U.S. Crude Oil, Natural Gas,

and Natural Gas Liquids Reserves

2003 Annual Report

DOE/EIA-0216(2003)

November 2004

DOE/EIA–0216(2003)

Distribution Category UC–950

U.S. Crude Oil, Natural Gas,

and Natural Gas Liquids Reserves

2003 Annual Report

November 2004

Energy Information Administration

Office of Oil and Gas

U.S. Department of Energy

Washington, DC 20585

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

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

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

of the Department of Energy or any other organization.

Preface

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

Liquids Reserves 2003 Annual Report is the 27th

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, 2003, as well as production volumes

for the United States and selected States and State

subdivisions for the year 2003. 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 2003 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 2003; 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, Rafi

Zeinalpour, and Rhonda S. Green. Technical

contributions were made by Jack Perrin, Dewayne

Cravens, Paul Chapman, and Gwen Cox. 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

 Chapters 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 2003 Annual Report iii
Energy Information Administration

iv U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 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.

COVER PHOTO:

Gas drilling operations in the Newark East Field in the Barnett Shale, courtesy

of Devon Energy Corporation. Devon Energy Corporation, headquartered in

Oklahoma City, is the largest producer in the Newark East Field in the Barnett

Shale. The Barnett has become the 6th largest gas field in the United States,

located in the Fort Worth area.
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

R/P Ratios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Proved Ultimate Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

International Perspective . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

International Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Petroleum Consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Dependence on Imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

List of Appendices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

3. Crude Oil Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Discussion of Reserves Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Total Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

New Field Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

New Reservoir Discoveries in Old Fields. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Revisions and Adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Sales and Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Areas of Note: Large Discoveries and Reserve Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Gulf of Mexico Federal Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Other Gain Areas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Areas of Note: Large Reserve Declines. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Other Decline Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Reserves in Nonproducing Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

4. Natural Gas Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Dry Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Discussion of Reserves Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Total Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Revisions and Adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Sales and Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Wet Natural Gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Nonassociated Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Total Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report v
Page

Associated-Dissolved Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

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

Coalbed Methane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Areas of Note: Large Discoveries and Reserves Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Areas of Note: Large Reserves Declines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Gulf of Mexico Federal Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Reserves in Nonproducing Status. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

5. Natural Gas Liquids Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Natural Gas Liquids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

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

Total Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Revisions and Adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Sales and Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Natural Gas Plant Liquids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Lease Condensate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Reserves in Nonproducing Status. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Appendices

A. Operator Data by Size Class . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

B. Top 100 Oil and Gas Fields for 2002 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1

C. Conversion to the Metric System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C-1

D. Historical Reserves Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . D-1

E. Summary of Data Collection Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . E-1

F. Statistical Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-1

G. Estimation of Reserves and Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . G-1

H. Maps of Selected State Subdivisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . H-1

I. Annual Survey Forms for Domestic Oil and Gas Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . I-1

Glossary

Tables

1. U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids, 1993-2003 ............ 4

2. Reserves Changes, 1977-2003 ........................................... 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, 1977-2003 . . . . . . . . . . . . . . . . . . . . . . . . . . 10

4. U.S. Exploratory and Development Well Completions, 1970-2003 . . . . . . . . . . . . . . . . . . . . . . . . . 12

5. International Oil and Natural Gas Reserves as of December 31, 2003 . . . . . . . . . . . . . . . . . . . . . . . 18

6. Crude Oil Proved Reserves, Reserves Changes, and Production, 2003 . . . . . . . . . . . . . . . . . . . . . . 22

7. Reported Reserves in Nonproducing Status for Crude Oil, 2003 . . . . . . . . . . . . . . . . . . . . . . . . . . 27

8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 2003 . . . . . . . . . . . . . . . . . . 30

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vi U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
Page

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

Wet After Lease Separation, 2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

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

Wet After Lease Separation, 2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

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

Wet After Lease Separation, 2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

12. U.S. Coalbed Methane Proved Reserves and Production, 1989-2003 . . . . . . . . . . . . . . . . . . . . . . . 37

13. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 2003 . . . . . . . . . . . . . . . . 42

14. Natural Gas Plant Liquids Proved Reserves and Production, 2003. . . . . . . . . . . . . . . . . . . . . . . . . 43

15. Lease Condensate Proved Reserves and Production, 2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Figures

1. U.S. Crude Oil Proved Reserves, 1993-2003 .................................... 5

2. Components of Reserves Changes for Crude Oil, 1993-2003 ........................... 5

3. U.S. Dry Natural Gas Proved Reserves, 1993-2003 ................................ 6

4. Components of Reserves Changes for Dry Natural Gas, 1993-2003 ........................ 6

5. U.S. Natural Gas Liquids Proved Reserves, 1993-2003 .............................. 8

6. Components of Reserves Changes for Natural Gas Liquids, 1993-2003 ...................... 8

7. U.S. Exploratory Gas Well Completions, 1977-2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

8. U.S. Exploratory Oil Well Completions, 1977-2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

9. U.S. Total Discoveries of Dry Natural Gas per Exploratory Gas Well Completion, 1977-2003 . . . . . . . . . . . 14

10. U.S. Total Discoveries of Crude Oil per Exploratory Oil Well Completion, 1977-2003 . . . . . . . . . . . . . . . 14

11. Reserves-to-Production Ratios for Crude Oil, 1945-2003. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

12. Reserves-to-Production Ratios for Wet Natural Gas, 1945-2003 . . . . . . . . . . . . . . . . . . . . . . . . . . 16

13. Components of Ultimate Recovery for Crude Oil and Lease Condensate, 1977-2003 . . . . . . . . . . . . . . . 17

14. Components of Ultimate Recovery for Wet Natural Gas, 1977-2003 . . . . . . . . . . . . . . . . . . . . . . . . 17

15 Replacement of U.S. Crude Oil Production by Reserves Additions, 1994-2003 . . . . . . . . . . . . . . . . . . 21

16. Crude Oil Proved Reserves by Area, 2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

17. Changes in Crude Oil Proved Reserves by Area, 2002 to 2003 . . . . . . . . . . . . . . . . . . . . . . . . . . 23

18. Replacement of U.S. Dry Gas Production by Reserves Additions, 1994-2003 . . . . . . . . . . . . . . . . . . . 29

19. Dry Natural Gas Proved Reserves by Area, 2003. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

20. Changes in Dry Natural Gas Proved Reserves by Area, 2002 to 2003 . . . . . . . . . . . . . . . . . . . . . . . 31

21. Coalbed Methane Proved Reserves, 1989-2003 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report vii

Executive Summary:

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

Reserves 2003 Annual Report

Proved reserves of natural gas increased for the fifth

year in a row as U.S. natural gas reserves increased

by 1 percent in 2003. The majority of natural gas total

discoveries were from extensions of existing

conventional and unconventional gas fields. Reserves

additions replaced 111 percent of 2003 gas

production. Natural gas proved reserves have

increased in nine of the past ten years. U.S. gas

production remained almost level in 2003 as declines

in the Gulf of Mexico and New Mexico were offset

by production increases in the Rocky Mountain

States and Texas.

Crude oil proved reserves declined 3 percent in 2003,

the first decline in five years. Operators only

replaced 58 percent of oil production with reserves

additions. Total discoveries, that included significant

new field discoveries in the Gulf of Mexico Federal

Offshore, were larger than average. However, proved

reserves in several fields were lowered substantially

because of poor well performance accompanied by

engineering reassessments. The net of revisions,

adjustments, sales, and acquisitions was a negative

141 million barrels in 2003 compared to a more

typical positive 1,160 million barrels in 2002.

The Rocky Mountain States and Texas saw large gas

reserves additions in 2003. These were driven by

continuing development of unconventional gas

fields, i.e., fields developed in tight sands, shales,

and coalbeds. Significant reserves were added in the

Powder River basin (coalbed methane) and Green

River basin (deep and tight sand) in Wyoming, and

in the Wattenberg Field (tight sand) and San Juan

basin (coalbed methane) in Colorado and New

Mexico. Significant reserves were also added in

Texas’ Newark East Field (Barnett Shale) which is the

Nation’s sixth largest natural gas field.

Coalbed methane reserves increased 1 percent from

2002 and accounted for 10 percent of U.S. dry gas

proved reserves. Coalbed methane production

declined very slightly in 2003 (less than 1 percent)

and accounted for 8 percent of U.S. dry gas

production.

Proved reserves are the estimated quantities which

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 2003 U.S. proved

reserves of crude oil, natural gas, and natural gas

liquids is the 27th in an annual series prepared by

the Energy Information Administration.

Crude Oil

Total discoveries 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. Total discoveries of

crude oil were 1,232 million barrels in 2003, 16

percent more than the prior 10-year average and 30

percent more than 2002’s discoveries of 946 million

barrels.

The majority of crude oil total discoveries in 2003

were new field discoveries in the Gulf of Mexico

Federal Offshore. The north slope of Alaska

(normally a major contributor to total discoveries)

had no significant impact on the Nation’s total

discoveries in 2003.

New field discoveries accounted for 705 million

barrels of crude oil reserves additions. Almost all

were in the Gulf of Mexico Federal Offshore (702 of

705 million). This was more than double the new

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report ix

As of December 31, 2003 proved reserves were:

Crude Oil (million barrels)

2002 22,677

2003 21,891

Decrease -3.5%

Dry Natural Gas (billion cubic feet)

2002 186,946

2003 189,044

Increase +1.1%

Natural Gas Liquids (million barrels)

2002 7,994

2003 7,459

Decrease -6.7%
field discoveries of 2002 and 84 percent more than

the prior 10-year average.

Operators discovered 426 million barrels in

extensions in 2003, 13 percent less than in 2002 and

14 percent less than the prior 10-year average.

New reservoir discoveries in old fields were 101

million barrels, 34 percent less than in 2002 and 43

percent less than the prior 10-year average.

Reserves additions are the sum of total discoveries,

revisions, adjustments, sales, and acquisitions. In

2003, reserve additions were 1,091 million barrels

which is 48 percent less than the volume of reserves

additions in 2002.

Crude oil net revisions and adjustments were 257

million barrels, which is 77 percent less than the net

revisions and adjustments of 2002. The net of sales

and acquisitions of crude oil proved reserves was

-398 million barrels.

Other 2003 crude oil events of note:

• The annual average domestic first purchase

price for crude oil increased 22 percent from

the 2002 level to $27.56 per barrel.

• Exploratory and developmental oil completions

were up 4 percent from 2002.

Natural Gas

Total discoveries of dry gas reserves were 19,286

billion cubic feet in 2003. This was 36 percent more

than the prior 10-year average and 8 percent more

than in 2002. The majority of natural gas total

discoveries in 2003 were from extensions of existing

conventional and unconventional gas fields.

Field extensions were 16,454 billion cubic feet, 11

percent more than extensions in 2002 and 66 percent

more than the prior 10-year average of 9,941 billion

cubic feet.

New field discoveries were 1,222 billion cubic feet, 8

percent less than the volume discovered in 2002 and

33 percent less than the prior 10-year average.

New reservoir discoveries in old fields were 1,610

billion cubic feet, down 5 percent from 2002 and 34

percent less than the prior 10-year average.

Natural gas net revisions and adjustments were 1,203

billion cubic feet, which is 74 percent less than the

net revisions and adjustments of 2002. The net of

sales and acquisitions of dry natural gas proved

reserves was 1,034 billion cubic feet.

Coalbed methane proved reserves grew in 2003,

while production declined slightly. Coalbed methane

proved reserves were 18,743 billion cubic feet, an

increase of 1 percent from 2002 and accounted for 10

percent of U.S. dry gas proved reserves. Coalbed

methane production was 1,600 billion cubic feet, a

decrease of less than 1 percent from 2002 and

accounted for 8 percent of U.S. dry gas production.

Other 2003 natural gas events of note:

• Natural gas prices were up 69 percent in 2003

to an average of $4.98 per thousand cubic feet

at the wellhead, as compared to $2.95 per

thousand cubic feet in 2002.

• Exploratory and developmental gas

completions were up 22 percent from 2002.

• U.S. gas production increased slightly (less

than 1 percent) in 2003.

Natural Gas Liquids

U.S. natural gas liquids proved reserves declined 7

percent in 2003 to 7,459 million barrels. This resulted

from changes in the relative economics of natural gas

and natural gas liquids, and in the liquids content of

the gas production. 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 29,350 million

barrels in 2003, a 4 percent decrease from the 2002

level. Natural gas liquids represented 25 percent of

total liquid hydrocarbon proved reserves in 2003.

Data

These estimates are based upon analysis of data from

Form EIA-23, Annual Survey of Domestic Oil and

Gas Reserves, filed by 1,554 operators of oil and gas

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

Origin of Natural Gas Liquids Production, filed by

operators of 507 active natural gas processing plants.

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

natural gas are associated with sampling errors of

less than 1 percent.

Energy Information Administration

x U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
1. Introduction

Background

The primary focus of EIA’s reserves program is

providing 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.

This report provides proved reserves estimates for

calendar year 2003. It is based on data filed by large,

intermediate, and a select group of small 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

during the report year. 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 within a field. 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 using statistical

calculations that preserved the relative relationships

between these items within each State or State

subdivision, as reported by large and intermediate

operators.

A sample selected from the large group of small

(Category III) operators are requested to provide

annual production and, if available, year ending

reserves volumes. Details on the selection of these

operators and the determination of the reserves

volumes is found in Appendix F.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 1
The published reserve estimates include an additional

term, adjustments, calculated by the EIA, that

preserves an exact annual reserves balance of the form:

Adjustments are the annual changes in the published

reserve estimates that cannot be attributed to the

estimates for other reserve change categories. They

result from the survey and statistical estimation

methods employed. For example, variations caused by

changes in the operator frame, different random

samples, different timing of reporting, 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 20,923 probable active operators and the

Form EIA-64A plant frame contained 504 probable

active natural gas processing plants in the United

States when the 2003 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 2003. For more

details on the survey process, see Appendix E,

Summary of Data Collection Operations.

The 2003 survey sample consisted of 1,554 operators.

EIA sampled 1,075 operators with certainty; 164

Category I operators, 512 Category II operators, and

399 smaller operators that were selected with certainty

because of their size in relation to the area or areas in

which they operated. EIA also chose 479 Noncertainty

operators as a systematic random sample of the

remaining operators. There were 15 Successor

operators in 2003. Fifty-five (55) of the 1,554 ceased

operating oil and/or gas properties (became

non-operator) during the survey year. Fifty-seven (57)

operators changed size significantly in 2003; 43

reduced in size from Category I or II to Category III,

and 14 operators increased in size from Category III to

Category II.

EIA mailed EIA-64A forms to all known natural gas

processing plant operators as of February 1, 2004. 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 504 unique

active natural gas processing plants in 2003.

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 2003,

the Form EIA-23 National production estimates were

less than 1 percent lower than the comparable

Petroleum Supply Annual (PSA) 2003 volumes for crude

oil and lease condensate combined, and were less than

2 percent higher than the comparable Natural Gas

Monthly, October 2004 volume for 2003 dry natural gas.

Accuracy in reserves reporting is EIA’s first and

foremost goal for this report. Because of differences in

timing and data availability, the estimates of oil and gas

production presented in this report may differ from

those presented in other EIA reports.

Energy Information Administration

2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Published Proved Reserves at End of Previous Report Year

+ Adjustments

+ Revision Increases

– Revision Decreases

– Sales

+ Acquisitions

+ 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, 2003:

 Crude Oil — 21,891 million barrels

 Dry Natural Gas — 189,044 billion cubic feet

 Natural Gas Liquids — 7,459 million barrels.

This Overview summarizes the 2003 proved reserves

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

liquids on a National level and provides historical

comparisons between 2003 and prior years. Table 1

lists the estimated annual reserve balances since 1993

for crude oil, dry natural gas, and natural gas liquids.

Crude Oil

Proved reserves of crude oil decreased by 786 million

barrels in 2003. Figure 1 shows the crude oil proved

reserves levels by major region and Figure 2 shows the

components of reserves changes from 1993 through

2003.

As indicated in Figure 1, U.S. crude oil proved reserves

decreased in 2003 in the lower 48 States onshore and

Alaska, but increased in the Federal Offshore.

The components of reserves changes for crude oil are

shown in Figure 2. EIA tracks all components of

reserves changes: adjustments, revision increases,

revision decreases, sales, acquisitions, extensions, new

field discoveries, new reservoir discoveries in old

fields, and estimated production. These components

are discussed below.

Total discoveries 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. Total discoveries of crude oil were

1,232 million barrels in 2003, 16 percent more than the

prior 10-year average and 30 percent more than 2002’s

discoveries of 946 million barrels.

The majority of crude oil total discoveries in 2003 were

new field discoveries in the Gulf of Mexico Federal

Offshore. The north slope of Alaska (normally a major

contributor to total discoveries) had no significant

impact on the Nation’s total discoveries in 2003.

New field discoveries accounted for 705 million barrels

of crude oil reserves additions, 702 million of which

were in the Gulf of Mexico Federal Offshore. This was

more than double the new field discoveries of 2002 and

84 percent more than the prior 10-year average.

Operators discovered 426 million barrels in extensions

in 2003, 13 percent less than in 2002 and 14 percent less

than the prior 10-year average.

New reservoir discoveries in old fields were 101

million barrels, 34 percent less than in 2002 and 43

percent less than the prior 10-year average.

Reserves additions are the sum of total discoveries,

revisions and adjustments, and sales and acquisitions.

In 2003 there were 1,091 million barrels of reserves

additions, 48 percent less than the volume of reserves

additions in 2002.

The smaller than average volume of net revisions and

adjustments and a negative net of sales and

acquisitions of crude oil proved reserves significantly

reduced reserves additions in 2003. Crude oil net

revisions and adjustments were 257 million barrels, 77

percent less than the net revisions and adjustments of

2002. The net of sales and acquisitions of crude oil

proved reserves was -398 million barrels.

Production of crude oil was an estimated 1,877 million

barrels in 2003 (lease condensate not included, see

Natural Gas Liquids section below for condensate

volumes). This was up less than 1 percent from 2002’s

level (1,875 million barrels) and down 9 percent from

the prior 10-year average (2,074 million barrels).

Operators replaced only 58 percent of crude oil

production with reserves additions in 2003.

Natural Gas

Dry natural gas proved reserves increased by 2,098

billion cubic feet in 2003. Figure 3 shows the dry

natural gas proved reserves levels by major region. It

indicates that additions of gas reserves in the Lower 48

onshore are raising the National total despite declining

offshore gas reserves. Figure 4 shows the components

of reserves changes from 1993 through 2003.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 3
Energy Information Administration

4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table 1. Total U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids, 1993-2003

Revisionsa Net of Salesb New Reservoir Provedd Change Net and and New Field Discoveries Totalc Estimated Reserves from

Adjustments Revisions Adjustments Acquisitions 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)

1993 271 495 766 NA 356 319 110 785 2,339 22,957 -788

1994 189 1,007 1,196 NA 397 64 111 572 2,268 22,457 -500

1995 122 1,028 1,150 NA 500 114 343 957 2,213 22,351 -106

1996 175 737 912 NA 543 243 141 927 2,173 22,017 -334

1997 520 914 1,434 NA 477 637 119 1,233 2,138 22,546 +529

1998 -638 518 -120 NA 327 152 120 599 1,991 21,034 -1,512

1999 139 1,819 1958 NA 259 321 145 725 1,952 21,765 +731

2000 143 746 889 -20 766 276 249 1,291 1,880 22,045 +280

2001 -4 -158 -162 -87 866 1,407 292 2,565 1,915 22,446 +401

2002 416 720 1,136 24 492 300 154 946 1,875 22,677 +231

2003 163 94 257 -398 426 705 101 1,232 1,877 21,891 -786

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

1993 972 5,349 6,321 NA 6,103 899 1,866 8,868 17,789 162,415 -2,600

1994 1,945 5,484 7,429 NA 6,941 1,894 3,480 12,315 18,322 163,837 +1,422

1995 580 7,734 8,314 NA 6,843 1,666 2,452 10,961 17,966 165,146 +1,309

1996 3,785 4,086 7,871 NA 7,757 1,451 3,110 12,318 18,861 166,474 +1,328

1997 -590 4,902 4,312 NA 10,585 2,681 2,382 15,648 19,211 167,223 +749

1998 -1,635 5,740 4,105 NA 8,197 1,074 2,162 11,433 18,720 164,041 -3,182

1999 982 10,504 11,486 NA 7,043 1,568 2,196 10,807 18,928 167,406 +3,365

2000 -891 6,962 6,071 4,031 14,787 1,983 2,368 19,138 19,219 177,427 +10,021

2001 2,742 -2,318 424 2,630 16,380 3,578 2,800 22,758 19,779 183,460 +6,033

2002 3,727 937 4,664 380 14,769 1,332 1,694 17,795 19,353 186,946 +3,486

2003 2,841 -1,638 1,203 1,034 16,454 1,222 1,610 19,286 19,425 189,044 +2,098

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

1993 102 124 226 NA 245 24 64 333 788 7,222 -229

1994 43 197 240 NA 314 54 131 499 791 7,170 -52

1995 192 277 469 NA 432 52 67 551 791 7,399 +229

1996 474 175 649 NA 451 65 109 625 850 7,823 +424

1997 -15 289 274 NA 535 114 90 739 864 7,973 +150

1998 -361 208 -153 NA 383 66 88 537 833 7,524 -449

1999 99 727 826 NA 313 51 88 452 896 7,906 +382

2000 -83 459 376 145 645 92 102 839 921 8,345 +439

2001 -429 -132 -561 102 717 138 142 997 890 7,993 -352

2002 62 31 93 54 612 48 78 738 884 7,994 +1

2003 -338 -161 -499 30 629 35 72 736 802 7,459 -535

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

bNet of sales and acquisitions = acquisitions - sales.

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

dProved reserves = Col. 10 from prior year + Col. 3 + Col. 4 + Col. 8 - Col. 9.

NA=Not available.

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

2003 contained in the Petroleum Supply Annual 2003, DOE/EIA-0340(03) and the Natural Gas Annual 2003, DOE/EIA-0131(03).

Sources: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1993 through 2002 annual reports, DOE/EIA-0216.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 5

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1993-2002 annual reports, DOE/EIA-0216.{17-26}

Figure 2. Components of Reserves Changes for Crude Oil, 1993-2003

Figure 1. U.S. Crude Oil Proved Reserves, 1993-2003
Energy Information Administration

6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Figure 4. Components of Reserves Changes for Dry Natural Gas, 1993-2003

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1993-2002 annual reports, DOE/EIA-0216.{17-26}

Figure 3. U.S. Dry Natural Gas Proved Reserves, 1993-2003
Total discoveries of dry gas reserves were 19,286 billion

cubic feet in 2003. This was 36 percent more than the

prior 10-year average and 8 percent less than in 2002.

The majority of natural gas total discoveries in 2003

were from extensions of existing conventional and

unconventional gas fields.

Field extensions were 16,454 billion cubic feet, 11

percent more than extensions in 2002 and 66 percent

more than the prior 10-year average of 9,941 billion

cubic feet.

New field discoveries were 1,222 billion cubic feet, 8

percent less than the volume discovered in 2002 and 33

percent less than the prior 10-year average.

New reservoir discoveries in old fields were 1,610

billion cubic feet, down 5 percent from 2002 and 34

percent less than the prior 10-year average.

Natural gas net revisions and adjustments were 1,203

billion cubic feet, 74 percent less than the net revisions

and adjustments of 2002. The net of sales and

acquisitions of dry natural gas proved reserves was

1,034 billion cubic feet.

Production removed an estimated 19,425 billion cubic

feet of proved reserves from the National total. Dry gas

production increased by less than 1 percent compared

to 2002. Operators replaced 111 percent of dry natural

gas production with reserves additions.

Coalbed methane reserves grew in 2003, while

production declined slightly. Coalbed methane proved

reserves were 18,743 billion cubic feet, an increase of 1

percent from 2002 and accounted for 10 percent of U.S.

dry gas reserves. Coalbed methane production was

1,600 billion cubic feet, a decrease of less than 1 percent

from 2002 and accounted for 8 percent of U.S. dry gas

production.

Natural Gas Liquids

Proved reserves of natural gas liquids declined 7

percent in 2003 to 7,459 million barrels. This resulted

from changes in the relative economics of natural gas

and natural gas liquids, and in the liquid content of gas

production. Figure 5 shows the natural gas liquids

proved reserves levels by major region. It indicates that

declining reserves in both the Lower 48 onshore and

offshore combine to cause the decrease in the National

total in 2003. Figure 6 shows the components of natural

gas liquids reserves changes from 1993 through 2003.

Operators replaced 33 percent of their 2003 natural gas

liquids production with reserve additions. Total

discoveries added 736 million barrels (primarily from

extensions), net revisions and adjustments were -498

million barrels, and net sales and acquisitions added 30

million barrels in 2003.

Total proved reserves of liquid hydrocarbons (crude oil

plus natural gas liquids) were 29,350 million barrels in

2003—a 4 percent decrease from the 2002 level. Natural

gas liquids represented 25 percent of total liquid

hydrocarbon proved reserves in 2003.

Reserves Changes Since 1977

EIA has collected oil and gas reserves estimates

annually since 1977. Table 2 lists the cumulative totals

of the components of reserves changes for crude oil and

dry natural gas from 1977 through 2003. The table has

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 2003 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 905 million barrels per

year of new reserves

 had proved reserves additions of an average

2,093 million barrels per year from total

discoveries, net revisions and adjustments, and

net sales and acquisitions.

 ended each year with an average net reduction

in U.S. proved reserves of 430 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 proved ultimate recovery appreciation in

existing fields rather than the discovery of new oil

fields. Only 12 percent of reserves additions since 1976

were booked as new field discoveries. Proved ultimate

recovery appreciation is the sum of net revisions,

adjustments, net sales and acquisitions, extensions, and

new reservoir discoveries in old fields (see the Proved

Ultimate Recovery section later in this chapter.) Since

1977, the 24,427 million barrels of total discoveries

accounted for 43 percent of reserves additions.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 7
Energy Information Administration

8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Figure 5. U.S. Natural Gas Liquids Proved Reserves, 1993-2003

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1993-2003 annual reports, DOE/EIA-0216.{17-26}

Figure 6. Components of Reserves Changes for Natural Gas Liquids, 1993-2003
Compared to the averages of reserves changes since

1977, 2003 was an up year for crude oil discoveries.

Total discoveries of crude oil (1,232 million barrels) in

2003 were 36 percent greater than the post-1976 U.S.

average (905 million barrels per year).

Looking at the components of total discoveries in 2003:

 2003’s new field discoveries (705 million barrels)

were almost three times larger than the

post-1976 average for crude oil,

 New reservoir discoveries in old fields (101

million barrels) were 31 percent less than the

post-1976 average, and

 Extensions in 2003 (426 million barrels) were 17

percent less than the post-1976 average for

crude oil.

In 2003, the Revisions, Adjustments, Sales &

Acquisitions were -141 million barrels, a net loss. This

loss was significantly smaller than the post-1976

average of 1,189 million barrels per year. Certain

downward revisions and large reported sales of

reserves have negatively impacted the National total

for 2003.

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

 discovered an average of 13,124 billion cubic

feet per year of new reserves,

 had proved reserves additions of an average

17,088 billion cubic feet per year from total

discoveries, net revisions and adjustments, and

net sales and acquisitions, and

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

898 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 accounted for 51 percent of all

reserves additions since 1977 while net revisions and

adjustments accounted for only 23 percent.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 9

Table 2. Reserves Changes, 1977-2003

Lower 48 States U.S. Total

Average Percent Average Percent

per of Reserves per of Reserves

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 . . . . . . . . . . . 5,692 211 12.3 6,643 246 11.8

New Reservoir Discoveries in Old Fields . . 3,840 142 8.3 3,970 147 7.0

Extensions . . . . . . . . . . . . . . . . 12,223 453 26.5 13,824 512 24.4

Total Discoveries . . . . . . . . . . . . . 21,755 806 47.1 24,427 905 43.2

Revisions, Adjustments, Sales & Acquisitionsa 24,416 904 52.9 32,097 1,189 56.8

Total Reserves Additions . . . . . . . . . 46,171 1,710 100.0 56,524 2,093 100.0

Production . . . . . . . . . . . . . . . . 53,590 1,985 116.1 68,135 2,524 120.5

Net Reserves Change . . . . . . . . . . . -7,419 -275 -16.1 -11,611 -430 -20.5

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 . . . . . . . . . . . 52,170 1,932 11.0 52,412 1,941 11.4

New Reservoir Discoveries in Old Fields . . 66,919 2,478 14.1 67,333 2,494 14.6

Extensions ................ 231,535 8,575 48.7 234,605 8,689 50.8

Total Discoveries ............. 350,624 12,986 73.7 354,350 13,124 76.8

Revisions, Adjustments, Sales & Acquisitionsa 125,060 4,632 26.3 107,037 3,964 23.2

Total Reserves Additions ......... 475,684 17,618 100.0 461,387 17,088 100.0

Production ................ 475,763 17,621 100.0 485,621 17,986 105.3

Net Reserves Change . . . . . . . . . . . -79 -3 0.0 -24,234 -898 -5.3

a EIA did not separately collect data on sales and acquisitions of proved reserves until the year 2000.

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1977-2003 annual reports, DOE/EIA-0216.{1-26}
Energy Information Administration

10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 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, 1977-2003

Crude Oil Natural Gas

Year Current 2003 Constant Current 2003 Constant

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

1977 8.57 21.41 0.79 1.97 2,001

1978 9.00 20.89 0.91 2.12 2,259

1979 12.64 27.21 1.18 2.54 2,177

1980 21.59 42.55 1.59 3.13 2,909

1981 31.77 57.28 1.98 3.57 3,970

1982 28.52 48.40 2.46 4.17 3,105

1983 26.19 42.76 2.59 4.23 2,232

1984 25.88 40.74 2.66 4.19 2,428

1985 24.09 36.76 2.51 3.83 1,980

1986 12.51 18.68 1.94 2.90 964

1987 15.40 22.32 1.67 2.42 936

1988 12.58 17.63 1.69 2.37 936

1989 15.86 21.42 1.69 2.28 869

1990 20.03 26.03 1.71 2.22 1,010

1991 16.54 20.74 1.64 2.06 860

1992 15.99 19.58 1.74 2.13 721

1993 14.25 17.04 2.04 2.44 754

1994 13.19 15.45 1.85 2.17 775

1995 14.62 16.76 1.55 1.78 723

1996 18.46 20.76 2.17 2.44 779

1997 17.23 19.00 2.32 2.56 943

1998 10.87 11.84 1.96 2.14 827

1999 15.56 16.71 2.19 2.35 625

2000 26.72 28.11 3.68 3.87 918

2001 21.84 22.44 4.00 4.11 1,156

2002 January 15.89 16.24 2.50 2.56 867

February 16.93 17.29 2.19 2.24 825

March 20.28 20.68 2.40 2.45 763

April 22.52 22.94 2.94 2.99 750

May 23.51 23.92 2.94 2.99 826

June 22.59 22.95 2.96 3.01 842

July 23.51 23.86 2.92 2.96 851

August 24.76 25.10 2.76 2.80 848

September 26.08 26.40 2.97 3.01 860

October 25.29 25.57 3.24 3.28 851

November 23.38 23.60 3.59 3.62 834

December 25.29 25.48 3.96 3.99 901

2002 22.51 22.87 2.95 3.00 830

2003 January 28.35 28.49 4.47 4.49 854

February 31.85 31.96 5.45 5.47 907

March 30.09 30.16 6.69 6.71 941

April 25.46 25.51 4.71 4.72 983

May 24.96 24.98 4.97 4.97 1,034

June 26.83 26.82 5.35 5.35 1,067

July 27.53 27.48 4.91 4.90 1,081

August 27.94 27.85 4.72 4.71 1,090

September 25.23 25.12 4.58 4.56 1,093

October 26.52 26.37 4.43 4.40 1,102

November 27.21 27.02 4.34 4.31 1,111

December 28.54 28.31 5.08 5.04 1,114

2003 27.56 27.56 4.98 4.98 1,032

=Revised data.

Sources: Current dollars and number of rigs: Monthly Energy Review September 2004, DOE/EIA-0035(2004/9). 2003 constant dollars:

U.S. Department of Commerce, Bureau of Economic Analysis, Gross Domestic Product Implicit Price Deflators, October 2004.
Compared to the averages of reserves changes since

1977, 2003 was an up year for dry natural gas total

discoveries. Operators reported 19,286 billion cubic

feet of total discoveries of dry natural gas proved

reserves, 47 percent more than the post-1976 average

(13,124 billion cubic feet).

The net of revisions, adjustments, sales, and

acquisitions was 2,237 billion cubic feet in 2003, 44

percent lower than the post-1976 U.S. average (3,964

billion cubic feet per year).

Economics and Drilling

Economics: Table 3 lists the average annual domestic

wellhead prices of crude oil and natural gas from 1977

to 2003.

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

average of $28.35 per barrel in January 2003, then

fluctuated between a high of $31.85 (February) and a

low of $24.96 (May). The average U.S. crude oil first

purchase price increased from $22.51 in 2002 to $27.56

per barrel in 2003.

Oil prices vary by region. In Texas the average 2003

crude oil first purchase price was $29.13 per barrel,

$26.43 per barrel in California, $30.71 per barrel in

Colorado, $28.18 per barrel in Ohio, and $24.25 per

barrel in the California Federal Offshore. The lowest

average crude oil first purchase price in 2003 was

$23.78 per barrel for the Alaska North Slope oil.{27}

The average annual wellhead natural gas price

increased from $3.00 in 2002 to $4.98 per thousand

cubic feet in 2003. Natural gas prices started at $4.49 per

thousand cubic feet in January 2003, rose to an annual

average high on $6.71 per thousand cubic feet in March,

then fluctuated between $4.31 and $5.35 until the end of

the year, ending with a price of $5.04 per thousand

cubic feet in December 2003. {28}

Drilling: Also listed in Table 3 are the average number

of active rotary drilling rigs from 1977 to 2003. From

2002 to 2003, the annual average active rig count

increased from 830 to 1,032, a 24 percent increase in

active rigs.

Looking first at exploratory wells, there were 2,341

exploratory wells drilled in 2003 (Table 4). Of these, 11

percent were completed as oil wells, 33 percent were

completed as gas wells, and 56 percent were dry holes.

Exploratory oil and gas completions (excluding dry

holes) in 2003 were 17 percent more (Figures 7 and 8)

than the revised 2002 total.

Figures 9 and 10 show the average volume of

discoveries per exploratory well for dry natural gas

and oil, respectively, since 1977. The 2003 average

volume of oil discoveries per exploratory well

increased 18 percent compared to 2002. The 2003

average volume of gas discoveries per exploratory well

decreased 7 percent compared to 2002.

The number of successful development wells increased

4 percent for oil and 22 percent for gas from their 2002

levels. Including dry holes, there were an estimated

29,984 exploratory and development wells drilled in

2003. This is 16 percent more than in 2002 and 21

percent more than the average number of wells drilled

annually in the prior 10 years (24,706).

For the eleventh 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

The following large mergers and acquisitions were

announced in 2003, and are expected to have a major

impact on the energy industry in the future:

On February 14, 2003, the Federal Trade Commission

voted unanimously voted 5- to-0 to approve Conoco

Inc.’s merger with Phillips Petroleum Co., Dow Jones

reported. The commission issued its final consent order

following a public comment period. In November 2001,

Oklahoma-based Phillips agreed to merge with

Houston-based Conoco in a $15.2 billion deal. The

transaction forms ConocoPhillips, the world’s

sixth-largest oil and gas company in terms of proved

reserves. The new company, which already is

operating as ConocoPhillips, will be headquartered in

Houston. {29}

In June 2003, Marathon signed a Dissolution and

Distribution Agreement with Kinder Morgan Energy

Partners, L.P. To dissolve MKM Partners L.P. Formed

in January 2001, the MKM partnership had oil and gas

production operations in the Permian Basin of Texas.

Prior to the dissolution of the partnership, an

agreement was signed exploring the sale of Marathon’s

interest in the Yates Field to Kinder Morgan. {30}

In October 2003, Shareholders of Carbon Energy

Corporation of Denver, CO approved the proposed

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 11
Energy Information Administration

12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table 4. U.S. Exploratory and Development Well Completions,a 1970-2003

Exploratory Total Exploratory and Development

Year Oil Gas Dry Total Oil Gas Dry Total

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

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

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

1973 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 291 504 1,647 2,442 R 7,064 R 11,144 4,840 R 23,048

1999 R 157 539 1,195 R 1,891 4,176 10,877 R 3,412 R 18,465

2000 264 R 602 1,288 R 2,154 7,358 16,455 4,025 27,838

2001 R 322 988 R 1,669 R 2,979 8,060 22,083 R 4,084 R 34,227

2002 R 231 R 659 R 1,240 R 2,130 R 6,058 R 16,155 R 3,531 R 25,744

2003 254 766 1,321 2,341 6,284 19,722 3,978 29,984

aExcludes service wells and stratigraphic and core testing.

R = Revised Data.

Notes: Estimates include only the original drilling of a hole intended to discover of further develop already discovered oil or gas re- sources. Other drilling activities, such as drilling an old well deeper, drilling of laterals from the original well, drilling of service and injection wells, and drilling for resources other than oil and gas are excluded.

Sources: Years 1970-1972: Energy Information Administration, Office of Oil and Gas. Years 1973-2003: EIA Monthly Energy Review

September 2004, DOE/EIA-0035(2004/09). Web Page http://www.eia.doe.gov/emeu/mer/resource.html.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 13

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

Figure 7. U.S. Exploratory Gas Well Completions, 1977-2003

Figure 8. U.S. Exploratory Oil Well Completions, 1977-2003
Energy Information Administration

14 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

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

Figure 9. U.S. Total Discoveries of Dry Natural Gas per Exploratory Gas Well Completion, 1977-2003

Figure 10. U.S. Total Discoveries of Crude Oil per Exploratory Oil Well Completion, 1977-2003
merger of Carbon with a subsidiary of Evergreen

Resources, Inc. also based in Denver, in a deal worth

about $90 million. Carbon has oil and gas operations in

the Piceance Basin of Colorado and in the Uintah Basin

in Utah, as well as in central Alberta and southest

Saskatchewan in Canada. The acquired Carbon

properties have about $88 billion cubic feet equivalent

of reserves, mostly in natural gas. {31}

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 2003, U.S. crude oil proved reserves decreased and

oil production increased, decreasing the National

average R/P ratio from 12.1 to 11.7.

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, because of differences in development

history and reservoir conditions. The 2003 National

average R/P ratio for crude oil was 11.7-to-1. 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 to add reserves equivalent to the annual

production, keeping the regional reserves and R/P

ratio for oil relatively stable.

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

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

since the interstate pipeline infrastructure was not well

developed. The market for natural gas grew rapidly

after World War II, lowering the R/P ratio. From 2002

to 2003 the U.S. average R/P ratio for natural gas

increased from 9.66 to 9.74 since proved reserves

increased and production decreased.

Different marketing, transportation, and production

characteristics for gas are seen when looking at

regional average R/P ratios, compared to the 2003 U.S.

average R/P ratio of about 9.7-to-1. Areas with a higher

range of R/P ratios than the National average were the

Pacific offshore and the Rockies, as well as 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.

Proved Ultimate Recovery

EIA had defined Ultimate Recovery as the sum of

proved reserves and cumulative production. However,

despite EIA’s definition, the volume presented by EIA

has often been 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 therefore introduced the term, Proved

Ultimate Recovery:

Proved Ultimate Recovery is the sum of

proved reserves and cumulative production. It is

expected to change over time for any field, group

of fields, State, or Country. Proved Ultimate

Recovery does not represent the maximum

recoverable volume of resources for an area. It is

instead a gauge of how much has already been

produced plus proved reserves. Proved reserves

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 15
Energy Information Administration

16 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Sources: Annual reserves and production - American Petroleum Institute and American Gas Association (1945–1976) {32} and Energy

Information Administration, Office of Oil and Gas (1977–2002){1-26}. Cumulative production: U.S. Oil and Gas Reserves by Year of Field

Discovery (1977-1988).{33}

Figure 11. Reserves-to-Production Ratios for Crude Oil, 1945-2003

Figure 12. Reserves-to-Production Ratios for Wet Natural Gas, 1945-2003
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 17

Sources: Annual reserves and production - American Petroleum Institute and American Gas Association (1945–1976) {32} and Energy

Information Administration, Office of Oil and Gas (1977–2002){1-26}. Cumulative production: U.S. Oil and Gas Reserves by Year of Field

Discovery (1977-1988).{33}

Figure 13. Components of Proved Ultimate Recovery for Crude Oil and Lease Condensate, 1977-2003

Figure 14. Components of Proved Ultimate Recovery for Wet Natural Gas, 1977-2003
Table 5. International Oil and Natural Gas Reserves as of December 31, 2003

Oil

(million barrels)

Natural Gas

(billion cubic feet)

Oil & Gas World Oil & Gas World

Ranka Country Journal Oil Rankb Country Journal Oil

1 Saudia Arabiac ....... d261,900 d259,400 1 Russia .............. 1,680,000 2,340,500

2 Iranc ............... 125,800 105,000 2 Iranc ................ 940,000 955,000

3 Iraqc ............... 115,000 115,000 3 Qatarc .............. 910,000 915,992

4 Kuwaitc ............. d99,000 d99,375 4 Saudia Arabiac........ d231,000 d238,500

5 Canadae ............ 178,893 4,957 5 United Arab Emiratesc . . 212,100 204,050

6 United Arab Emiratesc . 97,800 66,230 6 United States ........ 186,946 186,946

7 Venezuelac .......... 77,800 52,450 7 Nigeriac ............. 159,000 178,500

8 Russia.............. 60,000 65,393 8 Algeriac ............. 160,000 171,500

9 Libyac .............. 36,000 30,500 9 Venezuelac .......... 148,000 149,210

10 Nigeriac............. 25,000 33,000 10 Iraqc ................ 110,000 112,600

Top 10 Total.............. 1,077,193 831,305 Top 10 Total .............. 4,737,046 5,452,348

11 United States........ 22,677 22,677 11 Australia ............. 90,000 142,900

12 Qatarc .............. 15,207 27,352 12 Indonesiac ........... 90,300 67,650

13 China .............. 18,250 15,509 13 Norway.............. 74,800 74,733

14 Mexico ............. 15,674 14,597 14 Turkmenistan ......... 71,000 -

15 Algeriac............. 11,314 14,000 15 Malaysia............. 75,000 57,608

16 Norway ............. 10,447 9,395 16 Uzbekistan ........... 66,200 -

17 Brazil............... 8,500 10,602 17 Kazakhstan .......... 65,000 -

18 Kazakhstan.......... 9,000 - 18 Egypt ............... 58,500 71,250

19 Angola ............. 5,412 8,800 19 Canada.............. 59,069 59,069

20 Azerbaijan........... 7,000 - 20 Netherlands .......... 62,000 55,100

21 Oman .............. 5,506 5,700 21 Kuwaitc.............. d55,500 d56,600

22 Indonesiac .......... 4,700 5,500 22 China ............... 53,325 47,911

23 Ecuador ............ 4,630 4,950 23 Libyac............... 46,400 46,000

24 India ............... 5,371 4,002 24 Ukraine.............. 39,600 -

25 United Kingdom ...... 4,665 4,300 25 Oman ............... 29,280 31,000

Top 25 Total.............. 1,225,546 978,689 Top 25 Total .............. 5,673,020 6,162,169

OPEC Total .............. 869,521 807,807 OPEC Total ............... 3,062,400 3,095,602

World Total .............. 1,265,812 1,051,477 World Total ............... 6,076,494 6,803,282

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.

EOil and Gas Journal Canadian oil reserves include heavy (low gravity) oil.

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 22, 2003, pp. 46-47. Gulf Publishing Company, World Oil,

September, 2004, p 63.

Energy Information Administration

18 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
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 both crude oil plus lease

condensate and wet natural gas, over the period 1977

through 2003. They illustrate the continued

appreciation (growth) of proved ultimate recovery

over time.

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

reserves were 33,615 million barrels. Cumulative

production of crude oil plus lease condensate for 1977

through 2003 was 69,732 million barrels. This

substantially exceeds the 1977 proved reserves, but at

the end of 2003 there were still 23,106 million barrels of

crude oil plus 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 12 percent of proved reserves

additions of crude oil were booked as new field

discoveries from 1976 through 2003. The rest came from

the proved reserves categories related to the proved

ultimate recovery appreciation process.

Similarly, the 1977 wet natural gas proved reserves were

209,490 billion cubic feet, but more than twice this

amount of gas was produced from 1977 through 2003

and there were still 197,145 billion cubic feet of wet

natural gas proved reserves in 2003. Only 11 percent of

proved reserve additions of natural gas were booked as

new field discoveries from 1976 through 2003.

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 1.16 trillion barrels of oil and 6.5

quadrillion cubic feet of gas.

The United States ranked 11th in the world for proved

reserves of crude oil and 6th for natural gas in 2003. A

comparison of EIA's U.S. proved reserves estimates

with worldwide estimates obtained from other sources

shows that the United States had 2 percent of the

world's total crude oil proved reserves and 3 percent of

the world's total natural gas proved reserves at the end

of 2003. There are sometimes substantial differences

between the estimates from these sources. The Oil &

Gas Journal reported oil reserves for Canada at about

179 billion barrels. This is much higher than the World

Oil estimate of 5 billion. The Oil and Gas Journal estimate

includes heavy oil from Canadian tar sands, the World

Oil estimate does not. Another reason (among many)

for these differences is that condensate is often

included in foreign oil reserve estimates.

The Oil & Gas Journal {34} estimate for world oil

reserves increased 4 percent in 2003 owing to its

addition of former Soviet Union states. This addition

was not shared by World Oil {35} where the estimate

increased only 2 percent. For world gas reserves, the

Oil & Gas Journal reported a 10 percent increase, while

World Oil reported a 11 percent increase. World Oil

estimated a 38 percent increase in Russian gas reserves

in 2003, while Oil and Gas Journal attributed the reserves

increases to Turkmenistan, Uzbekistan, and

Kazakhstan.

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 and

Canada have triple. (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.{36} In 2003:

 The U.S. consumed 98,160,000,000,000,000 Btu of

energy (98.2 quadrillion Btu). This was an

increase of 0.13 quadrillion Btu from the 2002

level of consumption.

 64 percent of U.S. energy consumption was

provided by petroleum and natural gas—crude

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 19
oil and natural gas liquids combined (39

percent), and natural gas (25 percent).

 U.S. petroleum consumption was about 20

million barrels of oil and natural gas liquids and

60 billion cubic feet of dry gas per day.

Dependence on Imports

The United States remains dependent on imported oil

and gas. In 2003, crude oil imports made up 63 percent

of the U.S. crude oil supply.

Net gas imports decreased slightly from the revised

2002 total of 4.02 trillion cubic feet to 3.93 trillion cubic

feet in 2003. The last decline in imports was in 1986.

Imports satisfied 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 Trinidad and

Tobago, Nigeria, and Algeria.

Saudi Arabia, Mexico, Canada, and Venezuela were the

primary foreign suppliers of petroleum to the United

States.{37}

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. Two new tables have

been added to this appendix for 2003, ranking the top

100 oil and natural gas fields by their 2003 production

rather than their proved reserves. Table B5 in Appendix

B lists the top U.S. operators by reported 2003

production.

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 1993-2003, due

to expressed interest from the industry regarding this

area. Table D9 contains the production and proved

reserves for 1993-2003 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

20 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
3. Crude Oil Statistics

The United States had 21,891 million barrels of crude

oil proved reserves as of December 31, 2003. This is 3

percent (-786 million barrels) less than in 2002. The

major factors contributing to the decline in 2003 were

lower than average net revisions and adjustments and

a negative net of sales and acquisitions.

The majority of crude oil total discoveries in 2003 were

new field discoveries in the Gulf of Mexico Federal

Offshore. The north slope of Alaska (normally a key

area) had no significant impact on the National total in

2002. Operators replaced only 58 percent of 2003 oil

production with proved reserves additions (Figure 15).

Proved Reserves

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

of December 31, 2003, by selected States and State

subdivisions.

Figure 16 maps 2003 crude oil proved reserves by area.

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

crude oil proved reserves:

Percent of

Area U.S. Oil Reserves

Texas 21

Gulf of Mexico Federal Offshore 21

Alaska 20

California 16

Area Total 78

Of these four areas, only the Gulf of Mexico Federal

Offshore had an increase in crude oil proved reserves in

2003.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 21

Figure 15. Reserve Additions Replace Only 58% of 2003 U.S. Crude Oil Production.

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

.







































   	    

Percentage of U.S. Crude Oil Production Replaced
Energy Information Administration

22 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

 	 
  	  

   
   	   
  	 


bIncludes Arizona, Missouri, Nevada, New York, 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.” They may differ from the official Energy Information Administration production data for crude oil for 2003 contained in the

Petroleum Supply Annual 2003, DOE/EIA-0340(03).

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

Alaska ..................... 4,678 1 168 79 0 0 35 0 0 357 4,446

Lower 48 States ............. 17,999 162 1,318 1,313 1,107 709 391 705 101 1,520 17,445

Alabama. . . . . . . . . . . . . . . . . . . . 51 1 4 0 0 0 2 0 0 6 52

Arkansas . . . . . . . . . . . . . . . . . . . 49 9 2 1 4 2 0 0 0 7 50

California ................... 3,633 -18 190 107 58 49 9 0 0 246 3,452

Coastal Region Onshore . . . . . 404 -4 11 5 8 12 2 0 0 17 395

Los Angeles Basin Onshore. . . 330 0 31 24 31 26 3 0 0 16 319

San Joaquin Basin Onshore . . 2,702 -13 139 62 19 11 4 0 0 197 2,565

State Offshore . . . . . . . . . . . . . 197 -1 9 16 0 0 0 0 0 16 173

Colorado . . . . . . . . . . . . . . . . . . . 214 -4 19 4 1 2 7 0 0 16 217

Florida . . . . . . . . . . . . . . . . . . . . . 73 -1 0 1 0 0 0 0 0 3 68

Illinois. . . . . . . . . . . . . . . . . . . . . . 107 22 11 5 0 0 0 0 0 10 125

Indiana . . . . . . . . . . . . . . . . . . . . . 15 5 1 0 0 0 0 0 0 2 19

Kansas. . . . . . . . . . . . . . . . . . . . . 237 19 31 13 4 2 5 0 0 34 243

Kentucky ................... a27 2 2 4 0 0 0 0 0 2 25

Louisiana . . . . . . . . . . . . . . . . . . . 501 3 57 75 46 38 31 0 6 63 452

North . . . . . . . . . . . . . . . . . . . . 75 5 4 9 1 0 2 0 0 10 66

South Onshore. . . . . . . . . . . . . 335 1 46 48 26 19 23 0 3 39 314

State Offshore . . . . . . . . . . . . . 91 -3 7 18 19 19 6 0 3 14 72

Michigan . . . . . . . . . . . . . . . . . . . 61 12 14 16 10 21 0 0 0 7 75

Mississippi . . . . . . . . . . . . . . . . . . 179 9 20 9 15 1 0 0 0 16 169

Montana. . . . . . . . . . . . . . . . . . . . 288 -6 15 8 2 5 42 0 0 19 315

Nebraska . . . . . . . . . . . . . . . . . . . 18 0 1 0 0 0 0 0 0 3 16

New Mexico . . . . . . . . . . . . . . . . . 710 -5 65 69 18 15 38 0 0 59 677

East . . . . . . . . . . . . . . . . . . . . . 699 -6 64 67 17 15 38 0 0 58 668

West. . . . . . . . . . . . . . . . . . . . . 11 1 1 2 1 0 0 0 0 1 9

North Dakota . . . . . . . . . . . . . . . . 342 8 20 24 1 7 31 0 0 30 353

Ohio . . . . . . . . . . . . . . . . . . . . . . . 67 9 4 8 1 0 0 0 0 5 66

Oklahoma . . . . . . . . . . . . . . . . . . 598 3 80 49 36 21 26 0 0 55 588

Pennsylvania ................ a12 -3 6 1 0 0 1 0 0 2 13

Texas ...................... 5,015 63 362 178 639 242 77 3 2 364 4,583

RRC District 1 . . . . . . . . . . . . . 50 10 4 4 1 0 7 1 0 8 59

RRC District 2 Onshore . . . . . . 54 4 4 5 2 3 0 0 0 7 51

RRC District 3 Onshore . . . . . . 218 1 15 14 32 15 14 0 0 27 190

RRC District 4 Onshore . . . . . . 28 1 6 3 2 2 1 0 1 4 30

RRC District 5 . . . . . . . . . . . . . 24 1 1 2 8 8 0 0 0 4 20

RRC District 6 . . . . . . . . . . . . . 198 6 11 8 9 6 2 0 0 17 189

RRC District 7B . . . . . . . . . . . . 82 -2 15 3 18 5 0 0 0 11 68

RRC District 7C . . . . . . . . . . . . 177 9 28 5 3 3 12 0 0 16 205

RRC District 8 ............. 1,913 -5 118 57 513 144 23 1 0 111 1,513

RRC District 8A ............ 2,093 20 142 47 48 53 13 0 0 137 2,089

RRC District 9 . . . . . . . . . . . . . 113 10 11 10 1 2 4 0 0 15 114

RRC District 10 . . . . . . . . . . . . 59 9 6 20 2 1 1 0 0 6 48

State Offshore . . . . . . . . . . . . . 6 -1 1 0 0 0 0 1 1 1 7

Utah . . . . . . . . . . . . . . . . . . . . . . . 241 1 7 18 24 25 1 0 0 12 221

West Virginia ................ a13 0 2 1 0 0 0 0 0 1 13

Wyoming . . . . . . . . . . . . . . . . . . . 524 24 29 36 23 36 5 0 0 42 517

Federal Offshore ............. 5,009 8 376 686 225 243 115 702 93 515 5,120

Pacific (California) . . . . . . . . . . 565 1 10 2 0 0 22 0 0 30 566

Gulf of Mexico (Louisiana) .... 4,088 5 289 616 201 230 93 698 91 426 4,251

Gulf of Mexico (Texas). . . . . . . 356 2 77 68 24 13 0 4 2 59 303

Miscellaneousb . . . . . . . . . . . . . . 15 1 0 0 0 0 1 0 0 1 16

U.S. Total .................. 22,677 163 1,486 1,392 1,107 709 426 705 101 1,877 21,891

Table 6. Crude Oil Proved Reserves, Reserves Changes, and Production, 2003

(Million Barrels of 42 U.S. Gallons)

  	
 	 


Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Sales Acquisitions Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/02 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/03
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 23

Figure 17. Changes in Crude Oil Proved Reserves by Area, 2002 to 2003

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

Figure 16. Crude Oil Proved Reserves by Area, 2003
Discussion of Reserves Changes

Figure 17 maps the change in crude oil proved reserves

from 2002 to 2003 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 -432

Gulf of Mexico Federal Offshore +110

Alaska -232

California -181

Area Total -735

U.S. Total -786

Figure 2 in Chapter 2 shows the components of the

changes in crude oil proved reserves for 2003 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.

Total discoveries of crude oil were 1,232 million barrels

in 2003, 30 percent more than those of 2002. Only three

areas had total discoveries exceeding 40 million barrels:

 The Gulf of Mexico Federal Offshore had 888

million barrels of total discoveries, 72 percent of

the National total.

 Texas had 82 million barrels of total discoveries,

7 percent of the National total.

 Montana had 42 million barrels of total

discoveries, 3 percent of the National total.

The United States discovered an average of 1,060

million barrels of new crude oil proved reserves per

year in the prior 10 years (1993 through 2002). Total

discoveries in 2003 (1,232 million barrels) were 16

percent higher than that average.

Extensions

Operators reported 426 million barrels of extensions in

2003. The highest volume of extensions was reported in

the Gulf of Mexico Federal Offshore (93 million

barrels). Texas reported 77 million barrels of

extensions. Montana was third with 42 million barrels

of extensions.

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

average of 498 million barrels of extensions per year.

The 2003 extensions were 15 percent less than that

average.

New Field Discoveries

There were 705 million barrels of new field discoveries

of crude oil reported in 2003. Only two areas in the

United States reported any new field discoveries, and

only the Gulf of Mexico Federal Offshore contributed a

significant volume (702 million barrels, or 99.6

percent).

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

average of 383 million barrels of reserves from new

field discoveries per year. Reserves from new field

discoveries in 2003 were 84 percent more than that

average volume.

New Reservoir Discoveries in Old Fields

Operators in the United States reported 101 million

barrels of crude oil reserves from new reservoir

discoveries in old fields in 2003. 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—93 million barrels or 92

percent of the total. Louisiana had 6 million barrels (6

percent). Texas was third with 2 million barrels (2

percent).

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

average of 178 million barrels of reserves from new

reservoir discoveries in old fields per year. Reserves

Energy Information Administration

24 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

  	 




















    

Billion barrels



	



from new reservoir discoveries in old fields in 2003

were 43 percent less 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 1,486 million barrels of revision increases,

1,392 million barrels of revision decreases, and 163

million barrels of adjustments in 2003. Combined, there

were 257 million barrels of net revisions and

adjustments for crude oil in 2003.

In the prior 10 years, net revisions and adjustments

added an average of 916 million barrels per year. The

2003 net revisions and adjustments were substantially

less than this volume and a major factor in the net loss

of proved reserves of crude oil in 2003.

Sales and Acquisitions

Sales represents that volume of crude oil proved

reserves deducted from an operator’s total by selling or

transferring operations of existing oil fields or

properties to another operator (not a volume of

production “sold” at the wellhead). Similarly,

acquisitions are that volume of proved reserves added

to an operator’s total through purchase or operations

transfer of an existing oil field or properties.

There are several reasons why sales and aquistions

volumes are not equal. Since operators have different

engineering staffs and resources, or different

development plans or schedules, the estimate of

proved reserves for a field can change with a change in

ownership. Timing of the transfer of operations can

also impact these values.

In 2003, there were 1,107 million barrels of sales

transactions between operators, and 709 million barrels

of acquisitions -- yielding a net difference of -398

million barrels in 2003. This large net difference, like the

reduced net revisions and adjustments, contributed to

the net loss of proved reserves of crude oil in 2003.

Production

U.S. production of crude oil in 2003 was an estimated

1,877 million barrels. This volume does not include

lease condensate. This was less than 1 percent higher

than 2002’s production of 1,875 million barrels. The

Gulf of Mexico Federal Offshore remained the largest

producing area in the United States with 485 million

barrels of production (26 percent of the National total).

Texas and Alaska were second and third, each with 19

percent of the total. California was fourth with 13

percent.

The 2003 Form EIA-23 National production estimates

(2,068 million barrels of crude oil and lease condensate)

were slightly less than the comparable Petroleum

Supply Annual (PSA) 2003 volumes for crude oil and

lease condensate production combined (2,073 million

barrels).

Areas of Note: Large Discoveries

and Reserves Additions

The following State and area discussions summarize

notable activities during 2003 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 were the major success stories for

crude oil reserves and production for 2003.

Gulf of Mexico Federal Offshore

The Gulf of Mexico Federal Offshore led the Nation in

total discoveries of crude oil proved reserves in 2003,

888 million barrels of total discoveries which is 72

percent of the National total.

 Atlantis Field: On February 10, 2003, BHP

Billiton announced the results of appraisal well

drilling and approved full funding for the

development of the Atlantis Field. BHP Billiton

has 44 percent interest in the Atlantis Field, BP

is the operator with 56 percent interest. The

estimate of recovery is 635 million barrels of oil

equivalent. The Atlantis Field is located in the

Atwater Foldbelt, approximately 125 miles south

of New Orleans in the vicinity of Green Canyon

Block 743. Comprising seven blocks in the area

at water depths ranging from 4,400 to 7,100 feet.

The field will be developed using a moored

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 25
semi-submersible production facility with a

gross design capacity of 150,000 barrels of oil

and 180 million cubic feet of natural gas per

day. Atlantis is believed to be the third largest

oil and gas field yet discovered in the Gulf of

Mexico. {38}

 Tahiti Field: On April 22, 2003 ChevronTexaco

announced positive results from two Tahiti

appraisal wells, confirming one of the most

significant net pay accumulations in the history

of the deepwater Gulf of Mexico. The two-well

appraisal program confirmed that the reservoirs

in Tahiti are well developed and correlate over a

three-mile distance. These results validated the

hydrocarbon reservoirs found in the Tahiti

discovery well, with one appraisal well

encountering more than 1,000 feet of net pay in

high-quality sandstones.

The Tahiti appraisal wells, located in Green

Canyon blocks 596 and 640, approximately 190

miles southwest of New Orleans, were drilled in

slightly more than 4,000 feet of water. The wells

were drilled simultaneously using two rigs, the

Glomar Explorer and the Transocean Inc.

Discoverer Deep Seas, each drilling a vertical well

with a sidetrack.

The Tahiti appraisal program has provided

verification of the company’s initial estimates of

400 million to 500 million barrels of ultimate

recoverable oil reserves. The estimates were

announced in June 2002, soon after the

discovery. {39}

 New Water-Depth Drilling Record: On

November 17, 2003 Transocean Inc. and

ChevronTexaco announced that the Transocean

drillship Discoverer Deep Seas had set a new

world water-depth drilling record by spudding

a well in 10,011 feet of water in the U.S. Gulf of

Mexico. The record — set while constructing

ChevronTexaco’s Toledo well in Alaminos

Canyon block 951 — marks the first time in the

offshore drilling industry’s history that a drilling

rig has explored for oil and natural gas in more

than 10,000 feet of water.

The previous world water-depth drilling record

was 9,727 feet of water in the U.S. Gulf of

Mexico by another Transocean drillship, the

Discoverer Spirit, in October 2001 working for

Unocal.

{40}

Other Gain Areas

Montana: Montana reported a net increase of 27

million barrels of proved oil reserves in 2003 and had

the third largest volume of extensions nationwide in

2003 (42 million barrels).

Illinois: Proved oil reserves in Illinois were revised

upwards by 17 percent (18 million barrels) in 2003 as

compared to 2002.

Areas of Note:

Large Reserves Declines

The following areas had large declines in crude oil

proved reserves due to downward revisions or

unreplaced production.

Texas

Texas’ crude oil proved reserves declined 9 percent

(-432 million barrels) in 2003. Operators also reported a

production decrease of 1 percent (-4 million barrels)

from the 2002 level.

Alaska

Alaskan crude oil proved reserves declined 5 percent

(-232 million barrels) in 2003. Alaskan operators

reported revision increases and extensions in 2003, but

this did not offset Alaska’s oil production—an

estimated 357 million barrels in 2003. Alaska

production decreased 1 percent (-4 million barrels)

from its 2002 level.

California

There was a net decline of 5 percent (-181 million

barrels) in California’s crude oil proved reserves in

2003. California’s crude oil production declined 4

percent (-11 million barrels) from its 2002 level.

Other Decline Areas

Discovery and development of new or existing oil

fields was also outpaced by crude oil production in the

following areas of the United States.

Louisiana: Proved oil reserves decreased

by 10 percent (-49 million barrels).

New Mexico: Proved oil reserves decreased

by 5 percent (-33 million barrels).

Energy Information Administration

26 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
Reserves in

Nonproducing Status

Not all proved reserves of crude oil reported in 2003

were producing. Operators reported 5,580 million

barrels of proved reserves in nonproducing status, 6

percent more than reported in 2002 (5,271 million

barrels). Nonproducing crude oil reserves (not

including lease condensate) are listed in Table 7.

Nonproducing reserves are those awaiting well

workovers, the drilling of extensions or additional

development wells, installation of production or

pipeline facilities, and depletion of other zones or

reservoirs before recompletion in reservoirs not

currently open to production.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 27

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, South Dakota, and Tennessee.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 2003.

Table 7. Reported Reserves in Nonproducing Status for Crude Oil, 2003 a

(Million Barrels of 42 U.S. Gallons)

Nonproducing Nonproducing Crude Oil Crude Oil

State and Subdivision Reserves State and Subdivision Reserves

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 734

Lower 48 States............................. 4,846

Alabama .................................. 2

Arkansas .................................. 2

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 313

Coastal Region Onshore . . . . . . . . . . . . . . . . . . . 61

Los Angeles Basin Onshore . . . . . . . . . . . . . . . . . 117

San Joaquin Basin Onshore. . . . . . . . . . . . . . . . . 110

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

Florida .................................... 6

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

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

Kansas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Kentucky .................................. 4

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 190

North. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

South Onshore . . . . . . . . . . . . . . . . . . . . . . . . . . . 150

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

Montana. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

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

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

East. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133

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

New York . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0

North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47

Ohio ...................................... 8

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

Pennsylvania ............................... 1

Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 613

RRC District 1. . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

RRC District 2 Onshore . . . . . . . . . . . . . . . . . . . . 12

RRC District 3 Onshore . . . . . . . . . . . . . . . . . . . . 37

RRC District 4 Onshore .................... 7

RRC District 5............................ 2

RRC District 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

RRC District 7B........................... 5

RRC District 7C . . . . . . . . . . . . . . . . . . . . . . . . . . 12

RRC District 8. . . . . . . . . . . . . . . . . . . . . . . . . . . . 165

RRC District 8A. . . . . . . . . . . . . . . . . . . . . . . . . . . 319

RRC District 9. . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

RRC District 10........................... 6

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

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

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

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

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

Federal Offshore ............................ 3,041

Pacific (California). . . . . . . . . . . . . . . . . . . . . . . . . 93

Gulf of Mexico (Louisiana) .................. 2,801

Gulf of Mexico (Texas) . . . . . . . . . . . . . . . . . . . . . 147

Miscellaneousb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

U.S. Total ................................. 5,580

4. Natural Gas Statistics

Dry Natural Gas

Proved Reserves

The United States had 189,044 billion cubic feet of dry

natural gas reserves as of December 31, 2003, a 1

percent increase over the 2002 level (Table 8). All

natural gas proved reserves data shown in this report

exclude natural gas held in underground storage.

Reserves additions were 111 percent of production

(Figure 18), and gas production increased 0.4 percent in

2003. Production declines in the Gulf of Mexico, New

Mexico, and Louisiana were offset by production

increases in Colorado, Texas, Oklahoma, and

Wyoming.

In 2003, Colorado, Texas, Wyoming, and Oklahoma

dominated dry gas reserves additions. This activity

continues the trend of developing “unconventional”

gas fields, i.e., tight sands, shales, and coalbeds.

Considering the growing contribution of this gas to the

National total, the term “unconventional” is becoming

a misnomer.

Additions to dry gas reserves in 2003 were 21,523

billion cubic feet, 6 percent less than in 2002. However,

U.S. total discoveries of dry natural gas reserves were

19,286 billion cubic feet in 2003, up 8 percent from 2002

(17,795 billion cubic feet).

Proved reserves by State are shown on the map in

Figure 19. Six areas account for 73 percent of the

Nation’s dry natural gas proved reserves:

Percent of

Area U.S. Gas Reserves

Texas 24

Wyoming 12

Gulf of Mexico Federal Offshore 12

New Mexico 9

Colorado 8

Oklahoma 8

Area Total 73

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 29

Figure 18. Reserve Additions Replace 111% of 2003 U.S. Dry Natural Gas Production

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

108% 107% 107% 104%

118%

152%

118%

111%

131%

83%



















        	

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

30 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

 	 
  	  

   
   	   
  	 


bIncludes Federal offshore Alabama.

c

Includes 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,” 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 2003 contained in the Natural Gas Annual 2003, DOE/EIA-0131(03).

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

Alaska ..................... 8,468 1 427 235 0 0 81 20 1 478 8,285

Lower 48 States ............. 178,478 2,840 19,485 21,315 10,174 11,208 16,373 1,202 1,609 18,947 180,759

Alabama.................... 3,884 -36 588 122 246 264 315 0 4 350 4,301

Arkansas ................... 1,650 21 148 134 63 82 125 0 0 166 1,663

California ................... 2,591 -52 301 172 60 47 55 5 0 265 2,450

Coastal Region Onshore . . . . . 190 5 13 30 2 2 0 0 0 11 167

Los Angeles Basin Onshore. . . 207 3 19 34 25 26 1 0 0 10 187

San Joaquin Basin Onshore . . 2,102 -60 263 99 33 19 54 5 0 238 2,013

State Offshore . . . . . . . . . . . . . 92 0 6 9 0 0 0 0 0 6 83

Colorado ................... 13,888 -3 2,114 812 429 604 1,215 1 0 1,142 15,436

Florida . . . . . . . . . . . . . . . . . . . . . 91 -9 0 0 0 0 0 0 0 3 79

Kansas..................... 4,983 149 206 180 230 239 78 0 0 426 4,819

Kentucky ................... 1,907 49 128 167 0 0 49 0 1 78 1,889

Louisiana ................... 8,960 281 792 1,159 622 513 1,584 12 244 1,280 9,325

North .................... 4,245 95 255 319 287 242 1,233 5 6 401 5,074

South Onshore............. 4,224 154 452 755 237 166 323 7 164 753 3,745

State Offshore . . . . . . . . . . . . . 491 32 85 85 98 105 28 0 74 126 506

Michigan ................... 3,254 65 303 235 201 386 74 0 2 220 3,428

Mississippi . . . . . . . . . . . . . . . . . . 744 -26 67 41 42 29 81 0 28 94 746

Montana. . . . . . . . . . . . . . . . . . . . 906 -28 46 26 225 326 146 0 0 86 1,059

New Mexico ................. 17,320 -104 1,547 1,941 652 852 1,394 3 16 1,415 17,020

East ..................... 3,632 -14 622 950 218 242 475 3 16 507 3,301

West..................... 13,688 -90 925 991 434 610 919 0 0 908 13,719

New York ................... a315 41 37 29 118 111 24 19 0 35 a365

North Dakota . . . . . . . . . . . . . . . . 471 25 36 44 1 6 5 0 0 50 448

Ohio ....................... a1,117 97 121 127 7 0 7 0 0 a82 1,126

Oklahoma .................. 14,886 226 2,892 2,843 1,598 1,864 1,509 6 13 1,554 15,401

Pennsylvania ................ 2,216 314 241 263 30 1 149 21 3 165 2,487

Texas ...................... 44,297 1,289 4,462 5,100 2,552 2,878 5,044 195 383 5,166 45,730

RRC District 1 ............. 1,045 36 59 87 15 6 109 0 9 100 1,062

RRC District 2 Onshore ...... 1,782 200 205 333 146 29 279 11 25 282 1,770

RRC District 3 Onshore ...... 3,584 45 383 531 191 83 458 50 44 576 3,349

RRC District 4 Onshore ...... 9,469 325 943 1,936 441 465 1,084 38 197 1,381 8,763

RRC District 5 ............. 4,602 130 706 278 336 350 638 5 47 457 5,407

RRC District 6 ............. 6,256 184 383 496 667 787 829 1 50 642 6,685

RRC District 7B . . . . . . . . . . . . 260 165 57 104 5 5 19 0 0 57 340

RRC District 7C ............ 3,702 149 425 173 36 91 507 1 11 350 4,327

RRC District 8 ............. 5,361 -97 546 532 202 207 322 21 0 484 5,142

RRC District 8A ............ 1,084 10 112 54 11 12 3 0 0 100 1,056

RRC District 9 ............. 2,877 0 116 154 211 563 450 0 0 332 3,309

RRC District 10 ............ 3,838 87 490 333 268 261 326 1 0 338 4,064

State Offshore . . . . . . . . . . . . . 437 55 37 89 23 19 20 67 0 67 456

Utah ....................... 4,135 40 188 767 729 690 230 0 7 278 3,516

Virginia..................... 1,673 1 45 37 0 0 117 0 0 82 1,717

West Virginia ................ 3,360 54 182 306 1 36 167 0 3 189 3,306

Wyoming ................... 20,527 132 2,072 2,704 333 406 3,068 32 0 1,456 21,744

Federal Offshoreb ............ 25,204 311 2,963 4,106 2,035 1,873 902 908 903 4,353 22,570

Pacific (California) . . . . . . . . . . 515 -1 41 2 0 0 5 0 0 47 511

Gulf of Mexico (Louisiana)b . . . 18,500 261 1,866 2,922 1,557 1,563 713 824 724 3,244 16,728

Gulf of Mexico (Texas)....... 6,189 51 1,056 1,182 478 310 184 84 179 1,062 5,331

Miscellaneousc . . . . . . . . . . . . . . 99 3 6 0 0 1 35 0 2 12 134

U.S. Total .................. 186,946 2,841 19,912 21,550 10,174 11,208 16,454 1,222 1,610 19,425 189,044

Table 8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 2003

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

Changes in Reserves During 2003

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Sales Acquisitions Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/02 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/03
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 31

Figure 20. Changes in Dry Natural Gas Proved Reserves by Area, 2002 to 2003

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

Figure 19. Dry Natural Gas Proved Reserves by Area, 2003
Discussion of Reserves Changes

Figure 20 maps the change in dry gas proved reserves

from 2002 to 2003 by area. Here’s how the top six areas

fared, compared to the total United States:

Change in

U.S. Gas Reserves

Area (billion cubic feet)

Texas +1,433

Wyoming +1,217

Gulf of Mexico Federal Offshore -2,630

New Mexico -300

Colorado +1,548

Oklahoma +515

Area Total +1,783

U.S. Total +2,098

Figure 4 in Chapter 2 shows the components of change

in dry natural gas proved reserves for 2003 and the

preceding 10 years.

Total 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 19,286 billion cubic feet in 2003, an 8

percent increase from the level reported in 2002. About

29 percent of the total discoveries were in Texas, 16

percent were in Wyoming, 14 percent were in the Gulf

of Mexico Federal Offshore, 10 percent were in

Louisiana, 8 percent were in Oklahoma, and 7 percent

were in New Mexico.

The largest component of total discoveries in 2003 were

extensions of existing gas fields. Extensions were

16,454 billion cubic feet, 11 percent more than 2002 and

66 percent more than the prior 10-year average (9,941

billion cubic feet). Areas with the largest extensions

and their percentage of total extensions were:

 Texas had 5,044 billion cubic feet of extensions

(31 percent of the total)

 Wyoming had 3,068 billion cubic feet (19

percent)

 Louisiana had 1,584 billion cubic feet (10

percent)

 Oklahoma had 1,509 billion cubic feet (9 percent)

 New Mexico had 1,394 billion cubic feet (8

percent)

 Colorado had 1,215 billion cubic feet (7 percent).

New field discoveries were 1,222 billion cubic feet in

2003—8 percent less than in 2002. The areas with the

largest new field discoveries were the Gulf of Mexico

Federal Offshore (with 908 billion cubic feet of new

field discoveries, 74 percent of the total), Texas (195

billion cubic feet, 16 percent), and Wyoming (32 billion

cubic feet, 3 percent). In the prior 10 years, U.S.

operators reported an average of 1,813 billion cubic feet

of reserves from new field discoveries per year.

Reserves from new field discoveries in 2003 were 33

percent less than that average.

New reservoir discoveries in old fields were 1,610

billion cubic feet, 5 percent less than 2002. The areas

with the largest new reservoir discoveries in old fields

and their percentage of the total were:

 Gulf of Mexico Federal Offshore (903 billion

cubic feet, 56 percent)

 Texas (383 billion cubic feet, 24 percent)

 Louisiana (244 billion cubic feet, 15 percent).

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

average of 2,451 billion cubic feet of reserves from new

reservoirs discovered in old fields per year. Reserves

from new reservoirs discovered in old fields in 2003

were 66 percent of that average.

Revisions and Adjustments

There were 19,912 billion cubic feet of revision

increases, 21,550 billion cubic feet of revision decreases,

and 2,841 billion cubic feet of adjustments in 2003.

Combined, there were 1,203 billion cubic feet of net

revisions and adjustments in 2003, excluding reserves

additions from net sales and acquisitions. This is 80

percent less than the average volume of net revisions

and adjustments of the prior 10 years (6,100 billion

cubic feet).

Energy Information Administration

32 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

   	



















    

Trillion Cubic Feet



	



Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 33

 	 
  	  

   
   	   
  	 


bIncludes Federal offshore Alabama.

c

Includes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, Oregon, South Dakota, and Tennessee.

Note: The prouction 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 2003 contained in the

Natural Gas Annual 2003, DOE/EIA-0131(03).

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

Alaska ..................... 8,533 -1 428 234 0 0 81 20 1 480 8,348

Lower 48 States ............. 187,028 2,324 20,352 22,261 10,593 11,700 17,114 1,232 1,652 19,751 188,797

Alabama.................... 3,922 -42 598 125 251 270 321 0 4 352 4,345

Arkansas ................... 1,654 19 149 134 63 82 125 0 0 166 1,666

California ................... 2,696 -36 317 180 63 50 57 5 0 277 2,569

Coastal Region Onshore . . . . . 197 5 14 31 2 2 0 0 0 11 174

Los Angeles Basin Onshore. . . 218 1 20 36 26 28 1 0 0 10 196

San Joaquin Basin Onshore . . 2,190 -43 277 104 35 20 56 5 0 250 2,116

State Offshore . . . . . . . . . . . . . 91 1 6 9 0 0 0 0 0 6 83

Colorado ................... 14,348 -51 2,176 836 442 622 1,250 1 0 1,175 15,893

Florida . . . . . . . . . . . . . . . . . . . . . 102 -7 0 0 0 0 0 0 0 3 92

Kansas..................... 5,329 148 219 192 245 256 83 0 0 455 5,143

Kentucky ................... 1,999 41 134 174 0 0 51 0 1 81 1,971

Louisiana ................... 9,190 278 815 1,193 638 525 1,612 12 254 1,317 9,538

North .................... 4,283 111 258 323 291 245 1,249 5 6 406 5,137

South Onshore............. 4,395 135 468 781 245 171 334 7 170 780 3,874

State Offshore . . . . . . . . . . . . . 512 32 89 89 102 109 29 0 78 131 527

Michigan ................... 3,311 69 308 240 205 392 75 0 2 224 3,488

Mississippi . . . . . . . . . . . . . . . . . . 746 -27 67 41 42 29 81 0 28 93 748

Montana. . . . . . . . . . . . . . . . . . . . 914 -29 46 26 227 329 147 0 0 86 1,068

New Mexico ................. 18,453 -3 1,672 2,106 703 915 1,503 3 18 1,526 18,226

East ..................... 4,011 2 690 1,054 242 268 527 3 18 562 3,661

West..................... 14,442 -5 982 1,052 461 647 976 0 0 964 14,565

New York ................... a315 41 37 29 118 111 24 19 0 35 a365

North Dakota . . . . . . . . . . . . . . . . 524 25 41 49 1 7 6 0 0 56 497

Ohio ....................... a1,118 97 121 127 7 0 7 0 0 a82 1,127

Oklahoma .................. 15,753 175 3,048 2,996 1,684 1,964 1,590 6 13 1,638 16,231

Pennsylvania ................ 2,225 313 242 264 30 1 150 22 3 165 2,497

Texas ...................... 47,491 1,053 4,750 5,396 2,699 3,060 5,346 200 395 5,483 48,717

RRC District 1 ............. 1,094 20 61 89 15 6 113 0 9 104 1,095

RRC District 2 Onshore ...... 1,867 205 214 348 153 30 292 11 26 295 1,849

RRC District 3 Onshore ...... 3,826 18 406 562 202 88 485 53 46 610 3,548

RRC District 4 Onshore ...... 9,861 258 974 2,000 455 481 1,121 39 203 1,427 9,055

RRC District 5 ............. 4,653 125 713 281 339 354 644 5 47 461 5,460

RRC District 6 ............. 6,561 144 399 516 695 819 862 1 52 668 6,959

RRC District 7B . . . . . . . . . . . . 294 186 64 118 6 6 22 0 0 65 383

RRC District 7C ............ 4,167 99 471 192 40 100 561 0 12 387 4,791

RRC District 8 ............. 6,056 -80 619 604 230 235 365 24 0 550 5,835

RRC District 8A ............ 1,167 12 121 59 12 13 3 0 0 108 1,137

RRC District 9 ............. 3,210 -50 128 169 231 620 496 0 0 365 3,639

RRC District 10 ............ 4,299 59 543 369 298 289 362 1 0 376 4,510

State Offshore . . . . . . . . . . . . . 436 57 37 89 23 19 20 66 0 67 456

Utah ....................... 4,274 20 194 789 750 710 237 0 7 286 3,617

Virginia..................... 1,673 1 45 37 0 0 117 0 0 82 1,717

West Virginia ................ 3,498 13 187 315 1 37 171 0 3 194 3,399

Wyoming ................... 21,531 52 2,164 2,825 347 424 3,205 33 0 1,521 22,716

Federal Offshoreb ............ 25,862 174 3,016 4,187 2,077 1,915 921 931 922 4,444 23,033

Pacific (California) . . . . . . . . . . 515 0 40 2 0 0 5 0 0 47 511

Gulf of Mexico (Louisiana)b . . . 19,113 141 1,916 2,998 1,597 1,604 731 846 742 3,330 17,168

Gulf of Mexico (Texas)....... 6,234 33 1,060 1,187 480 311 185 85 180 1,067 5,354

Miscellaneousc . . . . . . . . . . . . . . 100 0 6 0 0 1 35 0 2 10 134

U.S. Total .................. 195,561 2,323 20,780 22,495 10,593 11,700 17,195 1,252 1,653 20,231 197,145

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

2003 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 2003

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Sales Acquisitions Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/02 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/03
Energy Information Administration

34 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

 	
 
	 




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 2003 contained in the

Natural Gas Annual 2003, DOE/EIA-0131(03).

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

Alaska ..................... 2,157 0 241 215 0 0 81 20 1 204 2,081

Lower 48 States ............. 163,863 2,121 17,495 19,490 9,553 10,638 16,297 785 1,528 17,172 166,512

Alabama.................... 3,891 -45 595 125 251 270 321 0 4 347 4,313

Arkansas ................... 1,616 17 146 132 63 81 125 0 0 161 1,629

California . . . . . . . . . . . . . . . . . . . 796 -22 70 28 15 4 36 5 0 87 759

Coastal Region Onshore . . . . . 0 -1 2 0 0 0 0 0 0 0 1

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

San Joaquin Basin Onshore . . 790 -21 65 27 15 4 36 5 0 86 751

State Offshore ............. 6 0 3 1 0 0 0 0 0 1 7

Colorado ................... 13,251 -64 2,068 826 438 615 1,185 1 0 1,085 14,707

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

Kansas..................... 5,263 144 195 187 245 255 79 0 0 446 5,058

Kentucky ................... 1,974 40 134 174 0 0 51 0 1 80 1,946

Louisiana ................... 8,520 270 704 1,051 559 464 1,573 12 246 1,227 8,952

North .................... 4,124 113 241 309 283 241 1,246 5 6 386 4,998

South Onshore............. 3,968 126 397 671 202 142 302 7 165 728 3,506

State Offshore . . . . . . . . . . . . . 428 31 66 71 74 81 25 0 75 113 448

Michigan ................... 3,097 50 225 197 82 244 75 0 2 195 3,219

Mississippi . . . . . . . . . . . . . . . . . . 713 -26 59 37 40 28 81 0 28 85 721

Montana. . . . . . . . . . . . . . . . . . . . 820 -21 39 23 227 325 122 0 0 79 956

New Mexico ................. 16,971 31 1,320 1,936 650 831 1,379 3 16 1,284 16,681

East ..................... 2,632 37 345 895 192 184 403 3 16 328 2,205

West..................... 14,339 -6 975 1,041 458 647 976 0 0 956 14,476

New York . . . . . . . . . . . . . . . . . . . 315 41 37 29 118 111 24 19 0 35 365

North Dakota . . . . . . . . . . . . . . . . 209 11 4 30 0 2 2 0 0 17 181

Ohio . . . . . . . . . . . . . . . . . . . . . . . 772 107 112 106 7 0 7 0 0 62 823

Oklahoma .................. 14,576 184 2,908 2,838 1,603 1,923 1,511 6 10 1,501 15,176

Pennsylvania ................ 2,088 279 229 249 30 1 146 22 3 156 2,333

Texas ...................... 41,104 935 3,843 4,885 2,452 2,846 5,111 199 394 4,815 42,280

RRC District 1 ............. 1,047 20 57 87 14 6 108 0 9 99 1,047

RRC District 2 Onshore ...... 1,797 205 189 342 150 29 276 11 26 273 1,768

RRC District 3 Onshore ...... 3,219 8 332 433 164 78 429 53 46 524 3,044

RRC District 4 Onshore ...... 9,711 248 955 1,971 449 476 1,116 39 202 1,408 8,919

RRC District 5 ............. 4,588 126 702 277 327 344 644 5 47 454 5,398

RRC District 6 ............. 6,161 125 340 491 692 809 862 1 52 595 6,572

RRC District 7B . . . . . . . . . . . . 237 198 26 113 4 3 19 0 0 52 314

RRC District 7C ............ 3,430 45 319 163 26 85 474 0 12 312 3,864

RRC District 8 ............. 3,284 -87 257 443 102 94 327 23 0 321 3,032

RRC District 8A . . . . . . . . . . . . 101 0 17 4 0 2 0 0 0 16 100

RRC District 9 ............. 3,070 -57 110 140 229 620 488 0 0 348 3,514

RRC District 10 ............ 4,028 49 502 332 272 281 348 1 0 347 4,258

State Offshore . . . . . . . . . . . . . 431 55 37 89 23 19 20 66 0 66 450

Utah ....................... 3,915 23 174 721 713 667 232 0 7 266 3,318

Virginia..................... 1,673 1 45 37 0 0 117 0 0 82 1,717

West Virginia ................ 3,477 14 182 314 1 37 171 0 3 193 3,376

Wyoming ................... 20,970 -24 2,128 2,667 336 418 3,202 33 0 1,458 22,266

Federal Offshorea ............ 17,772 171 2,272 2,898 1,723 1,515 712 485 812 3,502 15,616

Pacific (California) . . . . . . . . . . 56 0 1 0 0 0 0 0 0 2 55

Gulf of Mexico (Louisiana)a . . . 12,749 137 1,415 1,843 1,321 1,220 527 404 638 2,600 11,326

Gulf of Mexico (Texas)....... 4,967 34 856 1,055 402 295 185 81 174 900 4,235

Miscellaneousb . . . . . . . . . . . . . . 80 5 6 0 0 1 35 0 2 9 120

U.S. Total .................. 166,020 2,121 17,736 19,705 9,553 10,638 16,378 805 1,529 17,376 168,593

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

Wet After Lease Separation, 2003 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

  	
 	 


Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Sales Acquisitions Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/02 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/03
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 35

 	
 
	 




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 2003 contained in the

Natural Gas Annual 2003, DOE/EIA-0131(03).

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

Alaska ..................... 6,376 -1 187 19 0 0 0 0 0 276 6,267

Lower 48 States ............. 23,165 203 2,857 2,771 1,040 1,062 817 447 124 2,579 22,285

Alabama. . . . . . . . . . . . . . . . . . . . 31 3 3 0 0 0 0 0 0 5 32

Arkansas . . . . . . . . . . . . . . . . . . . 38 2 3 2 0 1 0 0 0 5 37

California ................... 1,900 -14 247 152 48 46 21 0 0 190 1,810

Coastal Region Onshore . . . . . 197 6 12 31 2 2 0 0 0 11 173

Los Angeles Basin Onshore. . . 218 1 20 36 26 28 1 0 0 10 196

San Joaquin Basin Onshore . . 1,400 -22 212 77 20 16 20 0 0 164 1,365

State Offshore . . . . . . . . . . . . . 85 1 3 8 0 0 0 0 0 5 76

Colorado ................... 1,097 13 108 10 4 7 65 0 0 90 1,186

Florida . . . . . . . . . . . . . . . . . . . . . 102 -7 0 0 0 0 0 0 0 3 92

Kansas. . . . . . . . . . . . . . . . . . . . . 66 4 24 5 0 1 4 0 0 9 85

Kentucky . . . . . . . . . . . . . . . . . . . 25 1 0 0 0 0 0 0 0 1 25

Louisiana . . . . . . . . . . . . . . . . . . . 670 8 111 142 79 61 39 0 8 90 586

North . . . . . . . . . . . . . . . . . . . . 159 -2 17 14 8 4 3 0 0 20 139

South Onshore. . . . . . . . . . . . . 427 9 71 110 43 29 32 0 5 52 368

State Offshore . . . . . . . . . . . . . 84 1 23 18 28 28 4 0 3 18 79

Michigan . . . . . . . . . . . . . . . . . . . 214 19 83 43 123 148 0 0 0 29 269

Mississippi . . . . . . . . . . . . . . . . . . 33 -1 8 4 2 1 0 0 0 8 27

Montana. . . . . . . . . . . . . . . . . . . . 94 -8 7 3 0 4 25 0 0 7 112

New Mexico ................. 1,482 -34 352 170 53 84 124 0 2 242 1,545

East ..................... 1,379 -35 345 159 50 84 124 0 2 234 1,456

West. . . . . . . . . . . . . . . . . . . . . 103 1 7 11 3 0 0 0 0 8 89

New York ................... 0 0 0 0 0 0 0 0 0 0 0

North Dakota . . . . . . . . . . . . . . . . 315 14 37 19 1 5 4 0 0 39 316

Ohio . . . . . . . . . . . . . . . . . . . . . . . 346 -10 9 21 0 0 0 0 0 20 304

Oklahoma .................. 1,177 -9 140 158 81 41 79 0 3 137 1,055

Pennsylvania . . . . . . . . . . . . . . . . 137 34 13 15 0 0 4 0 0 9 164

Texas ...................... 6,387 118 907 511 247 214 235 1 1 668 6,437

RRC District 1 . . . . . . . . . . . . . 47 0 4 2 1 0 5 0 0 5 48

RRC District 2 Onshore . . . . . . 70 0 25 6 3 1 16 0 0 22 81

RRC District 3 Onshore . . . . . . 607 10 74 129 38 10 56 0 0 86 504

RRC District 4 Onshore . . . . . . 150 10 19 29 6 5 5 0 1 19 136

RRC District 5 . . . . . . . . . . . . . 65 -1 11 4 12 10 0 0 0 7 62

RRC District 6 . . . . . . . . . . . . . 400 19 59 25 3 10 0 0 0 73 387

RRC District 7B . . . . . . . . . . . . 57 -12 38 5 2 3 3 0 0 13 69

RRC District 7C . . . . . . . . . . . . 737 54 152 29 14 15 87 0 0 75 927

RRC District 8 ............. 2,772 7 362 161 128 141 38 1 0 229 2,803

RRC District 8A ............ 1,066 12 104 55 12 11 3 0 0 92 1,037

RRC District 9 . . . . . . . . . . . . . 140 7 18 29 2 0 8 0 0 17 125

RRC District 10 . . . . . . . . . . . . 271 10 41 37 26 8 14 0 0 29 252

State Offshore ............. 5 2 0 0 0 0 0 0 0 1 6

Utah . . . . . . . . . . . . . . . . . . . . . . . 359 -3 20 68 37 43 5 0 0 20 299

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

West Virginia . . . . . . . . . . . . . . . . 21 -1 5 1 0 0 0 0 0 1 23

Wyoming . . . . . . . . . . . . . . . . . . . 561 76 36 158 11 6 3 0 0 63 450

Federal Offshorea ............ 8,090 3 744 1,289 354 400 209 446 110 942 7,417

Pacific (California) . . . . . . . . . . 459 0 39 2 0 0 5 0 0 45 456

Gulf of Mexico (Louisiana)a . . . 6,364 4 501 1,155 276 384 204 442 104 730 5,842

Gulf of Mexico (Texas)....... 1,267 -1 204 132 78 16 0 4 6 167 1,119

Miscellaneousb . . . . . . . . . . . . . . 20 -5 0 0 0 0 0 0 0 1 14

U.S. Total .................. 29,541 202 3,044 2,790 1,040 1,062 817 447 124 2,855 28,552

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

Wet After Lease Separation, 2003 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 2003

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Sales Acquisitions Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/02 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/03
Sales and Acquisitions

Sales represents that volume of dry natural gas proved

reserves deducted from an operator’s total through

sale or transfer of operations of an existing gas field or

properties to another operator (not a volume of

production “sold” at the wellhead). Similarly,

acquisitions are that volume of proved reserves added

to an operator’s total by purchase or operations

transfer of an existing gas field or properties.

In 2003, there were 10,174 billion cubic feet of sales

transactions between operators, and 11,208 billion

cubic feet of acquisitions. The net difference of 1,034

billion cubic feet was added to the National total of dry

natural gas reserves in 2003.

Production

The estimated 2003 U.S. dry natural gas production

was 19,425 billion cubic feet, an increase of less than 1

percent from 2002 (Table 8). Areas with the largest

production and their percentage of total production

were:

 Texas produced 5,166 billion cubic feet (BCF) of

dry natural gas (27 percent of the total)

 Gulf of Mexico Federal Offshore produced 4,306

BCF (22 percent)

 Oklahoma produced 1,554 BCF (8 percent)

 Wyoming produced 1,456 BCF (7 percent)

 New Mexico produced 1,415 BCF (7 percent)

 Louisiana produced 1,280 BCF (7 percent)

 Colorado produced 1,142 BCF (6 percent of the

National total).

In 2003, Colorado’s reported annual dry natural gas

production exceeded 1 TCF for the first time.

Wet Natural Gas

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

31, 2003 were 197,145 billion cubic feet, a 1 percent

increase from the volume reported in 2002 (Table 9). At

year-end 2003, proved wet natural gas reserves for the

lower 48 States had increased by 1 percent compared to

2002, 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 appears in Appendix F.

Nonassociated Natural Gas

Proved Reserves

Proved reserves of nonassociated (NA) natural gas, wet

after lease separation, in the United States increased by

2 percent (+2,573 billion cubic feet) in 2003 to 168,593

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

wet natural gas proved reserves increased 2 percent to a

level of 166,512 billion cubic feet, while Alaska had a 4

percent decline to a level of 2,081 billion cubic feet.

Those States with the largest increases in NA wet

natural gas reserves were Colorado, Wyoming, and

Texas.

Total Discoveries

NA wet natural gas total discoveries of 18,712 billion

cubic feet in 2003 increased 9 percent compared to

2002’s total of 17,182 billion cubic feet. Areas with the

most total discoveries in 2003 were Texas (5,704 billion

cubic feet), Wyoming (3,235 billion cubic feet), the Gulf

of Mexico Federal Offshore (2,009 billion cubic feet),

Louisiana (1,831 billion cubic feet), Oklahoma (1,527

billion cubic feet), and New Mexico (1,398 billion cubic

feet).

Production

U.S. production of NA wet natural gas increased less

than 1 percent from an estimated 17,260 billion cubic

feet in 2002 to 17,376 billion cubic feet in 2003. The five

leading producing areas were: Texas (28 percent), the

Gulf of Mexico Federal Offshore (20 percent),

Oklahoma (9 percent), Wyoming (8 percent), and New

Mexico (7 percent).

Associated-Dissolved Natural Gas

Proved Reserves

Proved reserves of associated-dissolved (AD) natural

gas, wet after lease separation, in the United States

declined 3 percent to 28,552 billion cubic feet in 2003

(Table 11). Proved reserves of AD wet natural gas in the

lower 48 States decreased by 4 percent (-880 billion

cubic feet) to 22,285 billion cubic feet, and in Alaska

Energy Information Administration

36 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
declined 2 percent (-109 billion cubic feet) to 6,267

billion cubic feet in 2003. The areas of the country with

the largest AD wet natural gas reserves and their

percentage of the total were:

 Gulf of Mexico Federal Offshore (24 percent)

 Texas (23 percent)

 Alaska (22 percent)

 California (6 percent)

 New Mexico (5 percent).

These areas logically correspond to the areas of the

country with the largest volumes of crude oil reserves.

Production

U.S. production of AD wet natural gas decreased 4

percent from an estimated 2,988 billion cubic feet in

2002 to 2,855 billion cubic feet in 2003 (Table 11).

Production of AD wet natural gas in the lower 48 States

decreased from 2,726 billion cubic feet to 2,579 billion

cubic feet in 2003, a decline of 5 percent. The areas of the

country with the largest AD wet natural gas production

and their percentage of the total were:

 Gulf of Mexico Federal Offshore (31 percent)

 Texas (23 percent)

 Alaska (10 percent)

 New Mexico (8 percent)

 California (7 percent).

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 37

Table 12. Coalbed Methane Proved Reserves and Production, 1989–2003

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

New Eastern Western United

Year Alabama Colorado Mexico Utah Wyoming Statesa Statesb Othersc States

Reserves

1989 537 1,117 2,022     0 3,676

1990 1,224 1,320 2,510     33 5,087

1991 1,714 2,076 4,206     167 8,163

1992 1,968 2,716 4,724     626 10,034

1993 1,237 3,107 4,775     1,065 10,184

1994 976 2,913 4,137     1,686 9,712

1995 972 3,461 4,299     1,767 10,499

1996 823 3,711 4,180     1,852 10,566

1997 1,077 3,890 4,351     2,144 11,462

1998 1,029 4,211 4,232     2,707 12,179

1999 1,060 4,826 4,080     3,263 13,229

2000 1,241 5,617 4,278 1,592 1,540 1,399 41 -- 15,708

2001 1,162 6,252 4,324 1,685 2,297 1,453 358 -- 17,531

2002 1,283 6,691 4,380 1,725 2,371 1,488 553 -- 18,491

2003 1,665 6,473 4,396 1,224 2,759 1,528 698 -- 18,743

Production

1989 23 12 56     0 91

1990 36 26 133     1 196

1991 68 48 229     3 348

1992 89 82 358     10 539

1993 103 125 486     18 752

1994 108 179 530     34 851

1995 109 226 574     47 956

1996 98 274 575     56 1,003

1997 111 312 597     70 1,090

1998 123 401 571     99 1,194

1999 108 432 582     130 1,252

2000 109 451 550 74 133 58 4 -- 1,379

2001 111 490 517 83 278 69 14 -- 1,562

2002 117 520 471 103 302 68 33 -- 1,614

2003 98 488 451 97 344 71 51 -- 1,600

aIncludes Indiana, Ohio, Pennsylvania, Virginia, and West Virginia. bIncludes Arkansas, Kansas, Montana, and Oklahoma.

cIncludes Oklahoma, Pennsylvania, Utah, Virginia, West Virginia, and Wyoming; these states are individually listed or grouped in

Eastern States and Western States for 2000-2003.

NA = Not applicable.

Source: Energy Information Administration, Office of Oil and Gas.
Again, these areas logically correspond to the areas of

the country with the largest volumes of crude oil

production.

Coalbed Methane

Proved Reserves

Proved reserves of coalbed methane increased to 18,743

billion cubic feet in 2003, a 1 percent increase over the

2002 level (18,491 billion cubic feet). Coalbed methane

accounted for 10 percent of all 2003 dry natural gas

reserves (Table 12). For the ninth year in a row, gas

reserves of fields identified as having coalbed methane

have increased (Figure 21). Five States (Colorado, New

Mexico, Wyoming, Utah, and Alabama) currently have

the majority (88 percent) of U.S. coalbed methane

proved reserves. Colorado and Utah reported declines

in their proved coalbed methane reserves in 2003.

Production

U.S. coalbed methane production declined less than 1

percent in 2003 to 1,600 billion cubic feet. It accounted

for 8 percent of U.S. dry gas production.

Areas of Note:

Large Discoveries and

Reserves Additions

The following State or area discussions summarize

notable activities during the year concerning expected

new field reserves, development plans, and possible

production rates as extracted from various trade

publications and company reports. The citations do not

necessarily reflect EIA’s concurrence, but are

considered important enough to be brought to the

reader’s attention.

Colorado

Colorado had a net increase of 1,548 billion cubic feet of

dry natural gas proved reserves in 2003, the largest of

any State. This was primarily due to development of

the Wattenberg Field, the Mamm Creek Field, and

coalbed methane reserves in the Raton Basin.

 Wattenberg Field: Onshore in the lower 48

States, Kerr-McGee Corporation’s exploration

and field exploitation programs target natural

gas to help meet strong domestic demand. Use

of 3-D seismic surveys, new well-stimulation

techniques and creative collaboration with

service companies enable the company to extract

Energy Information Administration

38 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report























       	      

U.S. CBM Reserves, Trillion Cubic Feet

Figure 21. Coalbed Methane Proved Reserves, 1989-2003

Source: Energy Information Administration, Office of Oil and Gas.
additional production from mature fields.

About a third of Kerr-McGee’s worldwide 2003

natural gas production flowed from tight sands

in Colorado and South Texas. These

unconventional reservoirs consist of harder, less

permeable rock formations than conventional

fields but are long-lived and generate

predictable cash flow at low unit cost. In

Colorado’s Wattenberg field, Kerr-McGee

operates more than 3,100 wells and a 1,600-mile

gathering system. Production techniques include

infill drilling, fracture stimulation, well

deepenings and recompletions.{40}

 Mamm Creek Field: Oil and Gas Investor

Magazine recently named EnCana Corporation’s

Mamm Creek Field as the Best Field

Rejuvenation in 2003, recognizing the

tremendous growth achieved over the past

couple of years from this high-quality Colorado

property. This is a success story of continuous

innovation. Mamm Creek’s gas-bearing zone is

typically 2,500 feet thick. These tight sandstone

reservoirs contain large volumes of natural gas

that are trapped by the dense structure of the

rock. Freeing the gas requires high-pressure rock

fracturing.

In 2000, the accepted technique called for

splitting the gas-bearing zone into several zones

through fracture stimulation, yielding typical

initial gas production rates of about 500,000

cubic feet per day. Through experiment and

pilot testing, EnCana has made great strides

with more frequent fracs across narrower

intervals. Instead of two big frac jobs, EnCana

now executes up to eight fracs across the same

2,500-foot zone. When improved fracturing

techniques are applied, the gains are

monumental, tripling production to more than

1.4 million cubic feet per day from the same

formations. {41}

Texas

Texas had a 3 percent increase in dry natural gas proved

reserves in 2003 (+1,433 billion cubic feet). Production

also increased 3 percent (+128 billion cubic feet). This

resulted from exploration in South Texas and

extensions of existing gas fields in the Permian Basin

and the Newark East Field in north central Texas.

 Newark East Field: Devon Energy Corporation

has drilled about 800 wells into the Barnett Shale

since 2001. Use of fracturing technology has

helped Devon increase its Barnett production

from 345 million cubic feet of natural gas

equivalent per day to nearly 600 million today.

In all, Devon is operating more than 1,700 wells

in what is known as the Barnett’s core area,

where dense layers of limestone separate the

shale’s gas deposits from the watery Ellenberger

formation which lies below.

Today, Devon is continuing to confront the most

challenging questions in the Barnett. It ventured

outside the core with horizontal drilling projects

where geological complexities have impeded

development in the past. Those projects have

shown promise, and Devon geoscientists

continue to explore the Barnett’s non-core area,

where it is a major lease holder with 390,000 net

acres of land. Through Devon’s pioneering

effort, the Barnett Shale formation has emerged

as the largest natural gas field in Texas and one

of the most important gas fields in the nation.

With recent inroads into the vast non-core area,

the Barnett has potential to remain one of the

country’s most vital energy resources for years

to come. Devon’s accomplishments in the

Barnett are an example of how technology and

innovation are helping to meet growing energy

demands by finding new ways to tap North

America’s remaining reserves. {42}

Wyoming

Wyoming’s dry natural gas reserves increased by 1,217

billion cubic feet in 2003. This was the result of

development in the Pinedale and Jonah fields, and in

coalbed methane fields located in the Powder River

Basin.

 Jonah Field: Spanning just 30 square miles in

southwest Wyoming, the Jonah natural gas field

contains an estimated 10 trillion cubic feet of

original gas-in-place and EnCana Corporation

owns about 75 percent of it. Jonah’s gas

treasures lay deep underground, in a zone

between 8,000 and 11,500 feet. Since Jonah’s

discovery in 1986, wells have been drilled on 40

acre spacing. Through pilot projects, we have

determined there’s plenty of untapped natural

gas between existing wells. Initial tests of these

infill wells have discovered several geological

horizons at original pressures and exhibited

production rates similar to existing

wider-spaced wells. Knowing there’s far more

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 39
gas to recover, we are seeking regulatory

approval to increase drilling density. This

approval process includes completion of an

environmental impact assessment by the U.S.

Bureau of Land Management, which is expected

later in 2004. Upon approval, EnCana plans to

increase drilling and significantly grow

production. This infill potential adds a five-year

inventory of up to 1,200 wells. Add to that the

application of recompletion techniques of

bypassed zones in wells drilled before 2000 and

the future of Jonah looks bright. In the second

quarter of 2004, EnCana’s gas production

averaged 387 million cubic feet per day from the

Jonah field. {43}

Areas of Note:

Large Reserves Declines

The following areas had large declines in dry natural

gas proved reserves due to downward revisions or

unreplaced production.

Gulf of Mexico Federal Offshore

Proved dry natural gas reserves in the Gulf of Mexico

Federal Offshore decreased by 11 percent (-2,630 billion

cubic feet) in 2003. Production decreased 3 percent

from 4,423 billion cubic feet in 2002 to 4,306 billion

cubic feet in 2003.

Utah

Utah’s proved dry natural gas reserves decreased by 15

percent (-619 billion cubic feet) in 2003. Production in

Utah decreased 3 percent (-8 billion cubic feet) in 2003.

New Mexico

New Mexico’s proved dry natural gas reserves

decreased by 2 percent (-300 billion cubic feet) in 2003.

Production in New Mexico decreased 7 percent (-109

billion cubic feet) in 2003.

Reserves in

Nonproducing Status

Nonproducing proved natural gas reserves (wet after

lease separation) of 49,068 billion cubic feet were

reported in 2003, 2 percent less than the 49,974 billion

cubic feet reported in 2002 (Appendix D, Table D10).

About 24 percent of the reserves in nonproducing

status are located in Texas. Another 22 percent are in

the Gulf of Mexico Federal Offshore, as most new

deepwater reserves are in the nonproducing category.

Wells or reservoirs are nonproducing due to any of

several operational reasons. These include awaiting

well workovers, the drilling of extensions or additional

development wells, installation of production or

pipeline facilities, and depletion of other zones or

reservoirs before recompletion in reservoirs not

currently open to production (called “behind pipe”

reserves).

Energy Information Administration

40 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
5. Natural Gas Liquids Statistics

Natural Gas Liquids

Proved Reserves

U.S. natural gas liquids proved reserves decreased 7

percent to 7,459 million barrels in 2003 (Table 13). The

significant decline is a result of changes in the relative

economics of natural gas and natural gas liquids, in the

liquids content of the gas production, and a reduction

in the number of U.S. gas plants active in 2003. Reserve

additions replaced only 33 percent of 2003 natural gas

liquids production.

The reserves of seven areas account for 87 percent of the

Nation’s natural gas liquids proved reserves.

Percent of

Area U.S. NGL Reserves

Texas 34

Utah - Wyoming 12

New Mexico 12

Gulf of Mexico Federal Offshore 10

Oklahoma 9

Colorado 5

Alaska 5

Area Total 87

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.

Total Discoveries

Total discoveries of natural gas liquids reserves were

736 million barrels in 2003, a decrease of less than 1

percent from 2002 (738 million barrels). Areas with the

largest total discoveries were:

 Texas (37 percent of the National total)

 Utah & Wyoming (17 percent)

 Gulf of Mexico Federal Offshore (13 percent)

 New Mexico (11 percent)

 Oklahoma (9 percent)

 Louisiana (7 percent).

New field discoveries in 2003 (35 million barrels) were

27 percent lower than in 2002(48 million barrels). Areas

with the largest new field discoveries were the Gulf of

Mexico Federal Offshore (71 percent of the National

total), Texas (26 percent), and Utah and Wyoming (3

percent).

New reservoir discoveries in old fields (72 million

barrels) were 8 percent lower than they were in 2002 (78

million barrels). Areas with the largest new reservoir

discoveries in old fields were the Gulf of Mexico

Federal Offshore (51 percent of the National total),

Texas (25 percent), and Louisiana (22 percent).

Extensions were 629 million barrels in 2002, 3 percent

more than the 2002 volume of 612 million barrels. Areas

with the largest extensions were Texas (39 percent of

the National total), Utah & Wyoming (19 percent),

New Mexico (12 percent), and Oklahoma (10 percent).

Revisions and Adjustments

In 2003, there were 882 million barrels of revision

increases, 1,043 million barrels of revision decreases

and -338 million barrels of adjustments. The net of

revisions and adjustments was -499 million barrels.

Sales and Acquisitions

There were 433 million barrels of acquisitions, and 403

million barrels of sales in 2003. The net of these

transactions added 30 million barrels of natural gas

liquids proved reserves.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 41

  	
 

















   

Millions of Barrels



	



Energy Information Administration

42 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

 	
 
	 




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 2003 contained in the publications Petroleum Supply

Annual 2003, DOE/EIA-0340(03) and Natural Gas Annual 2003 DOE/EIA-0131(03).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 405 0 0 0 0 0 0 0 0 18 387

Lower 48 States ............. 7,589 -338 882 1,043 403 433 629 35 72 784 7,072

Alabama. . . . . . . . . . . . . . . . . . . . 57 -2 8 3 4 4 5 0 0 5 60

Arkansas . . . . . . . . . . . . . . . . . . . 4 -1 0 0 0 0 0 0 0 0 3

California . . . . . . . . . . . . . . . . . . . 95 11 12 9 2 2 2 0 0 10 101

Coastal Region Onshore . . . . . 17 1 1 3 0 0 0 0 0 1 15

Los Angeles Basin Onshore. . . 10 -1 1 2 1 1 0 0 0 0 8

San Joaquin Basin Onshore . . 68 11 10 4 1 1 2 0 0 9 78

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

Colorado . . . . . . . . . . . . . . . . . . . 396 -38 51 21 10 13 33 0 0 29 395

Florida . . . . . . . . . . . . . . . . . . . . . 14 4 0 0 0 0 0 0 0 1 17

Kansas. . . . . . . . . . . . . . . . . . . . . 263 3 11 10 12 12 4 0 0 23 248

Kentucky . . . . . . . . . . . . . . . . . . . 66 3 4 6 0 0 2 0 0 3 66

Louisiana . . . . . . . . . . . . . . . . . . . 323 15 52 79 23 19 34 0 16 62 295

North . . . . . . . . . . . . . . . . . . . . 49 12 6 7 4 3 15 0 0 7 67

South Onshore. . . . . . . . . . . . . 226 3 39 63 12 8 16 0 8 43 182

State Offshore . . . . . . . . . . . . . 48 0 7 9 7 8 3 0 8 12 46

Michigan . . . . . . . . . . . . . . . . . . . 47 1 5 6 3 6 1 0 0 3 48

Mississippi .................. 8 0 1 1 0 0 0 0 0 1 7

Montana.................... 6 1 0 0 1 2 1 0 0 1 8

New Mexico . . . . . . . . . . . . . . . . . 838 66 103 137 39 47 78 0 1 82 875

East . . . . . . . . . . . . . . . . . . . . . 290 10 53 81 19 20 40 0 1 42 272

West. . . . . . . . . . . . . . . . . . . . . 548 56 50 56 20 27 38 0 0 40 603

North Dakota . . . . . . . . . . . . . . . . 47 3 4 6 0 1 0 0 0 4 45

Oklahoma . . . . . . . . . . . . . . . . . . 695 -23 124 123 69 86 66 0 0 70 686

Texas ...................... 2,711 -180 267 302 123 147 246 9 18 276 2,517

RRC District 1 . . . . . . . . . . . . . 39 -9 1 2 0 0 2 0 0 2 29

RRC District 2 Onshore . . . . . . 71 6 9 13 7 1 12 0 1 11 69

RRC District 3 Onshore . . . . . . 241 -26 29 30 9 4 27 4 4 37 207

RRC District 4 Onshore . . . . . . 370 -53 38 70 14 16 38 2 7 47 287

RRC District 5 . . . . . . . . . . . . . 50 -3 6 4 3 3 6 0 0 4 51

RRC District 6 . . . . . . . . . . . . . 277 -21 19 42 26 31 29 0 5 24 248

RRC District 7B . . . . . . . . . . . . 25 15 5 10 0 0 2 0 0 5 32

RRC District 7C . . . . . . . . . . . . 351 -40 35 16 4 8 39 0 1 29 345

RRC District 8 . . . . . . . . . . . . . 510 9 54 60 21 21 31 2 0 48 498

RRC District 8A . . . . . . . . . . . . 181 -11 17 9 2 2 0 0 0 15 163

RRC District 9 . . . . . . . . . . . . . 238 -30 9 12 15 39 32 0 0 25 236

RRC District 10 . . . . . . . . . . . . 353 -18 45 33 22 22 28 0 0 28 347

State Offshore ............. 5 1 0 1 0 0 0 1 0 1 5

Utah and Wyoming . . . . . . . . . . . 938 -70 115 144 33 32 121 1 0 62 898

West Virginia . . . . . . . . . . . . . . . . 99 -29 4 6 0 1 3 0 0 4 68

Federal Offshorea . . . . . . . . . . . . 973 -101 118 189 84 61 33 25 37 148 725

Pacific (California) .......... 8 0 0 0 0 0 0 0 0 0 8

Gulf of Mexico (Louisiana)a . . . 783 -93 89 129 77 58 30 25 32 120 598

Gulf of Mexico (Texas). . . . . . . 182 -8 29 60 7 3 3 0 5 28 119

Miscellaneousb . . . . . . . . . . . . . . 9 -1 3 1 0 0 0 0 0 0 10

U.S. Total .................. 7,994 -338 882 1,043 403 433 629 35 72 802 7,459

Table 13. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 2003

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 2003

Published New Reservoir

Proved Revision Revision New Field Discoveries Estimated Proved

Reserves Adjustments Increases Decreases Sales Acquisitions Extensions Discoveries in Old Fields Production Reserves

State and Subdivision 12/31/02 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/03
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 43

Table 14. Natural Gas Plant Liquids Proved Reserves and Production, 2003

(Million Barrels of 42 U.S. Gallons)

2003 2003 2003 2003

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska . . . . . . . . . . . . . . . . . . . . . . 387 18

Lower 48 States.............. 5,857 593

Alabama . . . . . . . . . . . . . . . . . . . . 33 2

Arkansas .................... 2 0

California. . . . . . . . . . . . . . . . . . . . 101 10

Coastal Region Onshore . . . . . 15 1

Los Angeles Basin Onshore . . . 8 0

San Joaquin Basin Onshore. . . 78 9

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

Colorado . . . . . . . . . . . . . . . . . . . . 325 24

Florida . . . . . . . . . . . . . . . . . . . . . . 17 1

Kansas . . . . . . . . . . . . . . . . . . . . . 245 22

Kentucky . . . . . . . . . . . . . . . . . . . . 65 3

Louisiana. . . . . . . . . . . . . . . . . . . . 183 33

North. . . . . . . . . . . . . . . . . . . . . 48 4

South Onshore . . . . . . . . . . . . . 100 20

State Offshore. . . . . . . . . . . . . . 35 9

Michigan . . . . . . . . . . . . . . . . . . . . 44 3

Mississippi................... 2 0

Montana .................... 7 1

New Mexico . . . . . . . . . . . . . . . . . 824 76

East . . . . . . . . . . . . . . . . . . . . . 251 38

West . . . . . . . . . . . . . . . . . . . . . 573 38

North Dakota. . . . . . . . . . . . . . . . . 40 4

Oklahoma . . . . . . . . . . . . . . . . . . . 582 59

Texas....................... 2,192 229

RRC District 1. . . . . . . . . . . . . . 24 2

RRC District 2 Onshore . . . . . . 56 9

RRC District 3 Onshore . . . . . . 135 23

RRC District 4 Onshore . . . . . . 202 32

RRC District 5. . . . . . . . . . . . . . 40 3

RRC District 6. . . . . . . . . . . . . . 195 19

RRC District 7B. . . . . . . . . . . . . 31 5

RRC District 7C . . . . . . . . . . . . 319 26

RRC District 8. . . . . . . . . . . . . . 484 46

RRC District 8A. . . . . . . . . . . . . 163 15

RRC District 9. . . . . . . . . . . . . . 228 23

RRC District 10. . . . . . . . . . . . . 315 26

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

Utah and Wyoming . . . . . . . . . . . . 756 52

West Virginia. . . . . . . . . . . . . . . . . 67 4

Federal Offshorea . . . . . . . . . . . . . 364 70

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

Gulf of Mexico (Louisiana)a . . . 347 67

Gulf of Mexico (Texas) . . . . . . . 17 3

Miscellaneousb ............... 8 0

U.S. Total ................... 6,244 611

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 2003 contained in the publications Petroleum Supply Annual 2003,

DOE/EIA-0340(2003) and Natural Gas Annual 2003, DOE/EIA-0131(2003).

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

44 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table 15. Lease Condensate Proved Reserves and Production, 2003

(Million Barrels of 42 U.S. Gallons)

2003 2003 2003 2003

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska ...................... 0 0

Lower 48 States.............. 1,215 191

Alabama . . . . . . . . . . . . . . . . . . . . 27 3

Arkansas .................... 1 0

California.................... 0 0

Coastal Region Onshore ..... 0 0

Los Angeles Basin Onshore . . . 0 0

San Joaquin Basin Onshore. . . 0 0

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

Colorado . . . . . . . . . . . . . . . . . . . . 70 5

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

Kansas ..................... 3 1

Kentucky .................... 1 0

Louisiana. . . . . . . . . . . . . . . . . . . . 112 29

North. . . . . . . . . . . . . . . . . . . . . 19 3

South Onshore . . . . . . . . . . . . . 82 23

State Offshore. . . . . . . . . . . . . . 11 3

Michigan .................... 4 0

Mississippi................... 5 1

Montana .................... 1 0

New Mexico . . . . . . . . . . . . . . . . . 51 6

East . . . . . . . . . . . . . . . . . . . . . 21 4

West . . . . . . . . . . . . . . . . . . . . . 30 2

North Dakota................. 5 0

Oklahoma . . . . . . . . . . . . . . . . . . . 104 11

Texas. . . . . . . . . . . . . . . . . . . . . . . 325 47

RRC District 1.............. 5 0

RRC District 2 Onshore . . . . . . 13 2

RRC District 3 Onshore . . . . . . 72 14

RRC District 4 Onshore . . . . . . 85 15

RRC District 5. . . . . . . . . . . . . . 11 1

RRC District 6. . . . . . . . . . . . . . 53 5

RRC District 7B............. 1 0

RRC District 7C . . . . . . . . . . . . 26 3

RRC District 8. . . . . . . . . . . . . . 14 2

RRC District 8A............. 0 0

RRC District 9.............. 8 2

RRC District 10. . . . . . . . . . . . . 32 2

State Offshore.............. 5 1

Utah and Wyoming . . . . . . . . . . . . 142 10

West Virginia................. 1 0

Federal Offshorea . . . . . . . . . . . . . 361 78

Pacific (California)........... 8 0

Gulf of Mexico (Louisiana)a . . . 251 53

Gulf of Mexico (Texas) . . . . . . . 102 25

Miscellaneousb ............... 2 0

U.S. Total ................... 1,215 191

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” 2003.

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

Natural gas liquids production was an estimated 802

million barrels in 2003, a decrease of 9 percent from

2002. Alaska production dropped from 20 to 18 million

barrels in 2003.

Six areas accounted for about 87 percent of the Nation’s

natural gas liquids production.

 Texas (34 percent of the National total)

 Gulf of Mexico Federal Offshore (18 percent)

 New Mexico (10 percent)

 Oklahoma (9 percent)

 Louisiana (8 percent)

 Utah-Wyoming (8 percent).

Natural Gas Plant Liquids

Proved Reserves

Natural gas plant liquids proved reserves decreased in

2003 to 6,244 million barrels, a 6 percent decrease from

the 2002 level (6,648 million barrels) (Table 14). Six

areas accounted for about 81 percent of the Nation’s

natural gas plant liquids proved reserves:

Percent of

Area U.S. Gas Plant Liquids

Texas 35

New Mexico 13

Utah-Wyoming 12

Oklahoma 9

Alaska 6

Gulf of Mexico Federal Offshore 6

Area Total 81

In a year where the U.S. dry natural gas reserves

increased, the volume of natural gas liquids reserves

decreased. This would seem to defy logic, but this

resulted from changes in the relative economics of

natural gas and natural gas liquids, and in the liquids

content of the gas production. Coalbed methane, in

particular, has almost no associated natural gas liquids

and is a significant portion of the U.S. dry natural gas

supply.

Production

Natural gas plant liquids production decreased 10

percent in 2003—from 677 million barrels in 2002 to 611

million barrels of production (Table 14).

In a year where the U.S. dry natural gas production

increased, the volume of liquids produced from gas

plants decreased significantly. The reasons for this are

primarily economic.

The higher average gas prices of 2003 reduced the

historical gap between gas and liquids prices. Given

certain gas market conditions, it became more

economic to offer higher BTU gas directly to the market

than to strip the liquids from the produced gas stream.

Also, the number of active gas plants dropped in 2003.

According to survey results from Form EIA-64A, the

number of unique active U.S. natural gas proccessing

plants dropped from 514 in 2002 to 497 in 2003.

The top six areas for proved reserves of natural gas

plant liquids accounted for about 82 percent of the

Nation’s natural gas plant liquids production:

 Texas (37 percent)

 New Mexico (12 percent)

 Gulf of Mexico Federal Offshore (11 percent)

 Oklahoma (10 percent)

 Utah and Wyoming (9 percent)

 Alaska (3 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 1,215 million barrels in 2003 (Table 15). This

was 10 percent less than the volume reported in 2002

(1,346 million barrels). The reserves of five areas

account for about 86 percent of the Nation’s lease

condensate proved reserves.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 45
Percent of U.S.

Area Condensate Reserves

Gulf of Mexico Federal Offshore 29

Texas 27

Utah-Wyoming 12

Louisiana 9

Oklahoma 9

Area Total 86

Production

Production of lease condensate was 191 million barrels

in 2003, a decrease of 8 percent from 2002’s production

(207 million barrels). The production of five areas

account for about 92 percent of the Nation’s lease

condensate production.

 Gulf of Mexico Federal Offshore (41 percent)

 Texas (25 percent)

 Louisiana (15 percent)

 Oklahoma (6 percent)

 Utah and Wyoming (5 percent).

Reserves in

Nonproducing Status

Like crude oil and natural gas, not all lease condensate

proved reserves were producing during 2003. Proved

reserves of 399 million barrels of lease condensate, a

decrease of 18 percent from 2002’s level (489 million

barrels), were reported in nonproducing status in 2003

(Appendix D, Table D10). About 41 percent of the

nonproducing lease condensate reserves were located

in the Gulf of Mexico Federal Offshore.

Energy Information Administration

46 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
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1991. U.S. Crude Oil, Natural Gas, and Natural Gas

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

Reserves 1992 Annual Report. DOE/EIA-0216(92).

Washington, DC.

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Reserves 1994 Annual Report. DOE/EIA-0216(94).

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1996. U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves 1995 Annual Report.

DOE/EIA-0216(95). Washington, DC.

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1997. U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves 1996 Annual Report.

DOE/EIA-0216(96). Washington, DC.

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1998. U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves 1997 Annual Report.

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DOE/EIA-0216(98). Washington, DC.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report 47
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2000. U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves 1999 Annual Report.

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Prices. Petroleum Marketing Monthly. DOE/EIA0380(2004/09). Washington, DC.

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DOE/EIA-0130(2004/09). Washington, DC.

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2003 (http:// houston.bizjournals.com/ houston/

stories/2003/02/10/daily66.html)

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release, June 20, 2003. (Http:// www. marathon.

com)

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shareholders approve merger, October 27, 2003.

(http://denver.bizjournals.com)

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Natural Gas in the United States and Canada as of

December 31, 1979. Vol. 34. June 1980. Washington,

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2004, pg. 63. Houston, TX.

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DOE/EIA-0384(2003). Washington, DC.

(http://www.eia.doe.gov/emeu/aer)

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of Origin, 1960-2003. 2003 Annual Energy Review.

DOE/EIA-0384(2003). Washington, DC.

(Http://www.eia.doe.gov/emeu/aer)

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10, March, 2004. Oklahoma City, OK.

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Mamm Creek. Internet News Release.

(http://www.encana.com/operations)

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operations)

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Jonah. Internet News Release. (Http:// www.

encana. com/operations)

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15, No. 8. Washington, DC, August 1992. p. 13.

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Assessment of the United States Oil and Gas Resources.

U.S. Geological Survey Circular 1118. Denver, CO,

pp. 5-6.

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Management Service, Gulf of Mexico OCS

Regional Office. August 1995. Estimated Proved Oil

and Gas Reserves, Gulf of Mexico, December 31, 1994.

OCS Report MMS 94-0045. New Orleans, LA, pp.

5-6.

Energy Information Administration

48 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
Appendix A

Operator Data by Size Class
Appendix A

Operator Data by Size Class

Appendix A provides a series of tables of the proved

reserves and production by production size class for

the years 1998 through 2003 for oil and gas well

operators. The tables show the volumetric change and

percent change from the previous year and from 1998.

In addition they show the 2003 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 20,423 small operators.

We estimated production and reserves for small

operators for 2003 from a sample of approximately 3

percent.

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

 

The wet natural gas proved reserves reported for 1998

through 2003 have changed from 172,443 billion cubic

feet to 197,145 billion cubic feet (Table A1). These

proved reserves are highly concentrated in the larger

companies. In 2003, the top 20 operators (Class 1-10 and

Class 11-20) producing companies had 57 percent of the

proved reserves of natural gas. The next two size

classes contain 80 and 400 companies and account for

27 and 10 percent of the U.S. natural gas proved

reserves, respectively. The top 20 operators had an

increase of 21 percent in their natural gas proved

reserves from 1998 to 2003. The rest of the operators in

(Class 21-100, Class 101-500, and Class Other) had an

increase of 2 percent in their reserves in the same

period. In 2003, the top 20 operators' natural gas

reserves had a decrease of 2 percent from 2002.

	


Wet natural gas production has decreased from 20,248

billion cubic feet in 2002 to 20,231 billion cubic feet in

2003 (Table A2). In 2003, the top 20 producing

companies had 56 percent of the production of wet

natural gas. The next two size classes have 26 and 12

percent of the wet natural gas production, respectively.

The top 20 operators had an increase of 11 percent in

wet natural gas production from 1998 to 2003. The rest

of the operators had a decrease of 5 percent from 1998

to 2003. The top 20 operators' wet natural gas

production had a decrease of 4 percent in 2003 from

2002.

Crude Oil

 

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

2003 had 70 percent of U.S. proved reserves of crude oil

(Table A3), in contrast to wet natural gas where these

same companies operated 57 percent of the total

proved reserves.

U.S. proved reserves of crude oil decreased 4 percent in

2003. The top 20 producing companies proved reserves

of crude oil during 2003 decreased 6 percent. The top 20

class had an increase of 16 percent in their crude oil

proved reserves from 1998 to 2003.

	


Crude oil production reported for 1998 to 2003 has

decreased from 1,991 million barrels to 1,877 million

barrels (Table A4). The 20 largest oil and gas producing

companies had 67 percent of U.S. production of crude

oil in 2003. In 1998 they accounted for 64 percent of

production.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report A-1
This is in contrast to wet natural gas where these same

companies produced only 56 percent of the total. U.S.

production of crude oil declined by 6 percent from 1998

to 2002. The top 20 operators had a decline of 2 percent

in their oil production during the same period. U.S.

production of crude oil remained level from 2002 to

2003, the top 20 operators production also decreased by

1 percent.




The number of fields in which Category I and Category

II operators were active increased during the 1998-2002

period (Table A5). From 1998-2002, the number of fields

in which the top 20 operators were active increased by

1,884 fields (44 percent) while in 2003 the number

increased by 193 fields from 2002.

Energy Information Administration

A-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report A-3

Class 1-10 64,336 64,320 81,437 88,936 88,100 82,222 -5,878 17,886 8,222.176

Percent of Total 37.3% 36.5% 43.7% 46.4% 45.0% 41.7% -6.7% 27.8%

Class 11-20 28,338 24,925 22,590 24,588 25,938 29,890 3,952 1,552 2,989.003

Percent of Total 16.4% 14.1% 12.1% 12.8% 13.3% 15.2% 15.2% 5.5%

Class 21-100 47,009 52,160 48,832 50,055 50,633 53,098 2,465 6,089 663.725

Percent of Total 27.3% 29.6% 26.2% 26.1% 25.9% 26.9% 4.9% 13.0%

Class 101-500 24,471 25,967 22,620 19,046 19,723 20,030 307 -4,441 50.076

Percent of Total 14.2% 14.7% 12.1% 9.9% 10.1% 10.2% 1.6% -18.1%

Class Other (22,019) 8,289 8,289 11,030 9,118 11,167 11,905 737 3,616 0.583

Percent of Total 4.8% 5.0% 5.9% 4.8% 5.7% 6.0% 6.6% 43.6%

Category I (179) 146,458 146,458 162,144 169,056 173,325 173,225 -100 26,767 1,056.252

Percent of Total 84.9% 82.8% 86.9% 88.2% 88.6% 87.9% -0.1% 18.3%

Category II (430) 18,033 18,033 13,123 13,346 11,051 11,983 932 -6,050 23.404

Percent of Total 10.5% 12.5% 7.0% 7.0% 5.7% 6.1% 8.4% -33.5%

Category III (22,519) 7,952 7,952 R11,243 9,342 11,184 11,937 752 3,985 0.590

Percent of Total 4.6% 4.7% R6.0% 4.9% 5.7% 6.1% 6.7% 50.1%

Total Published 172,443 176,159 186,510 191,743 195,561 197,145 1,584 24,702 9.422

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 0.8% 14.3%

Table A1. Natural Gas Proved Reserves, Wet After Lease Separation, by Operator Production Size Class,

1998–2003

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

2002–2003 1998–2003 2003

Volume and Volume and Average

Percent Percent Reserves

Size Class 1998 1999 2000 2001 2002 2003 Change Change per Operator

R = Revised

Note: There were 20,247 active Category III operators in the 2003 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 838 Category III operators (Table E2). The "other" size class represents 20,423 operators in the

2003 frame (20,923 active operators minus the 500 largest operators).

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

A-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Class 1-10 6,954 6,881 8,495 9,019 8,996 8,220 -776 1,266 821.954

Percent of Total 35.4% 34.7% 42.1% 43.7% 44.4% 40.6% -8.6% 18.2%

Class 11-20 3,317 3,560 2,886 3,064 2,854 3,136 282 -181 313.572

Percent of Total 16.4% 14.1% 14.3% 14.8% 14.1% 15.5% 9.9% -5.5%

Class 21-100 5,595 5,523 4,965 4,949 4,763 5,275 512 -320 65.942

Percent of Total 27.3% 29.6% 24.6% 24.0% 23.5% 26.1% 10.8% -5.7%

Class 101-500 2,721 2,793 2,780 2,609 2,475 2,386 -89 -335 5.965

Percent of Total 14.2% 14.7% 13.8% 12.6% 12.2% 11.8% -3.6% -12.3%

Class Other (22,019) 1,035 1,099 1,038 1,000 1,161 1,215 54 180 0.059

Percent of Total 4.8% 5.0% 5.1% 4.8% 5.7% 6.0% 4.6% 17.3%

Category I (179) 16,619 16,248 17,096 17,672 17,335 17,347 12 728 105.772

Percent of Total 84.9% 82.8% 84.8% 85.6% 85.6% 85.7% 0.1% 4.4%

Category II (430) 2,019 2,556 1,921 1,932 1,738 1,648 -90 -371 3.219

Percent of Total 10.5% 12.5% 9.5% 9.4% 8.6% 8.1% -5.2% -18.4%

Category III (22,519) 984 1,052 R1,147 1,038 1,176 1,236 61 252 0.061

Percent of Total 4.6% 4.7% R5.7% 5.0% 5.8% 6.1% 5.2% 25.6%

Total Published 19,622 19,856 20,164 20,642 20,248 20,231 -17 609 0.967

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -0.1% 3.1%

Table A2. Natural Gas Production, Wet After Lease Separation, by Operator Production Size Class,

1998–2003

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

2002–2003 1998–2003 2003

Volume and Volume and Average

Percent Percent Production

Size Class 1998 1999 2000 2001 2002 2003 Change Change per Operator

R = Revised

Note: There were 20,247 active Category III operators in the 2003 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 838 Category III operators (Table E2). The "other" size class represents 20,423 operators in the

2003 frame (20,923 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 2003 Annual Report A-5

Class 1-10 11,501 11,121 12,367 13,590 13,346 13,355 10 1,854 1,335.527

Percent of Total 54.7% 51.1% 56.1% 60.5% 58.9% 61.0% 0.1% 16.1%

Class 11-20 2,894 2,585 3,172 2,901 2,817 1,907 -910 -987 190.721

Percent of Total 13.8% 11.9% 14.4% 12.9% 12.4% 8.7% -32.3% -34.1%

Class 21-100 3,677 4,338 2,505 2,856 3,230 3,483 253 -194 43.539

Percent of Total 17.5% 19.9% 11.4% 12.7% 14.2% 15.9% 7.8% -5.3%

Class 101-500 1,754 2,379 2,286 1,794 1,817 1,705 -111 -49 4.264

Percent of Total 8.3% 10.9% 10.4% 8.0% 8.0% 7.8% -6.1% -2.8%

Class Other (22,019) 1,208 1,342 1,716 1,305 1,468 1,440 -28 232 0.071

Percent of Total 5.7% 6.2% 7.8% 5.8% 6.5% 6.6% -1.9% 19.2%

Category I (179) 18,819 18,952 19,421 20,325 20,213 19,499 -714 680 118.895

Percent of Total 89.5% 87.1% 88.1% 90.6% 89.1% 89.1% -3.5% 3.6%

Category II (430) 1,018 1,521 873 794 992 937 -56 -81 1.830

Percent of Total 4.8% 7.0% 4.0% 3.5% 4.4% 4.3% -5.6% -8.0%

Category III (22,519) 1,197 1,293 R1,751 1,326 1,472 1,456 -16 259 0.072

Percent of Total 5.7% 5.9% R7.9% 5.9% 6.5% 6.6% -1.1% 21.6%

Total Published 21,034 21,765 22,045 22,446 22,677 21,891 -786 857 1.046

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -3.5% 4.1%

Table A3. Crude Oil Proved Reserves by Operator Production Size Class, 1998–2003

(Million Barrels of 42 U.S. Gallons)

2002–2003 1998–2003 2003

Volume and Volume and Average

Percent Percent Reserves

Size Class 1998 1999 2000 2001 2002 2003 Change Change per Operator

R = Revised

Note: There were 20,247 active Category III operators in the 2003 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 838 Category III operators (Table E2). The "other" size class represents 20,423 operators in the

2003 frame (20,923 active operators minus the 500 largest operators).

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

A-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Class 1-10 1,025 974 961 1,061 1,037 1,047 10 22 104.708

Percent of Total 51.5% 49.9% 51.1% 55.4% 55.3% 55.8% 1.0% 2.2%

Class 11-20 255 241 304 240 233 205 -28 -50 20.491

Percent of Total 12.8% 12.3% 16.2% 12.5% 12.4% 10.9% -12.2% -19.6%

Class 21-100 342 350 214 233 240 272 32 -70 3.399

Percent of Total 17.2% 17.9% 11.4% 12.2% 12.8% 14.5% 13.2% -20.5%

Class 101-500 206 208 211 195 181 178 -3 -28 0.446

Percent of Total 10.3% 10.7% 11.2% 10.2% 9.7% 9.5% -1.5% -13.4%

Class Other (22,019) 163 179 190 186 184 175 -9 12 0.009

Percent of Total 8.2% 9.2% 10.1% 9.7% 9.8% 9.3% -4.9% 7.2%

Category I (179) 1,714 1,617 1,572 1,612 1,573 1,574 1 -140 9.599

Percent of Total 86.1% 82.8% 83.6% 84.2% 83.9% 83.9% 0.1% -8.2%

Category II (430) 118 160 111 112 115 124 9 6 0.243

Percent of Total 5.9% 8.2% 5.9% 5.8% 6.1% 6.6% 7.8% 5.3%

Category III (22,519) 159 175 R197 191 187 179 -8 20 0.009

Percent of Total 8.0% 9.0% R10.5% 10.0% 10.0% 9.5% -4.3% 12.3%

Total Published 1,991 1,952 1,880 1,915 1,875 1,877 2 -114 0.090

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 0.1% -5.7%

Table A4. Crude Oil Production by Operator Production Size Class, 1998–2003

(Million Barrels of 42 U.S. Gallons)

2002–2003 1998–2003 2003

Volume and Volume and Average

Percent Percent Production

Size Class 1998 1999 2000 2001 2002 2003 Change Change per Operator

R = Revised

Note: There were 20,247 active Category III operators in the 2003 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 838 Category III operators (Table E2). The "other" size class represents 20,423 operators in the

2003 frame (20,923 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 2003 Annual Report A-7

Class 1-10 2,475 2,559 3,444 3,794 3,596 3,689 93 1,214 368.900

Percent of Total 9.5% 10.0% 13.0% 14.0% 12.9% 13.2% 2.6% 49.1%

Class 11-20 1,822 1,514 1,923 2,212 2,392 2,492 100 670 249.200

Percent of Total 7.0% 5.9% 7.2% 8.2% 8.6% 8.9% 4.2% 36.8%

Class 21-100 7,526 8,180 7,084 7,195 7,947 8,168 221 642 102.100

Percent of Total 29.0% 32.0% 26.7% 26.5% 28.4% 29.3% 2.8% 8.5%

Class 101-500 12,817 12,344 12,580 12,435 12,661 11,859 -802 -958 29.648

Percent of Total 49.4% 48.2% 47.4% 45.9% 45.3% 42.5% -6.3% -7.5%

Rest 1,524 1,287 1,529 1,480 1,349 1,709 360 185 9.710

Percent of Total 5.9% 5.0% 5.8% 5.5% 4.8% 6.1% 26.7% 12.1%

Category I 15,666 15,120 16,174 16,196 17,049 16,760 -289 1,094 102.195

Percent of Total 60.4% 59.1% 60.9% 59.7% 61.0% 60.0% -1.7% 7.0%

Category II 10,271 10,467 10,146 10,764 10,473 10,688 215 417 20.875

Percent of Total 39.6% 40.9% 38.2% 39.7% 37.5% 38.3% 2.1% 4.1%

Total 25,937 25,587 26,560 27,116 27,945 27,917 -28 1,980 41.297

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.00% -0.1% 7.6%

Note: Includes only data from Category I and Category II operators. In 2003, there were 164 Category I operators and 512 Category II

operators. The “rest” size class had 176 operators in 2003.

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

Table A5. Operator Field Count by Operator Production Size Class, 1998–2003

2002–2003 1999–2003 2003 Average

Number and Number and Number of

Percent Percent Fields per

Size Class 1998 1999 2000 2001 2002 2003 Change Change Operator
Appendix B

Top 100 Oil and Gas Fields for 2003
Appendix B

Top 100 Oil and Gas Fields for 2003

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, labeled as liquids.

The total gas production and reserve data is wet after

lease separation. 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. Two

new tables have been added to this Appendix. They

rank the top 100 fields by production (B3 and B4) rather

than by reserves (B1 and B2).

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. Many of the same fields are in each of the tables

B1, B2, B3, and B4. The oil fields with the more recent

discovery dates are typically located in the Gulf of

Mexico Offshore and Alaska. The gas fields with the

more recent discovery dates are located in the Gulf of

Mexico Offshore, New Mexico, Colorado, and

Wyoming. Blanco/Ignacio-Blanco and Basin have been

combined into San Juan Basin Gas Area for the 2003

tables.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report B-1

Summary for the Top 100 Fields for 2003 Liquids and Gas

12/31/2003 12/31/2003 Estimated

Proved Nonproducing 2003 Rank Group Reserves Percent Reserves Percent Production Percent

Table B1. Top 100 U.S. Fields as Ranked by Liquids Proved Reserves (Million Barrels)

Top 10 6,725.4 29.1% 1,420.6 23.8% 390.2 18.9%

Top 20 9,231.8 40.0% 2,201.7 36.8% 590.8 28.6%

Top 50 12,536.3 54.3% 3,240.2 54.2% 816.3 39.5%

Top 100 14,894.8 64.5% 4,003.2 67.0% 1,010.5 48.9%

Others 8,211.2 35.5% 1,975.8 33.0% 1,057.5 51.1%

Total 23,106.0 100.0% 5,979.0 100.0% 2,068.0 100.0%

Table B2. Top 100 U.S. Fields as Ranked by Gas Proved Reserves (Billion Cubic Feet)

Top 10 48,552.4 24.6% 8,123.4 16.6% 3,217.3 15.9%

Top 20 64,681.6 32.8% 12,181.1 24.8% 4,303.2 21.3%

Top 50 85,803.4 43.5% 18,219.5 37.1% 6,024.4 29.8%

Top 100 102,144.6 51.8% 22,752.2 46.4% 7,441.3 36.8%

Others 95,000.4 48.2% 26,315.8 53.6% 12,789.7 63.2%

Total 197,145.0 100.0% 49,068.0 100.0% 20,231.0 100.0%

Table B3. Top 100 U.S. Fields as Ranked by Liquids Production (Million Barrels)

Top 10 6,042.4 26.2% 657.5 11.0% 516.6 25.0%

Top 20 8,094.1 35.0% 875.5 14.6% 697.7 33.7%

Top 50 10,175.2 44.0% 1,258.2 21.0% 963.1 46.6%

Top 100 12,192.4 52.8% 1,566.7 26.2% 1,173.6 56.8%

Others 10,913.6 47.2% 4,412.3 73.8% 894.4 43.2%

Total 23,106.0 100.0% 5,979.0 100.0% 2,068.0 100.0%

Table B4. Top 100 U.S. Fields as Ranked by Gas Production (Billion Cubic Feet)

Top 10 46,356.9 23.5% 8,251.4 16.8% 3,582.0 17.7%

Top 20 60,393.5 30.6% 11,042.4 22.5% 4,603.4 22.8%

Top 50 79,072.1 40.1% 15,801.0 32.2% 6,438.9 31.8%

Top 100 93,145.0 47.2% 18,654.6 38.0% 8,347.5 41.3%

Others 104,000.0 52.8% 30,413.4 62.0% 11,883.5 58.7%

Total 197,145.0 100.0% 49,068.0 100.0% 20,231.0 100.0%
  	 

  
   

The top 100 oil fields by reserves had 14,895 million

barrels of proved reserves accounting for 65 percent of

the total United States as of December 31, 2003, (Table 6

and Table 14) and 67 percent of the reported

nonproducing reserves. In the top 20 oil fields for 2003

there are six fields, which are in the deep water of the

Gulf of Mexico Federal Offshore and four are currently

nonproducing.

The top 100 oil fields by reserves had 1,011 million

barrels of production, or 49 percent of the 2003 U.S.

total (Table 6 and Table 14). From year to year these top

100 fields change rank. The most notable change from

last year is the 7th largest field, Yates, moving to 43rd in

2003, as a new operator had a different view of the

reserves for the field and a different method of

enhanced oil recovery.

  	 

  
   

The top 100 gas fields by reserves had 102,145 billion

cubic feet of wet natural gas proved reserves or 52

percent of the total, as of December 31, 2003 (Table 9)

and 46 percent of the reported nonproducing reserves.

producing-producing reserves. The top 100 gas fields

by reserves had 7,441 billion cubic feet of production,

or 37 percent of the 2003 U.S. total (Table 9).

  	 

  
   

The top 100 oil fields by production had 12,192 million

barrels of proved reserves accounting for 53 percent of

the total United States as of December 31, 2003 (Table 6

and Table 14) and 26 percent of the reported

nonproducing reserves. The top 100 oil fields by

production had 1,174 million barrels of production, or

57 percent of the 2003 U.S. total (Table 6 and Table 14).

  	 

  
   

The top 100 gas fields by production had 93,145 billion

cubic feet of wet natural gas proved reserves, as of

December 31, 2003, or 47 percent of the total (Table 9).

The top 100 gas fields had 8,348 billion cubic feet of

production, or 41 percent of the 2003 U.S. total (Table

9).

  	   	  



  !

Table B5 lists the top U.S. oil and gas operators ranked

by reported 2003 operated production data.

Energy Information Administration

B-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

















		 

















 



		 













		 





























 	




Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report B-3

Table B1. Top 100 U.S. Fields Ranked by Liquids Proved Reserves from Estimated 2003 Field Level Dataa

(Million Barrels of 42 U.S. Gallons)

Discovery Proved Reserves Nonproducing 2003 Estimated

Field Name Location Year Rank Group Reserves Production Volume

1 PRUDHOE BAY AK 1967 (1-10) 141.3

2 KUPARUK RIVER AK 1969 (1-10) 58.8

3 WASSON TX 1937 (1-10) 26.1

4 BELRIDGE SOUTH CA 1911 (1-10) 41.1

5 MISSISSIPPI CANYON BLK 778 FG 1999 (1-10) 0.0

6 MIDWAY-SUNSET CA 1901 (1-10) 47.8

7 KERN RIVER CA 1899 (1-10) 36.7

8 SPRABERRY TREND AREA TX 1950 (1-10) 19.8

9 ELK HILLS CA 1920 (1-10) 18.7

10 GREEN CANYON BLK 699 FG 1998 (1-10) 0.0

Top 10 Volume Subtotal 6,725.4 1,420.6 390.2

Top 10 Percentage of U.S. Total 29.1% 23.8% 18.9%

11 MISSISSIPPI CANYON BLK 807 FG 1989 (11-20) 58.1

12 ALPINE AK 1994 (11-20) 36.1

13 MILNE POINT AK 1982 (11-20) 18.8

14 SLAUGHTER TX 1937 (11-20) 14.3

15 GREEN CANYON BLK 644 FG 1999 (11-20) 0.0

16 HONDO FP 1969 (11-20) 6.8

17 GREEN CANYON BLK 826 FG 1999 (11-20) 0.0

18 LOST HILLS CA 1910 (11-20) 11.0

19 CYMRIC CA 1916 (11-20) 18.7

20 MISSISSIPPI CANYON BLK 810 FG 1996 (11-20) 36.9

Top 20 Volume Subtotal 9,231.8 2,201.7 590.8

Top 20 Percentage of U.S. Total 40.0% 36.8% 28.6%

21 LEVELLAND TX 1945 (21-50) 9.6

22 WILMINGTON CA 1932 (21-50) 14.9

23 MISSISSIPPI CANYON BLK 84 FG 1993 (21-50) 33.9

24 GREEN CANYON BLK 640 FG 2002 (21-50) 0.0

25 PESCADO FP 1970 (21-50) 6.3

26 WATTENBERG CO 1970 (21-50) 8.6

27 ENDICOTT AK 1978 (21-50) 9.2

28 POINT MCINTYRE AK 1988 (21-50) 13.8

29 COWDEN NORTH TX 1930 (21-50) 7.0

30 SAN ARDO CA 1947 (21-50) 4.5

31 SHO-VEL-TUM OK 1905 (21-50) 8.4

32 NORTHSTAR AK 1984 (21-50) 22.9

33 CEDAR HILLS ND & MT & SD 1954 (21-50) 3.9

34 HOBBS NM 1928 (21-50) 3.7

35 MISSISSIPPI CANYON BLK 383 FG 1987 (21-50) 0.3

36 INGLEWOOD CA 1924 (21-50) 2.4

37 SACATE FP 1970 (21-50) 2.8

38 GREEN CANYON BLK 339 FG 2001 (21-50) 0.0

39 WEST SAK AK 1969 (21-50) 2.9

40 VENTURA CA 1916 (21-50) 4.6

41 GREEN CANYON BLK 562 FG 1999 (21-50) 0.0

42 KELLY-SNYDER TX 1948 (21-50) 7.4

43 YATES TX 1926 (21-50) 6.9

44 BOREALIS AK 2001 (21-50) 11.8

45 MCELROY TX 1926 (21-50) 4.7

46 VACUUM NM 1929 (21-50) 7.4

47 ROBERTSON NORTH TX 1956 (21-50) 4.0

48 MISSISSIPPI CANYON BLK 773 FG 2000 (21-50) 0.0

49 VIOSCA KNOLL BLK 786 FG 1996 (21-50) 19.3

50 GREATER ANETH UT 1956 (21-50) 4.3

Top 50 Volume Subtotal 12,536.3 3,240.2 816.3

Top 50 Percentage of U.S. Total 54.3% 54.2% 39.5%
Energy Information Administration

B-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

51 MONUMENT BUTTE UT 1964 (51-100) 1.9

52 HAWKINS TX 1940 (51-100) 3.2

53 GOLDSMITH NORTH TX 1946 (51-100) 4.7

54 FULLERTON TX 1942 (51-100) 4.8

55 RANGELY CO 1902 (51-100) 4.7

56 MISSISSIPPI CANYON BLK 20 FG 1995 (51-100) 0.5

57 POLARIS AK 2000 (51-100) 0.9

58 ARROYO GRANDE CA 1906 (51-100) 0.7

59 GREEN CANYON BLK 680 FG 2003 (51-100) 0.0

60 LAKE WASHINGTON LA 1931 (51-100) 3.5

61 COALINGA CA 1887 (51-100) 6.4

62 GIDDINGS TX 1960 (51-100) 10.3

63 JAY AL & FL 1970 (51-100) 2.6

64 PENNEL MT 1955 (51-100) 2.4

65 SEMINOLE TX 1936 (51-100) 8.6

66 SALT CREEK TX 1942 (51-100) 4.9

67 TARN AK 1991 (51-100) 12.6

68 GREEN CANYON BLK 608 FG 2002 (51-100) 0.0

69 MISSISSIPPI CANYON BLK 582 FG 2000 (51-100) 1.1

70 MEANS TX 1934 (51-100) 3.8

71 ELM COULEE MT 2000 (51-100) 2.3

72 HARTZOG DRAW WY 1976 (51-100) 3.1

73 CEDAR LAKE TX 1939 (51-100) 2.4

74 GOLDEN TREND OK 1945 (51-100) 3.3

75 BELRIDGE NORTH CA 1912 (51-100) 2.8

76 AURORA AK 1969 (51-100) 3.8

77 GREEN CANYON BLK 243 FG 2001 (51-100) 8.2

78 KERN FRONT CA 1925 (51-100) 1.5

79 EWING BANK BLK 873 FG 1991 (51-100) 7.9

80 EAST BREAKS BLK 690 FG 2001 (51-100) 10.6

81 JO-MILL TX 1953 (51-100) 2.5

82 ANTON-IRISH TX 1944 (51-100) 5.5

83 ORION AK 2002 (51-100) 0.4

84 VIOSCA KNOLL BLK 990 FG 1981 (51-100) 8.1

85 WEST DELTA BLK 30 FG 1949 (51-100) 4.3

86 HOWARD-GLASSCOCK TX 1925 (51-100) 3.1

87 GARDEN BANKS BLK 668 FG 2000 (51-100) 0.0

88 GREEN CANYON BLK 205 FG 1988 (51-100) 11.5

89 ALAMINOS CANYON BLK 25 FG 1997 (51-100) 7.9

90 LOOKOUT BUTTE EAST MT 1986 (51-100) 1.8

91 VIOSCA KNOLL BLK 915 FG 1993 (51-100) 2.9

92 WASSON 72 TX 1940 (51-100) 1.7

93 NIAKUK AK 1984 (51-100) 4.6

94 MELTWATER AK 2001 (51-100) 2.1

95 PATRICK DRAW WY 1959 (51-100) 0.1

96 WELCH TX 1942 (51-100) 2.0

97 ELK BASIN MT & WY 1915 (51-100) 3.0

98 SOUTH PASS EA BLK 62 FG 1967 (51-100) 1.7

99 MISSISSIPPI CANYON BLK 935 FG 1994 (51-100) 4.9

100 FOSTER TX 1932 (51-100) 2.6

Top 100 Volume Subtotal 14,894.8 4,003.2 1,010.5

Top 100 Percentage of U.S. Total 64.5% 67.0% 48.9%

Table B1. Top 100 U.S. Fields Ranked by Liquids Proved Reserves from Estimated 2003 Field Level Dataa

(Continued)

(Million Barrels of 42 U.S. Gallons)

Discovery Proved Reserves Nonproducing 2003 Estimated

Field Name Location Year Rank Group Reserves Production Volume

aIncludes lease condensate.

Notes: The U.S. total production estimate of 2,068 million barrels and the U.S. total reserves estimate of 23,106 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.

FP = Federal Offshore Pacific

FG = Federal Offshore Gulf of Mexico

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report B-5

Table B2. Top 100 U.S. Fields Ranked by Gas Proved Reserves from Estimated 2003 Field Level Dataa

(Billion Cubic Feet)

Discovery Proved Reserves Nonproducing 2003 Reported

Field Name Location Year Rank Group Reserves Production Volume

1 SAN JUAN BASIN GAS AREA CO & NM 1927 (1-10) 1479.6

2 PRUDHOE BAY AK 1967 (1-10) 209.6

3 HUGOTON GAS AREA KS & OK & TX 1922 (1-10) 348.1

4 PINEDALE WY 1955 (1-10) 87.3

5 JONAH WY 1977 (1-10) 244.5

6 NEWARK EAST TX 1981 (1-10) 306.4

7 MADDEN WY 1968 (1-10) 108.1

8 WATTENBERG CO 1970 (1-10) 194.2

9 RATON BASIN GAS AREA CO & NM 1998 (1-10) 94.7

10 ANTRIM MI 1965 (1-10) 144.7

Top 10 Volume Subtotal 48,552.4 8,123.4 3,217.3

Top 10 Percentage of U.S. Total 24.6% 16.6% 15.9%

11 PRB COALBED WY 1992 (11-20) 296.3

12 LOWER MOBILE BAY AREA AL & FG 1979 (11-20) 187.9

13 CARTHAGE TX 1944 (11-20) 170.7

14 NATURAL BUTTES UT 1952 (11-20) 84.0

15 SPRABERRY TREND AREA TX 1950 (11-20) 72.1

16 FOGARTY CREEK WY 1975 (11-20) 34.7

17 SAWYER TX 1975 (11-20) 74.3

18 MAMM CREEK CO 1959 (11-20) 57.5

19 BIG SANDY KY & WV 1881 (11-20) 48.6

20 VERNON LA 1967 (11-20) 59.7

Top 20 Volume Subtotal 64,681.6 12,181.1 4,303.2

Top 20 Percentage of U.S. Total 32.8% 24.8% 21.3%

21 OAKWOOD VA 1990 (21-50) 51.2

22 PANHANDLE WEST TX 1918 (21-50) 91.6

23 RULISON CO 1958 (21-50) 30.1

24 DRUNKARDS WASH UT 1989 (21-50) 78.4

25 ELK HILLS CA 1920 (21-50) 113.2

26 RED OAK-NORRIS OK 1910 (21-50) 77.2

27 GRAND VALLEY CO 1985 (21-50) 31.2

28 OAK HILL TX 1958 (21-50) 62.4

29 GIDDINGS TX 1960 (21-50) 125.1

30 MISSISSIPPI CANYON BLK 810 FG 1996 (21-50) 60.9

31 LAKE RIDGE WY 1981 (21-50) 14.3

32 ELM GROVE LA 1958 (21-50) 57.9

33 STRONG CITY DISTRICT OK 1966 (21-50) 66.8

34 BELUGA RIVER AK 1962 (21-50) 56.6

35 PANOMA GAS AREA KS 1956 (21-50) 66.8

36 GOMEZ TX 1977 (21-50) 50.6

37 BALD PRAIRIE TX 1976 (21-50) 41.3

38 MAYFIELD NE OK 1951 (21-50) 100.2

39 GOLDEN TREND OK 1945 (21-50) 47.1

40 MOCANE-LAVERNE GAS AREA KS & OK & TX 1947 (21-50) 82.1

41 MISSISSIPPI CANYON BLK 383 FG 1987 (21-50) 5.7

42 DEW TX 1982 (21-50) 48.1

43 WATONGA-CHICKASHA TREND OK 1962 (21-50) 51.7

44 PARACHUTE CO 1985 (21-50) 24.0

45 COOK INLET NORTH AK 1962 (21-50) 48.1

46 FREESTONE TX 1949 (21-50) 55.1

47 EAST BREAKS BLK 690 FG 2001 (21-50) 66.6

48 FARRAR TX 1963 (21-50) 27.4

49 WEBBER CREEK MI 1994 (21-50) 20.7

50 MISSISSIPPI CANYON BLK 807 FG 1989 (21-50) 68.8

Top 50 Volume Subtotal 85,803.4 18,219.5 6,024.4

Top 50 Percentage of U.S. Total 43.5% 37.1% 29.8%
Energy Information Administration

B-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table B2. Top 100 U.S. Fields Ranked by Gas Proved Reserves from Estimated 2003 Field Level Dataa

(Continued)

(Billion Cubic Feet)

Discovery Proved Reserves Nonproducing 2003 Reported

Field Name Location Year Rank Group Reserves Production Volume

51 WAMSUTTER WY 1958 (51-100) 36.2

52 EAST BREAKS BLK 945 FG 1994 (51-100) 50.0

53 SLIGO LA 1922 (51-100) 14.0

54 KINTA OK 1914 (51-100) 42.9

55 VIOSCA KNOLL BLK 956 FG 1985 (51-100) 76.8

56 MISSISSIPPI CANYON BLK 778 FG 1999 (51-100) 0.0

57 DOWDY RANCH TX 1999 (51-100) 42.2

58 WASSON TX 1937 (51-100) 21.9

59 WILD ROSE WY 1975 (51-100) 22.0

60 GREEN RIVER BEND WY 1958 (51-100) 29.8

61 KUPARUK RIVER AK 1969 (51-100) 23.8

62 BRUFF WY 1969 (51-100) 33.3

63 OAKS TX 1975 (51-100) 19.2

64 ECHO SPRINGS WY 1977 (51-100) 30.8

65 WILBURTON OK 1941 (51-100) 47.9

66 STANDARD DRAW WY 1979 (51-100) 23.0

67 MOBILE BLK 823 FG 1983 (51-100) 31.9

68 OZONA TX 1962 (51-100) 28.6

69 NORA VA 1949 (51-100) 17.1

70 VERDEN WEST OK 1981 (51-100) 30.4

71 HOLLY LA 1928 (51-100) 19.4

72 BROWN-BASSETT TX 1953 (51-100) 35.3

73 BOONSVILLE TX 1950 (51-100) 27.7

74 MESA WY 1977 (51-100) 25.0

75 ELK CITY OK 1947 (51-100) 42.6

76 STRATTON TX 1937 (51-100) 14.0

77 CEMENT OK 1917 (51-100) 41.0

78 BUFFALO WALLOW TX 1978 (51-100) 19.1

79 GARDEN BANKS BLK 668 FG 2000 (51-100) 0.0

80 GARDEN BANKS BLK 877 FG 2003 (51-100) 0.0

81 BETHANY TX 1936 (51-100) 23.3

82 MESA UNIT WY 1981 (51-100) 23.0

83 KNOX OK 1916 (51-100) 35.1

84 MIMMS CREEK TX 1978 (51-100) 28.1

85 INDIAN BASIN NM 1971 (51-100) 124.3

86 OVERTON TX 1973 (51-100) 21.7

87 CEDARDALE NE OK 1958 (51-100) 21.7

88 LABARGE WY 1924 (51-100) 25.0

89 BROOKWOOD COAL DEGASIFICAT AL 1981 (51-100) 20.0

90 TEAGUE TX 1945 (51-100) 11.3

91 WILLOW SPRINGS TX 1954 (51-100) 28.0

92 GREEN CANYON BLK 699 FG 1998 (51-100) 0.0

93 CEDAR COVE COAL DEGAS AL 1983 (51-100) 17.9

94 MISSISSIPPI CANYON BLK 731 FG 1987 (51-100) 92.7

95 OAK GROVE COAL DEGAS AL 1980 (51-100) 14.1

96 BELRIDGE SOUTH CA 1911 (51-100) 16.3

97 BLANCO SOUTH NM 1951 (51-100) 18.0

98 BLUE CREEK COAL DEGAS AL 1988 (51-100) 19.5

99 BEAR GRASS TX 1977 (51-100) 11.8

100 DOUBLE A WELLS TX 1980 (51-100) 18.9

Top 100 Volume Subtotal 102,144.6 22,752.2 7,441.3

Top 100 Percentage of U.S. Total 51.8% 46.4% 36.8%

aTotal wet gas after lease separation.

Note: The U.S. total production estimate of 20,231 billion cubic feet and the U.S. total reserves estimate of 197,145 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.

FP = Federal Offshore Pacific

FG = Federal Offshore Gulf of Mexico

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report B-7

Table B3. Top 100 U.S. Fields Ranked by Liquids Production from Estimated 2003 Field Level Dataa

(Million Barrels of 42 U.S. Gallons)

Discovery Proved Reserves Nonproducing 2003 Estimated

Field Name Location Year Rank Group Reserves Production Volume

1 PRUDHOE BAY AK 1967 (1-10) 141.3

2 KUPARUK RIVER AK 1969 (1-10) 58.8

3 MISSISSIPPI CANYON BLK 807 FG 1989 (1-10) 58.1

4 MIDWAY-SUNSET CA 1901 (1-10) 47.8

5 BELRIDGE SOUTH CA 1911 (1-10) 41.1

6 MISSISSIPPI CANYON BLK 810 FG 1996 (1-10) 36.9

7 KERN RIVER CA 1899 (1-10) 36.7

8 ALPINE AK 1994 (1-10) 36.1

9 MISSISSIPPI CANYON BLK 84 FG 1993 (1-10) 33.9

10 WASSON TX 1937 (1-10) 26.1

Top 10 Volume Subtotal 6,042.4 657.5 516.6

Top 10 Percentage of U.S. Total 26.2% 11.0% 25.0%

11 NORTHSTAR AK 1984 (11-20) 22.9

12 GREEN CANYON BLK 158 FG 1992 (11-20) 19.8

13 SPRABERRY TREND AREA TX 1950 (11-20) 19.8

14 VIOSCA KNOLL BLK 786 FG 1996 (11-20) 19.3

15 MILNE POINT AK 1982 (11-20) 18.8

16 ELK HILLS CA 1920 (11-20) 18.7

17 CYMRIC CA 1916 (11-20) 18.7

18 WILMINGTON CA 1932 (11-20) 14.9

19 SLAUGHTER TX 1937 (11-20) 14.3

20 POINT MCINTYRE AK 1988 (11-20) 13.8

Top 20 Volume Subtotal 8,094.1 875.5 697.7

Top 20 Percentage of U.S. Total 35.0% 14.6% 33.7%

21 GREEN CANYON BLK 244 FG 1994 (21-50) 12.8

22 TARN AK 1991 (21-50) 12.6

23 BOREALIS AK 2001 (21-50) 11.8

24 GREEN CANYON BLK 205 FG 1988 (21-50) 11.5

25 EAST BREAKS BLK 643 FG 1999 (21-50) 11.3

26 LOST HILLS CA 1910 (21-50) 11.0

27 EAST BREAKS BLK 690 FG 2001 (21-50) 10.6

28 GIDDINGS TX 1960 (21-50) 10.3

29 MISSISSIPPI CANYON BLK 899 FG 1998 (21-50) 10.2

30 LEVELLAND TX 1945 (21-50) 9.6

31 MAIN PASS BLK 61 FG 2001 (21-50) 9.6

32 ENDICOTT AK 1978 (21-50) 9.2

33 GARDEN BANKS BLK 215 FG 1995 (21-50) 8.7

34 SEMINOLE TX 1936 (21-50) 8.6

35 WATTENBERG CO 1970 (21-50) 8.6

36 SHO-VEL-TUM OK 1905 (21-50) 8.4

37 GREEN CANYON BLK 243 FG 2001 (21-50) 8.2

38 VIOSCA KNOLL BLK 990 FG 1981 (21-50) 8.1

39 EWING BANK BLK 873 FG 1991 (21-50) 7.9

40 ALAMINOS CANYON BLK 25 FG 1997 (21-50) 7.9

41 VACUUM NM 1929 (21-50) 7.4

42 KELLY-SNYDER TX 1948 (21-50) 7.4

43 EUGENE ISLAND SA BLK 330 FG 1971 (21-50) 7.1

44 COWDEN NORTH TX 1930 (21-50) 7.0

45 YATES TX 1926 (21-50) 6.9

46 HONDO FP 1969 (21-50) 6.8

47 VIOSCA KNOLL BLK 956 FG 1985 (21-50) 6.6

48 COALINGA CA 1887 (21-50) 6.4

49 GARDEN BANKS BLK 426 FG 1992 (21-50) 6.4

50 INDIAN BASIN NM 1971 (21-50) 6.4

Top 50 Volume Subtotal 10,175.2 1,258.2 963.1

Top 50 Percentage of U.S. Total 44.0% 21.0% 46.6%
Energy Information Administration

B-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table B3. Top 100 U.S. Fields Ranked by Liquids Production from Estimated 2003 Field Level Dataa

(Continued)

(Million Barrels of 42 U.S. Gallons)

Discovery Proved Reserves Nonproducing 2003 Estimated

Field Name Location Year Rank Group Reserves Production Volume

51 GARDEN BANKS BLK 260 FG 1995 (51-100) 6.4

52 PESCADO FP 1970 (51-100) 6.3

53 SOUTH TIMBALIER BLK 37 FG 1974 (51-100) 6.3

54 GREEN CANYON BLK 236 FG 1999 (51-100) 6.1

55 KENT BAYOU LA 1950 (51-100) 5.5

56 ANTON-IRISH TX 1944 (51-100) 5.5

57 GARDEN BANKS BLK 559 FG 1999 (51-100) 5.4

58 GREEN CANYON BLK 254 FG 1994 (51-100) 5.2

59 VIOSCA KNOLL BLK 825 FG 1988 (51-100) 5.0

60 SALT CREEK TX 1942 (51-100) 4.9

61 MISSISSIPPI CANYON BLK 935 FG 1994 (51-100) 4.9

62 FULLERTON TX 1942 (51-100) 4.8

63 MCELROY TX 1926 (51-100) 4.7

64 POINT ARGUELLO FP 1981 (51-100) 4.7

65 RANGELY CO 1902 (51-100) 4.7

66 GOLDSMITH NORTH TX 1946 (51-100) 4.7

67 NIAKUK AK 1984 (51-100) 4.6

68 VENTURA CA 1916 (51-100) 4.6

69 GRAND ISLE BLK 43 FG 1956 (51-100) 4.6

70 SAN ARDO CA 1947 (51-100) 4.5

71 WEST DELTA BLK 30 FG 1949 (51-100) 4.3

72 GREATER ANETH UT 1956 (51-100) 4.3

73 GREEN CANYON BLK 282 FG 2002 (51-100) 4.3

74 MCARTHUR RIVER AK 1965 (51-100) 4.1

75 MAIN PASS SA BLK 299 FG 1967 (51-100) 4.1

76 GREEN CANYON BLK 65 FG 1984 (51-100) 4.0

77 BAY MARCHAND BLK 2 LA 1949 (51-100) 4.0

78 ELAND ND 1995 (51-100) 4.0

79 ROBERTSON NORTH TX 1956 (51-100) 4.0

80 CEDAR HILLS ND & MT & SD 1954 (51-100) 3.9

81 AURORA AK 1969 (51-100) 3.8

82 MEANS TX 1934 (51-100) 3.8

83 MISSISSIPPI CANYON BLK 109 FG 1984 (51-100) 3.7

84 EAST TEXAS TX 1930 (51-100) 3.7

85 HOBBS NM 1928 (51-100) 3.7

86 GREEN CANYON BLK 112 FG 1998 (51-100) 3.7

87 LAKE WASHINGTON LA 1931 (51-100) 3.5

88 LISBURNE AK 1967 (51-100) 3.4

89 HIGH ISLAND SA BLK A563 FG 1975 (51-100) 3.3

90 GOLDEN TREND OK 1945 (51-100) 3.3

91 HAWKINS TX 1940 (51-100) 3.2

92 EUGENE ISLAND BLK 238 FG 1964 (51-100) 3.1

93 HOWARD-GLASSCOCK TX 1925 (51-100) 3.1

94 HARTZOG DRAW WY 1976 (51-100) 3.1

95 SHIP SHOAL BLK 169 FG 1961 (51-100) 3.1

96 ELK BASIN MT & WY 1915 (51-100) 3.0

97 MAIN PASS BLK 41 FG 1957 (51-100) 3.0

98 HUNTINGTON BEACH CA 1920 (51-100) 3.0

99 DOLLARHIDE NM & TX 1945 (51-100) 2.9

100 SOUTH MARSH IS SA BLK 128 FG 1975 (51-100) 2.9

Top 100 Volume Subtotal 12,192.4 1,566.7 1,173.6

Top 100 Percentage of U.S. Total 52.8% 26.2% 56.8%

aIncludes lease condensate.

Notes: The U.S. total production estimate of 2,068 million barrels and the U.S. total reserves estimate of 23,106 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.

FP = Federal Offshore Pacific

FG = Federal Offshore Gulf of Mexico

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report B-9

1 SAN JUAN BASIN GAS AREA CO & NM 1927 (1-10) 1479.6

2 HUGOTON GAS AREA KS & OK & TX 1922 (1-10) 348.1

3 NEWARK EAST TX 1981 (1-10) 306.4

4 PRB COALBED WY 1992 (1-10) 296.3

5 JONAH WY 1977 (1-10) 244.5

6 PRUDHOE BAY AK 1967 (1-10) 209.6

7 WATTENBERG CO 1970 (1-10) 194.2

8 LOWER MOBILE BAY AREA AL & FG 1979 (1-10) 187.9

9 CARTHAGE TX 1944 (1-10) 170.7

10 ANTRIM MI 1965 (1-10) 144.7

Top 10 Volume Subtotal 46,356.9 8,251.4 3,582.0

Top 10 Percentage of U.S. Total 23.5% 16.8% 17.7%

11 GIDDINGS TX 1960 (11-20) 125.1

12 INDIAN BASIN NM 1971 (11-20) 124.3

13 ELK HILLS CA 1920 (11-20) 113.2

14 MADDEN WY 1968 (11-20) 108.1

15 MAYFIELD NE OK 1951 (11-20) 100.2

16 RATON BASIN GAS AREA CO & NM 1998 (11-20) 94.7

17 MISSISSIPPI CANYON BLK 731 FG 1987 (11-20) 92.7

18 PANHANDLE WEST TX 1918 (11-20) 91.6

19 PINEDALE WY 1955 (11-20) 87.3

20 NATURAL BUTTES UT 1952 (11-20) 84.0

Top 20 Volume Subtotal 60,393.5 11,042.4 4,603.4

Top 20 Percentage of U.S. Total 30.6% 22.5% 22.8%

21 MOCANE-LAVERNE GAS AREA KS & OK & TX 1947 (21-50) 82.1

22 DRUNKARDS WASH UT 1989 (21-50) 78.4

23 RED OAK-NORRIS OK 1910 (21-50) 77.2

24 VIOSCA KNOLL BLK 956 FG 1985 (21-50) 76.8

25 SAWYER TX 1975 (21-50) 74.3

26 SPRABERRY TREND AREA TX 1950 (21-50) 72.1

27 MISSISSIPPI CANYON BLK 305 FG 2002 (21-50) 71.5

28 MISSISSIPPI CANYON BLK 807 FG 1989 (21-50) 68.8

29 STRONG CITY DISTRICT OK 1966 (21-50) 66.8

30 PANOMA GAS AREA KS 1956 (21-50) 66.8

31 EAST BREAKS BLK 690 FG 2001 (21-50) 66.6

32 OAK HILL TX 1958 (21-50) 62.4

33 MISSISSIPPI CANYON BLK 810 FG 1996 (21-50) 60.9

34 VERNON LA 1967 (21-50) 59.7

35 ELM GROVE LA 1958 (21-50) 57.9

36 MAMM CREEK CO 1959 (21-50) 57.5

37 BELUGA RIVER AK 1962 (21-50) 56.6

38 FREESTONE TX 1949 (21-50) 55.1

39 LA PERLA TX 1958 (21-50) 53.9

40 JUDGE DIGBY LA 1977 (21-50) 53.4

41 MCALLEN RANCH TX 1986 (21-50) 53.3

42 VIOSCA KNOLL BLK 915 FG 1993 (21-50) 52.6

43 VAQUILLAS RANCH TX 1978 (21-50) 52.4

44 WHITNEY CANYON-CARTER CRK WY 1978 (21-50) 52.4

45 EAST BREAKS BLK 579 FG 2003 (21-50) 52.3

46 WATONGA-CHICKASHA TREND OK 1962 (21-50) 51.7

47 OAKWOOD VA 1990 (21-50) 51.2

48 GOMEZ TX 1977 (21-50) 50.6

49 EAST BREAKS BLK 945 FG 1994 (21-50) 50.0

50 MISSISSIPPI CANYON BLK 211 FG 1994 (21-50) 50.0

Top 50 Volume Subtotal 79,072.1 15,801.0 6,438.9

Top 50 Percentage of U.S. Total 40.1% 32.2% 31.8%

Table B4. Top 100 U.S. Fields Ranked by Gas Production from Estimated 2003 Field Level Dataa

(Billion Cubic Feet)

Discovery Proved Reserves Nonproducing 2003 Reported

Field Name Location Year Rank Group Reserves Production Volume
Energy Information Administration

B-10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table B4. Top 100 U.S. Fields Ranked by Gas Production from Estimated 2003 Field Level Dataa

(Continued)

(Billion Cubic Feet)

Discovery Proved Reserves Nonproducing 2003 Reported

Field Name Location Year Rank Group Reserves Production Volume

51 BIG SANDY KY & WV 1881 (51-100) 48.6

52 COOK INLET NORTH AK 1962 (51-100) 48.1

53 SOUTH TIMBALIER BLK 176 FG 1963 (51-100) 48.1

54 DEW TX 1982 (51-100) 48.1

55 WILBURTON OK 1941 (51-100) 47.9

56 WEST CAMERON BLK 46 FG 2002 (51-100) 47.4

57 GOLDEN TREND OK 1945 (51-100) 47.1

58 TOM EAST TX 2001 (51-100) 46.5

59 SOUTH TIMBALIER BLK 190 FG 1965 (51-100) 46.3

60 B. M. T. TX 1994 (51-100) 44.8

61 KINTA OK 1914 (51-100) 42.9

62 GREEN CANYON BLK 116 FG 1985 (51-100) 42.8

63 ELK CITY OK 1947 (51-100) 42.6

64 WEST CAMERON BLK 192 FG 1954 (51-100) 42.3

65 DOWDY RANCH TX 1999 (51-100) 42.2

66 BALD PRAIRIE TX 1976 (51-100) 41.3

67 CEMENT OK 1917 (51-100) 41.0

68 MATAGORDA ISLAND BLK 623 FG 1980 (51-100) 41.0

69 JAVELINA TX 1947 (51-100) 40.9

70 BRAZOS BLK A20 FG 1979 (51-100) 40.6

71 MCARTHUR RIVER AK 1965 (51-100) 39.0

72 DESOTO CANYON BLK 133 FG 1993 (51-100) 38.1

73 HAWKINS TX 1940 (51-100) 38.0

74 GARDEN BANKS BLK 215 FG 1995 (51-100) 37.5

75 MISSISSIPPI CANYON BLK 348 FG 2000 (51-100) 36.9

76 WAMSUTTER WY 1958 (51-100) 36.2

77 MISSISSIPPI CANYON BLK 311 FG 1975 (51-100) 36.0

78 SAMANO TX 1985 (51-100) 35.9

79 GREEN CANYON BLK 472 FG 1989 (51-100) 35.8

80 BROWN-BASSETT TX 1953 (51-100) 35.3

81 KNOX OK 1916 (51-100) 35.1

82 FOGARTY CREEK WY 1975 (51-100) 34.7

83 EAST BREAKS BLK 688 FG 1992 (51-100) 34.2

84 ANSCHUTZ RANCH EAST UT & WY 1980 (51-100) 34.1

85 BRAZOS SA BLK A133 FG 1975 (51-100) 33.9

86 BRUFF WY 1969 (51-100) 33.3

87 HAYNES TX 1954 (51-100) 33.3

88 EUGENE ISLAND BLK 238 FG 1964 (51-100) 33.1

89 FRESH WATER BAYOU LA 1965 (51-100) 33.0

90 RIO VISTA CA 1936 (51-100) 32.6

91 VIOSCA KNOLL BLK 783 FG 1985 (51-100) 32.3

92 MOBILE BLK 823 FG 1983 (51-100) 31.9

93 MISSISSIPPI CANYON BLK 194 FG 1975 (51-100) 31.5

94 CHARCO TX 1948 (51-100) 31.3

95 SOONER TREND OK 1938 (51-100) 31.2

96 GRAND VALLEY CO 1985 (51-100) 31.2

97 MISSISSIPPI CANYON BLK 84 FG 1993 (51-100) 30.9

98 ECHO SPRINGS WY 1977 (51-100) 30.8

99 MONTE CHRISTO NORTH TX 1988 (51-100) 30.4

100 KENAI AK 1959 (51-100) 30.4

Top 100 Volume Subtotal 93,145.0 18,654.6 8,347.5

Top 100 Percentage of U.S. Total 47.2% 38.0% 41.3%

aTotal wet gas after lease separation.

Note: The U.S. total production estimate of 20,231 billion cubic feet and the U.S. total reserves estimate of 197,145 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.

FP = Federal Offshore Pacific

FG = Federal Offshore Gulf of Mexico

Source: Energy Information Administration, Office of Oil and Gas.
Table B5. Top U.S. Operators Ranked by Reported 2003 Operated Production Data

Total Natural Gas

Crude Oil Production Production

Rank Company Name (thousand barrels/day) Rank Company Name (million cubic feet/day)

1 BP PLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 874 1 BP PLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,797

2 CHEVRONTEXACO INC . . . . . . . . . . . . . . . . . . . 567 2 EXXONMOBIL CORP ................... 2,992

3 SHELL OIL CO . . . . . . . . . . . . . . . . . . . . . . . . . . . 466 3 CHEVRONTEXACO INC................. 2,554

4 CONOCOPHILLIPS CO . . . . . . . . . . . . . . . . . . . . 351 4 DEVON ENERGY CORP................. 2,313

5 OCCIDENTAL PETROLEUM CORP . . . . . . . . . . 265 5 SHELL OIL CO......................... 2,279

6 EXXONMOBIL CORP. . . . . . . . . . . . . . . . . . . . . . 248 6 CONOCOPHILLIPS CO.................. 2,266

7 AERA ENERGY LLC. . . . . . . . . . . . . . . . . . . . . . . 228 7 ANADARKO PETROLEUM CORP ......... 1,777

8 ANADARKO PETROLEUM CORP. . . . . . . . . . . . 104 8 BURLINGTON RESOURCES OIL & GAS CO. 1,677

9 KERR-MCGEE CORP . . . . . . . . . . . . . . . . . . . . . . 97 9 EL PASO ENERGY ..................... 1,410

10 AMERADA HESS CORP . . . . . . . . . . . . . . . . . . . . 93 10 APACHE CORP........................ 1,164

Top 10 Volume Subtotal ........................ 3,293 Top 10 Volume Subtotal ...................... 23,229

Top 10 Percentage of U.S. Total . . . . . . . . . . . . . . . . . . . . 58% Top 10 Percentage of U.S. Total . . . . . . . . . . . . . . . . . . . 42%

11 MARATHON OIL CO. . . . . . . . . . . . . . . . . . . . . . . . 84 11 UNOCAL CORP........................ 1,025

12 DEVON ENERGY CORP . . . . . . . . . . . . . . . . . . . . 83 12 DOMINION RESOURCES INC. . . . . . . . . . . . . . 998

13 APACHE CORP . . . . . . . . . . . . . . . . . . . . . . . . . . . 82 13 XTO ENERGY INC . . . . . . . . . . . . . . . . . . . . . . . 985

14 UNOCAL CORP . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 14 CHESAPEAKE ENERGY CORP . . . . . . . . . . . . 929

15 NUEVO ENERGY CO. . . . . . . . . . . . . . . . . . . . . . . 44 15 KERR-MCGEE CORP . . . . . . . . . . . . . . . . . . . . 912

16 POGO PRODUCING CO . . . . . . . . . . . . . . . . . . . . 43 16 MARATHON OIL CO. . . . . . . . . . . . . . . . . . . . . . 909

17 WESTPORT RESOURCES CORP. . . . . . . . . . . . . 43 17 E O G RESOURCES INC. . . . . . . . . . . . . . . . . . 879

18 MERIT ENERGY CO . . . . . . . . . . . . . . . . . . . . . . . 40 18 ENCANA OIL & GAS INC . . . . . . . . . . . . . . . . . . 835

19 CITY OF LONG BEACH . . . . . . . . . . . . . . . . . . . . . 32 19 OCCIDENTAL PETROLEUM CORP . . . . . . . . . 701

20 PLAINS EXPLOR & PROD CO . . . . . . . . . . . . . . . 32 20 WILLIAMS ENERGY INC . . . . . . . . . . . . . . . . . . 662

Top 20 Volume Subtotal ........................ 3,841 Top 20 Volume Subtotal ...................... 32,064

Top 20 Percentage of U.S. Total . . . . . . . . . . . . . . . . . . . . 68% Top 20 Percentage of U.S. Total . . . . . . . . . . . . . . . . . . . 58%

21 PIONEER NATURAL RESOURCES USA . . . . . . . 29 21 NEWFIELD EXPLORATION CO. . . . . . . . . . . . . 579

22 CITATION OIL & GAS CORP . . . . . . . . . . . . . . . . . 26 22 PIONEER NATURAL RESOURCES USA . . . . . 495

23 BURLINGTON RESOURCES OIL & GAS CO . . . . 26 23 WESTPORT RESOURCES CORP. . . . . . . . . . . 476

24 EL PASO ENERGY. . . . . . . . . . . . . . . . . . . . . . . . . 26 24 AMERADA HESS CORP . . . . . . . . . . . . . . . . . . 466

25 NEXEN PETROLEUM USA INC. . . . . . . . . . . . . . . 25 25 QUESTAR CORP . . . . . . . . . . . . . . . . . . . . . . . . 466

26 ENI PETROLEUM CO INC . . . . . . . . . . . . . . . . . . . 23 26 SAMSON RESOURCES CO . . . . . . . . . . . . . . . 465

27 NEWFIELD EXPLORATION CO. . . . . . . . . . . . . . . 23 27 TOTALFINAELF SA . . . . . . . . . . . . . . . . . . . . . . 407

28 DENBURY RESOURCES INC . . . . . . . . . . . . . . . . 23 28 HOUSTON EXPLORATION . . . . . . . . . . . . . . . . 378

29 KINDER MORGAN PROD CO INC . . . . . . . . . . . . 23 29 TOM BROWN INC . . . . . . . . . . . . . . . . . . . . . . . 306

30 HILCORP ENERGY CO . . . . . . . . . . . . . . . . . . . . . 22 30 NOBLE ENERGY INC . . . . . . . . . . . . . . . . . . . . 302

31 E O G RESOURCES INC . . . . . . . . . . . . . . . . . . . . 21 31 MERIT ENERGY CO . . . . . . . . . . . . . . . . . . . . . 299

32 NOBLE ENERGY INC. . . . . . . . . . . . . . . . . . . . . . . 19 32 EQUITABLE RESOURCES INC . . . . . . . . . . . . . 292

33 VINTAGE PETROLEUM INC . . . . . . . . . . . . . . . . . 19 33 WALTER OIL & GAS CORP . . . . . . . . . . . . . . . . 277

34 PATINA OIL & GAS CORP . . . . . . . . . . . . . . . . . . . 19 34 YATES PETROLEUM CORP . . . . . . . . . . . . . . . 264

35 BERRY PETROLEUM CO . . . . . . . . . . . . . . . . . . . 18 35 PATINA OIL & GAS CORP . . . . . . . . . . . . . . . . . 249

36 ENCORE OPERATING LP . . . . . . . . . . . . . . . . . . . 18 36 POGO PRODUCING CO . . . . . . . . . . . . . . . . . . 245

37 DOMINION RESOURCES INC. . . . . . . . . . . . . . . . 17 37 HUNT OIL CO. . . . . . . . . . . . . . . . . . . . . . . . . . . 239

38 STONE ENERGY CORP . . . . . . . . . . . . . . . . . . . . 17 38 ENERGEN RESOURCES CORP. . . . . . . . . . . . 232

39 FOREST OIL CORP . . . . . . . . . . . . . . . . . . . . . . . . 16 39 CABOT OIL & GAS CORP . . . . . . . . . . . . . . . . . 230

40 XTO ENERGY INC . . . . . . . . . . . . . . . . . . . . . . . . . 16 40 FOREST OIL CORP . . . . . . . . . . . . . . . . . . . . . . 224

41 CHESAPEAKE ENERGY CORP . . . . . . . . . . . . . . 15 41 HILCORP ENERGY CO . . . . . . . . . . . . . . . . . . . 217

42 NATIONAL FUEL GAS . . . . . . . . . . . . . . . . . . . . . . 14 42 STONE ENERGY CORP . . . . . . . . . . . . . . . . . . 214

43 WALTER OIL & GAS CORP . . . . . . . . . . . . . . . . . . 14 43 CIMAREX ENERGY CO . . . . . . . . . . . . . . . . . . . 200

44 ST MARY LAND & EXPLOR CO . . . . . . . . . . . . . . 14 44 KAISER - FRANCIS OIL CO. . . . . . . . . . . . . . . . 192

45 GRUY PETROLEUM MANAGEMENT CO . . . . . . . 13 45 DENBURY RESOURCES INC . . . . . . . . . . . . . . 181

46 BASS ENTERPRISES PRODUCTION CO . . . . . . 12 46 W & T OFFSHORE INC . . . . . . . . . . . . . . . . . . . 181

47 BHP BILLITON . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 47 SPINNAKER EXPLORATION CO LLC. . . . . . . . 180

48 YATES PETROLEUM CORP . . . . . . . . . . . . . . . . . 11 48 CALPINE NATURAL GAS CO . . . . . . . . . . . . . . 177

49 HUNT OIL CO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 49 EVERGREEN OPERATING CORP . . . . . . . . . . 174

50 MARBOB ENERGY CORP. . . . . . . . . . . . . . . . . . . 10 50 RED WILLOW LLC . . . . . . . . . . . . . . . . . . . . . . . 173

Top 50 Volume Subtotal ........................ 4,393 Top 50 Volume Subtotal ...................... 40,844

Top 50 Percentage of U.S. Total . . . . . . . . . . . . . . . . . . . . 78% Top 50 Percentage of U.S. Total . . . . . . . . . . . . . . . . . . . 74%

Note: Crude oil production includes production of lease condensate. Total natural gas production is wet after lease separation.

Energy Information Administration

B-11 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 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 me tric sys tem o f

measurement in its procurements, grants, and other

business–related activities."{42}

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 2003 Annual Report C-1
Energy Information Administration

C-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table C1. U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids,

in Metric Units, 1993 – 2003

Revisionsa Net of Sales New Reservoir Provedc Change Net and and New Field Discoveries Totalb Estimated Reserves from

Adjustments Revisions Adjustments Acquisitions 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)

1993 43.1 78.7 121.8 NA 56.6 50.7 17.5 124.8 371.9 3,649.9 -125.3

1994 30.1 160.1 190.2 NA 63.1 10.2 17.6 90.9 360.6 3,570.4 -79.5

1995 19.4 163.4 182.8 NA 79.5 18.1 54.5 152.1 351.8 3,553.5 -16.9

1996 28.0 117.1 145.1 NA 86.3 38.6 22.4 147.3 345.5 3,500.4 -53.1

1997 82.6 145.4 228.0 NA 75.8 101.3 18.9 196.0 339.9 3,584.5 84.1

1998 -101.5 82.3 -19.2 NA 52.0 24.2 19.1 95.3 316.5 3,344.1 -240.4

1999 22.1 289.2 311.3 NA 41.2 51.0 23.1 115.3 310.3 3,460.4 116.3

2000 22.7 118.6 141.3 -3.2 121.8 43.9 39.6 205.3 298.9 3,504.9 44.5

2001 -0.6 -25.1 -25.8 -13.8 137.7 223.7 46.4 407.8 304.5 3,568.6 63.7

2002 66.1 114.5 180.6 3.8 78.2 47.7 24.5 150.4 298.1 3,605.4 36.8

2003 25.9 14.9 40.9 -63.3 67.7 112.1 16.1 195.9 298.4 3,480.4 -125.0

Dry Natural Gas (billion cubic meters)

1993 27.51 151.47 178.98 NA 172.82 25.46 52.84 251.12 503.73 4,599.08 -73.63

1994 55.08 155.29 210.37 NA 196.55 53.63 98.54 348.72 518.82 4,639.35 40.27

1995 16.42 219.00 235.42 NA 193.77 47.18 69.43 310.38 508.74 4,676.41 37.06

1996 107.18 115.70 222.88 NA 219.65 41.09 88.07 348.81 534.08 4,714.02 37.61

1997 -16.70 138.81 122.11 NA 299.73 75.92 67.45 443.10 544.00 4,735.23 21.21

1998 -46.30 162.54 116.24 NA 232.11 30.41 61.22 323.74 530.09 4,645.12 -90.11

1999 27.81 297.44 325.25 NA 199.44 44.40 62.18 306.02 535.98 4,740.41 95.29

2000 -25.23 197.14 171.91 114.15 418.72 56.15 67.05 541.93 544.22 5,024.17 283.76

2001 77.64 -65.64 12.01 74.47 463.83 101.32 79.29 644.44 560.08 5,195.01 170.84

2002 105.54 26.53 132.07 10.76 418.21 37.72 47.97 503.90 548.02 5,293.72 98.71

2003 80.45 -46.38 34.07 29.28 465.93 34.60 45.59 546.12 550.05 5,353.10 59.38

Natural Gas Liquids (million cubic meters)

1993 16.2 19.7 35.9 NA 39.0 3.8 10.2 53.0 125.3 1,148.2 -36.4

1994 6.9 31.3 38.2 NA 49.9 8.6 20.8 79.3 125.8 1,139.9 -8.3

1995 30.6 44.0 74.6 NA 68.7 8.1 10.7 87.6 125.8 1,176.3 36.4

1996 75.4 27.8 103.2 NA 71.7 10.3 17.3 99.4 135.1 1,243.8 67.4

1997 -2.2 45.9 43.7 NA 85.1 18.1 14.3 117.5 137.4 1,267.6 23.8

1998 -57.4 33.1 -24.3 NA 60.9 10.5 14.0 85.4 132.4 1,196.2 -71.4

1999 15.8 115.6 131.4 NA 49.8 8.1 14.0 71.9 142.5 1,257.0 60.8

2000 -13.2 73.0 59.8 23.1 102.5 14.6 16.2 133.4 146.4 1,326.7 69.7

2001 -68.2 -21.0 -89.2 16.2 114.0 21.9 22.6 158.5 141.5 1,270.8 -55.9

2002 9.9 4.9 14.8 8.6 97.3 7.6 12.4 117.3 140.5 1,270.9 0.1

2003 -53.7 -25.6 -79.3 4.8 100.0 5.6 11.4 117.0 127.5 1,185.9 -85.0

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

bTotal discoveries = Col. 5 + Col. 6 + Col. 7. cProved reserves = Col. 10 from prior year + Col. 3 + 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: barrels = 0.1589873 per cubic meter

and cubic feet = 0.02831685 per cubic 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, 1993–2003 annual reports, DOE/EIA–0216.{17–26}
Appendix D

Historical Reserves Statistics
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report D-1

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 2002 of the EIA publication U.S. Crude Oil, Natural

Gas, and Natural Gas Liquids Reserves, DOE EIA-0216.{1-26}

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

2000 34 NA c4,149 150

2001 42 NA c3,915 64

2002 51 NA c3,884 57

2003 52 NA c4,301 60

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; 2,645 Bcf in 2000; 2,454 Bcf in 2001; 2,290 Bcf

in 2002; 2,132 Bcf in 2003.

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

2000 4,861 NA 9,237 277

2001 4,851 NA 8,800 405

2002 4,678 NA 8,468 405

2003 4,446 NA 8,285 387

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

D-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 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

2000 48 NA 1,581 5

2001 43 NA 1,616 5

2002 49 NA 1,650 4

2003 50 NA 1,663 3

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

2000 d3,813 NA d2,849 d101

2001 d3,627 NA d2,681 d76

2002 d3,633 NA d2,591 d95

2003 d3,452 NA d2,450 d101

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

2000 455 NA 234 27

2001 385 NA 177 16

2002 404 NA 190 17

2003 395 NA 167 15

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

2000 292 NA 193 10

2001 297 NA 187 8

2002 330 NA 207 10

2003 319 NA 187 8
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report D-3

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

2000 2,870 NA 2,331 64

2001 2,766 NA 2,232 52

2002 2,702 NA 2,102 68

2003 2,565 NA 2,013 78

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

2000 792 NA 667 4

2001 726 NA 625 9

2002 762 NA 607 8

2003 739 NA 594 0

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

2000 196 NA 91 0

2001 179 NA 85 0

2002 197 NA 92 0

2003 173 NA 83 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

2000 596 NA 576 4

2001 547 NA 540 9

2002 565 NA 515 8

2003 566 NA 511 8
Energy Information Administration

D-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 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

2000 217 NA 10,428 316

2001 196 NA 12,527 345

2002 214 NA 13,888 396

2003 217 NA 15,436 395

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

2000 76 NA 82 11

2001 75 NA 84 12

2002 73 NA 91 14

2003 68 NA 79 17

Illinois

1977 *150 1 NA NA

1978 *158 1 NA NA

1979 *136 1 NA NA

1980 113 2 NA NA

1981 129 1 NA NA

1982 150 1 NA NA

1983 135 1 NA NA

1984 153 1 NA NA

1985 136 1 NA NA

1986 135 1 NA NA

1987 153 5 NA NA

1988 143 <1 NA NA

1989 123 <1 NA NA

1990 131 0 NA NA

1991 128 52 NA NA

1992 138 0 NA NA

1993 116 0 NA NA

1994 117 0 NA NA

1995 119 0 NA NA

1996 94 0 NA NA

1997 92 0 NA NA

1998 81 0 NA NA

1999 100 0 NA NA

2000 111 NA NA NA

2001 92 NA NA NA

2002 107 NA NA NA

2003 125 NA 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

2000 15 NA NA NA

2001 12 NA NA NA

2002 15 NA NA NA

2003 19 NA NA NA
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report D-5

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

2000 237 NA 5,299 306

2001 216 NA 5,101 302

2002 237 NA 4,983 263

2003 243 NA 4,819 248

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

2000 24 NA 1,760 56

2001 17 NA 1,860 72

2002 27 NA 1,907 66

2003 25 NA 1,889 66

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 f

601

1996 f658 f331 f9,543 f543

1997 f714 f313 f9,673 f437

1998 f551 f316 f9,147 f411

1999 f600 f278 f9,242 f457

2000 f529 NA f9,239 f436

2001 f564 NA f9,811 f391

2002 f501 NA f8,960 f323

2003 f452 NA f9,325 f295

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

2000 97 NA 3,298 61

2001 87 NA 3,881 62

2002 75 NA 4,245 49

2003 66 NA 5,074 67
Energy Information Administration

D-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 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

2000 310 NA 5,245 337

2001 341 NA 5,185 269

2002 335 NA 4,224 226

2003 314 NA 3,745 182

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 f

151 f838 f27

1996 f148 f9 f734 f47

1997 f151 f4 f725 f24

1998 f97 f2 f551 f29

1999 f108 f0 f628 f32

2000 f122 NA f696 f38

2001 f136 NA f745 f60

2002 f91 NA f491 f48

2003 f72 NA f506 f46

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

2000 56 NA 2,729 35

2001 46 NA 2,976 43

2002 61 NA 3,254 47

2003 75 NA 3,428 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

2000 182 NA 618 8

2001 167 NA 661 10

2002 179 NA 744 8

2003 169 NA 746 7
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report D-7

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

2000 235 NA 885 4

2001 260 NA 898 5

2002 288 NA 906 6

2003 315 NA 1,059 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

2000 18 NA NA NA

2001 15 NA NA NA

2002 18 NA NA NA

2003 16 NA 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

2000 719 NA 17,322 896

2001 715 NA 17,414 873

2002 710 NA 17,320 838

2003 677 NA 17,020 875

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

2000 705 NA 3,537 333

2001 703 NA 3,518 279

2002 699 NA 3,632 290

2003 668 NA 3,301 272
Energy Information Administration

D-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 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

2000 14 NA 13,785 563

2001 12 NA 13,896 594

2002 11 NA 13,688 548

2003 9 NA 13,719 603

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

2000 NA NA 322 NA

2001 NA NA 318 NA

2002 NA NA 315 NA

2003 NA NA 365 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

2000 270 NA 433 54

2001 328 NA 443 57

2002 342 NA 471 47

2003 353 NA 448 45

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

2000 59 NA 1,185 NA

2001 46 NA 970 NA

2002 67 NA 1,117 NA

2003 66 NA 1,126 NA
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report D-9

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

2000 610 NA 13,699 734

2001 556 NA 13,558 694

2002 598 NA 14,886 695

2003 588 NA 15,401 686

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

2000 15 NA 1,741 NA

2001 10 NA 1,775 NA

2002 12 NA 2,216 NA

2003 13 NA 2,487 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

2000 g5,273 NA g40,082 g2,819

2001 g4,944 NA g43,527 g2,653

2002 g5,015 NA g44,297 g2,711

2003 g4,583 NA g45,730 g2,517

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

2000 87 NA 1,032 55

2001 46 NA 1,018 40

2002 50 NA 1,045 39

2003 59 NA 1,062 29
Energy Information Administration

D-10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 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

2000 54 NA 1,980 72

2001 48 NA 1,801 67

2002 54 NA 1,782 71

2003 51 NA 1,770 69

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

2000 213 NA 3,873 209

2001 195 NA 3,770 226

2002 218 NA 3,584 241

2003 190 NA 3,349 207

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

2000 34 NA 9,645 406

2001 32 NA 9,956 378

2002 28 NA 9,469 370

2003 30 NA 8,763 287

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

2000 44 NA 3,168 49

2001 29 NA 4,231 49

2002 24 NA 4,602 50

2003 20 NA 5,407 51
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report D-11

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

2000 213 NA 5,976 283

2001 200 NA 6,128 269

2002 198 NA 6,256 277

2003 189 NA 6,685 248

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

2000 124 NA 312 34

2001 91 NA 252 29

2002 82 NA 260 25

2003 68 NA 340 32

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

2000 206 NA 3,504 434

2001 188 NA 3,320 290

2002 177 NA 3,702 351

2003 205 NA 4,327 345

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

2000 2,073 NA 5,388 526

2001 1,880 NA 5,255 525

2002 1,913 NA 5,361 510

2003 1,513 NA 5,142 498
Energy Information Administration

D-12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 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

2000 2,022 NA 1,101 217

2001 2,070 NA 1,085 251

2002 2,093 NA 1,084 181

2003 2,089 NA 1,056 163

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

2000 131 NA 1,626 161

2001 104 NA 2,289 189

2002 113 NA 2,877 238

2003 114 NA 3,309 236

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

2000 67 NA 4,079 369

2001 55 NA 3,955 335

2002 59 NA 3,838 353

2003 48 NA 4,064 347

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

2000 428 NA 6,782 157

2001 417 NA 7,242 187

2002 362 NA 6,626 187

2003 310 NA 5,787 124
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report D-13

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

2000 5 NA 398 4

2001 6 NA 467 5

2002 6 NA 437 5

2003 7 NA 456 5

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)

2000 283 NA 4,235 (h)

2001 271 NA 4,579 (h)

2002 241 NA 4,135 (h)

2003 221 NA 3,516 (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

2000 NA NA 1,704 NA

2001 NA NA 1,752 NA

2002 NA NA 1,673 NA

2003 NA NA 1,717 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

2000 12 NA 2,900 105

2001 8 NA 2,678 106

2002 13 NA 3,360 99

2003 13 NA 3,306 68
Energy Information Administration

D-14 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 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

2000 561 NA 16,158 i947

2001 489 NA 18,398 i897

2002 524 NA 20,527 i938

2003 517 NA 21,744 i898

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

2000 3,770 NA 26,748 1,078

2001 4,835 NA 27,036 976

2002 5,009 NA 25,204 973

2003 5,120 NA 22,570 725

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

2000 596 NA 576 4

2001 547 NA 540 9

2002 565 NA 515 8

2003 566 NA 511 8

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

2000 2,751 NA k19,788 k921

2001 3,877 NA k19,721 k785

2002 4,088 NA k18,500 k783

2003 4,251 NA k16,728 k598

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 2003 Annual Report D-15

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

2000 423 NA 6,384 153

2001 411 NA 6,775 182

2002 356 NA 6,189 182

2003 303 NA 5,331 119

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

2000 17 NA 42 7

2001 21 NA 82 7

2002 15 NA 99 9

2003 16 NA 134 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

2000 17,184 NA 168,190 8,068

2001 17,595 NA 174,660 7,588

2002 17,999 NA 178,478 7,589

2003 17,445 NA 180,759 7,072

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

2000 22,045 NA 177,427 8,345

2001 22,446 NA 183,460 7,993

2002 22,677 NA 186,946 7,994

2003 21,891 NA 189,044 7,459
Energy Information Administration

D-16 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table D1. U.S. Proved Reserves of Crude Oil, 1976–2003

(Million Barrels of 42 U.S. Gallons)

Revisionsb Net of Sales New Reservoir Provedd Change

Net and and New Field Discoveries Totalc Estimated Reserves from

Adjustmentsa Revisions Adjustments Acquisitions 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-40 386 346 NA 496 168 130 794 2,862 31,780 -1,722

1978 366 1,390 1,756 NA 444 267 116 827 3,008 31,355 -425

1979 337 437 774 NA 424 108 104 636 2,955 29,810 -1,545

1980 219 1,889 2,108 NA 572 143 147 862 2,975 29,805 -5

1981 138 1,271 1,409 NA 750 254 157 1,161 2,949 29,426 -379

1982 -83 434 351 NA 634 204 193 1,031 2,950 27,858 -1,568

1983 462 1,511 1,973 NA 629 105 190 924 3,020 27,735 -123

1984 159 2,445 2,604 NA 744 242 158 1,144 3,037 28,446 711

1985 429 1,598 2,027 NA 742 84 169 995 3,052 28,416 -30

1986 57 855 912 NA 405 48 81 534 2,973 26,889 -1,527

1987 233 2,316 2,549 NA 484 96 111 691 2,873 27,256 367

1988 364 1,463 1,827 NA 355 71 127 553 2,811 26,825 -431

1989 213 1,333 1,546 NA 514 112 90 716 2,586 26,501 -324

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

1991 163 223 386 NA 365 97 92 554 2,512 24,682 -1,572

1992 290 735 1,025 NA 391 8 85 484 2,446 23,745 -937

1993 271 495 766 NA 356 319 110 785 2,339 22,957 -788

1994 189 1,007 1,196 NA 397 64 111 572 2,268 22,457 -500

1995 122 1,028 1,150 NA 500 114 343 957 2,213 22,351 -106

1996 175 737 912 NA 543 243 141 927 2,173 22,017 -334

1997 520 914 1,434 NA 477 637 119 1,233 2,138 22,546 529

1998 -638 518 -120 NA 327 152 120 599 1,991 21,034 -1,512

1999 139 1,819 1,958 NA 259 321 145 725 1,952 21,765 731

2000 143 746 889 -20 766 276 249 1,291 1,880 22,045 280

2001 -4 -158 -162 -87 866 1,407 292 2,565 1,915 22,446 401

2002 416 720 1,136 24 492 300 154 946 1,875 22,677 231

2003 163 94 257 -398 426 705 101 1,232 1,877 21,891 -786

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. c

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

d

Proved reserves = Col. 10 from prior year + Col. 3 + 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 2003 annual reports, DOE/EIA-0216.{1-26}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report D-17

Table D2. U.S. Lower 48 Proved Reserves of Crude Oil, 1976–2003

(Million Barrels of 42 U.S. Gallons)

Revisionsb Net of Sales New Reservoir Provedd Change

Net and and New Field Discoveries Totalc Estimated Reserves from

Adjustmentsa Revisions Adjustments Acquisitions 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–40 383 343 NA 496 168 130 794 2,698 23,367 -1,561

1978 -48 509 461 NA 444 142 116 702 2,559 21,971 -1,396

1979 342 429 771 NA 424 108 104 636 2,443 20,935 -1,036

1980 210 1,524 1,734 NA 479 143 147 769 2,384 21,054 119

1981 276 1,009 1,285 NA 750 254 157 1,161 2,357 21,143 89

1982 -82 684 602 NA 633 204 193 1,030 2,323 20,452 -691

1983 462 949 1,411 NA 625 105 190 920 2,355 20,428 -24

1984 160 1,587 1,747 NA 742 207 158 1,107 2,399 20,883 455

1985 361 1,667 2,028 NA 581 84 169 834 2,385 21,360 477

1986 70 359 429 NA 399 48 81 528 2,303 20,014 -1,346

1987 233 1,353 1,586 NA 294 38 101 433 2,155 19,878 -136

1988 359 1,181 1,540 NA 340 43 127 510 2,062 19,866 -12

1989 214 1,113 1,327 NA 342 108 87 537 1,903 19,827 -39

1990 151 1,001 1,152 NA 371 98 135 604 1,853 19,730 -97

1991 164 50 214 NA 327 97 87 511 1,856 18,599 -1,131

1992 297 277 574 NA 279 8 84 371 1,821 17,723 -876

1993 250 198 448 NA 343 319 109 771 1,760 17,182 -541

1994 187 527 714 NA 316 64 111 491 1,697 16,690 -492

1995 117 756 873 NA 434 114 333 881 1,673 16,771 81

1996 172 728 900 NA 479 115 141 735 1,663 16,743 -28

1997 514 695 1,209 NA 459 520 119 1,098 1,665 17,385 642

1998 -639 315 -324 NA 299 56 120 475 1,554 15,982 -1,403

1999 138 1,669 1,807 NA 253 242 145 640 1,564 16,865 883

2000 144 622 766 132 540 276 157 973 1,552 17,184 319

2001 -5 -71 -76 -87 716 1,126 292 2,134 1,560 17,595 411

2002 414 567 981 24 467 300 146 913 1,514 17,999 404

2003 162 5 167 -398 391 705 101 1,197 1,520 17,445 -554

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. c

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

d

Proved reserves = Col. 10 from prior year + Col. 3 + 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 2003 annual reports, DOE/EIA-0216.{1-26}
Energy Information Administration

D-18 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table D3. U.S. Proved Reserves of Dry Natural Gas, 1976–2003

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

Revisionsb Net of Sales New Reservoir Provedd Change

Net and and New Field Discoveries Totalc Estimated Reserves from

Adjustmentsa Revisions Adjustments Acquisitions 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 -1,605 -1,625 NA 8,129 3,173 3,301 14,603 18,843 207,413 -5,865

1978 2,429 -1,025 1,404 NA 9,582 3,860 4,579 18,021 18,805 208,033 620

1979 -2,264 -219 -2,483 NA 8,950 3,188 2,566 14,704 19,257 200,997 -7,036

1980 1,201 1,049 2,250 NA 9,357 2,539 2,577 14,473 18,699 199,021 -1,976

1981 1,627 2,599 4,226 NA 10,491 3,731 2,998 17,220 18,737 201,730 2,709

1982 2,378 455 2,833 NA 8,349 2,687 3,419 14,455 17,506 201,512 -218

1983 3,090 -15 3,075 NA 6,909 1,574 2,965 11,448 15,788 200,247 -1,265

1984 -2,241 3,129 888 NA 8,299 2,536 2,686 13,521 17,193 197,463 -2,784

1985 -1,708 2,471 763 NA 7,169 999 2,960 11,128 15,985 193,369 -4,094

1986 1,320 3,572 4,892 NA 6,065 1,099 1,771 8,935 15,610 191,586 -1,783

1987 1,268 3,296 4,564 NA 4,587 1,089 1,499 7,175 16,114 187,211 -4,375

1988 2,193 -15,060 -12,867 NA 6,803 1,638 1,909 10,350 16,670 168,024 -19,187

1989 3,013 3,030 6,043 NA 6,339 1,450 2,243 10,032 16,983 167,116 -908

1990 1,557 5,538 7,095 NA 7,952 2,004 2,412 12,368 17,233 169,346 2,230

1991 2,960 4,416 7,376 NA 5,090 848 1,604 7,542 17,202 167,062 -2,284

1992 2,235 6,093 8,328 NA 4,675 649 1,724 7,048 17,423 165,015 -2,047

1993 972 5,349 6,321 NA 6,103 899 1,866 8,868 17,789 162,415 -2,600

1994 1,945 5,484 7,429 NA 6,941 1,894 3,480 12,315 18,322 163,837 1,422

1995 580 7,734 8,314 NA 6,843 1,666 2,452 10,961 17,966 165,146 1,309

1996 3,785 4,086 7,871 NA 7,757 1,451 3,110 12,318 18,861 166,474 1,328

1997 -590 4,902 4,312 NA 10,585 2,681 2,382 15,648 19,211 167,223 749

1998 -1,635 5,740 4,105 NA 8,197 1,074 2,162 11,433 18,720 164,041 -3,182

1999 982 10,504 11,486 NA 7,043 1,568 2,196 10,807 18,928 167,406 3,365

2000 -891 6,962 6,071 4,031 14,787 1,983 2,368 19,138 19,219 177,427 10,021

2001 2,742 -2,318 424 2,630 16,380 3,578 2,800 22,758 19,779 183,460 6,033

2002 3,727 937 4,664 380 14,769 1,332 1,694 17,795 19,353 186,946 3,486

2003 2,841 -1,638 1,203 -10,092 16,454 1,222 1,610 19,286 19,425 189,044 2,098

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. c

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

d

Proved reserves = Col. 10 from prior year + Col. 3 + 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 2003 annual reports, DOE/EIA-0216.{1-26}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report D-19

Table D4. U.S. Lower 48 Proved Reserves of Dry Natural Gas, 1976–2003

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

Revisionsb Net of Sales New Reservoir Provedd Change

Net and and New Field Discoveries Totalc Estimated Reserves from

Adjustmentsa Revisions Adjustments Acquisitions 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 -1,540 -1,561 NA 8,056 3,173 3,301 14,530 18,637 175,170 -5,668

1978 2,446 -758 1,688 NA 9,582 3,860 4,277 17,719 18,589 175,988 818

1979 -2,202 -707 -2,909 NA 8,949 3,173 2,566 14,688 19,029 168,738 -7,250

1980 1,163 62 1,225 NA 9,046 2,539 2,577 14,162 18,486 165,639 -3,099

1981 1,840 2,506 4,346 NA 10,485 3,731 2,994 17,210 18,502 168,693 3,054

1982 2,367 -1,748 619 NA 8,349 2,687 3,419 14,455 17,245 166,522 -2,171

1983 3,089 421 3,510 NA 6,908 1,574 2,965 11,447 15,515 165,964 -558

1984 -2,245 2,617 372 NA 8,298 2,536 2,686 13,520 16,869 162,987 -2,977

1985 -1,349 2,500 1,151 NA 7,098 999 2,960 11,057 15,673 159,522 -3,465

1986 1,618 4,144 5,762 NA 6,064 1,099 1,761 8,924 15,286 158,922 -600

1987 1,066 2,645 3,711 NA 4,542 1,077 1,499 7,118 15,765 153,986 -4,936

1988 2,017 8,895 10,912 NA 6,771 1,638 1,909 10,318 16,270 158,946 4,960

1989 2,997 2,939 5,936 NA 6,184 1,450 2,243 9,877 16,582 158,177 -769

1990 1,877 4,572 6,449 NA 7,898 2,004 2,412 12,314 16,894 160,046 1,869

1991 2,967 3,860 6,827 NA 5,074 848 1,563 7,485 16,849 157,509 -2,537

1992 1,946 5,937 7,883 NA 4,621 649 1,724 6,994 17,009 155,377 -2,132

1993 915 4,779 5,694 NA 6,076 899 1,858 8,833 17,396 152,508 -2,869

1994 1,896 5,289 7,185 NA 6,936 1,894 3,480 12,310 17,899 154,104 1,596

1995 973 7,223 8,196 NA 6,801 1,666 2,452 10,919 17,570 155,649 1,545

1996 3,640 4,055 7,695 NA 7,751 1,390 3,110 12,251 18,415 157,180 1,531

1997 -609 3,192 2,583 NA 10,571 2,681 2,382 15,634 18,736 156,661 -519

1998 -1,463 5,696 4,233 NA 8,195 1,070 2,162 11,427 18,207 154,114 -2,547

1999 849 10,452 11,301 NA 7,041 1,512 2,173 10,726 18,469 157,672 3,558

2000 -914 8,755 7,841 4,214 12,838 1,983 2,355 17,176 18,713 168,190 10,518

2001 2,753 -2,216 537 2,630 16,321 3,504 2,796 21,621 19,318 174,660 6,470

2002 3,692 914 4,606 380 14,707 1,332 1,686 17,725 18,893 178,478 3,818

2003 2,840 -1,830 1,010 1,034 16,373 1,202 1,609 19,184 18,947 180,759 2,281

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. c

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

d

Proved reserves = Col. 10 from prior year + Col. 3 + 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 2003 annual reports, DOE/EIA-0216.{1-26}
Energy Information Administration

D-20 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table D5. U.S. Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–2003

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

Revisionsb Net of Sales New Reservoir Provedd Change

Net and and New Field Discoveries Totalc Estimated Reserves from

Adjustmentsa Revisions Adjustments Acquisitions 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 -223 5,133 NA 9,332 3,279 2,637 15,248 20,079 208,335 302

1980 1,253 1,137 2,390 NA 9,757 2,629 2,648 15,034 19,500 206,259 -2,076

1981 2,057 2,743 4,800 NA 10,979 3,870 3,080 17,929 19,554 209,434 3,175

1982 2,598 455 3,053 NA 8,754 2,785 3,520 15,059 18,292 209,254 -180

1983 4,363 57 4,420 NA 7,263 1,628 3,071 11,962 16,590 209,046 -208

1984 -2,413 3,333 920 NA 8,688 2,584 2,778 14,050 18,032 205,984 -3,062

1985 -1,299 2,687 1,388 NA 7,535 1,040 3,053 11,628 16,798 202,202 -3,782

1986 2,137 3,835 5,972 NA 6,359 1,122 1,855 9,336 16,401 201,109 -1,093

1987 1,199 3,522 4,721 NA 4,818 1,128 1,556 7,502 16,904 196,428 -4,681

1988 2,180 -14,931 f-12,751 NA 7,132 1,677 1,979 10,788 17,466 f176,999 –19,429

1989 2,537 3,220 5,757 NA 6,623 1,488 2,313 10,424 17,752 175,428 -1,571

1990 1,494 5,837 7,331 NA 8,287 2,041 2,492 12,820 18,003 177,576 2,148

1991 3,368 4,569 7,937 NA 5,298 871 1,655 7,824 18,012 175,325 -2,251

1992 2,543 6,374 8,917 NA 4,895 668 1,773 7,336 18,269 173,309 -2,016

1993 1,048 5,541 6,589 NA 6,376 927 1,930 9,233 18,641 170,490 -2,819

1994 1,977 5,836 7,813 NA 7,299 1,941 3,606 12,846 19,210 171,939 1,449

1995 889 8,091 8,980 NA 7,204 1,709 2,518 11,431 18,874 173,476 1,537

1996 4,288 4,277 8,565 NA 8,189 1,491 3,209 12,889 19,783 175,147 1,671

1997 -730 5,057 4,327 NA 11,179 2,747 2,455 16,381 20,134 175,721 574

1998 -1,624 5,982 4,358 NA 8,630 1,116 2,240 11,986 19,622 172,433 -3,288

1999 1,102 11,182 12,284 NA 7,401 1,622 2,265 11,288 19,856 176,159 3,726

2000 -1,295 7,456 6,161 4,286 15,550 2,055 2,463 20,068 20,164 186,510 10,351

2001 1,849 -2,438 -589 2,715 17,183 3,668 2,898 23,749 20,642 191,743 5,233

2002 4,004 1,038 5,042 428 15,468 1,374 1,752 18,594 20,248 195,561 3,816

2003 2,323 -1,715 608 1,107 17,195 1,252 1,653 20,100 20,231 197,145 1,584

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. c

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

d

Proved reserves = Col. 10 from prior year + Col. 3 + 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 2003 annual reports, DOE/EIA-0216.{3-26}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report D-21

Table D6. U.S. Lower 48 Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–2003

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

Revisionsb Net of Sales New Reservoir Provedd Change

Net and and New Field Discoveries Totalc Estimated Reserves from

Adjustmentsa Revisions Adjustments Acquisitions 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 -711 4,691 NA 9,331 3,264 2,637 15,232 19,851 176,060 72

1980 1,218 150 1,368 NA 9,446 2,629 2,648 14,723 19,287 172,864 -3,196

1981 2,270 2,650 4,920 NA 10,973 3,870 3,076 17,919 19,318 176,385 3,521

1982 2,586 -1,748 838 NA 8,754 2,785 3,520 15,059 18,030 174,252 -2,133

1983 4,366 493 4,859 NA 7,262 1,628 3,071 11,961 16,317 174,755 503

1984 -2,409 2,821 412 NA 8,687 2,584 2,778 14,049 17,708 171,508 -3,247

1985 -1,313 2,713 1,400 NA 7,463 1,040 3,053 11,556 16,485 167,979 -3,529

1986 2,114 4,410 6,524 NA 6,357 1,122 1,845 9,324 16,073 167,754 -225

1987 1,200 2,868 4,068 NA 4,772 1,116 1,556 7,444 16,553 162,713 -5,041

1988 2,025 9,390 11,415 NA 7,099 1,677 1,979 10,755 17,063 167,820 5,107

1989 2,545 3,128 5,673 NA 6,467 1,485 2,313 10,265 17,349 166,409 -1,411

1990 1,811 4,859 6,670 NA 8,232 2,041 2,492 12,765 17,661 168,183 1,774

1991 3,367 4,013 7,380 NA 5,281 871 1,614 7,766 17,657 165,672 -2,511

1992 2,265 6,217 8,482 NA 4,840 668 1,773 7,281 17,851 163,584 -2,088

1993 996 4,971 5,967 NA 6,349 927 1,922 9,198 18,245 160,504 -3,080

1994 1,924 5,613 7,537 NA 7,294 1,941 3,606 12,841 18,756 162,126 1,622

1995 1,304 7,525 8,829 NA 7,162 1,709 2,518 11,389 18,443 163,901 1,775

1996 4,219 4,246 8,465 NA 8,183 1,430 3,209 12,822 19,337 165,851 1,950

1997 -835 3,322 2,487 NA 11,165 2,747 2,455 16,367 19,657 165,048 -803

1998 -1,461 5,937 4,476 NA 8,628 1,112 2,240 11,980 19,104 162,400 -2,648

1999 958 11,130 12,088 NA 7,399 1,566 2,242 11,207 19,391 166,304 3,904

2000 -1,294 9,273 7,979 4,471 13,574 2,055 2,450 18,079 19,654 177,179 10,875

2001 1,849 -2,336 -487 2,715 17,123 3,593 2,894 23,610 20,175 182,842 5,663

2002 4,004 1,038 5,042 428 15,468 1,374 1,752 18,594 20,248 19,5561 3,816

2003 2,324 -1,909 415 1,107 17,114 1,232 1,652 19,998 19,751 188,797 1,769

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. c

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

d

Proved reserves = Col. 10 from prior year + Col. 3 + 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 2003 annual reports, DOE/EIA-0216.{3-26}
Energy Information Administration

D-22 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table D7. U.S. Proved Reserves of Natural Gas Liquids, 1978–2003

(Million Barrels of 42 U.S. Gallons)

Revisionsb Net of Sales New Reservoir Provedd Change

Net and and New Field Discoveries Totalc Estimated Reserves from

Adjustmentsa Revisions Adjustments Acquisitions 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 -49 15 NA 364 94 97 555 727 6,615 -157

1980 153 104 257 NA 418 90 79 587 731 6,728 113

1981 231 86 317 NA 542 131 91 764 741 7,068 340

1982 299 -21 278 NA 375 112 109 596 721 7,221 153

1983 849 66 915 NA 321 70 99 490 725 7,901 680

1984 -123 142 19 NA 348 55 96 499 776 7,643 -258

1985 426 162 588 NA 337 44 85 466 753 7,944 301

1986 367 223 590 NA 263 34 72 369 738 8,165 221

1987 231 191 422 NA 213 39 55 307 747 8,147 -18

1988 11 453 464 NA 268 41 72 381 754 8,238 91

1989 -277 123 -154 NA 259 83 74 416 731 7,769 -469

1990 -83 221 138 NA 299 39 73 411 732 7,586 -183

1991 233 130 363 NA 189 25 55 269 754 7,464 -122

1992 225 261 486 NA 190 20 64 274 773 7,451 -13

1993 102 124 226 NA 245 24 64 333 788 7,222 -229

1994 43 197 240 NA 314 54 131 499 791 7,170 -52

1995 192 277 469 NA 432 52 67 551 791 7,399 229

1996 474 175 649 NA 451 65 109 625 850 7,823 424

1997 -14 289 275 NA 535 114 90 739 864 7,973 150

1998 -361 208 -153 NA 383 66 88 537 833 7,524 -449

1999 99 727 826 NA 313 51 88 452 896 7,906 382

2000 -83 459 376 145 645 92 102 839 921 8,345 439

2001 -429 -132 -561 102 717 138 142 997 890 7,993 -352

2002 62 31 93 54 612 48 78 738 884 7,994 1

2003 -338 -161 -499 30 629 35 72 736 802 7,459 -535

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. c

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

d

Proved reserves = Col. 10 from prior year + Col. 3 + 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 2003 annual reports, DOE/EIA-0216.{3-26}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report D-23

Table D8. U.S. Lower 48 Proved Reserves of Natural Gas Liquids, 1978–2003

(Million Barrels of 42 U.S. Gallons)

Revisionsb Net of Sales New Reservoir Provedd Change

Net and and New Field Discoveries Totalc Estimated Reserves from

Adjustmentsa Revisions Adjustments Acquisitions 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 -49 14 NA 364 94 97 555 726 6,592 -157

1980 165 104 269 NA 418 90 79 587 731 6,717 125

1981 233 85 318 NA 542 131 91 764 741 7,058 341

1982 300 -21 279 NA 375 112 109 596 721 7,212 154

1983 850 66 916 NA 321 70 99 490 725 7,893 681

1984 -115 123 8 NA 348 55 96 499 776 7,624 -269

1985 70 152 222 NA 334 44 85 463 748 7,561 -63

1986 363 226 589 NA 263 34 72 369 735 7,784 223

1987 179 191 370 NA 212 39 55 306 731 7,729 -55

1988 10 452 462 NA 267 41 72 380 734 7,837 108

1989 -273 123 -150 NA 259 83 74 416 714 7,389 -448

1990 -60 221 161 NA 298 39 73 410 714 7,246 -143

1991 183 138 321 NA 187 25 55 267 730 7,104 -142

1992 225 254 479 NA 183 20 64 267 746 7,104 0

1993 101 124 225 NA 245 24 64 333 761 6,901 -203

1994 38 196 234 NA 314 54 131 499 765 6,869 -32

1995 204 230 434 NA 432 52 67 551 761 7,093 224

1996 417 178 595 NA 450 56 109 615 817 7,486 393

1997 -107 55 -52 NA 533 114 90 737 829 7,342 -144

1998 -74 208 134 NA 383 66 88 537 809 7,204 -138

1999 102 617 719 NA 304 50 86 440 848 7,515 311

2000 9 459 468 145 645 92 102 839 899 8,068 553

2001 -429 -280 -709 -102 717 138 142 997 870 7,588 -480

2002 42 31 73 54 612 48 78 738 864 7,589 1

2003 -338 -161 -499 30 629 35 72 736 784 7,072 -517

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. c

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

d

Proved reserves = Col. 10 from prior year + Col. 3 + 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 2003 annual reports, DOE/EIA-0216.{3-26}
Energy Information Administration

D-24 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2003

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

2000 419 381 38 234 185 55.8

2001 459 417 42 286 173 62.2

2002 451 395 57 288 163 63.9

2003 485 426 59 336 149 69.3

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

2000 3,174 2,751 423 2,021 1,153 63.7

2001 4,288 3,877 411 3,208 1,080 74.8

2002 4,444 4,088 356 3,372 1,072 75.9

2003 4,554 4,251 303 3,627 927 79.6

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

2000 4,901 3,747 1,154 1,196 3,705 24.4

2001 5,027 3,843 1,184 1,367 3,660 27.2

2002 4,544 3,541 1,003 1,365 3,180 30.0

2003 4,397 3,330 1,067 1,545 2,852 35.1

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

2000 26,891 20,466 6,425 8,731 18,160 32.5

2001 27,100 20,290 6,810 11,229 15,871 41.4

2002 25,347 19,113 6,234 10,540 14,807 41.6

2003 22,522 17,168 5,354 10,041 12,481 44.6
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report D-25

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2003

(continued)

Gulf of Mexico Depth

Greater than Less than Deepwater

Year Total Louisianaa Texas 200 meters 200 meters Percentage

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

2000 199 164 35 84 115 42.2

2001 192 147 45 96 96 50.0

2002 184 149 35 66 118 36.0

2003 148 120 28 55 93 37.2

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

2000 1,074 921 153 468 606 43.6

2001 967 785 182 443 524 45.8

2002 965 783 182 407 558 42.2

2003 717 598 119 262 455 36.5

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

Production

1992 4,508 3,233 1,275 162 4,346 3.6

1993 4,577 3,319 1,258 224 4,353 4.9

1994 4,725 3,440 1,285 288 4,437 6.1

1995 4,627 3,376 1,251 361 4,266 7.8

1996 4,991 3,706 1,285 544 4,447 10.9

1997 5,133 3,895 1,238 565 4,568 11.0

1998 4,872 3,728 1,144 711 4,161 14.6

1999 4,885 3,721 1,164 1,099 3,786 22.5

2000 4,773 3,626 1,147 1,165 3,608 24.4

2001 4,913 3,735 1,178 1,334 3,578 27.4

2002 4,423 3,427 996 1,328 3,095 30.0

2003 4,306 3,244 1,062 1,513 2,793 35.1

Reserves

1992 26,649 19,653 6,996 3,225 23,424 12.1

1993 26,044 19,383 6,661 3,438 22,606 13.2

1994 27,218 20,835 6,383 4,709 22,509 17.3

1995 27,917 21,392 6,525 5,751 22,166 20.6

1996 27,852 21,856 5,996 6,322 21,530 22.7

1997 27,922 21,934 5,988 7,343 20,579 26.3

1998 26,422 20,774 5,648 7,425 18,997 28.1

1999 25,451 19,598 5,853 7,533 17,918 29.6

2000 26,172 19,788 6,384 8,506 17,666 32.5

2001 26,456 19,721 6,735 10,943 15,513 41.4

2002 24,689 18,500 6,189 10,266 14,423 41.6

2003 22,059 16,728 5,331 9,835 12,224 44.6
Energy Information Administration

D-26 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2003

(continued)

Gulf of Mexico Depth

Greater than Less than Deepwater

Year Total Louisianaa Texas 200 meters 200 meters Percentage

Lease Condensate (million barrels of 42 U.S. gallons)

Production

1992 44 35 9 2 42 4.4

1993 46 35 11 3 43 6.2

1994 47 37 10 3 44 6.1

1995 49 40 9 7 42 14.1

1996 60 49 11 8 52 12.9

1997 70 59 11 8 62 12.1

1998 72 57 15 13 59 18.7

1999 87 61 26 27 60 30.5

2000 106 76 30 45 61 42.2

2001 101 60 41 51 50 50.2

2002 90 60 30 38 52 42.2

2003 78 53 25 30 48 38.5

Reserves

1992 310 226 84 48 262 15.4

1993 316 235 81 51 265 16.0

1994 311 233 78 57 254 18.2

1995 412 305 107 192 220 46.7

1996 527 422 105 210 317 39.8

1997 527 433 94 203 324 38.5

1998 557 435 122 234 323 42.1

1999 567 430 137 234 333 41.3

2000 560 433 127 244 316 43.6

2001 482 325 157 221 261 45.8

2002 454 300 154 195 259 43.0

2003 353 251 102 135 218 38.2

aIncludes Federal Offshore Alabama.

Source: Based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves.”
Table D10. 2003 Reported Proved Nonproducing Reserves of 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 734 0 691 25 716

Lower 48 States .......................... 4,846 399 42,474 5,878 48,352

Alabama. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 3 284 2 286

Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 0 243 10 253

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 313 0 246 130 376

Coastal Region Onshore. . . . . . . . . . . . . . . . . . 61 0 0 29 29

Los Angeles Basin Onshore . . . . . . . . . . . . . . . 117 0 0 67 67

San Joaquin Basin Onshore . . . . . . . . . . . . . . . 110 0 246 18 264

State Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . 25 0 0 16 16

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 29 3,411 534 3,945

Florida .................................. 6 0 0 0 0

Kansas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 0 139 6 145

Kentucky . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 0 111 0 111

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 190 31 3,649 278 3,927

North . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 5 2,072 64 2,136

South Onshore . . . . . . . . . . . . . . . . . . . . . . . . . 150 23 1,384 184 1,568

State Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . 26 3 193 30 223

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 0 633 30 663

Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 0 92 11 103

Montana. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 0 175 31 206

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133 8 3,745 140 3,885

East. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133 3 563 140 703

West . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 5 3,182 0 3,182

New York . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 50 0 50

North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47 1 16 18 34

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 0 98 14 112

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92 28 3,537 121 3,658

Pennsylvania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0 274 59 333

Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 613 89 10,869 734 11,603

RRC District 1 . . . . . . . . . . . . . . . . . . . . . . . . . . 14 2 284 9 293

RRC District 2 Onshore . . . . . . . . . . . . . . . . . . 12 1 496 17 513

RRC District 3 Onshore . . . . . . . . . . . . . . . . . . 37 18 791 90 881

RRC District 4 Onshore . . . . . . . . . . . . . . . . . . 7 27 2,869 44 2,913

RRC District 5 .......................... 2 2 1,939 21 1,960

RRC District 6 . . . . . . . . . . . . . . . . . . . . . . . . . . 16 9 1,411 15 1,426

RRC District 7B. . . . . . . . . . . . . . . . . . . . . . . . . 5 0 29 3 32

RRC District 7C. . . . . . . . . . . . . . . . . . . . . . . . . 12 5 697 69 766

RRC District 8 . . . . . . . . . . . . . . . . . . . . . . . . . . 165 1 599 153 752

RRC District 8A. . . . . . . . . . . . . . . . . . . . . . . . . 319 0 19 265 284

RRC District 9 . . . . . . . . . . . . . . . . . . . . . . . . . . 16 3 1,050 15 1,065

RRC District 10 . . . . . . . . . . . . . . . . . . . . . . . . . 6 21 550 32 582

State Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . 2 0 135 1 136

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 2 840 143 983

Virginia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 743 0 743

West Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 295 0 295

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 37 5,361 20 5,381

Federal Offshoreb ......................... 3,041 171 7,624 3,596 11,220

Pacific (California). . . . . . . . . . . . . . . . . . . . . . . 93 8 51 130 181

Gulf of Mexico (Louisiana)b

................ 2,801 118 5,329 3,091 8,420

Gulf of Mexico (Texas) . . . . . . . . . . . . . . . . . . . 147 45 2,244 375 2,619

Miscellaneousc

. . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 0 39 1 40

U.S. Total ........................... 5,580 399 43,165 5,903 49,068

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," 2002.

Energy Information Administration D-27

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 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 2003 by crude oil or

natural gas well operators who were active as of

December 31, 2003. 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 1996 and 2003, and depicts

the number of active operators, with 1997 showing the

largest in the series. The 2003 sampling frame consisted

of 164 Category I, 512 Category II, 399 Category III

Certainty, and 19,848 Category III Noncertainty

operators, for a total of 20,923 active operators. The

survey sample consisted of 1,075 operators selected

with certainty that included all of the Category I and II

Certainty operators, the 399 smaller operators that

were selected with certainty because of their size in

relation to the area or areas in which they operated, and

479 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 2003 survey is

summarized in Table E2. EIA makes a considerable

effort to gain responses from all operators. About 3.5

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 55 nonoperators, 15 had successor operators that

had taken over the production of the nonoperator.

These successor operators were subsequently sampled.

The overall response rate for the 2003 survey was 96

percent. For the 61 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 2003 Annual Report E-1
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

Energy Information Administration

E-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table E1. Comparison of the EIA-23 Sample and Sampling Frame, 1996-2003

Number of Operators

Operator Category 1996 1997 1998 1999 2000 2001 2002` 2003

Certainty

Category I. . . . . . . . . . . . . 176 180 178 177 175 179 176 164

Category II . . . . . . . . . . . . 486 461 420 399 436 485 480 512

Category III............ 3 1,194 862 648 854 559 388 399

Sampled . . . . . . . . . . . . . 665 1,835 1,460 1,224 1,465 1,223 1,044 1,075

Percent Sampled . . . . . . . 100 100 100 100 100 100 100 100

Noncertainty

Sampled .............. 0 1,645 1,459 1,305 1,311 644 533 479

Percent Sampled ....... 0 8 7 6 6 3 3 2

Total

Active Operators........ 23,410 22,678 23,620 22,089 22,102 22,519 22,823 20,923

Not Sampled .......... 22,745 19,198 20,701 19,560 19,326 20,652 21,246 19,369

Sampled . . . . . . . . . . . . . . 665 3,480 2,919 R2,529 2,776 1,867 1,577 1,554

Percent Sampled . . . . . . . 3 15 12 R11 13 8 7 7

R=Revised data.

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

Table E2. Form EIA-23 Survey Response Statistics, 2003

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 . . . . . . . 164 0 10 -7 167 167 100.0 0 0.0

Category II . . . . . . . 512 15 -39 -23 465 459 98.7 6 1.3

Category III . . . . . . . 399 0 38 -12 425 401 94.4 e

24 5.6

Subtotal......... 1,075 15 9 -42 1,057 1,027 97.2 e

30 2.8

Noncertainty . . . . . . . . 479 0 -9 -13 457 426 93.2 e

31 6.8

Total ............ 1,554 15 0 -55 1,514 1,453 96.0 e

61 4.0

aSuccessor operators are those, not initially sampled, that have taken over the production of a sampled operator.

bNet of recategorized operators in the sample (excluding nonoperators).

c

Includes former operators reporting that they were not operators during the report year and operators that could not be located who are treated as nonoperators. dAdjusted sample equals original sample plus successor operators plus net category changes minus nonoperators.

eFor the 61 operators (24 Category III operators and 6 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” 2003.
report year, revision increases and revision decreases,

sales and acquisitions, extensions, new field

discoveries, new reservoirs in old fields, production,

indicated additional reserves of crude oil,

nonproducing reserves, field discovery year, water

depth, and field location information.

Category II operators who did not have reserves

estimates were required to file the field location

information and report year production for the four

hydrocarbon types from properties where reserves

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 2003, in January of 2004, was the 22nd

annual report and reflected data collected through

November 2003. This list was made available to

operators to assist in identifying the field code data

necessary for the preparation of Form EIA-23.

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 2003, Form EIA-23 National estimates of

production were 2,067 million barrels for crude oil and

lease condensate or 7 million barrels (less than 1

percent) lower than that reported in the Petroleum

Supply Annual 2003 for crude oil and lease condensate

(2,074 million barrels). Form EIA-23 National estimates

of production for dry natural gas were 19,425 billion

cubic feet, 357 billion cubic feet (less than 2 percent)

higher than the Natural Gas Monthly, September 2004 for

2003 dry natural gas production (19,068 billion cubic

feet).

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 in conjunction

with State production records and commercial

information data bases to update possible crude oil and

natural gas well operators presently listed on EIA’s

master frame and add new operators to the master

frame. This procedure identifies active operators and

nonoperators which improves the frame for future

sample selections for the annual 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 2003 survey mailing. These changes

resulted from all frame maintenance activities.

The Form EIA-23 operator frame contained a total of

68,616 entries as of December 14, 2003. Of these, 20,923

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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report E-3
operators (including both definite and probable

nonoperators) exist as a pool of names and addresses

that may be added to the active list if review indicates

activity.

Form EIA-64A Survey Design

The data for this report are also collected on Form

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

Liquids Production.” This section provides

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, 2003. In

addition, plant operators whose plants were shut down

or dismantled during 2002 were required to complete

forms for the portion of 2002 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

209 operators of 504 plants were sent forms. This

number included 2 new plants, 1 reactivated plants,

and 7 successor plants identified after the initial 2003

survey mailing. A total of 26 plants were reported as

nonoperating according to the Form EIA-64A

Energy Information Administration

E-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table E3. Summary of the 2003 Operator Frame

Activity, Form EIA-23

Total 2002 Operator Frame ............. 68,616

Operators....................... 22,823

Nonoperators.................... 45,793

Changes to 2002 Operator Status ...... 2,824

From Nonoperator to Operatora . . . . . 503

From Operator to Nonoperator ...... 2,321

No Changes to 2002 Operator Status . . . 65,792

Operators....................... 20,502

Nonoperators.................... 45,290

Additions to 2002 Operator Frame ..... 0

Operator ....................... 0

Nonoperator..................... 0

Total 2003 Operator Frame ............ 68,616

Operators....................... 20,923

Nonoperators.................... 47,693

a

Includes operator frame activity through December 14, 2003.

b

Relatively few additions were made since EIA ID numbers are now being recycled when no useable data is available with a

specific EIA ID number. This procedure will increase the number of

Nonoperator to Operator changes more than usual.

Source: Energy Information Administration, Office of Oil and Gas.
definition. For the 16th 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

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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report E-5

Figure E1. Natural Gas Liquids Extraction Flows

Source: Energy Information Administration, Office of Oil and Gas.
revisions to EIA’s monthly estimates. Differences,

when found, were reconciled in both sources. For 2003,

the Form EIA-64A National estimates were less than 1

percent (5 million barrels) lower than the Petroleum

Supply Annual 2003 volume for natural gas plant

liquids production.

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 2003 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 January 31, 2004.

Energy Information Administration

E-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table E5. Form EIA-64A 2003 Plant Frame Activity

Frame as of 2002 survey mailing . . . . . . . 515

Additions . . . . . . . . . . . . . . . . . . . 70

Deletions . . . . . . . . . . . . . . . . . . . –81

Frame as of 2003 survey mailing . . . . . . . 504

Note: Includes operator frame activity through February 15, 2004.

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

Table E4. Natural Gas Processed and Liquids Extracted at Natural Gas Processing Plants, 2003

Volume of Natural Gas Delivered to Processing Plants

State Federal Out of State Natural Gas Total Liquids

Plant Location Production Production Production Processed Extracted

(million cubic feet) (thousand barrels)

Alaska .................. 2,447,017 2,447,017 28,025

Alabama................. 38,437 197,484 1,456 237,377 7,994

Arkansas ................ 13,725 13,725 236

California ................ 237,778 965 238,743 10,598

Colorado ................ 555,544 555,544 23,982

Florida .................. 3,504 2,267 5,771 796

Kansas.................. 405,697 125,241 530,938 24,311

Kentucky ................ 42,758 42,758 1,304

Louisiana ................ 1,269,356 2,122,514 3,391,870 88,732

Michigan ................ 41,619 41,619 2,818

Mississippi ............... 2,150 281,525 283,675 8,431

Montana................. 6,263 6,263 491

North Dakota ............. 58,479 58,479 4,448

New Mexico .............. 987,762 987,762 76,393

Oklahoma ............... 802,437 1,592 804,029 53,116

Texas ................... 3,607,239 51,690 3,658,929 233,252

Utah . . . . . . . . . . . . . . . . . . . . 157,082 4,193 161,275 2,532

West Virginia ............. 86,012 30,749 116,761 5,220

Wyoming ................ 1,071,066 30,359 1,101,425 49,034

Miscellanousa ............ 13,356 13,356 578

Total . . . . . . . . . . . . . . . . . . . 11,847,281 2,602,488 247,547 14,697,316 622,291

aIncludes Illinois, Ohio, and Pennsylvania.

Source: Form EIA-64A, “Annual Report of the Origin of Natural Gas Liquids Production,” 2003
Appendix F

Statistical Considerations
Appendix F

Statistical Considerations

Sampling Plan

The goal was a sample that would provide estimates of

reserves and production of crude oil, natural gas, and

lease condensate for the United States. A stratified

sample using a single stage and systematic selection

with probability proportional to size was designed. The

measure of size was the volume of production for crude

oil, natural gas, and lease condensate by State by

company in 2002. There were two strata: companies

selected with certainty and companies selected under

the systematic probability proportional to size design.

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. EIA conducts extensive frame maintenance

activities each year to identify all current operators of

crude oil and natural gas wells in the country. 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.

Sample Design

To mee t survey objec tives, while minimizing

respondent burden, a sampling strategy has been used

since 1977. EIA publishes data on reserves and

production for crude oil, natural gas, and lease

condensate by State for most States, and by subdivision

for the States of California, Louisiana, New Mexico,

and Texas.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

2002 survey for each product class.

Each operator is asked to report production and

reserves 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.

EIA selected the following target sampling error for the

2003 survey for each product class.

 1.0 percent for National estimates and for each

of the States having subdivisions: Alaska,

California, Louisiana, New Mexico, and Texas.

 2.5 percent for each State having 1 percent or

more of estimated lower 48 States reserves or

production in 2002 for any product class.

 4 percent for each State/subdivision having less

than 1 percent of estimated U.S. reserves or

production in 2002 (lower 48 States) for all 3

product class.

 8 percent for States not published separately.

Certainty Stratum

There are three components to the certainty stratum

Category I, Category II, and certain Category III Small

Operators.

 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 2002.

 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

2002, and additionally, all coalbed methane and

Federal Offshore operators.

 Category III - Small Operators: Operators who

produced less than the Category II operators in

2002.

Small operators were further subdivided into certainty

and noncertainty strata. Small operators who satisfied

any of the following criteria based upon their

production shown in the operator frame are certainty

operators:

 All other operators with production or reserves

in a State/subdivision that exceed selected

cutoff levels.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report F-1
Table F1. 2003 EIA–23 Initial Number of Operators in Survey Sample

Number of Number of Number of

Certainty Multi–State Noncertainty Target Error

State and Subdivision Operators Operators Operators Oil Gas

Alabama Onshore 49 1 2 0.040 0.025

Alaska 8 0 0 0.000 0.000

Arkansas 77 7 8 0.040 0.025

California - Coastal Region Onshore 15 0 0 0.080 0.080

California - Los Angeles Basin Onshore 17 0 0 0.010 0.010

California - San Joaquin Basin Onshore 44 0 0 0.025 0.040

Colorado 117 14 1 0.025 0.010

Florida - Onshore 6 0 0 0.025 0.025

Illinois 33 37 25 0.040 0.040

Indiana 22 30 2 0.040 0.080

Kansas 181 54 57 0.040 0.080

Kentucky 29 21 19 0.025 0.010

Louisiana-North 132 6 0 0.040 0.040

Louisiana-South Onshore 202 1 0 0.010 0.010

Michigan 45 4 15 0.010 0.010

Mississippi - Onshore 90 2 2 0.040 0.040

Montana 69 8 2 0.040 0.040

Nebraska 26 14 2 0.040 0.040

New Mexico - East 169 2 0 0.040 0.080

New Mexico - West 61 0 0 0.025 0.025

New York 22 9 9 0.025 0.010

North Dakota 73 7 0 0.080 0.040

Ohio 52 9 52 0.040 0.040

Oklahoma 265 54 43 0.040 0.040

Pennsylvania 62 20 29 0.025 0.025

Texas - RRC District 1 162 0 0 0.040 0.040

Texas - RRC District 2 Onshore 192 1 0 0.025 0.025

Texas - RRC District 3 Onshore 265 1 0 0.040 0.025

Texas - RRC District 4 Onshore 213 0 0 0.025 0.025

Texas - RRC District 5 109 2 0 0.040 0.010

Texas - RRC District 6 178 4 0 0.040 0.010

Texas - RRC District 7B 163 3 0 0.025 0.010

Texas - RRC District 7C 170 4 0 0.025 0.025

Texas - RRC District 8 218 4 0 0.040 0.025

Texas - RRC District 8A 197 6 0 0.010 0.010

Texas - RRC District 9 167 4 0 0.010 0.040

Texas - RRC District 10 154 13 0 0.025 0.025

Utah 59 1 2 0.040 0.010

Virginia 19 0 0 0.040 0.025

West Virginia 56 11 54 0.080 0.040

Wyoming 163 10 3 0.040 0.025

Offshore Areas 313 0 0 0.025 0.025

Other Statesa 52 2 2 0.080 0.080

Total b1,069 151b 329 0.010 0.010

aIncludes Arizona, Idaho, Iowa, Maryland, Missouri, Nevada, Oregon, South Dakota, Tennessee, and Washington.

bNonduplicative count of operators by States.

Note: Sampling rate was 7 percent except in Alaska, Florida Onshore, Virginia, and Offshore areas where sampling rate was 100 percent.

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

Energy Information Administration

F-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
 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.

Noncertainty Stratum

Small operators not in the certainty stratum were

classified in the noncertainty stratum. They were

systematically sampled with probability proportional

to size. Only the operators in the following 10 states

were included in the noncertainty sample: Illinois,

Indiana, Kentucky, Maryland, New York, Ohio,

Pennsylvania, Tennessee, Virginia, and West Virginia.

All other States were treated as certainty stratum.

In each State/subdivision the balance between the

number of 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.

Independent samples of single location operators

(operators who, according to the sampling frame,

operate in only one State/subdivision) were selected

from each State/subdivision using systematic random

sampling.

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 and

for the U.S. Total. Table F1 shows sampling rates.

Total U.S. Reserve Estimates

Conceptually, the estimates of U.S. reserves and

production can be thought of as the sum of the

estimates for the individual States. Correspondingly,

the estimates for the four States for which estimates are

published separately by subdivision (California,

Louisiana, New Mexico, and Texas) can be thought of

as the sum of the estimates by subdivision. The

remaining States are not subdivided and may be

considered as a single subdivision.

The estimates of year-end proved reserves and annual

production for any State/subdivision is the sum of the

volumes in the State/subdivision reported by the

certainty stratum operators and an estimate of the total

volume in the State/subdivision by the noncertainty

stratum operators. The total volume of certainty

operators in the State/subdivision is simply the sum of

individual operator's volumes. The estimated total

volume of noncertainty operators in the

State/subdivision is the weighted sum of the reports of

the noncertainty sample operators.

In many State/subdivisions, the accuracy of the oil and

gas estimates was improved by using the probability

proportional to size procedure. This procedure took

advantage of the correlation between year-to-year

production reports. The weights used for estimating

the oil production 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.

The nonresponse rate for certainty operators for the

2002 survey was 0.1 percent and for the noncertainty

operators 0.4 percent. An imputation was made for the

production and reserves for these 3 nonresponding

operators.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report F-3
Imputation and Estimation for

Reserves Data

There were 457 operators sampled proportional to size

(Table E1) that responded as Category III noncertainty

operators. Only 241 of these, located in 10 states, had

their data weighted and used to estimate the

production and reserves of the operators that were not

sampled in those states. The remaining 216

noncertainty sampled operators were treated as

certainty sampled operators with a weight of 1 and

were used in states where the bulk of the operator

production data was obtained from auxiliary State

data.

The data reported by operator category on Form

EIA-23 and data imputed and estimated for report year

2002 are summarized in Tables F2, F3, F4, and F5. The

reported data in Table F2 shows that those responding

operators accounted for 99.9 percent of the published

production for wet natural gas and 95.2 percent of the

reserves shown in Table 9. Data shown in Table F3

indicate that those responding operators accounted for

99.9 percent of the nonassociated natural gas

production and 95.3 percent of the reserves published

in Table 10. The reported data shown in Table F4

indicate that those responding operators accounted for

99.6 percent of published crude oil production and 94.9

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 95.8 percent of the published proved reserves for

lease condensate shown in Table 15.

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).

 Imputation was required for the natural gas

data of the small operators to estimate their

volumes of associated-dissolved and

nonassociated natural gas.

 Adjustments to maintain reserves balance.

Methods used are discussed in the following sections.

Imputation of Year-End Proved Reserves

Category I operators were required to submit year-end

estimates of proved reserves. Category II and Category

III operators were required to provide year-end

estimates of proved reserves only if such estimates

existed in their records. Some of these respondents

provided estimates for all of their operated properties,

others provided estimates for only a portion of their

properties, and still others provided no estimates for

any of their properties. All respondents did, however,

provide annual production data.

A year-end proved reserves estimate was imputed

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 P/[P+R] = Beta * EXP(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 2003 production.

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 production plus end of year

reserves equal to zero were excluded from the

respondents selected to calculate the R/P coefficients.

In 2003, rather than rely on a weighted sample, the R/P

function was used to estimate the proved reserves of all

noncertainty operators in these States: Texas,

California, Colorado, Louisiana, Montana, New

Mexico, South Dakota, Utah, and Wyoming. These

States were chosen for this new procedure because of

the many years of historical production and reserves

data within EIA and availability of reliable State

government and commercial production data for these

States. This technique improved the correlation of EIA

data with State and commercial production data, and

Energy Information Administration

F-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report F-5

Table F2. Summary of Form EIA-23 Reported, Imputed, and Estimated Natural Gas Data for 2003,

Wet after Lease Separation (Million Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

Operator Category

Certainty Noncertainty Auxillary

Level of Reporting I II III III State Data Total

Reported

Number of Operators . . . . . . . . . . . . . . . 167 459 619 a

241 11,863 13,349

Proved Reserves as of 12/31/02 ...... 174,296,369 12,083,346 482,534 - - 186,862,249

(+) Revision Increases ............. 18,369,471 1,279,727 44,746 - - 19,693,944

(–) Revision Decreases ............ 19,893,218 1,180,431 181,383 - - 21,255,032

(–) Sales ........................ 8,675,864 1,803,025 114,677 - - 10,593,566

(+) Acquisitions................... 9,901,446 1,783,322 15,660 - - 11,700,428

(+) Extensions ................... 14,245,260 2,068,650 59,150 - - 16,373,060

(+) New Field Discoveries .......... 996,642 232,106 0 - - 1,228,748

(+) New Reservoirs in Old Fields ..... 1,347,733 256,998 0 - - 1,604,731

(–) Production With

Proved Reserves Reported....... 17,348,450 1,291,857 94,789 5,559 - 18,740,655

(–) Production Without

Proved Reserves Reported. . . . . . . 259 559,120 195,854 27,468 692,047 1,474,748

Proved Reserves as of 12/31/03 ...... 173,239,389 13,461,704 970,053 98,177 0 187,769,323

Imputed and Estimated

Number of Operators ............... - - - 7,574 - 7,574

Proved Reserves as of 12/31/02 ...... - - - - - -

(+) Revision Increases ............. 0 442,073 183,596 37,299 423,488 1,086,456

(–) Revision Decreases ............ 0 554,079 188,736 31,733 465,231 1,239,779

(–) Sales ........................ 0 0 0 0 0 0

(+) Acquisitions................... 0 0 0 0 0 0

(+) Extensions ................... 0 300,625 125,874 20,296 374,922 821,717

(+) New Field Discoveries .......... 0 10,109 4,815 1,336 7,096 23,357

(+) New Reservoirs in Old Fields ..... 0 18,635 5,090 347 23,787 47,859

(–) Production With

Proved Reserves Reported....... 0 0 0 1,785 - 1,785

(–) Production Without

Proved Reserves Reported....... 0 0 0 14,252 - 14,252

Proved Reserves as of 12/31/03 ...... 0 3,988,665 1,643,570 453,026 3,290,750 9,376,010

Total

Number of Operators . . . . . . . . . . . . . . . 167 459 619 7,815 11,863 20,923

Proved Reserves as of 12/31/02 ...... 174,296,369 12,083,346 482,534 0 0 186,862,249

(+) Revision Increases ............. 18,369,471 1,721,800 228,342 37,299 423,488 20,780,400

(–) Revision Decreases ............ 19,893,218 1,734,510 370,119 31,733 465,231 22,494,811

(–) Sales ........................ 8,675,864 1,803,025 114,677 0 0 10,593,566

(+) Acquisitions................... 9,901,446 1,783,322 15,660 0 0 11,700,428

(+) Extensions ................... 14,245,260 2,369,275 185,024 20,296 374,922 17,194,777

(+) New Field Discoveries .......... 996,642 242,215 4,815 1,336 7,096 1,252,105

(+) New Reservoirs in Old Fields ..... 1,347,733 275,633 5,090 347 23,787 1,652,590

(–) Production With

Proved Reserves Reported....... 17,348,450 1,291,857 94,789 7,344 0 18,742,440

(–) Production Without

Proved Reserves Reported. . . . . . . 259 559,120 195,854 41,720 692,047 1,489,000

Proved Reserves as of 12/31/03 ...... 173,239,389 17,450,369 2,613,623 551,203 3,290,750 197,145,333

Summary

Total Number of Operators . . . . . . . . . 167 459 619 7,815 11,863 20,923

Percent of Total .................. 0.8% 2.2% 2.8% 37.4% 56.9% 100.0%

Total Production in 2003 ........... 17,348,709 1,850,977 290,643 49,064 692,047 20,231,440

Percent of Total .................. 85.8% 9.1% 1.4% 0.2% 3.4% 100.0%

Total Proved Reserves 12/31/03 ..... 173,239,389 17,450,369 2,613,623 551,203 3,290,750 197,145,333

Percent of Total .................. 87.9% 8.9% 1.3% 0.3% 1.7% 100.0%

aThere were 457 noncertainty responses, 241 were used with their sample weights and 216 were treated as Certainty III operators.

– = 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,” 2003.
Energy Information Administration

F-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table F3. Summary of Form EIA-23 Reported, Imputed, and Estimated Nonassociated Natural Gas Data

for 2003, Wet after Lease Separation (Million Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

Operator Category

Certainty Noncertainty Auxillary

Level of Reporting I II III III State Data Total

Reported

Number of Operators . . . . . . . . . . . . . . . 167 459 619 a

241 11,863 13,349

Proved Reserves as of 12/31/02 ...... 147,855,953 10,445,583 462,862 - - 158,764,398

(+) Revision Increases ............. 15,801,437 1,028,659 43,903 - - 16,873,999

(–) Revision Decreases ............ 17,564,243 923,524 174,979 - - 18,662,746

(–) Sales ........................ 7,720,801 1,719,224 111,942 - - 9,551,967

(+) Acquisitions................... 8,956,366 1,682,644 0 - - 10,639,010

(+) Extensions ................... 13,618,926 1,951,679 57,519 - - 15,628,124

(+) New Field Discoveries .......... 552,045 228,992 0 - - 781,037

(+) New Reservoirs in Old Fields ..... 1,230,548 250,867 0 - - 1,481,415

(–) Production With

Proved Reserves Reported....... 14,911,813 1,128,912 83,949 5,409 - 16,130,083

(–) Production Without

Proved Reserves Reported. . . . . . . 119 494,371 176,856 26,154 531,288 1,228,788

Proved Reserves as of 12/31/03 ...... 147,818,418 11,847,691 883,044 96,768 0 160,645,921

Imputed and Estimated

Number of Operators ............... - - - 7,574 - 7,574

Proved Reserves as of 12/31/02 ...... - - - - - -

(+) Revision Increases ............. 0 368,184 157,781 31,778 304,658 862,401

(–) Revision Decreases ............ 0 487,943 168,553 27,268 358,614 1,042,379

(–) Sales . . . . . . . . . . . . . . . . . . . . . . . . 0 280 70 1 192 543

(+) Acquisitions................... 0 0 0 0 0 0

(+) Extensions ................... 0 286,962 126,502 20,507 316,306 750,276

(+) New Field Discoveries .......... 0 10,744 5,355 1,480 6,868 24,448

(+) New Reservoirs in Old Fields ..... 0 26,832 7,380 504 31,868 66,585

(–) Production With

Proved Reserves Reported....... 0 0 0 2,917 - 2,917

(–) Production Without

Proved Reserves Reported....... 0 0 0 14,262 - 14,262

Proved Reserves as of 12/31/03 ...... 0 3,533,735 1,486,047 411,345 2,515,613 7,946,739

Total

Number of Operators . . . . . . . . . . . . . . . 167 459 619 7,815 11,863 20,923

Proved Reserves as of 12/31/02 ...... 147,855,953 10,445,583 462,862 0 0 158,764,398

(+) Revision Increases ............. 15,801,437 1,396,843 201,684 31,778 304,658 17,736,400

(–) Revision Decreases ............ 17,564,243 1,411,467 343,532 27,268 358,614 19,705,125

(–) Sales ........................ 7,720,801 1,719,504 112,012 1 192 9,552,510

(+) Acquisitions................... 8,956,366 1,682,644 0 0 0 10,639,010

(+) Extensions ................... 13,618,926 2,238,641 184,021 20,507 316,306 16,378,400

(+) New Field Discoveries .......... 552,045 239,736 5,355 1,480 6,868 805,485

(+) New Reservoirs in Old Fields ..... 1,230,548 277,699 7,380 504 31,868 1,548,000

(–) Production With

Proved Reserves Reported....... 14,911,813 1,128,912 83,949 8,326 0 16,133,000

(–) Production Without

Proved Reserves Reported. . . . . . . 119 494,371 176,856 40,416 531,288 1,243,050

Proved Reserves as of 12/31/03 ...... 147,818,418 15,381,426 2,369,091 508,113 2,515,613 168,592,660

Summary

Total Number of Operators . . . . . . . . . 167 459 619 7,815 11,863 20,923

Percent of Total .................. 0.8% 2.2% 2.8% 37.4% 56.9% 100.0%

Total Production in 2003 ........... 14,911,932 1,623,283 260,805 48,742 531,288 17,376,050

Percent of Total .................. 85.8% 9.3% 1.5% 0.3% 3.1% 100.0%

Total Proved Reserves 12/31/03 ..... 147,818,418 15,381,426 2,369,091 508,113 2,515,613 168,592,660

Percent of Total .................. 87.7% 9.1% 1.4% 0.3% 1.5% 100.0%

aThere were 457 noncertainty responses, 241 were used with their sample weights and 216 were treated as Certainty III operators.

– = 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,” 2003.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report F-7

Table F4. Summary of Form EIA-23 Reported, Imputed, and Estimated Crude Oil Data for 2003,

(Thousand Barrels of 42 U.S. Gallons)

Operator Category

Certainty Noncertainty Auxillary

Level of Reporting I II III III State Data Total

Reported

Number of Operators . . . . . . . . . . . . . . . 167 459 619 a

241 11,863 13,349

Proved Reserves as of 12/31/02 ...... 20,310,374 1,027,391 21,913 - - 21,359,678

(+) Revision Increases ............. 1,230,638 129,215 1,254 - - 1,361,107

(–) Revision Decreases ............ 1,198,147 103,847 1,986 - - 1,303,980

(–) Sales ........................ 1,014,470 90,032 3,369 - - 1,107,871

(+) Acquisitions................... 620,449 86,066 3,007 - - 709,522

(+) Extensions ................... 338,355 53,396 2,776 - - 394,527

(+) New Field Discoveries .......... 704,055 1,534 0 - - 705,589

(+) New Reservoirs in Old Fields ..... 92,235 9,897 0 - - 102,132

(–) Production With

Proved Reserves Reported....... 1,575,292 95,209 18,854 492 - 1,689,847

(–) Production Without

Proved Reserves Reported. . . . . . . 53 38,402 40,237 3,052 102,700 184,444

Proved Reserves as of 12/31/03 ...... 19,508,197 1,019,615 186,814 5,289 0 20,719,915

Imputed and Estimated

Number of Operators ............... - - - 7,574 - 7,574

Proved Reserves as of 12/31/02 ...... - - - - - -

(+) Revision Increases ............. 3 32,995 31,905 2,513 57,708 125,124

(–) Revision Decreases ............ 3 23,813 27,032 4,345 33,271 88,463

(–) Sales ........................ 0 0 0 0 0 0

(+) Acquisitions................... 0 0 0 0 0 0

(+) Extensions ................... 1 7,558 7,067 226 16,733 31,584

(+) New Field Discoveries . . . . . . . . . . 0 8 1 0 2 11

(+) New Reservoirs in Old Fields . . . . . 0 22 26 0 53 101

(–)Production With

Proved Reserves Reported. . . . . . . 0 0 0 152 - 152

(–) Production Without

Proved Reserves Reported....... 0 0 0 2,400 - 2,400

Proved Reserves as of 12/31/03 . . . . . . 30 300,085 299,303 32,766 539,345 1,171,529

Total

Number of Operators . . . . . . . . . . . . . . . 167 459 619 7,815 11,863 20,923

Proved Reserves as of 12/31/02 ...... 20,310,374 1,027,391 21,913 0 0 21,359,678

(+) Revision Increases ............. 1,230,641 162,210 33,159 2,513 57,708 1,486,231

(–) Revision Decreases ............ 1,198,150 127,660 29,018 4,345 33,271 1,392,443

(–) Sales ........................ 1,014,470 90,032 3,369 0 0 1,107,871

(+) Acquisitions................... 620,449 86,066 3,007 0 0 709,522

(+) Extensions ................... 338,356 60,954 9,843 226 16,733 426,111

(+) New Field Discoveries .......... 704,055 1,542 1 0 2 705,600

(+) New Reservoirs in Old Fields ..... 92,235 9,919 26 0 53 102,233

(–) Production With

Proved Reserves Reported....... 1,575,292 95,209 18,854 644 0 1,689,999

(–) Production Without

Proved Reserves Reported. . . . . . . 53 38,402 40,237 5,452 102,700 186,844

Proved Reserves as of 12/31/03 ...... 19,508,227 1,319,700 486,117 38,055 539,345 21,891,444

Summary

Total Number of Operators . . . . . . . . . 167 459 619 7,815 11,863 20,923

Percent of Total .................. 0.8% 2.2% 2.8% 37.4% 56.9% 100.0%

Total Production in 2003 ........... 1,575,345 133,611 59,091 6,096 102,700 1,876,843

Percent of Total .................. 83.9% 7.1% 3.1% 0.3% 5.5% 100.0%

Total Proved Reserves 12/31/03 ..... 19,508,227 1,319,700 486,117 38,055 539,345 21,891,444

Percent of Total .................. 89.1% 6.0% 2.2% 0.2% 2.5% 100.0%

aThere were 457 noncertainty responses, 241 were used with their sample weights and 216 were treated as Certainty III operators.

– = 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,” 2003.
Energy Information Administration

F-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table F5. Summary of Form EIA-23 Reported, Imputed, and Estimated Lease Condensate Data for 2003,

(Thousand Barrels of 42 U.S. Gallons)

Operator Category

Certainty Noncertainty Auxillary

Level of Reporting I II III III State Data Total

Reported

Number of Operators . . . . . . . . . . . . . . . 167 459 619 a

241 11,863 13,349

Proved Reserves as of 12/31/02 ...... 1,225,384 80,418 2,583 - - 1,308,385

(+) Revision Increases ............. 218,570 26,253 792 - - 245,615

(–) Revision Decreases ............ 332,405 13,632 237 - - 346,274

(–) Sales ........................ 83,307 12,440 494 - - 96,241

(+) Acquisitions................... 69,614 12,459 0 - - 82,073

(+) Extensions ................... 86,780 12,629 10 - - 99,419

(+) New Field Discoveries .......... 7,765 4,479 0 - - 12,244

(+) New Reservoirs in Old Fields ..... 28,984 7,113 0 - - 36,097

(–) Production With

Proved Reserves Reported....... 164,671 13,649 438 5 - 178,763

(–) Production Without

Proved Reserves Reported....... 5 5,022 856 9 6,010 11,902

Proved Reserves as of 12/31/03 ...... 1,056,714 103,630 3,697 56 0 1,164,097

Imputed and Estimated

Number of Operators ............... - - - 7,574 - 7,574

Proved Reserves as of 12/31/02 ...... - - - - - -

(+) Revision Increases ............. 4 4,576 724 2 4,299 9,606

(–) Revision Decreases ............ 4 5,523 814 0 4,984 11,326

(–) Sales ........................ 0 0 0 0 0 0

(+) Acquisitions................... 0 0 0 0 0 0

(+) Extensions ................... 3 2,234 356 0 2,429 5,021

(+) New Field Discoveries . . . . . . . . . . 0 40 5 0 52 96

(+) New Reservoirs in Old Fields . . . . . 0 103 14 0 128 245

(–) Production With

Proved Reserves Reported....... 0 0 0 1 - 1

(–) Production Without

Proved Reserves Reported....... 0 0 0 4 - 4

Proved Reserves as of 12/31/03 . . . . . . 31 24,145 3,757 27 23,045 51,005

Total

Number of Operators . . . . . . . . . . . . . . . 167 459 619 7,815 11,863 20,923

Proved Reserves as of 12/31/02 ...... 1,225,384 80,418 2,583 0 0 1,308,385

(+) Revision Increases ............. 218,574 30,829 1,516 2 4,299 255,221

(–) Revision Decreases ............ 332,409 19,155 1,051 0 4,984 357,600

(–) Sales ........................ 83,307 12,440 494 0 0 96,241

(+) Acquisitions................... 69,614 12,459 0 0 0 82,073

(+) Extensions ................... 86,783 14,863 366 0 2,429 104,440

(+) New Field Discoveries .......... 7,765 4,519 5 0 52 12,340

(+) New Reservoirs in Old Fields ..... 28,984 7,216 14 0 128 36,342

(–) Production With

Proved Reserves Reported....... 164,671 13,649 438 6 0 178,764

(–) Production Without

Proved Reserves Reported....... 5 5,022 856 13 6,010 11,906

Proved Reserves as of 12/31/03 ...... 1,056,745 127,775 7,454 83 23,045 1,215,102

Summary

Total Number of Operators . . . . . . . . . 167 459 619 7,815 11,863 20,923

Percent of Total .................. 0.8% 2.2% 2.8% 37.4% 56.9% 100.0%

Total Production in 2003 ........... 164,676 18,671 19 1,294 6,010 190,670

Percent of Total .................. 86.4% 9.8% 0.0% 0.7% 3.2% 100.0%

Total Proved Reserves 12/31/03 ..... 1,056,745 127,775 83 7,454 23,045 1,215,102

Percent of Total .................. 87.0% 10.5% 0.0% 0.6% 1.9% 100.0%

aThere were 457 noncertainty responses, 241 were used with their sample weights and 216 were treated as Certainty III operators.

– = 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,” 2003.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report F-9

  		
	
 
	   	
	
 	
  
  

  	 

 


     

      
  
  


                     	 
	
 		 
		
 	 					 					

               
 
  
	
 	 
		
 		
	 
		 		

        	 
	
 		 
		
 	 					 					

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reduced the burden of reporting and analysis on both

EIA and the noncertainty operators in these States.

Imputation of 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 either:

 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, or

 applying a modified version of the R/P function

to each separate component of change,

calculated with its own set of geographically

dependent coefficients. This method was used

in all four states where the R/P Function was

applied to calculate end of year reserves.

Both methods preserved an exact annual reserves

balance of the following form:

The algebraic allocation method used for all but nine

states in the 2003 survey worked as follows: A ratio was

calculated as the sum of the annual production and

year-end proved reserves of those respondents who

did not provide the reserves balance components,

divided by the sum of year-end proved reserves and

annual production of those respondents of similar size

who did provide these quantities. This ratio was then

multiplied by each of the reserves balance components

reported by Category I and some Category II operators,

to obtain imputed volumes for the reserves balances of

the other Category II operators and certainty and

noncertainty operators. These were then added to the

State/subdivision totals.

Imputation of Natural Gas Volumes

Small operators in the 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 large and intermediate operators in the

same area.

Adjustments

The instructions for Schedule A of Form EIA-23 specify

that, when reporting reserves balance data, the

following arithmetic equation must hold:

Any remaining difference in the State/subdivision

annual reserves balance between the published

previous year-end proved reserves and current

year-end proved reserves not accounted for by the

imputed reserves changes was included in the

adjustments for the area. One of the primary reasons

that adjustments are necessary is the instability of the

noncertainty operators sampled each year. There is no

guarantee that in the smaller producing

States/subdivision the same number of small

operators will be selected each year, or that the

operators selected will be of comparable sizes when

paired with operators selected in a prior year. Thus,

some instability of this stratum from year to year is

unavoidable, resulting in minor adjustments.

Some of the adjustments are, however, more

substantial, and could be required for any one or more

of the following reasons:

 The frame coverage may or may not have

improved between survey years, such that more

Energy Information Administration

F-10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Published Proved Reserves at End of Previous Report Year

+ Adjustments

+ Revision Increases

– Revision Decreases

– Sales

+ Acquisitions

+ Extensions

+ New Field Discoveries

+ New Reservoir Discoveries in Old Fields

– Report Year Production

= Published Proved Reserves at End of Report Year

Proved Reserves at End of Previous Year

+ Revision Increases

– Revision Decreases

– Sales

+ Acquisitions

+ Extensions

+ New Field Discoveries

+ New Reservoir Discoveries in Old Fields

– Report Year Production

= Proved Reserves at End of Report Year
or fewer certainty operators were included in

2003 than in 2002.

 One or more operators may have reported data

incorrectly on Schedule A in 2003 or 2002, but

not both, and the error was not detected by edit

processing.

 Operation of properties was transferred during

2003 from operators not in the frame or

noncertainty operators not selected for the

sample to certainty operators or noncertainty

operators selected for the sample.

 Respondent changed classification of natural

gas from NA to AD or vice versa.

 The trend in reserve changes imputed for the

small operators, which was based on the trend

reported by the large operators, did not reflect

the actual trend for the small operators.

 noncertainty operators, who have grown

substantially in size since they were added to

the frame, occasionally cause a larger standard

error than expected.

 The noncertainty sample for either year in a

state may have been an unusual one.

The causes of adjustments are known for some but not

all areas. The only problems whose effects cannot be

expected to balance over a period of several years are

those associated with an inadequate frame or those

associated with any actual trend in reserves changes for

small operators not being the same as those for large

operators. EIA continues to attempt to improve sources

of operator data to resolve problems in frame

completeness.

Sampling Reliability of the Estimates

The sample of noncertainty operators selected is only

one of the large number of possible samples that could

have been selected and each would have resulted in

different estimates. The standard error or sampling

error of the estimates provides a measure of this

variability. When probability sampling methods are

used, as in the EIA-23 survey, the sampling error of

estimates can also be estimated from the survey data.

The estimated sampling error can be used to compute a

confidence interval around the survey estimate, with a

prescribed degree of confidence that the interval covers

the value that would have been obtained if all operators

in the frame had been surveyed. If the estimated

volume is denoted byV

s and its sampling error by S.E.

( - V

s ), the confidence interval can be expressed as:

 . .(  V kSE V ) s s ±

where k is a multiple selected to provide the desired

level of confidence. For this survey, k was taken equal

to 2. Then there is approximately 95 percent confidence

that the interval:

        ± 

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 and F8

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 189,044  371 billion

cubic feet. The sampling error of V

s is equal to the

sampling error of the noncertainty estimateV

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.

Sources of Errors

The EIA maintains an evaluation program to assess the

accuracy and quality of proved reserve estimates

gathered on Form EIA-23. Field teams consisting of

petroleum engineers from EIA's Reserves and

Production Division conduct technical reviews of

reserve estimates and independently estimate the

proved reserves of a selected sample of operator

properties. The results of these reviews are used to

evaluate the accuracy of reported reserve estimates.

Operators are apprized 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. Several sources of possible

error, apart from sampling error, are associated with

the Form EIA-23 survey:

 Operator nonresponse

 Respondent estimation errors

 Reporting errors and data processing errors

 Inadequate frame coverage

 Errors associated with statistical estimates.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report F-11
Imputation for Operator Nonresponse

The nonresponse rate for certainty operators for the

2003 survey was 1.3 percent and for the noncertainty

operators 6.8 percent. An imputation was made for the

production and reserves for these 6 nonresponding

operators.

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 and Data Processing Errors

Reporting errors on the part of respondents are of

definite concern in a survey of the magnitude and

complexity of the Form EIA-23 program. Several steps

were taken by EIA to minimize and detect such

problems. The survey instrument itself was carefully

developed, and included a detailed set of instructions

for filing data, subject to a common set of definitions

similar to those already used by the industry. Editing

software is continually developed to detect different

kinds of probable reporting errors and flag them for

resolution by analysts, either through confirmation of

the data by the respondent or through submission of

amendments to the filed data. Data processing errors,

consisting primarily of random keypunch errors, are

detected by the same software.

Frame Coverage Errors

Of all the sources of controllable error connected with

the Form EIA-23 survey, errors in the operator frame

were expected to be the most important. If the frame

does not list all operators in a given State, the sample

selected from the frame for the State will not represent

the entire operator population, a condition called

under coverage. Under coverage 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 2003 survey is particularly likely to be deficient in

States where a large portion of total reserves and

production is accounted for by small operators. EIA is

continuing to work to remedy the under coverage

problem in those States where it occurred.

Imputation Errors

Some error, generally expected to be small, is an

inevitable result of the various estimations outlined.

These imputation errors have not yet been completely

addressed by EIA and it is possible that estimation

methods may be altered in future surveys. Nationally,

5.4 percent of the crude oil proved reserve estimates, 4.8

percent of the wet natural gas proved reserve estimates,

and 4.2 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.

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

Energy Information Administration

F-12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
Energy Information Administration F-13

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

United States . . . . . . . . . . . . . . . . . . 14 1

Alabamab..................... 0 0

Alaskaa ...................... 0 0

Arkansasb .................... 0 0

Californiab .................... 0 0

Coastal Region Onshoreb...... 0 0

Los Angeles Basin Onshoreb ... 0 0

San Joaquin Basin Onshoreb ... 0 0

State Offshorea .............. 0 0

Coloradob .................... 0 0

Floridaa ...................... 0 0

Kansasb ...................... 0 0

Kentucky ..................... 5 0

Louisianab .................... 0 0

Northb ..................... 0 0

South Onshoreb ............. 0 0

State Offshorea .............. 0 0

Michiganb..................... 0 0

Mississippib ................... 0 0

Montanab ..................... 0 0

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

New Mexicob ................. 0 0

Eastb ...................... 0 0

Westb ..................... 0 0

North Dakotab ................. 0 0

Ohio ......................... 2 0

Oklahomab.................... 0 0

Pennsylvania .................. 0 1

Texasb ....................... 0 0

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

RRC District 2 Onshoreb....... 0 0

RRC District 3 Onshoreb....... 0 0

RRC District 4 Onshoreb....... 0 0

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

RRC District 6b .............. 0 0

RRC District 7Bb ............. 0 0

RRC District 7Cb............. 0 0

RRC District 8b .............. 0 0

RRC District 8Ab ............. 0 0

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

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

State Offshorea .............. 0 0

Utahb ........................ 0 0

Virginiaa ...................... 0 0

West Virginia .................. 1 0

Wyomingb .................... 0 0

Federal Offshorea .............. 0 0

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

Gulf of Mexico (Louisiana)a .... 0 0

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

Miscellaneousc ................ 8 0

aSampling rate was 100 percent in Alaska, Florida Onshore, Virginia, and Offshore areas. bSampling was not used. Estimates for each operator were made using an imputation function.

cIncludes 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 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,” 2003.

Table F7. Factors for Confidence Intervals (2S.E.) for Crude Oil Proved Reserves and Production, 2003

(Million Barrels of 42 U.S. Gallons)

2003 2003 2003 2003

State and Subdivision Reserves Production State and Subdivision Reserves Production

Table F8. Factors for Confidence Intervals (2S.E.) for Natural Gas Proved Reserves and Production,

Wet After Lease Separation, 2003 (Billion Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

2003 2003 2003 2003

State and Subdivision Reserves Production State and Subdivision Reserves Production

United States . . . . . . . . . . . . . . . . . . 371 28

Alabamab..................... 0 0

Alaskaa ...................... 0 0

Arkansasb .................... 0 0

Californiab .................... 0 0

Coastal Region Onshoreb...... 0 0

Los Angeles Basin Onshoreb ... 0 0

San Joaquin Basin Onshoreb ... 0 0

State Offshorea .............. 0 0

Coloradob .................... 0 0

Floridaa ...................... 0 0

Kansasb ...................... 0 0

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

Louisianab .................... 0 0

Northb ..................... 0 0

South Onshoreb ............. 0 0

State Offshorea .............. 0 0

Michiganb..................... 0 0

Mississippib ................... 0 0

Montanab ..................... 0 0

New Mexicob .................. 0 0

Eastb ...................... 0 0

Westb ..................... 0 0

New York . . . . . . . . . . . . . . . . . . . . . 150 4

North Dakotab ................. 0 0

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . 205 18

Oklahomab.................... 0 0

Pennsylvania . . . . . . . . . . . . . . . . . . 115 10

Texasb ....................... 0 0

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

RRC District 2 Onshoreb....... 0 0

RRC District 3 Onshoreb....... 0 0

RRC District 4 Onshoreb....... 0 0

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

RRC District 6b .............. 0 0

RRC District 7Bb ............. 0 0

RRC District 7Cb............. 0 0

RRC District 8b .............. 0 0

RRC District 8Ab ............. 0 0

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

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

State Offshorea .............. 0 0

Utahb ........................ 0 0

Virginiaa ...................... 0 0

West Virginia . . . . . . . . . . . . . . . . . . 59 4

Wyomingb .................... 0 0

Federal Offshorea c ............. 0 0

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

Gulf of Mexico (Louisiana)a c ... 0 0

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

Miscellaneousd ................ 2 0

aSampling rate was 100 percent in Alaska, Florida Onshore, Virginia, and Offshore areas. bSampling was not used. Estimates for each operator were made using an imputation function.

cIncludes Federal offshore Alabama. dIncludes 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 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,” 2003
presented in Table 14 were computed as the sum of

plant liquids estimates (Table 15) and lease condensate

(Table 16) estimates.

To generate estimates for each element in the reserves

balance for plant liquids in a given producing area, the

first step was to group all natural gas processing plants

that reported this area as an area-of-origin on their

Form EIA-64A, and then sum the liquids production

attributed to this area over all respondents. Next, the

ratio of the liquids production to the total wet natural

gas production for the area was determined. This ratio

represented the percentage of the wet natural gas that

was recovered as natural gas liquids. Finally, it was

assumed that this ratio was applicable to the reserves

and each component of reserve changes (except

adjustments), as well as production. Therefore, each

element in the wet natural gas reserves balance was

multiplied by this recovery factor to yield the

corresponding estimate for plant liquids. Adjustments

of natural gas liquids were set equal to the difference

between the end of previous year reserve estimates,

based upon the current report year Form EIA-23 and

Form EIA-64A surveys, and the end of current year

reserve estimates published in the preceding year's

annual reserves report.

Natural Gas Reserve Balance

This procedure involved downward adjustments of the

natural gas data, wet after lease separation, in

estimating the volumes of natural gas on a fully dry

basis. These reductions were based on estimates of the

gaseous equivalents of the liquids removed (in the case

of production), or expected to be removed (in the case

of reserves), from the natural gas stream at natural gas

processing plants. Form EIA-64A collected the

volumetric reduction, or shrinkage, of the input natural

gas stream that resulted from the removal of the NGL at

each natural gas processing plant.

The shrinkage volume was then allocated to the plant's

reported area or areas of origin. Because shrinkage is,

by definition, roughly in proportion to the NGL

recovered, i.e. the NGL produced, the allocation was in

proportion to the reported NGL volumes for each area

of origin. However, these derived shrinkage volumes

were rejected if the ratio between the shrinkage and the

NGL production (gas equivalents ratio) fell outside

certain limits of physical accuracy. The ratio was

expected to range between 1.558 MMCF per thousand

barrels (where NGL consists primarily of ethane) and

0.940 MMCF per thousand barrels (where NGL consists

primarily of natural gasolines). When the computed

gas equivalents ratio fell outside these limits, an

imputed ratio was utilized to estimate the plant's

natural gas shrinkage allocation to each reported area

of origin.

This imputed ratio was that calculated for the

aggregate of all other plants reporting production and

shrinkage, and having a gas equivalent ratio within the

aforesaid limits, from the area in question. The imputed

area ratio was applied only if there were at least five

plants to base its computation on. If there were less

than five plants, the imputed ratio was calculated

based on all plants in the survey whose individual gas

equivalents ratio was within the acceptable limits. Less

than one percent of the liquids production was

associated with shrinkage volumes imputed in this

manner. Based on the 2003 Form EIA-64A survey, the

national weighted average gas equivalents ratio was

computed to be 1,407 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.

Coalbed methane fields contain 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.

Energy Information Administration

F-14 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 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 commercially viable

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 2003 Annual Report G-1

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

Non-Producing

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 a

compilation of USGS and MMS estimates.

Technically recoverable resources of dry natural gas

(discovered, unproved, and undiscovered) are

estimated at 1,431 trillion cubic feet (Table G1).

Adding the 2003 U.S. proved reserves of 189 trillion

cubic feet yields a technically recoverable resource

target of 1,620 trillion cubic feet. This is about 83 times

the 2003 dry 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 2000 the PGC mean

estimate of potential gas resources was 1,091 trillion

cubic feet, about 340 trillion cubic feet less than the

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 1999, was

1,555 trillion cubic feet, 124 trillion cubic feet more than

the estimates summarized in Table G1. The differences

among these estimates are usually due to the

availability of newer data, differences in coverage or

resource category definitions, and legitimate but

differing data interpretations.

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 unproven technically

recoverable oil resources to 2003 oil production (Table

G1) was about 93 to 1, higher than the comparable gas

ratio.

Federal Land Resources

Estimates of technically recoverable resources that

underlie Federal jurisdiction lands are listed in Table

G1. These estimates are based on National assessments

performed by the USGS and the MMS. It is estimated

that 60 percent of the technically recoverable resources

of crude oil, 52.4 percent of the dry gas resources, and

34.7 percent of the natural gas liquids resources

underlie Federal lands.

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,

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G-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report G-3

Table G1. Mean Estimates of Technically Recoverable Oil and Gas Resources by Deposit Type and

Location

Natural Gas

Crude Oila Natural Gas (Dry) Liquids

Area Jurisdiction (billion barrels) (trillion cubic feet) (billion barrels)

Undiscovered Conventionally Reservoired Fields

Alaska Onshore + State Offshore Federal 3.75 33.97 0.54

Alaska Onshore + State Offshore Other 4.68 95.37 0.61

Alaska Federal Offshore Federal 24.90 122.60 0.00

Lower 48 States Onshore + State Offshore Federal 3.79 23.97 1.26

Lower 48 States Onshore + State Offshore Other 17.83 166.41 5.64

Lower 48 States Federal Offshore Federal 50.10 239.60 0.00

Alaska Subtotal 33.33 251.94 1.15

Alaska Percentage Federal 86.0% 62.1% 47.0%

Lower 48 States Subtotal 71.72 429.98 6.90

Lower 48 States Percentage Federal 75.1% 61.3% 18.3%

Technically Recoverable Resources in U.S.

Undiscovered Conventionally Reservoired Fields 105.05 681.92 8.05

Percentage Federal 78.6% 61.6% 22.4%

Ultimate Recovery Appreciation

U.S. Onshore + State Offshore Federal 14.33 118.70 4.94

U.S. Onshore + State Offshore Other 45.67 203.30 8.46

U.S. Federal Offshore Federal 7.70 68.00 0.00

Technically Recoverable Resources in U.S.

from Ultimate Recovery Appreciation in Discovered

Conventionally Reservoired Fields 67.70 390.00 13.40

U.S. Percentage Federal 32.5% 47.9% 36.9%

Continuous Type Deposits

Non-coal bed Federal 0.32 127.08 1.45

Non-coal bed Other 1.75 181.72 0.67

Coal bed Federal 0.00 16.08 0.00

Coal bed Other 0.00 33.83 0.00

Non-coal bed Subtotal 2.07 308.80 2.12

Non-coal bed Percentage Federal 15.5% 41.2% 68.4%

Coal bed Subtotal 0.00 49.91 0.00

Coal bed Percentage Federal 0.0% 32.2% 0.0%

Technically Recoverable Resources in U.S.

from Continuous Type Deposits 2.07 358.71 2.12

Continuous Type Percentage Federal 15.5% 39.9% 68.4%

U.S. Totals All Sources

U.S. Onshore + State Offshore Federal 22.19 319.80 8.19

U.S. Onshore + State Offshore Other 69.93 680.63 15.38

Federal Offshore Federal 82.70 430.20 0.00

Federal Subtotal 104.89 750.00 8.19

U.S. Technically Recoverable Resources 174.82 1,430.63 23.57

Percentage Federal 60.0% 52.4% 34.7%

Notes:

Proved Reserves are not included in these estimates.

Federal Onshore excludes Indian and Native lands even when Federally managed in trust.

Zero (0) indicates either that none exists in this area or that no estimate of this resource has been made for this area.
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.

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.{43} They are similarly defined by the MMS,

although its system also subdivides them by degree of

development and producing status.{44} 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.{43}

Inferred reserves are considered equivalent to

“probable reserves” by many analysts, for example,

those of the PGC.

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

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G-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Table G1. Mean Estimates of Technically Recoverable Oil and Gas Resources by Deposit Type and Location (continued)

Notes (continued): Federal Offshore indicates MMS estimates for Federal Offshore jurisdictions (Outer Continental Shelf and deeper water

areas seaward of State Offshore).

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.

Data Sources: National Oil and Gas Resource Assessment Team, 1996 National Assessment of United States Oil and Gas Resources,

Circular 1118, United States Geological Survey, Washington DC, 1995.

D.L Gautier, G.L. Dolton, and E.D. Atanasi, 1995 National Oil and Gas Assessment and Onshore Federal Lands, Open File Report

95-75-N, United States Geological Survey, Washington DC, January 1998.

Resource Evaluation Program, Outer Continental Shelf Petroleum Assessment 2000, Brochure 7, Minerals Management Service,

Washington, DC, January 2001 at <http://www.mms.gov/revaldiv/RedNatAssessment.htm>.

Resource Evaluation Program, An Assessment of the Undiscovered Hydrocarbon Potential of the Nation’s Outer Continental Shelf, OCS

Report MMS 96-0034, Minerals Management Service, Washington, DC, 1996.

Minerals Management Service, Mineral Revenues 1996, U.S. Department of the Interior, Washington, DC, 1997, Table 12 on p. 33 and

Table 23 on p. 70.

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

December 1997, Table 15 on p. 39.

Energy Information Administration, Petroleum Supply Annual 1996, Washington, DC, June 1997, Volume 1, Table 14 on p. 96.

Energy Information Administration, Natural Gas Annual 1996, Washington, DC, September 1997, Table 3 on p. 12.
determinate. Regardless of the definition selected,

proved reserves cannot be measured directly. They are

estimated quantities that are inferred on the basis of the

best geological, engineering, and economic data

available to the estimator, who generally uses

considerable judgment in the analysis and

interpretation of the data. Consequently, the accuracy

of a given estimate varies with and depends on the

quality and quantity of raw data available, the

estimation method used, and the training and

experience of the estimator. The element of judgment

commonly accounts for the differences among

independent estimates for the same reservoir or field.

Data Used in Making

Reserve Estimates

The raw data used in estimating proved reserves

include the engineering and geological data for

reservoir rock and its fluid content. These data are

obtained from direct and indirect measurements. The

data available for a given reservoir vary in kind,

quality, and quantity. When a reservoir is first

discovered only data from a single well are available,

and prior to flow testing or actual production, proved

reserves can only be inferred. As development of the

reservoir proceeds, and flow tests are made or actual

production commences, more and more data become

available, enabling proved reserves estimates to

become more accurate.

Many different kinds of data are useful in making

reserves estimates. They may include: data on porosity,

permeability, and fluid saturations of the reservoir

rocks (obtained directly from core analysis or from

various types of electrical measurements taken in a

well or several wells); data on the production of fluids

from a well or several wells; geologic maps of the areal

extent, thickness, and continuity of the reservoir rocks

(inferred from well logs, geophysical, and geological

data); and reservoir pressure and temperature data.

Also involved are economic data including the current

price of crude oil and natural gas, and various

developmental and operating costs.

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.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report G-5

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.
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

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

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G-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
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

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 2003 Annual Report G-7
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 2003 Annual Report H-1

Maps of Selected State Subdivisions
Figure H2. Subdivisions of California

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

Energy Information Administration

H-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
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 2003 Annual Report H-3
Figure H4. Subdivisions of New Mexico

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

Energy Information Administration

H-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
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 2003 Annual Report H-5
Figure H6. Western Planning Area, Gulf of Mexico Outer Continental Shelf Region

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

Energy Information Administration

H-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 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 2003 Annual Report H-7
Figure H8. Eastern Planning Area, Gulf of Mexico Outer Continental Shelf Region

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

Energy Information Administration

H-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 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 2003 Annual Report I-1

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

SAMPLE

Figure I1. Form EIA-23, Cover Page
Energy Information Administration

I-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Figure I2. Form EIA-23, Summary Report – Page 1

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

SAMPLE
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report I-3

Figure I3. Form EIA-23, Summary Report – Page 2

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

SAMPLE
Energy Information Administration

I-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Figure I4. Form EIA-23, Detail Report – Schedule A

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

SAMPLE
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report I-5

Figure I5. Form EIA-23, Detail Report – Schedule B

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

SAMPLE
Energy Information Administration

I-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report

Figure I6. Form EIA-64A

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 2001.

Acquisitions: The volume of proved reserves gained

by the purchase of an existing fields or properties,

from the date of purchase or transfer.

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)

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report Glossary-1

Published Proved Reserves at End of Previous Report Year

+ Adjustments

+ Revision Increases

– Revision Decreases

– Sales

+ Acquisitions

+ Extensions

+ New Field Discoveries

+ New Reservoir Discoveries in Old Fields

– Report Year Production

= Published Proved Reserves at End of Report Year
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

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

Energy Information Administration

Glossary-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
quality of the processed natural gas stream. Cycling

plants are considered natural gas processing plants.

Natural Gas, Wet After Lease Separation: The

volume of natural gas remaining after removal of

lease condensate in lease and/or field separation

facilities, if any, and after exclusion of

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 Reserves: Quantities of proved

liquid or gaseous hydrocarbon reserves that 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. This includes both proved

undeveloped and proved developed non-producing

reserves.

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

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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report Glossary-3
reservoirs in cycling, repressuring of oil reservoirs

and conservation operations; less (2) shrinkage

resulting from the removal of lease condensate and

plant liquids; and less (3) nonhydrocarbon gases

where they occur in sufficient quantity to render the

gas unmarketable. Volumes of gas withdrawn from

gas storage reservoirs and native gas, which has been

transferred to the storage category, are not

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.

Energy Information Administration

Glossary-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
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

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.

Sales: The volume of proved reserves deducted from

an operator’s total reserves when selling an existing

field or property, during the calendar year.

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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report Glossary-5
Subdivision: A prescribed portion of a given State

or other geographical region defined in this

publication for statistical reporting purposes.

Subsidiary Company: A company which is

controlled through the ownership of voting stock, or

a corporate joint venture in which a corporation is

owned by a small group of businesses as a separate

and specific business or project for the mutual

benefit of the members of the group. (See Control)

Total Discoveries: The sum of extensions, new

reservoir discoveries in old fields, and new field

discoveries, which occurred during the report year.

Total Liquid Hydrocarbon Reserves: The sum of

crude oil and natural gas liquids reserves volumes.

Total Operated Basis: The total reserves or

production associated with the wells operated by an

individual operator. This is also commonly known as

the “gross operated” or “8/8ths” basis.

Working Interest: A working interest permits the

owner(s) to explore, develop and operate a property.

The working interest owner(s) bear(s) the costs of

exploration, development and operation of the

property, and in return is (are) entitled to a share of

the mineral production from the property or to a

share of the proceeds therefrom.

Energy Information Administration

Glossary-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report