DOE/EIA-0216(2004)

November 2005

U.S. Crude Oil, Natural Gas,

and Natural Gas Liquids Reserves

2004 Annual Report

DOE/EIA–0216(2004)

Distribution Category UC–950

U.S. Crude Oil, Natural Gas,

and Natural Gas Liquids Reserves

2004 Annual Report

November 2005

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 2004 Annual Report is the 28th

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, 2004, as well as production volumes

for the United States and producing States and State

subdivisions for the year 2004. 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 crude oil, natural gas, and

lease condensate reserves in nonproducing

reservoirs. A discussion of notable oil and gas

exploration and development activities during 2004

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 2004; 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 Preston.

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 2004 Annual Report iii
Energy Information Administration

iv U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 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:

Rig drilling on the Pinedale Anticline in Wyoming, with the Wind River

Mountains in the background. Photo by Bob Lynn, courtesy of Ultra Petroleum.

Ultra Petroleum, headquartered in Houston, TX, is the largest lease holder on

the Pinedale Anticline and third largest operator in Jonah field.
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

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Montana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

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

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

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

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

Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

New Field Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

New Reservoir Discoveries in Old Fields. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Revisions and Adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

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

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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report v
Page

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

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

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

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

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

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

Associated-Dissolved Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

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

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

Coalbed Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

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

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

Areas of Note: Large Discoveries and Reserves Additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

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

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Areas of Note: Large Reserves Declines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Gulf of Mexico Federal Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

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

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

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

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

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

Extensions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

New Field Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

New Reservoir Discoveries in Old Fields. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

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

Sales and Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

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 Level Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1

B. Top 100 Oil and Gas Fields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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, 1994-2004 ............ 4

2. Reserves Changes, 1977-2004 ........................................... 9

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vi U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report
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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, 1977-2004 . . . . . . . . . . . . . . . . . . . . . . . . . . 10

4. U.S. Exploratory and Development Well Completions, 1970-2004 . . . . . . . . . . . . . . . . . . . . . . . . . 12

5. International Oil and Natural Gas Reserves as of December 31, 2004 . . . . . . . . . . . . . . . . . . . . . . . 18

6. Crude Oil Proved Reserves, Reserves Changes, and Production, 2004 . . . . . . . . . . . . . . . . . . . . . . 22

7. Reported Reserves in Nonproducing Status for Crude Oil, 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . 27

8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 2004 . . . . . . . . . . . . . . . . . . 30

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

Wet After Lease Separation, 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

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

Wet After Lease Separation, 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

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

Wet After Lease Separation, 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

12. Coalbed Natural Gas Proved Reserves and Production, 1989-2004 . . . . . . . . . . . . . . . . . . . . . . . . 38

13. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 2004 . . . . . . . . . . . . . . . . 42

14. Natural Gas Plant Liquids Proved Reserves and Production, 2004. . . . . . . . . . . . . . . . . . . . . . . . . 43

15. Lease Condensate Proved Reserves and Production, 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Figures

1. U.S. Crude Oil Proved Reserves, 1994-2004 .................................... 5

2. Components of Reserves Changes for Crude Oil, 1994-2004 ........................... 5

3. U.S. Dry Natural Gas Proved Reserves, 1994-2004 ................................ 6

4. Components of Reserves Changes for Dry Natural Gas, 1994-2004 ........................ 6

5. U.S. Natural Gas Liquids Proved Reserves, 1994-2004 .............................. 8

6. Components of Reserves Changes for Natural Gas Liquids, 1994-2004 ...................... 8

7. U.S. Exploratory Well Completions, 1994-2004. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

8. U.S. Development Well Completions, 1977-2004. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

9. U.S. Total Discoveries of Dry Natural Gas per Exploratory Gas Well Completion, 1977-2004 . . . . . . . . . . . 14

10. U.S. Total Discoveries of Crude Oil per Exploratory Oil Well Completion, 1977-2004 . . . . . . . . . . . . . . . 14

11. Reserves-to-Production Ratios for Crude Oil, 1945-2004. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

12. Reserves-to-Production Ratios for Wet Natural Gas, 1945-2004 . . . . . . . . . . . . . . . . . . . . . . . . . . 16

13. Components of Ultimate Recovery for Crude Oil and Lease Condensate, 1977-2004 . . . . . . . . . . . . . . . 17

14. Components of Ultimate Recovery for Wet Natural Gas, 1977-2004 . . . . . . . . . . . . . . . . . . . . . . . . 17

15 Replacement of U.S. Crude Oil Production by Reserves Additions, 1994-2004 . . . . . . . . . . . . . . . . . . 21

16. Crude Oil Proved Reserves by Area, 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

17. Changes in Crude Oil Proved Reserves by Area, 2003 to 2004 . . . . . . . . . . . . . . . . . . . . . . . . . . 23

18. Replacement of U.S. Dry Gas Production by Reserves Additions, 1994-2004 . . . . . . . . . . . . . . . . . . . 29

19. Dry Natural Gas Proved Reserves by Area, 2004. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

20. Changes in Dry Natural Gas Proved Reserves by Area, 2003 to 2004 . . . . . . . . . . . . . . . . . . . . . . . 31

21. Coalbed Natural Gas Proved Reserves, 1989-2004 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report vii

Executive Summary

Proved reserves of natural gas increased by 2 percent

in 2004, making it the sixth year in a row that U.S.

natural gas reserves have increased. The U.S. total

went up even though Gulf of Mexico natural gas

proved reserves dropped an unusually large 15

percent primarily due to low new discoveries.

Nevertheless because onshore lower 48 States total

discoveries were almost 18 trillion cubic feet, total

U.S. reserves additions replaced 118 percent of 2004

dry gas production.

Crude oil proved reserves declined by 2 percent in

2004 owing mostly to a large 9 percent decrease in

the Gulf of Mexico. Boosted by reserves additions in

Wyoming, Montana, North Dakota, and Texas, the

crude oil proved reserves of the onshore lower 48

States increased by 0.1 percent. However, three of the

four largest crude oil reserves areas, the Gulf of

Mexico, Alaska, and California, registered reserves

declines. U.S. new field discoveries were the lowest

in 12 years and as a result operators only replaced 71

percent of crude oil production with reserves

additions.

Natural gas liquids proved reserves grew by 6

percent in 2004, rebounding from their 2003 decline.

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.

Natural Gas

Increased onshore natural gas drilling in 2004

resulted in large reserves additions to known fields.

Discoveries of new gas fields, however, were the

lowest in 12 years. While natural gas proved reserves

have increased in ten of the past eleven years,

production has not. Total U.S. dry gas production

declined 1 percent in 2004.

The large proved natural gas reserves drop

experienced in the Gulf of Mexico was primarily due

to low new field discoveries and relatively large

negative revisions to proved reserves, but Hurricane

Ivan certainly didn't help. Twenty percent of U.S. dry

natural gas production is from the Gulf of Mexico

Federal Offshore and Ivan caused infrastructure

damage that impacted oil and gas production in the

Gulf in the last quarter of 2004. Ivan's damage will

also reduce 2005 Gulf production from what it could

have been.

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 new wells. Total discoveries of dry gas

reserves were 20,163 billion cubic feet in 2004. This

was 32 percent more than the prior 10-year average

and 5 percent more than in 2003.

The majority of natural gas total discoveries in 2004

were from extensions to existing gas fields. There

were almost 2 trillion cubic feet more reserves from

extensions than in 2003 with Texas and Wyoming

leading the Nation. Field extensions were 18,198

billion cubic feet, 11 percent more than extensions in

2003 and 66 percent more than the prior 10-year

average of 10,976 billion cubic feet.

New field discoveries were 759 billion cubic feet, 38

percent less than the volume discovered in 2003 and

59 percent less than the prior 10-year average.

New reservoir discoveries in old fields were 1,206

billion cubic feet, down 25 percent from 2003 and 50

percent less than the prior 10-year average.

Natural gas net revisions and adjustments were 630

billion cubic feet, which is 48 percent less than the

net revisions and adjustments of 2003. The net of

sales and acquisitions of dry natural gas proved

reserves was 1,844 billion cubic feet.

Coalbed natural gas is becoming a mature source

that in 2004 accounted for 9 percent of U.S. dry gas

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report ix

As of December 31, 2004 proved reserves were:

Crude Oil (million barrels)

2003 21,891

2004 21,371

Decrease -2.4%

Dry Natural Gas (billion cubic feet)

2003 189,044

2004 192,513

Increase +1.8%

Natural Gas Liquids (million barrels)

2003 7,459

2004 7,928

Increase +6.3%
production. Production increased 7 percent, but

coalbed natural gas proved reserves decreased 2

percent to 18,390 billion cubic feet. Even so, it still

accounted for almost 10 percent of 2004 U.S. dry gas

proved reserves. The last reported decline of coalbed

natural gas proved reserves was in 1994.

Other 2004 natural gas events of note:

• Natural gas prices were up 12 percent in 2004

to an average of $5.49 per thousand cubic feet

at the wellhead, as compared to $4.88 per

thousand cubic feet in 2003.

• Exploratory and developmental gas

completions were up 15 percent from 2003.

Crude Oil

Operators only replaced 71 percent of crude oil

production with reserves additions in 2004. U.S.

crude oil proved reserves declined over 2 percent as

new field discoveries reported in 2004 were the

lowest in 12 years. Of the four largest crude oil

proved reserves areas in the U.S. (the Gulf of Mexico,

Texas, Alaska, and California) only Texas reported

an increase in proved crude oil reserves in 2004 (1

percent). The Gulf of Mexico declined 9 percent,

Alaska declined 3 percent, and California declined 2

percent. In the Rockies, however, Wyoming (#6 in

the Nation for crude oil proved reserves), North

Dakota (#9) and Montana (#10) had significant

proved reserves increases.

Total discoveries of crude oil were 782 million

barrels in 2004, 29 percent less than the prior 10-year

average and 37 percent less than 2003's discoveries of

1,232 million barrels.

The majority of crude oil total discoveries in 2004

came from extensions to fields in Texas, Alaska, and

the Gulf of Mexico Federal Offshore. Operators

discovered 617 million barrels in extensions in 2004,

45 percent more than in 2003 and 22 percent more

than the prior 10-year average.

New field discoveries accounted for 33 million

barrels of crude oil reserves additions. Almost all of

these small discoveries (27 of the 33 million) were in

the Gulf of Mexico Federal Offshore. This was the

lowest volume of new field discoveries in 12 years,

95 percent less than the new field discoveries of 2003,

and only 8 percent of the prior 10-year average (422

million barrels).

New reservoir discoveries in old fields were 132

million barrels, 31 percent more than in 2003 and 26

percent less than the prior 10-year average.

Reserves additions are the sum of total discoveries,

revisions, adjustments, sales, and acquisitions.

Reserves additions in 2004 were 1,299 million barrels,

19 percent more than the 2003 volume but 32 percent

less than the prior 10-year average.

Crude oil net revisions and adjustments were 494

million barrels, 92 percent more than the net

revisions and adjustments of 2003. The net of sales

and acquisitions of crude oil proved reserves was 23

million barrels.

Other 2004 crude oil events of note:

• The annual average domestic first purchase

price for crude oil increased 33 percent from

the 2003 level to $37.77 per barrel.

• The West Texas Intermediate crude oil spot

price underwent significantly higher price

fluctuations in late 2004 and 2005.

• Exploratory and developmental oil

completions were down 2 percent from 2003.

Natural Gas Liquids

Natural gas liquids reserves are the sum of lease

condensate reserves and natural gas plant liquids

reserves. Lease condensate reserves increased only

slightly in 2004 (less than 1 percent). Natural gas

liquids proved reserves posted a 6 percent increase,

recovering from the loss reported in the prior year.

Texas led the Nation in natural gas liquids proved

reserves additions in part because of extensions to

existing fields. Operators replaced 157 percent of U.S.

natural gas liquids production with reserves

additions. Natural gas plant liquids reserves

increased by 7 percent in 2004 because operators of

natural gas processing plants produced 6 percent

more natural gas plant liquids and extracted a higher

average percentage of liquids from the processed gas.

In total, U.S. natural gas liquids proved reserves

increased by over 6 percent in 2004 to 7,928 million

barrels.

Total proved reserves of liquid hydrocarbons (crude

oil plus natural gas liquids) were 29,299 million

barrels in 2004, a less than 1 percent decrease from

the 2003 level. Natural gas liquids represented 27

percent of total liquid hydrocarbon proved reserves

in 2004.

Data

These estimates are based upon analysis of data from

Form EIA-23, Annual Survey of Domestic Oil and

Gas Reserves, filed by 1,341 operators of oil and gas

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

Origin of Natural Gas Liquids Production, filed by

operators of 493 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 2004 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 2004. 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 2004 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 20,670 probable active operators and the

Form EIA-64A plant frame contained 488 probable

active natural gas processing plants in the United

States when the 2004 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 2004. For more

details on the survey process, see Appendix E,

Summary of Data Collection Operations.

The 2004 survey sample consisted of 1,341 operators.

EIA sampled 971 operators with certainty; 164

Category I operators, 532 Category II operators, and

275 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 370 Noncertainty

operators as a systematic random sample of the

remaining operators. There were 12 Successor

operators in 2004. Fifty-one (51) of the 1,341 ceased

operating oil and/or gas properties (became

non-operator) during the survey year. For more details

on the survey response statistics, see Table E2 in

Appendix E, Summary of Data Collection Operations.

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

processing plant operators as of February 1, 2005. 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 491 unique

active natural gas processing plants in 2004.

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 2004,

the Form EIA-23 National production estimates were 1

percent higher than the comparable Petroleum Supply

Annual (PSA) 2004 volumes for crude oil and lease

condensate combined, and were 1 percent higher than

the comparable Natural Gas Monthly, October 2005

volume for 2004 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 2004 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, 2004:

Crude Oil — 21,371 million barrels

Dry Natural Gas — 192,513 billion cubic feet

Natural Gas Liquids — 7,928 million barrels.

This Overview summarizes the 2004 proved reserves

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

liquids on a National level and provides historical

comparisons between 2004 and prior years. Table 1

lists the estimated annual reserve balances since 1994

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

Crude Oil

Proved reserves of crude oil decreased by 520 million

barrels in 2004. Figure 1 shows the crude oil proved

reserves levels by major region and Figure 2 shows the

components of reserves changes from 1994 through

2004.

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

decreased in 2004 in Alaska and the Federal Offshore,

but remained level onshore in the lower 48 States.

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

782 million barrels in 2004, 29 percent less than the

prior 10-year average and 37 percent less than 2003’s

discoveries of 1,232 million barrels.

The majority of crude oil total discoveries in 2004 were

extensions of existing fields in northern Rocky

Mountain states and Texas.

Operators discovered 617 million barrels in extensions

in 2004, 45 percent more than in 2003 and 22 percent

more than the prior 10-year average.

New field discoveries accounted for 33 million barrels

of crude oil reserves additions, 27 million of which

were in the Gulf of Mexico Federal Offshore. This was

the lowest volume of new field discoveries since 1992

and 92 percent less than the prior 10-year average.

New reservoir discoveries in old fields were 132

million barrels, 31 percent more than in 2003 and 26

percent less than the prior 10-year average.

Reserves additions are the sum of total discoveries,

revisions and adjustments, and sales and acquisitions.

In 2004 there were 1,299 million barrels of reserves

additions, 19 percent more than the volume of reserves

additions in 2003.

Crude oil net revisions and adjustments were 494

million barrels, 92 percent more than the net revisions

and adjustments of 2003. The net of sales and

acquisitions of crude oil proved reserves was 23 million

barrels.

Production of crude oil was an estimated 1,819 million

barrels in 2004 (lease condensate not included, see

Natural Gas Liquids section below for condensate

volumes). This was down 3 percent from 2003’s level

(1,877 million barrels) and down 10 percent from the

prior 10-year average (2,028 million barrels). Operators

replaced 71 percent of crude oil production with

reserves additions in 2004.

Natural Gas

Dry natural gas proved reserves increased by 3,469

billion cubic feet in 2004. 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 1994 through 2004.

Total discoveries of dry gas reserves were 20,163 billion

cubic feet in 2004. This was 32 percent more than the

prior 10-year average and 5 percent more than in 2003.

The majority of natural gas total discoveries in 2004

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 3
Energy Information Administration

4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table 1. Total U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids, 1994-2004

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)

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

2004 74 420 494 23 617 33 132 782 1,819 21,371 -520

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

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

2004 -114 744 630 1,844 18,198 759 1,206 20,163 19,168 192,513 +3,469

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

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

2004 273 97 370 112 734 26 54 814 827 7,928 +469

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

2004 contained in the Petroleum Supply Annual 2004, DOE/EIA-0340(04) and the Natural Gas Annual 2004, DOE/EIA-0131(04).

Sources: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1994 through 2003 annual reports, DOE/EIA-0216.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 5

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1994-2003 annual reports, DOE/EIA-0216.{18-27}

Figure 1. U.S. Crude Oil Proved Reserves, 1994-2004

Figure 2. Components of Reserves Changes for Crude Oil, 1994-2004
Energy Information Administration

6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Figure 4. Components of Reserves Changes for Dry Natural Gas, 1994-2004

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1994-2003 annual reports, DOE/EIA-0216.{18-27}

Figure 3. U.S. Dry Natural Gas Proved Reserves, 1994-2004
were from extensions of existing conventional and

unconventional gas fields onshore in the lower 48

States.

Field extensions were 18,198 billion cubic feet, 11

percent more extensions than in 2003 and 66 percent

more than the prior 10-year average of 10,976 billion

cubic feet.

New field discoveries were 759 billion cubic feet, 38

percent less than the volume discovered in 2003 and 59

percent less than the prior 10-year average.

New reservoir discoveries in old fields were 1,206

billion cubic feet, down 25 percent from 2003 and 50

percent less than the prior 10-year average.

Natural gas net revisions and adjustments were 630

billion cubic feet, 48 percent less than the net revisions

and adjustments of 2003. The net of sales and

acquisitions of dry natural gas proved reserves was

1,844 billion cubic feet.

Production removed an estimated 19,168 billion cubic

feet of proved reserves from the National total. Dry gas

production decreased by 1 percent compared to 2003.

Operators replaced 118 percent of dry natural gas

production with reserves additions.

Coalbed natural gas reserves declined in 2004, while

production significantly increased. Coalbed natural

gas proved reserves were 18,390 billion cubic feet, a

decrease of 2 percent from 2003, and accounted for 10

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

production increased 8 percent from 2003 to 1,720

billion cubic feet, and accounted for 9 percent of U.S.

dry gas production.

Natural Gas Liquids

Proved reserves of natural gas liquids increased 6

percent in 2004 to 7,928 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

reserves are increasing in the Lower 48 onshore while

Alaska and the Federal offshore reserves remain level.

Figure 6 shows the components of natural gas liquids

reserves changes from 1994 through 2004.

Operators replaced 157 percent of their 2004 natural

gas liquids production with reserve additions. Total

discoveries added 814 million barrels (primarily from

extensions), net revisions and adjustments were 370

million barrels, and net sales and acquisitions added

112 million barrels in 2004.

Total proved reserves of liquid hydrocarbons (crude oil

plus natural gas liquids) were 29,299 million barrels in

2004—a less than 1 percent decrease from the 2003

level. Natural gas liquids represented 27 percent of

total liquid hydrocarbon proved reserves in 2004.

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 2004. 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 2004 proved reserves estimates as a

means of gauging the past year against history.

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

had average annual new reserves discoveries of

900 million barrels,

had average annual proved reserves additions

of 2,065 million barrels from total discoveries,

net revisions and adjustments, and net sales and

acquisitions, and

had an average annual proved reserves decline

of 433 million barrels Nationwide, because

production exceeded reserve additions.

Since 1977, crude oil reserves have primarily been

sustained by proved ultimate recovery appreciation in

existing fields rather than by the discovery of new oil

fields. Only 12 percent of reserves additions since 1977

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 25,209 million barrels of total discoveries

accounted for 44 percent of reserves additions.

Compared to the averages of reserves changes since

1977, 2004 was a down year for crude oil discoveries.

Total discoveries of crude oil (782 million barrels) in

2004 were 13 percent less than the post-1976 U.S.

average (900 million barrels per year).

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 7
Energy Information Administration

8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Figure 5. U.S. Natural Gas Liquids Proved Reserves, 1994-2004

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1994-2003 annual reports, DOE/EIA-0216.{18-27}

Figure 6. Components of Reserves Changes for Natural Gas Liquids, 1994-2004
Looking at the components of total discoveries in 2004:

2004’s new field discoveries (33 million barrels)

were 86 percent less than the post-1976 average

for crude oil and the lowest since 1992,

Extensions in 2004 (617 million barrels) were 20

percent more than the post-1976 average, and

New reservoir discoveries in old fields (132

million barrels) were 10 percent less than the

post-1976 average for crude oil.

Revisions, Adjustments, Sales & Acquisitions were 517

million barrels in 2004. This was 56 percent less than

the post-1976 average of 1,165 million barrels per year.

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

had average annual new reserves discoveries of

13,375 billion cubic feet,

had average annual proved reserves additions

of 17,287 billion cubic feet from total

discoveries, net revisions and adjustments, and

net sales and acquisitions, and

had an average annual proved reserves decline

Nationwide of 742 billion cubic feet.

Like crude oil reserves, natural gas reserves have

primarily been sustained by proved ultimate recovery

appreciation since 1977. For gas, extensions rather than

net revisions and adjustments are usually the largest

component. Extensions accounted for 52 percent of all

reserves additions since 1977 while net revisions and

adjustments accounted for only 23 percent.

Compared to the averages of reserves changes since

1977, 2004 was an up year for dry natural gas total

discoveries. Operators reported 20,163 billion cubic

feet of total discoveries of dry natural gas proved

reserves, 51 percent more than the post-1976 average

(13,375 billion cubic feet).

The net of revisions, adjustments, sales, and

acquisitions was 2,474 billion cubic feet in 2004, 37

percent lower than the post-1976 U.S. average (3,911

billion cubic feet per year).

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 9

Table 2. Reserves Changes, 1977-2004

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 ........... 5,725 204 12.1 6,676 238 11.5

New Reservoir Discoveries in Old Fields . . 3,914 140 8.3 4,102 147 7.1

Extensions ................ 12,729 455 26.9 14,431 515 25.0

Total Discoveries ............. 22,368 799 47.3 25,209 900 43.6

Revisions, Adjustments, Sales & Acquisitionsa 24,887 889 52.7 32,614 1,165 56.4

Total Reserves Additions ......... 47,255 1,688 100.0 57,823 2,065 100.0

Production ................ 55,075 1,967 116.5 69,954 2,498 121.0

Net Reserves Change ........... -7,820 -279 -16.5 -12,131 -433 -21.0

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

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

New Field Discoveries ........... 52,929 1,890 10.6 53,171 1,899 11.0

New Reservoir Discoveries in Old Fields . . 68,090 2,432 13.7 68,539 2,448 14.2

Extensions ................ 249,592 8,914 50.1 252,803 9,029 52.2

Total Discoveries ............. 370,611 13,236 74.5 374,513 13,375 77.4

Revisions, Adjustments, Sales & Acquisitionsa 127,110 4,540 25.5 109,511 3,911 22.6

Total Reserves Additions ......... 497,721 17,776 100.0 484,024 17,287 100.0

Production ................ 494,453 17,659 99.3 504,789 18,028 104.3

Net Reserves Change ........... 3268 117 0.7 -20,765 -742 -4.3

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 1977-2004 annual reports, DOE/EIA-0216.{1-27}
Energy Information Administration

10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 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, 1977-2004

Crude Oil Natural Gas

Year Current 2004 Constant Current 2004 Constant

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

1977 8.57 21.78 0.79 2.01 2,001

1978 9.00 21.35 0.91 2.16 2,259

1979 12.64 27.68 1.18 2.58 2,177

1980 21.59 43.29 1.59 3.19 2,909

1981 31.77 58.28 1.98 3.63 3,970

1982 28.52 49.24 2.46 4.25 3,105

1983 26.19 43.50 2.59 4.30 2,232

1984 25.88 41.45 2.66 4.26 2,428

1985 24.09 37.40 2.51 3.90 1,980

1986 12.51 19.00 1.94 2.95 964

1987 15.40 22.71 1.67 2.46 936

1988 12.58 17.94 1.69 2.41 936

1989 15.86 21.79 1.69 2.32 869

1990 20.03 26.48 1.71 2.26 1,010

1991 16.54 21.10 1.64 2.09 860

1992 15.99 19.92 1.74 2.17 721

1993 14.25 17.33 2.04 2.48 754

1994 13.19 15.72 1.85 2.20 775

1995 14.62 17.05 1.55 1.81 723

1996 18.46 21.12 2.17 2.48 779

1997 17.23 19.34 2.32 2.60 943

1998 10.87 12.05 1.96 2.17 827

1999 15.56 17.00 2.19 2.39 625

2000 26.72 28.60 3.68 3.94 918

2001 21.84 22.83 4.00 4.18 1,156

2002 22.51 23.27 2.95 3.05 830

2003 January 28.42 29.06 4.43 4.53 854

February 31.85 32.52 5.05 5.16 907

March 30.10 30.69 6.96 7.10 941

April 25.45 25.95 4.47 4.56 983

May 24.95 25.41 4.77 4.86 1,034

June 26.84 27.30 5.41 5.50 1,067

July 27.52 27.95 5.08 5.16 1,081

August 27.94 28.34 4.46 4.52 1,090

September 25.23 25.56 4.59 4.65 1,093

October 26.53 26.84 4.32 4.37 1,102

November 27.21 27.49 4.26 4.30 1,111

December 28.53 28.79 4.76 4.80 1,114

2003 Average 27.56 28.04 4.88 4.96 1,032

2004 January 30.35 30.59 5.53 5.57 1,101

February 31.21 31.42 5.15 5.18 1,119

March 32.86 33.04 4.97 5.00 1,135

April 33.20 33.34 5.20 5.22 1,151

May 35.73 35.83 5.63 5.65 1,164

June 34.53 34.57 5.85 5.86 1,176

July 36.54 36.50 5.60 5.59 1,213

August 40.10 39.98 5.36 5.34 1,234

September 40.56 40.37 4.86 4.84 1,240

October 46.14 45.84 5.45 5.41 1,240

November 42.85 42.50 6.07 6.02 1,262

December 38.22 37.85 6.25 6.19 1,246

2004 Average 36.77 36.77 5.49 5.49 1,192

=Revised data.

Sources: Current dollars and number of rigs: Monthly Energy Review October 2005, DOE/EIA-0035(2005/10). 2004 constant dollars:

U.S. Department of Commerce, Bureau of Economic Analysis, Gross Domestic Product Implicit Price Deflators, October 2005.
For the sixth year in a row (and 10 out of the last 11

years, the annual change to the National total of gas

reserves has been positive, not negative.

Economics and Drilling

Economics: Table 3 lists the average annual domestic

wellhead prices of crude oil and natural gas from 1977

to 2004.

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

average of $30.35 per barrel in January 2004, rose to a

high of $46.14 in October, and ended the year at $38.22

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

price increased from $27.56 in 2003 to $36.77 per barrel

in 2004.

Oil prices vary by region. The average 2004 crude oil

first purchase price was $38.79 per barrel in Texas,

$34.47 per barrel in California, $40.38 per barrel in

Colorado, $38.27 per barrel in Ohio, and $32.23 per

barrel in the California Federal Offshore. The lowest

average crude oil first purchase price in 2003 was

$32.23 per barrel in the Federal Offshore California.{28}

The average annual wellhead natural gas price

increased from $4.88 per thousand cubic feet in 2003 to

$5.49 in 2004. Natural gas prices started at $5.53 per

thousand cubic feet in January 2004, fluctuated

between $4.86 and $5.85 until October, and then rose

rapidly at end of the year to $6.25 per thousand cubic

feet in December 2004. {29}

Drilling: Also listed in Table 3 is the average number

of active rotary drilling rigs from 1977 to 2004. From

2003 to 2004, the annual average active rig count rose

from 1,032 to 1,192, a 16 percent increase.

Looking first at exploratory wells, there were 2,623

exploratory wells drilled in 2004 (Table 4). Of these, 12

percent were completed as oil wells, 36 percent were

completed as gas wells, and 52 percent were dry holes.

Exploratory oil and gas completions (excluding dry

holes) in 2004 were 9 percent more (Figure 7) than the

revised 2003 total.

Figures 9 and 10 show the average volume of

discoveries per exploratory well for dry natural gas

and oil, respectively, since 1977. The 2004 average

volume of oil discoveries per exploratory well

decreased 35 percent compared to 2003. The 2004

average volume of gas discoveries per exploratory well

decreased 7 percent compared to 2003.

The number of successful development wells

decreased 2 percent for oil and increased 15 percent for

gas from their 2003 levels (Figure 8). Including dry

holes, there were an estimated 33,813 exploratory and

development wells drilled in 2004. This is 10 percent

more than in 2003 and 29 percent more than the

average number of wells drilled annually in the prior

10 years (26,304).

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 2004 and are expected to have a major

impact on the energy industry in the future:

On April 7, 2004, Kerr-McGee Corporation and

Westport Resources Corporation announced that their

boards of directors had unanimously approved a

merger valued at approximately $3.4 billion. The

merged company will be known as Kerr-McGee

Corporation and will be headquartered in Oklahoma

City. The addition of Westport’s reserves will increase

Kerr-McGee’s proved reserves by nearly 30%, mainly

from North American natural gas. As of December 31,

2003, Westport had 1.8 TCF equivalent of proved

reserves which were 76% natural gas and primarily

located in the Rocky Mountain and Texas Gulf Coast

areas. Westport has an additional 1.8 TCF equivalent of

identified probable and possible resources.

Approximately 50% of these resources are located in

and around the Natural Buttes Field in the Uinta Basin

of northeast Utah. The Greater Natural Buttes area is

similar to Kerr-McGee’s Wattenberg Field and will

allow Kerr-McGee to use its proven expertise in

tight-gas and supply-chain management to maximize

the efficient recovery of these resources. {30}

On May 4, 2004, Pioneer Natural Resources Company

and Evergreen Resources, Inc. announced that their

boards of directors had approved a merger valued at

approximately $2.1 billion, in which Evergreen would

become a subsidiary of Pioneer. Pioneer Natural

Resources Company would continue to be

headquartered in Dallas, and would retain Evergreen’s

Denver offices as its base of operations in the Rockies.

{31}

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 11
Energy Information Administration

12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table 4. U.S. Exploratory and Development Well Completions,a 1970-2004

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 7,064 11,144 4,840 23,048

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

2000 R 268 R 607 1,288 R 2,163 7,358 16,455 4,025 27,838

2001 322 988 R 1,692 R 3,002 8,060 22,083 4,084 34,227

2002 R 234 R 668 R 1,253 R 2,155 6,058 16,155 R 3,581 R 25,794

2003 R 317 R 838 R 1,283 R 2,314 R 7,284 R 19,722 R 3,687 R 30,693

2004 310 946 1,367 2,623 7,165 22,673 3,973 33,813

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 1973-2004: EIA Monthly Energy Review

October 2005, DOE/EIA-0035(2005/10). 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 2004 Annual Report 13

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

Figure 7. U.S. Exploratory Well Completions, 1994-2004

Figure 8. U.S. Development Well Completions, 1994-2004
Energy Information Administration

14 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 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, 1977-2004

Figure 10. U.S. Total Discoveries of Crude Oil per Exploratory Oil Well Completion, 1977-2004
On May 19, 2004, EnCana Corporation completed its

cash tender offer for all outstanding common shares of

Tom Brown, Inc. The total value of the transaction,

including debt assumption, is approximately US$2.7

billion. This acquisition of Tom Brown will add about

325 million cubic feet per day of gas equivalent

production. EnCana’s U.S. gas production is expected

to reach 1 billion cubic feet per day. {32}

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 2004, U.S. crude oil proved reserves and oil

production decreased, increasing the National average

R/P ratio slightly from 11.7 to 11.8.

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 2004 National

average R/P ratio for crude oil was 11.8-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 2003

to 2004 the U.S. average R/P ratio for natural gas

increased from 9.7 to 10.1 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 10.1-to-1. Areas with a

higher range of R/P ratios than the National average

were the Pacific offshore and the Rockies. 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

of crude oil or natural gas are the estimated

quantities of petroleum which geological and

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 15
Energy Information Administration

16 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Sources: Annual reserves and production - American Petroleum Institute and American Gas Association (1945–1976) {33} and Energy

Information Administration, Office of Oil and Gas (1977–2003){1-27}. Cumulative production: U.S. Oil and Gas Reserves by Year of Field

Discovery (1977-1988).{34}

Figure 11. Reserves-to-Production Ratios for Crude Oil, 1945-2004

Figure 12. Reserves-to-Production Ratios for Wet Natural Gas, 1945-2004
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 17

Sources: Annual reserves and production - American Petroleum Institute and American Gas Association (1945–1976) {33} and Energy

Information Administration, Office of Oil and Gas (1977–2003){1-27}. Cumulative production: U.S. Oil and Gas Reserves by Year of Field

Discovery (1977-1988).{34}

Figure 13. Components of Proved Ultimate Recovery for Crude Oil and Lease Condensate, 1977-2004

Figure 14. Components of Proved Ultimate Recovery for Wet Natural Gas, 1977-2004
Table 5. International Oil and Natural Gas Reserves as of December 31, 2004

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 d262,075 1 Russia . . . . . . . . . . . . . . 1,680,000 2,361,053

2 Iranc ............... 125,800 130,800 2 Iranc ................ 940,000 944,670

3 Iraqc ............... 115,000 115,000 3 Qatarc .............. 910,000 913,400

4 Kuwaitc ............. d101,500 d99,675 4 Saudia Arabiac........ d235,000 d238,500

5 United Arab Emiratesc . 97,800 69,910 5 United Arab Emiratesc . . 212,100 204,050

6 Canadae ............ 178,893 4,700 6 United States ......... 192,513 192,513

7 Venezuelac . . . . . . . . . . 77,226 52,400 7 Nigeriac ............. 176,000 180,000

8 Russia. . . . . . . . . . . . . . 60,000 67,138 8 Algeriac ............. 160,500 171,500

9 Libyac . . . . . . . . . . . . . . 39,000 33,550 9 Venezuelac .......... 151,000 150,500

10 Nigeriac. . . . . . . . . . . . . 35,255 36,630 10 Iraqc ................ 110,000 112,600

Top 10 Total. . . . . . . . . . . . . . 1,077,193 831,305 Top 10 Total . . . . . . . . . . . . . . 4,737,113 5,468,786

11 United States . . . . . . . . 21,371 21,371 11 Australia . . . . . . . . . . . . . 90,000 142,900

12 Qatarc . . . . . . . . . . . . . . 15,207 20,000 12 Norway. . . . . . . . . . . . . . 74,800 84,261

13 China . . . . . . . . . . . . . . 18,250 15,443 13 Indonesiac . . . . . . . . . . . 90,300 63,000

14 Mexico . . . . . . . . . . . . . 14,600 14,803 14 Turkmenistan . . . . . . . . . 71,000 -

15 Algeriac. . . . . . . . . . . . . 11,800 15,303 15 Uzbekistan . . . . . . . . . . . 66,200 -

16 Brazil. . . . . . . . . . . . . . . 10,600 11,243 16 Malaysia. . . . . . . . . . . . . 75,000 56,562

17 Norway . . . . . . . . . . . . . 8,500 9,863 17 Kazakhstan . . . . . . . . . . 65,000 -

18 Kazakhstan. . . . . . . . . . 9,000 - 18 Egypt . . . . . . . . . . . . . . . 58,500 66,000

19 Angola . . . . . . . . . . . . . 5,412 9,035 19 Canada. . . . . . . . . . . . . . 59,069 60,715

20 Azerbaijan. . . . . . . . . . . 7,000 - 20 Netherlands . . . . . . . . . . 62,000 55,515

21 Oman . . . . . . . . . . . . . . 5,506 4,803 21 Kuwaitc.............. d55,500 d56,600

22 India . . . . . . . . . . . . . . . 5,371 4,936 22 China . . . . . . . . . . . . . . . 53,325 51,377

23 Ecuador . . . . . . . . . . . . 4,630 5,500 23 Libyac. . . . . . . . . . . . . . . 46,400 51,500

24 Indonesiac . . . . . . . . . . 4,700 5,295 24 Ukraine. . . . . . . . . . . . . . 39,600 -

25 United Kingdom . . . . . . 4,487 3,908 25 Oman . . . . . . . . . . . . . . . 29,280 24,240

Top 25 Total. . . . . . . . . . . . . . 1,238,808 1,013,381 Top 25 Total . . . . . . . . . . . . . . 5,703,087 6,181,456

OPEC Total . . . . . . . . . . . . . . 885,188 840,638 OPEC Total . . . . . . . . . . . . . . . 3,086,800 3,086,320

World Total . . . . . . . . . . . . . . 1,277,182 1,081,813 World Total . . . . . . . . . . . . . . . 6,040,208 6,994,298

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, Vol. 102, No. 47 (December 20, 2004). Gulf Publishing Company, World

Oil, Vol. 226, No. 9 (September, 2005).

Energy Information Administration

18 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report
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 2004. 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 2004 was 71,733 million barrels. This

substantially exceeds the 1977 proved reserves, but at

the end of 2004 there were still 22,592 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 2004. 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 2004

and there were still 201,200 billion cubic feet of wet

natural gas proved reserves in 2004. Only 11 percent of

proved reserve additions of natural gas were booked as

new field discoveries from 1976 through 2004.

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 1.2 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 2004. 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 2004. 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 {35} estimate for world oil

reserves increased 1 percent in 2004 owing to an

increase in its estimate of Kuwait’s reserves. The World

Oil {36} estimate increased 3 percent in 2004 due to its

larger estimate of Saudi Arabia and Iran’s reserves. For

world gas reserves, the Oil & Gas Journal reported a 0.5

percent increase, while World Oil reported a 0.3 percent

increase in 2004.

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 about 3 times U.S. Reserves based on

averages of the World Oil and Oil & Gas Journal

estimates.

Petroleum Consumption

The United States is the world's largest energy

consumer. The EIA estimates energy consumption and

publishes it in its Annual Energy Review.{37} In 2004:

The U.S. consumed 99,740,000,000,000,000 Btu of

energy (99.7 quadrillion Btu). This was an

increase of 1.43 quadrillion Btu from the 2003

level of consumption.

63 percent of U.S. energy consumption was

provided by petroleum and natural gas—crude

oil and natural gas liquids combined (40

percent), and natural gas (23 percent).

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 19
U.S. petroleum consumption was about 21

million barrels of oil and natural gas liquids

and 61 billion cubic feet of gas per day.

Dependence on Imports

The United States remains dependent on imported oil

and gas. In 2004, crude oil imports made up 63 percent

of the U.S. crude oil supply. Canada, Mexico, Saudi

Arabia, Venezuela, Nigeria, and Iraq were the primary

foreign suppliers of petroleum to the United States.{38}

Net gas imports increased from the 2003 total of 3.93

trillion cubic feet to 4.26 trillion cubic feet in 2004.

Imports satisfied approximately 19 percent of

consumption. Almost all of this gas was pipelined from

Canada. Some liquefied natural gas was imported from

Trinidad and Tobago and Algeria.

List Of Appendices

Appendix A: Operator Level Data - 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. Table A6 in Appendix A lists

the top U.S. operators by reported 2004 production.

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 2004, ranking the top

100 oil and natural gas fields by their 2004 production

rather than their proved reserves.

Appendix C: Conversion to the Metric System - To

simplify international comparisons, a summary of U.S.

Crude Oil, Natural Gas, and Natural Gas Liquids

Reserves expressed in metric units is included as

Appendix C.

Appendix D: Historical Reserves Statistics -

Appendix D contains selected historical reserves data

presented at the State and National level. Readers

interested in a historical look at one specific State or

region can review these tables. We have again included

Table D9, Deepwater Production and Proved Reserves

of the Gulf of Mexico Federal Offshore 1994-2004, due

to expressed interest from the industry regarding this

area. Table D9 contains the production and proved

reserves for 1994-2004 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 2004 Annual Report
3. Crude Oil Statistics

The United States had 21,371 million barrels of crude

oil proved reserves as of December 31, 2004. Crude oil

proved reserves declined by 2 percent in 2004 owing

mostly to a large 9 percent decrease in the Gulf of

Mexico.

Boosted by reserves additions in Wyoming, Montana,

North Dakota, and Texas, the crude oil proved reserves

of the onshore lower 48 States increased by 0.1 percent.

However, three of the four largest crude oil reserves

areas, the Gulf of Mexico, Alaska, and California,

registered reserves declines. U.S. new field discoveries

were the lowest in 12 years and as a result operators

only replaced 71 percent of crude oil production with

reserves additions. (Figure 15).

Proved Reserves

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

as of December 31, 2004, by selected States and State

subdivisions.

Figure 16 maps 2004 crude oil proved reserves by area.

The following four areas account for 77 percent of U.S.

crude oil proved reserves:

Percent of

Area U.S. Oil Reserves

Texas 22

Alaska 20

Gulf of Mexico Federal Offshore 19

California 16

Area Total 77

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 21

Figure 15. Replacement of U.S. Crude Oil Production by Reserves Additions, 1994-2004.

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

22 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

aIndicates the estimate is associated with a sampling error (95 percent confidence interval) that exceeds 20 percent of the estimated value. 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 2004 contained in the

Petroleum Supply Annual 2004, DOE/EIA-0340(04).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 4,446 -1 191 144 0 0 111 0 58 334 4,327

Lower 48 States . . . . . . . . . . . . . 17,445 75 1,748 1,375 937 960 506 33 74 1,485 17,044

Alabama. . . . . . . . . . . . . . . . . . . . 52 2 0 4 0 0 8 0 0 5 53

Arkansas . . . . . . . . . . . . . . . . . . . 50 1 4 1 0 0 1 2 0 6 51

California . . . . . . . . . . . . . . . . . . . 3,452 3 210 97 142 147 42 0 0 239 3,376

Coastal Region Onshore . . . . . 395 -5 16 23 11 17 8 0 0 17 380

Los Angeles Basin Onshore. . . 319 4 7 50 0 0 22 0 0 16 286

San Joaquin Basin Onshore . . 2,565 4 154 20 114 115 10 0 0 191 2,523

State Offshore . . . . . . . . . . . . . 173 0 33 4 17 15 2 0 0 15 187

Colorado . . . . . . . . . . . . . . . . . . . 217 -1 16 4 10 13 12 0 0 18 225

Florida . . . . . . . . . . . . . . . . . . . . . 68 1 0 1 0 0 0 0 0 3 65

Illinois. . . . . . . . . . . . . . . . . . . . . . 125 -7 11 2 25 0 0 0 0 10 92

Indiana . . . . . . . . . . . . . . . . . . . . . 19 -6 2 0 2 0 0 0 0 2 11

Kansas. . . . . . . . . . . . . . . . . . . . . 243 10 38 13 15 11 4 0 0 33 245

Kentucky . . . . . . . . . . . . . . . . . . . 25 3 1 2 0 0 2 0 0 2 a27

Louisiana . . . . . . . . . . . . . . . . . . . 452 0 67 71 31 29 32 2 4 57 427

North . . . . . . . . . . . . . . . . . . . . 66 3 10 14 2 1 3 0 0 9 58

South Onshore. . . . . . . . . . . . . 314 -3 42 43 21 21 25 2 3 36 304

State Offshore . . . . . . . . . . . . . 72 0 15 14 8 7 4 0 1 12 65

Michigan . . . . . . . . . . . . . . . . . . . 75 -12 2 9 0 0 2 0 0 5 53

Mississippi . . . . . . . . . . . . . . . . . . 169 -5 32 2 4 5 0 0 0 17 178

Montana. . . . . . . . . . . . . . . . . . . . 315 -5 54 32 5 10 47 0 2 22 364

Nebraska . . . . . . . . . . . . . . . . . . . 16 1 1 1 0 1 0 0 0 3 15

New Mexico . . . . . . . . . . . . . . . . . 677 11 60 48 76 72 32 0 1 60 669

East . . . . . . . . . . . . . . . . . . . . . 668 13 58 47 76 72 32 0 1 59 662

West. . . . . . . . . . . . . . . . . . . . . 9 -2 2 1 0 0 0 0 0 1 7

North Dakota . . . . . . . . . . . . . . . . 353 -4 167 115 27 32 14 0 1 32 389

Ohio . . . . . . . . . . . . . . . . . . . . . . . 66 -16 6 3 0 0 1 0 0 5 49

Oklahoma . . . . . . . . . . . . . . . . . . 588 23 96 104 56 58 15 0 1 51 570

Pennsylvania . . . . . . . . . . . . . . . . 13 1 1 2 0 0 1 0 0 2 12

Texas . . . . . . . . . . . . . . . . . . . . . . 4,583 71 401 261 229 281 125 2 0 360 4,613

RRC District 1 . . . . . . . . . . . . . 59 -1 9 2 4 2 2 1 0 8 58

RRC District 2 Onshore . . . . . . 51 9 2 4 1 1 6 0 0 8 56

RRC District 3 Onshore . . . . . . 190 24 50 47 16 9 3 0 0 28 185

RRC District 4 Onshore . . . . . . 30 1 6 7 0 0 1 0 0 4 27

RRC District 5 . . . . . . . . . . . . . 20 0 7 1 0 1 0 0 0 4 23

RRC District 6 . . . . . . . . . . . . . 189 13 8 12 1 2 4 0 0 16 187

RRC District 7B . . . . . . . . . . . . 68 4 11 2 8 6 4 0 0 10 73

RRC District 7C . . . . . . . . . . . . 205 -3 9 10 8 9 20 0 0 16 206

RRC District 8 . . . . . . . . . . . . . 1,513 7 120 95 81 129 67 1 0 109 1,552

RRC District 8A . . . . . . . . . . . . 2,089 9 162 56 104 112 14 0 0 136 2,090

RRC District 9 . . . . . . . . . . . . . 114 4 10 15 3 4 3 0 0 15 102

RRC District 10 . . . . . . . . . . . . 48 1 6 9 2 5 1 0 0 5 45

State Offshore ............. 7 3 1 1 1 1 0 0 0 1 9

Utah . . . . . . . . . . . . . . . . . . . . . . . 221 3 14 17 27 27 7 0 0 13 215

West Virginia . . . . . . . . . . . . . . . . 13 -4 3 0 0 0 0 0 0 1 11

Wyoming . . . . . . . . . . . . . . . . . . . 517 4 110 23 54 56 61 0 0 43 628

Federal Offshore . . . . . . . . . . . . . 5,120 3 450 562 234 218 99 27 65 495 4,691

Pacific (California) . . . . . . . . . . 566 1 24 14 103 97 4 0 0 28 547

Gulf of Mexico (Louisiana) . . . . 4,251 2 319 448 106 119 94 27 65 404 3,919

Gulf of Mexico (Texas) . . . . . . . 303 0 107 100 25 2 1 0 0 63 225

Miscellaneousb . . . . . . . . . . . . . . 16 -2 2 1 0 0 1 0 0 1 15

U.S. Total . . . . . . . . . . . . . . . . . . 21,891 74 1,939 1,519 937 960 617 33 132 1,819 21,371

Table 6. Crude Oil Proved Reserves, Reserves Changes, and Production, 2004

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 2004

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 12/31/03 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/04
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 23

Figure 17. Changes in Crude Oil Proved Reserves by Area, 2003 to 2004

Figure 16. Crude Oil Proved Reserves by Area, 2004

Source: Energy Information Administration, Office of Oil and Gas.
Of these four areas, only Texas had an increase in crude

oil proved reserves in 2004 (less than 1 percent). The

Gulf of Mexico reported a 9 percent decrease, Alaska

declined 3 percent, and California declined 2 percent.

Discussion of Reserves Changes

Figure 17 maps the change in crude oil proved reserves

from 2003 to 2004 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 +30

Alaska -119

Gulf of Mexico Federal Offshore -410

California -76

Area Total -575

U.S. Total -520

Figure 2 in Chapter 2 shows the components of the

changes in crude oil proved reserves for 2004 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 new wells.

Total discoveries of crude oil were 782 million barrels

in 2004, 37 percent less than those of 2003. Only four

areas had total discoveries exceeding 50 million barrels

in 2004:

The Gulf of Mexico Federal Offshore had 187

million barrels of total discoveries, 24 percent of

the National total.

Alaska had 169 million barrels of total

discoveries, 22 percent of the National total.

Texas had 127 million barrels of total

discoveries, 16 percent of the National total.

Wyoming had 61 million barrels of total

discoveries, 8 percent of the National total.

The United States discovered an average of 1,105

million barrels of new crude oil proved reserves per

year in the prior 10 years. Total discoveries in 2004

were 29 percent lower than that average.

Extensions

Operators reported 617 million barrels of extensions in

2004, 45 percent more than in 2003. The highest volume

of extensions was reported in Texas (125 million

barrels). The second highest volume of extensions in

2004 was in Alaska with 111 million barrels. The Gulf of

Mexico Federal Offshore reported 95 million barrels of

extensions. Wyoming was fourth with 61 million

barrels of extensions.

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

average of 422 million barrels of extensions per year.

The 2004 extensions were 22 percent more than that

average.

New Field Discoveries

There were 33 million barrels of new field discoveries

of crude oil reported in 2004. This is 95 percent less than

in 2003 and the lowest volume reported in twelve

years. Only four areas in the United States reported any

new field discoveries. The Gulf of Mexico Federal

Offshore had 27 million barrels (82 percent), and

Arkansas, Louisiana, and Texas each had 2 million

barrels of new field discoveries.

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

annual average of 422 million barrels of reserves from

new field discoveries. Reserves from new field

discoveries in 2004 were 92 percent less than that

average.

New Reservoir Discoveries in Old Fields

Operators reported 132 million barrels of crude oil

reserves from new reservoir discoveries in old fields in

2004. This is 31 percent more than 2003 and most of the

Energy Information Administration

24 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report
new reservoir discoveries in old fields came from two

areas: the Gulf of Mexico Federal Offshore—65 million

barrels (49 percent) and Alaska --58 million barrels (44

percent). The remaining 9 million barrels (7 percent) of

new reservoirs were discovered in Louisiana,

Montana, New Mexico, North Dakota, and Oklahoma.

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

average of 178 million barrels of reserves from new

reservoir discoveries in old fields. Reserves from new

reservoir discoveries in old fields in 2004 were 26

percent less than that average.

Revisions and Adjustments

Thousands of positive and negative revisions to

proved reserves occur each year as development 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 1,939 million barrels of revision increases,

1,519 million barrels of revision decreases, and 74

million barrels of adjustments in 2004. Combined, there

were 494 million barrels of net revisions and

adjustments for crude oil in 2004.

In the prior 10 years, net revisions and adjustments

added an annual average of 865 million barrels. The

2004 net revisions and adjustments were 43 percent less

than that average.

Sales and Acquisitions

Sales represents that volume of crude oil proved

reserves deducted from an operator’s total reserves 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 reserves through purchase or

operations transfer of an existing oil field or properties.

There are several reasons why sales and acquisitions

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

operatorship. Timing of the transfer of operations can

also impact these values.

In 2004, there were 937 million barrels of sales

transactions between operators and 960 million barrels

of acquisitions yielding a net difference of +23 million

barrels.

Production

U.S. production of crude oil in 2004 was an estimated

1,819 million barrels. This volume does not include

lease condensate. This was less than 3 percent lower

than 2003’s production of 1,877 million barrels.

In the last quarter of 2004, Hurricane Ivan disrupted

production operations in the Gulf of Mexico by

damaging surface facilities and triggering underwater

mudslides that destroyed sections of sea-bottom

pipelines. Production from the Gulf of Mexico Federal

Offshore dropped 4 percent from 2003 to 2004. Despite

this, the Gulf remained the largest producing area in

the United States with 26 percent of the National total

(467 million barrels of production). Texas and Alaska

were second and third, with 20 and 18 percent of the

National production total, respectively. California was

fourth with 13 percent.

The 2004 Form EIA-23 National production estimates

(2,001 million barrels of crude oil and lease condensate)

are 1 percent higher than the comparable Petroleum

Supply Annual (PSA) 2004 volumes for crude oil and

lease condensate production combined (1,983 million

barrels).

Areas of Note: Large Discoveries

and Reserves Additions

The following State and area discussions summarize

notable activities during 2004 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 2004.

Wyoming

Wyoming led the Nation in net crude oil proved

reserves additions in 2004, adding 111 million barrels

to the National total.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 25
Salt Creek Field: Of particular note are the new

carbon dioxide (CO2) injection enhanced oil

recovery projects begun by Anadarko Petroleum

Corporation, which completed construction of a

pipeline to deliver CO2 to Salt Creek, Monell,

and Sussex fields in Wyoming in early 2004.

Anadarko reports that the fields’ production

responses have met expectations.” {39}

Montana

Montana reported a net increase of 49 million barrels of

crude oil proved reserves in 2004. Montana’s

production also increased by 16 percent to 22 million

barrels in 2004.

Cedar Creek Anticline: Burlington Resources is

conducting two of the world’s largest

horizontally drilled waterflooding programs on

the eastern flank of the Cedar Creek Anticline,

centered in the 50-year old East Lookout Butte

and Cedar Hills South fields. Burlington

implemented a waterflood and 320-acre well

spacing, and also extended the original

horizontal wells to lateral lengths of 8,000 feet or

more to improve waterflood response. These

efforts have boosted the [estimated ultimate

recovery] from the original 2 percent to 30

percent of the oil in place. Production has

responded substantially, more than doubling in

2004. Capital investments in 2004 of $113 million

included drilling 47 new producing wells and

eight injection wells.{40}

North Dakota

North Dakota reported a net increase of 36 million

barrels of proved oil reserves in 2004. Like Montana,

this State is a beneficiary of increased activity at the

Cedar Creek Anticline, which straddles the border of

both States. (See Cedar Creek Anticline bullet, above.)

North Dakota’s oil production rose 6 percent in 2004.

Texas

Texas reported a net increase of 30 million barrels of

proved oil reserves in 2004 and had the largest volume

of extensions in 2004 (125 million barrels). The majority

of these extensions were to fields located in the

Permian Basin.

Other Gain Areas

Mississippi: Mississippi reported a net increase of 9

million barrels of crude oil proved reserves in 2004.

Colorado: Colorado reported a net increase of 8 million

barrels of crude oil proved reserves in 2004.

Areas of Note:

Large Reserves Declines

The following areas had large declines in crude oil

proved reserves due to downward revisions or

unreplaced production.

Gulf of Mexico Federal Offshore

The Gulf of Mexico Federal Offshore crude oil proved

reserves declined 9 percent (-410 million barrels) in

2004. Operators also reported a production decrease of

4 percent (-18 million barrels) from the 2003 level.

Hurricane Ivan’s damage was a factor, as mentioned

previously. In its aftermath, U.S. Secretary of Energy

Spencer Abraham agreed to loan out 1.7 million barrels

of oil from the Strategic Petroleum Reserve.

Alaska

Alaskan crude oil proved reserves declined 3 percent

(-119 million barrels) in 2004. No new field discoveries

were reported in Alaska in 2004 and Alaska’s proved

reserves additions did not offset its oil production.

Alaska’s estimated 2004 production of 334 million

barrels decreased 6 percent (-23 million barrels) from

the 2003 level.

California

There was a net decline of 2 percent (-76 million barrels)

in California’s crude oil proved reserves in 2004.

California’s crude oil production declined 3 percent (-7

million barrels) from its 2003 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:

Illinois: Proved oil reserves decreased by

26 percent (-33 million barrels). A large

volume of reported sales was not reported

by any operator as an acquisition in 2004.

Energy Information Administration

26 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report
Louisiana: Proved oil reserves decreased

by 6 percent (-25 million barrels).

Reserves in

Nonproducing Status

Not all proved reserves of crude oil reported in 2004

were producing. Operators reported 5,143 million

barrels of proved reserves in nonproducing status, 8

percent less than reported in 2003 (5,580 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 2004 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,” 2004.

Table 7. Reported Reserves in Nonproducing Status for Crude Oil, 2004 a

(Million Barrels of 42 U.S. Gallons)

Nonproducing Nonproducing Crude Oil Crude Oil

State and Subdivision Reserves State and Subdivision Reserves

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 707

Lower 48 States............................. 4,436

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

Arkansas .................................. 3

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 267

Coastal Region Onshore . . . . . . . . . . . . . . . . . . . 16

Los Angeles Basin Onshore . . . . . . . . . . . . . . . . . 63

San Joaquin Basin Onshore. . . . . . . . . . . . . . . . . 158

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

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

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

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

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

Kansas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Kentucky .................................. 5

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150

North. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

South Onshore . . . . . . . . . . . . . . . . . . . . . . . . . . . 115

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

Montana. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104

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

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

East. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

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

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

North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Ohio ...................................... 7

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

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

Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 625

RRC District 1............................ 9

RRC District 2 Onshore . . . . . . . . . . . . . . . . . . . . 13

RRC District 3 Onshore . . . . . . . . . . . . . . . . . . . . 21

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

RRC District 5............................ 1

RRC District 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

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

RRC District 7C . . . . . . . . . . . . . . . . . . . . . . . . . . 14

RRC District 8. . . . . . . . . . . . . . . . . . . . . . . . . . . . 218

RRC District 8A. . . . . . . . . . . . . . . . . . . . . . . . . . . 311

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

RRC District 10........................... 5

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

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

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

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

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

Federal Offshore ............................ 2,708

Pacific (California). . . . . . . . . . . . . . . . . . . . . . . . . 55

Gulf of Mexico (Louisiana) .................. 2,581

Gulf of Mexico (Texas) . . . . . . . . . . . . . . . . . . . . . 72

Miscellaneousb ............................. 4

U.S. Total ................................. 5,143

4. Natural Gas Statistics

Dry Natural Gas

Proved Reserves

The United States had 192,513 billion cubic feet of dry

natural gas reserves as of December 31, 2004, a 2

percent increase over the 2003 level (Table 8). All

natural gas proved reserves data shown in this report

exclude natural gas held in underground storage.

U.S. natural gas reserves increased for the sixth year in

a row in 2004. The U.S. total went up even though Gulf

of Mexico natural gas proved reserves dropped an

unusually large 15 percent primarily due to low new

discoveries. Discoveries of new gas fields nationwide

were the lowest in 12 years. Nevertheless, because

onshore lower 48 States total discoveries were almost

18 trillion cubic feet, total U.S. reserves additions

replaced 118 percent of 2004 dry gas production

(Figure 18).

U.S. dry gas production declined 1 percent in 2004.

Twenty percent of U.S. dry natural gas production

comes from the Gulf of Mexico Federal Offshore which

reported a 10 percent drop in production in 2004.

Hurricane Ivan caused infrastructure damage that

impacted oil and gas production in the Gulf in the last

quarter of 2004 and will also reduce 2005 Gulf

production from what it could have been.

The proved reserves by State are shown on the map in

Figure 19. Six areas account for 74 percent of the

Nation’s dry natural gas proved reserves:

Percent of

Area U.S. Gas Reserves

Texas 26

Wyoming 12

Gulf of Mexico Federal Offshore 10

New Mexico 10

Colorado 8

Oklahoma 8

Area Total 74

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 29

Figure 18. Replacement of U.S. Dry Natural Gas Production by Reserves Additions, 1994-2004.

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

30 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

aIndicates the estimate is associated with a sampling error (95 percent confidence interval) that exceeds 20 percent of the estimated value. bIncludes Federal offshore Alabama.

cIncludes 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 2004 contained in the Natural Gas Annual 2004, DOE/EIA-0131(04).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 8,285 -1 632 207 0 0 141 0 35 478 8,407

Lower 48 States ............. 180,759 -113 26,261 25,942 11,106 12,950 18,057 759 1,171 18,690 184,106

Alabama. . . . . . . . . . . . . . . . . . . . 4,301 34 162 155 29 0 131 3 0 327 4,120

Arkansas . . . . . . . . . . . . . . . . . . . 1,663 13 200 91 24 52 170 4 18 170 1,835

California . . . . . . . . . . . . . . . . . . . 2,450 19 440 152 128 147 100 0 5 247 2,634

Coastal Region Onshore . . . . . 167 -3 32 9 3 7 8 0 0 10 189

Los Angeles Basin Onshore. . . 187 1 4 48 0 0 40 0 0 10 174

San Joaquin Basin Onshore . . 2,013 26 389 94 123 138 51 0 5 220 2,185

State Offshore . . . . . . . . . . . . . 83 -5 15 1 2 2 1 0 0 7 86

Colorado . . . . . . . . . . . . . . . . . . . 15,436 -55 1,505 2,167 2,528 2,397 1,017 171 17 1,050 14,743

Florida . . . . . . . . . . . . . . . . . . . . . 79 3 0 1 0 0 0 0 0 3 78

Kansas. . . . . . . . . . . . . . . . . . . . . 4,819 24 750 647 140 174 47 1 0 376 4,652

Kentucky . . . . . . . . . . . . . . . . . . . 1,889 -40 176 153 5 0 96 0 0 83 1,880

Louisiana . . . . . . . . . . . . . . . . . . . 9,325 -11 1,089 1,229 935 592 1,940 18 121 1,322 9,588

North . . . . . . . . . . . . . . . . . . . . 5,074 -12 348 417 588 281 1,521 5 11 453 5,770

South Onshore. . . . . . . . . . . . . 3,745 60 629 681 281 250 392 9 83 770 3,436

State Offshore . . . . . . . . . . . . . 506 -59 112 131 66 61 27 4 27 99 382

Michigan . . . . . . . . . . . . . . . . . . . 3,428 -97 205 360 13 14 90 0 31 207 3,091

Mississippi . . . . . . . . . . . . . . . . . . 746 20 48 55 18 9 27 0 7 93 691

Montana. . . . . . . . . . . . . . . . . . . . 1,059 -56 73 124 3 3 131 1 6 95 995

New Mexico . . . . . . . . . . . . . . . . . 17,020 126 2,757 1,771 682 1,323 1,243 20 3 1,527 18,512

East . . . . . . . . . . . . . . . . . . . . . 3,301 80 646 467 263 434 383 20 3 516 3,621

West. . . . . . . . . . . . . . . . . . . . . 13,719 46 2,111 1,304 419 889 860 0 0 1,011 14,891

New York . . . . . . . . . . . . . . . . . . . 365 -93 81 75 12 15 87 0 0 44 a324

North Dakota . . . . . . . . . . . . . . . . 448 -29 86 57 11 22 7 0 2 51 417

Ohio . . . . . . . . . . . . . . . . . . . . . . . 1,126 -138 103 64 0 0 29 0 0 82 974

Oklahoma . . . . . . . . . . . . . . . . . . 15,401 -113 2,173 1,912 511 763 1,983 8 9 1,563 16,238

Pennsylvania . . . . . . . . . . . . . . . . 2,487 -188 657 567 28 29 123 0 3 155 2,361

Texas . . . . . . . . . . . . . . . . . . . . . . 45,730 674 7,442 6,397 2,780 4,137 5,891 264 312 5,318 49,955

RRC District 1 . . . . . . . . . . . . . 1,062 57 111 128 82 91 92 100 1 120 1,184

RRC District 2 Onshore . . . . . . 1,770 3 272 343 154 283 262 13 34 296 1,844

RRC District 3 Onshore . . . . . . 3,349 175 704 901 201 176 344 58 63 582 3,185

RRC District 4 Onshore . . . . . . 8,763 43 1,248 1,531 547 774 1,157 7 80 1,295 8,699

RRC District 5 . . . . . . . . . . . . . 5,407 68 1,068 421 295 622 509 7 48 490 6,523

RRC District 6 . . . . . . . . . . . . . 6,685 92 891 663 207 481 946 18 78 683 7,638

RRC District 7B . . . . . . . . . . . . 340 52 23 64 19 22 7 0 0 51 310

RRC District 7C . . . . . . . . . . . . 4,327 -21 829 458 271 293 316 0 1 348 4,668

RRC District 8 . . . . . . . . . . . . . 5,142 7 697 730 269 372 527 44 4 493 5,301

RRC District 8A . . . . . . . . . . . . 1,056 -4 234 37 17 46 14 4 0 108 1,188

RRC District 9 . . . . . . . . . . . . . 3,309 14 423 210 517 552 1,062 0 0 412 4,221

RRC District 10 . . . . . . . . . . . . 4,064 184 777 705 74 345 654 3 0 375 4,873

State Offshore . . . . . . . . . . . . . 456 4 165 206 127 80 1 10 3 65 321

Utah . . . . . . . . . . . . . . . . . . . . . . . 3,516 113 475 278 946 953 299 5 11 282 3,866

Virginia. . . . . . . . . . . . . . . . . . . . . 1,717 -19 39 69 0 0 146 0 0 72 1,742

West Virginia . . . . . . . . . . . . . . . . 3,306 -287 664 256 71 25 185 0 1 170 3,397

Wyoming . . . . . . . . . . . . . . . . . . . 21,744 50 2,853 3,586 865 811 3,105 8 36 1,524 22,632

Federal Offshoreb . . . . . . . . . . . . 22,570 -61 4,276 5,734 1,375 1,482 1,193 252 589 3,921 19,271

Pacific (California) . . . . . . . . . . 511 0 22 17 113 103 0 0 0 47 459

Gulf of Mexico (Louisiana)b . . . 16,728 -85 2,034 3,201 998 1,177 1,110 208 514 2,802 14,685

Gulf of Mexico (Texas) . . . . . . . 5,331 24 2,220 2,516 264 202 83 44 75 1,072 4,127

Miscellaneousc . . . . . . . . . . . . . . 134 -2 7 42 2 2 17 4 0 8 110

U.S. Total . . . . . . . . . . . . . . . . . . 189,044 -114 26,893 26,149 11,106 12,950 18,198 759 1,206 19,168 192,513

Table 8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 2004

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

Changes in Reserves During 2004

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 12/31/03 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/04
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 31

Figure 20. Changes in Dry Natural Gas Proved Reserves by Area, 2003 to 2004

Figure 19. Dry Natural Gas Proved Reserves by Area, 2004

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

Figure 20 maps the change in dry gas proved reserves

from 2003 to 2004 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 +4,225

Wyoming +888

Gulf of Mexico Federal Offshore -3,247

New Mexico +1,492

Oklahoma +837

Colorado -693

Area Total +3,502

U.S. Total +3,469

Figure 4 in Chapter 2 shows the components of change

in dry natural gas proved reserves for 2004 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 20,163 billion cubic feet in 2004, a 5

percent increase from the level reported in 2003. About

32 percent of the total discoveries were in Texas, 16

percent were in Wyoming, 10 percent were in the Gulf

of Mexico Federal Offshore, 10 percent were in

Louisiana, 10 percent were in Oklahoma, and 6 percent

were in New Mexico.

Extensions

The largest component of total discoveries in 2004 was

extensions of existing gas fields. Extensions were

18,198 billion cubic feet, 11 percent more than 2003 and

66 percent more than the prior 10-year average (10,976

billion cubic feet). Areas with the largest extensions

and their percentage of total extensions were:

Texas had 5,891 billion cubic feet of extensions

(32 percent of the total)

Wyoming had 3,105 billion cubic feet (17

percent)

Oklahoma had 1,983 billion cubic feet (11

percent)

Louisiana had 1,940 billion cubic feet (11

percent)

New Mexico had 1,243 billion cubic feet (7

percent)

Gulf of Mexico Federal Offshore had 1,193

billion cubic feet (7 percent)

Colorado had 1,017 billion cubic feet (6 percent).

New Field Discoveries

New field discoveries were 759 billion cubic feet in

2004—38 percent less than in 2003. The areas with the

largest new field discoveries were Texas (with 264

billion cubic feet of new field discoveries; 35 percent of

the total), the Gulf of Mexico Federal Offshore (252

billion cubic feet; 33 percent of the total), and Colorado

(171 billion cubic feet; 23 percent of the total). In the

prior 10 years, U.S. operators had reported an annual

average of 1,845 billion cubic feet of reserves from new

field discoveries. Reserves from new field discoveries

in 2004 were the lowest since 1992 and 59 percent less

than the prior 10 year average.

New Reservoir Discoveries in Old Fields

New reservoir discoveries in old fields were 1,206

billion cubic feet, 25 percent less than 2003. The areas

with the largest new reservoir discoveries in old fields

and their percentage of the total were:

Gulf of Mexico Federal Offshore (589 billion

cubic feet; 49 percent of the total)

Texas (312 billion cubic feet; 26 percent of the

total)

Louisiana (121 billion cubic feet; 10 percent of

the total).

Energy Information Administration

32 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 33

aIndicates the estimate is associated with a sampling error (95 percent confidence interval) that exceeds 20 percent of the estimated value. bIncludes Federal offshore Alabama.

cIncludes 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 2004 contained in the

Natural Gas Annual 2004, DOE/EIA-0131(04).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 8,348 0 638 208 0 0 141 0 35 481 8,473

Lower 48 States ............. 188,797 170 27,478 27,083 11,583 13,558 18,927 790 1,209 19,536 192,727

Alabama. . . . . . . . . . . . . . . . . . . . 4,345 31 164 157 30 0 133 3 0 330 4,159

Arkansas . . . . . . . . . . . . . . . . . . . 1,666 12 200 91 24 52 170 4 18 170 1,837

California . . . . . . . . . . . . . . . . . . . 2,569 30 462 160 135 154 107 0 5 259 2,773

Coastal Region Onshore . . . . . 174 -4 33 10 3 7 9 0 0 10 196

Los Angeles Basin Onshore. . . 196 2 4 50 0 0 42 0 0 10 184

San Joaquin Basin Onshore . . 2,116 36 410 99 130 145 55 0 5 232 2,306

State Offshore . . . . . . . . . . . . . 83 -4 15 1 2 2 1 0 0 7 87

Colorado . . . . . . . . . . . . . . . . . . . 15,893 14 1,556 2,241 2,615 2,480 1,053 177 18 1,086 15,249

Florida . . . . . . . . . . . . . . . . . . . . . 92 0 0 1 0 0 0 0 0 3 88

Kansas. . . . . . . . . . . . . . . . . . . . . 5,143 66 806 695 151 187 50 1 0 404 5,003

Kentucky . . . . . . . . . . . . . . . . . . . 1,971 -21 185 162 5 0 101 0 0 87 1,982

Louisiana . . . . . . . . . . . . . . . . . . . 9,538 -13 1,119 1,263 954 606 1,973 18 126 1,358 9,792

North . . . . . . . . . . . . . . . . . . . . 5,137 -9 352 423 596 284 1,539 5 11 459 5,841

South Onshore. . . . . . . . . . . . . 3,874 63 652 705 290 259 406 9 86 797 3,557

State Offshore . . . . . . . . . . . . . 527 -67 115 135 68 63 28 4 29 102 394

Michigan . . . . . . . . . . . . . . . . . . . 3,488 -87 209 367 14 15 91 0 31 212 3,154

Mississippi . . . . . . . . . . . . . . . . . . 748 19 49 55 18 8 27 0 7 93 692

Montana. . . . . . . . . . . . . . . . . . . . 1,068 -59 73 125 2 3 132 1 6 95 1,002

New Mexico . . . . . . . . . . . . . . . . . 18,226 8 2,936 1,888 731 1,414 1,328 22 4 1,632 19,687

East . . . . . . . . . . . . . . . . . . . . . 3,661 40 707 512 288 476 420 22 4 565 3,965

West. . . . . . . . . . . . . . . . . . . . . 14,565 -32 2,229 1,376 443 938 908 0 0 1,067 15,722

New York . . . . . . . . . . . . . . . . . . . 365 -93 81 75 12 15 87 0 0 44 a324

North Dakota . . . . . . . . . . . . . . . . 497 -30 96 64 12 25 8 0 2 57 465

Ohio . . . . . . . . . . . . . . . . . . . . . . . 1,127 -138 103 64 0 0 29 0 0 82 975

Oklahoma . . . . . . . . . . . . . . . . . . 16,231 -37 2,302 2,026 541 808 2,100 9 10 1,656 17,200

Pennsylvania . . . . . . . . . . . . . . . . 2,497 -188 660 569 28 29 123 0 3 156 2,371

Texas . . . . . . . . . . . . . . . . . . . . . . 48,717 797 7,930 6,830 2,958 4,393 6,284 280 324 5,662 53,275

RRC District 1 . . . . . . . . . . . . . 1,095 66 115 133 85 95 95 104 1 124 1,229

RRC District 2 Onshore . . . . . . 1,849 13 286 360 162 296 275 13 35 311 1,934

RRC District 3 Onshore . . . . . . 3,548 214 751 962 214 188 367 62 67 621 3,400

RRC District 4 Onshore . . . . . . 9,055 126 1,301 1,595 571 806 1,205 7 83 1,350 9,067

RRC District 5 . . . . . . . . . . . . . 5,460 67 1,077 425 298 628 514 7 48 495 6,583

RRC District 6 . . . . . . . . . . . . . 6,959 110 929 692 216 502 987 19 81 713 7,966

RRC District 7B . . . . . . . . . . . . 383 79 27 76 22 25 8 0 0 60 364

RRC District 7C . . . . . . . . . . . . 4,791 -3 922 509 301 325 351 0 1 387 5,190

RRC District 8 . . . . . . . . . . . . . 5,835 -6 789 826 304 421 597 50 5 559 6,002

RRC District 8A . . . . . . . . . . . . 1,137 -2 252 40 18 49 16 4 0 117 1,281

RRC District 9 . . . . . . . . . . . . . 3,639 -53 457 226 559 596 1,146 0 0 445 4,555

RRC District 10 . . . . . . . . . . . . 4,510 183 859 780 82 381 722 4 0 414 5,383

State Offshore . . . . . . . . . . . . . 456 3 165 206 126 81 1 10 3 66 321

Utah . . . . . . . . . . . . . . . . . . . . . . . 3,617 93 485 284 966 974 305 5 11 289 3,951

Virginia. . . . . . . . . . . . . . . . . . . . . 1,717 -19 39 69 0 0 146 0 0 72 1,742

West Virginia . . . . . . . . . . . . . . . . 3,399 -281 686 265 73 26 191 0 1 175 3,509

Wyoming . . . . . . . . . . . . . . . . . . . 22,716 47 2,980 3,745 904 847 3,244 8 38 1,591 23,640

Federal Offshoreb . . . . . . . . . . . . 23,033 20 4,349 5,844 1,408 1,520 1,228 258 605 4,014 19,747

Pacific (California) . . . . . . . . . . 511 1 22 17 114 103 0 0 0 47 459

Gulf of Mexico (Louisiana)b . . . 17,168 -5 2,098 3,301 1,029 1,214 1,145 214 530 2,890 15,144

Gulf of Mexico (Texas) . . . . . . . 5,354 24 2,229 2,526 265 203 83 44 75 1,077 4,144

Miscellaneousc . . . . . . . . . . . . . . 134 -1 8 43 2 2 17 4 0 9 110

U.S. Total . . . . . . . . . . . . . . . . . . 197,145 170 28,116 27,291 11,583 13,558 19,068 790 1,244 20,017 201,200

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

2004 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 2004

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 12/31/03 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/04
Energy Information Administration

34 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

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

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

Reserves.” They may differ from the official Energy Information Administration production data for natural gas for 2004 contained in the

Natural Gas Annual 2004, DOE/EIA-0131(04).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 2,081 -1 49 53 0 0 108 0 26 206 2,004

Lower 48 States ............. 166,512 192 24,058 24,068 10,579 12,571 18,053 756 1,121 17,069 171,547

Alabama. . . . . . . . . . . . . . . . . . . . 4,313 28 163 157 30 0 132 3 0 325 4,127

Arkansas . . . . . . . . . . . . . . . . . . . 1,629 13 193 91 24 52 170 3 18 166 1,797

California . . . . . . . . . . . . . . . . . . . 759 41 84 62 115 109 23 0 5 77 767

Coastal Region Onshore . . . . . 1 0 1 0 0 0 6 0 0 0 8

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

San Joaquin Basin Onshore . . 751 45 83 62 115 109 17 0 5 76 757

State Offshore . . . . . . . . . . . . . 7 -4 0 0 0 0 0 0 0 1 2

Colorado . . . . . . . . . . . . . . . . . . . 14,707 19 1,455 2,233 2,596 2,461 943 177 18 995 13,956

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

Kansas. . . . . . . . . . . . . . . . . . . . . 5,058 67 795 683 147 180 48 1 0 396 4,923

Kentucky . . . . . . . . . . . . . . . . . . . 1,946 -21 184 155 5 0 101 0 0 87 1,963

Louisiana . . . . . . . . . . . . . . . . . . . 8,952 -12 974 1,110 912 572 1,922 13 119 1,283 9,235

North . . . . . . . . . . . . . . . . . . . . 4,998 -19 328 373 588 284 1,533 5 11 445 5,734

South Onshore. . . . . . . . . . . . . 3,506 73 543 623 260 230 365 4 80 750 3,168

State Offshore . . . . . . . . . . . . . 448 -66 103 114 64 58 24 4 28 88 333

Michigan . . . . . . . . . . . . . . . . . . . 3,219 -90 204 298 14 15 88 0 31 194 2,961

Mississippi . . . . . . . . . . . . . . . . . . 721 21 46 53 10 3 27 0 7 90 672

Montana. . . . . . . . . . . . . . . . . . . . 956 -55 47 113 1 1 116 1 6 86 872

New Mexico . . . . . . . . . . . . . . . . . 16,681 -23 2,620 1,691 609 1,309 1,202 14 3 1,397 18,109

East . . . . . . . . . . . . . . . . . . . . . 2,205 9 407 322 166 371 294 14 3 338 2,477

West. . . . . . . . . . . . . . . . . . . . . 14,476 -32 2,213 1,369 443 938 908 0 0 1,059 15,632

New York . . . . . . . . . . . . . . . . . . . 365 -93 81 75 12 15 87 0 0 44 324

North Dakota . . . . . . . . . . . . . . . . 181 -4 9 29 0 0 3 0 0 15 145

Ohio . . . . . . . . . . . . . . . . . . . . . . . 823 -60 93 55 0 0 29 0 0 63 767

Oklahoma . . . . . . . . . . . . . . . . . . 15,176 -76 2,103 1,711 496 756 2,052 9 8 1,520 16,301

Pennsylvania . . . . . . . . . . . . . . . . 2,333 -183 656 530 28 29 113 0 3 147 2,246

Texas . . . . . . . . . . . . . . . . . . . . . . 42,280 738 6,711 6,016 2,658 4,029 6,037 277 322 4,992 46,728

RRC District 1 . . . . . . . . . . . . . 1,047 64 106 126 84 95 94 104 0 116 1,184

RRC District 2 Onshore . . . . . . 1,768 8 270 355 156 295 263 13 35 283 1,858

RRC District 3 Onshore . . . . . . 3,044 187 542 747 177 170 355 61 67 543 2,959

RRC District 4 Onshore . . . . . . 8,919 127 1,232 1,572 570 805 1,203 7 82 1,331 8,902

RRC District 5 . . . . . . . . . . . . . 5,398 66 1,071 419 298 628 512 7 48 488 6,525

RRC District 6 . . . . . . . . . . . . . 6,572 111 887 662 215 470 968 19 81 667 7,564

RRC District 7B . . . . . . . . . . . . 314 66 16 72 16 21 5 0 0 46 288

RRC District 7C . . . . . . . . . . . . 3,864 -2 811 463 272 274 293 0 1 310 4,196

RRC District 8 . . . . . . . . . . . . . 3,032 -11 366 472 114 238 492 48 5 318 3,266

RRC District 8A . . . . . . . . . . . . 100 -4 18 10 0 1 2 4 0 16 95

RRC District 9 . . . . . . . . . . . . . 3,514 -72 441 191 551 587 1,142 0 0 425 4,445

RRC District 10 . . . . . . . . . . . . 4,258 194 793 721 79 365 707 4 0 387 5,134

State Offshore . . . . . . . . . . . . . 450 4 158 206 126 80 1 10 3 62 312

Utah . . . . . . . . . . . . . . . . . . . . . . . 3,318 90 454 243 937 947 284 5 11 268 3,661

Virginia. . . . . . . . . . . . . . . . . . . . . 1,717 -19 39 69 0 0 146 0 0 72 1,742

West Virginia . . . . . . . . . . . . . . . . 3,376 -280 685 263 73 26 191 0 1 174 3,489

Wyoming . . . . . . . . . . . . . . . . . . . 22,266 73 2,949 3,699 889 827 3,242 8 38 1,537 23,278

Federal Offshorea . . . . . . . . . . . . 15,616 18 3,508 4,692 1,021 1,238 1,080 241 531 3,133 13,386

Pacific (California) . . . . . . . . . . 55 0 0 0 15 8 0 0 0 1 47

Gulf of Mexico (Louisiana)a . . . 11,326 -7 1,483 2,376 794 1,032 999 197 456 2,235 10,081

Gulf of Mexico (Texas) . . . . . . . 4,235 25 2,025 2,316 212 198 81 44 75 897 3,258

Miscellaneousb . . . . . . . . . . . . . . 120 0 5 40 2 2 17 4 0 8 98

U.S. Total . . . . . . . . . . . . . . . . . . 168,593 191 24,107 24,121 10,579 12,571 18,161 756 1,147 17,275 173,551

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

Wet After Lease Separation, 2004 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 2004

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 12/31/03 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/04
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 35

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

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

Reserves.” They may differ from the official Energy Information Administration production data for natural gas for 2004 contained in the

Natural Gas Annual 2004, DOE/EIA-0131(04).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 6,267 1 589 155 0 0 33 0 9 275 6,469

Lower 48 States . . . . . . . . . . . . . 22,285 -22 3,420 3,015 1,004 987 874 34 88 2,467 21,180

Alabama. . . . . . . . . . . . . . . . . . . . 32 3 1 0 0 0 1 0 0 5 32

Arkansas . . . . . . . . . . . . . . . . . . . 37 -1 7 0 0 0 0 1 0 4 40

California . . . . . . . . . . . . . . . . . . . 1,810 -11 378 98 20 45 84 0 0 182 2,006

Coastal Region Onshore . . . . . 173 -4 32 10 3 7 3 0 0 10 188

Los Angeles Basin Onshore. . . 196 2 4 50 0 0 42 0 0 10 184

San Joaquin Basin Onshore . . 1,365 -9 327 37 15 36 38 0 0 156 1,549

State Offshore . . . . . . . . . . . . . 76 0 15 1 2 2 1 0 0 6 85

Colorado . . . . . . . . . . . . . . . . . . . 1,186 -5 101 8 19 19 110 0 0 91 1,293

Florida . . . . . . . . . . . . . . . . . . . . . 92 0 0 1 0 0 0 0 0 3 88

Kansas. . . . . . . . . . . . . . . . . . . . . 85 -1 11 12 4 7 2 0 0 8 80

Kentucky . . . . . . . . . . . . . . . . . . . 25 0 1 7 0 0 0 0 0 0 19

Louisiana . . . . . . . . . . . . . . . . . . . 586 -1 145 153 42 34 51 5 7 75 557

North . . . . . . . . . . . . . . . . . . . . 139 10 24 50 8 0 6 0 0 14 107

South Onshore. . . . . . . . . . . . . 368 -10 109 82 30 29 41 5 6 47 389

State Offshore . . . . . . . . . . . . . 79 -1 12 21 4 5 4 0 1 14 61

Michigan . . . . . . . . . . . . . . . . . . . 269 3 5 69 0 0 3 0 0 18 193

Mississippi . . . . . . . . . . . . . . . . . . 27 -2 3 2 8 5 0 0 0 3 20

Montana. . . . . . . . . . . . . . . . . . . . 112 -4 26 12 1 2 16 0 0 9 130

New Mexico . . . . . . . . . . . . . . . . . 1,545 31 316 197 122 105 126 8 1 235 1,578

East . . . . . . . . . . . . . . . . . . . . . 1,456 31 300 190 122 105 126 8 1 227 1,488

West. . . . . . . . . . . . . . . . . . . . . 89 0 16 7 0 0 0 0 0 8 90

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

North Dakota . . . . . . . . . . . . . . . . 316 -26 87 35 12 25 5 0 2 42 320

Ohio . . . . . . . . . . . . . . . . . . . . . . . 304 -78 10 9 0 0 0 0 0 19 208

Oklahoma . . . . . . . . . . . . . . . . . . 1,055 39 199 315 45 52 48 0 2 136 899

Pennsylvania . . . . . . . . . . . . . . . . 164 -5 4 39 0 0 10 0 0 9 125

Texas . . . . . . . . . . . . . . . . . . . . . . 6,437 59 1,219 814 300 364 247 3 2 670 6,547

RRC District 1 . . . . . . . . . . . . . 48 2 9 7 1 0 1 0 1 8 45

RRC District 2 Onshore . . . . . . 81 5 16 5 6 1 12 0 0 28 76

RRC District 3 Onshore . . . . . . 504 27 209 215 37 18 12 1 0 78 441

RRC District 4 Onshore . . . . . . 136 -1 69 23 1 1 2 0 1 19 165

RRC District 5 . . . . . . . . . . . . . 62 1 6 6 0 0 2 0 0 7 58

RRC District 6 . . . . . . . . . . . . . 387 -1 42 30 1 32 19 0 0 46 402

RRC District 7B . . . . . . . . . . . . 69 13 11 4 6 4 3 0 0 14 76

RRC District 7C . . . . . . . . . . . . 927 -1 111 46 29 51 58 0 0 77 994

RRC District 8 . . . . . . . . . . . . . 2,803 5 423 354 190 183 105 2 0 241 2,736

RRC District 8A . . . . . . . . . . . . 1,037 2 234 30 18 48 14 0 0 101 1,186

RRC District 9 . . . . . . . . . . . . . 125 19 16 35 8 9 4 0 0 20 110

RRC District 10 . . . . . . . . . . . . 252 -11 66 59 3 16 15 0 0 27 249

State Offshore . . . . . . . . . . . . . 6 -1 7 0 0 1 0 0 0 4 9

Utah . . . . . . . . . . . . . . . . . . . . . . . 299 3 31 41 29 27 21 0 0 21 290

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

West Virginia . . . . . . . . . . . . . . . . 23 -1 1 2 0 0 0 0 0 1 20

Wyoming . . . . . . . . . . . . . . . . . . . 450 -26 31 46 15 20 2 0 0 54 362

Federal Offshorea . . . . . . . . . . . . 7,417 2 841 1,152 387 282 148 17 74 881 6,361

Pacific (California) . . . . . . . . . . 456 1 22 17 99 95 0 0 0 46 412

Gulf of Mexico (Louisiana)a . . . 5,842 2 615 925 235 182 146 17 74 655 5,063

Gulf of Mexico (Texas) . . . . . . . 1,119 -1 204 210 53 5 2 0 0 180 886

Miscellaneousb . . . . . . . . . . . . . . 14 -1 3 3 0 0 0 0 0 1 12

U.S. Total . . . . . . . . . . . . . . . . . . 28,552 -21 4,009 3,170 1,004 987 907 34 97 2,742 27,649

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

Wet After Lease Separation, 2004 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 2004

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 12/31/03 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/04
In the prior 10 years, U.S. operators had reported an

annual average of 2,425 billion cubic feet of reserves

from new reservoirs discovered in old fields. Reserves

from new reservoirs discovered in old fields in 2004

were 50 percent of that average.

Revisions and Adjustments

There were 26,893 billion cubic feet of revision

increases, 26,149 billion cubic feet of revision decreases,

and -114 billion cubic feet of adjustments in 2004.

Combined, there were 630 billion cubic feet of net

revisions and adjustments in 2004, excluding reserves

additions from net sales and acquisitions. This is 89

percent less than the average volume of net revisions

and adjustments of the prior 10 years (5,588 billion

cubic feet).

Sales and Acquisitions

Sales represents that volume of dry natural gas proved

reserves deducted from an operator’s total reserves

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 reserves by purchase or

operations transfer of an existing gas field or

properties.

There are several reasons why sales and acquisitions

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

operatorship. Timing of the transfer of operations can

also impact these values.

In 2004, there were 11,106 billion cubic feet of sales

transactions between operators, and 12,950 billion

cubic feet of acquisitions. The net difference of 1,844

billion cubic feet was added to the National total of dry

natural gas reserves in 2004.

Production

The estimated 2004 U.S. dry natural gas production

was 19,168 billion cubic feet (Table 8), a decrease of 1

percent from 2003. Areas with the largest production

and their percentage of total production were:

Texas produced 5,318 billion cubic feet (BCF) of

dry natural gas (28 percent of the total)

Gulf of Mexico Federal Offshore produced 3,874

BCF (20 percent)

Oklahoma produced 1,563 BCF (8 percent)

New Mexico produced 1,527 BCF (8 percent)

Wyoming produced 1,524 BCF (8 percent)

Louisiana produced 1,322 BCF (7 percent)

Colorado produced 1,050 BCF (5 percent of the

National total).

Wet Natural Gas

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

31, 2004 were 201,200 billion cubic feet, a 2 percent

increase from the volume reported in 2003 (Table 9). At

year-end 2004, proved wet natural gas reserves for the

lower 48 States had increased by 2 percent compared to

2003, while those of Alaska had increased by 1 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

3 percent (4,958 billion cubic feet) in 2004 to 173,551

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

wet natural gas proved reserves increased 3 percent to

a level of 171,547 billion cubic feet, while Alaska had a 4

percent decline to a level of 2,004 billion cubic feet.

Those States with the largest increases in NA wet

natural gas reserves were Texas, New Mexico,

Oklahoma, and Wyoming.

Total Discoveries

NA wet natural gas total discoveries of 20,064 billion

cubic feet in 2004 were 7 percent more that the 2003

total of 18,712 billion cubic feet. Areas with the most

total discoveries in 2004 were Texas (6,636 billion cubic

feet), Wyoming (3,288 billion cubic feet), Oklahoma

(2,069 billion cubic feet), Louisiana (2,054 billion cubic

feet), the Gulf of Mexico Federal Offshore (1,852 billion

cubic feet), and New Mexico (1,219 billion cubic feet).

Energy Information Administration

36 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report
Production

U.S. production of NA wet natural gas decreased less

than 1 percent from an estimated 17,376 billion cubic

feet in 2003 to 17,275 billion cubic feet in 2004. The five

leading producing areas were: Texas (29 percent), the

Gulf of Mexico Federal Offshore (18 percent),

Wyoming (9 percent), Oklahoma (9 percent), and New

Mexico (8 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 27,649 billion cubic feet in 2004

(Table 11). Proved reserves of AD wet natural gas in

the lower 48 States decreased by 5 percent to 21,180

billion cubic feet, and in Alaska increased 3 percent

(202 billion cubic feet) to 6,469 billion cubic feet. The

areas of the country with the largest AD wet natural gas

reserves and their percentage of the total were:

Texas (24 percent)

Alaska (23 percent)

Gulf of Mexico Federal Offshore (22 percent)

California (7 percent)

New Mexico (6 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 2,855 billion cubic feet in

2003 to 2,742 billion cubic feet in 2004 (Table 11).

Production of AD wet natural gas in the lower 48 States

decreased from 2,579 billion cubic feet to 2,467 billion

cubic feet in 2004, a decline of 4 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 (30 percent)

Texas (24 percent)

Alaska (10 percent)

New Mexico (9 percent)

California (7 percent).

Again, these areas logically correspond to the areas of

the country with the largest volumes of crude oil

production.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 37

Figure 21. Coalbed Natural Gas Proved Reserves, 1989-2004

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

Proved Reserves

Proved reserves of coalbed natural gas decreased to

18,390 billion cubic feet in 2004, 2 percent lower than

the 2003 level (18,743 billion cubic feet). Coalbed

natural gas accounted for 10 percent of all 2004 dry

natural gas reserves (Table 12). The last time reserves

of coalbed natural gas had declined was in 1994 (Figure

21). Five States (Colorado, New Mexico, Wyoming,

Alabama and Utah) currently have the vast majority

(86 percent) of U.S. coalbed natural gas proved

reserves. Three of them (Colorado, Wyoming, and

Utah) reported declines in their proved coalbed natural

gas reserves in 2004.

Production

U.S. coalbed natural gas production increased 8

percent in 2004 to 1,720 billion cubic feet. It accounted

for 9 percent of U.S. dry gas production.

Energy Information Administration

38 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table 12. Coalbed Natural Gas Proved Reserves and Production, 1989–2004

(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 NA NA NA NA 0 3,676

1990 1,224 1,320 2,510 NA NA NA NA 33 5,087

1991 1,714 2,076 4,206 NA NA NA NA 167 8,163

1992 1,968 2,716 4,724 NA NA NA NA 626 10,034

1993 1,237 3,107 4,775 NA NA NA NA 1,065 10,184

1994 976 2,913 4,137 NA NA NA NA 1,686 9,712

1995 972 3,461 4,299 NA NA NA NA 1,767 10,499

1996 823 3,711 4,180 NA NA NA NA 1,852 10,566

1997 1,077 3,890 4,351 NA NA NA NA 2,144 11,462

1998 1,029 4,211 4,232 NA NA NA NA 2,707 12,179

1999 1,060 4,826 4,080 NA NA NA NA 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

2004 1,900 5,787 5,166 934 2,085 1,620 898 -- 18,390

Production

1989 23 12 56 NA NA NA NA 0 91

1990 36 26 133 NA NA NA NA 1 196

1991 68 48 229 NA NA NA NA 3 348

1992 89 82 358 NA NA NA NA 10 539

1993 103 125 486 NA NA NA NA 18 752

1994 108 179 530 NA NA NA NA 34 851

1995 109 226 574 NA NA NA NA 47 956

1996 98 274 575 NA NA NA NA 56 1,003

1997 111 312 597 NA NA NA NA 70 1,090

1998 123 401 571 NA NA NA NA 99 1,194

1999 108 432 582 NA NA NA NA 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

2004 121 520 528 82 320 72 77 -- 1,720

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.
Areas of Note:

Large Discoveries and

Reserves Additions

The following State or area discussions summarize

notable activities during the year concerning expected

new field reserves, development plans, and possible

production rates as extracted from various trade

publications and company reports. The citations do not

necessarily reflect EIA’s concurrence, but are

considered important enough to be brought to the

reader’s attention.

Texas

Texas had a 9 percent increase in dry natural gas

proved reserves in 2004 (4,225 billion cubic feet), the

largest of any State. 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: On August 6, 2004 Devon

Energy Corporation (Devon) announced it had

drilled its 100th horizontal well in the Barnett

Shale, a vast underground natural gas bearing

formation that meanders underneath 10 Texas

counties. The new well is northwest of Fort

Worth.

Devon, the predominant driller in the “core

area” of the northwest part of the formation, has

also leased almost 400,000 acres south of Fort

Worth and is beginning to drill in Johnson

County. One Johnson County well is producing

nearly 4 million cubic feet of natural gas a day,

more than double the formation’s average,

company officers say. Devon plans to continue

drilling in the Barnett Shale at the rate of 60 new

wells a year for several years.

The company estimates its natural gas reserves

in the Barnett Shale are in excess of 1 trillion

cubic feet. Experts estimate that every every 7

square miles of the formation contain that much

natural gas. Devon soon will begin refracturing

19 of its old Barnett Shale wells, north and west

of Fort Worth in Wise and Denton counties,

hoping to get a little more production from

them. Devon plans 50 more refracturings next

year and 250 more the year after that. {41}

New Mexico

New Mexico’s dry natural gas reserves increased by 9

percent (1,492 billion cubic feet) in 2004. This was the

result of development in the San Juan Basin.

San Juan Basin Gas Area: Measuring 7,500

square miles, the San Juan Basin Gas Area is the

one of the largest natural gas producing areas

and currently ranks as the leading U.S. field in

both production and remaining resources.

Burlington Resources (Burlington) operates 7,500

well completions, holds interests in 4,700

partner-operated completions, and has interests

in 1.1 million acres. Its ongoing initiatives

include applying advanced stimulation

techniques to existing wells; upgrading

compressors, pipelines and other infrastructure;

and reducing operating costs. During 2004

Burlington participated in 361 new wells and

172 mechanical workovers of existing wells. {42}

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 15 percent (-3,247 billion

cubic feet) in 2004. Production also decreased by 10

percent from 4,306 billion cubic feet in 2003 to 3,874

billion cubic feet in 2004.

The large proved natural gas reserves drop

experienced in the Gulf of Mexico was primarily due to

low new field discoveries and relatively large negative

revisions to proved reserves. As previously mentioned,

Hurricane Ivan caused pipeline damage that shut in

significant gas production in the Gulf in the last quarter

of 2004. Ivan's damage will reduce 2005 Gulf

production from what it could have been, and it

remains to be seen what impact the damage from 2005

hurricanes will have on reserves and production in the

Gulf.

For the latest estimates of 2005 hurricane damage

effects, readers should visit our website at

http://www.eia.doe.gov and select the link, “Report

on the impact of recent hurricanes on energy in the US“.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 39
Colorado

Colorado’s proved dry natural gas reserves decreased

by 4 percent (-693 billion cubic feet) in 2004. Production

in Colorado decreased 8 percent (-92 billion cubic feet)

in 2004.

Michigan

Michigan’s proved dry natural gas reserves decreased

by 10 percent (-337 billion cubic feet) in 2004.

Production in Michigan decreased 6 percent (-13 billion

cubic feet) in 2004.

Reserves in

Nonproducing Status

Nonproducing proved natural gas reserves (wet after

lease separation) of 45,996 billion cubic feet were

reported in 2004, 6 percent less than the 49,068 billion

cubic feet reported in 2003 (Appendix D, Table D10).

About 28 percent of the reserves in nonproducing

status are located in Texas. Another 15 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 2004 Annual Report
5. Natural Gas Liquids Statistics

Natural Gas Liquids

Proved Reserves

U.S. natural gas liquids proved reserves increased 6

percent to 7,928 million barrels in 2004 (Table 13),

rebounding from the decline observed in 2003. Reserve

additions replaced 157 percent of 2004 natural gas

liquids production.

The reserves of seven areas account for 88 percent of

the Nation’s natural gas liquids proved reserves.

Percent of

Area U.S. NGL Reserves

Texas 35

Utah - Wyoming 12

New Mexico 11

Oklahoma 10

Gulf of Mexico Federal Offshore 9

Colorado 6

Alaska 5

Area Total 88

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

814 million barrels in 2004, an increase of 11 percent

from 2003 (736 million barrels). Areas with the largest

total discoveries were:

Texas (43 percent of the National total)

Utah & Wyoming (15 percent)

Oklahoma (12 percent)

Gulf of Mexico Federal Offshore (10 percent)

New Mexico (8 percent)

Louisiana (5 percent).

Extensions

Extensions were 734 million barrels in 2004, 17 percent

more than the 2003 volume of 629 million barrels. Areas

with the largest extensions were Texas (43 percent of

the National total), Utah & Wyoming (17 percent),

Oklahoma (13 percent), and New Mexico (9 percent).

New Field Discoveries

New field discoveries in 2004 (26 million barrels) were

26 percent lower than in 2003 (35 million barrels). Areas

with the largest new field discoveries were Texas (54

percent), the Gulf of Mexico Federal Offshore (27

percent), and Colorado (15 percent).

New Reservoir Discoveries in Old Fields

New reservoir discoveries in old fields in 2004 (54

million barrels) were 25 percent lower than they were

in 2003 (72 million barrels). Areas with the largest new

reservoir discoveries in old fields were the Gulf of

Mexico Federal Offshore (59 percent of the National

total), Texas (28 percent), and Louisiana (11 percent).

Revisions and Adjustments

In 2004, there were 1,232 million barrels of revision

increases, 1,135 million barrels of revision decreases,

and 273 million barrels of adjustments. The net of

revisions and adjustments was 370 million barrels.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 41
Energy Information Administration

42 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

aIncludes Federal offshore Alabama. bIncludes Arizona, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, New York, Ohio, Oregon, Pennsylvania, South Dakota,

Tennessee, and Virginia.

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

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

Information Administration production data for natural gas and natural gas liquids for 2004 contained in the publications Petroleum Supply

Annual 2004, DOE/EIA-0340(04) and Natural Gas Annual 2004 DOE/EIA-0131(04).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 387 0 0 0 0 0 0 0 0 18 369

Lower 48 States . . . . . . . . . . . . . 7,072 273 1,232 1,135 442 554 734 26 54 809 7,559

Alabama. . . . . . . . . . . . . . . . . . . . 60 -5 4 2 5 0 2 0 0 4 50

Arkansas . . . . . . . . . . . . . . . . . . . 3 0 0 0 0 0 0 0 0 0 3

California . . . . . . . . . . . . . . . . . . . 101 9 22 7 5 7 5 0 0 10 122

Coastal Region Onshore . . . . . 15 1 3 1 0 1 1 0 0 1 19

Los Angeles Basin Onshore. . . 8 0 0 2 0 0 2 0 0 0 8

San Joaquin Basin Onshore . . 78 8 19 4 5 6 2 0 0 9 95

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

Colorado . . . . . . . . . . . . . . . . . . . 395 55 72 56 71 69 29 4 0 32 465

Florida . . . . . . . . . . . . . . . . . . . . . 17 -5 0 0 0 0 0 0 0 0 12

Kansas. . . . . . . . . . . . . . . . . . . . . 248 32 44 37 8 11 3 0 0 22 271

Kentucky . . . . . . . . . . . . . . . . . . . 66 4 7 6 0 0 4 0 0 3 72

Louisiana . . . . . . . . . . . . . . . . . . . 295 -8 54 57 32 23 38 0 6 56 263

North . . . . . . . . . . . . . . . . . . . . 67 -2 8 7 8 6 17 0 0 7 74

South Onshore. . . . . . . . . . . . . 182 -2 34 38 17 11 18 0 4 39 153

State Offshore . . . . . . . . . . . . . 46 -4 12 12 7 6 3 0 2 10 36

Michigan . . . . . . . . . . . . . . . . . . . 48 4 6 7 0 0 1 0 0 4 48

Mississippi . . . . . . . . . . . . . . . . . . 7 0 1 1 0 0 0 0 0 1 6

Montana. . . . . . . . . . . . . . . . . . . . 8 -1 0 1 0 0 1 0 0 1 6

New Mexico . . . . . . . . . . . . . . . . . 875 -72 131 90 37 72 63 1 0 79 864

East . . . . . . . . . . . . . . . . . . . . . 272 -20 48 36 21 39 30 1 0 39 274

West. . . . . . . . . . . . . . . . . . . . . 603 -52 83 54 16 33 33 0 0 40 590

North Dakota . . . . . . . . . . . . . . . . 45 -1 8 6 1 2 1 0 0 5 43

Oklahoma . . . . . . . . . . . . . . . . . . 686 40 122 93 25 37 98 0 0 75 790

Texas . . . . . . . . . . . . . . . . . . . . . . 2,517 115 445 398 147 218 318 14 15 296 2,801

RRC District 1 . . . . . . . . . . . . . 29 6 4 4 3 2 2 4 0 4 36

RRC District 2 Onshore . . . . . . 69 7 12 15 6 12 11 0 2 13 79

RRC District 3 Onshore . . . . . . 207 32 50 63 14 13 28 4 5 41 221

RRC District 4 Onshore . . . . . . 287 57 51 69 19 26 41 0 3 51 326

RRC District 5 . . . . . . . . . . . . . 51 -2 9 6 2 4 3 0 0 4 53

RRC District 6 . . . . . . . . . . . . . 248 10 50 29 8 19 36 1 3 26 304

RRC District 7B . . . . . . . . . . . . 32 24 3 10 3 3 1 0 0 7 43

RRC District 7C . . . . . . . . . . . . 345 18 69 49 27 29 28 0 0 30 383

RRC District 8 . . . . . . . . . . . . . 498 -10 66 73 26 36 50 4 0 46 499

RRC District 8A . . . . . . . . . . . . 163 11 39 6 3 8 2 1 0 18 197

RRC District 9 . . . . . . . . . . . . . 236 -48 25 15 28 30 59 0 0 24 235

RRC District 10 . . . . . . . . . . . . 347 10 67 58 6 34 57 0 0 31 420

State Offshore ............. 5 0 0 1 2 2 0 0 2 1 5

Utah and Wyoming . . . . . . . . . . . 898 -20 150 158 50 46 122 0 1 62 927

West Virginia . . . . . . . . . . . . . . . . 68 7 16 6 2 1 5 0 0 4 85

Federal Offshorea . . . . . . . . . . . . 725 119 148 208 59 68 44 7 32 155 721

Pacific (California) . . . . . . . . . . 8 0 0 0 0 0 0 0 0 0 8

Gulf of Mexico (Louisiana)a . . . 598 118 104 168 57 66 43 7 31 127 615

Gulf of Mexico (Texas) . . . . . . . 119 1 44 40 2 2 1 0 1 28 98

Miscellaneousb . . . . . . . . . . . . . . 10 0 2 2 0 0 0 0 0 0 10

U.S. Total . . . . . . . . . . . . . . . . . . 7,459 273 1,232 1,135 442 554 734 26 54 827 7,928

Table 13. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 2004

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 2004

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 12/31/03 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/04
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 43

Table 14. Natural Gas Plant Liquids Proved Reserves and Production, 2004

(Million Barrels of 42 U.S. Gallons)

2004 2004 2004 2004

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska . . . . . . . . . . . . . . . . . . . . . . 369 18

Lower 48 States.............. 6,338 627

Alabama . . . . . . . . . . . . . . . . . . . . 29 2

Arkansas .................... 2 0

California. . . . . . . . . . . . . . . . . . . . 121 10

Coastal Region Onshore . . . . . 19 1

Los Angeles Basin Onshore . . . 8 0

San Joaquin Basin Onshore. . . 94 9

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

Colorado . . . . . . . . . . . . . . . . . . . . 362 26

Florida . . . . . . . . . . . . . . . . . . . . . . 12 0

Kansas . . . . . . . . . . . . . . . . . . . . . 267 22

Kentucky . . . . . . . . . . . . . . . . . . . . 71 3

Louisiana. . . . . . . . . . . . . . . . . . . . 167 31

North. . . . . . . . . . . . . . . . . . . . . 53 4

South Onshore . . . . . . . . . . . . . 87 20

State Offshore. . . . . . . . . . . . . . 27 7

Michigan . . . . . . . . . . . . . . . . . . . . 44 3

Mississippi................... 1 0

Montana .................... 6 1

New Mexico . . . . . . . . . . . . . . . . . 805 73

East . . . . . . . . . . . . . . . . . . . . . 245 35

West . . . . . . . . . . . . . . . . . . . . . 560 38

North Dakota. . . . . . . . . . . . . . . . . 39 5

Oklahoma . . . . . . . . . . . . . . . . . . . 666 64

Texas ...................... 2,466 250

RRC District 1. . . . . . . . . . . . . . 31 3

RRC District 2 Onshore . . . . . . 64 10

RRC District 3 Onshore . . . . . . 149 27

RRC District 4 Onshore . . . . . . 253 38

RRC District 5. . . . . . . . . . . . . . 44 3

RRC District 6. . . . . . . . . . . . . . 233 21

RRC District 7B. . . . . . . . . . . . . 42 7

RRC District 7C . . . . . . . . . . . . 365 27

RRC District 8. . . . . . . . . . . . . . 487 45

RRC District 8A. . . . . . . . . . . . . 197 18

RRC District 9. . . . . . . . . . . . . . 228 22

RRC District 10. . . . . . . . . . . . . 373 29

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

Utah and Wyoming . . . . . . . . . . . . 765 52

West Virginia. . . . . . . . . . . . . . . . . 84 4

Federal Offshorea . . . . . . . . . . . . . 423 81

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

Gulf of Mexico (Louisiana)a . . . 410 78

Gulf of Mexico (Texas) . . . . . . . 13 3

Miscellaneousb ............... 8 0

U.S. Total ................... 6,707 645

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 2004 contained in the publications Petroleum Supply Annual 2004,

DOE/EIA-0340(2004) and Natural Gas Annual 2004, DOE/EIA-0131(2004).

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

44 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table 15. Lease Condensate Proved Reserves and Production, 2004

(Million Barrels of 42 U.S. Gallons)

2004 2004 2004 2004

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska ...................... 0 0

Lower 48 States.............. 1,221 182

Alabama . . . . . . . . . . . . . . . . . . . . 21 2

Arkansas .................... 1 0

California.................... 1 0

Coastal Region Onshore ..... 0 0

Los Angeles Basin Onshore . . . 0 0

San Joaquin Basin Onshore. . . 1 0

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

Colorado . . . . . . . . . . . . . . . . . . . . 103 6

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

Kansas ..................... 4 0

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

Louisiana. . . . . . . . . . . . . . . . . . . . 96 25

North. . . . . . . . . . . . . . . . . . . . . 21 3

South Onshore . . . . . . . . . . . . . 66 19

State Offshore.............. 9 3

Michigan .................... 4 1

Mississippi................... 5 1

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

New Mexico . . . . . . . . . . . . . . . . . 59 6

East . . . . . . . . . . . . . . . . . . . . . 29 4

West . . . . . . . . . . . . . . . . . . . . . 30 2

North Dakota................. 4 0

Oklahoma . . . . . . . . . . . . . . . . . . . 124 11

Texas . . . . . . . . . . . . . . . . . . . . . . 335 46

RRC District 1.............. 5 1

RRC District 2 Onshore . . . . . . 15 3

RRC District 3 Onshore . . . . . . 72 14

RRC District 4 Onshore . . . . . . 73 13

RRC District 5.............. 9 1

RRC District 6. . . . . . . . . . . . . . 71 5

RRC District 7B............. 1 0

RRC District 7C . . . . . . . . . . . . 18 3

RRC District 8. . . . . . . . . . . . . . 12 1

RRC District 8A............. 0 0

RRC District 9.............. 7 2

RRC District 10. . . . . . . . . . . . . 47 2

State Offshore.............. 5 1

Utah and Wyoming . . . . . . . . . . . . 162 10

West Virginia................. 1 0

Federal Offshorea . . . . . . . . . . . . . 298 74

Pacific (California)........... 8 0

Gulf of Mexico (Louisiana)a . . . 205 49

Gulf of Mexico (Texas) . . . . . . . 85 25

Miscellaneousb ............... 2 0

U.S. Total ................... 1,221 182

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” 2004.

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

There were 554 million barrels of acquisitions and 442

million barrels of sales in 2004. The net of these

transactions added 112 million barrels of natural gas

liquids proved reserves.

Production

Natural gas liquids production was an estimated 827

million barrels in 2004, an increase of 3 percent from

2003. Alaskan production remained level and

production in the lower 48 States increased.

Six areas accounted for about 87 percent of the Nation’s

natural gas liquids production.

Texas (36 percent of the National total)

Gulf of Mexico Federal Offshore (19 percent)

New Mexico (10 percent)

Oklahoma (9 percent)

Utah-Wyoming (7 percent)

Louisiana (7 percent).

Natural Gas Plant Liquids

Proved Reserves

Natural gas plant liquids proved reserves increased in

2004 to 6,707 million barrels, a 7 percent increase from

the 2003 level (6,244 million barrels) (Table 14). Six

areas accounted for about 82 percent of the Nation’s

natural gas plant liquids proved reserves:

Percent of

Area U.S. Gas Plant Liquids

Texas 37

New Mexico 12

Utah-Wyoming 11

Oklahoma 10

Gulf of Mexico Federal Offshore 6

Alaska 6

Area Total 82

Production

Natural gas plant liquids production increased 6

percent in 2004—from 611 million barrels in 2003 to 645

million barrels of production (Table 14) even though

gas production decreased in 2004. The reasons for this

are primarily economic.

In 2003, given certain gas market conditions, it was

more economic to offer higher BTU gas directly to the

market than to strip the liquids from the produced gas

stream. With higher average crude oil prices in 2004,

liquids regained an advantage and more liquids were

produced at gas plants.

The number of active gas plants dropped in 2004.

According to survey results from Form EIA-64A, the

number of unique active U.S. natural gas proccessing

plants dropped from 497 in 2003 to 491 in 2004.

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 (39 percent)

Gulf of Mexico Federal Offshore (13 percent)

New Mexico (11 percent)

Oklahoma (10 percent)

Utah and Wyoming (8 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 1,221 million barrels in 2004 (Table 15).

This was less than 1 percent higher than the volume

reported in 2003 (1,215 million barrels). The reserves of

five areas accounts for about 82 percent of the Nation’s

lease condensate proved reserves.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report 45
Percent of U.S.

Area Condensate Reserves

Texas 27

Gulf of Mexico Federal Offshore 24

Utah-Wyoming 13

Oklahoma 10

Colorado 8

Area Total 82

Production

Production of lease condensate was 182 million barrels

in 2004, a decrease of 5 percent from 2003’s production

(191 million barrels). The production of five areas

account for about 91 percent of the Nation’s lease

condensate production.

Gulf of Mexico Federal Offshore (41 percent)

Texas (25 percent)

Louisiana (14 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 2004. Proved

reserves of 409 million barrels of lease condensate, an

increase of 3 percent from 2003’s level (399 million

barrels), were reported in nonproducing status in 2004

(Appendix D, Table D10). About 37 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 2004 Annual Report
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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids

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Washington, DC.

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

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

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.

DOE/EIA-0216(97). Washington, DC.

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1999. U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves 1998 Annual Report.

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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DOE/EIA-0130(2005/10). Washington, DC.

30. Kerr-McGee Corporation. Oklahoma City, OK.

Press release, April 7, 2004.

(http://kerr-mcgee.com)

31. Pioneer Natural Resources, Dallas, TX.

Press release, May 4, 2004.

(http://www.pioneernrc.com)

32. EnCana Corporation. Calgary, Alberta, Canada.

Press release, May 19, 2004.

(http://www.encana.com)

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Natural Gas in the United States and Canada as of

December 31, 1979. Vol. 34. June 1980. Washington,

DC.

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U.S. Oil and Gas Reserves by Year of Field Discovery.

DOE/EIA-0534. Washington, DC.

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Journal, Vol. 102, No. 47 (December 20, 2004). Tulsa,

OK.

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9 (September, 2005). Houston, TX.

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2005. Table 1.3, Energy Consumption by Source,

1949-2004. 2004 Annual Energy Review.

DOE/EIA-0384(2004). Washington, DC.

(http://www.eia.doe.gov/emeu/aer)

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2005. Table 5.7, Petroleum Net Imports by Country

of Origin, 1960-2004. 2004 Annual Energy Review.

DOE/EIA-0384(2004). Washington, DC.

(http://www.eia.doe.gov/emeu/aer)

39. Anadarko Petroleum Corporation. Houston, TX.

Global Operations, North America, Western States.

Internet News Release.

(http://www.anadarko.com)

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Assets: Mid-Continent Division, The Williston

Basin. Internet News Release.

(http://www.br-inc.com/assets)

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Press Release, August 6, 2004.

(http://www.devonenergy.com)

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Assets: San Juan Division. Internet News Release.

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Assessment of the United States Oil and Gas Resources.

U.S. Geological Survey Circular 1118. Denver, CO,

pp. 5-6.

45. U.S. Department of the Interior, Minerals

Management Service, Gulf of Mexico OCS

Regional Office. August 1995. Estimated Proved Oil

and Gas Reserves, Gulf of Mexico, December 31, 1994.

OCS Report MMS 94-0045. New Orleans, LA, pp.

5-6.

Energy Information Administration

48 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
Appendix A

Operator Level Data

Appendix A

Operator Level Data

Appendix A provides a series of tables of the proved

reserves and production by production size class for

the years 1999 through 2004 for oil and gas well

operators. The tables show the volumetric change and

percent change from the previous year and from 1999.

In addition they show the 2004 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 20,170 small operators.

We estimated production and reserves for small

operators for 2004 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.

Natural Gas Proved Reserves

The wet natural gas proved reserves reported for 1999

through 2004 have changed from 176,159 billion cubic

feet to 201,200 billion cubic feet (Table A1). These

proved reserves are highly concentrated in the larger

companies. In 2004, the top 20 operators (Class 1-10 and

Class 11-20) producing companies had 60 percent of

the proved reserves of natural gas. The next two size

classes contain 80 and 400 companies and account for

25 and 10 percent of the U.S. natural gas proved

reserves, respectively. The top 20 operators had an

increase of 34 percent in their natural gas proved

reserves from 1999 to 2004. The rest of the operators in

(Class 21-100, Class 101-500, and Class Other) had a

decrease of 6 percent in their reserves in the same

period. In 2004, the top 20 operators' natural gas

reserves had a increase of 7 percent from 2003.

Natural Gas Production

Wet natural gas production has decreased from 20,231

billion cubic feet in 2003 to 20,017 billion cubic feet in

2004 (Table A2). In 2004, the top 20 producing

companies had 56 percent of the production of wet

natural gas. The next two size classes have 25 and 13

percent of the wet natural gas production, respectively.

The top 20 operators had an increase of 8 percent in wet

natural gas production from 1999 to 2004. The rest of

the operators had a decrease of 7 percent from 1999 to

2004. The top 20 operators' wet natural gas production

had a decrease of less than 1 percent in 2004 from 2003.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report A-1
Crude Oil Proved Reserves

Proved reserves of crude oil are more highly

concentrated in a few companies than those of natural

gas. The 20 largest oil and gas producing companies in

2004 had 68 percent of U.S. proved reserves of crude oil

(Table A3), in contrast to wet natural gas where these

same companies operated 60 percent of the total

proved reserves.

U.S. proved reserves of crude oil decreased 2 percent in

2004 from 2003. The top 20 producing companies

proved reserves of crude oil during 2004 decreased 5

percent from 2003. The top 20 class had an increase of 6

percent in their crude oil proved reserves from 1999 to

2004.

Crude Oil Production

Crude oil production reported for 1999 to 2004 has

decreased from 1,877 million barrels to 1,819 million

barrels (Table A4). The 20 largest oil and gas producing

companies had 64 percent of U.S. production of crude

oil in 2004. In 1999 they accounted for 62 percent of

production.

This is in contrast to wet natural gas where these same

companies produced 56 percent of the total. U.S.

production of crude oil declined by 7 percent from 1999

to 2004. The top 20 operators had a decline of 4 percent

in their oil production during the same period. U.S.

production of crude oil declined 3 percent from 2003 to

2004. In the same period the top 20 operators

production decreased by 7 percent.

Crude Oil and Natural Gas Fields

The number of fields in which Category I and Category

II operators were active increased during the 1999-2004

period (Table A5). From 1999-2004, the number of

fields in which the top 20 operators were active

increased by 2,688 fields (66 percent) while in 2004 the

number increased by 580 fields from 2003.

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.

Ranked Crude Oil and

Natural Gas Production

Table A6 lists the top U.S. Oil and gas operators ranked

by reported 2004 operated production data. Table A6

has been moved from Appendix B to Appendix A to

reflect the operator nature of the table. The following

list of companies taken from previous reports is

representative of the tremendous change that has taken

place in the US oil and gas industry since 1999. In this

list are companies, formerly in the top 50 producing

operators in the United States, which are longer

reporting to the Energy Information Administration on

the form EIA-23. Former operators in this list were

either merged or acquired by other operators. On the

other hand, this does not mean that all the reserves

which they operated have disappeared as most

reserves remained with the acquiring company. Some

reserves were sold by the acquiring or merging

company as the consolidation occurred.

Energy Information Administration

A-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report A-3

Operators Formerly in the Ranks of the Top 50 Reported for the U.S. 1999-2003

Num Formerly Operated As Currently Operated By

1 AEC Oil & Gas (USA) Inc Encana Oil & Gas Inc

2 Agip Petroleum Co Inc Eni SpA

3 Altura Energy Ltd Occidental Petroleum Corp

4 Arco Exploration & Production BP Plc

5 Arguello Inc Plains Explor & Prod Co

6 Barrett Resources Corp Williams Energy Inc

7 BP Amoco BP Plc

8 British Borneo USA Inc Eni SpA

9 C N G Producing Co Dominion Resources Inc

10 Chevron USA Production Co ChevronTexaco Inc

11 Coastal Oil & Gas Corp El Paso Energy

12 Coho Resources Inc Denbury Resources Inc

13 Conoco Inc ConocoPhillips Co

14 Evergreen Operating Corp Pioneer Natural Resources USA

15 Fina Oil & Chemical Co Total SA

16 Helmerich & Payne Inc Cimarex Energy Co

17 Howell Petroleum Corp Anadarko Petroleum Corp

18 HS Resources Inc Kerr-McGee Corp

19 Louis Dreyfus Natural Gas Corp Dominion Resources Inc

20 Mitchell Energy & Development Corp Devon Energy Corp

21 Nuevo Energy Co Plains Explor & Prod Co

22 Ocean Energy Inc Devon Energy Corp

23 Patina Oil & Gas Corp Noble Energy Inc

24 Phillips Petroleum Co ConocoPhillips Co

25 Prize Operating Co Gruy Petroleum Management Co

26 River Gas Corp ConocoPhillips Co

27 Santa Fe Snyder Corp Devon Energy Corp

28 Stocker Resources Inc Plains Explor & Prod Co

29 Texaco Inc ChevronTexaco Inc

30 Tom Brown Inc Encana Oil & Gas Inc

31 Union Pacific Resources Anadarko Petroleum Corp

32 Vastar Resources Inc BP Plc

33 Westport Resources Corp Kerr-McGee Corp
Energy Information Administration

A-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Class 1-10 64,320 81,437 88,936 88,100 82,222 81,325 -896 17,005 8,132.536

Percent of Total 36.5% 43.7% 46.4% 45.0% 41.7% 40.4% -1.1% 26.4%

Class 11-20 24,925 22,590 24,588 25,938 29,890 38,643 8,753 13,718 3,864.340

Percent of Total 14.1% 12.1% 12.8% 13.3% 15.2% 19.2% 29.3% 55.0%

Class 21-100 52,160 48,832 50,055 50,633 53,098 50,149 -2,949 -2,011 626.867

Percent of Total 29.6% 26.2% 26.1% 25.9% 26.9% 24.9% -5.6% -3.9%

Class 101-500 25,967 22,620 19,046 19,723 20,030 20,912 882 -5,055 52.280

Percent of Total 14.7% 12.1% 9.9% 10.1% 10.2% 10.4% 4.4% -19.5%

Class Other (20,170) 8,289 11,030 9,118 11,167 11,905 10,170 -1,735 1,881 0.504

Percent of Total 5.0% 5.9% 4.8% 5.7% 6.0% 5.1% -14.6% 22.7%

Category I (164) 146,458 162,144 169,056 173,325 173,225 178,269 5,044 31,811 1,087.006

Percent of Total 82.8% 86.9% 88.2% 88.6% 87.9% 88.6% 2.9% 21.7%

Category II (532) 18,033 13,123 13,346 11,051 11,983 12,494 511 -5,539 23.485

Percent of Total 12.5% 7.0% 7.0% 5.7% 6.1% 6.2% 4.3% -30.7%

Category III (19,974) 7,952 R11,243 9,342 11,184 11,937 10,437 -1,500 2,485 0.523

Percent of Total 4.7% 6.0% 4.9% 5.7% 6.1% 5.2% -12.6% 31.2%

Total Published 176,159 186,510 191,743 195,561 197,145 201,200 4,055 25,041 9.734

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 2.1% 14.2%

Table A1. Natural Gas Proved Reserves, Wet After Lease Separation, by Operator Production Size Class,

1999–2004

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

2003–2004 1999–2004 2004

Volume and Volume and Average

Percent Percent Reserves

Size Class 1999 2000 2001 2002 2003 2004 Change Change per Operator

R = Revised

Note: There were 19,974 active Category III operators in the 2004 sample frame.The reserves and production of Category III operators

were estimated from an adjusted sample of 606 Category III operators (Table E2). The "other" size class represents 20,170 operators in the

2004 frame (20,670 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 2004 Annual Report A-5

Class 1-10 6,881 8,495 9,019 8,996 8,220 7,617 -603 736 761.662

Percent of Total 34.7% 42.1% 43.7% 44.4% 40.6% 38.1% -7.3% 10.7%

Class 11-20 3,560 2,886 3,064 2,854 3,136 3,647 511 87 364.658

Percent of Total 14.1% 14.3% 14.8% 14.1% 15.5% 18.2% 16.3% 2.4%

Class 21-100 5,523 4,965 4,949 4,763 5,275 4,982 -293 -541 62.275

Percent of Total 29.6% 24.6% 24.0% 23.5% 26.1% 24.9% -5.6% -9.8%

Class 101-500 2,793 2,780 2,609 2,475 2,386 2,559 173 -234 6.396

Percent of Total 14.7% 13.8% 12.6% 12.2% 11.8% 12.8% 7.2% -8.4%

Class Other (20,170) 1,099 1,038 1,000 1,161 1,215 1,213 -1 114 0.060

Percent of Total 5.0% 5.1% 4.8% 5.7% 6.0% 6.1% -0.1% 10.4%

Category I (164) 16,248 17,096 17,672 17,335 17,347 17,036 -311 788 103.876

Percent of Total 82.8% 84.8% 85.6% 85.6% 85.7% 85.1% -1.8% 4.8%

Category II (532) 2,556 1,921 1,932 1,738 1,648 1,718 70 -838 3.230

Percent of Total 12.5% 9.5% 9.4% 8.6% 8.1% 8.6% 4.3% -32.8%

Category III (19,974) 1,052 1,147 1,038 1,176 1,236 1,263 27 211 0.063

Percent of Total 4.7% 5.7% 5.0% 5.8% 6.1% 6.3% 2.1% 20.0%

Total Published 19,856 20,164 20,642 20,248 20,231 20,017 -214 161 0.968

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -1.1% 0.8%

Table A2. Natural Gas Production, Wet After Lease Separation, by Operator Production Size Class,

1999–2004

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

2003–2004 1999–2004 2004

Volume and Volume and Average

Percent Percent Production

Size Class 1999 2000 2001 2002 2003 2004 Change Change per Operator

R = Revised

Note: There were 19,974 active Category III operators in the 2004 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 606 Category III operators (Table E2). The "other" size class represents 20,170 operators in the

2004 frame (20,670 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 2004 Annual Report

Class 1-10 11,121 12,367 13,590 13,346 13,355 12,454 -901 1,333 1,245.392

Percent of Total 51.1% 56.1% 60.5% 58.9% 61.0% 58.3% -6.7% 12.0%

Class 11-20 2,585 3,172 2,901 2,817 1,907 2,053 145 -532 205.270

Percent of Total 11.9% 14.4% 12.9% 12.4% 8.7% 9.6% 7.6% -20.6%

Class 21-100 4,338 2,505 2,856 3,230 3,483 3,711 228 -627 46.386

Percent of Total 19.9% 11.4% 12.7% 14.2% 15.9% 17.4% 6.5% -14.5%

Class 101-500 2,379 2,286 1,794 1,817 1,705 1,761 55 -618 4.402

Percent of Total 10.9% 10.4% 8.0% 8.0% 7.8% 8.2% 3.2% -26.0%

Class Other (20,170) 1,342 1,716 1,305 1,468 1,440 1,393 -47 51 0.069

Percent of Total 6.2% 7.8% 5.8% 6.5% 6.6% 6.5% -3.3% 3.8%

Category I (164) 18,952 19,421 20,325 20,213 19,499 19,055 -443 103 116.192

Percent of Total 87.1% 88.1% 90.6% 89.1% 89.1% 89.2% -2.3% 0.5%

Category II (532) 1,521 873 794 992 937 906 -31 -615 1.703

Percent of Total 7.0% 4.0% 3.5% 4.4% 4.3% 4.2% -3.3% -40.4%

Category III (19,974) 1,293 1,751 1,326 1,472 1,456 1,410 -46 117 0.071

Percent of Total 5.9% 7.9% 5.9% 6.5% 6.6% 6.6% -3.1% 9.0%

Total Published 21,765 22,045 22,446 22,677 21,891 21,371 -520 -394 1.034

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -2.4% -1.8%

Table A3. Crude Oil Proved Reserves by Operator Production Size Class, 1999–2004

(Million Barrels of 42 U.S. Gallons)

2003–2004 1999–2004 2004

Volume and Volume and Average

Percent Percent Reserves

Size Class 1999 2000 2001 2002 2003 2004 Change Change per Operator

R = Revised

Note: There were 19,974 active Category III operators in the 2004 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 606 Category III operators (Table E2). The "other" size class represents 20,170 operators in the

2004 frame (20,670 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 2004 Annual Report A-7

Class 1-10 974 961 1,061 1,037 1,047 986 -61 12 98.641

Percent of Total 49.9% 51.1% 55.4% 55.3% 55.8% 54.2% -5.8% 1.3%

Class 11-20 241 304 240 233 205 180 -25 -61 18.025

Percent of Total 12.3% 16.2% 12.5% 12.4% 10.9% 9.9% -12.0% -25.2%

Class 21-100 350 214 233 240 272 303 31 -47 3.783

Percent of Total 17.9% 11.4% 12.2% 12.8% 14.5% 16.6% 11.3% -13.5%

Class 101-500 208 211 195 181 178 172 -6 -36 0.430

Percent of Total 10.7% 11.2% 10.2% 9.7% 9.5% 9.5% -3.5% -17.3%

Class Other (20,170) 179 190 186 184 175 178 3 -1 0.009

Percent of Total 9.2% 10.1% 9.7% 9.8% 9.3% 9.8% 1.7% -0.8%

Category I (164) 1,617 1,572 1,612 1,573 1,574 1,534 -40 -83 9.353

Percent of Total 82.8% 83.6% 84.2% 83.9% 83.9% 84.3% -2.6% -5.1%

Category II (532) 160 111 112 115 124 105 -19 -55 0.198

Percent of Total 8.2% 5.9% 5.8% 6.1% 6.6% 5.8% -15.1% -34.1%

Category III (19,974) 175 197 191 187 179 180 1 5 0.009

Percent of Total 9.0% 10.5% 10.0% 10.0% 9.5% 9.9% 0.6% 2.6%

Total Published 1,952 1,880 1,915 1,875 1,877 1,819 -58 -133 0.088

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -3.1% -6.8%

Table A4. Crude Oil Production by Operator Production Size Class, 1999–2004

(Million Barrels of 42 U.S. Gallons)

2003–2004 1999–2004 2004

Volume and Volume and Average

Percent Percent Production

Size Class 1999 2000 2001 2002 2003 2004 Change Change per Operator

R = Revised

Note: There were 19,974 active Category III operators in the 2004 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 606 Category III operators (Table E2). The "other" size class represents 20,170 operators in the

2004 frame (20,670 active operators minus the 500 largest operators).

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

A-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Class 1-10 2,559 3,444 3,794 3,596 3,689 3,409 -280 850 340.900

Percent of Total 10.0% 13.0% 14.0% 12.9% 13.2% 12.4% -7.6% 33.2%

Class 11-20 1,514 1,923 2,212 2,392 2,492 3,352 860 1,838 335.200

Percent of Total 5.9% 7.2% 8.2% 8.6% 8.9% 12.2% 34.5% 121.4%

Class 21-100 8,180 7,084 7,195 7,947 8,168 8,071 -97 -109 100.888

Percent of Total 32.0% 26.7% 26.5% 28.4% 29.3% 29.4% -1.2% -1.3%

Class 101-500 12,344 12,580 12,435 12,661 11,859 10,698 -1,161 -1,646 26.745

Percent of Total 48.2% 47.4% 45.9% 45.3% 42.5% 39.0% -9.8% -13.3%

Rest 1,287 1,529 1,480 1,349 1,709 1,929 220 642 9.842

Percent of Total 5.0% 5.8% 5.5% 4.8% 6.1% 7.0% 12.9% 49.9%

Category I 15,120 16,174 16,196 17,049 16,760 17,368 608 2,248 105.902

Percent of Total 59.1% 60.9% 59.7% 61.0% 60.0% 63.3% 3.6% 14.9%

Category II 10,467 10,146 10,764 10,473 10,688 9,486 -1,202 -981 17.831

Percent of Total 40.9% 38.2% 39.7% 37.5% 38.3% 34.5% -11.2% -9.4%

Total 25,587 26,560 27,116 27,945 27,917 27,459 -458 1,872 39.453

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -1.6% 7.3%

Note: Includes only data from Category I and Category II operators. In 2004 there were 164 Category I operators and 532 Category II

operators. The “rest” size class had 196 operators in 2004.

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

Table A5. Operator Field Count by Operator Production Size Class, 1999–2004

2003–2004 1999–2004 2004 Average

Number and Number and Number of

Percent Percent Fields per

Size Class 1999 2000 2001 2002 2003 2004 Change Change Operator
Table A6. Top 50 U.S. Operators Ranked by Reported 2004 Operated Production Data

Total Natural Gas

Crude Oil Production Production

Rank Company Name (thousand barrels/day) Rank Company Name (milion cubic feet/day)

1 BP PLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 827 1 BP PLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,252

2 CHEVRONTEXACO INC . . . . . . . . . . . . . . . . . . . 493 2 EXXONMOBIL CORP ................... 2,513

3 SHELL EXPLORATION & PRODUCTION CO . . . 413 3 DEVON ENERGY CORPORATION ........ 2,244

4 CONOCOPHILLIPS CO . . . . . . . . . . . . . . . . . . . . 322 4 CHEVRONTEXACO INC................. 2,128

5 OCCIDENTAL PETROLEUM CORP . . . . . . . . . . 261 5 CONOCOPHILLIPS CO.................. 2,110

6 AERA ENERGY LLC . . . . . . . . . . . . . . . . . . . . . . 216 6 BURLINGTON RESOURCES OIL & GAS CO 1,928

7 EXXONMOBIL CORP. . . . . . . . . . . . . . . . . . . . . . 213 7 SHELL EXPLORATION & PRODUCTION CO 1,894

8 KERR-MCGEE CORP . . . . . . . . . . . . . . . . . . . . . 152 8 ANADARKO PETROLEUM CORP ......... 1,628

9 APACHE CORP . . . . . . . . . . . . . . . . . . . . . . . . . . . 95 9 KERR-MCGEE CORP ................... 1,459

10 ANADARKO PETROLEUM CORP. . . . . . . . . . . . . 88 10 CHESAPEAKE OPERATING INC. ......... 1,368

Top 10 Volume Subtotal 3,080 Top 10 Volume Subtotal 21,524

Top 10 Percentage of U.S. Total 56% Top 10 Percentage of U.S. Total 39%

11 AMERADA HESS CORP . . . . . . . . . . . . . . . . . . . . 83 11 ENCANA OIL & GAS INC ................ 1,328

12 DEVON ENERGY CORPORATION . . . . . . . . . . . . 74 12 APACHE CORP........................ 1,276

13 PLAINS EXPLOR & PROD CO . . . . . . . . . . . . . . . 66 13 XTO ENERGY INC ..................... 1,219

14 MARATHON OIL CO . . . . . . . . . . . . . . . . . . . . . . . 59 14 DOMINION RESOURCES INC ............ 1,099

15 UNOCAL CORP . . . . . . . . . . . . . . . . . . . . . . . . . . . 54 15 EL PASO ENERGY ..................... 1,010

16 KINDER MORGAN PROD CO INC . . . . . . . . . . . . 48 16 E O G RESOURCES INC. . . . . . . . . . . . . . . . . . 936

17 BURLINGTON RESOURCES OIL & GAS CO . . . . 37 17 UNOCAL CORP . . . . . . . . . . . . . . . . . . . . . . . . . 843

18 MERIT ENERGY CO . . . . . . . . . . . . . . . . . . . . . . . 36 18 MARATHON OIL CO . . . . . . . . . . . . . . . . . . . . . 808

19 POGO PRODUCING CO . . . . . . . . . . . . . . . . . . . . 33 19 NEWFIELD EXPLORATION CO . . . . . . . . . . . . 745

20 CITY OF LONG BEACH . . . . . . . . . . . . . . . . . . . . . 32 20 PIONEER NATURAL RESOURCES USA INC. . 698

Top 20 Volume Subtotal 3,602 Top 20 Volume Subtotal 31,486

Top 20 Percentage of U.S. Total 66% Top 20 Percentage of U.S. Total 58%

21 XTO ENERGY INC . . . . . . . . . . . . . . . . . . . . . . . . . 31 21 OCCIDENTAL PETROLEUM CORP . . . . . . . . . 656

22 E O G RESOURCES INC . . . . . . . . . . . . . . . . . . . . 30 22 WILLIAMS ENERGY INC . . . . . . . . . . . . . . . . . . 577

23 CITATION OIL & GAS CORP. . . . . . . . . . . . . . . . . 28 23 SAMSON RESOURCES CO . . . . . . . . . . . . . . . 504

24 PIONEER NATURAL RESOURCES USA INC. . . . 28 24 QUESTAR CORP . . . . . . . . . . . . . . . . . . . . . . . . 471

25 DENBURY RESOURCES INC. . . . . . . . . . . . . . . . 27 25 AMERADA HESS CORP . . . . . . . . . . . . . . . . . . 346

26 NEXEN PETROLEUM USA INC. . . . . . . . . . . . . . . 26 26 TOTALFINAELF SA . . . . . . . . . . . . . . . . . . . . . . 330

27 CHESAPEAKE OPERATING INC. . . . . . . . . . . . . . 26 27 HOUSTON EXPLORATION . . . . . . . . . . . . . . . . 324

28 MURPHY OIL CORP . . . . . . . . . . . . . . . . . . . . . . . 26 28 MERIT ENERGY CO . . . . . . . . . . . . . . . . . . . . . 290

29 DOMINION RESOURCES INC. . . . . . . . . . . . . . . . 23 29 NOBLE ENERGY INC . . . . . . . . . . . . . . . . . . . . 288

30 HILCORP ENERGY CO . . . . . . . . . . . . . . . . . . . . . 22 30 YATES PETROLEUM CORP . . . . . . . . . . . . . . . 280

31 NEWFIELD EXPLORATION CO . . . . . . . . . . . . . . 22 31 POGO PRODUCING CO . . . . . . . . . . . . . . . . . . 275

32 ENCORE OPERATING LP. . . . . . . . . . . . . . . . . . . 22 32 ENERGEN RESOURCES CORP. . . . . . . . . . . . 273

33 BERRY PETROLEUM CO . . . . . . . . . . . . . . . . . . . 21 33 PATINA OIL & GAS CORP. . . . . . . . . . . . . . . . . 270

34 PATINA OIL & GAS CORP. . . . . . . . . . . . . . . . . . . 21 34 CIMAREX ENERGY CO. . . . . . . . . . . . . . . . . . . 257

35 FOREST OIL CORP . . . . . . . . . . . . . . . . . . . . . . . . 20 35 FOREST OIL CORP . . . . . . . . . . . . . . . . . . . . . . 253

36 ENI PETROLEUM CO INC . . . . . . . . . . . . . . . . . . . 20 36 WALTER OIL & GAS CORP. . . . . . . . . . . . . . . . 248

37 NOBLE ENERGY INC . . . . . . . . . . . . . . . . . . . . . . 19 37 HUNT OIL CO. . . . . . . . . . . . . . . . . . . . . . . . . . . 246

38 VINTAGE PETROLEUM INC . . . . . . . . . . . . . . . . . 18 38 EQUITABLE RESOURCES INC. . . . . . . . . . . . . 246

39 ST MARY LAND & EXPLOR CO . . . . . . . . . . . . . . 17 39 CABOT OIL & GAS CORP . . . . . . . . . . . . . . . . . 236

40 STONE ENERGY CORP . . . . . . . . . . . . . . . . . . . . 16 40 HILCORP ENERGY CO . . . . . . . . . . . . . . . . . . . 211

41 EL PASO ENERGY . . . . . . . . . . . . . . . . . . . . . . . . 16 41 HUNT PETROLEUM CORPORATION. . . . . . . . 199

42 SWIFT ENERGY CO . . . . . . . . . . . . . . . . . . . . . . . 15 42 KAISER FRANCIS OIL CO. . . . . . . . . . . . . . . . . 188

43 BHP BILLITON . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 43 W & T OFFSHORE INC . . . . . . . . . . . . . . . . . . . 172

44 TOTALFINAELF SA . . . . . . . . . . . . . . . . . . . . . . . . 14 44 RED WILLOW PRODUCTION CO . . . . . . . . . . . 162

45 CONTINENTAL RESOURCES INC . . . . . . . . . . . . 14 45 STONE ENERGY CORP . . . . . . . . . . . . . . . . . . 160

46 NATIONAL FUEL GAS . . . . . . . . . . . . . . . . . . . . . . 13 46 ENERGY PARTNERS LTD . . . . . . . . . . . . . . . . 158

47 GRUY PETROLEUM MANAGEMENT CO. . . . . . . 13 47 WESTERN GAS RESOURCES INC. . . . . . . . . . 156

48 ENERGEN RESOURCES CORP. . . . . . . . . . . . . . 13 48 C N X GAS CO LLC . . . . . . . . . . . . . . . . . . . . . . 156

49 ENDEAVOR ENERGY RESOURCES LP . . . . . . . 12 49 FIDELITY EXPLORATION & PROD CO . . . . . . 151

50 WALTER OIL & GAS CORP. . . . . . . . . . . . . . . . . . 12 50 PEOPLES ENERGY CORP . . . . . . . . . . . . . . . . 150

Top 50 Volume Subtotal 4,202 Top 50 Volume Subtotal 39,719

Top 50 Percentage of U.S. Total 77% Top 50 Percentage of U.S. Total 73%

Note: Crude oil production includes production of lease condensate. Total natural gas production is wet after lease separation.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report A-9

Appendix B

Top 100 Oil and Gas Fields

Appendix B

Top 100 Oil and Gas Fields

This appendix presents estimates of the proved

reserves and production of the top 100 liquids or gas

fields by reserves or by production. The liquids

production and reserve data include both crude oil and

lease condensate, and are 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 may be estimated for the proved reserves

and production of most fields. 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 liquids 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 2004

tables.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report B-1

Summary for the Top 100 Fields for 2004 Liquids and Gas

12/31/2004 12/31/2004 Est.

Proved Nonproducing 2004 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 6,813.1 30.2% 1,591.6 28.7% 432.9 21.6%

Top 20 9,289.7 41.1% 2,252.1 40.6% 584.9 29.2%

Top 50 12,564.7 55.6% 3,148.2 56.7% 823.5 41.2%

Top 100 14,893.3 65.9% 3,782.2 68.1% 1,016.0 50.8%

Others 7,698.7 34.1% 1,769.8 31.9% 985.0 49.2%

Total 22,592.0 100.0% 5,552.0 100.0% 2,001.0 100.0%

Table B2. Top 100 U.S. Fields as Ranked by Gas Proved Reserves (Billion Cubic Feet)

Top 10 51,973.3 25.8% 10,221.2 19.9% 3,584.3 17.9%

Top 20 69,821.9 34.7% 14,362.2 27.9% 4,781.2 23.9%

Top 50 92,477.1 46.0% 20,800.8 40.5% 6,574.9 32.8%

Top 100 110,298.0 54.8% 25,915.7 50.4% 8,012.5 40.0%

Others 90,902.0 45.2% 25,496.3 49.6% 12,004.5 60.0%

Total 201,200.0 100.0% 51,412.0 100.0% 20,017.0 100.0%

Table B3. Top 100 U.S. Fields as Ranked by Liquids Production (Million Barrels)

Top 10 n/a n/a n/a n/a 516.4 25.8%

Top 20 n/a n/a n/a n/a 684.5 34.2%

Top 50 n/a n/a n/a n/a 934.3 46.7%

Top 100 n/a n/a n/a n/a 1,139.8 57.0%

Others n/a n/a n/a n/a 861.2 43.0%

Total n/a n/a n/a n/a 2,001.0 100.0%

Table B4. Top 100 U.S. Fields as Ranked by Gas Production (Billion Cubic Feet)

Top 10 n/a n/a n/a n/a 3,797.6 19.0%

Top 20 n/a n/a n/a n/a 5,006.1 25.0%

Top 50 n/a n/a n/a n/a 6,974.6 34.8%

Top 100 n/a n/a n/a n/a 8,746.1 43.7%

Others n/a n/a n/a n/a 11,270.9 56.3%

Total n/a n/a n/a n/a 20,017.0 100.0%
Table B1. Top 100 Liquids Fields Ranked by

Reserves

The top 100 liquids fields by reserves had 14,893

million barrels of proved reserves accounting for 66

percent of the total United States as of December 31,

2004, (Table 6 and Table 14) and 68 percent of the

reported nonproducing reserves. In the top 20 liquids

fields for 2004 there are five fields, which are in the

deep water of the Gulf of Mexico Federal Offshore and

four are currently nonproducing.

The top 100 liquids fields by reserves had 1,016 million

barrels of production, or 51 percent of the 2004 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 Salt Creek field in Wyoming,

moving to 29rd in 2004, as the operator increased

enhanced oil recovery by CO2 injection.

Table B2. Top 100 Gas Fields Ranked by Reserves

The top 100 gas fields by reserves had 110,298 billion

cubic feet of wet natural gas proved reserves or 55

percent of the total, as of December 31, 2004 (Table 9)

and 50 percent of the reported nonproducing reserves.

The top 100 gas fields by reserves had 8,012 billion

cubic feet of production, or 40percent of the 2004 U.S.

total (Table 9).

Table B3. Top 100 Liquids Fields Ranked by

Production

The top 100 liquids fields by production had 1,139

million barrels of production, or 57 percent of the 2004

U.S. total (Table 6 and Table 14).

Table B4. Top 100 Gas Fields Ranked by Production

The top 100 gas fields had 8,746 billion cubic feet of

production, or 44 percent of the 2004 U.S. total (Table

9).

Energy Information Administration

B-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report B-3

Table B1. Top 100 U.S. Fields Ranked by Liquids Proved Reserves from Estimated 2004 Field Level Dataa

(Million Barrels of 42 U.S. Gallons)

Rank Group 2004 Estimated

Discovery Proved Nonproducing Production

Num Field Name Location Year Reserves Reserves Volume

1 PRUDHOE BAY AK 1967 (1-10) 129.0

2 WASSON TX 1937 (1-10) 24.8

3 KUPARUK RIVER AK 1969 (1-10) 51.1

4 BELRIDGE SOUTH CA 1911 (1-10) 39.8

5 MISSISSIPPI CANYON BLK 807 (MARS-URSA) FG 1989 (1-10) 98.4

6 MISSISSIPPI CANYON BLK 778 (THUNDER HORSE) FG 1999 (1-10) 0.0

7 MIDWAY-SUNSET CA 1901 (1-10) 45.0

8 SPRABERRY TREND AREA TX 1950 (1-10) 26.2

9 GREEN CANYON BLK 699 (ATLANTIS) FG 1998 (1-10) 0.0

10 ELK HILLS CA 1920 (1-10) 18.7

Top 10 Volume Subtotal 6,813.1 1,591.6 432.9

Top 10 Percentage of U.S. Total 30.2% 28.7% 21.6%

11 KERN RIVER CA 1899 (11-20) 35.1

12 ALPINE AK 1994 (11-20) 36.1

13 SLAUGHTER TX 1937 (11-20) 14.8

14 MILNE POINT AK 1982 (11-20) 18.8

15 GREEN CANYON BLK 644 (HOLSTEIN) FG 1999 (11-20) 0.0

16 HONDO FP 1969 (11-20) 8.0

17 GREEN CANYON BLK 826 (MAD DOG) FG 1999 (11-20) 0.0

18 CYMRIC CA 1916 (11-20) 18.8

19 LEVELLAND TX 1945 (11-20) 9.5

20 LOST HILLS CA 1910 (11-20) 11.1

Top 20 Volume Subtotal 9,289.7 2,252.1 584.9

Top 20 Percentage of U.S. Total 41.1% 40.6% 29.2%

21 WILMINGTON CA 1932 (21-50) 14.8

22 WATTENBERG CO 1970 (21-50) 10.8

23 CEDAR HILLS ND & MT & SD 1951 (21-50) 7.9

24 GREEN CANYON BLK 640 (TAHITI) FG 2002 (21-50) 0.0

25 WEST SAK AK 1969 (21-50) 4.5

26 PESCADO FP 1970 (21-50) 5.3

27 MISSISSIPPI CANYON BLK 84 (KING/HORN MT.) FG 1993 (21-50) 31.0

28 SHO-VEL-TUM OK 1905 (21-50) 9.1

29 SALT CREEK WY 1889 (21-50) 1.6

30 ENDICOTT AK 1978 (21-50) 7.7

31 INGLEWOOD CA 1924 (21-50) 2.5

32 POINT MCINTYRE AK 1988 (21-50) 13.9

33 COWDEN NORTH TX 1930 (21-50) 7.2

34 HOBBS NM 1928 (21-50) 4.0

35 SAN ARDO CA 1947 (21-50) 4.0

36 SACATE FP 1970 (21-50) 3.0

37 GREEN CANYON BLK 339 (FRONT RUNNER) FG 2001 (21-50) 0.3

38 KELLY-SNYDER TX 1948 (21-50) 10.4

39 NORTHSTAR AK 1984 (21-50) 24.7

40 ORION AK 2002 (21-50) 2.1

41 YATES TX 1926 (21-50) 7.2

42 MISSISSIPPI CANYON BLK 383 (KEPLER) FG 1987 (21-50) 21.0

43 VENTURA CA 1916 (21-50) 4.4

44 BOREALIS AK 2001 (21-50) 9.9

45 ROBERTSON NORTH TX 1956 (21-50) 4.6

46 MCELROY TX 1926 (21-50) 5.3

47 VACUUM NM 1929 (21-50) 6.4

48 ELM COULEE MT 2000 (21-50) 5.7

49 GOLDSMITH NORTH TX 1946 (21-50) 5.1

50 FULLERTON TX 1942 (21-50) 4.3

Top 50 Volume Subtotal 12,564.7 3,148.2 823.5

Top 50 Percentage of U.S. Total 55.6% 56.7% 41.2%
Energy Information Administration

B-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

51 MISSISSIPPI CANYON BLK 773 (DEVILS TOWER) FG 2000 (51-100) 3.0

52 LOOKOUT BUTTE EAST MT 1986 (51-100) 4.6

53 GREATER ANETH UT 1956 (51-100) 3.6

54 HAWKINS TX 1940 51-100) 2.8

55 SEMINOLE TX 1936 (51-100) 8.5

56 VIOSCA KNOLL BLK 786 (PETRONIUS) FG 1996 (51-100) 11.5

57 RANGELY CO 1902 (51-100) 5.0

58 MONUMENT BUTTE UT 1964 (51-100) 2.8

59 PENNEL MT 1955 (51-100) 2.1

60 GREEN CANYON BLK 680 FG 2003 (51-100) 0.0

61 POLARIS AK 2000 (51-100) 1.0

62 LAKE WASHINGTON LA 1931 (51-100) 5.3

63 ARROYO GRANDE CA 1906 (51-100) 0.6

64 MISSISSIPPI CANYON BLK 20 FG 1995 (51-100) 0.3

65 JAY AL & FL 1951 (51-100) 2.4

66 GIDDINGS TX 1960 (51-100) 9.1

67 COALINGA CA 1887 (51-100) 6.0

68 LISBURNE AK 1967 (51-100) 3.4

69 GREEN CANYON BLK 518 (K2 NORTH) FG 2003 (51-100) 0.0

70 SALT CREEK TX 1942 (51-100) 4.2

71 BELRIDGE NORTH CA 1912 (51-100) 3.2

72 MEANS TX 1934 (51-100) 3.4

73 MISSISSIPPI CANYON BLK 582 (MEDUSA) FG 2000 (51-100) 10.2

74 TARN AK 1991 (51-100) 10.6

75 CEDAR LAKE TX 1939 (51-100) 2.4

76 AURORA AK 1969 (51-100) 3.3

77 KERN FRONT CA 1925 (51-100) 1.6

78 HOWARD-GLASSCOCK TX 1925 (51-100) 2.8

79 WESTBROOK TX 1920 (51-100) 1.5

80 EWING BANK BLK 873 (LOBSTER) FG 1991 (51-100) 6.6

81 MELTWATER AK 2001 (51-100) 2.5

82 GREEN CANYON BLK 562 (K2) FG 1999 (51-100) 0.0

83 ANTON-IRISH TX 1944 (51-100) 4.2

84 PINEDALE WY 1955 (51-100) 1.1

85 DOLLARHIDE NM & TX 1945 (51-100) 2.9

86 EAST BREAKS BLK 602 (NANSEN) FG 1999 (51-100) 11.3

87 EAST TEXAS TX 1930 (51-100) 4.7

88 BLUEBELL UT 1949 (51-100) 2.5

89 GARDEN BANKS BLK 215 (BALDPATE) FG 1995 (51-100) 9.0

90 JO-MILL TX 1953 (51-100) 2.5

91 PATRICK DRAW WY 1959 (51-100) 0.3

92 VIOSCA KNOLL BLK 990 (POMPANO) FG 1981 (51-100) 4.9

93 GREEN CANYON BLK 243 (ASPEN) FG 2001 (51-100) 7.1

94 IATAN EAST HOWARD TX 1926 (51-100) 1.5

95 NIAKUK AK 1984 (51-100) 4.0

96 FOSTER TX 1932 (51-100) 2.6

97 WELCH TX 1942 (51-100) 2.0

98 ELK BASIN MT & WY 1915 (51-100) 2.0

99 GARDEN BANKS BLK 668 (GUNNISON) FG 2000 (51-100) 4.1

100 SOUTH PASS EA BLK 62 FG 1967 (51-100) 1.0

Top 100 Volume Subtotal 14,893.3 3,782.2 1,016.0

Top 100 Percentage of U.S. Total 65.9% 68.1% 50.8%

Table B1. Top 100 U.S. Fields Ranked by Liquids Proved Reserves from Estimated 2004 Field Level Dataa

(Continued)

(Million Barrels of 42 U.S. Gallons)

Rank Group 2004 Estimated

Discovery Proved Nonproducing Production

Num Field Name Location Year Reserves Reserves Volume

aIncludes lease condensate.

Notes: The U.S. total production estimate of 2,001 million barrels and the U.S. total reserves estimate of 22,592 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 2004 Annual Report B-5

Table B2. Top 100 U.S. Fields Ranked by Gas Proved Reserves from Estimated 2004 Field Level Dataa

(Billion Cubic Feet)

Rank Group 2004 Estimated

Discovery Proved Nonproducing Production

Num Field Name Location Year Reserves Reserves Volume

1 SAN JUAN BASIN GAS AREA CO & NM 1927 (1-10) 1450.8

2 PRUDHOE BAY AK 1967 (1-10) 209.3

3 PINEDALE WY 1955 (1-10) 150.4

4 NEWARK EAST TX 1981 (1-10) 412.6

5 HUGOTON GAS AREA KS & OK & TX 1922 (1-10) 307.9

6 JONAH WY 1977 (1-10) 250.9

7 LOWER MOBILE BAY AREA AL & FG 1979 (1-10) 290.1

8 WATTENBERG CO 1970 (1-10) 192.0

9 MADDEN WY 1968 (1-10) 153.5

10 ANTRIM MI 1965 (1-10) 166.7

Top 10 Volume Subtotal 51,973.3 10,221.2 3,584.3

Top 10 Percentage of U.S. Total 25.8% 19.9% 17.9%

11 RATON BASIN GAS AREA CO & NM 1998 (11-20) 101.8

12 CARTHAGE TX 1923 (11-20) 191.4

13 PRB COAL BED WY 1992 (11-20) 325.7

14 NATURAL BUTTES UT 1952 (11-20) 103.9

15 SPRABERRY TREND AREA TX 1950 (11-20) 128.7

16 SAWYER TX 1975 (11-20) 76.5

17 VERNON LA 1967 (11-20) 90.7

18 FOGARTY CREEK WY 1975 (11-20) 36.6

19 MAMM CREEK CO 1959 (11-20) 95.7

20 BIG SANDY KY & WV 1926 (11-20) 45.8

Top 20 Volume Subtotal 69,821.9 14,362.2 4,781.2

Top 20 Percentage of U.S. Total 34.7% 27.9% 23.9%

21 OAKWOOD VA 1990 (21-50) 56.9

22 MISSISSIPPI CANYON BLK 807 (MARS-URSA) FG 1989 (21-50) 149.3

23 GRAND VALLEY CO 1985 (21-50) 42.3

24 ELK HILLS CA 1920 (21-50) 105.7

25 ELM GROVE LA 1958 (21-50) 73.2

26 PANHANDLE WEST TX 1918 (21-50) 97.4

27 RED OAK-NORRIS OK 1910 (21-50) 64.7

28 OAK HILL TX 1958 (21-50) 66.2

29 STRONG CITY DISTRICT OK 1966 (21-50) 71.9

30 RULISON CO 1958 (21-50) 37.9

31 DRUNKARDS WASH UT 1989 (21-50) 68.4

32 LAKE RIDGE WY 1981 (21-50) 16.9

33 BALD PRAIRIE TX 1976 (21-50) 51.9

34 PANOMA GAS AREA KS 1956 (21-50) 57.4

35 PARACHUTE CO 1985 (21-50) 32.5

36 MAYFIELD NE OK 1951 (21-50) 108.1

37 BELUGA RIVER AK 1962 (21-50) 56.7

38 GIDDINGS TX 1960 (21-50) 106.8

39 GOLDEN TREND OK 1945 (21-50) 42.6

40 MOCANE-LAVERNE GAS AREA KS & OK & TX 1946 (21-50) 79.8

41 FARRAR TX 1963 (21-50) 40.2

42 GOMEZ TX 1977 (21-50) 48.0

43 OAKS TX 1975 (21-50) 29.4

44 KINTA OK 1914 (21-50) 51.1

45 BUFFALO WALLOW TX 1978 (21-50) 39.4

46 WILD ROSE WY 1975 (21-50) 22.0

47 WATONGA-CHICKASHA TREND OK 1962 (21-50) 56.0

48 WAMSUTTER WY 1958 (21-50) 31.5

49 DEW TX 1982 (21-50) 42.5

50 FREESTONE TX 1949 (21-50) 46.9

Top 50 Volume Subtotal 92,477.1 20,800.8 6,574.9

Top 50 Percentage of U.S. Total 46.0% 40.5% 32.8%
Energy Information Administration

B-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table B2. Top 100 U.S. Fields Ranked by Gas Proved Reserves from Estimated 2004 Field Level Dataa

(Continued)

(Billion Cubic Feet)

Rank Group 2004 Estimated

Discovery Proved Nonproducing Production

Num Field Name Location Year Reserves Reserves Volume

51 DOWDY RANCH TX 1999 (51-100) 42.9

52 SLIGO LA 1922 (51-100) 30.9

53 STANDARD DRAW WY 1979 (51-100) 21.6

54 COOK INLET NORTH AK 1962 (51-100) 42.8

55 MISSISSIPPI CANYON BLK 383 (KEPLER) FG 1987 (51-100) 100.4

56 WASSON TX 1937 (51-100) 24.0

57 EAST BREAKS BLK 602 (NANSEN) FG 1999 (51-100) 57.6

58 OVERTON TX 1973 (51-100) 34.3

59 HALEY TX 1985 (51-100) 15.9

60 GREEN RIVER BEND WY 1958 (51-100) 34.7

61 MISSISSIPPI CANYON BLK 778 (THUNDER HORSE) FG 1999 (51-100) 0.0

62 SHO-VEL-TUM OK 1905 (51-100) 39.0

63 ECHO SPRINGS WY 1977 (51-100) 25.8

64 EAST BREAKS BLK 945 (DIANA) FG 1994 (51-100) 57.7

65 WILBURTON OK 1941 (51-100) 37.7

66 SIBERIA RIDGE WY 1976 (51-100) 8.3

67 MIMMS CREEK TX 1978 (51-100) 42.7

68 ELK CITY OK 1947 (51-100) 49.4

69 VIOSCA KNOLL BLK 956 (RAM-POWELL) FG 1985 (51-100) 64.0

70 BRUFF WY 1969 (51-100) 31.1

71 VERDEN OK 1948 (51-100) 28.4

72 BEAR GRASS TX 1977 (51-100) 17.4

73 CEDARDALE NE OK 1958 (51-100) 24.5

74 MISSISSIPPI CANYON BLK 731 (MENSA) FG 1987 (51-100) 84.6

75 KUPARUK RIVER AK 1969 (51-100) 18.1

76 HOLLY LA 1928 (51-100) 22.1

77 NORA VA 1949 (51-100) 2.4

78 MOBILE BLK 823 FG 1983 (51-100) 30.8

79 CEMENT OK 1917 (51-100) 38.7

80 BROWN-BASSETT TX 1953 (51-100) 32.1

81 EXSUN TX 1974 (51-100) 34.6

82 OZONA TX 1962 (51-100) 25.0

83 STILES RANCH TX 1984 (51-100) 9.9

84 DAVIDSON RANCH TX 1980 (51-100) 16.8

85 STRATTON TX 1937 (51-100) 15.5

86 GREEN CANYON BLK 699 (ATLANTIS) FG 1998 (51-100) 0.0

87 TEAGUE TX 1945 (51-100) 8.3

88 BOONSVILLE TX 1950 (51-100) 27.0

89 BETHANY TX 1936 (51-100) 28.6

90 BLANCO SOUTH NM 1951 (51-100) 20.7

91 WHISKEY BUTTE WY 1975 (51-100) 18.7

92 MISSISSIPPI CANYON BLK 657 (COULOMB) FG 1988 (51-100) 9.0

93 OAK GROVE COAL DEGASIFICATION AL 1980 (51-100) 15.8

94 WILLOW SPRINGS TX 1954 (51-100) 26.4

95 KENAI AK 1959 (51-100) 24.3

96 BLOCKER TX 1954 (51-100) 9.8

97 BROOKWOOD COAL DEGASIFICATION AL 1981 (51-100) 18.7

98 OKEENE NW OK 1980 (51-100) 18.9

99 CARPENTER OK 1980 (51-100) 19.4

100 SOONER TREND OK 1938 (51-100) 30.6

Top 100 Volume Subtotal 110,298.0 25,915.7 8,012.5

Top 100 Percentage of U.S. Total 54.8% 50.4% 40.0%

aTotal wet gas after lease separation.

Note: The U.S. total production estimate of 20,017 billion cubic feet and the U.S. total reserves estimate of201,200 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 2004 Annual Report B-7

Table B3. Top 100 U.S. Fields Ranked by Liquids Production from Estimated 2004 Field Level Dataa

(Million Barrels of 42 U.S. Gallons)

Discovery 2004 Estimated

Num Field Name Location Year Production Volume

1 PRUDHOE BAY AK 1967 129.0

2 MISSISSIPPI CANYON BLK 807 (MARS-URSA) FG 1989 98.4

3 KUPARUK RIVER AK 1969 51.1

4 MIDWAY-SUNSET CA 1901 45.0

5 BELRIDGE SOUTH CA 1911 39.8

6 ALPINE AK 1994 36.1

7 KERN RIVER CA 1899 35.1

8 MISSISSIPPI CANYON BLK 84 (KING/HORN MT.) FG 1993 31.0

9 SPRABERRY TREND AREA TX 1950 26.2

10 WASSON TX 1937 24.8

Top 10 Volume Subtotal 516.4

Top 10 Percentage of U.S. Total 25.8%

11 NORTHSTAR AK 1984 24.7

12 MISSISSIPPI CANYON BLK 383 (KEPLER) FG 1987 21.0

13 MILNE POINT AK 1982 18.8

14 CYMRIC CA 1916 18.8

15 ELK HILLS CA 1920 18.7

16 WILMINGTON CA 1932 14.8

17 SLAUGHTER TX 1937 14.8

18 POINT MCINTYRE AK 1988 13.9

19 VIOSCA KNOLL BLK 786 (PETRONIUS) FG 1996 11.5

20 EAST BREAKS BLK 602 (NANSEN) FG 1999 11.3

Top 20 Volume Subtotal 684.5

Top 20 Percentage of U.S. Total 34.2%

21 LOST HILLS CA 1910 11.1

22 WATTENBERG CO 1970 10.8

23 TARN AK 1991 10.6

24 GREEN CANYON BLK 205 (GENESIS) FG 1988 10.5

25 EAST BREAKS BLK 643 (BOOMVANG) FG 1999 10.4

26 KELLY-SNYDER TX 1948 10.4

27 MISSISSIPPI CANYON BLK 582 (MEDUSA) FG 2000 10.2

28 BOREALIS AK 2001 9.9

29 GARDEN BANKS BLK 387 (LLANO) FG 1990 9.8

30 LEVELLAND TX 1945 9.5

31 GIDDINGS TX 1960 9.1

32 GREEN CANYON BLK 158 (BRUTUS) FG 1992 9.1

33 SHO-VEL-TUM OK 1905 9.1

34 GARDEN BANKS BLK 215 (BALDPATE) FG 1995 9.0

35 SEMINOLE TX 1936 8.5

36 HONDO FP 1969 8.0

37 CEDAR HILLS ND & MT & SD 1951 7.9

38 ENDICOTT AK 1978 7.7

39 COWDEN NORTH TX 1930 7.2

40 YATES TX 1926 7.2

41 GREEN CANYON BLK 243 (ASPEN) FG 2001 7.1

42 SOUTH TIMBALIER SA BLK 314 FG 2001 6.7

43 EWING BANK BLK 873 (LOBSTER) FG 1991 6.6

44 MAIN PASS BLK 61 FG 2001 6.5

45 ALAMINOS CANYON BLK 25 (HOOVER) FG 1997 6.5

46 VACUUM NM 1929 6.4

47 SOUTH TIMBALIER BLK 37 FG 1974 6.2

48 COALINGA CA 1887 6.0

49 EUGENE ISLAND SA BLK 352 FG 1983 5.9

50 GREEN CANYON BLK 236 (TYPHOON) FG 1999 5.9

Top 50 Volume Subtotal 934.3

Top 50 Percentage of U.S. Total 46.7%
Energy Information Administration

B-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table B3. Top 100 U.S. Fields Ranked by Liquids Production from Estimated 2004 Field Level Dataa

(Continued)

(Million Barrels of 42 U.S. Gallons)

Discovery 2004 Estimated

Num Field Name Location Year Production Volume

51 ELM COULEE MT 2000 5.7

52 VIOSCA KNOLL BLK 956 (RAM-POWELL) FG 1985 5.6

53 GREEN CANYON BLK 282 (BORIS) FG 2002 5.5

54 LAKE WASHINGTON LA 1931 5.3

55 PESCADO FP 1970 5.3

56 MISSISSIPPI CANYON BLK 899 (CROSBY) FG 1998 5.3

57 MCELROY TX 1926 5.3

58 GREEN CANYON BLK 254 (ALLEGHENY) FG 1994 5.2

59 GOLDSMITH NORTH TX 1946 5.1

60 RANGELY CO 1902 5.0

61 GREEN CANYON BLK 244 (TROIKA) FG 1994 4.9

62 VIOSCA KNOLL BLK 990 (POMPANO) FG 1981 4.9

63 GARDEN BANKS BLK 426 (AUGER) FG 1992 4.8

64 INDIAN BASIN NM 1971 4.7

65 EAST TEXAS TX 1930 4.7

66 ROBERTSON NORTH TX 1956 4.6

67 LOOKOUT BUTTE EAST MT 1986 4.6

68 GARDEN BANKS BLK 260 FG 1995 4.6

69 WEST SAK AK 1969 4.5

70 MISSISSIPPI CANYON BLK 243 (MATTERHORN) FG 1993 4.5

71 VENTURA CA 1916 4.4

72 FULLERTON TX 1942 4.3

73 ANTON-IRISH TX 1944 4.2

74 SALT CREEK TX 1942 4.2

75 GARDEN BANKS BLK 668 (GUNNISON) FG 2000 4.1

76 NIAKUK AK 1984 4.0

77 SAN ARDO CA 1947 4.0

78 HOBBS NM 1928 4.0

79 WEST DELTA BLK 30 FG 1949 4.0

80 GRAYBURG JACKSON NM 1929 3.8

81 GREEN CANYON BLK 608 (MARCO POLO) FG 2002 3.7

82 POINT ARGUELLO FP 1981 3.6

83 GREATER ANETH UT 1956 3.6

84 BAY MARCHAND BLK 2 LA 1949 3.5

85 MEANS TX 1934 3.4

86 VIOSCA KNOLL BLK 825 (NEPTUNE) FG 1988 3.4

87 LISBURNE AK 1967 3.4

88 AURORA AK 1969 3.3

89 MONUMENT NM 1935 3.3

90 MCARTHUR RIVER AK 1965 3.3

91 BELRIDGE NORTH CA 1912 3.2

92 SHIP SHOAL BLK 169 FG 1961 3.1

93 COGDELL TX 1949 3.1

94 MISSISSIPPI CANYON BLK 773 (DEVILS TOWER) FG 2000 3.0

95 KENT BAYOU LA 1950 3.0

96 SACATE FP 1970 3.0

97 EWING BANK BLK 921 (MORPETH) FG 1993 2.9

98 DOLLARHIDE NM & TX 1945 2.9

99 HOWARD-GLASSCOCK TX 1925 2.8

100 MONUMENT BUTTE UT 1964 2.8

Top 100 Volume Subtotal 1,139.8

Top 100 Percentage of U.S. Total 57.0%

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 2004 Annual Report B-9

1 SAN JUAN BASIN GAS AREA CO & NM 1927 1450.8

2 NEWARK EAST TX 1981 412.6

3 PRB COAL BED WY 1992 325.7

4 GUYMON-HUGOTON GAS AREA KS & OK & TX 1922 307.9

5 LOWER MOBILE BAY AREA AL & FG 1979 290.1

6 JONAH WY 1977 250.9

7 PRUDHOE BAY AK 1967 209.3

8 WATTENBERG CO 1970 192.0

9 CARTHAGE TX 1923 191.4

10 ANTRIM MI 1965 166.7

Top 10 Volume Subtotal 3,797.6

Top 10 Percentage of U.S. Total 19.0%

11 MADDEN WY 1968 153.5

12 PINEDALE WY 1955 150.4

13 MISSISSIPPI CANYON BLK 807 (MARS-URSA) FG 1989 149.3

14 SPRABERRY TREND AREA TX 1950 128.7

15 MAYFIELD NE OK 1951 108.1

16 GIDDINGS TX 1960 106.8

17 ELK HILLS CA 1920 105.7

18 NATURAL BUTTES UT 1952 103.9

19 RATON BASIN GAS AREA CO & NM 1998 101.8

20 MISSISSIPPI CANYON BLK 383 (KEPLER) FG 1987 100.4

Top 20 Volume Subtotal 5,006.1

Top 20 Percentage of U.S. Total 25.0%

21 PANHANDLE WEST TX 1918 97.4

22 INDIAN BASIN NM 1971 96.7

23 MAMM CREEK CO 1959 95.7

24 VERNON LA 1967 90.7

25 MISSISSIPPI CANYON BLK 731 (MENSA) FG 1987 84.6

26 MOCANE-LAVERNE GAS AREA KS & OK & TX 1946 79.8

27 JUDGE DIGBY LA 1977 78.3

28 SAWYER TX 1975 76.5

29 WHITNEY CANYON-CARTER CRK WY 1978 73.4

30 ELM GROVE LA 1958 73.2

31 STRONG CITY DISTRICT OK 1966 71.9

32 DRUNKARDS WASH UT 1989 68.4

33 OAK HILL TX 1958 66.2

34 RED OAK-NORRIS OK 1910 64.7

35 VIOSCA KNOLL BLK 956 (RAM-POWELL) FG 1985 64.0

36 EAST BREAKS BLK 945 (DIANA) FG 1994 57.7

37 EAST BREAKS BLK 602 (NANSEN) FG 1999 57.6

38 PANOMA GAS AREA KS 1956 57.4

39 OAKWOOD VA 1990 56.9

40 BELUGA RIVER AK 1962 56.7

41 WATONGA-CHICKASHA TREND OK 1962 56.0

42 BALD PRAIRIE TX 1976 51.9

43 MISSISSIPPI CANYON BLK 305 (ACONCAGUA) FG 2002 51.6

44 KINTA OK 1914 51.1

45 MCALLEN RANCH TX 1986 49.5

46 ELK CITY OK 1947 49.4

47 EAST BREAKS BLK 579 (FALCON) FG 2003 48.6

48 GOMEZ TX 1977 48.0

49 VAQUILLAS RANCH TX 1978 47.3

50 SOUTH TIMBALIER BLK 176 FG 1963 47.1

Top 50 Volume Subtotal 6,974.6

Top 50 Percentage of U.S. Total 34.8%

Table B4. Top 100 U.S. Fields Ranked by Gas Production from Estimated 2004 Field Level Dataa

(Billion Cubic Feet)

Discovery 2004 Estimated

Num Field Name Location Year Production Volume
Energy Information Administration

B-10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table B4. Top 100 U.S. Fields Ranked by Gas Production from Estimated 2004 Field Level Dataa

(Continued)

(Billion Cubic Feet)

Discovery 2004 Estimated

Num Field Name Location Year Production Volume

51 FREESTONE TX 1949 46.9

52 BIG SANDY KY & WV 1926 45.8

53 GARDEN BANKS BLK 668 (GUNNISON) FG 2000 44.9

54 LA PERLA TX 1958 43.0

55 DOWDY RANCH TX 1999 42.9

56 COOK INLET NORTH AK 1962 42.8

57 MIMMS CREEK TX 1978 42.7

58 GOLDEN TREND OK 1945 42.6

59 DEW TX 1982 42.5

60 GRAND VALLEY CO 1985 42.3

61 FARRAR TX 1963 40.2

62 BUFFALO WALLOW TX 1978 39.4

63 DESOTO CANYON BLK 133 (KING'S PEAK) FG 1993 39.2

64 SHO-VEL-TUM OK 1905 39.0

65 CEMENT OK 1917 38.7

66 WEST CAMERON BLK 19 FG 2000 38.6

67 B M T TX 1994 38.6

68 RULISON CO 1958 37.9

69 WILBURTON OK 1941 37.7

70 FOGARTY CREEK WY 1975 36.6

71 JAVELINA TX 1947 36.2

72 MISSISSIPPI CANYON BLK 348 (CAMDEN HILLS) FG 2000 35.8

73 GARDEN BANKS BLK 215 (BALDPATE) FG 1995 35.6

74 HAYNES TX 1954 34.8

75 GREEN RIVER BEND WY 1958 34.7

76 EXSUN TX 1974 34.6

77 OVERTON TX 1973 34.3

78 MCARTHUR RIVER AK 1965 34.2

79 GREEN CANYON BLK 472 (KING KONG) FG 1989 33.6

80 BRAZOS SA BLK A133 FG 1975 32.8

81 PARACHUTE CO 1985 32.5

82 SOUTH TIMBALIER BLK 172 FG 1965 32.2

83 BROWN-BASSETT TX 1953 32.1

84 WAMSUTTER WY 1958 31.5

85 BRUFF WY 1969 31.1

86 SLIGO LA 1922 30.9

87 MOBILE BLK 823 FG 1983 30.8

88 SOONER TREND OK 1938 30.6

89 CHARCO TX 1948 30.2

90 MATAGORDA ISLAND BLK 623 FG 1980 29.9

91 GREEN CANYON BLK 116 (POPEYE) FG 1985 29.9

92 WEST CAMERON BLK 100 FG 1989 29.7

93 TOM EAST TX 2001 29.5

94 SAMANO TX 1985 29.5

95 BAYOU BILOXI LA 1963 29.5

96 OAKS TX 1975 29.4

97 BETHANY TX 1936 28.6

98 KNOX OK 1916 28.5

99 VERDEN OK 1948 28.4

100 LOS MOGOTES TX 1960 27.9

Top 100 Volume Subtotal 8,746.1

Top 100 Percentage of U.S. Total 43.7%

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.
Appendix C

Conversion to the Metric System

Appendix C

Conversion to the Metric System

Public Law 100–418, the Omnibus Trade and

Competitiveness Act of 1988, states: “It is the

declared policy of the United States—

(1) to designate the metric system of measurement as

the preferred system of weights and measures for

United States trade and commerce....

(2) to require that each Federal agency, by the end of

Fiscal Year 1992, use the metric system of

measurement in its procurements, grants, and other

business–related activities."{43}

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 2004 Annual Report C-1
Energy Information Administration

C-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table C1. U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids,

in Metric Units, 1994 – 2004

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)

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

2004 11.8 66.8 78.5 3.7 98.1 5.2 21.0 124.3 289.2 3,397.7 -82.7

Dry Natural Gas (billion cubic meters)

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

2004 -3.2 21.1 17.8 52.2 515.3 21.5 34.2 571.0 542.8 5,451.4 98.2

Natural Gas Liquids (million cubic meters)

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

2004 43.4 15.4 58.8 17.8 116.7 4.1 8.6 129.4 131.5 1,260.5 74.6

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, 1994–2003 annual reports, DOE/EIA–0216.{18–27}
Appendix D

Historical Reserves Statistics

Appendix D 

Historical Reserves Statistics 

EIA maintains a data archive of all published proved reserves volumes at the State and National level. Appendix 

D provides a series of tables of the proved reserves and production of crude oil, natural gas, and natural gas 

liquids for the U.S. and the lower 48 States for the years 1977 through 2004. 

All historical statistics included have previously been published in the annual reports of 1977 through 2003 of the 

EIA publication U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves Annual Report, DOE EIA-0216.{1-27} 

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. 

An electronic version of the Data Archive (in Microsoft ExcelTM) format is available for downloading at the 

following link: 

http://www.eia.doe.gov/oil_gas/natural_gas/data_publications/crude_oil_natural_gas_reserves/cr.html

The Data Archive is listed in the “Special Files” section of the destination site. 

Energy Information Administration 

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report D-1
Energy Information Administration

D-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table D1. U.S. Proved Reserves of Crude Oil, 1976–2004

(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

2004 74 420 494 23 617 33 132 782 1,819 21,371 -520

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 2004 annual reports, DOE/EIA-0216.{1-27}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report D-3

Table D2. U.S. Lower 48 Proved Reserves of Crude Oil, 1976–2004

(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

2004 75 373 448 23 506 33 74 613 1,485 17,044 -401

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 2004 annual reports, DOE/EIA-0216.{1-27}
Energy Information Administration

D-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table D3. U.S. Proved Reserves of Dry Natural Gas, 1976–2004

(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

2004 -114 744 630 1,844 18,198 759 1,206 20,163 19,168 192,513 3,469

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 2004 annual reports, DOE/EIA-0216.{1-27}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report D-5

Table D4. U.S. Lower 48 Proved Reserves of Dry Natural Gas, 1976–2004

(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

2004 -113 319 206 1,844 18,057 759 1,171 19,987 18,690 184,106 3,347

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 2004 annual reports, DOE/EIA-0216.{1-27}
Energy Information Administration

D-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table D5. U.S. Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–2004

(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

2004 170 825 995 1,975 19,068 790 1,244 21,102 20,017 201,200 4,055

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 2004 annual reports, DOE/EIA-0216.{3-27}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report D-7

Table D6. U.S. Lower 48 Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–2004

(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

2004 170 395 565 1,975 18,927 790 1,209 20,926 19,536 192,727 3,930

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 2004 annual reports, DOE/EIA-0216.{3-27}
Energy Information Administration

D-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table D7. U.S. Proved Reserves of Natural Gas Liquids, 1978–2004

(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

2004 273 97 370 112 734 26 54 814 827 7,928 469

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 2004 annual reports, DOE/EIA-0216.{3-27}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report D-9

Table D8. U.S. Lower 48 Proved Reserves of Natural Gas Liquids, 1978–2004

(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

2004 273 97 370 112 734 26 54 814 809 7,559 487

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 2004 annual reports, DOE/EIA-0216.{3-27}
Energy Information Administration

D-10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2004

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

2004 467 404 63 310 157 66.4

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

2004 4,144 3,919 225 3,280 864 79.2
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report D-11

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2004

(continued)

Gulf of Mexico Depth

Greater than Less than Deepwater

Year Total Louisianaa Texas 200 meters 200 meters Percentage

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

2004 3,967 2,890 1,077 1,251 2,716 31.5

Reserves

1992 27,050 20,006 7,044 3,273 23,777 12.1

1993 26,463 19,751 6,712 3,495 22,968 13.2

1994 27,626 21,208 6,418 4,772 22,854 17.3

1995 28,229 21,664 6,565 5,811 22,418 20.6

1996 28,153 22,119 6,034 6,389 21,764 22.7

1997 28,455 22,428 6,027 7,491 20,964 26.3

1998 26,937 21,261 5,676 7,575 19,362 28.1

1999 26,062 20,172 5,890 7,726 18,336 29.6

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

2004 19,288 15,144 4,144 8,591 10,698 44.5
Energy Information Administration

D-12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2004

(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

2004 155 127 28 51 104 40.9

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

2004 713 615 98 292 421 40.9
Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2004

(continued)

Gulf of Mexico Depth

Greater than Less than Deepwater

Year Total Louisianaa Texas 200 meters 200 meters Percentage

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

2004 3,874 2,802 1,072 1,222 2,652 31.5

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

2004 18,812 14,685 4,127 8,379 10,433 44.5

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report D-13
Energy Information Administration

D-14 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2004

(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

2004 74 49 25 27 47 36.2

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

2004 290 205 85 103 187 35.6

aIncludes Federal Offshore Alabama.

Source: Based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves.”
Table D10. 2004 Reported Proved Nonproducing Reserves of Crude Oil, Lease Condensate, and

Wet Natural Gas, After Lease Separationa

Lease Nonassociated Associated Total

Crude Oil Condensate Gas Dissolved Gas Gas

State and Subdivision (mbbls) (mbbls) (bcf) (bcf) (bcf)

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 707 0 664 17 681

Lower 48 States . . . . . . . . . . . . . . . . . . . . . . . . . . 4,436 409 45,332 5,399 50,731

Alabama. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 3 369 2 371

Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 0 315 10 325

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 267 0 221 403 624

Coastal Region Onshore. . . . . . . . . . . . . . . . . . 16 0 6 12 18

Los Angeles Basin Onshore . . . . . . . . . . . . . . . 63 0 0 30 30

San Joaquin Basin Onshore . . . . . . . . . . . . . . . 158 0 215 342 557

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . 30 0 0 19 19

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62 39 3,788 621 4,409

Florida . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 0 0 0 0

Kansas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 0 54 5 59

Kentucky . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 0 107 0 107

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150 30 3,524 282 3,806

North . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 6 1,982 46 2,028

South Onshore . . . . . . . . . . . . . . . . . . . . . . . . . 115 23 1,376 215 1,591

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . 24 1 166 21 187

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 1 468 29 497

Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 0 76 7 83

Montana. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104 0 158 41 199

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142 15 4,169 160 4,329

East. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142 10 613 159 772

West . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 5 3,556 1 3,557

New York . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 26 0 26

North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 1 14 22 36

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 0 92 11 103

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92 38 3,800 80 3,880

Pennsylvania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0 410 38 448

Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 625 76 13,084 831 13,915

RRC District 1 . . . . . . . . . . . . . . . . . . . . . . . . . . 9 2 395 6 401

RRC District 2 Onshore . . . . . . . . . . . . . . . . . . 13 2 545 15 560

RRC District 3 Onshore . . . . . . . . . . . . . . . . . . 21 20 760 51 811

RRC District 4 Onshore . . . . . . . . . . . . . . . . . . 4 22 3,067 42 3,109

RRC District 5 . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 2,461 23 2,484

RRC District 6 . . . . . . . . . . . . . . . . . . . . . . . . . . 15 12 1,729 30 1,759

RRC District 7B. . . . . . . . . . . . . . . . . . . . . . . . . 5 0 21 4 25

RRC District 7C. . . . . . . . . . . . . . . . . . . . . . . . . 14 1 842 98 940

RRC District 8 . . . . . . . . . . . . . . . . . . . . . . . . . . 218 0 737 186 923

RRC District 8A. . . . . . . . . . . . . . . . . . . . . . . . . 311 0 10 327 337

RRC District 9 . . . . . . . . . . . . . . . . . . . . . . . . . . 9 1 1,417 4 1,421

RRC District 10 . . . . . . . . . . . . . . . . . . . . . . . . . 5 14 1,041 41 1,082

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . 0 1 59 4 63

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 5 1,136 127 1,263

Virginia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 742 0 742

West Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 510 0 510

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45 41 5,524 23 5,547

Federal Offshoreb . . . . . . . . . . . . . . . . . . . . . . . . . 2,708 160 6,718 2,707 9,425

Pacific (California). . . . . . . . . . . . . . . . . . . . . 55 8 47 60 107

Gulf of Mexico (Louisiana)b . . . . . . . . . . . . . 2,581 112 5,114 2,488 7,602

Gulf of Mexico (Texas) . . . . . . . . . . . . . . . . . 72 40 1,557 159 1,716

Miscellaneousc . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 0 27 0 27

U.S. Total . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,143 409 45,996 5,416 51,412

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," 2004.

Energy Information Administration D-15

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 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 2004 by crude oil or

natural gas well operators who were active as of

December 31, 2004. 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 1997 and 2004, and depicts

the number of active operators, with 2002 showing the

largest in the series. The 2004 sampling frame consisted

of 164 Category I, 532 Category II, 275 Category III

Certainty, and 19,699 Category III Noncertainty

operators, for a total of 20,670 active operators. The

survey sample consisted of 971 operators selected with

certainty that included all of the Category I and II

Certainty operators, the 275 smaller operators that

were selected with certainty because of their size in

relation to the area or areas in which they operated, and

370 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 2004 survey is

summarized in Table E2. EIA makes a considerable

effort to gain responses from all operators. About 3.8

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 51 nonoperators, 12 had successor operators that

had taken over the production of the nonoperator.

These successor operators were subsequently sampled.

The overall response rate for the 2004 survey was 96

percent. For the 47 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 2004 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 2004 Annual Report

Table E1. Comparison of the EIA-23 Sample and Sampling Frame, 1997-2004

Number of Operators

Operator Category 1997 1998 1999 2000 2001 2002 2003 2004

Certainty

Category I. . . . . . . . . . . . . 180 178 177 175 179 176 164 164

Category II . . . . . . . . . . . . 461 420 399 436 485 480 512 532

Category III............ 1,194 862 648 854 559 388 399 275

Sampled ............. 1,835 1,460 1,224 1,465 1,223 1,044 1,075 971

Percent Sampled . . . . . . . 100 100 100 100 100 100 100 100

Noncertainty

Sampled .............. 1,645 1,459 1,305 1,311 644 533 479 370

Percent Sampled ....... 8 7 6 6 3 3 2 2

Total

Active Operators........ 22,678 23,620 22,089 22,102 22,519 22,823 20,923 20,670

Not Sampled .......... 19,198 20,701 19,560 19,326 20,652 21,246 19,369 19,329

Sampled .............. 3,480 2,919 R2,529 2,776 1,867 1,577 1,554 1,341

Percent Sampled . . . . . . . 15 12 R11 13 8 7 7 7

R=Revised data.

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

Table E2. Form EIA-23 Survey Response Statistics, 2004

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 14 -7 171 171 100.0 0 0.0

Category II . . . . . . . 532 12 -49 -27 468 459 98.1 9 1.9

Category III . . . . . . . 275 0 39 -6 308 289 93.8 e

19 6.2

Subtotal. . . . . . . . . 971 12 4 -40 947 919 97.0 e

28 3.0

Noncertainty . . . . . . . . 370 0 -4 -11 355 336 94.6 e

19 5.4

Total............. 1,341 12 0 -51 1,302 1,255 96.4 e

47 3.6

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 47 operators (9 Category II operators, 19 Category III operators, and 19 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” 2004.
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

60Fahrenheit, 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 2004, in December 2004, was the 23nd

annual report and reflected data collected through

November 2004. 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 2004, Form EIA-23 National estimates of

production were 2,001 million barrels for crude oil and

lease condensate or 18 million barrels (less than 1

percent) lower than that reported in the Petroleum

Supply Annual 2004 for crude oil and lease condensate

(1,983 million barrels). Form EIA-23 National estimates

of production for dry natural gas were 19,168 billion

cubic feet, 244 billion cubic feet (less than 2 percent)

higher than the Natural Gas Monthly, September 2005 for

2004 dry natural gas production (18,924 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 2004 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, 2004. Of these, 20,670

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 2004 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, 2005. In

addition, plant operators whose plants were shut down

or dismantled during 2004 were required to complete

forms for the portion of 2004 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

211 operators of 488 plants were sent forms. This

number included 3 new plants and 2 successor plants

identified after the initial 2004 survey mailing. A total

of 14 plants were reported as nonoperating according

Energy Information Administration

E-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table E3. Summary of the 2004 Operator Frame

Activity, Form EIA-23

Total 2003 Operator Frame ............. 68,616

Operators....................... 20,923

Nonoperators.................... 47,693

Changes to 2003 Operator Status ...... 1,264

From Nonoperator to Operatora . . . . . 122

From Operator to Nonoperator . . . . . . 619

New Operators . . . . . . . . . . . . . . . . . . 523

No Changes to 2003 Operator Status . . . 67,352

Operators....................... 20,386

Nonoperators.................... 46,966

Additions to 2003 Operator Frame ..... 0

Operator ....................... 0

Nonoperator..................... 0

Total 2004 Operator Frame ............. 68,616

Operators....................... 20,670

Nonoperators.................... 47,946

a

Includes operator frame activity through December 14, 2004.

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.
to the Form EIA-64A definition. For the 17th

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 2004 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 2004,

the Form EIA-64A National estimates were less than 3

percent (17 million barrels) lower than the Petroleum

Supply Annual 2004 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 2004 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 February 15, 2005.

Energy Information Administration

E-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table E5. Form EIA-64A 2004 Plant Frame Activity

Frame as of 2003 survey mailing . . . . . . . 504

Additions . . . . . . . . . . . . . . . . . . . 74

Deletions . . . . . . . . . . . . . . . . . . . –90

Frame as of 2004 survey mailing . . . . . . . 488

Note: Includes operator frame activity through February 15, 2005.

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

Table E4. Natural Gas Processed and Liquids Extracted at Natural Gas Processing Plants, 2004

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 .................. 2,680,859 0 0 2,680,859 27,866

Alabama................. 32,825 229,319 1,282 263,426 10,534

Arkansas ................ 10,139 0 0 10,139 190

California ................ 235,655 810 0 236,465 10,898

Colorado ................ 703,804 0 0 703,804 25,706

Florida .................. 3,088 0 1,717 4,805 587

Kansas.................. 391,395 0 115,777 507,172 24,278

Kentucky ................ 38,208 0 0 38,208 1,662

Louisiana ................ 1,025,344 2,219,506 0 3,244,850 93,995

Michigan ................ 37,977 0 0 37,977 2,933

Mississippi ............... 2,471 281,292 0 283,763 9,333

Montana................. 6,720 0 0 6,720 496

North Dakota ............. 60,261 0 0 60,261 4,754

New Mexico .............. 940,295 0 0 940,295 72,918

Oklahoma ............... 836,636 0 2,730 839,366 58,437

Texas ................... 3,702,000 0 46,670 3,748,670 254,266

Utah . . . . . . . . . . . . . . . . . . . . 188,524 0 4,569 193,093 2,556

West Virginia ............. 95,589 0 31,795 127,384 5,671

Wyoming ................ 1,227,994 0 21,315 1,249,309 49,380

Miscellanousa ............ 13,634 0 0 13,634 572

Total . . . . . . . . . . . . . . . . . . . . 12,233,418 2,730,927 225,855 15,190,200 657,032

aIncludes Illinois, Ohio, and Pennsylvania.

Source: Form EIA-64A, “Annual Report of the Origin of Natural Gas Liquids Production,” 2004
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 2003. 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 meet survey objectives, 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

2003 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

2004 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 2003 for any product class.

4 percent for each State/subdivision having less

than 1 percent of estimated U.S. reserves or

production in 2003 (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 2003.

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

2003, and additionally, all coalbed methane and

Federal Offshore operators.

Category III - Small Operators: Operators who

produced less than the Category II operators in

2003.

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 2004 Annual Report F-1
Table F1. 2004 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 42 1 4 0.040 0.025

Alaska 20 0 0

Arkansas 67 5 11 0.040 0.025

California - Coastal Region Onshore 18 0 4 0.080 0.080

California - Los Angeles Basin Onshore 13 3 2 0.010 0.010

California - San Joaquin Basin Onshore 41 2 7 0.025 0.040

Colorado 118 3 21 0.025 0.010

Florida - Onshore 5 0 0 0.025 0.025

Illinois 30 6 25 0.040 0.040

Indiana 18 4 19 0.040 0.080

Kansas 184 81 70 0.040 0.080

Kentucky 28 12 14 0.025 0.010

Louisiana-North 115 22 25 0.040 0.040

Louisiana-South Onshore 183 8 21 0.010 0.010

Michigan 36 5 4 0.010 0.010

Mississippi - Onshore 81 4 16 0.040 0.040

Montana 69 1 5 0.040 0.040

Nebraska 25 2 19 0.040 0.040

New Mexico - East 160 1 34 0.040 0.080

New Mexico - West 55 1 3 0.025 0.025

New York 18 9 5 0.025 0.010

North Dakota 65 0 5 0.080 0.040

Ohio 22 23 16 0.040 0.040

Oklahoma 265 26 77 0.040 0.040

Pennsylvania 46 11 11 0.025 0.025

Texas - RRC District 1 137 12 49 0.040 0.040

Texas - RRC District 2 Onshore 186 2 43 0.025 0.025

Texas - RRC District 3 Onshore 269 16 64 0.040 0.025

Texas - RRC District 4 Onshore 198 3 37 0.025 0.025

Texas - RRC District 5 111 2 18 0.040 0.010

Texas - RRC District 6 181 20 47 0.040 0.010

Texas - RRC District 7B 163 35 96 0.025 0.010

Texas - RRC District 7C 167 3 53 0.025 0.025

Texas - RRC District 8 211 7 69 0.040 0.025

Texas - RRC District 8A 191 0 53 0.010 0.010

Texas - RRC District 9 158 23 67 0.010 0.040

Texas - RRC District 10 154 12 30 0.025 0.025

Utah 57 2 3 0.040 0.010

Virginia 17 0 1 0.040 0.025

West Virginia 38 18 14 0.080 0.040

Wyoming 164 2 16 0.040 0.025

Offshore Areas 320 0 0 0.025 0.025

Other States (a) 56 12 0 0.080 0.080

Total b987 399 b398 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 2004 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.

Imputation and Estimation for

Reserves Data

There were 355 operators sampled proportional to size

(Table E1) that responded as Category III noncertainty

operators. Only 137 of these, located in 10 states, had

their data weighted and used to estimate the

production and reserves of the operators that were not

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report F-3
sampled in those states. The remaining 218

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

2004 are summarized in Tables F2, F3, F4, and F5. The

reported data in Table F2 shows that those responding

operators accounted for 97.0 percent of the published

production for wet natural gas and 95.4 percent of the

reserves shown in Table 9. Data shown in Table F3

indicate that those responding operators accounted for

96.9 percent of the nonassociated natural gas

production and 95.5 percent of the reserves published

in Table 10. The reported data shown in Table F4

indicate that those responding operators accounted for

95.9 percent of published crude oil production and 93.9

percent of the reserves shown in Table 6. Additionally,

Table F5 indicates that those responding operators

accounted for 97.8 percent of the published production

and 96.0 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 2004 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 2004, 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

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

Energy Information Administration

F-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report F-5

Table F2. Summary of Form EIA-23 Reported, Imputed, and Estimated Natural Gas Data for 2004,

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 . . . . . . . . . . . . . . . 171 459 289 336 13,664 14,919

Proved Reserves as of 12/31/03 . . . . . . 173,021,831 13,832,380 904,544 1,606 0 187,760,361

(+) Revision Increases . . . . . . . . . . . . 25,344,424 1,379,662 46,603 0 0 26,770,689

(–) Revision Decreases. . . . . . . . . . . . 24,254,297 1,668,617 70,416 0 0 25,993,330

(–) Sales . . . . . . . . . . . . . . . . . . . . . . . 8,582,347 2,259,065 662,280 0 0 11,503,692

(+) Acquisitions . . . . . . . . . . . . . . . . . . 11,930,606 1,238,458 27,874 13,290 0 13,210,228

(+) Extensions. . . . . . . . . . . . . . . . . . . 15,359,064 2,861,495 28,667 0 0 18,249,226

(+) New Field Discoveries.......... 554,690 198,921 388 0 0 753,999

(+) New Reservoirs in Old Fields .... 818,884 349,950 1,217 0 0 1,170,051

(–) Production With

Proved Reserves Reported . . . . . 16,896,526 1,463,271 45,169 343 0 18,405,309

(–) Production Without

Proved Reserves Reported . . . . . 17,397 456,894 11,680 0 0 485,971

Proved Reserves as of 12/31/04 . . . . . . 177,293,000 14,485,809 231,544 14,553 0 192,024,906

Imputed and Estimated

Number of Operators . . . . . . . . . . . . . . . - - - 5,751 - 5,751

Proved Reserves as of 12/31/03. . . . . - - - - - -

(+) Revision Increases . . . . . . . . . . . . 0 0 0 0 1,346,399 1,346,399

(–) Revision Decreases. . . . . . . . . . . . 0 0 0 0 1,297,072 1,297,072

(–) Sales . . . . . . . . . . . . . . . . . . . . . . . 0 0 0 0 78,056 78,056

(+) Acquisitions .................. 0 0 0 0 350,242 350,242

(+) Extensions................... 0 0 0 0 819,835 819,835

(+) New Field Discoveries. . . . . . . . . . 0 0 0 0 37,444 37,444

(+) New Reservoirs in Old Fields . . . . 0 0 0 0 74,259 74,259

(–) Production With

Proved Reserves Reported . . . . . 0 0 0 0 63,314 63,314

(–) Production Without

Proved Reserves Reported . . . . . 3,820 153,710 109,288 266,818 527,016 1,060,652

Proved Reserves as of 12/31/04 . . . . . . 22,758 1,296,243 731,272 2,050,273 5,069,781 9,170,327

Total

Number of Operators . . . . . . . . . . . . . . . 171 459 289 6,087 13,664 20,670

Proved Reserves as of 12/31/03 . . . . . . 173,021,831 13,832,380 904,544 1,606 0 187,760,361

(+) Revision Increases . . . . . . . . . . . . 25,344,424 1,379,662 46,603 0 1,346,399 28,117,088

(–) Revision Decreases. . . . . . . . . . . . 24,254,297 1,668,617 70,416 0 1,297,072 27,290,402

(–) Sales . . . . . . . . . . . . . . . . . . . . . . . 8,582,347 2,259,065 662,280 0 78,056 11,581,748

(+) Acquisitions . . . . . . . . . . . . . . . . . . 11,930,606 1,238,458 27,874 13,290 350,242 13,560,470

(+) Extensions. . . . . . . . . . . . . . . . . . . 15,359,064 2,861,495 28,667 0 819,835 19,069,061

(+) New Field Discoveries.......... 554,690 198,921 388 0 37,444 791,443

(+) New Reservoirs in Old Fields .... 818,884 349,950 1,217 0 74,259 1,244,310

(–) Production With

Proved Reserves Reported . . . . . 16,896,526 1,463,271 45,169 343 63,314 18,468,623

(–) Production Without

Proved Reserves Reported . . . . . 21,217 610,604 120,968 266,818 527,016 1,546,623

Proved Reserves as of 12/31/04 . . . . . . 177,315,758 15,782,052 962,816 2,064,826 5,069,781 201,195,233

Summary

Total Number of Operators . . . . . . . . . 171 459 289 6,087 13,664 20,670

Percent of Total . . . . . . . . . . . . . . . . . . 0.8% 2.2% 1.4% 29.4% 66.1% 100.0%

Total Production in 2004 . . . . . . . . . . . 16,917,743 2,073,875 166,137 267,161 590,330 20,015,246

Percent of Total . . . . . . . . . . . . . . . . . . 84.5% 10.4% 0.8% 1.3% 2.9% 100.0%

Total Proved Reserves 12/31/04 ..... 177,315,758 15,782,052 962,816 2,064,826 5,069,781 201,195,233

Percent of Total . . . . . . . . . . . . . . . . . . 88.1% 7.8% 0.5% 1.0% 2.5% 100.0%

aThere were 355 noncertainty responses, 137 were used with their sample weights and 218 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,” 2004.
Energy Information Administration

F-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table F3. Summary of Form EIA-23 Reported, Imputed, and Estimated Nonassociated Natural Gas Data

for 2004, 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 . . . . . . . . . . . . . . . 171 459 289 336 13,664 14,919

Proved Reserves as of 12/31/03 . . . . . . 147,537,859 12,388,805 821,519 636 0 160,748,819

(+) Revision Increases . . . . . . . . . . . . 21,771,601 1,187,590 45,071 0 0 23,004,262

(–) Revision Decreases. . . . . . . . . . . . 21,559,084 1,480,544 51,726 0 0 23,091,354

(–) Sales . . . . . . . . . . . . . . . . . . . . . . . 7,756,635 2,116,675 626,074 0 0 10,499,384

(+) Acquisitions . . . . . . . . . . . . . . . . . . 11,147,233 1,064,400 26,671 433 0 12,238,737

(+) Extensions. . . . . . . . . . . . . . . . . . . 14,613,036 2,766,447 26,099 0 0 17,405,582

(+) New Field Discoveries.......... 528,835 191,991 388 0 0 721,214

(+) New Reservoirs in Old Fields .... 729,776 343,373 1,217 0 0 1,074,366

(–) Production With

Proved Reserves Reported . . . . . 14,577,571 1,297,837 41,935 194 0 15,917,537

(–) Production Without

Proved Reserves Reported . . . . . 14,364 410,336 9,243 0 0 433,943

Proved Reserves as of 12/31/04 . . . . . . 152,435,411 13,062,395 201,345 875 0 165,700,026

Imputed and Estimated

Number of Operators . . . . . . . . . . . . . . . - - - 5,751 - 5,751

Proved Reserves as of 12/31/03 . . . . . . - - - - - -

(+) Revision Increases . . . . . . . . . . . . 0 0 0 0 1,104,909 1,104,909

(–) Revision Decreases. . . . . . . . . . . . 0 0 0 0 1,029,717 1,029,717

(–) Sales . . . . . . . . . . . . . . . . . . . . . . . 0 0 0 0 78,004 78,004

(+) Acquisitions . . . . . . . . . . . . . . . . . . 0 0 0 0 332,755 332,755

(+) Extensions. . . . . . . . . . . . . . . . . . . 0 0 0 0 759,114 759,114

(+) New Field Discoveries. . . . . . . . . . 0 0 0 0 36,069 36,069

(+) New Reservoirs in Old Fields . . . . 0 0 0 0 72,857 72,857

(–) Production With

Proved Reserves Reported . . . . . 0 0 0 0 56,034 56,034

(–) Production Without

Proved Reserves Reported . . . . . 3,521 139,524 96,008 239,053 389,251 867,357

Proved Reserves as of 12/31/04 . . . . . . 21,034 1,169,058 652,333 1,842,425 4,165,195 7,850,045

Total

Number of Operators . . . . . . . . . . . . . . . 171 459 289 6,087 13,664 20,670

Proved Reserves as of 12/31/03. . . . . 147,537,859 12,388,805 821,519 636 0 160,748,819

(+) Revision Increases . . . . . . . . . . . . 21,771,601 1,187,590 45,071 0 1,104,909 24,109,171

(–) Revision Decreases. . . . . . . . . . . . 21,559,084 1,480,544 51,726 0 1,029,717 24,121,071

(–) Sales . . . . . . . . . . . . . . . . . . . . . . . 7,756,635 2,116,675 626,074 0 78,004 10,577,388

(+) Acquisitions . . . . . . . . . . . . . . . . . . 11,147,233 1,064,400 26,671 433 332,755 12,571,492

(+) Extensions. . . . . . . . . . . . . . . . . . . 14,613,036 2,766,447 26,099 0 759,114 18,164,696

(+) New Field Discoveries.......... 528,835 191,991 388 0 36,069 757,283

(+) New Reservoirs in Old Fields .... 729,776 343,373 1,217 0 72,857 1,147,223

(–) Production With

Proved Reserves Reported . . . . . 14,577,571 1,297,837 41,935 194 56,034 15,973,571

(–) Production Without

Proved Reserves Reported . . . . . 17,885 549,860 105,251 239,053 389,251 1,301,300

Proved Reserves as of 12/31/04 . . . . . . 152,456,445 14,231,453 853,678 1,843,300 4,165,195 173,550,071

Summary

Total Number of Operators . . . . . . . . . 171 459 289 6,087 13,664 20,670

Percent of Total . . . . . . . . . . . . . . . . . . 0.8% 2.2% 1.4% 29.4% 66.1% 100.0%

Total Production in 2004 . . . . . . . . . . . 14,595,456 1,847,697 147,186 239,247 445,285 17,274,871

Percent of Total . . . . . . . . . . . . . . . . . . 84.5% 10.7% 0.9% 1.4% 2.6% 100.0%

Total Proved Reserves 12/31/04 ..... 152,456,445 14,231,453 853,678 1,843,300 4,165,195 173,550,071

Percent of Total . . . . . . . . . . . . . . . . . . 87.8% 8.2% 0.5% 1.1% 2.4% 100.0%

aThere were 355 noncertainty responses, 137 were used with their sample weights and 218 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,” 2004.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report F-7

Table F4. Summary of Form EIA-23 Reported, Imputed, and Estimated Crude Oil Data for 2004,

(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 . . . . . . . . . . . . . . . 171 459 289 336 13,664 14,919

Proved Reserves as of 12/31/03 . . . . . . 19,530,949 1,005,518 35,508 1,581 0 20,573,556

(+) Revision Increases . . . . . . . . . . . . 1,668,535 116,677 2,060 0 0 1,787,272

(–) Revision Decreases. . . . . . . . . . . . 1,304,833 100,662 3,861 0 0 1,409,356

(–) Sales ....................... 804,315 110,375 20,564 0 0 935,254

(+) Acquisitions .................. 790,706 129,255 378 13,384 0 933,723

(+) Extensions................... 519,783 58,072 1,131 0 0 578,986

(+) New Field Discoveries. . . . . . . . . . 28,926 4,398 26 0 0 33,350

(+) New Reservoirs in Old Fields .... 125,721 6,051 0 0 0 131,772

(–) Production With

Proved Reserves Reported . . . . . 1,527,996 88,359 2,110 310 0 1,618,775

(–) Production Without

Proved Reserves Reported . . . . . 29 15,179 777 0 0 15,985

Proved Reserves as of 12/31/04 . . . . . . 19,026,541 1,021,392 12,569 14,655 0 20,075,157

Imputed and Estimated

Number of Operators . . . . . . . . . . . . . . . - - - 5,751 - 5,751

Proved Reserves as of 12/31/03 . . . . . . - - - - - -

(+) Revision Increases . . . . . . . . . . . . 0 0 0 0 152,390 152,390

(–) Revision Decreases. . . . . . . . . . . . 0 0 0 0 112,689 112,689

(–) Sales . . . . . . . . . . . . . . . . . . . . . . . 0 0 0 0 637 637

(+) Acquisitions . . . . . . . . . . . . . . . . . . 0 0 0 0 25,314 25,314

(+) Extensions. . . . . . . . . . . . . . . . . . . 0 0 0 0 40,793 40,793

(+) New Field Discoveries. . . . . . . . . . 0 0 0 0 1,759 1,759

(+) New Reservoirs in Old Fields . . . . 0 0 0 0 1,278 1,278

(–) Production With

Proved Reserves Reported . . . . . 0 0 0 0 13,575 13,575

(–) Production Without

Proved Reserves Reported . . . . . 42 17,329 12,877 30,248 110,460 170,956

Proved Reserves as of 12/31/04 . . . . . . 270 143,700 109,695 253,665 786,111 1,293,441

Total

Number of Operators . . . . . . . . . . . . . . . 171 459 289 6,087 13,664 20,670

Proved Reserves as of 12/31/03 . . . . . . 19,530,949 1,005,518 35,508 1,581 0 20,573,556

(+) Revision Increases . . . . . . . . . . . . 1,668,535 116,677 2,060 0 152,390 1,939,662

(–) Revision Decreases. . . . . . . . . . . . 1,304,833 100,662 3,861 0 112,689 1,522,045

(–) Sales ....................... 804,315 110,375 20,564 0 637 935,891

(+) Acquisitions .................. 790,706 129,255 378 13,384 25,314 959,037

(+) Extensions................... 519,783 58,072 1,131 0 40,793 619,779

(+) New Field Discoveries. . . . . . . . . . 28,926 4,398 26 0 1,759 35,109

(+) New Reservoirs in Old Fields .... 125,721 6,051 0 0 1,278 133,050

(–) Production With

Proved Reserves Reported . . . . . 1,527,996 88,359 2,110 310 13,575 1,632,350

(–) Production Without

Proved Reserves Reported . . . . . 71 32,508 13,654 30,248 110,460 186,941

Proved Reserves as of 12/31/04 . . . . . . 19,026,811 1,165,092 122,264 268,320 786,111 21,368,598

Summary

Total Number of Operators . . . . . . . . . 171 459 289 6,087 13,664 20,670

Percent of Total . . . . . . . . . . . . . . . . . . 0.8% 2.2% 1.4% 29.4% 66.1% 100.0%

Total Production in 2004 . . . . . . . . . . . 1,528,067 120,867 15,764 30,558 124,035 1,819,291

Percent of Total . . . . . . . . . . . . . . . . . . 84.0% 6.6% 0.9% 1.7% 6.8% 100.0%

Total Proved Reserves 12/31/04 . . . . . 19,026,811 1,165,092 122,264 268,320 786,111 21,368,598

Percent of Total . . . . . . . . . . . . . . . . . . 89.0% 5.5% 0.6% 1.3% 3.7% 100.0%

aThere were 355 noncertainty responses, 137 were used with their sample weights and 218 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,” 2004.
Energy Information Administration

F-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

Table F5. Summary of Form EIA-23 Reported, Imputed, and Estimated Lease Condensate Data for 2004,

(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 . . . . . . . . . . . . . . . 171 459 289 336 13,664 14,919

Proved Reserves as of 12/31/03 . . . . . . 1,055,487 103,119 8,882 0 0 1,167,488

(+) Revision Increases . . . . . . . . . . . . 284,962 26,153 1,482 0 0 312,597

(–) Revision Decreases. . . . . . . . . . . . 263,941 21,945 369 0 0 286,255

(–) Sales . . . . . . . . . . . . . . . . . . . . . . . 80,417 11,048 4,457 0 0 95,922

(+) Acquisitions . . . . . . . . . . . . . . . . . . 79,008 23,877 1,096 0 0 103,981

(+) Extensions. . . . . . . . . . . . . . . . . . . 90,912 18,984 147 0 0 110,043

(+) New Field Discoveries. . . . . . . . . . 3,072 905 0 0 0 3,977

(+) New Reservoirs in Old Fields . . . . 15,530 9,363 7 0 0 24,900

(–) Production With

Proved Reserves Reported ..... 152,210 16,106 668 0 0 168,984

(–) Production Without

Proved Reserves Reported . . . . . 158 3,918 75 0 0 4,151

Proved Reserves as of 12/31/04 . . . . . . 1,032,347 133,347 6,120 0 0 1,171,814

Imputed and Estimated

Number of Operators . . . . . . . . . . . . . . . - - - 5,751 - 5,751

Proved Reserves as of 12/31/03 . . . . . . - - - - - -

(+) Revision Increases . . . . . . . . . . . . 0 0 0 0 12,355 12,355

(–) Revision Decreases. . . . . . . . . . . . 0 0 0 0 16,147 16,147

(–) Sales . . . . . . . . . . . . . . . . . . . . . . . 0 0 0 0 435 435

(+) Acquisitions . . . . . . . . . . . . . . . . . . 0 0 0 0 7,435 7,435

(+) Extensions. . . . . . . . . . . . . . . . . . . 0 0 0 0 5,479 5,479

(+) New Field Discoveries. . . . . . . . . . 0 0 0 0 354 354

(+) New Reservoirs in Old Fields . . . . 0 0 0 0 1,521 1,521

(–) Production With

Proved Reserves Reported . . . . . 0 0 0 0 257 257

(–) Production Without

Proved Reserves Reported . . . . . 108 566 861 1,535 4,426 7,496

Proved Reserves as of 12/31/04 . . . . . . 711 2,179 3,392 6,282 35,185 47,749

Total

Number of Operators . . . . . . . . . . . . . . . 171 459 289 6,087 13,664 20,670

Proved Reserves as of 12/31/03 . . . . . . 1,055,487 103,119 8,882 0 0 1,167,488

(+) Revision Increases . . . . . . . . . . . . 284,962 26,153 1,482 0 12,355 324,952

(–) Revision Decreases. . . . . . . . . . . . 263,941 21,945 369 0 16,147 302,402

(–) Sales . . . . . . . . . . . . . . . . . . . . . . . 80,417 11,048 4,457 0 435 96,357

(+) Acquisitions . . . . . . . . . . . . . . . . . . 79,008 23,877 1,096 0 7,435 111,416

(+) Extensions. . . . . . . . . . . . . . . . . . . 90,912 18,984 147 0 5,479 115,522

(+) New Field Discoveries. . . . . . . . . . 3,072 905 0 0 354 4,331

(+) New Reservoirs in Old Fields . . . . 15,530 9,363 7 0 1,521 26,421

(–) Production With

Proved Reserves Reported ..... 152,210 16,106 668 0 257 169,241

(–) Production Without

Proved Reserves Reported . . . . . 266 4,484 936 1,535 4,426 11,647

Proved Reserves as of 12/31/04 . . . . . . 1,033,058 135,526 9,512 6,282 35,185 1,219,563

Summary

Total Number of Operators . . . . . . . . . 171 459 289 6,087 13,664 20,670

Percent of Total . . . . . . . . . . . . . . . . . . 0.8% 2.2% 1.4% 29.4% 66.1% 100.0%

Total Production in 2004 ........... 152,476 20,590 1,604 1,535 4,683 180,888

Percent of Total . . . . . . . . . . . . . . . . . . 84.3% 11.4% 0.9% 0.8% 2.6% 100.0%

Total Proved Reserves 12/31/04 . . . . . 1,033,058 135,526 9,512 6,282 35,185 1,219,563

Percent of Total . . . . . . . . . . . . . . . . . . 84.7% 11.1% 0.8% 0.5% 2.9% 100.0%

aThere were 355 noncertainty responses, 137 were used with their sample weights and 218 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,” 2004.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report F-9

Table F6. Statistical Parameters of Reserves Estimation Equation by Region for 2004

Number of Nonzero Equation Coefficients

Region R/P Pairs Oil Gas LC

Number Region Oil Gas LC Alpha Beta Alpha Beta Alpha Beta

1 Alaska.................. 8 8 0 -0.1320 0.3987 -0.1295 0.4172 0.0000 0.0000

2 Pacific Coast States . . . . . . . . . . . 42 56 5 -0.1320 0.3027 -0.1295 0.3526 -0.1166 0.7765

2A Federal Offshore Pacific ......... 4 6 0 -0.1320 0.5436 -0.1295 0.4245 0.0000 0.0000

3 Western Rocky Mountains . . . . . . . . 74 130 52 -0.1320 0.2551 -0.1295 0.2928 -0.1166 0.1836

4 Northern Rocky Mountains . . . . . . . . 163 169 49 -0.1320 0.2583 -0.1295 0.2827 -0.1166 0.2280

5 West Texas and East New Mexico . . . . 491 498 167 -0.1320 0.2764 -0.1295 0.3614 -0.1166 0.5075

6 Western Gulf Basin. . . . . . . . . . . . 511 849 577 -0.1320 0.3503 -0.1295 0.4163 -0.1166 0.4956

6A Gulf of Mexico . . . . . . . . . . . . . . 75 140 115 -0.1320 0.4990 -0.1295 0.7261 -0.1166 0.7270

7 Mid-Continent . . . . . . . . . . . . . . 274 367 147 -0.1320 0.2639 -0.1295 0.3172 -0.1166 0.2826

8 + 9 Michigan Basin and Eastern Interior . . . . 68 59 16 -0.1320 0.2239 -0.1295 0.1888 -0.1166 0.2684

10 + 11 Appalachians . . . . . . . . . . . . . . 24 66 9 -0.1320 0.2519 -0.1295 0.1673 -0.1166 0.2526

United States .............. 1,734 2,348 1,137 -0.1320 0.3627 -0.1295 0.3818 -0.1166 0.4676

Source: Based on data filed on Form EIA-23,"Annual Survey of Domestic Oil and Gas Reserves, 2004".

Figure F1. Form EIA-23 Regional Boundaries
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 2004 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

or fewer certainty operators were included in

2004 than in 2003.

One or more operators may have reported data

incorrectly on Schedule A in 2004 or 2003, but

not both, and the error was not detected by edit

processing.

Energy Information Administration

F-10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 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
Operation of properties was transferred during

2004 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 by V

s and its sampling error by S.E.

( - V

s), the confidence interval can be expressed as:

. .( V kSE V ) s s 

where k is a multiple selected to provide the desired

level of confidence. For this survey, k was taken equal

to 2. Then there is approximately 95 percent confidence

that the interval:

. .( V SE V ) s s  2

includes the universe value, for both the estimates of

reserves and production volumes. Correspondingly,

for approximately 95 percent of the estimates in this

report, the difference between the published estimate

and the value that would be found from a complete

survey of all operators is expected to be less than twice

the sampling error of the estimate. Tables F7 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 192,513 392 billion

cubic feet. The sampling error of V

s is equal to the

sampling error of the noncertainty estimate V

sr ,

because the certainty total is not subject to sampling

error. The estimated sampling error of a noncertainty

estimate is the square root of its estimated sampling

variance.

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.

Imputation for Operator Nonresponse

The nonresponse rate for certainty operators for the

2004 survey was 3.0 percent and for the noncertainty

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report F-11
operators 5.4 percent. An imputation was made for the

production and reserves for the 47 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 2004 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,

6.0 percent of the crude oil proved reserve estimates,

3.9 percent of the wet natural gas proved reserve

estimates, and 3.9 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

presented in Table 14 were computed as the sum of

plant liquids estimates (Table 15) and lease condensate

(Table 16) estimates.

Energy Information Administration

F-12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 Annual Report

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 2004 Form

EIA-64A survey, the national weighted average gas

equivalents ratio was computed to be 1,401 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 2004 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 2004 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 2004 U.S. proved reserves of 193 trillion

cubic feet yields a technically recoverable resource

target of 1,624 trillion cubic feet. This is about 85 times

the 2004 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 2004 oil production (Table

G1) was about 88 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 2004 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 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.{44} They are similarly defined by the MMS,

although its system also subdivides them by degree of

development and producing status.{45} 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

Energy Information Administration

G-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 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 2004 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 2004 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 2004 Annual Report G-7

Appendix H

Maps of Selected State Subdivisions
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2003 Annual Report
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 2004 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 2004 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 2004 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 2004 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 2004 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 2004 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 2004 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 2004 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 2004 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 2004 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 2004 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 2004 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 2004 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 2004 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 2004 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 2004 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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 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 2004 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.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2004 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 2004 Annual Report