to the EIA reserves survey.

Natural Gas Liquids

U.S. natural gas liquids proved reserves increased 5

percent to 7,906 million barrels in 1999. Natural gas

liquids reserves are the sum of natural gas plant

liquids and lease condensate reserves.

Total proved reserves of liquid hydrocarbons (crude oil

plus natural gas liquids) were 29,671 million barrels in

1999, a 4 percent increase from the 1998 level. Natural

gas liquids represented 27 percent of total liquid

hydrocarbon proved reserves in 1999.

Data

These estimates are based upon analysis of data from

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

Reserves, filed by 1,897 operators of oil and gas wells,

and Form EIA-64A, Annual Report of the Origin of

Natural Gas Liquids Production, filed by operators of 608

active natural gas processing plants. By use of improved

sampling and imputation procedures, the sample of oil

and gas well operators was reduced by almost a third

from that of the 1998 survey without sacrificing accuracy.

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

natural gas are associated with sampling errors of

less than 1 percent.

Energy Information Administration

x U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report
1. Introduction

Background

The principal focus of this report is to provide accurate

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

natural gas, and natural gas liquids. These estimates

are essential to the development, implementation, and

evaluation of national energy policy and legislation. In

the past, the Government and the public relied upon

industry estimates of proved reserves. However, the

industry ceased publication of reserve estimates after

its 1979 report.

In response to a recognized need for credible annual

proved reserves estimates, Congress, in 1977, required

the Department of Energy to prepare such estimates.

To meet this requirement, the Energy Information

Administration (EIA) developed a program that

established a unified, verifiable, comprehensive, and

continuing annual statistical series for proved reserves

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

proved reserves of natural gas liquids for the 1979 and

subsequent reports.

Survey Overview

EIA defines proved reserves, the major topic of this

report, as those volumes of oil and gas that geological

and engineering data demonstrate with reasonable

certainty to be recoverable in future years from known

reservoirs under existing economic and operating

conditions. There are other categories of reserves, but

by definition they are more speculative and less precise

than proved reserves. Readers who are unfamiliar with

the distinctions between types of reserves or with how

reserves fit in the description of overall oil and gas

resources should see Appendix G.

While the primary topic of this report is proved

reserves, information is also presented on indicated

additional crude oil reserves. Indicated additional

crude oil reserves are not included in proved reserves

because of their uncertain economic recoverability.

When economic recoverability is demonstrated, these

volumes will be reclassified and transferred to the

proved reserves category as positive revisions.

This report provides proved reserves estimates for

calendar year 1999. 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 operator

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 (Category I) and most intermediate

size operators (Category II) 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 1999 Annual Report 1
A select group of small operators (Category III) are

requested to provide annual production and year

ending reserves volumes if available. Details on the

selection of these operators and the determination of

the reserves volumes is found in Appendix F.

The published reserve estimates include an additional

term, adjustments, calculated by the EIA, that

preserves an exact annual reserves balance of the form:

Adjustments are the annual changes in the published

reserve estimates that cannot be attributed to the

estimates for other reserve change categories. They

result from the survey and statistical estimation

methods employed. For example, variations caused by

changes in the operator frame, different random

samples, changes in reserve estimates following

ownership changes, incorrectly reported data, or

imputations for missing or unreported reserve changes

can contribute to adjustments.

Form EIA-64A

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

survey year in order to develop estimates for total

natural gas liquids reserves. Data on liquids recovered

from natural gas, as reported by natural gas processing

plant operators, are combined with lease condensate

data collected on Form EIA-23 to provide the total

natural gas liquids reserves estimates.

Data Collection Operations

An intensive effort is made each year to maintain an

accurate and complete survey frame consisting of

operators of oil and gas wells and of natural gas

processing plants. The Form EIA-23 operator frame

contained 22,125 probable active operators and the

Form EIA-64A plant frame contained 589 probable

active natural gas processing plants in the United

States when the 1999 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 1999.

For the report year 1999, EIA mailed 576 EIA-23 forms

to all known large and intermediate size oil and gas

well operators that were believed to be active during

1999. Of these, 33 were found to be nonoperators that

did not have successor operator and 35 were new

operators or operators that changed category. Data

were received from 578 operators, an overall response

rate of 100 percent of the active operators in the Form

EIA-23 survey. EIA mailed 589 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 554 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 1999,

the Form EIA-23 National production estimates were 4

percent lower than the comparable Petroleum Supply

Annual (PSA) 1999 volumes for crude oil and lease

condensate combined, and were 0.1 percent higher

than the comparable Natural Gas Annual 1999 volume

for 1999 dry natural gas. For report year 1999, the Form

EIA-64A National estimates were 6 percent lower than

the PSA 1999 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.

Energy Information Administration

2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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, 1999:

 Crude Oil — 21,765 million barrels

 Dry Natural Gas — 167,406 billion cubic feet

 Natural Gas Liquids — 7,906 million barrels.

This Overview summarizes the 1999 proved reserves

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

liquids on a National level and provides historical

comparisons between 1999 and years past.

Table 1 lists the estimated annual reserve balances

since 1989. From 1998 to 1999, proved reserves of crude

oil increased by 3.5 percent—the largest percentage

increase in the 23-year EIA reserves program. Proved

reserves of dry natural gas increased by 2 percent.

Natural gas liquids reserves increased 5 percent.

Crude Oil

Proved reserves of crude oil increased by 731 million

barrels in 1999. Figure 1 shows the crude oil proved

reserves levels by major region and Figure 2 shows the

components of reserves changes from 1989 through

1999.

As shown in Figure 2, total reserve additions (the

positive side of the scale) were up substantially in 1999,

due primarily to the substantial difference in oil prices

seen in December 1998 and December 1999. Operators

replaced 137 percent of the 1999 oil production with

reserve additions. Production of crude oil (the negative

side of the scale of Figure 2) declined slightly for the

eighth 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 725 million barrels of

total discoveries of crude oil proved reserves in 1999.

This is 21 percent more than what was discovered in

1998, but still 3 percent less than what was discovered

on average in the prior 10 years.

Extensions added 259 million barrels of proved

reserves. This is 21 percent less than in 1998 (327

million barrels) and 40 percent less than the average

extensions in the prior 10 years (433 million barrels).

New field discoveries were 321 million barrels, more than

double the 1998 level and 74 percent more than the

average volume discovered in the prior 10 years (184

million barrels). New field discoveries in Alaska and

the Gulf of Mexico Federal Offshore made up 99

percent of the 1999 volume of new field discoveries.

New reservoir discoveries in old fields added 145 million

barrels of proved reserves. This is more than the 1998

level (120 million barrels) and the prior 10-year average

for the United States (135 million barrels).

Net revisions and adjustments added 1,958 million

barrels of proved reserves. This is substantially more

than 1998’s -120 million barrels, which was the first

negative total for net revisions and adjustments for

crude oil since EIA began collecting this data. In the

past 10 years, net revisions and adjustments have added

an average of 986 million barrels of crude oil proved

reserves per year. Revisions include sales and

acquisitions.

Production removed an estimated 1,952 million barrels

of proved reserves from the National total. Production

was down 2 percent from 1998’s level (1,991 million

barrels), and down 16 percent from the prior 10-year

average (2,317 million barrels).

Natural Gas

U.S. proved reserves of dry natural gas increased 2

percent, resuming an increasing trend that began 5

years ago but was interrupted by a decline in 1998. Dry

natural gas reserves increased by 3,558 billion cubic

feet in the Lower 48 States, and in Alaska declined by

193 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 1989

through 1999. Dry natural gas production increased 1

percent from 1998 to 1999. Operators were able to

replace 118 percent of 1999’s dry gas production with

new reserves.

For 1999, U.S. total discoveries of dry gas reserves were

10,807 billion cubic feet, down 5 percent from 1998, but

almost equal the average annual volume discovered in

the past 10 years. Total discoveries were 48 percent of all

reserve additions in 1999.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 3
Energy Information Administration

4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

Table 1. Total U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids, 1989-1999

Revisionsa New Reservoir Provedc Change Revision Revision and New Field Discoveries Totalb Estimated 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)

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

1999 139 6,284 4,465 1958 259 321 145 725 1,952 21,765 +731

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

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

1999 982 42,167 31,663 11,486 7,043 1,568 2,196 10,807 18,928 167,406 +3,365

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

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

1999 99 2,048 1,321 826 313 51 88 452 896 7,906 +382

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.

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

1999 contained in the Petroleum Supply Annual 1999, DOE/EIA-0340(99) and the Natural Gas Annual 1999, DOE/EIA-0131(99).

Sources: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1989 through 1999 annual reports, DOE/EIA-0216.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 5

0

5

10

15

20

25

30

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

Crude Oil, Billions of Barrels

0

5

10

15

20

25

30

U.S. Total

Lower 48 Onshore

Lower 48 Offshore

Alaska

-5

-4

-3

-2

-1

0

1

2

3

4

5

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

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

Figure 1. U.S. Crude Oil Proved Reserves, 1989-1999

Figure 2. Components of Reserves Changes for Crude Oil, 1989-1999

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1989-1999 annual reports, DOE/EIA-0216.{12-22}
Energy Information Administration

6 U.S. Crude Oil, NaturalGas, and Natural Gas Liquids Reserves 1999 Annual Report

0

20

40

60

80

100

120

140

160

180

200

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

Dry Natural Gas, Trillion Cubic Feet

0

20

40

60

80

100

120

140

160

180

200

U.S. Total

Lower 48 Onshore

Lower 48 Offshore

Alaska

-30

-20

-10

0

10

20

30

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

Dry Natural Gas, Trillion Cubic Feet

-30

-20

-10

0

10

20

30

New Fields New Reservoirs Extensions

Production Revisions & Adjustments Net Reserves Changes

Figure 4. Components of Reserves Changes for Dry Natural Gas, 1989-1999

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1989-1999 annual reports, DOE/EIA-0216.{12-22}

Figure 3. U.S. Dry Natural Gas Proved Reserves, 1989-1999
Extensions added 7,043 billion cubic feet of proved

reserves. This is 14 percent less than 1998’s extensions

but is comparable to the average of extensions in the

prior 10 years (7,048 billion cubic feet).

New field discoveries added 1,568 billion cubic feet of

proved reserves. This is 46 percent higher than what

was discovered in 1998 and 7 percent higher than the

average volume discovered in the prior 10 years (1,462

billion cubic feet).

New reservoir discoveries in old fields added 2,196 billion

cubic feet of proved reserves. This is 2 percent more

than the volume discovered in 1998, and 6 percent

lower than the prior 10-year average (2,344 billion

cubic feet).

Net revisions and adjustments added 11,486 billion cubic

feet of proved reserves. This is 180 percent more than

1998’s revisions and adjustments and 71 percent more

than the prior 10-year average (6,719 billion cubic feet).

Revisions include sales and acquisitions.

Production removed an estimated 18,928 billion cubic

feet of proved reserves from the National total. Dry gas

production increased 1 percent compared to 1998.

Coalbed methane gas production and reserves are

included in the 1999 totals. However, EIA separately

tracks these reserves in order to record the

development and performance of this gas source.

Coalbed methane reserves increased in 1999 to a

volume of 13,229 billion cubic feet. Coalbed methane

accounted for 8 percent of 1999 U.S. dry natural gas

reserves and 7 percent of 1999 U.S. dry gas production.

Natural Gas Liquids

Proved reserves of natural gas liquids increased 382

million barrels to 7,906 million barrels during 1999— a

5 percent increase from 1998 levels. Figure 5 shows the

natural gas liquids proved reserves levels by major

region and Figure 6 shows the components of reserves

changes from 1989 through 1999.

Operators replaced 143 percent of their 1999 natural

gas liquids production with reserve additions. Total

discoveries added 452 million barrels, and net revisions

and adjustments added 826 million barrels.

Total proved reserves of liquid hydrocarbons (crude oil

plus natural gas liquids) were 29,671 million barrels in

1999—a 4 percent increase from the 1998 level. Natural

gas liquids represented 27 percent of total liquid

hydrocarbon proved reserves in 1999.

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 1999. 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 1999 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 800 million barrels per

year of new reserves

 revised and adjusted their proved reserves

upward by an average of 1,328 million barrels

per year from revisions and adjustments

 ended each year with an average net reduction

in U.S. proved reserves of 508 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 18,393 million barrels of total discoveries

accounted for the remaining 38 percent of reserves

additions.

Compared to the average reserves changes since 1977,

1999 was a down year for crude oil discoveries. Total

discoveries of crude oil (725 million barrels) in 1999 were

9 percent less the post-1976 U.S. average. In 1999, net

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 7
Energy Information Administration

8 U.S. Crude Oil, NaturalGas, and Natural Gas Liquids Reserves 1999 Annual Report

0

1

2

3

4

5

6

7

8

9

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

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

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

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 5. U.S. Natural Gas Liquids Proved Reserves, 1989-1999

Figure 6. Components of Reserves Changes for Natural Gas Liquids, 1989-1999

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1989-1999 annual reports, DOE/EIA-0216.{12-22}
revisions and adjustments were 47 percent higher than

the post-1976 U.S. Average.

Looking at the components of total discoveries in 1999:

 both new field discoveries and new reservoir

discoveries in old fields exceeded the post-1976

averages for crude oil, and

 1999’s extensions fell far short of the post-1976

average -- enough to result in the 9 percent

decline in total discoveries.

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

 discovered an average of 11,972 billion cubic

feet per year of new reserves

 revised and adjusted their proved reserves

upward by an average 3,759 billion cubic feet

per year

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

2,001 billion cubic feet per year.

Like crude oil reserves, natural gas reserves have been

sustained primarily by proved ultimate recovery

appreciation since 1977. Usually extensions rather than

net revisions and adjustments are the largest component.

Extensions account for 48 percent while net revisions and

adjustments account for only 24 percent of all reserve

additions since 1977. In 1999, net revisions and

adjustments were 52 percent of all reserves additions. In

1999, extensions were 32 percent of all reserves

additions.

Compared to the average reserves changes since 1977,

1999 was a below average year for natural gas reserve

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

gas reserves increased 2 percent, resuming an

increasing trend. Operators reported 10,807 billion

cubic feet of total discoveries of dry natural gas proved

reserves—10 percent less than the post-1976 average

(11,972 billion cubic feet). However, net revisions and

adjustments were substantially more in 1999 (11,486

billion cubic feet) compared to the post-1976 U.S.

Average (3,759 billion cubic feet).

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 9

Table 2. Reserves Changes, 1977-1999

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 ........... 3,285 143 8.3 3,955 172 8.1

New Reservoir Discoveries in Old Fields . . 3,144 137 8.0 3,174 138 6.5

Extensions ................ 10,109 440 25.7 11,264 490 23.1

Total Discoveries ............. 16,538 719 42.0 18,393 800 37.7

Revisions and Adjustments ........ 22,831 993 58.0 30,458 1,324 62.3

Total Reserve Additions .......... 39,369 1,712 100.0 48,851 2,124 100.0

Production ................ 47,432 2,062 120.5 60,588 2,634 124.0

Net Reserve Change............ -8,063 -351 -20.5 -11,737 -510 -24.0

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

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

New Field Discoveries ........... 44,149 1,920 11.7 44,297 1,926 12.2

New Reservoir Discoveries in Old Fields . . 58,473 2,542 15.5 58,861 2,559 16.3

Extensions ................ 171,296 7,448 45.5 172,215 7,488 47.6

Total Discoveries ............. 273,918 11,909 72.7 275,373 11,973 76.1

Revisions and Adjustments ........ 102,808 4,470 27.3 86,600 3,765 23.9

Total Reserve Additions .......... 376,726 16,379 100.0 361,973 15,738 100.0

Production ................ 399,892 17,387 106.1 407,845 17,732 112.7

Net Reserve Change............ -23,166 -1,007 -6.1 -45,872 -1,994 -12.7

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1977-1999 annual reports, DOE/EIA-0216.{1-22}
Energy Information Administration

10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

Table 3. U.S. Average Annual Domestic First Purchase Prices for Crude Oil, Wellhead Prices for Natural

Gas, and the Average Number of Active Rotary Drilling Rigs, 1977-1999

Crude Oil Natural Gas

Year Current 1999 Constant Current 1999 Constant

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

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 18.46 19.00 2.17 2.23 779

1997 17.23 17.40 2.32 2.34 943

1998 January 13.45 13.72 1.95 1.99 993

February 12.17 12.41 1.95 1.99 974

March 11.15 11.36 2.05 2.09 932

April 11.28 11.48 2.15 2.19 886

May 11.13 11.31 2.04 2.07 855

June 10.00 10.15 1.90 1.93 854

July 10.44 10.58 2.08 2.11 816

August 10.20 10.33 1.81 1.83 792

September 11.29 11.42 1.69 1.71 774

October 11.32 11.45 1.85 1.87 734

November 9.64 9.74 1.93 1.95 688

December 8.03 8.10 1.94 1.96 647

1998 10.87 11.03 1.94 1.97 827

1999 January 8.59 8.64 1.80 1.81 587

February 8.58 8.62 1.73 1.74 542

March 10.75 10.78 1.70 1.71 526

April 12.84 12.87 1.93 1.93 496

May 13.84 13.85 2.10 2.10 516

June 14.34 14.34 2.09 2.09 558

July 16.13 16.14 2.07 2.07 588

August 17.58 17.60 2.34 2.34 639

September 20.10 20.12 2.42 2.42 696

October 19.21 19.73 2.31 2.31 741

November 21.35 21.39 2.44 2.44 782

December 22.55 22.60 2.03 2.03 798

1999 15.56 15.56 2.08 2.08 625

=Revised data.

Sources: Current dollars and number of rigs: Monthly Energy Review August 2000, DOE/EIA-0035(00/08). 1999 constant dollars: U.S.

Department of Commerce, Bureau of Economic Analysis, Gross Domestic Product Implicit Price Deflators, August 2000.
Economics and Drilling

Economics: Price matters. In 1999, resurgent crude oil

prices generated the largest positive net revisions to

proved reserves in over a decade. This section

describes the price behavior in 1999 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 1999.

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

average of $8.03 per barrel in December 1998 (an

inflation-adjusted 53-year low), then accelerated

during the year, reaching $22.55 per barrel in December

1999. The average U.S. crude oil first purchase price

increased from an average $10.87 in 1998 to $15.56 per

barrel in 1999. The price increases continue in the year

2000.

Oil prices vary by region. In Texas the average 1999

crude oil first purchase price was $17.29 per barrel,

while in California it was $14.08 per barrel, and only

$12.46 per barrel on the Alaskan North Slope. The

lowest average crude oil first purchase price in 1999

was for Federal Offshore California oil—$11.78 per

barrel.{23}

The average annual wellhead natural gas price

increased from $1.94 in 1998 to $2.08 per thousand

cubic feet in 1999. Natural gas prices started at $1.80 per

thousand cubic feet in January 1999 and rose to $2.44

per thousand cubic feet by November 1999 (the highest

average price of the year). The price increases continue

in 2000, passing $3.00 per thousand cubic feet in June

2000. {24}

Drilling: From 1998 to 1999, the annual average active

rig count decreased from 827 to 625 (Table 3), a 24

percent decline in active rigs. The rig count remains

well below the peak activity level of the early 80’s.

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 2,123

exploratory wells drilled in 1999 (Table 4). Of these, 7

percent were oil wells, 27 percent were gas wells, and

66 percent were dry holes. The total (which includes

dry holes) was 21 percent less than in 1998.

There were 1 percent more exploratory gas wells

(Figure 7) and 50 percent fewer exploratory oil wells

(Figure 8) than in 1998. The number of successful

development wells decreased 42 percent for oil and

decreased 14 percent for gas from 1998.

Figures 9 and 10 show the average volume of

discoveries per exploratory well for dry natural gas

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

gas discoveries per exploratory well decreased slightly,

while the average volume of oil discoveries per

exploratory well in 1999 increased. Altogether there

were an estimated 18,180 exploratory and

development wells drilled in 1999, 25 percent less than

in 1998 and 28 percent less than the average number of

wells drilled annually in the prior 10 years (25,328).

For the seventh 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 1999 occurred in frontier

drilling areas. Some occurred around the boardroom

tables of major oil and gas corporations. The following

large mergers were announced in 1999, and are

expected to have a major impact on the energy industry

in the future:

On November 30, 1999, Exxon Corporation and Mobil

Corporation confirmed that the U.S. Federal Trade

Commission (FTC) completed its review of the

proposed merger and has approved a consent order for

the merger of the two companies. Exxon and Mobil

have accepted terms and conditions specified by the

FTC and will comply with them fully and in a timely

manner. The merged ExxonMobil Corporation expects

that the scale of the worldwide near-term cost savings

and the long-term strategic benefits will likely exceed

those announced last year. The FTC’s review was one

of the most thorough and exhaustive ever undertaken,

lasting some 11 months. Exxon and Mobil worked

closely with the FTC to provide appropriate

information on a timely basis to facilitate regulatory

review of the merger. {25}

On August 17, 1999 Devon Energy Corporation and

PennzEnergy Company announced that their merger

had been completed. The merger was announced on

May 20, 1999. Shareholders of both companies

approved the merger at special meetings of

shareholders on August 17, 1999. PennzEnergy

shareholders will own approximately 31 percent of the

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 11
combined company and Devon shareholders will own

approximately 69 percent. The new Devon Energy

Corporation now ranks in the top 10 of all U.S.-based

independent oil and gas producers in terms of market

capitalization, total proved reserves and annual

production. Devon Energy Corporation operates one

of the world's largest coal bed methane fields in the San

Juan Basin, plus has significant exposure to the

developing Powder River Basin and Raton Basin coal

seam plays. Devon also is one of the largest producers

in the Gulf of Mexico with operations on 75 blocks and

interests in an additional 98 undeveloped blocks. {26}

On October 25, 1999, El Paso Energy Corporation and

Sonat Incorporated completed their $6 billion merger.

The transaction creates a natural gas transmission

system comprising over 40,000 miles, the largest

natural gas transmission system in North America,

Energy Information Administration

12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

Table 4. U.S. Exploratory and Development Well Completions,a 1970-1999

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 303 579 1,816 2,698 7,064 12,106 4,913 24,083

1999 151 583 1,389 2,123 4,087 10,513 3,580 18,180

aExcludes service wells and stratigraphic and core testing.

bAll drilling counts for the years 1973-1998 have been revised.

Notes: Estimates are based on well completions taken from American Petroleum Institute data tapes through August 2000. 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 1973-1999: Monthly Energy Review August

2000, DOE/EIA-0035(00/08).
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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 99

Wells

0

5

10

15

20

25

30

35

77 79 81 83 85 87 89 91 93 95 97 99

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 99

Wells

0

1

2

3

4

5

6

77 79 81 83 85 87 89 91 93 95 97 99

Million Barrels per Well

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

1977-1999

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

Exploratory Gas Well Completion, 1977-1999

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

1977-1999

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

Exploratory Oil Well Completion, 1977-1999
both in terms of throughput and miles of pipeline. El

Paso Energy’s pipeline systems will transport 12.4

billion cubic feet of natural gas—fully one quarter of

the natural gas volumes transported in the United

States each day. El Paso Energy has agreed to divest its

100-percent ownership in East Tennessee Natural Gas

Company, Sonat’s 100-percent ownership of Sea Robin

Pipeline Company, and Sonat’s one-third interest in

Destin Pipeline Company, L.L.C. following the merger.

{27}

Reserve-to-Production Ratio

and Ultimate Recovery

R/P Ratios

The relationship between proved reserves and

production levels, expressed as the ratio of reserves to

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

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

reasonably stable, so that the proved reserves at the end

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

that can be maintained during the following year.

Operators report data which yield R/P ratios that vary

widely by area depending upon:

 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.

In 1999, U.S. crude oil proved reserves increased, while

oil production decreased—resulting in an upward shift

in the National average R/P ratio (11.1).

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 1999 National average of 11.1-to-1.

Other areas with relatively high R/P ratios are the

Permian Basin of Texas and New Mexico, and

California, where enhanced oil recovery techniques

such as carbon dioxide (CO2) injection or

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 1999, as reserves increased 2 percent

Nationally while production had a slight increase.

Different marketing, transportation, and production

characteristics for gas are seen when looking at

regional average R/P ratios, compared to the 1999 U.S.

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

higher range of R/P ratios are the less developed 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

6.9-to-1 in 1998 to 7.1-to-1 in 1999, and is below the

National 1999 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

Energy Information Administration

14 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 15

Sources: Annual reserves and production - American Petroleum Institute and American Gas Association (1945–1976){28} and Energy

Information Administration, Office of Oil and Gas (1977–1999){1-22}. Cumulative production: U.S. Oil and Gas Reserves by Year of Field

Discovery (1977-1988).{29}

0

5

10

15

20

25

30

35

45 50 55 60 65 70 75 80 85 90 95

R/P Ratio

United States

Lower 48 States

0

5

10

15

20

25

30

35

45 50 55 60 65 70 75 80 85 90 95

R/P Ratio

United States

Lower 48 States

0

50

100

150

200

250

77 79 81 83 85 87 89 91 93 95 97 99

Billions of Barrels

Cumulative Production

Proved Reserves

Ultimate Recovery

0

200

400

600

800

1,000

1,200

1,400

77 79 81 83 85 87 89 91 93 95 97 99

Trillions of Cubic Feet

Cumulative Production

Proved Reserves

Ultimate Recovery

Figure 11. Reserves-to-Production Ratios for

Crude Oil, 1945-1999

Figure 13. Components of Proved Ultimate Recovery for

Crude Oil and Lease Condensate, 1977-1999

Figure 12. Reserves-to-Production Ratios for

Wet Natural Gas, 1945-1999

Figure 14. Components of Proved Ultimate Recovery

for Wet Natural Gas, 1977-1999
Table 5. International Oil and Natural Gas Reserves as of December 31, 1999

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 . . . . . . . . d263,500 d261,425 1 Former U.S.S.R.. . . . . . . 1,979,330 1,935,731

2 Iraqc . . . . . . . . . . . . . . . 112,500 100,000 2 Iranc . . . . . . . . . . . . . . . . 812,300 789,990

3 Kuwaitc . . . . . . . . . . . . . d96,500 d94,725 3 Qatarc . . . . . . . . . . . . . . 300,000 394,000

4 Iranc . . . . . . . . . . . . . . . 89,700 93,100 4 Saudi Arabiac. . . . . . . . . d204,500 d208,000

5 United Arab Emiratesc . 96,200 63,460 5 United Arab Emiratesc . . 200,200 202,550

6 Former U.S.S.R. . . . . . . 57,252 63,016 6 United States . . . . . . . . e164,041 160,920

7 Venezuelac . . . . . . . . . . 72,600 47,058 7 Algeriac . . . . . . . . . . . . . 159,700 159,700

8 Libyac . . . . . . . . . . . . . . 29,500 29,500 8 Venezuelac. . . . . . . . . . . 142,500 145,763

9 China . . . . . . . . . . . . . . 24,000 34,100 9 Nigeriac . . . . . . . . . . . . . 124,000 126,000

10 Mexico . . . . . . . . . . . . . 28,399 28,259 10 Iraqc . . . . . . . . . . . . . . . . 109,800 112,600

Top 10 Total . . . . . . . . . . . . . . 870,151 814,643 Top 10 Total. . . . . . . . . . . . . . . 4,196,371 4,235,254

11 Nigeriac

. . . . . . . . . . . . . 22,500 24,500 11 Malaysia . . . . . . . . . . . . . 81,700 85,200

12 United States. . . . . . . . e21,034 19,625 12 Indonesiac . . . . . . . . . . . 72,268 80,832

13 Algeriac. . . . . . . . . . . . . 9,200 13,000 13 Canada. . . . . . . . . . . . . . 63,874 63,515

14 Norway . . . . . . . . . . . . . 10,787 10,026 14 Netherlands . . . . . . . . . . 62,542 59,763

15 Brazil. . . . . . . . . . . . . . . 7,357 8,150 15 Kuwaitc. . . . . . . . . . . . . . d52,700 d57,350

16 Angola . . . . . . . . . . . . . 5,412 8,475 16 Libyac . . . . . . . . . . . . . . . 46,400 46,400

17 Indonesiac . . . . . . . . . . 4,980 8,380 17 China . . . . . . . . . . . . . . . 48,300 41,300

18 Oman . . . . . . . . . . . . . . 5,283 5,700 18 Australia . . . . . . . . . . . . . 44,638 44,600

19 Canada . . . . . . . . . . . . . 4,931 5,578 19 Norway . . . . . . . . . . . . . . 41,389 42,854

20 United Kingdom . . . . . . 5,153 5,003 20 Egypt . . . . . . . . . . . . . . . 35,180 42,500

21 Qatarc . . . . . . . . . . . . . . 3,700 5,437 21 Mexico . . . . . . . . . . . . . . 30,064 30,393

22 Malaysia . . . . . . . . . . . . 3,900 4,557 22 Oman . . . . . . . . . . . . . . . 28,416 29,300

23 India . . . . . . . . . . . . . . . 4,838 3,390 23 United Kingdom . . . . . . . 26,663 26,828

24 Egypt . . . . . . . . . . . . . . 2,948 3,767 24 Argentina . . . . . . . . . . . . 24,247 24,300

25 Yemen. . . . . . . . . . . . . . 4,000 2,100 25 Pakistan . . . . . . . . . . . . . 21,600 22,900

Top 25 Total . . . . . . . . . . . . . . 986,174 942,331 Top 25 Total. . . . . . . . . . . . . . . 4,876,352 4,933,289

OPEC Total . . . . . . . . . . . . . . 800,880 740,585 OPEC Total . . . . . . . . . . . . . . . 2,224,368 2,323,185

World Total. . . . . . . . . . . . . . . 1,016,041 978,868 World Total . . . . . . . . . . . . . . . 5,146,207 5,197,863

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, 1998 were published by the Oil & Gas Journal as its estimates as

of December 31, 1999.

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 20, 1999, pp. 91-93. Gulf Publishing Company, World Oil,

August, 2000, pp. 31-35.

Energy Information Administration

16 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report
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

1999. 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 1999 was 61,356 million barrels. This

substantially exceeds the 1977 proved reserves, but at

the end of 1999 there were still 23,168 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 1999. The rest was from

proved reserves categories included in the proved

ultimate recovery appreciation process (new reservoir

discoveries in old fields, extensions, and revisions and

adjustments.) A significant part of the total proved

ultimate recovery appreciation came from the proved

ultimate recovery appreciation of those new fields

discovered between 1976 and 1999.

Similarly, the 1977 wet natural gas proved reserves

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

production from 1977 through 1999 was 410,846 billion

cubic feet. Cumulative wet gas production exceeded

the 1977 reserves, but at the end of 1999 there were still

176,159 billion cubic feet of wet natural gas proved

reserves, for the same reasons. Only 12 percent of

proved reserve additions of natural gas were booked as

new field discoveries from 1976 through 1999.

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 1999. 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 1999. 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 96 billion barrels. This is

about 50 percent higher than the World Oil estimate of

63 billion. One reason (among many) for these

differences is that condensate is often included in

foreign oil reserve estimates.

The Oil & Gas Journal{30} estimate for world oil reserves

decreased 2 percent in 1999, while the World Oil{31}

estimate increased 1 percent. For world gas reserves,

the Oil & Gas Journal reported no change, while World

Oil reported a 1 percent increase.

Several foreign countries have oil reserves

considerably larger than those of the United States.

Saudi Arabian oil reserves are the largest in the world,

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

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

almost triple and Mexico has around 30 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.{32} In 1999:

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 17
 The U.S. consumed 96,596,000,000,000,000 Btu of

energy (96.6 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 19.4

million barrels of oil and natural gas liquids

and 58.7 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 1999, crude oil imports made up

59 percent of the U.S. crude oil supply.

Net gas imports increased slightly in 1999 to 3.56

trillion cubic feet, which is approximately 17 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.

Canada, Saudi Arabia, Venezuela, and Mexico were

the primary foreign suppliers of petroleum to the

United States.{33}

List Of Appendices

Appendix A: Reserves by Operator Production Size

Class - How much of the National total of proved

reserves are owned and operated by the large oil and

gas corporations? Appendix A separates the large

operators from the small and presents reserves data

according to operator production size classes.

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

have the most reserves and production in the United

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

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

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

U.S. crude oil proved reserves. Table B3 in Appendix B

lists the top U.S. operators by reported 1999 production

and indicates pending mergers announced in 1999 with

linked arrows.

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 1992-1999, due

to expressed interest from the industry regarding this

area. Table D9 contains the production and proved

reserves for 1992-1999 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

maintenance.

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 1999 Annual Report
3. Crude Oil Statistics

The United States had 21,765 million barrels of crude

oil proved reserves as of December 31, 1999. This is 3.5

percent (731 million barrels) more than in 1998, and is

the largest percentage increase in oil reserves in the

23-year EIA reserves program.

Operators replaced 137 percent of 1999 oil production

with proved reserves additions (Figure 15). This was

not a result of increased drilling, more successful

exploratory drilling, or dramatically improved

technology. Crude oil prices began slowly increasing

from the inflation-adjusted 53-year low of December

1998 and then accelerated during the year, reaching

$22.55 per barrel in December 1999. Price was the most

significant factor in the largest positive net revisions to

proved reserves in over a decade.

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

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

per year. The decline was much more severe in 1998. In

1999, oil reserve levels appear to have recovered from

the 1998 decline.

Proved Reserves

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

as of December 31, 1999, by selected States and State

subdivisions.

Figure 16 maps 1999 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

Texas 25

Alaska 23

California 18

Gulf of Mexico Federal Offshore 13

Area Total 79

Of these four areas, Texas and California increased

their reserves in 1999, while Alaska and the Gulf of

Mexico 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 +412

Alaska -152

California +91

Gulf of Mexico Federal Offshore -49

Area Total +302

U.S. Total +731

Figure 2 in Chapter 2 shows the components of the

changes in crude oil proved reserves for 1999 and the

preceding 10 years.

Total Discoveries

Total discoveries are those new reserves attributable to

extensions of existing fields, new field discoveries, and new

reservoir discoveries in old fields. They result from the

drilling of exploratory wells.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 19

37%

62%

66%

78%

85%

125%

24%

137%

95%

0%

20%

40%

60%

80%

100%

120%

140%

160%

1991 1992 1993 1994 1995 1996 1997 1998 1999

Percentage of U.S. Crude Oil Production Replaced

Figure 15. Reserve Additions Replace 137

Percent of U.S. Oil Production in 1999

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

20 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

Table 6. Crude Oil Proved Reserves, Reserves Changes, and Production, 1999

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 1999

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 12/31/98 (+,-) (+) (--) (+) (+) (+) (-) 12/31/99

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 1999 contained in the Petroleum

Supply Annual 1999, DOE/EIA-0340(99).

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

Alaska. . . . . . . . . . . . . . . . . . . . . . . 5,052 1 2,351 2,201 6 79 0 388 4,900

Lower 48 States . . . . . . . . . . . . . . 15,982 138 3,933 2,264 253 242 145 1,564 16,865

Alabama . . . . . . . . . . . . . . . . . . . . . 39 -1 29 13 0 0 0 5 49

Arkansas . . . . . . . . . . . . . . . . . . . . 47 -7 23 10 0 0 0 5 48

California . . . . . . . . . . . . . . . . . . . . 3,843 72 575 337 60 0 0 279 3,934

Coastal Region Onshore . . . . . . 354 2 150 31 33 0 0 17 491

Los Angeles Basin Onshore . . . 207 40 98 42 13 0 0 19 297

San Joaquin Basin Onshore . . . 3,127 19 275 264 14 0 0 222 2,949

State Offshore . . . . . . . . . . . . . . 155 11 52 0 0 0 0 21 197

Colorado. . . . . . . . . . . . . . . . . . . . . 212 -9 25 9 0 0 0 16 203

Florida . . . . . . . . . . . . . . . . . . . . . . 71 1 18 0 0 0 0 5 85

Illinois . . . . . . . . . . . . . . . . . . . . . . . 81 5 24 1 0 0 0 9 100

Indiana . . . . . . . . . . . . . . . . . . . . . . 13 -4 3 1 0 0 0 1 10

Kansas . . . . . . . . . . . . . . . . . . . . . . 246 -97 60 17 4 0 2 23 175

Kentucky. . . . . . . . . . . . . . . . . . . . . 23 0 3 0 0 0 0 2 24b

Louisiana . . . . . . . . . . . . . . . . . . . . 551 10 184 90 20 2 10 87 600

North . . . . . . . . . . . . . . . . . . . . . 101 -6 33 15 12 0 0 17 108

South Onshore. . . . . . . . . . . . . . 353 3 126 63 8 2 8 53 384

State Offshore . . . . . . . . . . . . . . 97 13 25 12 0 0 2 17 108

Michigan. . . . . . . . . . . . . . . . . . . . . 44 3 26 14 0 0 0 7 52

Mississippi . . . . . . . . . . . . . . . . . . . 141 -16 62 12 2 0 1 15 163

Montana . . . . . . . . . . . . . . . . . . . . . 167 -5 136 94 15 0 0 12 207

Nebraska . . . . . . . . . . . . . . . . . . . . 18 -3 7 3 0 0 0 2 17

New Mexico . . . . . . . . . . . . . . . . . . 620 54 149 55 11 0 0 61 718

East . . . . . . . . . . . . . . . . . . . . . . 610 51 147 54 11 0 0 60 705

West. . . . . . . . . . . . . . . . . . . . . . 10 3 2 1 0 0 0 1 13

North Dakota . . . . . . . . . . . . . . . . . 245 21 55 31 3 0 0 31 262

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 40 -21 28 2 0 0 10 4b 51

Oklahoma. . . . . . . . . . . . . . . . . . . . 599 5 148 81 6 0 0 56 621

Pennsylvania . . . . . . . . . . . . . . . . . 15 0 3 2 1 0 0 1 16

Texas . . . . . . . . . . . . . . . . . . . . . . . 4,927 127 1,239 601 59 1 3 416 5,339

RRC District 1 . . . . . . . . . . . . . . 61 -17 31 1 0 0 0 8 66

RRC District 2 Onshore . . . . . . . 45 8 15 6 0 0 0 9 53

RRC District 3 Onshore . . . . . . . 211 15 62 44 10 0 0 33 221

RRC District 4 Onshore . . . . . . . 40 -1 14 7 2 0 0 6 42

RRC District 5 . . . . . . . . . . . . . . 40 -2 6 2 1 0 0 6 37

RRC District 6 . . . . . . . . . . . . . . 308 6 126 167 3 0 0 31 245

RRC District 7B . . . . . . . . . . . . . 115 20 9 7 0 0 0 14 123

RRC District 7C . . . . . . . . . . . . . 173 21 60 31 3 0 1 18 209

RRC District 8 . . . . . . . . . . . . . . 1,865 31 406 123 18 0 2 132 2,067

RRC District 8A . . . . . . . . . . . . . 1,895 22 444 159 21 1 0 135 2,089

RRC District 9 . . . . . . . . . . . . . . 111 16 52 41 1 0 0 16 123

RRC District 10 . . . . . . . . . . . . . 62 4 11 9 0 0 0 7 61

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

Utah . . . . . . . . . . . . . . . . . . . . . . . . 201 4 112 35 0 0 0 14 268

West Virginia . . . . . . . . . . . . . . . . . 17 5 2 2 0 0 0 1 21

Wyoming . . . . . . . . . . . . . . . . . . . . 547 -6 141 45 4 1 0 52 590

Federal Offshore . . . . . . . . . . . . . . 3,261 1 876 808 68 238 119 458 3,297

Pacific (California) . . . . . . . . . . . 468 -1 147 26 2 0 0 37 553

Gulf of Mexico (Louisiana) . . . . . 2,483 2 693 730 55 238 77 376 2,442

Gulf of Mexico (Texas). . . . . . . . 310 0 36 52 11 0 42 45 302

Miscellaneousa. . . . . . . . . . . . . . . . 14 -1 5 1 0 0 0 2 15

U.S. Total. . . . . . . . . . . . . . . . . . . . 21,034 139 6,284 4,465 259 321 145 1,952 21,765
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 21

Figure 17. Changes in Crude Oil Proved Reserves by Area, 1998 to 1999

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

Figure 16. 1999 Crude Oil Proved Reserves by Area

4,900

553

3,934

207 262

590

268 203

718

17

621

5,339

175

600

48

163

49

2,744 85

16

24

51

52

100 10

21

Crude Oil Proved Reserves

1999, Millions of Barrels

1000 to 5339 (4)

100 to 1000 (12)

1 to 100 (16)

0 to 0 (19)

Four Areas Contain

78 Percent of U.S.

Crude Oil Proved Reserves

U.S. TOTAL:

21.765 Billion Barrels

1

Changes in Crude Oil Proved Reserves by Area

1998 to 1999, Millions of Barrels

1 to 412 (22)

0 to 0 (22)

-100 to 0 (6)

-152 to -100 (1)

Crude Oil Proved Reserves Increase Significantly

In Major Oil Producing States, Except Alaska, Kansas, and the Gulf.

Total U.S. Increase: +731 Million Barrels.

412

-49

49

98

-152

91

85

1

67

-1

-71

-3

-1

-9

1

4 1

19

43

22

40 17

8

1 11

1

22

10

14
Total discoveries of crude oil were 725 million barrels in

1999, 21 percent more than those of 1998. Only five

areas had total discoveries exceeding 30 million barrels:

 The Gulf of Mexico Federal Offshore had 423

million barrels of total discoveries, 58 percent of

the National total.

 Alaska had 85 million barrels of total discoveries,

12 percent of the National total.

 Texas had 63 million barrels of total discoveries, 9

percent of the National total.

 California had 60 million barrels of total

discoveries, 8 percent of the National total.

 Louisiana had 32 million barrels of total

discoveries, 4 percent of the National total.

The United States discovered an average of 752 million

barrels of new crude oil proved reserves per year in the

prior 10 years (1989 through 1998). Total discoveries in

1999 were 4 percent less than that average.

Extensions

Operators reported 259 million barrels of extensions in

1999. The highest volume of extensions was reported in

the Gulf of Mexico Federal Offshore (66 million barrels

of extensions.) Operators in California reported 60

million barrels of extensions. Texas was third with 59

million barrels, followed by Louisiana with 20 million

barrels.

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

average of 433 million barrels of extensions per year.

The 1999 extensions were 40 percent less than that

average.

New Field Discoveries

There were 321 million barrels of new field discoveries

reported in 1998. Only five areas in the United States

reported any new field discoveries, and only two

contributed more than 1 percent to the total:

 Gulf of Mexico Federal Offshore (74 percent; 238

million barrels)

 Alaska (25 percent; 79 million barrels).

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

average of 184 million barrels of reserves from new field

discoveries per year. Reserves from new field discoveries

in 1999 were 74 percent more than that average

volume.

New Reservoir Discoveries in Old Fields

Operators in the United States reported 145 million

barrels of crude oil reserves from new reservoir

discoveries in old fields in 1999. 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—119 million barrels or 82

percent of the total. Louisiana and Ohio each had 10

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

U.S. operators reported an average of 135 million

barrels of reserves from new reservoir discoveries in old

fields per year. Reserves from new reservoir discoveries in

old fieldsin 1999 were 7 percent more than that average.

Revisions and Adjustments

Thousands of positive and negative revisions to proved

reserves occur each year as infill wells are drilled, well

performance is analyzed, new technology is applied, or

economic conditions change. Adjustments are the

annual changes in the published reserve estimates that

cannot be directly attributed to the estimates for other

reserve change categories because of the survey and

statistical estimation methods employed.

There were 1,958 million barrels of net revisions and

adjustments for crude oil in 1999. This is the largest

contribution in the 23-year history of the EIA reserves

program. Average revisions and adjustments for the

prior 10 years were 986 million barrels.

Production

U.S. production of crude oil in 1999 was 1,952 million

barrels. This was 2 percent lower than 1998’s

production of 1,991 million barrels. U.S. crude oil

production has declined eight years in a row. The Gulf of

Mexico Federal Offshore leapt from third place to the

largest producing area in the United States in 1999 with

22 percent of the National total of oil production. Texas

and Alaska are now second and third with 21 percent

and 20 percent of the total, respectively. California is

fourth with 14 percent.

In 1999, the Form EIA-23 National production

estimates were within two tenths of 1 percent of the

comparable Petroleum Supply Annual (PSA) 1999

volumes for crude oil and lease condensate production

combined (2,147 million barrels).

Energy Information Administration

22 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report
Areas of Note: Large Discoveries

and Reserves Additions

The following State and area discussions summarize

notable activities during 1999 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 1999.

Texas

Texas, the state with the largest proved reserves of

crude oil, also reported the largest increase in proved

reserves in 1999. Texas proved oil reserves increased by

412 million barrels in 1999. The largest increase

component was revisions and adjustments in the

Permian Basin area (Texas Subdivisions 8 and 8A).

These 2 state subdivisions accounted for 396 million

barrels of the crude oil proved reserves increase.

New Mexico

New Mexico had the second highest net increase in

crude oil proved reserves in 1999, an increase of 98

million barrels. Operators in New Mexico, as they did

in Texas, revised their crude oil proved reserves

upward in 1999. New Mexico had a 16 percent increase

in proved crude oil reserves, and a production increase

of 3 percent from 1998 (59 million barrels production)

to 1999.

Gulf of Mexico Federal Offshore

Despite the net loss of reserves in 1999, the Gulf of

Mexico still holds much promise for future

development and reserves additions, especially in

deep water. In 1999, this area had the most total

discoveries of crude oil proved reserves – 423 million

barrels of total discoveries, which is 58 percent of the

National total.

 The British (Petroleum) Invasion: BP Amoco

announced four major discoveries in the

deepwater Gulf in 1999. These include Crazy

Horse, Mad Dog, Atlantis, and Holstein. All four

of these fields are operated by BP Amoco. Crazy

Horse, the largest deepwater discovery to date,

is anticipated to have reserves of at least one

billion barrels of oil equivalent. It is owned 75%

by the BP Amoco group, and 25% by Exxon

Mobil. Mad Dog is 63.56% group-owned by BP

Amoco, with partners Unocal and BHP. Atlantis

is owned 56% by the BP Amoco group and 44%

by BHP, and Holstein is an equal partnership

between BP Amoco and Shell. The latter three

discoveries are anticipated to add another 600

million barrels of oil equivalent in net additional

reserves.{34}

 Brutus: Shell Exploration and Production

Company announced in April 1999 its plans to

develop Brutus using a tension leg platform to

be installed on Green Canyon Block 158 in 2,985

feet of water. Estimated ultimate gross recovery

from the development is greater than 200

million barrels of oil equivalent, with a 70:30

oil/gas ratio. The Brutus TLP facilities are

designed to accommodate 100,000 barrels of oil

and 300 million cubic feet of gas per day. The

TLP will be utilized as a hub for surrounding

developments.{35}

 Oregano: On April 22, 1999, Shell Exploration

and Production Company announced its third

oil and gas discovery in the deepwater Auger

basin of the Gulf of Mexico. The Oregano

prospect, located at Garden Banks Block 559 in a

water depth of 3,393 feet, was drilled to a

measured depth of 19,500 feet and encountered

commercial quantities of hydrocarbons.{36}

 Hoover and Diana: In 1999, Exxon Mobil

Corporation installed the largest deep draft

caisson vessel in the Gulf of Mexico to develop

the Hoover and Diana fields, located in the Gulf

of Mexico 320 kilometers (200 miles) from

Houston. These fields hold the equivalent of 400

million barrels of oil. ExxonMobil is also the

primary leaseholder on several good prospects

and discoveries nearby, such as the Marshall

and Madison fields, which will be tied into the

Hoover hub in 2002. Exxon Mobil set another

record while developing these fields – the

deepest water-depth for horizontal wells and

gravel packs: 760 meters (2,500 feet) of

horizontal section in 1,425 meters (4,700 feet) of

water, Diana field, Gulf of Mexico.{37}

California

California’s crude oil proved reserves increased 2

percent (91 million barrels) in 1999. Operators in

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 23
California revised their 1998 reserves upward, plus

added reserves through extensions.

Other Gain Areas

Pacific Federal Offshore: Proved oil reserves in the

Pacific Federal Offshore increased by 18 percent (85

million barrels) in 1999. The increase was from upward

revisions of reserves.

Utah: Utah’s proved oil reserves increased by 33

percent (67 million barrels) in 1999 compared to 1998.

The increase was from upward revisions of reserves.

Areas of Note:

Large Reserves Declines

The following areas had large declines in crude oil

proved reserves due to downward revisions or

unreplaced production.

Alaska

Alaska’s crude oil proved reserves declined 152 million

barrels in 1999, 39 percent more than the decline

reported in 1998 (109 million barrels). Alaska had the

second highest volume of new field discoveries (79

million barrels) of any area in 1999, but this did not

offset Alaska’s oil production—an estimated 388

million barrels in 1999. Alaska’s production declined

11 percent from its 1998 level (437 million barrels

production).

Kansas

Kansas’ crude oil proved reserves declined 29 percent

(71 million barrels) in 1999. Operators also reported a

production decline of 32 percent (11 million barrels)

from 1998 (34 million barrels production) to 1999.

Gulf of Mexico Federal Offshore

There was a net decline of 49 million barrels of crude oil

proved reserves in the Gulf of Mexico Federal Offshore

in 1999. It is expected that development and

exploration in the Gulf of Mexico Federal Offshore will

continue to add future reserves.

The Gulf of Mexico produced about 421 million barrels

of crude oil in 1999, an increase of 13 percent over

1998’s production (372 million barrels). However, there

were only 372 million barrels of total reserves additions

(which includes adjustments, net revisions, and total

discoveries) in this area, which replaced just 88 percent

of production from this area.

Other Decline Areas

In the following areas of the United States,

development of existing or new oil fields was outpaced

by crude oil production.

Colorado: Proved oil reserves decreased by

4 percent (9 million barrels).

Indiana: Proved oil reserves decreased by

23 percent (3 million barrels).

Reserves in

Nonproducing Reservoirs

Not all proved reserves of crude oil were contained in

reservoirs that were producing. Operators reported

4,206 million barrels of proved reserves in

nonproducing reservoirs, 1 percent more than reported

in 1998 (4,147 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

1999 volume, 2,865 million barrels, is about 9 percent

less than what was reported in 1998 (3,160 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

24 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 1999 Annual Report 25

Table 7. Reported Indicated Additional Crude Oil Reserves,a 1999

(Million Barrels of 42 U.S. Gallons)

Indicated Indicated

Additional Additional

State and Subdivision Reserves State and Subdivision Reserves

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 464

Lower 48 States. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,400

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

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

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,400

Coastal Region Onshore . . . . . . . . . . . . . . . . . . . 30

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

San Joaquin Basin Onshore. . . . . . . . . . . . . . . . . 1,330

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

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

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

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

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

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

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

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 278

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

South Onshore . . . . . . . . . . . . . . . . . . . . . . . . . . . 278

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

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

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

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

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

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 165

East. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 165

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

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

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

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

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

Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 426

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

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

RRC District 3 Onshore . . . . . . . . . . . . . . . . . . . . 25

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

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

RRC District 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

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

RRC District 7C . . . . . . . . . . . . . . . . . . . . . . . . . . 3

RRC District 8. . . . . . . . . . . . . . . . . . . . . . . . . . . . 279

RRC District 8A. . . . . . . . . . . . . . . . . . . . . . . . . . . 115

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

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

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

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42

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

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Federal Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

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

Gulf of Mexico (Louisiana) . . . . . . . . . . . . . . . . . . 5

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

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

U.S. Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,865

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,” 1999.
4. Natural Gas Statistics

Dry Natural Gas

Proved Reserves

As of December 31, 1999, U.S. operators had 167,406

billion cubic feet of dry natural gas proved reserves, 2

percent more than in 1998 (Table 8).

Additions to dry gas reserves in 1999 were 22,293

billion cubic feet, up 43 percent compared to 1998.

Operators replaced 118 percent of dry gas production

(Figure 18). U.S. total discoveries of dry natural gas

reserves were 10,807 billion cubic feet in 1998, down 5

percent from 1998 (11,433 billion cubic feet).

Proved reserves by State are shown on the map in

Figure 19. Seven areas account for 75 percent of the

Nation’s dry natural gas proved reserves:

Percent of

Area U.S. Gas Reserves

Texas 24

Gulf of Mexico Federal Offshore 15

New Mexico 9

Wyoming 8

Oklahoma 7

Alaska 6

Louisiana 6

Area Total 75

Of these seven areas, Texas, New Mexico, Wyoming,

and Louisiana had increased reserves in 1999, while

Alaska, the Gulf of Mexico Federal Offshore, and

Oklahoma had decreases in dry natural gas proved

reserves.

Discussion of Reserves Changes

Figure 20 maps the change in dry gas proved reserves

from 1998 to 1999 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 +2,573

Gulf of Mexico Federal Offshore -971

New Mexico +462

Wyoming +576

Oklahoma -1,102

Alaska -193

Louisiana +95

Area Total +1,440

U.S. Total +3,365

Figure 4 in Chapter 2 shows the components of the

changes in dry natural gas proved reserves for 1999

and the preceding 10 years.

Revisions and Adjustments

Net revisions and adjustments increased to 11,486 billion

cubic feet in 1999, almost triple 1998’s level (4,105

billion cubic feet). Texas had the largest increase in net

revisions and adjustments (4,456 billion cubic feet). New

Mexico had the second largest with 1,412 billion cubic

feet of net revisions and adjustments.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 27

Figure 18. Reserve Additions Replace 118% of

1999 U.S. Dry Natural Gas Production.

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

87% 88% 85%

108% 107% 107%

104%

83%

118%

0%

20%

40%

60%

80%

100%

120%

140%

1991 1992 1993 1994 1995 1996 1997 1998 1999

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

28 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

Table 8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 1999

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

Changes in Reserves During 1999

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 12/31/98 (+,-) (+) (-) (+) (+) (+) (-) 12/31/99

Alaska. . . . . . . . . . . . . . . . . . . . . . . 9,927 133 3,577 3,525 2 56 23 459 9,734

Lower 48 States . . . . . . . . . . . . . . 154,114 849 38,590 28,138 7,041 1,512 2,173 18,469 157,672

Alabama . . . . . . . . . . . . . . . . . . . . . 4,604 -17 215 140 1 0 0 376 4,287

Arkansas . . . . . . . . . . . . . . . . . . . . 1,328 -48 761 376 27 1 12 163 1,542

California . . . . . . . . . . . . . . . . . . . . 2,244 111 553 316 58 0 3 266 2,387

Coastal Region Onshore . . . . . . 106 -11 69 10 46 0 0 8 192

Los Angeles Basin Onshore . . . 149 -1 40 15 4 0 0 9 168

San Joaquin Basin Onshore . . . 1,945 125 398 291 8 0 3 237 1,951

State Offshore . . . . . . . . . . . . . . 44 -2 46 0 0 0 0 12 76

Colorado. . . . . . . . . . . . . . . . . . . . . 7,881 82 2,788 1,607 430 123 9 719 8,987

Florida . . . . . . . . . . . . . . . . . . . . . . 88 1 0 0 0 0 0 5 84

Kansas . . . . . . . . . . . . . . . . . . . . . . 6,402 -152 437 479 24 6 1 486 5,753

Kentucky. . . . . . . . . . . . . . . . . . . . . 1,222 34 230 41 30 0 19 59 1,435

Louisiana . . . . . . . . . . . . . . . . . . . . 9,147 509 2,571 2,297 316 44 373 1,421 9,242

North . . . . . . . . . . . . . . . . . . . . . 2,898 222 1,024 842 149 0 5 377 3,079

South Onshore. . . . . . . . . . . . . . 5,698 104 1,412 1,238 144 23 319 927 5,535

State Offshore . . . . . . . . . . . . . . 551 183 135 217 23 21 49 117 628

Michigan. . . . . . . . . . . . . . . . . . . . . 2,328 12 624 478 2 0 1 234 2,255

Mississippi . . . . . . . . . . . . . . . . . . . 658 34 165 120 11 0 8 79 677

Montana . . . . . . . . . . . . . . . . . . . . . 782 42 98 55 15 0 0 41 841

New Mexico . . . . . . . . . . . . . . . . . . 14,987 394 1,882 864 560 2 27 1,539 15,449

East . . . . . . . . . . . . . . . . . . . . . . 2,693 187 938 411 113 2 6 491 3,037

West. . . . . . . . . . . . . . . . . . . . . . 12,294 207 944 453 447 0 21 1,048 12,412

New York . . . . . . . . . . . . . . . . . . . . 218 -78 89 44 0 42 10 16 221

North Dakota . . . . . . . . . . . . . . . . . 447 -13 50 31 1 0 1 39 416

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 890 -75 401 113 8 0 162 94 1,179

Oklahoma. . . . . . . . . . . . . . . . . . . . 13,645 -1,233 3,029 2,251 624 0 37 1,308 12,543

Pennsylvania . . . . . . . . . . . . . . . . . 1,840 -9 642 595 23 0 1 130 1,772

Texas . . . . . . . . . . . . . . . . . . . . . . . 37,584 1,379 11,392 8,315 2,690 92 232 4,897 40,157

RRC District 1 . . . . . . . . . . . . . . 1,104 -163 287 137 19 1 4 107 1,008

RRC District 2 Onshore . . . . . . . 1,614 203 556 339 108 20 25 306 1,881

RRC District 3 Onshore . . . . . . . 3,961 220 932 890 429 39 35 813 3,913

RRC District 4 Onshore . . . . . . . 8,429 94 3,442 2,777 803 10 150 1,236 8,915

RRC District 5 . . . . . . . . . . . . . . 1,953 52 334 203 398 3 1 219 2,319

RRC District 6 . . . . . . . . . . . . . . 5,949 163 1,557 1,581 353 5 2 591 5,857

RRC District 7B . . . . . . . . . . . . . 442 55 153 171 0 0 1 64 416

RRC District 7C . . . . . . . . . . . . . 3,113 192 659 542 64 11 8 327 3,178

RRC District 8 . . . . . . . . . . . . . . 4,857 145 1,281 514 218 2 4 559 5,434

RRC District 8A . . . . . . . . . . . . . 807 121 479 96 45 1 0 100 1,257

RRC District 9 . . . . . . . . . . . . . . 734 -16 584 64 3 0 0 104 1,137

RRC District 10 . . . . . . . . . . . . . 4,273 279 958 888 208 0 2 408 4,424

State Offshore . . . . . . . . . . . . . . 348 34 170 113 42 0 0 63 418

Utah . . . . . . . . . . . . . . . . . . . . . . . . 2,388 -56 801 322 618 4 0 220 3,213

Virginia . . . . . . . . . . . . . . . . . . . . . . 1,973 -12 198 81 2 0 3 66 2,017

West Virginia . . . . . . . . . . . . . . . . . 2,868 28 360 260 60 0 53 173 2,936

Wyoming . . . . . . . . . . . . . . . . . . . . 13,650 171 3,857 2,910 603 18 50 1,213 14,226

Federal Offshorea . . . . . . . . . . . . . 26,902 -283 7,406 6,405 938 1,180 1,171 4,922 25,987

Pacific (California) . . . . . . . . . . . 480 9 107 23 0 0 0 37 536

Gulf of Mexico (Louisiana)a . . . . 20,774 -202 5,752 5,480 493 1,077 905 3,721 19,598

Gulf of Mexico (Texas). . . . . . . . 5,648 -90 1,547 902 445 103 266 1,164 5,853

Miscellaneousb. . . . . . . . . . . . . . . . 38 28 41 38 0 0 0 3c 66

U.S. Total. . . . . . . . . . . . . . . . . . . . 164,041 982 42,167 31,663 7,043 1,568 2,196 18,928 167,406

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 1999 contained in the Natural Gas Annual 1999, DOE/EIA-0131(99).
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 29

9,734

2,387

3,213

536

5,753

14,226

15,449

40,157

8,987

841 416

12,543

677

25,451

9,242

1,542

84

2,235

1,435

4,287

1,179

2,936

2,017

1,772

221

Dry Gas Proved Reserves

1999, Billions of Cubic Feet

10,000 to 40,200 (5)

1,000 to 10,000 (14)

1 to 1,000 (12)

0 to 0 (20)

Five Areas Contain

64 Percent of U.S.

Dry Natural Gas Proved Reserves

U.S. TOTAL:

167.406 Trillion Cubic Feet

Figure 20. Changes in Dry Natural Gas Proved Reserves by Area, 1998 to 1999

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

Figure 19. 1999 Dry Natural Gas Proved Reserves by Area

Changes in Dry Natural Gas Reserves by Area

1998 to 1999, Billions of Cubic Feet

100 to 2573 (9)

1 to 100 (10)

0 to 0 (20)

-100 to 0 (7)

-1102 to -100 (5)

Dry Gas Reserves Increase Significantly in

Texas, Colorado, Utah, and other areas.

Large declines noted in Oklahoma and the Gulf of Mexico.

Total U.S. Increase: +3,365 Billion Cubic Feet.

-193

462

2,573

-971

214

-317

-649

213

825 1,106

-1,102

576

143

289

59

1

1

3

68

44

56

95

19

32

-31

-3

-1

-4

-68 -2

-73
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 10,807 billion cubic feet in 1999, a 5

percent decrease from the level reported in 1998 and

equivalent to 57 percent of 1999 dry gas production.

About 30 percent of the total discoveries were in the Gulf

of Mexico Federal Offshore, and 28 percent were in

Texas.

Extensions were 7,043 billion cubic feet, 14 percent

lower than in 1998. Areas with the largest extensions

and their percentage of total extensions were:

 Texas (38 percent)

 Gulf of Mexico Federal Offshore (13 percent)

 Oklahoma (9 percent)

 Utah (9 percent)

 Wyoming (9 percent)

 New Mexico (8 percent).

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

average of 7,048 billion cubic feet of dry gas reserves

from extensions per year. Reserves from extensions in

1999 were almost an exact match of this average

volume.

New field discoveries were 1,568 billion cubic feet in

1999—46 percent more than in 1998. Those areas with

the largest new field discoveries were the Gulf of Mexico

Federal Offshore (with 75 percent of the total),

Colorado (8 percent), and Texas (6 percent). In the prior

10 years, U.S. operators reported an average of 1,462

billion cubic feet of reserves from new field discoveries

per year. Reserves from new field discoveries in 1999

were 7 percent higher than that average.

New reservoir discoveries in old fields were 2,196 billion

cubic feet, 2 percent higher than 1998. Among the areas

with the largest new reservoir discoveries in old fields and

their percentage of the total were:

 Gulf of Mexico Federal Offshore (53 percent)

 Louisiana (17 percent)

 Texas (11 percent).

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

average of 2,344 billion cubic feet of reserves from new

reservoirs discovered in old fields per year. Reserves from

new reservoirs discovered in old fields in 1999 were 6

percent lower than that average volume.

Production

The estimated 1999 U.S. dry natural gas production

was 18,928 billion cubic feet, an increase of 1 percent

from 1998 (Table 8). As in 1998, the Gulf of Mexico

Federal Offshore and the State of Texas were the

leading producers of dry natural gas in 1999, each with

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

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

percent), and Oklahoma (7 percent) added almost

another one-fourth of the 1999 dry gas production.

Wet Natural Gas

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

31, 1999 were 176,159 billion cubic feet, a 2 percent

increase from the volume reported in 1998 (Table 9). At

year-end 1999, proved wet natural gas reserves for the

lower 48 States had increased by 2 percent compared to

1998, while those of Alaska had decreased by 2 percent.

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 increased by

2 percent (2,961 billion cubic feet) in 1999 to 144,744

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

wet natural gas proved reserves increased 2 percent to

a level of 142,098 billion cubic feet, while Alaska

declined 4 percent to a level of 2,646 billion cubic feet of

NA wet natural gas proved reserves in 1999. Those

States with the largest increases in NA wet natural gas

reserves were Texas, Colorado, Utah, Wyoming, and

New Mexico. There were large decreases in NA wet

natural gas reserves in Oklahoma, Kansas, and the Gulf

of Mexico Federal Offshore.

Discoveries

NA wet natural gas total discoveries of 9,884 billion cubic

feet in 1999 decreased 10 percent (1,050 billion cubic

Energy Information Administration

30 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 31

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

1999 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 1999 Proved Reserves 12/31/99

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Non- Associated

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

State and Subdivision 12/31/98 (+,–) (+) (–) (+) (+) (+) (–) Total Gas Gas Gas

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

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

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

Information Administration production data for natural gas for 1999 contained in the Natural Gas Annual 1999, DOE/EIA-0131(99).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 10,043 144 3,627 3,575 2 56 23 465 9,855 2,646 7,209

Lower 48 States . . . . . . . . . . . . . 162,400 958 40,606 29,476 7,399 1,566 2,242 19,391 166,304 142,098 24,206

Alabama. . . . . . . . . . . . . . . . . . . . 4,643 31 219 142 1 0 0 387 4,365 4,338 27

Arkansas . . . . . . . . . . . . . . . . . . . 1,332 -48 763 377 27 1 12 164 1,546 1,505 41

California . . . . . . . . . . . . . . . . . . . 2,332 125 583 329 68 0 3 277 2,505 355 2,150

Coastal Region Onshore . . . . 118 -3 84 12 56 0 0 10 233 0 233

Los Angeles Basin Onshore . 154 0 41 16 4 0 0 9 174 0 174

San Joaquin Basin Onshore . 2,016 129 412 301 8 0 3 246 2,021 336 1,685

State Offshore . . . . . . . . . . . . 44 -1 46 0 0 0 0 12 77 19 58

Colorado . . . . . . . . . . . . . . . . . . . 8,208 105 2,875 1,660 443 135 10 744 9,372 8,591 781

Florida . . . . . . . . . . . . . . . . . . . . . 106 0 0 0 0 0 0 6 100 0 100

Kansas. . . . . . . . . . . . . . . . . . . . . 6,862 -73 475 521 26 6 1 528 6,248 6,196 52

Kentucky . . . . . . . . . . . . . . . . . . . 1,295 44 245 43 31 0 20 62 1,530 1,501 29

Louisiana . . . . . . . . . . . . . . . . . . . 9,480 597 2,678 2,393 329 47 394 1,486 9,646 8,667 979

North . . . . . . . . . . . . . . . . . . . 2,943 224 1,041 855 152 0 5 383 3,127 2,867 260

South Onshore. . . . . . . . . . . . 5,966 173 1,495 1,310 152 25 337 980 5,858 5,259 599

State Offshore . . . . . . . . . . . . 571 200 142 228 25 22 52 123 661 541 120

Michigan . . . . . . . . . . . . . . . . . . . 2,386 16 639 491 2 0 1 240 2,313 2,086 227

Mississippi . . . . . . . . . . . . . . . . . . 662 34 166 120 11 0 8 80 681 650 31

Montana. . . . . . . . . . . . . . . . . . . . 789 46 98 56 15 0 0 41 851 784 67

New Mexico . . . . . . . . . . . . . . . . . 16,259 392 2,044 942 611 2 30 1,646 16,750 15,172 1,578

East . . . . . . . . . . . . . . . . . . . . 3,039 153 1,040 456 125 2 7 544 3,366 1,880 1,486

West. . . . . . . . . . . . . . . . . . . . 13,220 239 1,004 486 486 0 23 1,102 13,384 13,292 92

New York . . . . . . . . . . . . . . . . . . . 218 -78 89 44 0 42 10 16 221 212 9

North Dakota . . . . . . . . . . . . . . . . 501 -4 57 36 1 0 1 45 475 225 250

Ohio . . . . . . . . . . . . . . . . . . . . . . . 890 -75 401 113 8 0 162 94 1,179 777 402

Oklahoma . . . . . . . . . . . . . . . . . . 14,517 -1,169 3,258 2,422 672 0 39 1,405 13,490 12,252 1,238

Pennsylvania . . . . . . . . . . . . . . . . 1,848 -9 645 598 23 0 1 130 1,780 1,684 96

Texas . . . . . . . . . . . . . . . . . . . . . . 40,793 1,165 12,327 8,858 2,841 97 245 5,260 43,350 35,470 7,880

RRC District 1 . . . . . . . . . . . . 1,152 -2 351 167 23 1 5 131 1,232 1,165 67

RRC District 2 Onshore . . . . . 1,720 188 583 355 113 20 26 321 1,974 1,772 202

RRC District 3 Onshore . . . . . 4,205 210 984 940 453 40 38 858 4,132 3,218 914

RRC District 4 Onshore . . . . . 8,824 115 3,611 2,912 842 11 157 1,297 9,351 9,169 182

RRC District 5 . . . . . . . . . . . . 1,995 35 339 205 404 3 1 222 2,350 2,301 49

RRC District 6 . . . . . . . . . . . . 6,271 102 1,623 1,648 368 5 2 616 6,107 5,562 545

RRC District 7B . . . . . . . . . . . 510 44 170 190 0 0 1 70 465 275 190

RRC District 7C . . . . . . . . . . . 3,496 241 746 613 72 13 9 371 3,593 2,977 616

RRC District 8 . . . . . . . . . . . . 5,547 89 1,443 579 245 3 4 630 6,122 2,947 3,175

RRC District 8A . . . . . . . . . . . 1,115 35 592 118 56 1 0 124 1,557 44 1,513

RRC District 9 . . . . . . . . . . . . 864 -5 699 76 3 0 0 125 1,360 1,180 180

RRC District 10 . . . . . . . . . . . 4,744 81 1,015 942 220 0 2 432 4,688 4,447 241

State Offshore . . . . . . . . . . . . 350 32 171 113 42 0 0 63 419 413 6

Utah . . . . . . . . . . . . . . . . . . . . . . . 2,502 -52 838 343 653 5 0 232 3,371 3,050 321

Virginia. . . . . . . . . . . . . . . . . . . . . 1,973 -12 198 81 2 0 3 66 2,017 2,017 0

West Virginia . . . . . . . . . . . . . . . . 2,968 32 372 270 62 0 55 179 3,040 2,952 88

Wyoming . . . . . . . . . . . . . . . . . . . 14,371 26 4,014 3,027 618 19 51 1,263 14,809 14,096 713

Federal Offshorea . . . . . . . . . . . . 27,426 -163 7,581 6,572 955 1,212 1,196 5,037 26,598 19,505 7,093

Pacific (California) . . . . . . . . . 489 0 107 23 0 0 0 37 536 48 488

Gulf of Mexico (Louisiana)a . . 21,261 -79 5,917 5,642 507 1,108 929 3,829 20,172 14,950 5,222

Gulf of Mexico (Texas). . . . . . 5,676 -84 1,557 907 448 104 267 1,171 5,890 4,507 1,383

Miscellaneousb . . . . . . . . . . . . . . 39 28 41 38 0 0 0 3c 67 13 54

U.S. Total . . . . . . . . . . . . . . . . . . 172,443 1,102 44,233 33,051 7,401 1,622 2,265 19,856 176,159 144,744 31,415
Energy Information Administration

32 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

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

Lease Separation, 1999

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

Changes in Reserves During 1999

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 12/31/98 (+,-) (+) (-) (+) (+) (+) (-) 12/31/99

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 1999 contained in the

Natural Gas Annual 1999, DOE/EIA-0131(99).

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

Alaska. . . . . . . . . . . . . . . . . . . . . . . 2,768 -1 50 45 0 53 23 202 2,646

Lower 48 States . . . . . . . . . . . . . . 139,015 960 32,957 24,301 6,815 1,175 1,818 16,341 142,098

Alabama . . . . . . . . . . . . . . . . . . . . . 4,615 31 210 139 1 0 0 380 4,338

Arkansas . . . . . . . . . . . . . . . . . . . . 1,294 -47 734 357 27 1 12 159 1,505

California . . . . . . . . . . . . . . . . . . . . 453 27 92 176 3 0 3 47 355

Coastal Region Onshore . . . . . . 2 0 0 2 0 0 0 0 0

Los Angeles Basin Onshore . . . 1 -1 0 0 0 0 0 0 0

San Joaquin Basin Onshore . . . 445 28 72 174 3 0 3 41 336

State Offshore . . . . . . . . . . . . . . 5 0 20 0 0 0 0 6 19

Colorado. . . . . . . . . . . . . . . . . . . . . 7,436 92 2,727 1,565 443 135 10 687 8,591

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

Kansas . . . . . . . . . . . . . . . . . . . . . . 6,802 -66 453 503 24 6 0 520 6,196

Kentucky. . . . . . . . . . . . . . . . . . . . . 1,275 43 231 39 31 0 20 60 1,501

Louisiana . . . . . . . . . . . . . . . . . . . . 8,569 556 2,298 2,108 264 46 365 1,323 8,667

North . . . . . . . . . . . . . . . . . . . . . 2,760 184 930 793 109 0 5 328 2,867

South Onshore. . . . . . . . . . . . . . 5,336 191 1,271 1,108 130 24 309 894 5,259

State Offshore . . . . . . . . . . . . . . 473 181 97 207 25 22 51 101 541

Michigan. . . . . . . . . . . . . . . . . . . . . 2,158 44 532 441 1 0 0 208 2,086

Mississippi . . . . . . . . . . . . . . . . . . . 615 40 156 106 11 0 8 74 650

Montana . . . . . . . . . . . . . . . . . . . . . 737 42 56 28 12 0 0 35 784

New Mexico . . . . . . . . . . . . . . . . . . 14,816 357 1,544 734 580 2 28 1,421 15,172

East . . . . . . . . . . . . . . . . . . . . . . 1,694 104 558 251 94 2 6 327 1,880

West. . . . . . . . . . . . . . . . . . . . . . 13,122 253 986 483 486 0 22 1,094 13,292

New York . . . . . . . . . . . . . . . . . . . . 217 -84 86 44 0 42 10 15 212

North Dakota . . . . . . . . . . . . . . . . . 240 -3 7 6 0 0 1 14 225

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 548 -36 343 88 8 0 54 52 777

Oklahoma. . . . . . . . . . . . . . . . . . . . 13,321 -1,064 2,703 2,103 634 0 39 1,278 12,252

Pennsylvania . . . . . . . . . . . . . . . . . 1,769 -5 616 589 15 0 0 122 1,684

Texas . . . . . . . . . . . . . . . . . . . . . . . 33,429 1,179 9,927 7,525 2,582 81 235 4,438 35,470

RRC District 1 . . . . . . . . . . . . . . 1,101 0 318 159 23 1 5 124 1,165

RRC District 2 Onshore . . . . . . . 1,516 181 561 337 113 12 26 300 1,772

RRC District 3 Onshore . . . . . . . 3,275 185 679 684 321 34 35 627 3,218

RRC District 4 Onshore . . . . . . . 8,430 129 3,555 2,673 838 11 156 1,277 9,169

RRC District 5 . . . . . . . . . . . . . . 1,906 34 336 172 404 2 1 210 2,301

RRC District 6 . . . . . . . . . . . . . . 5,691 126 1,338 1,374 360 5 2 586 5,562

RRC District 7B . . . . . . . . . . . . . 306 35 154 165 0 0 0 55 275

RRC District 7C . . . . . . . . . . . . . 2,939 243 563 542 60 13 7 306 2,977

RRC District 8 . . . . . . . . . . . . . . 2,727 103 632 344 200 3 1 375 2,947

RRC District 8A . . . . . . . . . . . . . 18 35 8 9 0 0 0 8 44

RRC District 9 . . . . . . . . . . . . . . 665 0 676 63 3 0 0 101 1,180

RRC District 10 . . . . . . . . . . . . . 4,510 76 946 895 218 0 2 410 4,447

State Offshore . . . . . . . . . . . . . . 345 32 161 108 42 0 0 59 413

Utah . . . . . . . . . . . . . . . . . . . . . . . . 2,293 -52 623 264 653 5 0 208 3,050

Virginia . . . . . . . . . . . . . . . . . . . . . . 1,973 -12 198 81 2 0 3 66 2,017

West Virginia . . . . . . . . . . . . . . . . . 2,925 32 311 259 61 0 55 173 2,952

Wyoming . . . . . . . . . . . . . . . . . . . . 13,577 27 3,883 2,879 598 19 44 1,173 14,096

Federal Offshorea . . . . . . . . . . . . . 19,931 -164 5,227 4,236 865 838 931 3,887 19,505

Pacific (California) . . . . . . . . . . . 52 0 0 4 0 0 0 0 48

Gulf of Mexico (Louisiana)a . . . . 15,427 -80 4,054 3,434 443 734 729 2,923 14,950

Gulf of Mexico (Texas). . . . . . . . 4,452 -84 1,173 798 422 104 202 964 4,507

Miscellaneousb. . . . . . . . . . . . . . . . 22 23 0 31 0 0 0 1 13

U.S. Total. . . . . . . . . . . . . . . . . . . . 141,783 959 33,007 24,346 6,815 1,228 1,841 16,543 144,744
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 33

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

Wet After Lease Separation, 1999

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

Changes in Reserves During 1999

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 12/31/98 (+,-) (+) (-) (+) (+) (+) (-) 12/31/99

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 1999 contained in the

Natural Gas Annual 1999, DOE/EIA-0131(99).

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

Alaska. . . . . . . . . . . . . . . . . . . . . . . 7,275 145 3,577 3,530 2 3 0 263 7,209

Lower 48 States . . . . . . . . . . . . . . 23,385 -2 7,649 5,175 584 391 424 3,050 24,206

Alabama . . . . . . . . . . . . . . . . . . . . . 28 0 9 3 0 0 0 7 27

Arkansas . . . . . . . . . . . . . . . . . . . . 38 -1 29 20 0 0 0 5 41

California . . . . . . . . . . . . . . . . . . . . 1,879 98 491 153 65 0 0 230 2,150

Coastal Region Onshore . . . . . . 116 -3 84 10 56 0 0 10 233

Los Angeles Basin Onshore . . . 153 1 41 16 4 0 0 9 174

San Joaquin Basin Onshore . . . 1,571 101 340 127 5 0 0 205 1,685

State Offshore . . . . . . . . . . . . . . 39 -1 26 0 0 0 0 6 58

Colorado. . . . . . . . . . . . . . . . . . . . . 772 13 148 95 0 0 0 57 781

Florida . . . . . . . . . . . . . . . . . . . . . . 106 0 0 0 0 0 0 6 100

Kansas . . . . . . . . . . . . . . . . . . . . . . 60 -7 22 18 2 0 1 8 52

Kentucky. . . . . . . . . . . . . . . . . . . . . 20 1 14 4 0 0 0 2 29

Louisiana . . . . . . . . . . . . . . . . . . . . 911 41 380 285 65 1 29 163 979

North . . . . . . . . . . . . . . . . . . . . . 183 40 111 62 43 0 0 55 260

South Onshore. . . . . . . . . . . . . . 630 -18 224 202 22 1 28 86 599

State Offshore . . . . . . . . . . . . . . 98 19 45 21 0 0 1 22 120

Michigan. . . . . . . . . . . . . . . . . . . . . 228 -28 107 50 1 0 1 32 227

Mississippi . . . . . . . . . . . . . . . . . . . 47 -6 10 14 0 0 0 6 31

Montana . . . . . . . . . . . . . . . . . . . . . 52 4 42 28 3 0 0 6 67

New Mexico . . . . . . . . . . . . . . . . . . 1,443 35 500 208 31 0 2 225 1,578

East . . . . . . . . . . . . . . . . . . . . . . 1,345 49 482 205 31 0 1 217 1,486

West. . . . . . . . . . . . . . . . . . . . . . 98 -14 18 3 0 0 1 8 92

New York . . . . . . . . . . . . . . . . . . . . 1 6 3 0 0 0 0 1 9

North Dakota . . . . . . . . . . . . . . . . . 261 -1 50 30 1 0 0 31 250

Ohio . . . . . . . . . . . . . . . . . . . . . . . . 342 -39 58 25 0 0 108 42 402

Oklahoma. . . . . . . . . . . . . . . . . . . . 1,196 -105 555 319 38 0 0 127 1,238

Pennsylvania . . . . . . . . . . . . . . . . . 79 -4 29 9 8 0 1 8 96

Texas . . . . . . . . . . . . . . . . . . . . . . . 7,364 -14 2,400 1,333 259 16 10 822 7,880

RRC District 1 . . . . . . . . . . . . . . 51 -2 33 8 0 0 0 7 67

RRC District 2 Onshore . . . . . . . 204 7 22 18 0 8 0 21 202

RRC District 3 Onshore . . . . . . . 930 25 305 256 132 6 3 231 914

RRC District 4 Onshore . . . . . . . 394 -14 56 239 4 0 1 20 182

RRC District 5 . . . . . . . . . . . . . . 89 1 3 33 0 1 0 12 49

RRC District 6 . . . . . . . . . . . . . . 580 -24 285 274 8 0 0 30 545

RRC District 7B . . . . . . . . . . . . . 204 9 16 25 0 0 1 15 190

RRC District 7C . . . . . . . . . . . . . 557 -2 183 71 12 0 2 65 616

RRC District 8 . . . . . . . . . . . . . . 2,820 -14 811 235 45 0 3 255 3,175

RRC District 8A . . . . . . . . . . . . . 1,097 0 584 109 56 1 0 116 1,513

RRC District 9 . . . . . . . . . . . . . . 199 -5 23 13 0 0 0 24 180

RRC District 10 . . . . . . . . . . . . . 234 5 69 47 2 0 0 22 241

State Offshore . . . . . . . . . . . . . . 5 0 10 5 0 0 0 4 6

Utah . . . . . . . . . . . . . . . . . . . . . . . . 209 0 215 79 0 0 0 24 321

Virginia . . . . . . . . . . . . . . . . . . . . . . 0 0 0 0 0 0 0 0 0

West Virginia . . . . . . . . . . . . . . . . . 43 0 61 11 1 0 0 6 88

Wyoming . . . . . . . . . . . . . . . . . . . . 794 -1 131 148 20 0 7 90 713

Federal Offshorea . . . . . . . . . . . . . 7,495 1 2,354 2,336 90 374 265 1,150 7,093

Pacific (California) . . . . . . . . . . . 437 0 107 19 0 0 0 37 488

Gulf of Mexico (Louisiana)a . . . . 5,834 1 1,863 2,208 64 374 200 906 5,222

Gulf of Mexico (Texas). . . . . . . . 1,224 0 384 109 26 0 65 207 1,383

Miscellaneousb. . . . . . . . . . . . . . . . 17 5 41 7 0 0 0 2 54

U.S. Total. . . . . . . . . . . . . . . . . . . . 30,660 143 11,226 8,705 586 394 424 3,313 31,415
feet) compared to 1998. Areas with the most total

discoveries in 1999 were Texas, the Gulf of Mexico

Federal Offshore, Louisiana, Oklahoma, and

Wyoming.

Production

U.S. production of NA wet natural gas increased by 57

billion cubic feet from 1998 to 1999 (Table 10). The five

leading producing areas were: Texas (27 percent), the

Gulf of Mexico Federal Offshore (23 percent), New

Mexico (9 percent), Louisiana (8 percent) and

Oklahoma (8 percent).

Associated-Dissolved Natural Gas

Proved Reserves

Proved reserves of associated-dissolved (AD) natural

gas, wet after lease separation, in the United States

increased 2 percent (755 billion cubic feet) to 31,415

billion cubic feet in 1999 (Table 11). Proved reserves of

AD wet natural gas in the lower 48 States increased by 4

percent (821 billion cubic feet) to 24,206 billion cubic

feet, and Alaska declined 1 percent to 7,209 billion

cubic feet in 1999. Those areas of the country with the

largest AD wet natural gas reserves and their

percentage of the total were:

 Texas (25 percent)

 Alaska (23 percent)

 Gulf of Mexico Federal Offshore (21 percent)

 California (7 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 6

percent in 1999 (Table 11), and production of AD wet

natural gas in the lower 48 States increased by 8 percent

(228 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 (34 percent)

 Texas (25 percent)

 Alaska (8 percent)

 California (7 percent)

 New Mexico (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 1999, reserves of coalbed methane increased 9

percent to 13,229 billion cubic feet from 1998’s level

(12,179 billion cubic feet), and now account for 8

percent of all 1999 dry natural gas reserves (Table 12).

EIA estimates that the 1999 proved gas reserves of

fields identified as having coalbed methane are now

more than triple the volume reported in 1989 (Figure

21). Three States (New Mexico, Colorado, and

Alabama) currently have the majority (75 percent) of

U.S. Coalbed methane proved reserves. Estimates of

proved coalbed methane reserves increased in

Colorado and Alabama, but decreased slightly in New

Mexico in 1999.

Production

Coalbed methane production grew by about 5 percent

in 1999 to 1,252 billion cubic feet—about 7 percent of

U.S. dry gas production.

Energy Information Administration

34 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

0

2

4

6

8

10

12

14

1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999

Trillion Cubic Feet

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

Figure 21. Coalbed Methane Proved Reserves

1989-1999
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.

Texas

The State of Texas had the largest increase in dry

natural gas proved reserves of any State in 1999. Texas’

dry natural gas reserves increased by 2,573 billion cubic

feet.

South Texas: As in 1998, 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 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 486 billion

cubic feet in 1999. 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 (26 percent of the State

total). RRC District 4’s dry gas production decreased 7

percent from 1998 to 1999.

West Texas: In 1999, operators in the Permian Basin in

west Texas (RRC District 8, 8A) reported an increase in

dry gas reserves of 1,027 billion cubic feet.

Colorado

Colorado had a net increase of 1,106 billion cubic feet of

dry natural gas proved reserves in 1999. Development

of coalbed methane fields in the San Juan Basin and

other existing conventional gas fields boosted the

reserves additions for this State.

Utah

Utah had a net increase of 825 billion cubic feet of dry

natural gas proved reserves in 1999. This was the result

of development of large existing coalbed methane

fields and gas fields within the Uinta Basin.

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.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 35

Table 12. U.S. Coalbed Methane Proved Reserves and Production, 1989-1999

(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

1989 537 23 1,117 12 2,022 56 0 0 3,676 91

1990 1,224 36 1,320 26 2,510 133 33 1 5,087 196

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

1999 1,060 108 4,826 432 4,080 582 3,263 130 13,229 1,252

aIncludes Oklahoma, Pennsylvania, Utah, Virginia, West Virginia, and Wyoming.

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

This State’s proved dry natural gas reserves decreased

by 8 percent (1,102 billion cubic feet) in 1999. Dry gas

production in Oklahoma declined by 15 percent (236

billion cubic feet) from 1998 to 1999.

Gulf of Mexico Federal Offshore

This area’s proved dry natural gas reserves decreased

by 4 percent (971 billion cubic feet) in 1999. Production

from this area in 1999 remained essentially the same as

in 1998 (a decline of only 13 billion cubic feet).

Kansas

This State’s proved dry natural gas reserves decreased

by 10 percent (649 billion cubic feet) in 1999. Production

in Kansas in 1999 decreased 11 percent (62 billion cubic

feet) from 1998.

Reserves in

Nonproducing Reservoirs

Nonproducing proved natural gas reserves (wet after

lease separation) of 36,873 billion cubic feet were

reported in 1999 (Appendix D, Table D10). This was 2

percent more gas than in 1998 (36,047 billion cubic feet).

About 30 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 1999 Annual Report
5. Natural Gas Liquids Statistics

Natural Gas Liquids

Proved Reserves

U.S. natural gas liquids proved reserves increased 5

percent to 7,906 million barrels in 1999 (Table 13).

Reserve additions replaced 143 percent of 1999 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 33

Gulf of Mexico Federal Offshore 13

New Mexico 12

Oklahoma 9

Utah-Wyoming 8

Louisiana 6

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 were 452

million barrels in 1999, a decrease of 16 percent from

1998. Areas with the largest total discoveries were:

 Texas (31 percent)

 Gulf of Mexico Federal Offshore (23 percent)

 Louisiana (9 percent)

 Oklahoma (9 percent)

 Utah and Wyoming (9 percent)

 New Mexico (9 percent).

New field discoveries in 1999 (51 million barrels) were 23

percent lower than in 1998. Areas with the largest new

field discoveries were the Gulf of Mexico Federal

Offshore (67 percent of 1999 new field discoveries) and

Colorado (16 percent).

New reservoir discoveries in old fields (88 million barrels)

were the same as they were in 1998. Areas with the

largest new reservoir discoveries in old fields were the Gulf

of Mexico Federal Offshore (49 percent of 1999 new

reservoir discoveries in old fields), Louisiana (25

percent), and Texas (14 percent).

Extensions were 313 million barrels, a decrease of 18

percent from 1998 to 1999. Areas with the largest

extensions were Texas (40 percent of 1999 extensions),

Oklahoma (13 percent), and New Mexico (12 percent).

Production

Natural gas liquids production was an estimated 896

million barrels in 1999. Alaska production decreased 13

percent to 21 million barrels in 1999, while lower 48

States production increased 5 percent to 848 million

barrels in 1999.

Six areas accounted for about 86 percent of the Nation’s

natural gas liquids production.

 Texas (33 percent)

 Gulf of Mexico Federal Offshore (19 percent)

 New Mexico (9 percent)

 Oklahoma (9 percent)

 Louisiana (9 percent)

 Utah-Wyoming (7 percent).

Natural Gas Plant Liquids

Proved Reserves

Natural gas plant liquids proved reserves increased 5

percent in 1999 to 6,503 million barrels (Table 14). Six

areas accounted for about 79 percent of the Nation’s

natural gas plant liquids proved reserves:

Percent of

Area U.S. Gas Plant Liquids

Texas 35

New Mexico 14

Oklahoma 10

Utah-Wyoming 8

Gulf of Mexico Federal Offshore 7

Kansas 5

Area Total 79

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 37
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 38

Table 13. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 1999

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 1999

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 12/31/98 (+,-) (+) (-) (+) (+) (+) (-) 12/31/99

Alaska. . . . . . . . . . . . . . . . . . . . . . . 320 0 0 0 0 0 0 21 299

Lower 48 States . . . . . . . . . . . . . . 7,204 102 1,902 1,285 304 50 86 848 7,515

Alabama . . . . . . . . . . . . . . . . . . . . . 81 31 9 2 0 0 0 12 107

Arkansas . . . . . . . . . . . . . . . . . . . . 5 -2 3 1 0 0 0 0 5

California . . . . . . . . . . . . . . . . . . . . 72 14 25 12 7 0 0 8 98

Coastal Region Onshore . . . . . . 9 7 11 2 7 0 0 1 31

Los Angeles Basin Onshore . . . 5 1 2 1 0 0 0 0 7

San Joaquin Basin Onshore . . . 58 6 12 9 0 0 0 7 60

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

Colorado. . . . . . . . . . . . . . . . . . . . . 260 18 71 43 10 8 1 22 303

Florida . . . . . . . . . . . . . . . . . . . . . . 18 -1 0 0 0 0 0 1 16

Kansas . . . . . . . . . . . . . . . . . . . . . . 334 55 28 30 1 0 0 30 358

Kentucky. . . . . . . . . . . . . . . . . . . . . 54 8 11 3 1 0 1 3 69

Louisiana . . . . . . . . . . . . . . . . . . . . 411 83 134 135 17 3 22 78 457

North . . . . . . . . . . . . . . . . . . . . . 57 5 24 21 5 0 0 9 61

South Onshore. . . . . . . . . . . . . . 325 53 103 87 11 2 20 63 364

State Offshore . . . . . . . . . . . . . . 29 25 7 27 1 1 2 6 32

Michigan. . . . . . . . . . . . . . . . . . . . . 51 -2 14 11 0 0 0 4 48

Mississippi . . . . . . . . . . . . . . . . . . . 8 -1 4 1 1 0 0 1 10

Montana . . . . . . . . . . . . . . . . . . . . . 5 3 1 1 0 0 0 0 8

New Mexico . . . . . . . . . . . . . . . . . . 929 -1 129 62 37 0 3 81 954

East . . . . . . . . . . . . . . . . . . . . . . 262 -26 85 35 10 0 0 41 255

West. . . . . . . . . . . . . . . . . . . . . . 667 25 44 27 27 0 3 40 699

North Dakota . . . . . . . . . . . . . . . . . 48 7 6 4 0 0 0 4 53

Oklahoma. . . . . . . . . . . . . . . . . . . . 698 44 186 142 40 0 2 79 749

Texas . . . . . . . . . . . . . . . . . . . . . . . 2,544 -137 794 464 126 4 12 295 2,584

RRC District 1 . . . . . . . . . . . . . . 38 120 46 23 3 0 1 18 167

RRC District 2 Onshore . . . . . . . 85 -13 24 15 5 1 1 12 76

RRC District 3 Onshore . . . . . . . 246 -5 53 49 22 2 2 45 226

RRC District 4 Onshore . . . . . . . 363 21 178 125 32 0 7 54 422

RRC District 5 . . . . . . . . . . . . . . 35 -9 8 3 4 0 0 3 32

RRC District 6 . . . . . . . . . . . . . . 276 -46 62 60 14 0 0 23 223

RRC District 7B . . . . . . . . . . . . . 51 -7 15 17 0 0 0 6 36

RRC District 7C . . . . . . . . . . . . . 282 37 63 54 7 1 1 32 305

RRC District 8 . . . . . . . . . . . . . . 491 -38 119 47 21 0 0 51 495

RRC District 8A . . . . . . . . . . . . . 226 -60 84 17 8 0 0 18 223

RRC District 9 . . . . . . . . . . . . . . 93 8 81 10 0 0 0 14 158

RRC District 10 . . . . . . . . . . . . . 354 -146 61 43 10 0 0 19 217

State Offshore . . . . . . . . . . . . . . 4 1 0 1 0 0 0 0 4

Utah and Wyoming. . . . . . . . . . . . . 675 -101 172 112 38 1 1 59 615

West Virginia . . . . . . . . . . . . . . . . . 72 0 9 6 1 0 1 4 73

Federal Offshorea . . . . . . . . . . . . . 931 82 304 254 25 34 43 167 998

Pacific (California) . . . . . . . . . . . 12 -8 0 0 0 0 0 0 4

Gulf of Mexico (Louisiana)a . . . . 776 87 253 234 17 34 36 136 833

Gulf of Mexico (Texas). . . . . . . . 143 3 51 20 8 0 7 31 161

Miscellaneousb. . . . . . . . . . . . . . . . 8 2 2 2 0 0 0 0 10

U.S. Total. . . . . . . . . . . . . . . . . . . . 7,524 99 2,048 1,321 313 51 88 896 7,906

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 1999 contained in the publications Petroleum Supply

Annual 1999, DOE/EIA-0340(99) and Natural Gas Annual 1999 DOE/EIA-0131(99).

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 39

Table 14. Natural Gas Plant Liquids Proved Reserves and Production, 1999

(Million Barrels of 42 U.S. Gallons)

1999 1999 1999 1999

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska . . . . . . . . . . . . . . . . . . . . . . 299 21

Lower 48 States. . . . . . . . . . . . . . 6,112 649

Alabama . . . . . . . . . . . . . . . . . . . . 57 8

Arkansas. . . . . . . . . . . . . . . . . . . . 3 0

California. . . . . . . . . . . . . . . . . . . . 97 8

Coastal Region Onshore . . . . . 31 1

Los Angeles Basin Onshore . . . 7 0

San Joaquin Basin Onshore. . . 59 7

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

Colorado . . . . . . . . . . . . . . . . . . . . 277 19

Florida. . . . . . . . . . . . . . . . . . . . . . 16 1

Kansas . . . . . . . . . . . . . . . . . . . . . 355 30

Kentucky . . . . . . . . . . . . . . . . . . . . 69 3

Louisiana. . . . . . . . . . . . . . . . . . . . 281 45

North. . . . . . . . . . . . . . . . . . . . . 36 4

South Onshore . . . . . . . . . . . . . 222 37

State Offshore. . . . . . . . . . . . . . 23 4

Michigan . . . . . . . . . . . . . . . . . . . . 42 4

Mississippi. . . . . . . . . . . . . . . . . . . 3 0

Montana . . . . . . . . . . . . . . . . . . . . 8 0

New Mexico. . . . . . . . . . . . . . . . . . 896 74

East . . . . . . . . . . . . . . . . . . . . . 230 37

West . . . . . . . . . . . . . . . . . . . . . 666 37

North Dakota. . . . . . . . . . . . . . . . . 46 4

Oklahoma . . . . . . . . . . . . . . . . . . . 667 70

Texas. . . . . . . . . . . . . . . . . . . . . . . 2,257 254

RRC District 1. . . . . . . . . . . . . . 161 17

RRC District 2 Onshore . . . . . . 64 10

RRC District 3 Onshore . . . . . . 152 31

RRC District 4 Onshore . . . . . . 300 42

RRC District 5. . . . . . . . . . . . . . 24 2

RRC District 6. . . . . . . . . . . . . . 182 18

RRC District 7B . . . . . . . . . . . . 34 5

RRC District 7C . . . . . . . . . . . . 291 30

RRC District 8. . . . . . . . . . . . . . 479 49

RRC District 8A . . . . . . . . . . . . 222 18

RRC District 9. . . . . . . . . . . . . . 156 14

RRC District 10. . . . . . . . . . . . . 191 18

State Offshore. . . . . . . . . . . . . . 1 0

Utah and Wyoming . . . . . . . . . . . . 531 45

West Virginia. . . . . . . . . . . . . . . . . 72 4

Federal Offshorea . . . . . . . . . . . . . 427 80

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

Gulf of Mexico (Louisiana)a . . . 403 75

Gulf of Mexico (Texas) . . . . . . . 24 5

Miscellaneousb . . . . . . . . . . . . . . . 8 0

U.S. Total . . . . . . . . . . . . . . . . . . . 6,503 697

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 1999 contained in the publications Petroleum Supply Annual 1999,

DOE/EIA-0340(99) and Natural Gas Annual 1999, DOE/EIA-0131(99).

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

40 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

Table 15. Lease Condensate Proved Reserves and Production, 1999

(Million Barrels of 42 U.S. Gallons)

1999 1999 1999 1999

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska . . . . . . . . . . . . . . . . . . . . . . 0 0

Lower 48 States. . . . . . . . . . . . . . 1,403 199

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 . . . . . . . . . . . . . . . . . . . . 26 3

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

Kansas . . . . . . . . . . . . . . . . . . . . . 3 0

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

Louisiana. . . . . . . . . . . . . . . . . . . . 176 33

North. . . . . . . . . . . . . . . . . . . . . 25 5

South Onshore . . . . . . . . . . . . . 142 26

State Offshore. . . . . . . . . . . . . . 9 2

Michigan . . . . . . . . . . . . . . . . . . . . 6 0

Mississippi. . . . . . . . . . . . . . . . . . . 7 1

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

New Mexico. . . . . . . . . . . . . . . . . . 58 7

East . . . . . . . . . . . . . . . . . . . . . 25 4

West . . . . . . . . . . . . . . . . . . . . . 33 3

North Dakota. . . . . . . . . . . . . . . . . 7 0

Oklahoma . . . . . . . . . . . . . . . . . . . 82 9

Texas. . . . . . . . . . . . . . . . . . . . . . . 327 41

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

RRC District 2 Onshore . . . . . . 12 2

RRC District 3 Onshore . . . . . . 74 14

RRC District 4 Onshore . . . . . . 122 12

RRC District 5. . . . . . . . . . . . . . 8 1

RRC District 6. . . . . . . . . . . . . . 41 5

RRC District 7B . . . . . . . . . . . . 2 1

RRC District 7C . . . . . . . . . . . . 14 2

RRC District 8. . . . . . . . . . . . . . 16 2

RRC District 8A . . . . . . . . . . . . 1 0

RRC District 9. . . . . . . . . . . . . . 2 0

RRC District 10. . . . . . . . . . . . . 26 1

State Offshore. . . . . . . . . . . . . . 3 0

Utah and Wyoming . . . . . . . . . . . . 84 14

West Virginia. . . . . . . . . . . . . . . . . 1 0

Federal Offshorea . . . . . . . . . . . . . 571 87

Pacific (California). . . . . . . . . . . 4 0

Gulf of Mexico (Louisiana)a . . . 430 61

Gulf of Mexico (Texas) . . . . . . . 137 26

Miscellaneousb . . . . . . . . . . . . . . . 2 0

U.S. Total . . . . . . . . . . . . . . . . . . . 1,403 199

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” 1999.

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

Natural gas plant liquids production increased 6

percent in 1999—from 655 million barrels in 1998 to 697

million barrels of production (Table 14). The top six

areas for proved reserves of natural gas plant liquids

accounted for about 80 percent of the Nation’s natural

gas plant liquids production:

 Texas (36 percent)

 New Mexico (11 percent)

 Gulf of Mexico Federal Offshore (11 percent)

 Oklahoma (10 percent)

 Utah and Wyoming (6 percent)

 Louisiana (6 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 1,403 million barrels in 1999 (Table 15).

This was 5 percent more than the volume reported in

1998. 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 40

Texas 23

Louisiana 13

Oklahoma 6

Utah-Wyoming 6

Area Total 88

Production

Production of lease condensate was 199 million barrels,

an increase of 12 percent in 1999. The production of five

areas account for about 93 percent of the Nation’s lease

condensate production.

 Gulf of Mexico Federal Offshore (44 percent)

 Texas (21 percent)

 Louisiana (17 percent)

 Utah-Wyoming (7 percent)

 Oklahoma (5 percent).

Reserves in

Nonproducing Reservoirs

Like crude oil and natural gas, not all lease condensate

proved reserves were contained in reservoirs that were

producing during 1999. Proved reserves of 418 million

barrels of lease condensate, a decrease of 21 percent

from 1998, were reported in nonproducing reservoirs

in 1999 (Appendix D, Table D10). About 55 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 1999 Annual Report 41
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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report 43
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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

1994 through 1999 for oil and gas well operators. The

tables show the volumetric change and percent change

from the previous year and from 1994. In addition they

show the 1999 average per operator in each class. All

companies that reported to EIA were ranked by

production size for each of the 6 years. We computed

company production size classes as the sum of the

barrel oil equivalent of the crude oil production, lease

condensate production, and wet gas production for

each operator. The companies were then placed in the

following production size classes: 1–10, 11–20, 21–100,

101–500, and all “other” oil and gas operators. The

“other” category contains 22,127 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 1994

through 1999 have changed from 171,939 billion cubic

feet to 176,159 billion cubic feet (Table A1). These

proved reserves are highly concentrated in the larger

companies. In 1999, the top 20 operators (Class 1–10

and Class 11–20) producing companies had 51 percent

of the proved reserves of natural gas. The next two size

classes contain 80 and 400 companies and account for

30 and 15 percent of the U.S. natural gas proved

reserves, respectively. The top 20 operators had a

decline of 10 percent in their natural gas proved

reserves from 1994 to 1999. While the rest of the

operators in (Class 21–100, Class 101–500, and Class

Other) had an increase of 20 percent in their reserves.

In 1999, the top 20 operators’ natural gas reserves

decreased by 4 percent from 1998.

Production

Wet natural gas production has increased from 19,622

billion cubic feet in 1998 to 19,856 billion cubic feet in

1999 (Table A2). In 1999, the top 20 producing

companies had 53 percent of the production of wet

natural gas, while having 51 percent of the proved

reserves. The next two size classes have 28 and 14

percent of the wet natural gas production, respectively.

The top 20 operators had an increase of 1 percent in

their wet natural gas production from 1994 to 1999. The

rest of the operators had an increase of 6 percent from

1994 to 1999. The top 20 operators’ wet natural gas

production had a increase of 2 percent in 1999 from

1998, while the rest of the operators had a increase of

0.1 percent.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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

1999 had 63 percent of U.S. proved reserves of crude oil

(Table A3), in contrast to wet natural gas where these

same companies operated only 51 percent of the total

proved reserves. These companies have tended in the

past few years to concentrate their domestic operations

in fewer fields and focus more of their resources on

their foreign operations.

U.S. proved reserves of crude oil increased 3.5 percent

in 1999. The top 20 producing companies proved

reserves of crude oil during 1999 decreased 5 percent.

The top 20 class had a decline of 18 percent in their

crude oil proved reserves from 1994 to 1999. The class

“other” had a 22 percent decrease from 1994 to 1999.

During the 1994–1999 period, many operators were

continuing to actively buy, sell, and restructure their oil

property positions.

Production

Crude oil production reported for 1994 to 1999 has

decreased from 2.3 billion barrels to 1.9 billion barrels

(Table A4). The 20 largest oil and gas producing

companies had 62 percent of U.S. production of crude

oil in 1999, while in 1994 they accounted for 68 percent

of production. This is in contrast to wet natural gas

where these same companies produced only 51 percent

of the total. U.S. production of crude oil declined by 14

percent from 1994 to 1999. The top 20 operators had a

decline of 21 percent in their oil production during the

same period. U.S. production of crude oil declined by 2

percent from 1998 to 1999, while the top 20 operators

production decreased by 5 percent. The next two size

classes account for 18 and 11 percent of the U.S. crude

oil production, respectively.

Fields

The number of fields in which Category I and Category

II operators were active dropped significantly during

the 1994–1999 period (Table A5). From 1994 through

1999, the number of fields in which the top 20 operators

were active in dropped by 1,980 (33 percent), while in

1999 the number dropped 224 (5 percent) from 1998.

Energy Information Administration

48 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 49

Class 1–10 76,665 75,856 72,606 68,876 64,336 64,320 -16 -12,235 6,431.995

Percent of Total 44.6% 43.7% 41.5% 39.2% 37.3% 36.5% 0.0% -16.1%

Class 11–20 22,691 24,648 25,416 27,705 28,338 24,925 -3,413 2,234 2,492.482

Percent of Total 13.2% 14.2% 14.5% 15.8% 16.4% 14.1% -12.0% 9.8%

Class 21–100 40,566 42,604 43,300 45,593 47,009 52,160 1,151 11,594 652.006

Percent of Total 23.6% 24.6% 24.7% 25.9% 27.3% 29.6% 11.0% 28.6%

Class 101–500 20,608 20,150 22,483 23,338 24,471 25,967 1,496 5,359 64.918

Percent of Total 12.0% 11.6% 12.8% 13.3% 14.2% 14.7% 6.1% 26.0%

Class Other (23,120) 11,409 10,218 11,342 10,209 8,289 8,787 498 -2,622 0.408

Percent of Total 6.6% 5.9% 6.5% 5.8% 4.8% 5.0% 6.0% -23.0%

Category I (170) 143,703 148,233 146,601 147,491 146,458 145,922 -536 2,219 824.420

Percent of Total 83.6% 85.4% 83.7% 83.9% 84.9% 82.8% -0.4% 1.5%

Category II (418) 18,158 15,828 18,382 17,764 18,033 21,979 3,946 3,821 55.086

Percent of Total 10.6% 9.1% 10.5% 10.1% 10.5% 12.5% 21.9% 21.0%

Category III (23,032) 10,078 9,416 10,164 10,466 7,952 8,257 305 -1,821 0.384

Percent of Total 5.9% 5.4% 5.8% 6.0% 4.6% 4.7% 3.8% -18.1%

Total Published 171,939 173,476 175,147 175,721 172,443 176,159 3,716 4,220 7.975

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.00% 100.00% 2.2% 2.5%

Table A1. Natural Gas Proved Reserves, Wet After Lease Separation, by Operator Production Size Class,

1994–1999

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

1998–1999 1994–1999 1999

Volume and Volume and Average

Percent Percent Reserves

Size Class 1994 1995 1996 1997 1998 1999 Change Change per Operator

Note: There were 21,513 active Category III operators in the 1999 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 1,953 Category III operators (Table E2). The “other” size class represents 21,589 operators in the

1999 frame (22,089 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 1999 Annual Report

Class 1–10 7,216 7,174 7,448 7,178 6,954 6,881 -73 -335 688.074

Percent of Total 37.6% 38.0% 37.5% 35.7% 35.4% 34.7% -1.0% -4.6%

Class 11–20 3,083 3,101 3,002 3,286 3,317 3,560 243 477 356.000

Percent of Total 16.0% 16.4% 15.1% 16.3% 16.9% 17.9% 7.3% 15.5%

Class 21–100 4,878 4,871 5,316 5,729 5,595 5,523 -72 645 69.044

Percent of Total 25.4% 25.8% 26.7% 28.4% 28.5% 27.8% -1.3% 13.2%

Class 101–500 2,552 2,477 2,623 2,665 2,721 2,793 72 241 6.983

Percent of Total 13.3% 13.1% 13.2% 13.2% 13.9% 14.1% 2.6% 9.4%

Class Other (23,120) 1,481 1,251 1,484 1,276 1,035 1,099 64 -382 0.051

Percent of Total 7.7% 6.6% 7.5% 6.3% 5.3% 5.5% 6.2% -25.8%

Category I (170) 15,656 15,800 16,381 16,897 16,619 16,248 -371 592 91.799

Percent of Total 81.5% 83.7% 82.4% 83.9% 84.7% 81.8% -2.2% 3.8%

Category II (418) 2,221 1,923 2,128 1,979 2,019 2,556 537 335 6.406

Percent of Total 11.6% 10.2% 10.7% 9.8% 10.3% 12.9% 26.6% 15.1%

Category III (23,032) 1,333 1,151 1,364 1,258 984 1,052 68 -281 0.049

Percent of Total 6.9% 6.1% 6.9% 6.2% 5.0% 5.3% 6.9% -21.1%

Total Published 19,210 18,874 19,873 20,134 19,622 19,856 234 646 0.899

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 1.2% 3.4%

Table A2. Natural Gas Production, Wet After Lease Separation, by Operator Production Size Class,

1994–1999

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

1998–1999 1994–1999 1999

Volume and Volume and Average

Percent Percent Production

Size Class 1994 1995 1996 1997 1998 1999 Change Change per Operator

Note: There were 21,513 active Category III operators in the 1999 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 1,953 Category III operators (Table E2). The “other” size class represents 23,589 operators in the

1999 frame (22,089 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 1999 Annual Report 51

Class 1–10 14,351 13,891 13,362 11,434 11,501 11,121 -380 -3,230 1,112.080

Percent of Total 63.9% 62.1% 60.7% 50.7% 54.7% 51.1% -3.3% -22.5%

Class 11–20 2,276 2,422 2,013 2,977 2,894 2,585 -309 309 258.454

Percent of Total 10.1% 10.8% 9.1% 13.2% 13.8% 11.9% -10.7% 13.6%

Class 21–100 2,607 2,623 3,155 4,384 3,677 4,338 661 1,731 54.224

Percent of Total 11.6% 11.7% 14.3% 19.4% 17.50% 19.9% 18.0% 66.4%

Class 101–500 1,512 1,793 1,838 2,111 1,754 2,379 625 867 5.949

Percent of Total 6.7% 8.0% 8.3% 9.4% 8.3% 10.9% 35.6% 57.3%

Class Other (23,120) 1,711 1,622 1,649 1,640 1,208 1,342 134 -369 0.062

Percent of Total 7.6% 7.3% 7.5% 7.3% 5.7% 6.2% 11.1% -21.6%

Category I (170) 19,648 19,647 19,312 19,461 18,819 18,952 133 -696 107.073

Percent of Total 87.5% 87.9% 87.7% 86.3 89.5% 87.1% -3.3% -3.5%

Category II (418) 1,142 1,103 1,117 1,400 1,018 1,521 503 379 3.811

Percent of Total 5.1% 4.9% 5.1% 6.2 4.8% 7.0% 49.4% 33.2%

Category III (23,032) 1,668 1,600 1,588 1,685 1,197 1,293 96 -375 0.060

Percent of Total 7.4% 7.2% 7.2% 7.5 5.7% 5.9% -29.0% -22.5%

Total Published 22,457 22,351 22,017 22,546 21,034 21,765 731 -692 0.985

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 3.5% -3.1%

Table A3. Crude Oil Proved Reserves by Operator Production Size Class, 1994–1999

(Million Barrels of 42 U.S. Gallons)

1998–1999 1994–1999 1999

Volume and Volume and Average

Percent Percent Reserves

Size Class 1994 1995 1996 1997 1998 1999 Change Change per Operator

Note: There were 21,513 active Category III operators in the 1999 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 1,953 Category III operators (Table E2). The “other” size class represents 21,589 operators in the

1999 frame (22,089 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 1999 Annual Report

Class 1–10 1,310 1,270 1,220 1,047 1,025 974 -51 -336 97.397

Percent of Total 57.8% 57.4% 56.1% 49.0% 51.5% 49.9% -2.1% -25.6%

Class 11–20 224 221 185 262 255 241 -14 17 24.138

Percent of Total 9.9% 10.0% 8.5% 12.3% 12.8% 12.3% -2.7% 7.6%

Class 21–100 287 276 307 373 342 350 8 63 4.378

Percent of Total 12.7% 12.5% 14.1% 17.4% 17.2% 17.9% -8.3% 22.0%

Class 101–500 200 214 213 237 206 208 2 8 0.520

Percent of Total 8.8% 9.7% 9.8% 11.1% 10.3% 10.7% -13.1% 4.0%

Class Other (23,120) 247 232 248 219 163 179 16 -68 0.008

Percent of Total% 10.9% 10.5% 11.4% 10.2% 8.2% 9.2% -25.6% -27.5%

Category I (170) 1,879 1,844 1,791 1,760 1,714 1,617 -97 -262 9.135

Percent of Total 82.8% 83.3% 82.4% 82.3% 86.1% 82.8% -2.6% -13.9%

Category II (418) 150 139 143 157 118 160 42 10 0.401

Percent of Total 6.6% 6.3% 6.6% 7.3% 5.9% 8.2% -24.8% 6.7%

Category III (23,032) 239 230 239 221 159 175 16 -64 0.008

Percent of Total 10.5% 10.4% 11.0% 10.3% 8.0% 9.0% -28.1% -26.8%

Total Published 2,268 2,213 2,173 2,138 1,991 1,952 -39 -316 0.088

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -2.0% -13.9%

Table A4. Crude Oil Production by Operator Production Size Class, 1994–1999

(Million Barrels of 42 U.S. Gallons)

1998–1999 1994–1999 1999

Volume and Volume and Average

Percent Percent Production

Size Class 1994 1995 1996 1997 1998 1999 Change Change per Operator

Note: There were 21,513 active Category III operators in the 1999 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 1,953 Category III operators (Table E2). The “other” size class represents 21,589 operators in the

1999 frame (22,089 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 1999 Annual Report 53

Class 1–10 3,258 3,113 2,800 2,566 2,475 2,559 84 -699 255.900

Percent of Total 12.2% 11.9% 10.7% 10.4% 9.5% 10.0% 3.4% -21.5%

Class 11–20 2,795 2,772 2,441 2,257 1,822 1,514 -308 -1,281 151.400

Percent of Total 10.5% 10.6% 9.3% 9.1% 7.0% 5.9% -16.9% -45.8%

Class 21–100 7,752 7,569 7,526 7,159 7,526 8,180 654 177 102.250

Percent of Total 29.1% 28.9% 28.7% 28.9% 29.0% 32.0% 8.7% 2.2%

Class 101–500 11,878 11,886 12,492 12,878 12,817 12,344 473 466 30.860

Percent of Total 44.6% 45.4% 47.7% 52.0% 49.4% 48.2% -3.7% 3.9%

Rest 1,897 1,601 a952 1,332 1,524 1,287 -237 -359 1.778

Percent of Total 7.1% 6.1% a

3.6% 5.4% 5.9% 5.0% -15.6% -21.8%

Category I 16,161 16,256 15,635 15,232 15,666 15,120 -546 -1,041 85.424

Percent of Total 60.7% 62.1% 59.7% 58.2% 60.4% 59.1% -3.5% -6.4%

Category II 10,452 9,939 10,576 R9,530 10,271 10,467 196 15 26.233

Percent of Total 39.3% 37.9% 40.3% 41.8% 39.6% 40.9% 1.9% 0.1%

Total Reported 26,613 26,195 26,211 R24,762 25,937 25,587 -350 -1,026 44.422

Percent Change 100.0% 100.0% 100.0% 100.0% 100.0% 100.00% -1.3% -3.9%

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 1999, there were 177 Category I operators and 399 Category II

operators. The “rest” size class had 76 operators in 1999.

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

Table A5. Operator Field Count by Operator Production Size Class, 1994–1999

1998–1999 1994–1999 1999 Average

Number and Number and Number of

Percent Percent Fields per

Size Class 1994 1995 1996 1997 1998 1999 Change Change Operator
Appendix B

Top 100 Oil and Gas Fields for 1999
Appendix B

Top 100 Oil and Gas Fields for 1999

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 1999

The top 100 oil fields in the United States as of

December 31, 1999, had 14,681 million barrels of

proved reserves accounting for 63 percent of the total

United States (Table 6 and Table 15). 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 1999 there are two fields,

Mississippi Canyon Block 807 (Mars) and Mississippi

Canyon Block 810 (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, 1999, had 1,120 million barrels of

production, or 52 percent of the total (Table 6 and

Table 15). Many of the oil fields in the top 100 are very

old, 49 of the oil fields in Table B1 were discovered

prior to 1950. The oldest, Coalinga in California, was

discovered in 1887. The newest, Mississippi Canyon

Block 127, in the Gulf of Mexico Federal Offshore was

reported to EIA in 1999.

The oil fields with newer discovery dates are typically

located in the Gulf of Mexico Offshore and Alaska. Of

the top 100 oil fields; 25 percent are in Texas, 24 percent

are in the Gulf of Mexico Federal Offshore, 20 percent

are in California, and 11 percent are in Alaska. There

were 17 different fields in this year’s tabulation than in

last years.

Table B2. Top 100 Gas Fields for 1999

The top 100 gas fields in the United States as of

December 31, 1999, had 82,759 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, 1999, had 6,700 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 in Table B2 that were

discovered prior to 1950. 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 reported to EIA 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 26 percent are in Texas, 14 percent

in the Gulf of Mexico Offshore, an additional 24 percent

are in Oklahoma and Wyoming. There were 11

different fields in this year’s tabulation than in last

year’s table.

Table B3. Top U.S. Operators Ranked by Reported

1999 Operated Production Data

Table B3 lists the top U.S. operators ranked by

reported 1999 operated production data. Pending

mergers and acquisitions announced in 1999 between

these top operators are indicated in the left margin with

linked arrows.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 57
Energy Information Administration

58 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

Table B1. Top 100 U.S. Fields Ranked by Oila Proved Reserves, from Reported 1999 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 1-10 193.2

Kuparuk River AK 1969 1-10 81.9

Midway-Sunset CA 1901 1-10 56.9

Belridge South CA 1911 1-10 42.3

Wasson TX 1937 1-10 24.9

Yates TX 1926 1-10 14.3

Kern River CA 1899 1-10 48.1

Elk Hills CA 1920 1-10 23.6

Mississippi Canyon Blk 807 GF 1989 1-10 51.5

Slaughter TX 1937 1-10 14.5

Top 10 Volume Subtotal 7,686.4 551.2

Top 10 Percentage of U.S. Total 33.2% 25.6%

Milne Point AK 1982 11-20 19.6

Spraberry Trend Area TX 1951 11-20 17.7

Hondo CA 1969 11-20 12.1

Levelland TX 1945 11-20 9.6

Alpine AK 1994 11-20 0.0

Point McIntyre AK 1988 11-20 33.7

Endicott AK 1978 11-20 13.7

Cymric CA 1916 11-20 17.8

Mississippi Canyon Blk 810 GF 1996 11-20 8.5

San Ardo CA 1947 11-20 4.2

Top 20 Volume Subtotal 9,821.0 688.1

Top 20 Percentage of U.S. Total 42.4% 32.0%

Wilmington CA 1932 21-50 16.3

Sho-Vel-Tum OK 1905 21-50 8.7

Cowden North TX 1930 21-50 8.2

Lost Hills CA 1910 21-50 10.9

Ventura CA 1916 21-50 4.8

Green Canyon Blk 244 GF 1994 21-50 35.0

Pescado CA 1970 21-50 9.2

Vacuum NM 1929 21-50 7.7

Alaminos Canyon Blk 25 GF 1997 21-50 0.0

Greater Aneth UT 1956 21-50 6.1

Rangely CO 1902 21-50 6.0

Fullerton TX 1942 21-50 5.7

Hawkins TX 1940 21-50 3.4

Mississippi Canyon Blk 127 GF 1999 21-50 0.0

Green Canyon Blk 205 GF 1988 21-50 10.8

Coalinga CA 1887 21-50 8.1

Seminole TX 1936 21-50 10.8

McElroy TX 1926 21-50 6.3

Wattenberg CO 1970 21-50 5.1

Goldsmith TX 1935 21-50 4.2

Howard-Glasscock TX 1925 21-50 3.1

Salt Creek TX 1950 21-50 7.1

Monument Butte UT 1964 21-50 1.6

Garden Banks Blk 426 GF 1992 21-50 21.4

Mississippi Canyon Blk 935 GF 1994 21-50 0.0

Robertson North TX 1956 21-50 3.0

Jay FL & AL 1970 21-50 4.2

Green Canyon Blk 158 GF 1992 21-50 0.0

Arroyo Grande CA 1906 21-50 0.6

Wasson 72 TX 1940 21-50 2.2

Top 50 Volume Subtotal 12,531.7 898.8

Top 50 Percentage of U.S. Total 54.1% 41.8%
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 59

Hobbs NM 1928 51-100 2.7

Monument NM & UT 1935 51-100 2.8

Niakuk AK 1984 51-100 16.0

Viosca Knoll Blk 990 GF 1981 51-100 15.1

West Delta Blk 30 GF 1949 51-100 7.7

Giddings TX 1960 51-100 11.7

East Texas TX 1930 51-100 12.9

Pennel MT 1955 51-100 1.7

Tarn AK 1991 51-100 9.5

Sacate CA 1970 51-100 0.2

West Sak AK 1969 51-100 1.2

Inglewood CA 1924 51-100 2.5

Mississippi Canyon Blk 84 GF 1993 51-100 0.0

Garden Banks Blk 260 GF 1995 51-100 22.6

Jo-Mill TX 1954 51-100 2.3

Ewing Bank Blk 873 GF 1991 51-100 18.0

Viosca Knoll Blk 956 GF 1985 51-100 16.9

Cedar Lake TX 1939 51-100 2.5

Fiord AK 1992 51-100 0.0

Fitts OK 1934 51-100 1.3

Foster TX 1932 51-100 2.7

Bay Marchand Blk 2 GF & LA 1949 51-100 5.4

Beverly Hills CA 1900 51-100 1.5

Eugene Island SA Blk 330 GF 1971 51-100 8.5

Lisburne AK 1967 51-100 2.0

Elk Basin WY 1915 51-100 2.2

Eunice Monument NM 1929 51-100 1.4

T X L TX 1944 51-100 1.9

Dollarhide TX & NM 1945 51-100 3.2

Lookout Butte East MT 1986 51-100 1.3

Bluebell UT 1949 51-100 2.0

Viosca Knoll Blk 915 GF 1993 51-100 0.0

Cogdell TX 1949 51-100 0.7

Garden Banks Blk 171 GF 1988 51-100 0.9

Mississippi Canyon Blk 755 GF 1986 51-100 0.0

Dos Cuadras CA 1968 51-100 2.3

Brea-Olinda CA 1897 51-100 0.8

Means TX 1934 51-100 3.9

Huntington Beach CA 1920 51-100 3.6

Kern Front CA 1925 51-100 1.5

Westbrook TX 1920 51-100 0.9

Grayburg-Jackson NM 1929 51-100 3.3

Viosca Knoll Blk 786 GF 1996 51-100 0.0

South Pass EA Blk 62 GF 1967 51-100 3.4

Main Pass SA Blk 299 GF 1967 51-100 4.6

Cedar Hills ND 1995 51-100 3.8

Mississippi Canyon Blk 899 GF 1998 51-100 0.0

Hartzog Draw WY 1976 51-100 2.3

Hamilton Dome WY 1918 51-100 1.7

Pecan Lake LA 1982 51-100 7.7

Top 100 Volume Subtotal 14,681.0 1,120.0

Top 100 Percentage of U.S. Total 63.4% 52.1%

Table B1. Top 100 U.S. Fields Ranked by Oila Proved Reserves, from Reported 1999 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 2,151 million barrels and the U.S. total reserves estimate of 23,168 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 1999 Annual Report

Table B2. Top 100 U.S. Fields Ranked by Gasa Proved Reserves, from Reported 1999 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 1-10 713.6

Basin NM 1947 1-10 673.7

Prudhoe Bay AK 1967 1-10 198.3

Hugoton Gas Area KS & OK & TX 1922 1-10 442.5

Madden WY 1968 1-10 71.3

Carthage TX 1944 1-10 203.9

Mobile Bay AL 1979 1-10 150.0

Wattenberg CO 1970 1-10 125.9

Natural Buttes UT 1952 1-10 63.4

Oakwood VA 1990 1-10 36.8

Top 10 Volume Subtotal 38,938.5 2,679.3

Top 10 Percentage of U.S. Total 22.1% 13.5%

Fogarty Creek WY 1975 11-20 31.1

Antrim MI 1965 11-20 126.1

Panhandle West TX 1918 11-20 109.8

Big Sandy KY & WV 1881 11-20 48.5

Jonah WY 1977 11-20 79.2

Spraberry Trend Area TX 1951 11-20 64.9

Raton CO 1994 11-20 27.7

Panoma Gas Area KS 1956 11-20 83.7

Red Oak-Norris OK 1910 11-20 54.2

Lake Ridge WY 1981 11-20 15.8

Top 20 Volume Subtotal 49,617.4 3,320.3

Top 20 Percentage of U.S. Total 28.2% 16.7%

Giddings TX 1960 21-50 240.3

Elk Hills CA 1920 21-50 133.3

Cook Inlet North AK 1962 21-50 51.3

Beluga River AK 1962 21-50 34.9

Wasson TX 1937 21-50 20.2

Gomez TX 1977 21-50 62.4

Mocane-Laverne Gas Area KS & OK & TX 1979 21-50 69.5

Whitney Canyon-Carter Crk WY 1978 21-50 74.7

Viosca Knoll Blk 956 GF 1985 21-50 103.3

Newark East TX 1981 21-50 36.6

East Breaks Blk 945 GF 1994 21-50 0.0

Strong City District OK 1966 21-50 67.1

Sawyer TX 1975 21-50 44.4

Oak Hill TX 1958 21-50 62.1

Knox OK 1916 21-50 62.4

Drunkards Wash UT 1989 21-50 47.7

Mobile Blk 823 GF 1983 21-50 66.7

Lower Mobile Bay-Mary Ann AL 1979 21-50 28.7

Mississippi Canyon Blk 810 GF 1996 21-50 14.5

Nora VA 1949 21-50 23.4

Golden Trend OK 1945 21-50 38.9

Mississippi Canyon Blk 731 GF 1987 21-50 92.0

Watonga-Chickasha Trend OK 1962 21-50 61.6

Bruff WY 1969 21-50 42.0

Bob West TX 1990 21-50 52.2

Wilburton OK 1941 21-50 47.7

Indian Basin NM 1971 21-50 90.3

Kinta OK 1914 21-50 37.2

Elk City OK 1947 21-50 47.2

Agua Dulce TX 1928 21-50 8.1

Top 50 Volume Subtotal 67,829.4 5,081.3

Top 50 Percentage of U.S. Total 38.5% 25.6%
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 61

Table B2. Top 100 U.S. Fields Ranked by Gasa Proved Reserves, from Reported 1999 Field Level Data

(Continued)

(Billion Cubic Feet)

Discovery Proved Reserves Reported Production

Field Name Location Year Rank Group Rank Group

Garden Banks Blk 426 GF 1992 51-100 89.6

Judge Digby LA 1977 51-100 42.8

La Perla TX 1958 51-100 58.0

Vaquillas Ranch TX 1978 51-100 78.5

Viosca Knoll Blk 915 GF 1993 51-100 0.1

McArthur River AK 1965 51-100 70.0

Wamsutter WY 1958 51-100 28.6

Ozona TX 1962 51-100 33.6

Mississippi Canyon Blk 807 GF 1989 51-100 55.0

Belridge South CA 1911 51-100 18.5

Dew TX 1982 51-100 20.7

McAllen Ranch TX 1986 51-100 61.0

Kuparuk River AK 1969 51-100 28.9

Fairway AL 1986 51-100 28.6

Elm Grove LA 1958 51-100 13.1

Verden OK 1948 51-100 36.6

Standard Draw WY 1979 51-100 21.6

Garden Banks Blk 171 GF 1988 51-100 16.5

Rulison CO 1956 51-100 12.8

Anschutz Ranch East UT & WY 1980 51-100 58.0

A W P TX 1981 51-100 19.1

Mimms Creek TX 1978 51-100 14.6

Painter Reservoir East WY 1979 51-100 35.3

Matagorda Island Blk 623 GF 1980 51-100 97.9

Grand Valley CO 1985 51-100 7.9

Table Rock WY 1946 51-100 12.4

Double A Wells TX 1980 51-100 33.0

South Pass SA Blk 89 GF 1969 51-100 35.4

Pegasus TX 1949 51-100 23.7

Willow Springs TX 1954 51-100 26.8

Hondo CA 1969 51-100 22.6

Cedar Cove Coal Degas AL 1983 51-100 20.2

Lake Arthur South LA 1955 51-100 20.2

Blanco South NM 1952 51-100 17.4

Waltman WY 1959 51-100 41.2

Moorewood NE OK 1979 51-100 29.4

Wild Rose WY 1975 51-100 18.2

Tip Top WY 1928 51-100 18.5

Mississippi Canyon Blk 354 GF 1977 51-100 36.9

Monte Christo TX 1982 51-100 16.2

Cement OK 1917 51-100 24.0

Boonsville TX 1950 51-100 29.9

Kenai AK 1959 51-100 10.1

Sugg Ranch TX 1985 51-100 7.8

Bryceland West LA 1952 51-100 29.9

Sarita East TX 1967 51-100 31.8

Endicott AK 1978 51-100 10.1

Jeffress NE TX 1975 51-100 27.6

Green Canyon Blk 244 GF 1994 51-100 68.3

Viosca Knoll Blk 783 GF 1985 51-100 59.5

Top 100 Volume Subtotal 82,759.0 6,699.8

Top 100 Percentage of U.S. Total 47.0% 33.7%

aTotal wet gas after lease separation.

Note: The U.S. total production estimate of 19,856 billion cubic feet and the U.S. total reserves estimate of 176,159 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.
Table B3. Top U.S. Operators Ranked by Reported 1999 Operated Production Data

Total Natural Gas

Crude Oil Production Production

Rank Company Name (thousand barrels/day) Rank Company Name (billion cubic feet/day)

1 Arco Exploration & Production . . . . . . . . . . . . 682 1 Exxon Mobil Production Co.............. 3,611

2 BP Amoco . . . . . . . . . . . . . . . . . . . . . . . . . . . . 581 2 BP Amoco ........................... 3,540

3 Shell Oil Co . . . . . . . . . . . . . . . . . . . . . . . . . . . 359 3 Shell Oil Co .......................... 2,699

4 ChevronUSA Production Co . . . . . . . . . . . . 346 4 Burlington Resources Oil & Gas .......... 2,302

5 Texaco Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . . 310 5 ChevronUSA Production Co ........... 2,116

6 Exxon Mobil Production Co. . . . . . . . . . . . . . . 310 6 Texaco Inc........................... 1,715

7 Aera Energy LLC. . . . . . . . . . . . . . . . . . . . . . . 260 7 Unocal Corp ......................... 1,333

8 Altura Energy Ltd . . . . . . . . . . . . . . . . . . . . . . 170 8 Santa Fe Snyder Corp ................. 1,306

9 Marathon Oil Co . . . . . . . . . . . . . . . . . . . . . . . 165 9 Union Pacific Resources ................ 1,275

10 Amerada Hess Corp . . . . . . . . . . . . . . . . . . . . 117 10 Vastar Resources Inc .................. 1,191

Top 10 Volume Subtotal .............. 3,298 Top 10 Volume Subtotal .............. 21,088

Top 10 Percentage of U.S. Total . . . . . . . . . 56% Top 10 Percentage of U.S. Total . . . . . . . . . 39%

11 Oxy USA Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . 99 11 Devon Energy Corp.................... 1,157

12 Unocal Corp . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 12 Conoco Inc .......................... 1,125

13 Kerr McGee O&G Corp . . . . . . . . . . . . . . . . . . . 74 13 Phillips Petroleum Co .................. 1,123

14 Apache Corp . . . . . . . . . . . . . . . . . . . . . . . . . . . 72 14 Coastal Oil & Gas Corp................. 1,042

15 Devon Energy Corp. . . . . . . . . . . . . . . . . . . . . . 67 15 Marathon Oil Co . . . . . . . . . . . . . . . . . . . . . . . . 862

16 Union Pacific Resources . . . . . . . . . . . . . . . . . . 54 16 EOG Resources Inc . . . . . . . . . . . . . . . . . . . . . 855

17 Ocean Energy Inc . . . . . . . . . . . . . . . . . . . . . . . 46 17 Oxy USA Inc. . . . . . . . . . . . . . . . . . . . . . . . . . . 847

18 Burlington Resources Oil & Gas . . . . . . . . . . . . 46 18 Apache Corp . . . . . . . . . . . . . . . . . . . . . . . . . . 742

19 Vastar Resources Inc . . . . . . . . . . . . . . . . . . . . 41 19 Arco Exploration & Production . . . . . . . . . . . . . 673

20 City Of Long Beach . . . . . . . . . . . . . . . . . . . . . . 38 20 El Paso Production Co . . . . . . . . . . . . . . . . . . . 635

Top 20 Volume Subtotal .............. 3,910 Top 20 Volume Subtotal .............. 30,149

Top 20 Percentage of U.S. Total . . . . . . . . . 66% Top 20 Percentage of U.S. Total . . . . . . . . . 55%

21 Conoco Inc . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 21 Amerada Hess Corp. . . . . . . . . . . . . . . . . . . . . 600

22 Nuevo Energy Co . . . . . . . . . . . . . . . . . . . . . . . 36 22 Kerr McGee O&G Corp . . . . . . . . . . . . . . . . . . 561

23 Phillips Petroleum Co . . . . . . . . . . . . . . . . . . . . 36 23 Cross Timbers Operating Co . . . . . . . . . . . . . . 490

24 Pioneer Natural Resources USA. . . . . . . . . . . . 35 24 Anadarko Petroleum Corp . . . . . . . . . . . . . . . . 466

25 Santa Fe Snyder Corp . . . . . . . . . . . . . . . . . . . 32 25 Newfield Exploration Co. . . . . . . . . . . . . . . . . . 454

26 Plains Resources Inc . . . . . . . . . . . . . . . . . . . . 29 26 Ocean Energy Inc . . . . . . . . . . . . . . . . . . . . . . 439

27 Merit Energy Co . . . . . . . . . . . . . . . . . . . . . . . . 24 27 Chesapeake Operating Inc . . . . . . . . . . . . . . . 429

28 British Borneo USA Inc . . . . . . . . . . . . . . . . . . . 24 28 Pioneer Natural Resources USA . . . . . . . . . . . 416

29 Anadarko Petroleum Corp. . . . . . . . . . . . . . . . . 23 29 Questar Exploration & Production . . . . . . . . . . 387

30 Goodrich Petroleum Co. . . . . . . . . . . . . . . . . . . 22 30 C N G Producing Co . . . . . . . . . . . . . . . . . . . . 378

31 Citation Oil & Gas Corp. . . . . . . . . . . . . . . . . . . 22 31 Samedan Oil Corp . . . . . . . . . . . . . . . . . . . . . . 368

32 Samedan Oil Corp. . . . . . . . . . . . . . . . . . . . . . . 22 32 Louis Dreyfus Natural Gas Corp . . . . . . . . . . . 352

33 Newfield Exploration Co . . . . . . . . . . . . . . . . . . 22 33 Mitchell Energy Corp . . . . . . . . . . . . . . . . . . . . 320

34 Hunt Oil Co . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 34 Samson Resources Co . . . . . . . . . . . . . . . . . . 317

35 EOG Resources Inc . . . . . . . . . . . . . . . . . . . . . 21 35 Houston Exploration Co The . . . . . . . . . . . . . . 257

36 Vintage Petroleum Inc. . . . . . . . . . . . . . . . . . . . 21 36 Walter Oil & Gas Corp . . . . . . . . . . . . . . . . . . . 251

37 Coastal Oil & Gas Corp. . . . . . . . . . . . . . . . . . . 17 37 Cabot Oil & Gas Corp . . . . . . . . . . . . . . . . . . . 239

38 Meridian Resource Corp . . . . . . . . . . . . . . . . . . 16 38 Murphy Exploration & Production. . . . . . . . . . . 230

39 Duncan Oil Inc. . . . . . . . . . . . . . . . . . . . . . . . . . 16 39 Barrett Resources Corp . . . . . . . . . . . . . . . . . . 206

40 Berry Petroleum Co. . . . . . . . . . . . . . . . . . . . . . 16 40 Equitable Production Co . . . . . . . . . . . . . . . . . 196

41 Denbury Resources Inc. . . . . . . . . . . . . . . . . . . 15 41 Tom Brown Inc . . . . . . . . . . . . . . . . . . . . . . . . . 190

42 Swift Energy Co . . . . . . . . . . . . . . . . . . . . . . . . 15 42 River Gas Corp . . . . . . . . . . . . . . . . . . . . . . . . 182

43 Cross Timbers Operating Co . . . . . . . . . . . . . . 15 43 Helmerich & Payne Inc. . . . . . . . . . . . . . . . . . . 180

44 El Paso Production Co . . . . . . . . . . . . . . . . . . . 15 44 Fina Oil & Chemical Co . . . . . . . . . . . . . . . . . . 177

45 C N G Producing Co . . . . . . . . . . . . . . . . . . . . . 14 45 Hunt Oil Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . 177

46 Seneca Resources Corp . . . . . . . . . . . . . . . . . . 14 46 Kaiser - Francis Oil Co . . . . . . . . . . . . . . . . . . . 172

47 Prize Energy Corp. . . . . . . . . . . . . . . . . . . . . . . 13 47 Altura Energy Ltd . . . . . . . . . . . . . . . . . . . . . . . 172

48 Continental Resources Inc . . . . . . . . . . . . . . . . 13 48 Yates Petroleum Corp . . . . . . . . . . . . . . . . . . . 164

49 Murphy Exploration & Production . . . . . . . . . . . 13 49 Koch Exploration Co . . . . . . . . . . . . . . . . . . . . 164

50 Howell Petroleum Corp . . . . . . . . . . . . . . . . . . . 13 50 Forest Oil Corp. . . . . . . . . . . . . . . . . . . . . . . . . 161

Top 50 Volume Subtotal .............. 4,542 Top 50 Volume Subtotal .............. 39,244

Top 50 Percentage of U.S. Total . . . . . . . . . 77% Top 50 Percentage of U.S. Total . . . . . . . . . 72%

Note: Arrows indicate mergers, acquisitions in 2000, and announced plans.

aCrude oil production includes production of lease condensate. Total natural gas is wet after lease separation.

Energy Information Administration

62 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report
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."{38}

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 1999 Annual Report 65
Energy Information Administration

66 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

Table C1. U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids,

in Metric Units, 1989 – 1999

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)

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

1999 22.1 999.1 709.9 311.3 41.2 51.0 23.1 115.3 310.3 3,460.4 116.3

Dry Natural Gas (billion cubic meters)

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

1999 27.81 1,194.04 896.60 325.25 199.44 44.40 62.18 306.02 535.98 4,740.41 95.29

Natural Gas Liquids (million cubic meters)

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

1999 15.8 325.6 210.0 131.4 49.8 8.1 14.0 71.9 142.5 1,257.0 60.8

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

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

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

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, 1989–1999 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 1999 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 1999 of the EIA publication U.S. Crude Oil, Natural

Gas, and Natural Gas Liquids Reserves, DOE EIA-0216.{1-22}

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

1999 49 0 c4,287 107

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;

2,853 Bcf in 1999.

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

1999 4,900 464 9,734 299

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 1999 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

1999 48 0 1,542 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

1999 d3,934 d1,400 d2,387 d98

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

1999 491 40 192 31

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

1999 297 0 168 7
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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

1999 2,949 1,330 1,951 60

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

1999 750 30 612 4

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

1999 197 30 76 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

1999 553 0 536 4
Energy Information Administration

72 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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

1999 203 21 8,987 303

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

1999 85 0 84 16

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

1999 100 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

1999 10 0 NA NA
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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

1999 175 0 5,753 358

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

1999 24 0 1,435 69

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

1999 f600 f278 f9,242 f457

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

1999 108 0 3,079 61
Energy Information Administration

74 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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

1999 384 278 5,535 364

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

1999 f108 f0 f628 f32

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

1999 52 0 2,255 48

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

1999 163 0 677 10
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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

1999 207 0 841 8

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

1999 17 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

1999 718 165 15,449 954

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

1999 705 165 3,037 255
Energy Information Administration

76 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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

1999 13 0 12,412 699

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

1999 NA NA 221 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

1999 262 1 416 53

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

1999 51 0 1,179 NA
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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

1999 621 58 12,543 749

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

1999 16 0 1,772 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

1999 g5,339 g426 g40,157 g2,584

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

1999 66 0 1,008 167
Energy Information Administration

78 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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

1999 53 0 1,881 76

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

1999 221 25 3,913 226

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

1999 42 0 8,915 422

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

1999 37 0 2,319 32
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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

1999 245 4 5,857 223

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

1999 123 0 416 36

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

1999 209 3 3,178 305

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

1999 2,067 279 5,434 495
Energy Information Administration

80 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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

1999 2,089 115 1,257 223

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

1999 123 0 1,137 158

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

1999 61 0 4,424 217

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

1999 305 0 6,271 165
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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

1999 3 0 418 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)

1999 268 42 3,213 (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

1999 NA NA 2,017 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

1999 21 0 2,936 73
Energy Information Administration

82 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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

1999 590 5 14,226 i615

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 7 26,902 931

1999 3,297 5 25,987 998

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

1999 553 0 536 4

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

1999 2,442 5 k19,598 k833

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 1999 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

1999 302 0 5,853 161

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

1999 15 0 66 10

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

1999 16,865 2,400 157,672 7,515

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

1999 21,765 2,865 167,406 7,906
Energy Information Administration

84 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

Table D1. U.S. Proved Reserves of Crude Oil, 1976–1999

(Million Barrels of 42 U.S. Gallons)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Estimated 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

1999 139 6,284 4,465 1,958 259 321 145 725 1,952 21,765 +731

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 1999 annual reports, DOE/EIA-0216.{1-22}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 85

Table D2. U.S. Lower 48 Proved Reserves of Crude Oil, 1976–1999

(Million Barrels of 42 U.S. Gallons)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Estimated 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

1999 138 3,933 2,264 1,807 253 242 145 640 1,564 16,865 +883

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 1999 annual reports, DOE/EIA-0216.{1-22}
Energy Information Administration

86 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

Table D3. U.S. Proved Reserves of Dry Natural Gas, 1976–1999

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

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Estimated 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

1999 982 42,167 31,663 11,486 7,043 1,568 2,196 10,807 18,928 167,406 +3,365

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 1999 annual reports, DOE/EIA-0216.{1-22}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 87

Table D4. U.S. Lower 48 Proved Reserves of Dry Natural Gas, 1976–1999

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

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Estimated 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

1999 849 38,590 28,138 11,301 7,041 1,512 2,173 10,726 18,469 157,672 +3,558

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 1999 annual reports, DOE/EIA-0216.{1-22}
Energy Information Administration

88 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

Table D5. U.S. Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–1999

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

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Estimated 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 –1,624 29,401 23,419 4,385 8,630 1,116 2,240 11,986 19,622 172,433 -3,288

1999 1,102 44,233 33,051 12,284 7,401 1,622 2,265 11,288 19,856 176,159 +3,726

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 1999 annual reports, DOE/EIA-0216.{2-22}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 89

Table D6. U.S. Lower 48 Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–1999

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

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Estimated 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 –1,461 29,231 23,294 4,476 8,628 1,112 2,240 11,980 19,104 162,400 –2,648

1999 958 40,606 29,476 12,088 7,399 1,566 2,242 11,207 19,391 166,304 +3,904

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 1999 annual reports, DOE/EIA-0216.{2-22}
Energy Information Administration

90 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

Table D7. U.S. Proved Reserves of Natural Gas Liquids, 1978–1999

(Million Barrels of 42 U.S. Gallons)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Estimated 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

1999 99 2,048 1,321 826 313 51 88 452 896 7,906 +382

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 1999 annual reports, DOE/EIA-0216.{2-22}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 91

Table D8. U.S. Lower 48 Proved Reserves of Natural Gas Liquids, 1978–1999

(Million Barrels of 42 U.S. Gallons)

Revisionsb New Reservoir Provedd Change

Revision Revision and New Field Discoveries Totalc Estimated 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 88 537 809 7,204 –138

1999 102 1,902 1,285 719 304 50 86 440 848 7,515 +311

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 1999 annual reports, DOE/EIA-0216.{2-22}
Energy Information Administration

92 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-1999

Gulf of Mexico Depth

Greater than Less than Deepwater

Year Total Louisianaa Texas 200 meters 200 meters Percentage

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

1999 421 376 45 228 193 54.2

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

1999 2,744 2,442 302 1,626 1,118 59.3

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

1999 5,000 3,829 1,171 1,124 3,876 22.5

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

1999 26,062 20,172 5,890 7,726 18,336 29.6

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

1999 167 136 31 51 116 30.5

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 753 621 132 300 456 39.8

1997 906 785 121 349 557 38.5

1998 919 776 143 387 532 42.1

1999 994 833 161 411 583 41.3

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. 1999 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 932 - 696 97 793

Lower 48 States . . . . . . . . . . . . . . . . . . . . . . . . . 3,274 418 30,539 5,542 36,080

Alabama . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 5 172 1 173

Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 - 186 9 195

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 511 - 73 215 288

Coastal Region Onshore . . . . . . . . . . . . . . . . 134 - 063 63

Los Angeles Basin Onshore . . . . . . . . . . . . . . 56 - 043 43

San Joaquin Basin Onshore . . . . . . . . . . . . . . 321 - 73 108 181

State Offshore . . . . . . . . . . . . . . . . . . . . . . . . . 0- 000

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 308 1,689 296 1,985

Florida . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 - - - -

Illinois. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 - - 2 2

Indiana. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - - - - -

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 - 92 7 99

Kentucky . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - - 226 - 226

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 226 58 2,970456 3,426

North . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42 5 936 123 1,059

South Onshore . . . . . . . . . . . . . . . . . . . . . . . . 146 501,796 289 2,085

State Offshore . . . . . . . . . . . . . . . . . . . . . . . . . 38 3 238 44 282

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 52 1 53

Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 2 152 4 156

Montana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83 - 89 20110

Nebraska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - - - - -

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157 8 2,423 122 2,545

East . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156 4 286 118 404

West . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 04 2,137 4 2,141

New York . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - - 32 - 32

North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 3 67 15 81

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 - 142 69 211

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8018 1,559 181 1,741

Pennsylvania . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 - 19026 216

Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 565 71 7,642 8608,502

RRC District 1 . . . . . . . . . . . . . . . . . . . . . . . . . . 13 2 309 5 314

RRC District 2 Onshore . . . . . . . . . . . . . . . . . 7 3 38073 453

RRC District 3 Onshore . . . . . . . . . . . . . . . . . 26 18 769 141 910

RRC District 4 Onshore . . . . . . . . . . . . . . . . . 9 25 2,395 79 2,474

RRC District 5 . . . . . . . . . . . . . . . . . . . . . . . . . 5 2 857 4 860

RRC District 6 . . . . . . . . . . . . . . . . . . . . . . . . . 10101,146 45 1,191

RRC District 7B . . . . . . . . . . . . . . . . . . . . . . . . 6 - 7 2 8

RRC District 7C . . . . . . . . . . . . . . . . . . . . . . . . 33 1 332 54 386

RRC District 8 . . . . . . . . . . . . . . . . . . . . . . . . . 234 1 430364 794

RRC District 8A . . . . . . . . . . . . . . . . . . . . . . . . 212 - 3 55 58

RRC District 9 . . . . . . . . . . . . . . . . . . . . . . . . . 4 - 489 2 491

RRC District 10. . . . . . . . . . . . . . . . . . . . . . . . 5 6 471 33 505

State Offshore . . . . . . . . . . . . . . . . . . . . . . . . . - 2 54 3 57

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58 1 1,177 101 1,278

Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - - 165 - 165

West Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 - 427 1 428

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 9 3,075 60 3,136

Federal Offshoreb

. . . . . . . . . . . . . . . . . . . . . . . . . 1,355 234 7,941 3,093 11,034

Pacific (California) . . . . . . . . . . . . . . . . . . . . . . . 15 4 48 2068

Gulf of Mexico (Louisiana)b . . . . . . . . . . . . . . . . 1,133 1806,267 2,099 8,366

Gulf of Mexico (Texas) . . . . . . . . . . . . . . . . . . . . 207 50 1,625 975 2,600

Miscellaneousc

. . . . . . . . . . . . . . . . . . . . . . . . . . . 1 - - 1 1

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,206 418 31,235 5,639 36,873

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," 1999.

Energy Information Administration 93

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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 1999 by crude oil or

natural gas well operators who were active as of

December 31, 1999. 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 1992 and 1999, and depicts

the number of active operators, 1994 showing the

largest in the series. The 1999 sampling frame consisted

of 177 Category I, 399 Category II, 648 Category III

Certainty, and 20,865 Category III Noncertainty

operators, for a total of 22,089 active operators. The

survey sample consisted of 1,224 operators selected

with certainty that included all of the Category I and II

Certainty operators, the 648 smaller operators that

were selected with certainty because of their size in

relation to the area or areas in which they operated, and

1,305 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 1999 survey is

summarized in Table E2. EIA makes a considerable

effort to gain responses from all operators. About 3

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 88 nonoperators, 20 had successor operators that

had taken over the production of the nonoperator.

These successor operators were subsequently sampled.

The overall response rate for the 1999 survey was 94.1

percent. For the 146 operators that did not respond,

production data was obtained from State or other

sources.

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 1999 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 1999 Annual Report

Table E1. Comparison of the EIA-23 Sample and Sampling Frame, 1992-1999

Number of Operators

Operator Category 1992 1993 1994 1995 1996 1997 1998 1999

Certainty

Category I. . . . . . . . . . . . . 157 160 161 161 176 180 178 177

Category II . . . . . . . . . . . . 480 500 482 476 486 461 420 399

Category III............ 1,896 1,723 1,694 1,596 3 1,194 862 648

Sampled ............. 2,533 2,383 2,337 2,233 665 1,835 1,460 1,224

Percent Sampled . . . . . . . 100 100 100 100 100 100 100 100

Noncertainty

Sampled .............. 1,724 1,691 1,737 1,632 0 1,645 1,459 1,305

Percent Sampled ....... 8 8 8 8 0 8 7 6

Total

Active Operators........ R24,173 R23,656 R24,222 22,766 23,410 22,678 23,620 22,089

Not Sampled .......... 19,916 19,791 20,148 18,901 22,745 19,198 20,701 19,560

Sampled .............. 4,257 4,074 4,074 3,865 665 3,480 2,919 1,868

Percent Sampled . . . . . . . 18 17 17 17 3 15 12 8

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, 1999

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 . . . . . . . 177 3 10 -16 174 174 100.0 0 0.0

Category II . . . . . . . 399 17 -33 -17 366 366 100.0 0 0.0

Category III . . . . . . . 648 0 23 -21 650 591 90.9 59e 9.1

Subtotal......... 1,224 20 0 -54 1,190 1,131 95.0 59e 5.0

Noncertainty ........ 1,305 1 0 -34 1,272 1,185 93.2 87e 6.8

Total ............ 2,529 1 0 -88 2,462 2,316 94.1 146e 5.9

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.

eFor the 146 operators (59 CategoryIII operators and 87 Noncertainty operators) that did not respond, production data was obtained from State or other sources.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves” 1999.
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 1999, Form EIA-23 National estimates of

production were 2,151 million barrels for crude oil and

lease condensate or 4 million barrels (0.1 percent)

higher than that reported in the Petroleum Supply

Annual 1999 for crude oil and lease condensate. Form

EIA-23 National estimates of production for dry

natural gas were 18,928 billion cubic feet – 231 billion

cubic feet (1 percent) higher than the Natural Gas

Annual 1999 for 1999 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 1999 survey

mailing. These changes resulted from all frame

maintenance activities.

The Form EIA-23 operator frame contained a total of

68,501 entries as of December 29, 1999. Of these, 22,127

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 1999 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, 2000. In

addition, plant operators whose plants were shut down

or dismantled during 1999 were required to complete

forms for the portion of 1999 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

254 operators of 589 plants were sent forms. This

number included 3 new plants, 2 reactivated plants,

and 14 successor plants identified after the initial 1999

survey mailing. A total of 35 plants were reported as

nonoperating according to the Form EIA-64A

definition. For the twelfth 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 1999 Annual Report

Table E3. Summary of the 1999 Operator Frame

Activity, Form EIA-23

Total 1998 Operator Frame............. 68,468

Operators....................... 23,392

Nonoperators.................... 45,076

Changes to 1998 Operator Status...... 1,642

From Nonoperator to Operator . . . . . . 54

From Operator to Nonoperator ...... 1,588

No Changes to 1998 Operator Status . . . 66,826

Operators....................... 22,040

Nonoperators.................... 44,786

Additions to 1998 Operator Frame . . . . . 33

Operator . . . . . . . . . . . . . . . . . . . . . . . 33

Nonoperator..................... 0

Total 1999 Operator Frame............ 68,501

Operators....................... 22,127

Nonoperators.................... 46,374

Note: Includes operator frame activity through December 29, 1999.

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 1999,

the Form EIA-64A National estimates were 21 percent

(157 million barrels) higher than the Petroleum Supply

Annual 1999 volume for natural gas plant liquids

production.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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 1999 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, 1999.

Energy Information Administration

102 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report

Table E5. Form EIA-64A 1999 Plant Frame Activity

Frame as of 1998 survey mailing . . . . . . . 621

Additions . . . . . . . . . . . . . . . . . . . 159

Deletions ................... –191

Frame as of 1999 survey mailing . . . . . . . 589

Note: Includes operator frame activity through December 28, 1999.

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

Table E4. Natural Gas Processed and Liquids Extracted at Natural Gas Processing Plants, 1999

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 .................. 2,950,502 0 2,950,502 32,297

Alabama................. 308,008 1,484 309,492 12,586

Arkansas ................ 179,524 0 179,524 355

California ................ 259,518 0 259,518 8,848

Colorado ................ 444,894 84 444,978 19,047

Florida .................. 4,937 3,502 8,439 1,594

Illinois. . . . . . . . . . . . . . . . . . . 358 0 358 43

Kansas.................. 532,139 121,376 653,515 34,455

Kentucky ................ 44,064 0 44,064 1,691

Louisiana ................ 4,526,840 160,421 4,687,261 114,826

Michigan ................ 67,514 0 67,514 4,315

Mississippi ............... 3,661 132,112 135,773 4,149

Montana................. 5,211 0 5,211 337

North Dakota ............. 52,191 0 52,191 4,462

New Mexico .............. 872,842 959 873,801 74,570

Ohio .................... 2,933 0 2,933 61

Oklahoma ............... 883,517 8,879 892,396 65,212

Pennsylvania ............. 6,773 4,488 11,261 674

Texas................... 3,875,214 28,137 3,903,351 257,661

Utah .................... 205,709 5,805 211,514 7,974

West Virginia ............. 66,249 139 66,388 5,112

Wyoming ................ 902,365 524 902,889 36,593

Total ................... 16,194,963 467,910 16,662,873 686,862

aIncludes Illinois, Nebraska, Ohio, Pennsylvania, and Tennessee.

Source: Form EIA-64A, “Annual Report of the Origin of Natural Gas Liquids Production,” 1999.
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

1999 survey for each product class.

n 1.0 percent for National estimates.

n 1.0 percent for each of the 5 States having

subdivisions: Alaska, California, Louisiana,

New Mexico, and Texas. For selected

subdivisions within these States, targets of 1.0

percent or 1.5 percent as required to meet the

State target.

n 2.5 percent for each State/subdivision having 1

percent or more of estimated U.S. reserves or

production in 1998 (lower 48 States) for any

product class.

n 4 percent for each State/subdivision having less

than 1 percent of estimated U.S. reserves or

production in 1998 (lower 48 States) for all 3

product classes.

n 8 percent for States not published separately.

The combined production from these States was

less than 0.2 percent of the U.S. total in 1998 for

crude oil and for natural gas.

The volume of production defining the Certainty

stratum, referred to as the cutoff, varies by product or

State/subdivision. The cutoff criteria and sampling

rates are shown in Table F1. The Certainty stratum,

therefore, has three components.

n Category I - Large Operators: Operators who

produced a total of 1.5 million barrels or more of

crude, or 15 billion cubic feet or more of natural

gas, or both in 1999.

n Category II - Intermediate Operators: Operators

who produced a total of at least 400,000 barrels

of crude oil or 2 billion cubic feet of natural gas,

or both, but less than Category I operators in

1999.

n Category III - Small Operators: Operators who

produced less than the Category II operators in

1999, but which were selected with certainty.

Category III operators were subdivided into

operators sampled with certainty (Certainty)

and operators that were randomly sampled

(Noncertainty).

n Certainty - A small operators who satisfied

any of the following criteria based upon their

production shown in the operator frame:

· Operators with annual crude oil

production of 200 thousand barrels or

more, or reserves of 4 million barrels or

more; or annual natural gas production of

1 billion cubic feet or more, or reserves of

20 billion cubic feet or more.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 105
Table F1. 1999 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 61 2 0

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 11 0 0

Arkansas. . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 1,000 140 18 4

California Unspecified. . . . . . . . . . . . . . . . . . 17 88 38 34 1

California Coastal Region Onshore . . . . . . . 200 1,000 20 0 1

California Los Angeles Basin Onshore . . . . . 200 25 27 1 0

California San Joaquin Basin Onshore. . . . . 200 1,000 46 2 1

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 151 24 6

Florida Onshore . . . . . . . . . . . . . . . . . . . . . . 200 1,000 2 2 0

Illinois . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 27 43 71 5

Indiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 1 54 22 4

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85 1,000 199 147 15

Kentucky . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 1,000 34 42 5

Louisiana Unspecified. . . . . . . . . . . . . . . . . . 73 183 14 50 3

Louisiana North. . . . . . . . . . . . . . . . . . . . . . . 13 633 207 9 1

Louisiana South Onshore . . . . . . . . . . . . . . . 70 1,000 218 4 2

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 53 9 0

Mississippi Onshore . . . . . . . . . . . . . . . . . . . 200 1,000 115 9 2

Montana . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 82 11 2

Nebraska . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 2 56 5 1

New Mexico Unspecified. . . . . . . . . . . . . . . . 10 13 137 11 0

New Mexico East . . . . . . . . . . . . . . . . . . . . . 200 1,000 187 0 0

New Mexico West . . . . . . . . . . . . . . . . . . . . . 21 1,000 64 1 0

New York. . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 1,000 28 51 0

North Dakota. . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 88 4 2

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92 1,000 48 180 2

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . 143 1,000 355 263 25

Pennsylvania. . . . . . . . . . . . . . . . . . . . . . . . . 4 1,000 65 61 0

Texas Unspecified. . . . . . . . . . . . . . . . . . . . . 7 118 10 99 0

Texas-RRC District 1. . . . . . . . . . . . . . . . . . . 23 800 173 36 18

Texas-RRC District 2 Onshore . . . . . . . . . . . 200 1,000 205 10 14

Texas-RRC District 3 Onshore . . . . . . . . . . . 200 1,000 281 20 22

Texas-RRC District 4 Onshore . . . . . . . . . . . 91 1,000 202 7 15

Texas-RRC District 5. . . . . . . . . . . . . . . . . . . 38 630 119 7 8

Texas-RRC District 6. . . . . . . . . . . . . . . . . . . 200 1,000 199 19 8

Texas-RRC District 7B . . . . . . . . . . . . . . . . . 34 82 290 55 29

Texas-RRC District 7C . . . . . . . . . . . . . . . . . 200 1,000 216 15 24

Texas-RRC District 8. . . . . . . . . . . . . . . . . . . 200 1,000 272 25 21

Texas-RRC District 8A . . . . . . . . . . . . . . . . . 200 1,000 238 11 14

Texas-RRC District 9. . . . . . . . . . . . . . . . . . . 52 1,000 216 65 19

Texas-RRC District 10. . . . . . . . . . . . . . . . . . 200 1,000 188 31 7

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 65 6 1

Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 12 1 1

West Virginia. . . . . . . . . . . . . . . . . . . . . . . . . 5 1,000 76 34 1

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200 1,000 161 16 6

Offshore Areas . . . . . . . . . . . . . . . . . . . . . . . 0 0 286 0 0

Other Statesa . . . . . . . . . . . . . . . . . . . . . . . . 125 49 32 19 1

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . b1,724 1,509 b121

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 1999 Annual Report
- All other operators with production or

reserves in a State/subdivision that

exceed selected cutoff levels for that

State/subdivision.

- The largest operator in each

State/subdivision regardless of level of

production or reserves.

- Operators with production or reserves of

oil or gas for six or more

State/subdivisions.

n Noncertainties - Small operators not in the

certainty stratum were classified in a

noncertainty stratum.

- In most areas, data from the noncertainty

operators were sampled at a rate of 8

percent.

- In four States (Texas, California,

Louisiana, and New Mexico) EIA did not

survey the noncertainty operators in 1999.

Instead, a new imputation function was

applied to estimate reserves volumes. The

function used EIA historic production and

reserves data, State and commercially

available production data, and the size

classifications of reporting operators.

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 random sampling

proportional to size.

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 consisting of 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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 107
V$

sr = estimated total volume in the

State/subdivision of Noncertainty

operators.

The total volume of Certainty operators in the

State/subdivision is simply the sum of individual

operator's volumes:

V V sc

m

n

scm

sc

= =

∑

1

where

nsc = number of Certainty operators reporting

production in the State/subdivision

Vscm = 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 sampling 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

1999 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. A

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 1999 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.

Energy Information Administration

108 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report
Energy Information Administration 109

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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 12/31/98. . . . . . . . . . . . . 148,732,495 11,704,959 54,744 8,705 160,500,903

(+) Revision Increases . . . . . . . . . . . . . . . . . . . . 32,573,449 9,208,444 100,511 56,489 41,938,893

(–) Revision Decreases . . . . . . . . . . . . . . . . . . . 28,575,341 2,996,869 7,071 1,709 31,580,990

(+)Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . 6,271,113 813,319 0 0 7,084,432

(+) New Field Discoveries . . . . . . . . . . . . . . . . . 1,253,294 326,453 0 0 1,579,747

(+) New Reservoirs in Old Fields . . . . . . . . . . . . 1,680,270 454,447 0 0 2,134,717

(–) Production With Reserves in 1999 . . . . . . . . 16,218,949 2,013,038 17,183 4,390 18,253,560

Proved Reserves Reported as of 12/31/99. . . . . 145,716,341 17,497,716 131,001 59,095 163,404,153

Production Without Proved Reserves. . . . . . . . . 29,444 510,699 4,382 0 544,525

Reserves Imputed for Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 205,356 4,134,411 35,348 0 4,375,115

Subtotal Production . . . . . . . . . . . . . . . . . . . . . 16,248,393 2,523,737 21,565 4,390 18,798,085

Subtotal Proved Reserves 1999 . . . . . . . . . . . 145,921,697 21,632,127 166,349 59,095 167,779,268

State Level Reported and Imputed Data

Production With Proved Reserves . . . . . . . . . . . 0 0 112,958 48,281 161,239

Production Without Proved Reserves. . . . . . . . . 93 32,080 120,620 99,838 252,631

Production Estimated from Auxiliary Data . . . . . 0 0 576,759 0 576,759

Subtotal Production. . . . . . . . . . . . . . . . . . . . . . . 93 32,080 810,133 148,119 990,425

Weighted Subtotal Production . . . . . . . . . . . . 93 32,080 810,133 201,420 1,043,726

Proved Reserves Reported. . . . . . . . . . . . . . . . . 0 0 1,163,024 445,339 1,608,363

Reserves Imputed for Reported Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 679 347,293 4,559,148 1,497,537 6,404,657

Reserves Estimated from Auxiliary Data . . . . . . 0 0 3,735,072 0 3,735,072

Subtotal Proved Reserves . . . . . . . . . . . . . . . . . 679 347,293 5,722,172 1,942,876 8,013,020

Weighted Subtotal Proved Reserves . . . . . . . 679 347,293 5,722,172 1,942,876 8,013,020

Total Production in 1999. . . . . . . . . . . . . . . . . . . . 16,248,486 2,555,817 831,698 219,999 19,856,000

Total Proved Reserves as of 12/31/99 . . . . . . . . . 145,922,376 21,979,420 5,888,521 2,368,683 176,159,000

– = 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,” 1999.
110 Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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 12/31/98. . . . . . . . . . . . . 121,614,116 10,129,399 50,538 6,188 131,800,241

(+) Revision Increases . . . . . . . . . . . . . . . . . . . . 23,517,230 7,552,399 81,650 51,456 31,202,735

(–) Revision Decreases . . . . . . . . . . . . . . . . . . . 20,577,502 2,500,921 7,044 958 23,086,425

(+)Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . 5,741,639 791,613 0 0 6,533,252

(+) New Field Discoveries . . . . . . . . . . . . . . . . . 980,988 207,124 0 0 1,188,112

(+) New Reservoirs in Old Fields . . . . . . . . . . . . 1,501,800 257,025 0 0 1,758,825

(–) Production With Reserves in 1999 . . . . . . . . 13,540,667 1,645,093 15,729 3,774 15,205,263

Proved Reserves Reported as of 12/31/99. . . . . 119,237,615 14,791,547 109,415 52,912 134,191,489

Production Without Proved Reserves. . . . . . . . . 27,987 441,491 3,718 0 473,196

Reserves Imputed for Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 195,254 3,579,110 0 29,459 3,803,823

Subtotal Production . . . . . . . . . . . . . . . . . . . . . 13,568,654 2,086,584 19,447 3,774 15,678,459

Subtotal Proved Reserves 1999 . . . . . . . . . . . 119,432,869 18,370,657 109,415 52,912 137,965,853

State Level Reported and Imputed Data

Production With Proved Reserves . . . . . . . . . . . — — — — —

Production Without Proved Reserves. . . . . . . . . — — — — —

Production Estimated from Auxiliary Data . . . . . — — 864,541 — —

Subtotal Production. . . . . . . . . . . . . . . . . . . . . . . — — 864,541 — —

Weighted Subtotal Production . . . . . . . . . . . . — — 864,541 — —

Proved Reserves Reported. . . . . . . . . . . . . . . . . — — — — —

Reserves Imputed for Reported Production

Without Proved Reserves . . . . . . . . . . . . . . . . . — — — — —

Reserves Estimated from Auxiliary Data . . . . . . — — 6,778,147

Subtotal Proved Reserves . . . . . . . . . . . . . . . . . — — 6,778,147 — —

Weighted Subtotal Proved Reserves . . . . . . . — — 6,778,147 — —

Total Production in 1999. . . . . . . . . . . . . . . . . . . . 13,568,654 2,086,584 883,988 3,774 16,543,000

Total Proved Reserves as of 12/31/99 . . . . . . . . . 119,432,869 18,370,657 6,887,562 52,912 144,744,000

– = 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,” 1999.
Energy Information Administration 111

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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 12/31/98. . . . . . . . . . . . . 18,860,026 741,381 2,054 1,537 19,604,998

(+) Revision Increases . . . . . . . . . . . . . . . . . . . . 5,299,692 596,144 5,294 2,604 5,903,734

(–) Revision Decreases . . . . . . . . . . . . . . . . . . . 4,157,555 126,081 75 210 4,283,921

(+)Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . 230,211 8,206 0 0 238,417

New Field Discoveries . . . . . . . . . . . . . . . . . 206,812 114,514 0 0 321,326

(+) New Reservoirs in Old Fields . . . . . . . . . . . . 122,952 15,871 60 0 138,883

(–) Production With Reserves in 1999 . . . . . . . . 1,616,216 126,524 809 387 1,743,936

Proved Reserves Reported as of 12/31/99. . . . . 18,945,924 1,223,512 6,524 3,544 20,179,504

Production Without Proved Reserves. . . . . . . . . 743 28,579 698 0 30,020

Reserves Imputed for Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 5,975 235,271 5,598 0 246,844

Subtotal Production . . . . . . . . . . . . . . . . . . . . . 1,616,959 155,103 1,507 387 1,773,956

Subtotal Proved Reserves 1999 . . . . . . . . . . . 18,951,899 1,458,783 12,122 3,544 20,426,348

State Level Reported and Imputed Data

Production With Proved Reserves . . . . . . . . . . . 0 0 22,406 5,555 27,961

Production Without Proved Reserves. . . . . . . . . 0 5,094 28,810 16,356 50,260

Production Estimated from Auxiliary Data . . . . . . 0 0 83,639 0 83,639

Subtotal Production. . . . . . . . . . . . . . . . . . . . . . . 0 5,094 134,702 21,911 161,707

Weighted Subtotal Production . . . . . . . . . . . . 0 5,094 134,702 39,281 179,077

Proved Reserves Reported. . . . . . . . . . . . . . . . . 0 0 246,391 79,963 326,354

Reserves Imputed for Reported Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 0 61,768 714,585 218,753 995,106

Reserves Estimated from Auxiliary Data . . . . . . 0 0 559,169 0 559,169

Subtotal Proved Reserves . . . . . . . . . . . . . . . . . 0 61,768 960,976 298,716 1,321,460

Weighted Subtotal Proved Reserves . . . . . . . 0 61,768 960,976 298,716 1,321,460

Total Production in 1999. . . . . . . . . . . . . . . . . . . . 1,616,959 160,197 136,209 38,635 1,952,000

Total Proved Reserves as of 12/31/99 . . . . . . . . . 18,951,899 1,520,551 973,098 319,452 21,765,000

– = 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,” 1999.
112 Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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 12/31/98. . . . . . . . . . . . . 1,191,176 89,125 791 21 1,281,113

(+) Revision Increases . . . . . . . . . . . . . . . . . . . . 372,808 85,654 367 5 458,834

(–) Revision Decreases . . . . . . . . . . . . . . . . . . . 279,078 37,219 6 2 316,305

(+)Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . 44,694 4,125 0 0 48,819

(+) New Field Discoveries . . . . . . . . . . . . . . . . . 14,148 1,763 0 0 15,911

(+) New Reservoirs in Old Fields . . . . . . . . . . . . 32,083 3,163 0 0 35,246

(–) Production With Reserves in 1999 . . . . . . . . 168,321 20,016 121 10 188,468

Proved Reserves Reported as of 12/31/99. . . . . 1,207,508 126,595 1,031 14 1,335,148

Production Without Proved Reserves. . . . . . . . . 691 3,224 5 0 3,920

Reserves Imputed for Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 3,959 17,430 35 0 21,424

Subtotal Production . . . . . . . . . . . . . . . . . . . . . 169,012 23,240 126 10 192,388

Subtotal Proved Reserves 1999 . . . . . . . . . . . 1,211,467 144,025 1,066 14 1,356,572

State Level Reported and Imputed Data

Production With Proved Reserves . . . . . . . . . . . 0 0 690 209 899

Production Without Proved Reserves. . . . . . . . . 0 301 797 246 1,344

Production Estimated from Auxiliary Data . . . . . 0 0 6,192 0 6,192

Subtotal Production. . . . . . . . . . . . . . . . . . . . . . . 0 301 7,475 455 8,231

Weighted Subtotal Production . . . . . . . . . . . . 0 301 7,475 455 8,231

Proved Reserves Reported. . . . . . . . . . . . . . . . . 0 0 15,574 2,391 17,965

Reserves Imputed for Reported Production

Without Proved Reserves . . . . . . . . . . . . . . . . . 0 2,473 25,883 0 28,356

Reserves Estimated from Auxiliary Data . . . . . . 0 0 29,894 0 29,894

Subtotal Proved Reserves . . . . . . . . . . . . . . . . . 0 2,473 41,457 0 43,930

Weighted Subtotal Proved Reserves . . . . . . . 0 2,473 41,457 2,498 46,428

Total Production in 1999. . . . . . . . . . . . . . . . . . . . 169,012 23,541 7,601 465 200,619

Total Proved Reserves as of 12/31/99 . . . . . . . . . 1,211,467 146,498 42,523 2,512 1,403,000

– = 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,” 1999.
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

estimate the full noncertainty stratum when calculating

reserves and production as previously described in the

section “Total U.S. Reserves Estimates” in this

appendix.

R/P Function

A year-end proved reserves estimate was imputed

from reported production data in each case where an

estimate was not provided by the respondent. A R/P

function was derived and used to calculate a

reserves-to-production (R/P) ratio, based on operator

size and the geographic region where the operator’s

properties were located. The R/P function has the

following functional form for each geographic region:

Calculated R/P = Beta (Alpha + ln (1 + MOS))

- Alpha, Beta = Regional Coefficients

(calculated).

- MOS = Measure of size for a respondent,

which is equal to the barrel oil equivalent

volume of a respondent’s 1999 oil, gas,

and condensate production (in units of

thousand barrels per year).

Table F6 lists the coefficients used for each region and

the number of observations on which it was based. The

regional areas used are similar to the National

Petroleum Council Regions (Figure F1). These regions

generally follow the boundaries of geologic provinces

wherein the stage of resource development tends to be

somewhat similar.

Once the R/P ratio was obtained for an operator, it

could be multiplied by the reported or estimated

production to give a proved reserves estimate.

Operators that had R/P ratios equal to zero or that

exceeded 25 to 1 were excluded from the respondents

selected to calculate the R/P coefficients.

In 1999, the R/P function was used to estimate the

proved reserves of all noncertainty operators in four

States -- Texas, California, Louisiana, and New Mexico,

rather than rely on a sample. These four States were

chosen for this new procedure because EIA has many

years of production and reserves data for them, and

reliable State government and commercial production

data are available for these States. This technique

improved the correlation of EIA data with State and

commercial production data, and reduced the burden

of reporting and analysis on both EIA and the

noncertainty operators in these States.

In Region 5 (West Texas and East New Mexico) in 1999,

the average MOS of all noncertainty respondents was

149 thousand barrels of oil equivalent per year. Using

the coefficients in Table F6, the regional R/P for

noncertainty operators in Region 5 of average MOS size

was 7.9 for oil, 6.9 for natural gas, and 4.3 for lease

condensate. In 1998, the characteristic multipliers in

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 113

Table F6. Statistical Parameters of Reserve Estimation Equation by Region for 1999

Number of Nonzero Equation Coefficients

Region R/P Pairs Oil Gas LC

Number Region Oil Gas LC Alpha Beta Alpha Beta Alpha Beta

2 Pacific Coast States . . . . . . . . . . 40 47 4 2.89 0.95 17.08 0.29 11.00 0.40

3 Western Rocky Mountains. . . . . . . . 98 150 50 2.89 0.96 17.08 0.41 11.00 0.44

4 Northern Rocky Mountains . . . . . . . 193 153 42 2.89 0.84 17.08 0.41 11.00 0.26

5 West Texas and East New Mexico. . . . 575 556 160 2.89 1.01 17.08 0.31 11.00 0.27

6 + 6A Western Gulf Basin and Gulf of Mexico . 630 882 532 2.89 0.62 17.08 0.26 11.00 0.29

7 Mid-Continent . . . . . . . . . . . . . 394 475 174 2.89 0.85 17.08 0.38 11.00 0.40

8 + 9 Michigan Basin and Eastern Interior . . . 89 60 12 2.89 0.93 17.08 0.41 11.00 0.41

10 + 11 Appalachians. . . . . . . . . . . . . . 31 80 6 2.89 1.11 17.08 0.59 11.00 0.63

United States.............. 2,050 2,403 980 2.89 0.89 17.08 0.33 11.00 0.31

Source: Based on data filed on Form EIA-23,"Annual Survey of Domestic Oil and Gas Reserves, 1999".
Region 5 were 7.0 for oil, 7.1 for natural gas, and 6.5 for

lease condensate.

Imputation of Annual Changes to Proved

Reserves by Component of Change

Category II and Category III operators that do not keep

reserves data were not asked to provide estimates of

beginning-of-year reserves or annual changes to

proved reserves by component of change, i.e.,

revisions, extensions, and discoveries. When they did

not provide estimates, these volumes were estimated

by applying an algebraic allocation scheme which

preserved the relative relationships between these

items within each State/subdivision, as reported by

Category I and Category II operators, and also

preserved an exact annual reserves balance of the

following form:

A ratio was calculated as the sum of the annual

production and year-end proved reserves of those

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.

Energy Information Administration

114 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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
Imputation of Natural Gas Type Volumes

Operators in the State/subdivision certainty and

noncertainty strata were not asked to segregate their

natural gas volumes by type of natural gas, i.e.,

nonassociated natural gas (NA) and

associated-dissolved natural gas (AD). The total

estimated year-end proved reserves of natural gas and

the total annual production of natural gas reported by,

or imputed to, operators in the State/subdivision

certainty and noncertainty strata were, therefore,

subdivided into the NA and AD categories, by

State/subdivision, in the same proportion as was

reported by Category I and Category II operators in the

same area.

Adjustments

The instructions for Schedule A of Form EIA-23 specify

that, when reporting reserves balance data, the

following arithmetic equation must hold:

Any remaining difference in the State/subdivision

annual reserves balance between the published

previous year-end proved reserves and current

year-end proved reserves not accounted for by the

imputed reserves changes is included in the

adjustments for the area. One of the primary reasons

that adjustments are necessary is instability of the

Noncertainty operators sampled each year. About 24

percent of the Noncertainty stratum operators sampled

in 1998 were sampled again in 1999. There is no

guarantee that in the smaller States/subdivisions the

same number of small operators will be selected each

year, or that the operators selected will be of

comparable sizes when paired with operators selected

in a prior year. Thus, some instability of this stratum

from year to year is unavoidable, resulting in minor

adjustments.

Some of the adjustments are, however, more

substantial, and could be required for any one or more

of the following reasons:

n The frame coverage may or may not have

improved between survey years, such that more

or fewer Certainty operators were included in

1999 than in 1998.

n One or more operators may have reported data

incorrectly on Schedule A in 1998 or 1999, but

not both, and the error was not detected by edit

processing.

n Operation of properties was transferred during

1999 from operators not in the frame or

Noncertainty operators not selected for the

sample to Certainty operators or Noncertainty

operators selected for the sample.

n Operations of properties was transferred

during 1999 to an operator with a different

evaluation of the proved reserves associated

with the properties than that of the 1998

operator.

n Respondent changed classification of natural

gas from NA to AD or vice versa.

n The trend in reserve changes imputed for the

small operators, that was based on the trend

reported by the large operators, did not reflect

the actual trend for the small operators.

n Noncertainty operators, who have grown

substantially in size since they were added to

the frame, occasionally cause a larger standard

error than expected.

n The Noncertainty sample for either year in a

state may have been an unusual one.

The causes of adjustments are known for some but not

all areas. The only problems where effects cannot be

expected to balance over a period of several years are

those associated with an inadequate frame or those

associated with the trend in reserve changes for small

operators not being the same as those for large

operators. EIA continually attempts to improve

sources of operator data to avoid and/or resolve

problems in frame completeness.

Sampling Reliability of the Estimates

The sample of Noncertainty operators selected is only

one of a large number of possible samples that could

have been selected; each would have resulted in

slightly 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.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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
The estimated sampling error can be used to compute a

confidence interval around the survey estimate, with a

prescribed degree of confidence that the interval covers

the value that would have been obtained if all operators

in the frame had been surveyed. If the estimated

volume is denoted byV$

s and its sampling error by S.E. (

V$

s ), the confidence interval can be expressed as:

$ . .( $ V kSE V ) s s ±

where k is a multiple selected to provide the desired

level of confidence. For this survey, k was taken equal

to 2. Then there is approximately 95 percent confidence

that the interval:

$ . .( $ V SE V ) s s ± 2

includes the universe value, for both the estimates of

reserves and production volumes. Correspondingly,

for approximately 95 percent of the estimates in this

report, the difference between the published estimate

and the value that would be found from a complete

survey of all operators is expected to be less than twice

the sampling error of the estimate. Tables F7, F8, F9,

and F10 provide estimates for 2S.E. (V$

s ) by product.

These estimates are directly applicable for constructing

approximate 95 percent confidence intervals. For

example, the 95 percent confidence interval for dry

natural gas proved reserves is 164,041 ± 1,003 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.

Energy Information Administration

116 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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,

1999 (Billion Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

1999 1999 1999 1999

State and Subdivision Reserves Production State and Subdivision Reserves Production

United States . . . . . . . . . . . . . . . . . . 142 13

Alabama. . . . . . . . . . . . . . . . . . . . . . 45 10

Alaska . . . . . . . . . . . . . . . . . . . . . . . 0 0

Arkansas . . . . . . . . . . . . . . . . . . . . . 31 4

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 . . . . . . . . . . . . . . . . . . . . . 58 5

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

Kansas. . . . . . . . . . . . . . . . . . . . . . . 5 1

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

Louisiana . . . . . . . . . . . . . . . . . . . . . 0 0

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

South Onshore . . . . . . . . . . . . . . 0 0

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

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

Mississippi . . . . . . . . . . . . . . . . . . . . 10 2

Montana. . . . . . . . . . . . . . . . . . . . . . 7 1

New Mexico . . . . . . . . . . . . . . . . . . . 0 0

East. . . . . . . . . . . . . . . . . . . . . . . 0 0

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

New York . . . . . . . . . . . . . . . . . . . . . 12 1

North Dakota . . . . . . . . . . . . . . . . . . 0 0

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . 62 5

Oklahoma . . . . . . . . . . . . . . . . . . . . 34 3

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

Texas . . . . . . . . . . . . . . . . . . . . . . . . 0 0

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

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

RRC District 3 Onshore . . . . . . . 0 0

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

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

Utah . . . . . . . . . . . . . . . . . . . . . . . . . 0 0

Virginia. . . . . . . . . . . . . . . . . . . . . . . 0 0

West Virginia . . . . . . . . . . . . . . . . . . 80 4

Wyoming . . . . . . . . . . . . . . . . . . . . . 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, 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,” 1999 and Form

EIA-64A, “Annual Report of the Origin of Natural Gas Liquids Production,” 1999.

Table F8. Factors for Confidence Intervals (2S.E.) for Natural Gas Proved Reserves and Production,

Wet After Lease Separation, 1999 (Billion Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

1999 1999 1999 1999

State and Subdivision Reserves Production State and Subdivision Reserves Production

United States . . . . . . . . . . . . . . . . . . 147 14

Alabama. . . . . . . . . . . . . . . . . . . . . . 55 13

Alaska . . . . . . . . . . . . . . . . . . . . . . . 0 0

Arkansas . . . . . . . . . . . . . . . . . . . . . 31 4

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 . . . . . . . . . . . . . . . . . . . . . 63 6

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

Kansas. . . . . . . . . . . . . . . . . . . . . . . 6 1

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

Louisiana . . . . . . . . . . . . . . . . . . . . . 0 0

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

South Onshore . . . . . . . . . . . . . . 0 0

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

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

Mississippi . . . . . . . . . . . . . . . . . . . . 10 2

Montana. . . . . . . . . . . . . . . . . . . . . . 7 1

New Mexico . . . . . . . . . . . . . . . . . . . 0 0

East. . . . . . . . . . . . . . . . . . . . . . . 0 0

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

New York . . . . . . . . . . . . . . . . . . . . . 12 1

North Dakota . . . . . . . . . . . . . . . . . . 2 0

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . 63 5

Oklahoma . . . . . . . . . . . . . . . . . . . . 36 3

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

Texas . . . . . . . . . . . . . . . . . . . . . . . . 0 0

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

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

RRC District 3 Onshore . . . . . . . 0 0

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

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

Utah . . . . . . . . . . . . . . . . . . . . . . . . . 3 1

Virginia. . . . . . . . . . . . . . . . . . . . . . . 0 0

West Virginia . . . . . . . . . . . . . . . . . . 82 4

Wyoming . . . . . . . . . . . . . . . . . . . . . 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, 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,” 1999.
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, 1999

(Million Barrels of 42 U.S. Gallons)

1999 1999 1999 1999

State and Subdivision Reserves Production State and Subdivision Reserves Production

United States . . . . . . . . . . . . . . . . . . 24 2

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

Alaska . . . . . . . . . . . . . . . . . . . . . . . 0 0

Arkansas . . . . . . . . . . . . . . . . . . . . . 2 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 . . . . . . . . . . . . . . . . . . . . . 4 0

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

Illinois. . . . . . . . . . . . . . . . . . . . . . . . 5 0

Indiana. . . . . . . . . . . . . . . . . . . . . . . 1 0

Kansas. . . . . . . . . . . . . . . . . . . . . . . 5 1

Kentucky . . . . . . . . . . . . . . . . . . . . . 10 0

Louisiana . . . . . . . . . . . . . . . . . . . . . 0 0

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

South Onshore . . . . . . . . . . . . . . 0 0

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

Michigan . . . . . . . . . . . . . . . . . . . . . 1 0

Mississippi . . . . . . . . . . . . . . . . . . . . 2 0

Montana. . . . . . . . . . . . . . . . . . . . . . 4 0

Nebraska . . . . . . . . . . . . . . . . . . . . . 1 0

New Mexico . . . . . . . . . . . . . . . . . . . 0 0

East. . . . . . . . . . . . . . . . . . . . . . . 0 0

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

North Dakota . . . . . . . . . . . . . . . . . . 8 1

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . 4 1

Oklahoma . . . . . . . . . . . . . . . . . . . . 15 1

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 . . . . . . . . . . . . . . . . . . . . . . . . 5 1

West Virginia . . . . . . . . . . . . . . . . . . 6 0

Wyoming . . . . . . . . . . . . . . . . . . . . . 0 0

Federal Offshore . . . . . . . . . . . . . . . 0 0

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

Gulf of Mexico (Louisiana) . . . . . 0 0

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

Miscellaneousa . . . . . . . . . . . . . . . . 0 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,” 1999.

Table F10. Factors for Confidence Intervals (2S.E.) for Lease Condensate Proved Reserves and

Production, 1999 (Million Barrels of 42 U.S. Gallons)

1999 1999 1999 1999

State and Subdivision Reserves Production State and Subdivision Reserves Production

United States . . . . . . . . . . . . . . . . . . 1 0

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. . . . . . . . . . . . . . . . . . . . . . . 0 0

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

Louisiana . . . . . . . . . . . . . . . . . . . . . 0 0

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

South Onshore . . . . . . . . . . . . . . 0 0

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

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

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

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

New Mexico . . . . . . . . . . . . . . . . . . . 0 0

East. . . . . . . . . . . . . . . . . . . . . . . 0 0

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

North Dakota . . . . . . . . . . . . . . . . . . 0 0

Oklahoma . . . . . . . . . . . . . . . . . . . . 1 0

Texas . . . . . . . . . . . . . . . . . . . . . . . . 0 0

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

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

RRC District 3 Onshore . . . . . . . 0 0

RRC District 4 Onshore . . . . . . . 0 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 . . . . . . . . . . . . . . 0 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,” 1999.
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,

8.3 percent of the crude oil proved reserve estimates,

8.2 percent of the natural gas proved reserve estimates,

and 5.7 percent of the lease condensate proved reserve

estimates resulted from the imputation and estimation

of reserves for those Certainty and Noncertainty

operators who did not provide estimates for all of their

properties, in combination with the expansion of the

sample of Noncertainty operators to the full

population. Errors for the latter were quantitatively

calculated, as discussed in the previous section.

Standard errors, for the former, would tend to cancel

each other from operator to operator, and are,

therefore, expected to be negligible, especially at the

National level of aggregation. In States where a large

share of total reserves is accounted for by Category III

and smaller Category II operators, the errors are

expected to be somewhat larger than in States where a

large share of total reserves is accounted for by

Category I and larger Category II operators.

Frame Coverage Errors

Of all the sources of controllable error connected with

the Form EIA-23 survey, errors in the operator frame

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 1999 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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report 119
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. The 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 1999

Form EIA-64A survey, the national weighted average

gas equivalents ratio was computed to be 1,406 cubic

feet of natural gas shrinkage per barrel of NGL

recovered. The total shrinkage volume (reported plus

imputed) for all plants reporting a given area of origin

was then subtracted from the estimated value of

natural gas production, wet after lease separation,

yielding dry natural gas production for the area. The

amount of the reduction in the wet natural gas

production was then expressed as a percentage of the

wet natural gas production. Dry natural gas reserves

and reserve changes were determined by reducing the

wet natural gas reserves and reserve changes by the

same percentage reduction factor.

A further refinement of the estimation process was

used to generate an estimate of the natural gas liquids

reserves in those States with coalbed methane fields.

The States where this procedure was applied were

Alabama, Colorado, Kansas, New Mexico, Oklahoma,

Pennsylvania, Utah, Virginia, West Virginia, and

Wyoming. The first step in the process was to identify

all Form EIA-23 reported coalbed methane fields. The

assumption was made that coalbed methane fields

contained little or no extractable natural gas liquids.

Therefore, when the normal shrinkage procedure was

applied to the wet gas volume reserve components, the

estimate of State coalbed methane volumes were

excluded and were not reduced for liquid extraction.

Following the computation for shrinkage, each coalbed

field gas volume reserve components was added back

to each of the dry gas volume reserve components in a

State. The effect of this is that the large increases in

reserves in some States from coalbed methane fields

did not cause corresponding increases in the State

natural gas liquids proved reserves.

Adjustments of dry natural gas were set equal to the

difference between the end of previous year reserves

estimates, based upon the current report year Form

EIA-23 and Form EIA-64A surveys, and the end of

current year reserve estimates published in the

preceding year's annual reserves report.

Each estimate of end of year reserves and report year

production has associated with it an estimated

sampling error. The standard errors for dry natural gas

were computed by multiplying the wet natural gas

standard errors by these same percentage reduction

factors. Table F7 provides estimates for 2 times the

SE Vs . .($ ) for dry natural gas.

Energy Information Administration

120 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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 1999 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 1999 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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, 1999)............................... 16,865 b157,672 7,515

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 .............................................. 112,922 1,175,197 NA

Alaska

Discovered

Proved Reserves (EIA, 1999)............................... 4,900 9,734 299

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 .............................................. 51,040 236,744 NA

Total Lower 48 States and Alaska............................. 163,962 1,411,941 32,333

Deductions for Production and Proved Reserves Changes,

1991-1999 ............................................. -13,461 -133,119 -6,684

U.S. Total, 1999 ............................................ 150,501 1,278,822 25,649

a Condensate is included with crude oil for MMS estimates in Federal Offshore regions. b Includes 13,229 billion cubic feet of coalbed methane (EIA, 1999). 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.{39} They are similarly defined by the MMS,

although its system also subdivides them by degree of

development and producing status.{40} 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 1999 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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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 1999 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 1999 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 1999 Annual Report 133

Maps of Selected State Subdivisions

SOUTH OFFSHORE

PACIFIC OCEAN

GULF OF

ALASKA

SOUTH

NORTH

(INCLUDES ALL OFFSHORE)

ARCTIC OCEAN

CHUKCHI SEA

BERING SEA

MIDDLETON

ISLAND

BLYING

SOUND

ICY BAY

BERING

GLACIER

MCCARTHY

NABESNA

TANACROSS

EAGLE

CHARLEY

RIVER

BLACK

RIVER

COLEEN

TABLE

MTN.

DEMARCATION

POINT

BARTER

ISLAND

MT. ST. ELIAS

VALDEZ

GULKANA

MT. HAYES

BIG DELTA

CIRCLE

FORT

YUKON

ARCTIC

CHRISTIAN

MT

MICHELSON

FLAXMAN

ISLAND

ANCHORAGE

TALKEETNA

MTS.

HEALY

FAIRBANKS

LIVENGOOD

BEAVER

CHANDALAR

PHILIP

SMITH

MTS.

BEECHEY

PT.

Seldovia

KENAI

TYONEK

TALKEETNA

MT.

MCKINLEY

KANTISHNA

RIVER

TANANA

BETTLES

WISEMAN

CHANDLER

LAKE

UMIAT

KAGUYAK

KODIAK

TRINITY

ISLANDS

KARLUK

MT.

KATMAI

ILIAMNA

LAKE CLARK

LIME HILLS

MCGRATH

MEDFRA

RUBY

MELOZITNA

HUGHES

SURVEY

PASS

KILLIK

RIVER

IKPIKPUK

RIVER

TESHEKPUK

BARROW

SUTWIK

ISLAND

UGASHIK

NAKNEK

DILLINGHAM

TAYLOR

MTS.

SLEETMUTE

IDITAROD

OPHIR

NULATO

KATEEL

RIVER

SHUNGNAK

AMBLER

RIVER

HOWARD

PASS

LOOKOUT

RIDGE

MEADE

RIVER

BRISTOL

BAY

GOODNEWS

BETHEL

RUSSIAN

MISSION

HOLY

C ROSS

URALAKLEET

NORTON

BAY

CANDLE

SELAWIK

BAIRD

MTS.

UTUKOK

RIVER

POINT

LAY

DELONG

MTS.

KOTZEBUE

BENDELEBEN

SOLOMON

ST. MICHAEL

KWIGUK

MARSHALL

BAIRD

INLET

KUSKOKWIM BAY

BLACK

HOOPER

BAY

NUNIVAK

ISLAND

CAPE

MENDENHALL

PRIBILOF

ISLANDS

ST. MATTHEW

NOME

TELLER

SHISHMAREF

AMUKTA

UMNAK

SAMALGA

ISLAND

UNALASKA

UNIMAK

FALSE SIMEONOF

ISLAND

COLD

BAY

PORT

MOLLER

ATTU

KISKA

RAT

ISLANDS

Gareloi

Island ADAK

Atka SEGUAM

ATLIN

TAKU

RIVER

PETERSBURG

BRADFIELD

CANAL

CRAIG

KETCHikan

PRINCE

DIXON

RUPERT ENTRANCE

FAIRBANKS

JUNEAU

ST. LAWRENCE

BARROW

PASS

NUSHAGAK BAY

NOATAK

SKAGWAY

HARRISON

BAY

AFOGNAK

CHIGNIK

HAGEMEISTER ISLAND

CORDOVA

SEWARD

SAGAVANIRKTOK

WAINWRIGHT

JUNEAU

SUMDUM

ANCHORAGE

POINT

HOPE

NOME

PORT ALEXANDER

SITKA

MT. FAIRWEATHER

STEPOVAK BAY

MISHEGUK MTN.

YAKUTAT

Alaska - South State Offshore .............

Alaska - South Federal Offshore .........

Alaska - South Onshore ......................

Offshore .................................

Alaska - North Onshore and

ALASKA

(1:250,000 - SCALE QUADRANGLES)

AK 50

AK 10

AK 05

AK 00
Figure 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 1999 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 1999 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 1999 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 1999 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 Wheeler

Randall Armstrong Donley

Bailey

Cochran

Castro

Swisher Briscoe Hall Childress

Lamb Hale Floyd Motley Cottle

Crosby Dickens King

Terry Lynn Garza Kent Stonewall

Wil

Barger Wichita Clay

Montague Cooke

Foard

Knox Baylor Archer

Young

Bowie

Hockley

Lubbock

Dawson

Haskell

Throckmorton

ugio houn

CalGonzales

Jackson

Jack Wise Denton Collin

Parker Tarrant Dallas

Hood Johnson Ellis

Hill

Coryell

Navarro

Limestone

Freestone

Leon

Kaufman Van

Zandt

Henderson

Anderson

Houston

Cherokee

Hunt

Wood

Smith

Lamar Red

River

Hopkins Cass

Marion

Harrison

Panola

Shelby

Upshur

Camp

Franklin

Titus

Morris

Rusk

Angelina Jasper

Chambers

Jefferson

Brown

Comanche

Mills

San

Saba

Hamilton

Delta

Gregg

Grayson

Sabine

Newton

Orange

Grimes

Austin

Collingsworth

Coleman

Howard Mitchell

Brooks

Bastrop

Aransas

San

Augustine

Madison

Brazos

Robertson

Kendall

Guadalupe

Nacogdoches

ler

WalMcLennan

Caldwell

Karnes

Parmer

Yoakum

Cameron

Rockwall Rains

Hardeman

Fannin

7C Schleicher

Texas- Railroad Commission District 1 ............. TX 10

Texas- Railroad Commission District 2

Onshore ................................................. TX 20

Texas- Railroad Commission District 3

Onshore ................................................. TX 30

Texas- Railroad Commission District 4

Onshore .................................................. TX 40

Texas- Railroad Commission District 5 ............ TX 50

Texas- Railroad Commission District 6 ............ TX 60

Texas- Railroad Commission District 7B ......... TX 70

Texas- Railroad Commission District 7C ......... TX 75

Texas- Railroad Commission District 8 ........... TX 80

Texas- Railroad Commission District 8A ......... TX 85

Texas- Railroad Commission District 9 ........... TX 90

Texas- Railroad Commission District 10 ......... TX 95

Texas- State Offshore ....................................... TX 05

Texas- Federal Offshore ................................... TX 00
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 1999 Annual Report
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 1999 Annual Report 139
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 1999 Annual Report
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. 1999 ANNUAL S URVEY OF DOMES TIC OIL AND GAS RES ERVES U.S . DEPARTMENT OF ENERGY CALENDAR YEAR 1 999 Form Approve d OMB No. 1905-0057 Expire s 12/31/2000 This re port is ma nda tory unde r Public La w 93-275. Fa ilure to comply ma y re s ult in crimina l fine s , civil pe na ltie s a nd othe r s a nctions a s provide d by law. For the s a nctions a nd the provis ions conce rning the confide ntia lity of informa tion s ubmitte d on this form, s e e pa ge 2 of the Ins tructions . Public re porting burde n for this colle ction of informa tion is e s tima te d to a ve ra ge from 62 to 333 hours pe r re s pons e , including the time of re vie wing ins tructions , s e a rching e xis ting da ta s ource s , ga the ring a nd ma inta ining the da ta ne e de d, a nd comple ting a nd re vie wing the colle ction of informa tion. S e nd comme nts re ga rding this burde n e s tima te or a ny othe r a s pe ct of this colle ction of informa tion, including s ugge s tions for re ducing this burde n, to the Ene rgy Informa tion Adminis tra tion, S ta tis tica l Me thods Group EI-70, Wa s hington, DC 20585; a nd to the Office of Informa tion a nd Re gula tory Affa irs , Office of Ma na ge me nt a nd Budge t, Wa s hington, DC 20503. COVER PAGE IDENTIFICATION 1 . Were you an operator (s e e d e fin itio n o f a n o p e ra to r, p .1) of one or more oil or gas wells on December 31 , 1 999? (1)

 No... Co m p le te o nly ite m s 3 th ro ug h 22 b e lo w a nd re turn th is p a g e w ith a le tte r s ta ting w h e n o p e ra tio ns c e a s e d a nd

2. I.D. Code FOR DOE US E ONLY

w h a t b e c a m e o f th e w e lls y o u o p e ra te d to U. S . Department of Energy Was hington, DC 20585

(2)

 Ye s ... Co m p le te th e a tta c h e d fo rm s a nd re turn th e m to U. S . Department of Energy Was hington, DC 20585 0000

If info rm a tio n to th e le ft is inc o rre c t o r is m is s ing , e nte r c o rre c t info rm a tio n b e lo w .

3. Na me

4. Addre s s

5. City 6. S ta te 7. Zip Code

8. EIN Che ck if Atte s tor's

 S ocia l S e curity Numbe r

9. Na me of Conta ct Pe rs on

10. Te le phone Numbe r of Conta ct Pe rs on Are a Code ( ) ______- ___________

PARENT COMPANY IDENTIFICATION

11. Is the re a pa re nt compa ny which e xe rcis e s ultima te control ove r 12. Na me

your company?

(1)

 No... Ans we r 18 thru 22

13. Addre s s

(2)

 Ye s ... Ans we r 12 thru 22 14. City 15. S ta te 16. Zip Code

17. Pa re nt Compa ny EIN

18. Wha t is the tota l numbe r of pa ge s (including this pa ge ) s ubmitte d in this filing?

ATTES TATION

(Th is re p o rt m u s t b e a tte s te d to b y a re s p o n s ib le o ffic ia l o f th e c o m p a n y .)

I he re by s we a r or a ffirm tha t I ha ve re a d the re port a nd a m fa milia r with its conte nts , a nd tha t to the be s t of my knowle dge , informa tion, a nd be lie f, the informa tion provide d a nd

a ppe nde d is true a nd comple te .

19. Na me of Atte s tor (P le a s e p rin t) 21. S igna ture

20. Title 22. Da te

Title 1 8 US C 1 001 makes it a criminal offens e for any pers on knowingly and willingly to make to any Agency or

Department of the United S tates any fals e, fictitious or fraudulent s tatements as to any matter within its juris diction

FOR AS S IS TANCE CALL 1 -800-879-1 470

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. 1999 ANNUAL S URVEY OF DOMES TIC OIL AND GAS RES ERVES S UMMARY REPORT PAGE 1 OF 2 (Re port All Volume s of Crude Oil a nd Le a s e Conde ns a te in Thous a nds of Ba rre ls [Mbbl]; Form Approve d OMB No. 1905-0057 Expire s 12/2000 1.0 OPERATOR AND REPORT IDENTIFICATION DATA Re port All Volume s of Na tura l Ga s in Millions of Cubic Fe e t [MMcf] a t 14.73 ps ia a nd 60°F) 1.1 OPERATOR I.D. CODE 1.2 OPERATOR NAME REPORT DATE 1.3 ORIGINAL 1.4 AMENDED 12 31 99 2.0 PRODUCTION AND RES ERVES DATA CRUDE OIL NATURAL GAS LEAS E CONDENS ATE S TATE OR RES ERVES 1 999 PRODUCTION RES ERVES 1 999 PRODUCTION RES ERVES 1 999 PRODUCTION GEOGRAPHIC S UBDIVIS ION Prove d Re s e rve s De c. 31, 1999 (Mbbl) (A) (From prope rtie s for which re s e rve s we re Es tima te d) (Mbbl) (B) (From prope rtie s for which re s e rve s we re Not Es tima te d) (Mbbl) (C) Prove d Re s e rve s De c. 31, 1999 (MMcf) (D) (From prope rtie s for which re s e rve s we re Es tima te d) (MMcf) (E) (From prope rtie s for which re s e rve s we re Not Es tima te d (MMcf) (F) Prove d Re s e rve s De c. 31, 1999 (Mbbl) (G) (From prope rtie s for which re s e rve s we re Es tima te d) (Mbbl) (H) (From prope rtie s for which re s e rve s we re Not Es tima te d) (Mbbl) (I) ALABAMA-ONS HOR E AL ALABAMA-S TATE OFFS HOR E AL05 ALAS KA-NOR TH ONS HOR E AND OFFS HOR E AK5 0 ALAS KA-S OUTH ONS HOR E AK1 0 ALAS KA-S OUTH S TATE OFFS HOR E AK0 5 AR IZONA AZ AR KANS AS AR

C ALIFOR NIA-C OAS TAL R EGION ONS HOR E CA50C ALIFOR NIA-LOS ANGELES BAS IN ONS HOR E CA90C ALIFOR NIA-S AN J OAQUIN BAS IN ONS HOR E CA10C ALIFOR NIA-S TATE OFFS HOR E CA05C OLOR ADO C OFLOR IDA-ONS HOR E FLFLOR IDA-S TATE OFFS HOR E FL05ILLINOIS ILINDIANA INKANS AS KSKENTUC KY KYLOUIS IANA-NOR TH LA50LOUIS IANA-S OUTH ONS HOR E LA10LOUIS IANA-S OUTH S TATE ONS HOR E LA05MAR YLAND MDMIC HIGAN MIMIS S IS S IP P I-ONS HOR E MSMIS S IS S IP P I-S TATE OFFS HOR E MS 05MIS S OUR I MOMONTANA MTNEBR AS KA NENEVADA NVNEW MEXIC O-EAS T NM1 0NEW MEXIC O-W ES T NM5 0NEW YOR K NYNOR TH 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. 1999 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 99 2.0 PRODUCTION AND RESERVES DATA CRUDE OIL NATURAL GAS LEASE CONDENSATE STATE OR RESERVES 1999 PRODUCTION RESERVES 1999 PRODUCTION RESERVES 1999 PRODUCTION GEOGRAPHIC SUBDIVISION Proved Reserves Dec. 31, 1999 (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, 1999 (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, 1999 (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 TX40 TEXAS-RRC DISTRICT 5 TX50

TEXAS-RRC DISTRICT 6 TX60

TEXAS-RRC DISTRICT 7B TX70

TEXAS-RRC DISTRICT 7C TX75

TEXAS-RRC DISTRICT 8 TX80

TEXAS-RRC DISTRICT 8A TX85

TEXAS-RRC DISTRICT 9 TX90

TEXAS-RRC DISTRICT 10 TX95

TEXAS-STATE OFFSHORE TX05

UTAH UT

VIRGINIA VA

WEST VIRGINIA WV

WYOMING WY

FEDERAL OFFSHORE-GULF OF MEXICO (ALABAMA) AL00

FEDERAL OFFSHORE-GULF OF MEXICO (FLORIDA) FL00

FEDERAL OFFSHORE-GULF OF MEXICO (LOUISIANA) LA00

FEDERAL OFFSHORE-GULF OF MEXICO

(MISSISSIPPI)

MS00

FEDERAL OFFSHORE-GULF OF MEXICO (TEXAS) TX00

FEDERAL OFFSHORE-PACIFIC (ALASKA) AK00

FEDERAL OFFSHORE-PACIFIC (CALIFORNIA) CA00

FEDERAL OFFSHORE-PACIFIC (OREGON) OR00

OTHER 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. 1999 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 99 2.0 FIELD DATA (OPERATED BASIS) 1. STATE ABBR. 2. SUBDIV. CODE 3. COUNTY CODE 4. FIELD CODE 5. OCS BLOCK NUMBER 6. FIELD NAME 7. Calendar Year PRODUCTION From Properties For which RESERVES Were NOT ESTIMATED 8. FOOTNOTE 2.1 CRUDE OIL (a) (Mbbl) ASSOC-DISSOLVED (b) GAS (MMcf) NONASSOCIATED (c) GAS (MMcf) LEASE CON- (d) DENSATE (Mbbl) 9. WATER DEPTH 10. FIELD DISCOVERY YEAR 11. INDICATED ADDITIONAL RESERVES OF CRUDE OIL (Mbbl) TYPE HYDROCARBON RESERVES (a) DECEMBER 31, 1998 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, 1999 NONPRODUCING (i) RESERVES 12. CRUDE OIL (Mbbl) 13. ASSOCIATED-DISSOLVED GAS(MMcf) 14. NONASSOCIATED GAS (MMcf) 15. LEASE CONDENSATE (Mbbl) 1. STATE ABBR. 2. SUBDIV. CODE 3. COUNTY CODE 4. FIELD CODE 5. OCS BLOCK NUMBER 6. FIELD NAME 7. Calendar Year PRODUCTION From Properties For which RESERVES Were NOT ESTIMATED 8. FOOTNOTE 2.2 CRUDE OIL (a) (Mbbl) ASSOC-DISSOLVED (b) GAS (MMcf) NONASSOCIATED (c) GAS (MMcf) LEASE CON- (d) DENSATE (Mbbl) 9. WATER DEPTH 10. FIELD DISCOVERY YEAR 11. INDICATED ADDITIONAL RESERVES OF CRUDE OIL (Mbbl)

TYPE HYDROCARBON

RESERVES

(a) DECEMBER 31, 1998

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, 1999

NONPRODUCING

(i) RESERVES

12. CRUDE OIL (Mbbl)

13. ASSOCIATED-DISSOLVED GAS(MMcf)

14. NONASSOCIATED GAS (MMcf)

15. LEASE CONDENSATE (Mbbl)

1. STATE

ABBR.

2. SUBDIV.

CODE

3. COUNTY

CODE

4. FIELD

CODE

5. OCS BLOCK

NUMBER 6. FIELD NAME 7. Calendar Year PRODUCTION From Properties For which RESERVES Were NOT ESTIMATED 8. FOOTNOTE

2.3 CRUDE OIL (a) (Mbbl) ASSOC-DISSOLVED (b) GAS (MMcf) NONASSOCIATED (c) GAS (MMcf) LEASE CON- (d) DENSATE (Mbbl)

9. WATER DEPTH 10. FIELD DISCOVERY YEAR 11. INDICATED ADDITIONAL RESERVES OF CRUDE OIL (Mbbl)

TYPE HYDROCARBON

RESERVES

(a) DECEMBER 31, 1998

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, 1999

NONPRODUCING

(i) RESERVES

12. CRUDE OIL (Mbbl)

13. ASSOCIATED-DISSOLVED GAS(MMcf)

14. NONASSOCIATED GAS (MMcf)

15. LEASE CONDENSATE (Mbbl)

1. STATE

ABBR.

2. SUBDIV.

CODE

3. COUNTY

CODE

4. FIELD

CODE

5. OCS BLOCK

NUMBER 6. FIELD NAME 7. Calendar Year PRODUCTION From Properties For which RESERVES Were NOT ESTIMATED 8. FOOTNOTE

2.4 CRUDE OIL (a) (Mbbl) ASSOC-DISSOLVED (b) GAS (MMcf) NONASSOCIATED (c) GAS (MMcf) LEASE CON- (d) DENSATE (Mbbl)

9. WATER DEPTH 10. FIELD DISCOVERY YEAR 11. INDICATED ADDITIONAL RESERVES OF CRUDE OIL (Mbbl)

TYPE HYDROCARBON

RESERVES

(a) DECEMBER 31, 1998

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, 1999

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. 1999 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 99 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

U.S. DEPARTMENT OF ENERGY

ENERGY INFORMATION ADMINISTRATION

Washington, D.C. 20585

Form Approved

OMB No. 1905-0057

Expiration Date: 12/31/00

ANNUAL REPORT OF THE ORIGIN OF NATURAL GAS LIQUIDS PRODUCTION

FORM EIA-64A

CALENDAR YEAR 1999

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

Fax Number: ( ) - E-mail address:

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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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

Energy Information Administration

152 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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 1999 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 1999 Annual Report
information on fluid contacts, the lowest known

structural occurrence of hydrocarbons is considered

to be the lower proved limit of the reservoir.

Volumes of natural gas placed in underground

storage are not to be considered proved reserves.

For natural gas, wet after lease separation, an

appropriate reduction in the reservoir gas volume

has been made to cover the removal of the

liquefiable portions of the gas in lease and/or field

separation facilities and the exclusion of

nonhydrocarbon gases where they occur in sufficient

quantity to render the gas unmarketable.

For dry natural gas, an appropriate reduction in the

gas volume has been made to cover the removal of

the liquefiable portions of the gas in lease and/or

field separation facilities, and in natural gas

processing plants, and the exclusion of

nonhydrocarbon gases where they occur in sufficient

quantity to render the gas unmarketable.

It is not necessary that production, gathering, or

transportation facilities be installed or operative for a

reservoir to be considered proved. It is to be

assumed that compression will be initiated if and

when economically justified.

Proved Reserves of Natural Gas Liquids: Proved

reserves of natural gas liquids as of December 31 of

the report year are those volumes of natural gas

liquids (including lease condensate) demonstrated

with reasonable certainty to be separable in the

future from proved natural gas reserves, under

existing economic and operating conditions.

Proved Ultimate Recovery: The sum of proved

reserves and cumulative production. It is expected to

change over time for any field, group of fields, State,

or Country. Proved Ultimate Recovery does not

represent the maximum recoverable volume of

resources for an area. It is instead a gauge of how

much has already been produced plus proved

reserves. Proved reserves of crude oil or natural gas

are the estimated quantities of petroleum which

geological and engineering data demonstrate with

reasonable certainty to be recoverable in future years

from known reservoirs under existing economic and

operating conditions. When deterministic proved

reserves estimation methods are used, the term

reasonable certainty is intended to express a high

degree of confidence that the estimated quantities

will be recovered. When probabilistic methods are

used there should be at least a 90 percent probability

that the actual quantities recovered will exceed the

estimate.

Report Year: The calendar year to which data

reported in this publication pertain.

Reserves: (See Proved Reserves)

Reserve Additions: Consist of adjustments, net

revisions, extensions to old reservoirs, new reservoir

discoveries in old fields, and new field discoveries.

Reserves Changes: Positive and negative revisions,

extensions, new reservoir discoveries in old fields,

and new field discoveries, which occurred during the

report year.

Reservoir: A porous and permeable underground

formation containing an individual and separate

natural accumulation of producible hydrocarbons (oil

and/or gas) which is confined by impermeable rock

or water barriers and is characterized by a single

natural pressure system.

Revisions: Changes to prior year--end proved

reserves estimates, either positive or negative,

resulting from new information other than an

increase in proved acreage (extension). Revisions

include increases of proved reserves associated with

the installation of improved recovery techniques or

equipment. They also include correction of prior

report year arithmetical or clerical errors and

adjustments to prior year--end production volumes

to the extent that these alter reported prior year

reserves estimates.

Royalty (Including Overriding Royalty) Interests:

These interests entitle their owner(s) to a share of the

mineral production from a property or to a share of

the proceeds therefrom. They do not contain the

rights and obligations of operating the property, and

normally do not bear any of the costs of exploration,

development, and operation of the property.

Subdivision: A prescribed portion of a given State

or other geographical region defined in this

publication for statistical reporting purposes.

Subsidiary Company: A company which is

controlled through the ownership of voting stock, or

a corporate joint venture in which a corporation is

owned by a small group of businesses as a separate

and specific business or project for the mutual

benefit of the members of the group. (See Control)

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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 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.

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156 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1999 Annual Report