U.S. Crude Oil, Natural Gas,

and Natural Gas Liquids Reserves

2005 Annual Report

DOE/EIA-0216(2005)

November 2006

DOE/EIA–0216(2005)

Distribution Category UC–950

U.S. Crude Oil, Natural Gas,

and Natural Gas Liquids Reserves

2005 Annual Report

November 2006

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 2005 Annual Report is the 29th

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, 2005, as well as production volumes

for the United States and producing States and State

subdivisions for the year 2005. 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 2005

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 2005; 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 2005 Annual Report iii
Energy Information Administration

iv U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 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 in the Elm Coulee Field in Richland County, Montana amid a carpet

of Montana snow. Photo by Tim Lechner, Senior Operations Engineer,

Headington Oil Company, Sidney, Montana.

Headington Oil Company, headquartered in Dallas, TX, is one of the two

largest lease holders in the Elm Coulee 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

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

Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

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

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

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

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

Pacific Federal Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Gulf of Mexico Federal Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

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

Reserves in Nonproducing Status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

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

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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report v
Page

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

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

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

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

Total Discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

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

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

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

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

Coalbed Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

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

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

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

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

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

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

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

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

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

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

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

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

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

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

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

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, 1995-2005 ............ 4

2. Reserves Changes, 1977-2005 ........................................... 9

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vi U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report
Page

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, 1977-2005 . . . . . . . . . . . . . . . . . . . . . . . . . . 10

4. U.S. Exploratory and Development Well Completions, 1973-2005 . . . . . . . . . . . . . . . . . . . . . . . . . 12

5. International Oil and Natural Gas Reserves as of December 31, 2005 . . . . . . . . . . . . . . . . . . . . . . . 18

6. Crude Oil Proved Reserves, Reserves Changes, and Production, 2005 . . . . . . . . . . . . . . . . . . . . . . 22

7. Reported Reserves in Nonproducing Status for Crude Oil, 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . 27

8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 2005 . . . . . . . . . . . . . . . . . . 30

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

Wet After Lease Separation, 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

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

Wet After Lease Separation, 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

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

Wet After Lease Separation, 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

12. Coalbed Natural Gas Proved Reserves and Production, 1989-2005 . . . . . . . . . . . . . . . . . . . . . . . . 38

13. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 2005 . . . . . . . . . . . . . . . . 42

14. Natural Gas Plant Liquids Proved Reserves and Production, 2005. . . . . . . . . . . . . . . . . . . . . . . . . 43

15. Lease Condensate Proved Reserves and Production, 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Figures

1. U.S. Crude Oil Proved Reserves, 1995-2005 .................................... 5

2. Components of Reserves Changes for Crude Oil, 1995-2005 ........................... 5

3. U.S. Dry Natural Gas Proved Reserves, 1995-2005 ................................ 6

4. Components of Reserves Changes for Dry Natural Gas, 1995-2005 ........................ 6

5. U.S. Natural Gas Liquids Proved Reserves, 1995-2005 .............................. 8

6. Components of Reserves Changes for Natural Gas Liquids, 1995-2005 ...................... 8

7. U.S. Exploratory Well Completions, 1995-2005. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

8. U.S. Development Well Completions, 1995-2005. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

9. U.S. Total Discoveries of Dry Natural Gas per Exploratory Gas Well Completion, 1977-2005 . . . . . . . . . . . 14

10. U.S. Total Discoveries of Crude Oil per Exploratory Oil Well Completion, 1977-2005 . . . . . . . . . . . . . . . 14

11. Reserves-to-Production Ratios for Crude Oil, 1945-2005. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

12. Reserves-to-Production Ratios for Wet Natural Gas, 1945-2005 . . . . . . . . . . . . . . . . . . . . . . . . . . 16

13. Components of Proved Ultimate Recovery for Crude Oil and Lease Condensate, 1977-2005 . . . . . . . . . . . 17

14. Components of Proved Ultimate Recovery for Wet Natural Gas, 1977-2005 . . . . . . . . . . . . . . . . . . . . 17

15 Replacement of U.S. Crude Oil Production by Reserves Additions, 1995-2005 . . . . . . . . . . . . . . . . . . 21

16. Crude Oil Proved Reserves by Area, 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

17. Changes in Crude Oil Proved Reserves by Area, 2004 to 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . 23

18. Replacement of U.S. Dry Natural Gas Production by Reserves Additions, 1995-2005 . . . . . . . . . . . . . . . 29

19. Dry Natural Gas Proved Reserves by Area, 2005. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

20. Changes in Dry Natural Gas Proved Reserves by Area, 2004 to 2005 . . . . . . . . . . . . . . . . . . . . . . . 31

21. Coalbed Natural Gas Proved Reserves, 1989-2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report vii

Executive Summary

Reserves additions replaced 164 percent of 2005 dry

gas production as U.S. gas reserves increased for the

seventh year in a row. Proved reserves of natural gas

increased by 6 percent in 2005, the largest annual

increase in natural gas proved reserves since 1970.

Reserves additions of crude oil replaced 122 percent

of the 2005 production. Crude oil proved reserves

increased for the first time in 3 years, up 2 percent

from 2004.

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

Gas reserves additions onshore in the lower 48 States

were large enough to overcome a 10 percent drop in

gas reserves reported for the Gulf of Mexico Federal

Offshore. The majority of natural gas reserves

additions in 2005 resulted from extensions of existing

gas fields rather than new field or reservoir

discoveries. Texas and Colorado led the nation in

2005 natural gas reserves additions with notable

reserves increases in the Newark East Field (Barnett

Shale, TX) and Ignacio-Blanco Field (tight sands and

coalbeds, CO).

Total U.S. natural gas production declined 4 percent

in 2005 because, in August and September of 2005,

Hurricanes Katrina and Rita wreaked havoc along

the Gulf Coast. Beyond devastating much of coastal

Alabama, Louisiana, Mississippi, and the flooding of

New Orleans, these storms destroyed 113 offshore

platforms and seriously damaged offshore pipelines

and coastal oil and natural gas processing facilities,

impacting the Nation's oil and gas production. At its

nadir, natural gas production in the Gulf of Mexico

(which accounted for 20 percent of U.S. dry gas

production in 2004) was cut by 80 percent. Gulf of

Mexico production slowly returned and reached

roughly 80 percent of 2005’s pre-hurricane

production rate (10.2 Bcf/day gross withdrawal in

June 2005) in September 2006. For several years

before Hurricane Katrina, gas production from the

Gulf had been declining about 10 percent per year.

Total discoveries of dry natural gas reserves

attributed to the drilling of exploratory wells, which

include field extensions, new field discoveries, and

new reservoir discoveries in old fields, were 23,200

billion cubic feet in 2005. This was 45 percent more

than the prior 10-year average and 15 percent more

than in 2004.

The majority of natural gas total discoveries in 2005

were from extensions to existing gas fields. Field

extensions were 21,050 billion cubic feet, 16 percent

more than in 2004 and 74 percent more than the

prior 10-year average (12,101 billion cubic feet).

New field discoveries were 942 billion cubic feet, 24

percent more than the volume discovered in 2004

and 46 percent less than the prior 10-year average

(1,731 billion cubic feet).

New reservoir discoveries in old fields were 1,208

billion cubic feet, up slightly from 2004 and 45

percent less than the prior 10-year average (2,198

billion cubic feet).

Natural gas net revisions and adjustments were 4,586

billion cubic feet, which is seven times the net

revisions and adjustments of 2004, but 7 percent less

that the prior 10-year average (4,908 billion cubic

feet). The net of sales and acquisitions of dry natural

gas proved reserves was 2,544 billion cubic feet.

Coalbed natural gas reserves increased 8 percent in

2005 and accounted for 10 percent of U.S. dry natural

gas reserves. Coalbed natural gas production

increased less than 1 percent from 2004 and

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report ix

As of December 31, 2005 proved reserves were:

Crude Oil (million barrels)

2004 21,371

2005 21,757

Increase +1.8%

Dry Natural Gas (billion cubic feet)

2004 192,513

2005 204,385

Increase +6.2%

Natural Gas Liquids (million barrels)

2004 7,928

2005 8,165

Increase +3.0%
accounted for 9 percent of U.S. dry natural gas

production.

Other 2005 natural gas events of note:

• Natural gas prices at the wellhead rose 38

percent in 2005 to an average of $7.51 per

thousand cubic feet, as compared to $5.46 per

thousand cubic feet in 2004.

• Exploratory and developmental gas

completions were up 27 percent from 2004.

Crude Oil

Reserves additions of crude oil replaced 122 percent

of the 2005 production. Crude oil proved reserves

increased for the first time in 3 years, increasing by 2

percent from 2004. Two of the four largest U.S.

oil-producing areas, Texas and California, reported

increases in proved crude oil reserves in 2005 while

Alaska and the Gulf of Mexico Federal Offshore

reported declines. Several significant deepwater

discoveries that have been made in recent years in

the Gulf are not yet booked as proved reserves.

Texas reported the largest increase in crude oil

reserves, a majority from the Permian Basin in west

Texas. Wyoming and Montana had the second and

third largest increases.

U.S. crude oil production declined in 2005 due to

lower production in the Gulf of Mexico and Alaska.

The Rocky Mountain States generally increased

crude oil production in 2005 with the largest increase

occurring in Montana (up 36 percent) from

development of the Bakken formation of the

Williston Basin.

Total discoveries of crude oil were 1,051 million

barrels in 2005, 7 percent less than the prior 10-year

average and 34 percent more than 2004's discoveries

of 782 million barrels.

The majority of crude oil total discoveries in 2005

came from extensions to fields in Texas, California,

Montana, and Wyoming.

New field discoveries accounted for 205 million

barrels of crude oil reserves additions. Almost all of

these discoveries (201 of 205 million) were in the

Gulf of Mexico Federal Offshore. This was 6 times

greater than the new field discoveries of 2004 and

only 49 percent of the prior 10-year average (419

million barrels).

Operators discovered 805 million barrels in

extensions in 2005, 30 percent more than in 2004 and

53 percent more than the prior 10-year average (527

million barrels).

New reservoir discoveries in old fields were 41

million barrels, 69 percent less than 2004 and only 23

percent of the prior 10-year average (180 million

barrels).

Reserves additions are the sum of total discoveries,

revisions, adjustments, sales, and acquisitions. In

2005, reserve additions were 2,119 million barrels, 63

percent more than the volume of reserves additions

in 2004 and 13 percent more than the prior 10-year

average (1,875 million barrels).

Crude oil net revisions and adjustments were 790

million barrels, 60 percent more than the net

revisions and adjustments of 2004 and almost equal

to the prior 10-year average (795 million barrels). The

net of sales and acquisitions of crude oil proved

reserves was 278 million barrels.

Other 2005 crude oil events of note:

• The annual average domestic first purchase

price for crude oil increased 37 percent from

$36.77 per barrel in 2004 to $50.28 per barrel.

• Exploratory and developmental oil

completions were up 25 percent from 2004.

Natural Gas Liquids

Natural gas liquids reserves are the sum of lease

condensate reserves and natural gas plant liquids

reserves. Natural gas liquids proved reserves

increased 3 percent in 2005. Operators replaced 130

percent of U.S. natural gas liquids production with

reserves additions.

Total proved reserves of liquid hydrocarbons (crude

oil plus natural gas liquids) were 29,922 million

barrels in 2005, a 2 percent increase from the 2004

level. Natural gas liquids represented 27 percent of

total liquid hydrocarbon proved reserves in 2005.

Data

These estimates are based upon analysis of data from

Form EIA-23, Annual Survey of Domestic Oil and

Gas Reserves, filed by 1,394 operators of oil and gas

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

Origin of Natural Gas Liquids Production, filed by

operators of 508 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 2005 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 2005. 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 2005 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 15,158 probable active operators and the

Form EIA-64A plant frame contained 489 probable

active natural gas processing plants in the United

States when the 2005 surveys were initiated.

For more details on the survey process, see Appendix

E, Summary of Data Collection Operations.

The 2005 survey sample consisted of 1,394 operators.

EIA sampled 889 operators with certainty; 172

Category I operators, 522 Category II operators, and

195 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 505 Noncertainty

operators as a systematic random sample of the

remaining operators. There were 8 Successor operators

in 2005. Forty-seven (47) of the 1,394 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 496 unique

active natural gas processing plants in 2005.

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 2005,

the Form EIA-23 National production estimates were 1

percent higher than the comparable Petroleum Supply

Annual (PSA) 2005 volumes for crude oil and lease

condensate combined, and were 1 percent higher than

the comparable Natural Gas Monthly, October 2006

volume for 2005 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 2005 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, 2005:

Crude Oil — 21,757 million barrels

Dry Natural Gas — 204,385 billion cubic feet

Natural Gas Liquids — 8,165 million barrels.

This Overview summarizes the 2005 proved reserves

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

liquids on a National level and provides historical

comparisons between 2005 and prior years. Table 1

lists the estimated annual reserve balances since 1995

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

Crude Oil

Crude oil proved reserves went up for the first time in 3

years, increasing by 386 million barrels in 2005. Figure

1 shows the crude oil proved reserves levels by major

region and Figure 2 shows the components of reserves

changes from 1995 through 2005.

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

increased onshore in the lower 48 States in 2005, but

declined in Alaska and the Federal Offshore.

The components of reserves changes for crude oil are

shown in Figure 2. EIA tracks all components of

reserves changes: adjustments, revision increases,

revision decreases, sales, acquisitions, extensions, new

field discoveries, new reservoir discoveries in old

fields, and estimated production. These components

are discussed below.

Total discoveries are those reserves attributable to field

extensions, new field discoveries, and new reservoir

discoveries in old fields. They result from the drilling of

exploratory wells. Total discoveries of crude oil were

1,051 million barrels in 2005, 7 percent less than the

prior 10-year average but 34 percent more than 2004’s

discoveries of 782 million barrels.

The majority of crude oil total discoveries in 2005 came

from extensions to fields in Texas, California, Montana,

and Wyoming.

New field discoveries accounted for 205 million barrels

of crude oil total discoveries. Almost all of these

discoveries (201 of 205 million) were in the Gulf of

Mexico Federal Offshore. While this was 6 times

greater than the new field discoveries of 2004 (33

million barrels), it was only 49 percent of the prior

10-year average (419 million barrels).

Operators discovered 805 million barrels in extensions

in 2005, 30 percent more than in 2004 and 53 percent

more than the prior 10-year average (527 million

barrels).

New reservoir discoveries in old fields were 41 million

barrels, 69 percent less than 2004 and only 23 percent of

the prior 10-year average (180 million barrels).

Reserves additions are the sum of total discoveries,

revisions, adjustments, sales, and acquisitions. In 2005,

crude oil reserves additions were 2,119 million barrels,

63 percent more than in 2004 and 13 percent more than

the prior 10-year average (1,875 million barrels).

Crude oil net revisions and adjustments were 790

million barrels, 60 percent more than the net revisions

and adjustments of 2004 and almost equal to the prior

10-year average (795 million barrels). The net of sales

and acquisitions of crude oil proved reserves was 278

million barrels.

U.S. crude oil production declined in 2005 due to lower

production in the Gulf of Mexico and Alaska. The

Rocky Mountain States generally increased crude oil

production in 2005 with the largest increase occurring

in Montana (up 36 percent, from 22 to 30 million

barrels) owing to development of the Bakken

formation of the Williston Basin. Reserves additions of

crude oil replaced 122 percent of the 2005 production.

Natural Gas

Dry natural gas proved reserves increased by 11,872

billion cubic feet in 2005. 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 1995 through 2005.

Total discoveries of dry natural gas reserves, which is

the sum of field extensions, new field discoveries, and

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 3
Energy Information Administration

4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table 1. Total U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids, 1995-2005

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)

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

2005 221 569 790 278 805 205 41 1,051 1,733 21,757 +386

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

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

2005 1,887 2,699 4,586 2,544 21,050 942 1,208 23,200 18,458 204,385 +11,872

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

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

2005 -89 21 -68 156 863 32 42 937 788 8,165 +237

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

2005 contained in the Petroleum Supply Annual 2005, DOE/EIA-0340(05) and the Natural Gas Annual 2005, DOE/EIA-0131(05).

Sources: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1995 through 2005 annual reports, DOE/EIA-0216.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 5

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1995-2004 annual reports, DOE/EIA-0216.{19-28}

Figure 1. U.S. Crude Oil Proved Reserves, 1995-2005

Figure 2. Components of Reserves Changes for Crude Oil, 1995-2005
Energy Information Administration

6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Figure 4. Components of Reserves Changes for Dry Natural Gas, 1995-2005

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1995-2004 annual reports, DOE/EIA-0216.{19-28}

Figure 3. U.S. Dry Natural Gas Proved Reserves, 1995-2005
new reservoir discoveries in old fields, were 23,200

billion cubic feet in 2005. This was 45 percent more than

the prior 10-year average and 15 percent more than in

2004.

The majority of natural gas total discoveries in 2005

were from extensions to existing fields. Field

extensions were 21,050 billion cubic feet, 16 percent

more than in 2004 and 74 percent more than the prior

10-year average (12,101 billion cubic feet).

New field discoveries were 942 billion cubic feet, 24

percent more than the volume discovered in 2004 and

46 percent less than the prior 10-year average (1,731

billion cubic feet).

New reservoir discoveries in old fields were 1,208

billion cubic feet, up slightly from 2004 and 45 percent

less than the prior 10-year average (2,198 billion cubic

feet).

Natural gas net revisions and adjustments were 4,586

billion cubic feet, which is seven times the net revisions

and adjustments of 2004, but 7 percent less that the

prior 10-year average (4,908 billion cubic feet). The net

of sales and acquisitions of dry natural gas proved

reserves was 2,544 billion cubic feet.

Total U.S. natural gas production declined 4 percent in

2005 because, in August and September of 2005,

Hurricanes Katrina and Rita wreaked havoc along the

Gulf Coast. Beyond devastating much of coastal

Alabama, Louisiana, Mississippi, and the flooding of

New Orleans, these storms destroyed 113 offshore

platforms and seriously damaged offshore pipelines

and coastal oil and natural gas processing facilities,

impacting the Nation's oil and gas production. At its

nadir, natural gas production in the Gulf of Mexico

(which accounted for 20 percent of U.S. dry gas

production in 2004) was cut by 80 percent. Gulf of

Mexico production slowly returned and reached

roughly 80 percent of 2005’s pre-hurricane production

rate (10.2 Bcf/day gross withdrawal in June 2005) in

September 2006. For several years before Hurricane

Katrina, gas production from the Gulf had been

declining about 10 percent per year.

Coalbed natural gas reserves increased 8 percent in

2005 and accounted for 10 percent of U.S. dry natural

gas reserves. Coalbed natural gas production increased

less than 1 percent from 2004 and accounted for 9

percent of U.S. dry natural gas production.

Natural Gas Liquids

Natural gas liquids reserves are the sum of lease

condensate reserves and natural gas plant liquids

reserves. Natural gas liquids proved reserves increased

3 percent in 2005. Operators replaced 130 percent of

U.S. natural gas liquids production with reserves

additions.

Total proved reserves of liquid hydrocarbons (crude oil

plus natural gas liquids) were 29,922 million barrels in

2005, a 2 percent increase from the 2004 level. Natural

gas liquids represented 27 percent of total liquid

hydrocarbon proved reserves in 2005.

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 2005. 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 2005 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

906 million barrels,

had average annual proved reserves additions

of 2,067 million barrels from total discoveries,

net revisions and adjustments, and net sales and

acquisitions, and

had an average annual proved reserves decline

of 405 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 26,260 million barrels of total discoveries

accounted for 44 percent of reserves additions.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 7
Energy Information Administration

8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Figure 5. U.S. Natural Gas Liquids Proved Reserves, 1995-2005

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1995-2004 annual reports, DOE/EIA-0216.{19-28}

Figure 6. Components of Reserves Changes for Natural Gas Liquids, 1995-2005
Compared to the averages of reserves changes since

1977, 2005 was an up year for crude oil discoveries.

Total discoveries of crude oil (1,051 million barrels) in

2005 were 16 percent more than the post-1976 U.S.

average (906 million barrels per year).

Looking at the components of total discoveries in 2005:

Extensions in 2005 (805 million barrels) were 53

percent more than the post-1976 average (525

million barrels),

2005’s new field discoveries (205 million barrels)

were 14 percent less than the post-1976 average

for crude oil (237 million barrels), and

New reservoir discoveries in old fields (41

million barrels) were 71 percent less than the

post-1976 average (143 million barrels).

Revisions, Adjustments, Sales & Acquisitions were

1,068 million barrels in 2005. This was 8 percent less

than the post-1976 average of 1,161 million barrels per

year.

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

had average annual new reserves discoveries of

13,714 billion cubic feet,

had average annual proved reserves additions

of 17,736 billion cubic feet from total

discoveries, net revisions and adjustments, and

net sales and acquisitions, and

had an average annual production of 18,043

billion cubic feet, decreasing U.S. dry natural

gas reserves by an average 307 billion cubic feet

per year.

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 53 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, 2005 was an up year for dry natural gas total

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 9

Table 2. Reserves Changes, 1977-2005

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 . . . . . . . . . . . 5,930 204 12.0 6,881 237 11.5

New Reservoir Discoveries in Old Fields . . 3,955 136 8.0 4,143 143 6.9

Extensions . . . . . . . . . . . . . . . . 13,478 465 27.4 15,236 525 25.4

Total Discoveries . . . . . . . . . . . . . 23,363 806 47.5 26,260 906 43.8

Revisions, Adjustments, Sales & Acquisitionsa 25,855 892 52.5 33,682 1,161 56.2

Total Reserves Additions . . . . . . . . . 49,218 1,697 100.0 59,942 2,067 100.0

Production . . . . . . . . . . . . . . . . 56,496 1,948 114.8 71,687 2,472 119.6

Net Reserves Change . . . . . . . . . . . -7,278 -251 -14.8 -11,745 -405 -19.6

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 . . . . . . . . . . . 53,849 1,857 10.2 54,113 1,866 10.5

New Reservoir Discoveries in Old Fields . . 69,288 2,389 13.1 69,747 2,405 13.6

Extensions ................ 270,580 9,330 51.3 273,853 9,443 53.2

Total Discoveries ............. 393,717 13,576 74.6 397,713 13,714 77.3

Revisions, Adjustments, Sales & Acquisitionsa 134,101 4,624 25.4 116,641 4,022 22.7

Total Reserves Additions ......... 527,818 18,201 100.0 514,354 17,736 100.0

Production ................ 512,442 17,670 97.1 523,247 18,043 101.7

Net Reserves Change . . . . . . . . . . . 15,376 530 2.9 -8,893 -307 -1.7

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 1977-2005 annual reports, DOE/EIA-0216.{1-28}
Energy Information Administration

10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 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, 1977-2005

Crude Oil Natural Gas

Year Current 2005 Constant Current 2005 Constant

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

1977 8.57 22.22 0.79 2.05 2,001

1978 9.00 21.78 0.91 2.20 2,259

1979 12.64 28.24 1.18 2.64 2,177

1980 21.59 44.16 1.59 3.25 2,909

1981 31.77 59.45 1.98 3.70 3,970

1982 28.52 50.23 2.46 4.33 3,105

1983 26.19 44.38 2.59 4.39 2,232

1984 25.88 42.28 2.66 4.35 2,428

1985 24.09 38.15 2.51 3.97 1,980

1986 12.51 19.38 1.94 3.01 964

1987 15.40 23.17 1.67 2.51 936

1988 12.58 18.30 1.69 2.46 936

1989 15.86 22.23 1.69 2.37 869

1990 20.03 27.01 1.71 2.31 1,010

1991 16.54 21.53 1.64 2.13 860

1992 15.99 20.32 1.74 2.21 721

1993 14.25 17.68 2.04 2.53 754

1994 13.19 16.03 1.85 2.25 775

1995 14.62 17.39 1.55 1.84 723

1996 18.46 21.54 2.17 2.53 779

1997 17.23 19.72 2.32 2.66 943

1998 10.87 12.29 1.96 2.22 827

1999 15.56 17.35 2.19 2.44 625

2000 26.72 29.17 3.68 4.02 918

2001 21.84 23.29 4.00 4.27 1,156

2002 22.51 23.74 2.95 3.11 830

2003 27.56 28.60 4.88 5.06 1,032

2004 January 30.35 31.21 5.21 5.36 1,101

February 31.21 32.05 5.02 5.16 1,119

March 32.86 33.70 5.12 5.25 1,135

April 33.20 34.01 5.03 5.15 1,151

May 35.73 36.55 5.40 5.52 1,164

June 34.53 35.26 5.82 5.94 1,176

July 36.54 37.23 5.62 5.73 1,213

August 40.10 40.78 5.52 5.61 1,234

September 40.56 41.18 5.06 5.14 1,240

October 46.14 46.76 5.43 5.50 1,240

November 42.85 43.35 6.21 6.28 1,262

December 38.22 38.61 6.01 6.07 1,246

2004 Average 36.77 37.51 5.46 5.57 1,192

2005 January 40.18 40.53 5.52 5.57 1,255

February 42.19 42.50 5.59 5.63 1,276

March 47.56 47.84 5.98 6.02 1,306

April 47.26 47.48 6.44 6.47 1,334

May 44.03 44.18 6.02 6.04 1,320

June 49.83 49.93 6.15 6.16 1,355

July 53.35 53.40 6.69 6.70 1,398

August 58.90 58.87 7.68 7.68 1,436

September 59.64 59.53 9.50 9.48 1,452

October 56.99 56.79 10.97 10.93 1,479

November 53.20 52.92 9.54 9.49 1,486

December 53.24 52.87 10.02 9.95 1,470

2005 Average 50.28 50.28 7.51 7.51 1,383

Sources: Current dollars and number of rigs: Monthly Energy Review September 2006, DOE/EIA-0035(2006/09). 2005 constant dollars:

U.S. Department of Commerce, Bureau of Economic Analysis, Gross Domestic Product Implicit Price Deflators, October 2006.
discoveries. Operators reported 23,200 billion cubic

feet of total discoveries of dry natural gas proved

reserves, 69 percent more than the post-1976 average

(13,714 billion cubic feet).

The net of revisions, adjustments, sales, and

acquisitions was 7,130 billion cubic feet in 2005, 77

percent higher than the post-1976 U.S. average (4,022

billion cubic feet per year).

For the seventh year in a row (and 11 out of the last 12

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 2005.

In 2005, the U.S. crude oil first purchase price started at

a monthly average of $40.18 per barrel in January, rose

to a high of $59.64 in September, and ended the year at

$53.24 per barrel in December. The average annual U.S.

crude oil first purchase price increased from $36.77 in

2004 to $50.28 per barrel in 2005.

Oil prices vary by region. The average annual 2005

crude oil first purchase price ranged from $52.61 per

barrel in Texas through $47.08 per barrel in California,

$55.34 per barrel in Colorado, and $53.47 per barrel in

Ohio, to a low of $43.48 per barrel in the California

Federal Offshore. {29}

The average annual wellhead natural gas price

increased from $5.46 per thousand cubic feet in 2004 to

$7.51 in 2005. Monthly average natural gas prices

started at $5.52 per thousand cubic feet in January 2005,

rose to a high of $10.97 in October, and ended the year

at $10.02 per thousand cubic feet in December 2005. {30}

Drilling: Also listed in Table 3 is the average number

of active rotary drilling rigs from 1977 to 2005. From

2004 to 2005, the annual average active rig count rose

from 1,192 to 1,383, a 16 percent increase.

Looking first at exploratory wells, there were 3,458

exploratory wells drilled in 2005 (Table 4). Of these, 12

percent were completed as oil wells, 42 percent were

completed as gas wells, and 46 percent were dry holes.

Exploratory oil and gas completions (excluding dry

holes) in 2005 were 12 percent more (Figure 7) than the

revised 2004 total.

Figures 9 and 10 show the average volume of

discoveries per exploratory well for dry natural gas

and oil, respectively, since 1977. The 2005 average

volume of oil discoveries per exploratory well

increased 5 percent compared to 2004. The 2005

average volume of gas discoveries per exploratory well

increased 5 percent compared to 2004.

The number of successful development wells increased

by 28 percent for oil and by 27 percent for gas from their

2004 levels (Figure 8). Including dry holes, there were

an estimated 41,874 exploratory and development

wells drilled in 2005. This is 27 percent more than in

2004 and 57 percent more than the average number of

wells drilled annually in the prior 10 years (26,705).

For the twelfth 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 2005 and are expected to have an impact

on the energy industry in the future:

On August 10, 2005, Chevron Corporation announced

that it had completed its merger with Unocal

Corporation. Unocal’s stockholders agreed to

Chevron’s offer, which was originally announced on

April 4, 2005, and rejected a higher bid tendered on

June 24, 2005 by Chinese oil company CNOOC Ltd. The

merger will reportedly increase Chevron’s proved

reserves (based on year-end 2004 reporting and

including the company’s share of equity affiliates) by

more than 15 percent. {31}

On April 26, 2005, Valero Energy Corporation agreed

to acquire refiner Premcor Incorporated for $8.9 billion

in cash and stock plus the assumption of about $1.8

billion of debt. The merger created the largest refiner of

crude oil in North America and marks a major step in

the U.S. refinery industry’s rapid consolidation. The

deal between Valero and Premcor will give Valero total

refining capacity of 3.3 million barrels per day and will

raise it above Exxon Mobil Corporation’s North

American refinery capacity. Valero will then claim

about 13 percent of the U.S. market for refined

products. {32}

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 11
Energy Information Administration

12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table 4. U.S. Exploratory and Development Well Completions,a 1973-2005

Exploratory Total Exploratory and Development

Year Oil Gas Dry Total Oil Gas Dry Total

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 R 1,777 2,099 9,081 12,957 32,959 17,461 20,785 71,205

1981 R 2,651 2,522 12,400 17,573 43,887 20,250 27,953 92,090

1982 R 2,437 2,133 11,307 15,877 39,459 19,076 26,379 84,914

1983 R 2,030 1,605 10,206 13,841 37,366 14,684 24,355 76,405

1984 R 2,209 1,528 11,321 15,058 42,906 17,338 25,884 86,128

1985 R 1,680 1,200 8,954 11,834 35,261 14,324 21,211 70,796

1986 R 1,084 797 5,567 7,448 19,213 8,599 12,799 40,611

1987 R 926 756 5,052 6,734 16,210 8,096 11,167 35,473

1988 R 855 747 4,711 6,313 13,646 8,578 10,119 32,343

1989 R 607 706 3,934 5,247 10,230 9,522 8,236 27,988

1990 R 664 693 3,793 5,150 12,445 11,126 8,496 32,067

1991 R 601 544 3,390 4,535 12,035 9,611 7,882 29,528

1992 R 498 427 2,550 3,475 9,019 8,305 6,284 23,608

1993 R 509 541 2,509 3,559 8,764 10,174 6,513 25,451

1994 R 579 740 2,465 3,784 7,001 9,739 5,515 22,255

1995 R 549 583 2,279 3,411 7,827 8,454 5,319 21,600

1996 R 496 591 2,246 3,333 8,760 9,539 5,587 23,886

1997 R 434 543 2,178 3,155 10,445 11,186 5,955 27,586

1998 R 286 510 1,649 2,445 6,979 11,127 4,805 22,911

1999 R 156 519 1,167 1,842 4,314 11,121 3,504 18,939

2000 R 267 615 1,349 2,231 7,585 16,242 4,046 27,873

2001 R 330 972 1,716 3,018 8,186 21,403 4,432 34,021

2002 R 239 701 1,283 2,223 6,226 16,728 3,610 26,564

2003 R 326 892 1,266 2,484 7,465 19,522 3,688 30,675

2004 R 353 1,323 1,200 2,876 7,703 21,816 3,474 32,993

2005 429 1,452 1,577 3,458 9,833 27,397 4,644 41,874

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.

Source: Table 5.2, EIA Monthly Energy Review October 2006, DOE/EIA-0035(2006/10).
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 13

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

Figure 7. U.S. Exploratory Well Completions, 1995-2005

Figure 8. U.S. Development Well Completions, 1995-2005
Energy Information Administration

14 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 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, 1977-2005

Figure 10. U.S. Total Discoveries of Crude Oil per Exploratory Oil Well Completion, 1977-2005
On May 9, 2005, Duke Energy and Cinergy announced

their merger. The combined company, to be named

Duke Energy Corporation, through its joint venture

with ConocoPhillips, is now the largest producer of

natural gas liquids in North America. {33}

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 2005, U.S. crude oil proved reserves increased and

oil production decreased, increasing the National

average R/P ratio from 11.8 to 12.6.

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

since 1945. After World War II, increased drilling and

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

drilling found fewer reserves than were produced, the

ratio became smaller. R/P ratios also vary

geographically, because of differences in development

history and reservoir conditions. The 2005 National

average R/P ratio for crude oil was 12.6-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 the 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 2004

to 2005 the U.S. average R/P ratio for natural gas

increased from 10.1 to 11.1 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 as compared to the 2005

U.S. average R/P ratio of about 11.1-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

Proved Ultimate Recovery is the sum of proved

reserves and cumulative production at a specified

point in time. It measures the maximum recoverable

volume known at that time and is a dynamic quantity

that is expected to change over time for any field, group

of fields, State, or Country. In most instances, therefore,

an estimate of Proved Ultimate Recovery does not

represent the all-time maximum recoverable volume of

resources for a given field or area. Also, the proved

ultimate recovery of a field, a group of fields, a State, or

a Country grows (appreciates) over time in most

instances.

Figures 13 and 14 show successive estimates of proved

ultimate recovery for the United States. The figures

show proved reserves and cumulative production for

crude oil plus lease condensate and wet natural gas, over

the period 1977 through 2005. 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 2005 was 73,640 million barrels. This

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 15
Energy Information Administration

16 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Sources: Annual reserves and production - American Petroleum Institute and American Gas Association (1945–1976) {34} and Energy

Information Administration, Office of Oil and Gas (1977–2004){1-28}. Cumulative production: U.S. Oil and Gas Reserves by Year of Field

Discovery (1977-1988).{35}

Figure 11. Reserves-to-Production Ratios for Crude Oil, 1945-2005

Figure 12. Reserves-to-Production Ratios for Wet Natural Gas, 1945-2005
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 17

Sources: Annual reserves and production - American Petroleum Institute and American Gas Association (1945–1976) {34} and Energy

Information Administration, Office of Oil and Gas (1977–2004){1-28}. Cumulative production: U.S. Oil and Gas Reserves by Year of Field

Discovery (1977-1988).{35}

Figure 13. Components of Proved Ultimate Recovery for Crude Oil and Lease Condensate, 1977-2005

Figure 14. Components of Proved Ultimate Recovery for Wet Natural Gas, 1977-2005
Table 5. International Oil and Natural Gas Reserves as of December 31, 2005

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 ....... d266,810 d262,175 1 Russia . . . . . . . . . . . . . . 1,680,000 1,688,749

2 Iranc ............... 132,460 131,500 2 Iranc ................ 971,150 965,000

3 Iraqc ............... 115,000 115,000 3 Qatarc .............. 910,520 906,000

4 Kuwaitc ............. d104,000 d100,875 4 Saudia Arabiac........ d241,840 d243,500

5 Canadae ............ 178,792 12,025 5 United Arab Emiratesc . . 214,400 205,550

6 United Arab Emiratesc . 97,800 70,250 6 United States . . . . . . . . . 204,385 204,385

7 Russia. . . . . . . . . . . . . . 60,000 74,400 7 Nigeriac ............. 184,660 182,000

8 Venezuelac . . . . . . . . . . 79,729 52,650 8 Algeriac ............. 160,505 160,682

9 Libyac . . . . . . . . . . . . . . 39,126 34,050 9 Venezuelac .......... 151,395 150,890

10 Nigeriac. . . . . . . . . . . . . 35,876 37,175 10 Iraqc ................ 111,950 84,000

Top 10 Total. . . . . . . . . . . . . . 1,109,593 890,100 Top 10 Total . . . . . . . . . . . . . . 4,830,805 4,790,756

11 United States . . . . . . . . 21,757 21,757 11 Indonesiac . . . . . . . . . . . 97,786 91,500

12 Qatarc . . . . . . . . . . . . . . 15,207 20,346 12 Norway. . . . . . . . . . . . . . 84,260 83,272

13 China . . . . . . . . . . . . . . 18,250 16,189 13 Australia . . . . . . . . . . . . . 27,640 119,500

14 Mexico . . . . . . . . . . . . . 12,882 12,353 14 Turkmenistan . . . . . . . . . 71,000 -

15 Brazil. . . . . . . . . . . . . . . 11,243 11,925 15 Malaysia. . . . . . . . . . . . . 75,000 58,000

16 Algeriac. . . . . . . . . . . . . 11,350 11,350 16 Uzbekistan . . . . . . . . . . . 66,200 -

17 Kazakhstan. . . . . . . . . . 9,000 - 17 Kazakhstan . . . . . . . . . . 65,000 -

18 Norway . . . . . . . . . . . . . 7,705 8,246 18 Egypt . . . . . . . . . . . . . . . 58,500 66,840

19 Angola . . . . . . . . . . . . . 5,412 9,050 19 Kuwaitc.............. d56,015 d57,000

20 Azerbaijan. . . . . . . . . . . 7,000 - 20 Netherlands . . . . . . . . . . 62,000 50,500

21 Oman . . . . . . . . . . . . . . 5,506 4,790 21 Canada. . . . . . . . . . . . . . 56,577 53,700

22 India . . . . . . . . . . . . . . . 5,848 3,980 22 China . . . . . . . . . . . . . . . 53,325 55,606

23 Ecuador . . . . . . . . . . . . 4,630 5,145 23 Libyac. . . . . . . . . . . . . . . 52,650 51,500

24 Indonesiac . . . . . . . . . . 4,301 5,025 24 Ukraine. . . . . . . . . . . . . . 39,600 -

25 United Kingdom . . . . . . 4,029 3,750 25 India . . . . . . . . . . . . . . . . 38,800 27,259

Top 25 Total. . . . . . . . . . . . . . 1,253,713 1,024,006 Top 25 Total . . . . . . . . . . . . . . 5,735,238 5,448,433

OPEC Total . . . . . . . . . . . . . . 901,659 840,396 OPEC Total . . . . . . . . . . . . . . . 3,152,871 3,097,622

World Total . . . . . . . . . . . . . . 1,292,550 1,119,058 World Total . . . . . . . . . . . . . . . 6,112,144 6,215,220

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. 103, No. 47 (December 19, 2005). Gulf Publishing Company, World

Oil, Vol. 227, No. 9 (September, 2006).

Energy Information Administration

18 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report
substantially exceeds the 1977 proved reserves, but at

the end of 2005 there were still 23,019 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 phenomenon that typically accompanies

the 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 2005.

The other 88 percent 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 531 trillion cubic feet of

gas was produced from 1977 through 2005 and there

are still 213,308 billion cubic feet of wet natural gas

proved reserves in 2005. Only 11 percent of proved

reserve additions of natural gas were booked as new

field discoveries from 1976 through 2005. The other 89

percent came from proved ultimate recovery

appreciation.

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 6.2

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 2005. 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 2005. 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 12 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 Saudi Arabian and Iranian

reserves. The World Oil {36} estimate increased 3

percent in 2005 due to its larger estimate of Russian and

Canadian reserves. For world gas reserves, the Oil &

Gas Journal reported a 1 percent increase, while World

Oil reported an 11 percent decrease in 2005. The

decrease in World Oil’s estimate is from lower

estimates of Russian, Indonesian, and Australian gas

reserves.

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.{38} In 2005:

The U.S. consumed 99,894,000,000,000,000 Btu of

energy (99.9 quadrillion Btu). This was a

decrease of 0.52 quadrillion Btu from the 2004

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).

U.S. petroleum consumption was about 21

million barrels of oil and natural gas liquids

and 60 billion cubic feet of gas per day.

Dependence on Imports

The United States remains dependent on imported oil

and gas. In 2005, crude oil imports made up 66 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.{39}

Net gas imports increased from the 2004 total of 4.26

trillion cubic feet to 4.33 trillion cubic feet in 2005.

Imports satisfied approximately 20 percent of

consumption. Almost all of this gas was pipelined from

Canada. Some liquefied natural gas was imported from

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 19
Trinidad and Tobago, Algeria, and for the first time

ever, Russia.

List of Appendices

Appendix A: Operator Level Data - How much of the

National total of proved reserves are 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 lists the top U.S. operators by

reported 2005 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.

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 National level. Readers interested in a

historical look at one specific State or region can review

these tables in an electronic data archive on the EIA

website. Table D9 contains the production and proved

reserves for 1995-2005 for the Gulf of Mexico Federal

Offshore region by water depths greater than 200

meters, and less than 200 meters. Table D10 contains

Nonproducing Reserves.

Appendix E: Summary of Data Collection Operations

- This report is based on two annual EIA surveys.

Proved reserves data is collected 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 all of the technical

terms used in this report.

Energy Information Administration

20 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report
3. Crude Oil Statistics

The United States had 21,757 million barrels of crude

oil proved reserves as of December 31, 2005. Crude oil

proved reserves rose for the first time in 3 years,

increasing by 2 percent above the 2004 level. Reserves

additions of crude oil in the United States replaced 122

percent of the 2005 production (Figure 15).

Boosted by reserves additions in many States,

particularly Texas, Wyoming, Montana, Oklahoma,

and California, the lower 48 States’ crude oil proved

reserves increased by 3 percent.

Despite significant new field discoveries in the Gulf of

Mexico Federal Offshore and revision increases in

Alaska, the proved reserves of these two areas declined

in 2005 because reserves additions did not keep pace

with production. The crude oil reserves of the Pacific

Federal Offshore were revised downward in 2005. In

August and September 2005, Hurricanes Katrina and

Rita had major impacts on the Gulf Coast. The

extensive storm damage to platforms, pipelines, and

refining reduced U.S. annual oil production.

Proved Reserves

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

as of December 31, 2005, by selected States and State

subdivisions.

Figure 16 maps 2005 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 23

Alaska 19

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 2005 Annual Report 21

Figure 15. Replacement of U.S. Crude Oil Production by Reserves Additions, 1995-2005.

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

.
Energy Information Administration

22 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

aIncludes 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 2005 contained in the

Petroleum Supply Annual 2005, DOE/EIA-0340(05).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 4,327 -2 188 86 37 37 56 0 0 312 4,171

Lower 48 States . . . . . . . . . . . . . 17,044 223 1,356 889 786 1,064 749 205 41 1,421 17,586

Alabama. . . . . . . . . . . . . . . . . . . . 53 0 3 2 0 0 6 0 0 5 55

Arkansas . . . . . . . . . . . . . . . . . . . 51 -5 3 3 5 4 0 0 0 5 40

California . . . . . . . . . . . . . . . . . . . 3,376 16 177 70 4 23 147 0 0 230 3,435

Coastal Region Onshore . . . . . 380 3 12 15 2 1 10 0 0 15 374

Los Angeles Basin Onshore. . . 286 9 26 29 2 22 4 0 0 16 300

San Joaquin Basin Onshore . . 2,523 4 95 13 0 0 131 0 0 184 2,556

State Offshore . . . . . . . . . . . . . 187 0 44 13 0 0 2 0 0 15 205

Colorado . . . . . . . . . . . . . . . . . . . 225 -1 33 5 54 55 16 0 0 19 250

Florida . . . . . . . . . . . . . . . . . . . . . 65 1 0 4 0 0 0 0 0 3 59

Illinois. . . . . . . . . . . . . . . . . . . . . . 92 10 3 1 0 1 0 0 0 10 95

Indiana . . . . . . . . . . . . . . . . . . . . . 11 6 1 0 0 0 0 0 0 2 16

Kansas. . . . . . . . . . . . . . . . . . . . . 245 32 44 18 1 4 6 0 2 33 281

Kentucky . . . . . . . . . . . . . . . . . . . 27 -3 1 0 0 0 0 0 0 2 23

Louisiana . . . . . . . . . . . . . . . . . . . 427 23 54 44 21 26 19 0 3 55 432

North . . . . . . . . . . . . . . . . . . . . 58 5 11 9 0 1 10 0 0 8 68

South Onshore. . . . . . . . . . . . . 304 18 36 31 19 19 8 0 3 39 299

State Offshore . . . . . . . . . . . . . 65 0 7 4 2 6 1 0 0 8 65

Michigan . . . . . . . . . . . . . . . . . . . 53 1 7 1 0 0 7 0 0 5 62

Mississippi . . . . . . . . . . . . . . . . . . 178 2 25 8 1 11 0 0 0 18 189

Montana. . . . . . . . . . . . . . . . . . . . 364 -1 24 23 2 7 87 0 1 30 427

Nebraska . . . . . . . . . . . . . . . . . . . 15 1 2 0 0 0 0 0 0 2 16

New Mexico . . . . . . . . . . . . . . . . . 669 9 52 40 29 44 43 0 0 58 690

East . . . . . . . . . . . . . . . . . . . . . 662 10 50 40 29 43 43 0 0 57 682

West. . . . . . . . . . . . . . . . . . . . . 7 -1 2 0 0 1 0 0 0 1 8

North Dakota . . . . . . . . . . . . . . . . 389 -4 26 16 1 6 49 2 1 34 418

Ohio . . . . . . . . . . . . . . . . . . . . . . . 49 -4 5 4 0 0 3 0 1 4 46

Oklahoma . . . . . . . . . . . . . . . . . . 570 54 86 61 71 80 22 0 1 51 630

Pennsylvania . . . . . . . . . . . . . . . . 12 3 1 2 0 0 2 0 0 2 14

Texas . . . . . . . . . . . . . . . . . . . . . . 4,613 64 455 229 520 723 163 2 3 355 4,919

RRC District 1 . . . . . . . . . . . . . 58 -1 5 3 0 2 12 0 1 9 65

RRC District 2 Onshore . . . . . . 56 2 5 2 2 3 7 0 0 7 62

RRC District 3 Onshore . . . . . . 185 -2 19 11 2 5 9 0 1 25 179

RRC District 4 Onshore . . . . . . 27 2 9 3 7 15 1 0 0 4 40

RRC District 5 . . . . . . . . . . . . . 23 3 5 3 7 7 0 0 0 4 24

RRC District 6 . . . . . . . . . . . . . 187 -1 6 12 2 1 4 0 0 15 168

RRC District 7B . . . . . . . . . . . . 73 13 6 4 1 1 1 0 0 9 80

RRC District 7C . . . . . . . . . . . . 206 6 16 10 56 63 36 1 0 17 245

RRC District 8 . . . . . . . . . . . . . 1,552 11 172 96 193 325 70 0 0 110 1,731

RRC District 8A . . . . . . . . . . . . 2,090 20 192 74 239 292 17 0 1 135 2,164

RRC District 9 . . . . . . . . . . . . . 102 12 10 7 8 5 2 1 0 14 103

RRC District 10 . . . . . . . . . . . . 45 3 8 3 3 4 4 0 0 5 53

State Offshore . . . . . . . . . . . . . 9 -4 2 1 0 0 0 0 0 1 5

Utah . . . . . . . . . . . . . . . . . . . . . . . 215 7 65 35 0 0 19 0 0 15 256

West Virginia . . . . . . . . . . . . . . . . 11 4 7 0 0 0 0 0 0 1 21

Wyoming . . . . . . . . . . . . . . . . . . . 628 8 28 17 35 56 81 0 0 45 704

Federal Offshore . . . . . . . . . . . . . 4,691 0 253 305 42 24 68 201 29 436 4,483

Pacific (California) . . . . . . . . . . 547 -1 3 81 0 0 0 0 0 27 441

Gulf of Mexico (Louisiana) . . . . 3,919 1 206 198 25 23 55 199 14 342 3,852

Gulf of Mexico (Texas) . . . . . . . 225 0 44 26 17 1 13 2 15 67 190

Miscellaneousa . . . . . . . . . . . . . . 15 0 1 1 0 0 11 0 0 1 25

U.S. Total . . . . . . . . . . . . . . . . . . 21,371 221 1,544 975 823 1,101 805 205 41 1,733 21,757

Table 6. Crude Oil Proved Reserves, Reserves Changes, and Production, 2005

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 2005

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 12/31/04 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/05
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 23

Figure 17. Changes in Crude Oil Proved Reserves by Area, 2004 to 2005

Figure 16. Crude Oil Proved Reserves by Area, 2005

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

Figure 17 maps the change in crude oil proved reserves

from 2004 to 2005 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 +306

Alaska -156

Gulf of Mexico Federal Offshore -102

California +59

Area Total +107

U.S. Total +386

Texas had a 7 percent increase in crude oil proved

reserves in 2005 and California had a 2 percent

increase. The Gulf of Mexico reported a 2 percent

decrease and Alaska declined 4 percent.

Figure 2 in Chapter 2 shows the components of the

changes in crude oil proved reserves for 2005 and the

preceding 10 years.

Total Discoveries

Total discoveries are those new reserves attributable to

extensions of existing fields, new field discoveries, and

new reservoir discoveries in old fields. They result

from the drilling of exploratory wells.

Total discoveries of crude oil were 1,051 million barrels

in 2005, 34 percent more than those of 2004(782 million

barrels). Only seven areas had total discoveries

exceeding 50 million barrels in 2005:

Percent of U.S.

Area Oil Total Discoveries

Federal Offshore Gulf of Mexico 28

Texas 16

California 14

Montana 8

Wyoming 8

Alaska 5

North Dakota 5

Area Total 84

The United States discovered an average of 1,126

million barrels of new crude oil proved reserves per

year in the prior 10 years. Total discoveries in 2005

were 7 percent lower than that average.

Extensions

Operators reported 805 million barrels of extensions in

2005, 30 percent more than in 2004. The highest volume

of extensions was reported in Texas (163 million

barrels). The second highest volume of extensions in

2005 was in California with 147 million barrels.

Montana was third with 87 million barrels and

Wyoming was fourth with 81 million barrels of

extensions.

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

average of 527 million barrels of extensions per year.

The 2005 extensions were 53 percent more than that

average.

New Field Discoveries

New field discoveries accounted for 205 million barrels

of crude oil reserves additions. Almost all of these

discoveries (201 of 205 million) were in the Gulf of

Mexico Federal Offshore. This was 6 times greater than

the new field discoveries of 2004.

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

average of 419 million barrels of reserves from new

field discoveries. Reserves from new field discoveries

in 2005 were 51 percent less than that average.

New Reservoir Discoveries in Old Fields

Operators reported 41 million barrels of crude oil

reserves from new reservoir discoveries in old fields in

2005. This is 69 percent less than in 2004. Most of the

new reservoir discoveries in old fields (29 of 41 million

barrels) came from the Gulf of Mexico Federal

Offshore.

Energy Information Administration

24 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report
In the prior 10 years, U.S. operators reported an annual

average of 180 million barrels of reserves from new

reservoir discoveries in old fields. Reserves from new

reservoir discoveries in old fields in 2005 were 77

percent less than that average.

Revisions and Adjustments

Operators report thousands of positive and negative

revisions to proved reserves 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 1,544 million barrels of revision increases,

975 million barrels of revision decreases, and 221

million barrels of adjustments in 2005. Combined, there

were 790 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 795 million barrels. The

2005 net revisions and adjustments were 1 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 2005, there were 823 million barrels of sales

transactions between operators and 1,101 million

barrels of acquisitions yielding a net difference of +278

million barrels.

Production

U.S. production of crude oil in 2005 was an estimated

1,733 million barrels. This volume, which does not

include lease condensate, was 5 percent lower than

2004’s production of 1,819 million barrels.

In August and September 2005, hurricanes Katrina and

Rita caused extensive damage on the Gulf Coast

disrupted production operations in the Gulf of Mexico

by damaging or destroying platforms, surface facilities,

and pipelines. Crude oil production from the Gulf of

Mexico Federal Offshore dropped 12 percent from 2004

to 2005. Despite this, the Gulf remained the largest

producing area in the United States with 24 percent of

the National total (409 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 2005 Form EIA-23 National production estimates

(1,733 million barrels of crude oil and 174 million

barrels of lease condensate) are 1 percent higher than

the comparable Petroleum Supply Annual (PSA) 2005

volumes for crude oil and lease condensate production

combined (1,890 million barrels).

Areas of Note: Large Discoveries

and Reserves Additions

The following State and area discussions summarize

notable activities during 2005 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 2005.

Texas

Texas reported the largest increase (306 million barrels

of proved oil reserves) in 2005 and had the largest

volume of extensions in 2005 (163 million barrels). The

majority of these extensions were to fields located in

the Permian Basin.

SACROC and Yates Fields: Kinder Morgan’s

carbon dioxide (CO2) flooding operations

increased oil production at both the SACROC

and the Yates Fields in west Texas, which

together have more than 5 billion barrels of oil

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 25
remaining in place. Kinder Morgan’s CO2

business produced over 56,000 barrels a day at

SACROC and Yates in 2005. {40}

Wyoming

Wyoming reported a net increase of 76 million barrels

of crude oil proved reserves in 2005. Wyoming’s

production also increased by 5 percent from 43 million

barrels in 2004 to 45 million barrels in 2005.

Salt Creek Field: Anadarko Petroleum

Corporation has increased oil production at its

Salt Creek Field using CO2 injection for

enhanced oil recovery. CO2 injection is

predicted to boost Salt Creek's production from

about 5,000 barrels a day now to 30,000 barrels a

day by 2010. {41}

Montana

Montana reported a net increase of 63 million barrels of

crude oil proved reserves in 2005. Montana’s

production also increased by 37 percent from 22

million barrels in 2004 to 30 million barrels in 2005.

Elm Coulee Field: Montana reports that the Elm

Coulee Field, which is completed in the middle

member of the Bakken Formation, has doubled

its oil production for the third year in a row in

2005. Discovered in 2000 and now grown to 529

square miles, the Elm Coulee Field produced 15

million barrels of oil in 2005. It now accounts for

almost 50,000 barrels of oil per day, about half

of Montana’s crude oil production. {42}

Other Gain Areas

Oklahoma: Oklahoma reported a net increase of 60

million barrels of crude oil proved reserves in 2005.

California: California reported a net increase of 59

million barrels of crude oil proved reserves in 2005.

Areas of Note:

Large Reserves Declines

The following areas had large declines in crude oil

proved reserves due to downward revisions or

unreplaced production.

Alaska

Alaskan crude oil proved reserves declined 4 percent

(-156 million barrels) in 2005. No new field discoveries

were reported in Alaska in 2005 and despite notable net

revision increases in Alaska’s proved reserves, the

additions did not offset its oil production. Alaska’s

estimated 2005 production of 312 million barrels

decreased 7 percent from the 2004 level (334 million

barrels).

Pacific Federal Offshore

There was a 19 percent decline (-106 million barrels) in

the crude oil proved reserves of the Pacific Federal

Offshore in 2005. Crude oil reserves in 2005 were

revised significantly downward. Crude oil production

from this area declined 4 percent from its 2004 level.

Gulf of Mexico Federal Offshore

The Gulf of Mexico Federal Offshore crude oil proved

reserves declined 2 percent (-102 million barrels) in

2005. Crude oil production declined 12 percent from

467 million barrels in 2004 to 409 million barrels in 2005,

due to damaged platforms, pipelines, and surface

facilities caused by the hurricanes of 2005.

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:

Arkansas: Proved oil reserves decreased by 22 percent (-11 million barrels).

Florida: Proved oil reserves decreased by 9

percent (-6 million barrels).

Reserves in

Nonproducing Status

Not all proved reserves of crude oil reported in 2005

were producing. Operators reported 5,691 million

barrels of proved reserves in nonproducing status, 11

percent more than reported in 2004 (5,143 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

26 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 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, Illinois, Indiana, Maryland, Missouri, Nebraska, Nevada, Oregon, South Dakota, and Tennessee.

c Includes Federal Offshore Alabama.

Source: Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 2005.

Table 7. Reported Reserves in Nonproducing Status for Crude Oil, 2005 a

(Million Barrels of 42 U.S. Gallons)

Nonproducing Nonproducing Crude Oil Crude Oil

State and Subdivision Reserves State and Subdivision Reserves

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 595

Lower 48 States ............................ 5,096

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

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

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 455

Coastal Region Onshore . . . . . . . . . . . . . . . . . . . 70

Los Angeles Basin Onshore . . . . . . . . . . . . . . . . . 112

San Joaquin Basin Onshore. . . . . . . . . . . . . . . . . 238

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

Florida .................................... 2

Kansas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

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

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193

North. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

South Onshore . . . . . . . . . . . . . . . . . . . . . . . . . . . 148

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

Montana. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 171

East. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 171

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

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

North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

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

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101

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

Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 828

RRC District 1. . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

RRC District 2 Onshore . . . . . . . . . . . . . . . . . . . . 16

RRC District 3 Onshore . . . . . . . . . . . . . . . . . . . . 19

RRC District 4 Onshore . . . . . . . . . . . . . . . . . . . . 17

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

RRC District 6............................ 3

RRC District 7B........................... 3

RRC District 7C . . . . . . . . . . . . . . . . . . . . . . . . . . 31

RRC District 8. . . . . . . . . . . . . . . . . . . . . . . . . . . . 333

RRC District 8A. . . . . . . . . . . . . . . . . . . . . . . . . . . 374

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

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

State Offshore............................ 1

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

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

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

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 249

Federal Offshore ............................ 2,687

Pacific (California). . . . . . . . . . . . . . . . . . . . . . . . . 32

Gulf of Mexico (Louisiana)c

.................. 2,591

Gulf of Mexico (Texas) . . . . . . . . . . . . . . . . . . . . . 64

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

U.S. Total ................................. 5,691

4. Natural Gas Statistics

Dry Natural Gas

Proved Reserves

The United States had 204,385 billion cubic feet of dry

natural gas reserves as of December 31, 2005 (Table 8).

Proved reserves of natural gas increased by 6 percent in

2005, the largest annual increase in natural gas proved

reserves since 1970. All natural gas proved reserves

data shown in this report exclude natural gas held in

underground storage.

Gas reserves additions onshore in the lower 48 States

were large enough to overcome a 10 percent drop in gas

reserves reported for the Gulf of Mexico Federal

Offshore. The majority of natural gas reserves

additions in 2005 resulted from extensions of existing

gas fields rather than new field or reservoir discoveries.

Texas and Colorado led the nation in 2005 natural gas

reserves additions with notable reserves increases in

the Newark East Field (Barnett Shale, TX) and

Ignacio-Blanco Field (tight sands and coalbeds, CO).

Total U.S. reserves additions replaced 164 percent of

2005 dry gas production (Figure 18).

The proved reserves by State are shown on the map in

Figure 19. Seven areas account for 78 percent of the

Nation’s dry natural gas proved reserves:

Percent of

Area U.S. Gas Reserves

Texas 28

Wyoming 12

New Mexico 9

Oklahoma 8

Gulf of Mexico Federal Offshore 8

Colorado 8

Louisiana 5

Area Total 78

Total U.S. natural gas production declined 4 percent in

2005 because, in August and September of 2005,

Hurricanes Katrina and Rita wreaked havoc along the

Gulf Coast. Beyond devastating much of coastal

Alabama, Louisiana, and Mississippi, and flooding

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 29

Figure 18. Replacement of U.S. Dry Natural Gas Production by Reserves Additions, 1995-2005.

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

30 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 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 2005 contained in the Natural Gas Annual 2005, DOE/EIA-0131(05).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 8,407 -2 293 154 96 98 62 22 10 469 8,171

Lower 48 States ............. 184,106 1,889 22,060 19,500 9,034 11,576 20,988 920 1,198 17,989 196,214

Alabama. . . . . . . . . . . . . . . . . . . . 4,120 -27 135 60 419 431 85 0 0 300 3,965

Arkansas . . . . . . . . . . . . . . . . . . . 1,835 8 122 142 31 30 281 4 31 174 1,964

California . . . . . . . . . . . . . . . . . . . 2,634 78 739 129 201 244 129 0 2 268 3,228

Coastal Region Onshore . . . . . 189 72 31 13 0 1 6 0 0 18 268

Los Angeles Basin Onshore. . . 174 1 10 17 1 16 2 0 0 9 176

San Joaquin Basin Onshore . . 2,185 5 685 96 200 227 120 0 2 234 2,694

State Offshore . . . . . . . . . . . . . 86 0 13 3 0 0 1 0 0 7 90

Colorado . . . . . . . . . . . . . . . . . . . 14,743 57 2,018 1,478 1,238 1,767 1,795 32 4 1,104 16,596

Florida . . . . . . . . . . . . . . . . . . . . . 78 1 0 0 0 0 0 0 0 2 77

Kansas. . . . . . . . . . . . . . . . . . . . . 4,652 88 207 381 44 60 108 0 4 380 4,314

Kentucky . . . . . . . . . . . . . . . . . . . 1,880 65 251 77 1 0 101 17 0 85 2,151

Louisiana . . . . . . . . . . . . . . . . . . . 9,588 130 876 849 224 378 1,560 6 188 1,206 10,447

North . . . . . . . . . . . . . . . . . . . . 5,770 69 337 252 71 141 1,188 0 11 498 6,695

South Onshore. . . . . . . . . . . . . 3,436 32 485 554 121 208 343 6 139 640 3,334

State Offshore . . . . . . . . . . . . . 382 29 54 43 32 29 29 0 38 68 418

Michigan . . . . . . . . . . . . . . . . . . . 3,091 1 141 163 104 89 55 11 0 211 2,910

Mississippi . . . . . . . . . . . . . . . . . . 691 5 57 27 17 54 75 0 3 86 755

Montana. . . . . . . . . . . . . . . . . . . . 995 3 63 122 6 9 130 0 14 100 986

New Mexico . . . . . . . . . . . . . . . . . 18,512 44 2,071 2,269 963 1,238 1,048 10 3 1,493 18,201

East . . . . . . . . . . . . . . . . . . . . . 3,621 37 457 412 514 649 468 5 2 522 3,791

West. . . . . . . . . . . . . . . . . . . . . 14,891 7 1,614 1,857 449 589 580 5 1 971 14,410

New York . . . . . . . . . . . . . . . . . . . 324 18 51 20 1 2 7 20 0 52 349

North Dakota . . . . . . . . . . . . . . . . 417 -10 49 27 1 22 49 5 2 53 453

Ohio . . . . . . . . . . . . . . . . . . . . . . . 974 -78 166 111 54 7 58 5 7 76 898

Oklahoma . . . . . . . . . . . . . . . . . . 16,238 297 3,064 2,945 539 728 1,818 1 48 1,587 17,123

Pennsylvania . . . . . . . . . . . . . . . . 2,361 186 234 154 78 139 275 0 0 181 2,782

Texas . . . . . . . . . . . . . . . . . . . . . . 49,955 561 6,008 5,637 4,098 5,024 9,640 138 340 5,424 56,507

RRC District 1 . . . . . . . . . . . . . 1,184 25 70 130 62 76 115 0 11 128 1,161

RRC District 2 Onshore . . . . . . 1,844 156 188 260 207 255 338 26 38 305 2,073

RRC District 3 Onshore . . . . . . 3,185 62 478 532 92 110 431 63 45 558 3,192

RRC District 4 Onshore . . . . . . 8,699 55 1,119 1,120 839 976 1,019 21 63 1,232 8,761

RRC District 5 . . . . . . . . . . . . . 6,523 93 1,216 398 347 348 2,609 0 163 650 9,557

RRC District 6 . . . . . . . . . . . . . 7,638 111 548 538 478 1,014 1,418 8 7 752 8,976

RRC District 7B . . . . . . . . . . . . 310 -33 142 50 23 121 400 0 0 65 802

RRC District 7C . . . . . . . . . . . . 4,668 79 404 487 276 283 793 8 0 349 5,123

RRC District 8 . . . . . . . . . . . . . 5,301 25 464 692 430 664 1,114 11 0 464 5,993

RRC District 8A . . . . . . . . . . . . 1,188 25 187 77 116 232 27 1 1 102 1,366

RRC District 9 . . . . . . . . . . . . . 4,221 -53 445 702 305 387 696 0 0 361 4,328

RRC District 10 . . . . . . . . . . . . 4,873 -2 712 616 893 554 680 0 0 398 4,910

State Offshore . . . . . . . . . . . . . 321 18 35 35 30 4 0 0 12 60 265

Utah . . . . . . . . . . . . . . . . . . . . . . . 3,866 65 186 112 6 0 596 4 4 308 4,295

Virginia. . . . . . . . . . . . . . . . . . . . . 1,742 18 163 3 1 3 166 0 0 70 2,018

West Virginia . . . . . . . . . . . . . . . . 3,397 214 646 76 6 132 371 11 0 230 4,459

Wyoming . . . . . . . . . . . . . . . . . . . 22,632 115 2,160 1,822 139 470 1,987 11 2 1,642 23,774

Federal Offshorea . . . . . . . . . . . . 19,271 26 2,645 2,878 863 749 642 632 546 2,939 17,831

Pacific (California) . . . . . . . . . . 459 -1 418 19 0 0 0 0 0 33 824

Gulf of Mexico (Louisiana)a . . . 14,685 21 1,408 1,903 716 628 546 618 375 1,997 13,665

Gulf of Mexico (Texas) . . . . . . . 4,127 6 819 956 147 121 96 14 171 909 3,342

Miscellaneousb . . . . . . . . . . . . . . 110 24 8 18 0 0 12 13 0 18 131

U.S. Total . . . . . . . . . . . . . . . . . . 192,513 1,887 22,353 19,654 9,130 11,674 21,050 942 1,208 18,458 204,385

Table 8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 2005

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

Changes in Reserves During 2005

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 12/31/04 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/05
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 31

Figure 20. Changes in Dry Natural Gas Proved Reserves by Area, 2004 to 2005

Figure 19. Dry Natural Gas Proved Reserves by Area, 2005

Source: Energy Information Administration, Office of Oil and Gas.
New Orleans, these storms destroyed 113 offshore

platforms and seriously damaged offshore pipelines

and coastal oil and natural gas processing facilities,

impacting the Nation's oil and gas production. At its

lowest point, the natural gas production rate in the Gulf

of Mexico was cut by 80 percent. Gulf of Mexico

production slowly returned and reached roughly 80

percent of 2005’s pre-hurricane production rate (10.2

Bcf/day gross withdrawal in June 2005) in September

2006.

Discussion of Reserves Changes

Figure 20 maps the change in dry gas proved reserves

from 2004 to 2005 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 +6,552

Wyoming +1,142

New Mexico -311

Oklahoma +885

Gulf of Mexico Federal Offshore -1,805

Colorado +1,853

Area Total +8,316

U.S. Total +11,872

Figure 4 in Chapter 2 shows the components of change

in dry natural gas proved reserves for 2005 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

23,200 billion cubic feet in 2005, a 15 percent increase

from the level reported in 2004. Seven areas reported

total discoveries of dry natural gas exceeding 1 trillion

cubic feet in 2005:

2005 Total Discoveries

Area (Billion cubic feet)

Texas 10,118

Wyoming 2,000

Oklahoma 1,867

Colorado 1,831

Gulf of Mexico Federal Offshore 1,820

Louisiana 1,754

New Mexico 1,061

U.S. Total 23,200

Extensions

The largest component of total discoveries in 2005 was

extensions of existing gas fields. Extensions were

21,050 billion cubic feet, 16 percent more than 2004 and

74 percent more than the prior 10-year average (12,101

billion cubic feet). Areas with the largest extensions

and their percentage of total extensions were:

Percent of

Area 2005 Extensions

Texas 46

Wyoming 9

Oklahoma 9

Colorado 9

Louisiana 7

New Mexico 5

Gulf of Mexico 3

New Field Discoveries

New field discoveries were 942 billion cubic feet in

2005—24 percent more than in 2004. The areas with the

largest new field discoveries were the Gulf of Mexico

Federal Offshore (632 billion cubic feet; 67 percent of

the total), Texas (138 billion cubic feet; 15 percent),

Colorado (32 billion cubic feet; 3 percent) and Alaska

(22 billion cubic feet; 2 percent). In the prior 10 years,

U.S. operators had reported an annual average of 1,731

billion cubic feet of reserves from new field discoveries.

Reserves from new field discoveries in 2005 were 46

percent less than the prior 10 year average.

Energy Information Administration

32 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 33

aIncludes Federal offshore Alabama. bIncludes 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 2005 contained in the

Natural Gas Annual 2005, DOE/EIA-0131(05).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 8,473 -1 295 155 96 98 62 22 10 471 8,237

Lower 48 States ............. 192,727 1,694 23,067 20,492 9,536 12,208 22,007 951 1,233 18,788 205,071

Alabama. . . . . . . . . . . . . . . . . . . . 4,159 -25 137 61 427 439 87 0 0 303 4,006

Arkansas . . . . . . . . . . . . . . . . . . . 1,837 8 122 142 31 30 282 4 31 174 1,967

California . . . . . . . . . . . . . . . . . . . 2,773 69 777 136 212 256 135 0 3 281 3,384

Coastal Region Onshore . . . . . 196 72 33 13 0 1 6 0 0 18 277

Los Angeles Basin Onshore. . . 184 1 11 18 1 16 2 0 0 9 186

San Joaquin Basin Onshore . . 2,306 -3 720 102 211 239 126 0 3 247 2,831

State Offshore . . . . . . . . . . . . . 87 -1 13 3 0 0 1 0 0 7 90

Colorado . . . . . . . . . . . . . . . . . . . 15,249 21 2,082 1,525 1,278 1,824 1,851 33 4 1,139 17,122

Florida . . . . . . . . . . . . . . . . . . . . . 88 2 0 0 0 0 0 0 0 3 87

Kansas. . . . . . . . . . . . . . . . . . . . . 5,003 50 220 406 47 64 115 0 4 405 4,598

Kentucky . . . . . . . . . . . . . . . . . . . 1,982 43 262 81 1 0 106 18 0 89 2,240

Louisiana . . . . . . . . . . . . . . . . . . . 9,792 156 903 878 231 389 1,589 6 195 1,242 10,679

North . . . . . . . . . . . . . . . . . . . . 5,841 60 341 254 71 142 1,201 0 11 503 6,768

South Onshore. . . . . . . . . . . . . 3,557 63 506 579 127 217 358 6 145 668 3,478

State Offshore . . . . . . . . . . . . . 394 33 56 45 33 30 30 0 39 71 433

Michigan . . . . . . . . . . . . . . . . . . . 3,154 -8 144 166 106 91 56 11 0 215 2,961

Mississippi . . . . . . . . . . . . . . . . . . 692 7 57 27 17 54 75 0 3 86 758

Montana. . . . . . . . . . . . . . . . . . . . 1,002 8 64 123 6 9 131 0 14 101 998

New Mexico . . . . . . . . . . . . . . . . . 19,687 28 2,201 2,409 1,035 1,330 1,123 10 3 1,594 19,344

East . . . . . . . . . . . . . . . . . . . . . 3,965 23 498 449 561 708 510 5 2 569 4,132

West. . . . . . . . . . . . . . . . . . . . . 15,722 5 1,703 1,960 474 622 613 5 1 1,025 15,212

New York . . . . . . . . . . . . . . . . . . . 324 17 51 20 1 2 7 20 0 51 349

North Dakota . . . . . . . . . . . . . . . . 465 -8 55 31 1 24 56 5 2 59 508

Ohio . . . . . . . . . . . . . . . . . . . . . . . 975 -79 166 111 54 7 58 5 7 76 898

Oklahoma . . . . . . . . . . . . . . . . . . 17,200 324 3,247 3,121 572 772 1,926 1 51 1,682 18,146

Pennsylvania . . . . . . . . . . . . . . . . 2,371 187 234 155 78 139 276 0 0 181 2,793

Texas . . . . . . . . . . . . . . . . . . . . . . 53,275 602 6,388 6,055 4,396 5,382 10,244 149 350 5,761 60,178

RRC District 1 . . . . . . . . . . . . . 1,229 27 73 136 65 79 119 0 12 133 1,205

RRC District 2 Onshore . . . . . . 1,934 164 197 273 217 267 355 28 40 320 2,175

RRC District 3 Onshore . . . . . . 3,400 67 510 568 98 118 459 67 47 596 3,406

RRC District 4 Onshore . . . . . . 9,067 29 1,163 1,164 872 1,014 1,059 22 66 1,280 9,104

RRC District 5 . . . . . . . . . . . . . 6,583 71 1,223 400 350 350 2,624 0 164 654 9,611

RRC District 6 . . . . . . . . . . . . . 7,966 99 570 560 497 1,056 1,476 9 7 783 9,343

RRC District 7B . . . . . . . . . . . . 364 -42 164 59 26 141 465 0 1 76 932

RRC District 7C . . . . . . . . . . . . 5,190 93 450 543 307 314 883 10 0 388 5,702

RRC District 8 . . . . . . . . . . . . . 6,002 44 527 786 488 753 1,263 12 0 527 6,800

RRC District 8A . . . . . . . . . . . . 1,281 24 202 82 125 250 29 1 1 110 1,471

RRC District 9 . . . . . . . . . . . . . 4,555 5 487 768 334 424 760 0 0 395 4,734

RRC District 10 . . . . . . . . . . . . 5,383 4 787 681 988 612 752 0 0 439 5,430

State Offshore . . . . . . . . . . . . . 321 17 35 35 29 4 0 0 12 60 265

Utah . . . . . . . . . . . . . . . . . . . . . . . 3,951 38 189 114 6 0 605 4 5 313 4,359

Virginia. . . . . . . . . . . . . . . . . . . . . 1,742 18 163 3 1 3 166 0 0 70 2,018

West Virginia . . . . . . . . . . . . . . . . 3,509 192 662 77 6 135 381 11 0 235 4,572

Wyoming . . . . . . . . . . . . . . . . . . . 23,640 15 2,246 1,895 145 489 2,066 11 3 1,708 24,722

Federal Offshorea . . . . . . . . . . . . 19,747 5 2,689 2,938 885 769 660 649 558 3,002 18,252

Pacific (California) . . . . . . . . . . 459 1 418 19 0 0 0 0 0 34 825

Gulf of Mexico (Louisiana)a . . . 15,144 1 1,450 1,960 738 647 563 636 386 2,056 14,073

Gulf of Mexico (Texas) . . . . . . . 4,144 3 821 959 147 122 97 13 172 912 3,354

Miscellaneousb . . . . . . . . . . . . . . 110 24 8 18 0 0 12 14 0 18 132

U.S. Total . . . . . . . . . . . . . . . . . . 201,200 1,693 23,362 20,647 9,632 12,306 22,069 973 1,243 19,259 213,308

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

2005 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 2005

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 12/31/04 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/05
Energy Information Administration

34 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 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 2005 contained in the

Natural Gas Annual 2005, DOE/EIA-0131(05).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 2,004 -1 116 129 74 79 61 22 10 213 1,875

Lower 48 States ............. 171,547 1,568 19,965 18,484 7,903 10,156 20,976 832 1,154 16,614 183,197

Alabama. . . . . . . . . . . . . . . . . . . . 4,127 -21 133 60 427 439 84 0 0 298 3,977

Arkansas . . . . . . . . . . . . . . . . . . . 1,797 11 121 141 15 3 281 4 31 171 1,921

California . . . . . . . . . . . . . . . . . . . 767 -4 66 60 211 239 84 0 3 85 799

Coastal Region Onshore . . . . . 8 -1 1 0 0 0 0 0 0 0 8

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

San Joaquin Basin Onshore . . 757 -3 65 60 211 239 84 0 3 84 790

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

Colorado . . . . . . . . . . . . . . . . . . . 13,956 13 2,065 1,499 587 1,123 1,736 33 4 1,048 15,796

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

Kansas. . . . . . . . . . . . . . . . . . . . . 4,923 50 208 401 47 61 113 0 4 396 4,515

Kentucky . . . . . . . . . . . . . . . . . . . 1,963 43 246 73 1 0 102 18 0 88 2,210

Louisiana . . . . . . . . . . . . . . . . . . . 9,235 100 787 799 187 355 1,570 6 191 1,167 10,091

North . . . . . . . . . . . . . . . . . . . . 5,734 49 333 232 70 141 1,197 0 11 493 6,670

South Onshore. . . . . . . . . . . . . 3,168 21 405 526 90 192 345 6 141 611 3,051

State Offshore . . . . . . . . . . . . . 333 30 49 41 27 22 28 0 39 63 370

Michigan . . . . . . . . . . . . . . . . . . . 2,961 1 136 142 106 91 54 11 0 198 2,808

Mississippi . . . . . . . . . . . . . . . . . . 672 6 53 25 16 54 74 0 3 83 738

Montana. . . . . . . . . . . . . . . . . . . . 872 8 44 109 5 7 92 0 14 86 837

New Mexico . . . . . . . . . . . . . . . . . 18,109 48 1,975 2,287 906 1,171 943 10 3 1,383 17,683

East . . . . . . . . . . . . . . . . . . . . . 2,477 42 288 329 436 554 333 5 2 367 2,569

West. . . . . . . . . . . . . . . . . . . . . 15,632 6 1,687 1,958 470 617 610 5 1 1,016 15,114

New York . . . . . . . . . . . . . . . . . . . 324 14 51 20 1 2 7 20 0 51 346

North Dakota . . . . . . . . . . . . . . . . 145 7 6 6 0 20 10 0 1 18 165

Ohio . . . . . . . . . . . . . . . . . . . . . . . 767 -49 143 102 54 7 58 5 0 61 714

Oklahoma . . . . . . . . . . . . . . . . . . 16,301 364 3,070 2,937 514 694 1,878 1 50 1,570 17,337

Pennsylvania . . . . . . . . . . . . . . . . 2,246 180 228 143 78 139 259 0 0 172 2,659

Texas . . . . . . . . . . . . . . . . . . . . . . 46,728 517 5,612 5,549 3,821 4,525 9,817 147 345 5,146 53,175

RRC District 1 . . . . . . . . . . . . . 1,184 27 67 134 64 78 105 0 11 126 1,148

RRC District 2 Onshore . . . . . . 1,858 165 158 249 214 260 319 28 39 298 2,066

RRC District 3 Onshore . . . . . . 2,959 63 453 530 93 109 412 66 45 523 2,961

RRC District 4 Onshore . . . . . . 8,902 30 1,136 1,145 850 1,003 1,054 22 66 1,262 8,956

RRC District 5 . . . . . . . . . . . . . 6,525 70 1,218 394 345 347 2,623 0 164 648 9,560

RRC District 6 . . . . . . . . . . . . . 7,564 86 543 511 497 1,052 1,471 9 7 725 8,999

RRC District 7B . . . . . . . . . . . . 288 -42 158 52 25 138 457 0 1 64 859

RRC District 7C . . . . . . . . . . . . 4,196 83 362 458 117 136 772 9 0 318 4,665

RRC District 8 . . . . . . . . . . . . . 3,266 -6 253 568 321 381 1,134 12 0 322 3,829

RRC District 8A . . . . . . . . . . . . 95 14 13 52 3 2 27 1 0 12 85

RRC District 9 . . . . . . . . . . . . . 4,445 -8 474 759 324 405 751 0 0 376 4,608

RRC District 10 . . . . . . . . . . . . 5,134 17 744 664 942 610 692 0 0 414 5,177

State Offshore . . . . . . . . . . . . . 312 18 33 33 26 4 0 0 12 58 262

Utah . . . . . . . . . . . . . . . . . . . . . . . 3,661 33 134 80 6 0 590 0 5 286 4,051

Virginia. . . . . . . . . . . . . . . . . . . . . 1,742 18 163 3 1 3 166 0 0 70 2,018

West Virginia . . . . . . . . . . . . . . . . 3,489 192 661 75 6 135 380 11 0 234 4,553

Wyoming . . . . . . . . . . . . . . . . . . . 23,278 16 2,200 1,864 127 407 2,062 11 3 1,648 24,338

Federal Offshorea . . . . . . . . . . . . 13,386 4 1,855 2,095 787 681 614 541 497 2,348 12,348

Pacific (California) . . . . . . . . . . 47 1 2 0 0 0 0 0 0 1 49

Gulf of Mexico (Louisiana)a . . . 10,081 1 1,149 1,443 657 566 523 532 347 1,607 9,492

Gulf of Mexico (Texas) . . . . . . . 3,258 2 704 652 130 115 91 9 150 740 2,807

Miscellaneousb . . . . . . . . . . . . . . 98 17 8 14 0 0 2 14 0 7 118

U.S. Total . . . . . . . . . . . . . . . . . . 173,551 1,567 20,081 18,613 7,977 10,235 21,037 854 1,164 16,827 185,072

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

Wet After Lease Separation, 2005 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 2005

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 12/31/04 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/05
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 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 2005 contained in the

Natural Gas Annual 2005, DOE/EIA-0131(05).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 6,469 0 179 26 22 19 1 0 0 258 6,362

Lower 48 States . . . . . . . . . . . . . 21,180 126 3,102 2,008 1,633 2,052 1,031 119 79 2,174 21,874

Alabama. . . . . . . . . . . . . . . . . . . . 32 -4 4 1 0 0 3 0 0 5 29

Arkansas . . . . . . . . . . . . . . . . . . . 40 -3 1 1 16 27 1 0 0 3 46

California . . . . . . . . . . . . . . . . . . . 2,006 73 711 76 1 17 51 0 0 196 2,585

Coastal Region Onshore . . . . . 188 73 32 13 0 1 6 0 0 18 269

Los Angeles Basin Onshore. . . 184 1 11 18 1 16 2 0 0 9 186

San Joaquin Basin Onshore . . 1,549 0 655 42 0 0 42 0 0 163 2,041

State Offshore . . . . . . . . . . . . . 85 -1 13 3 0 0 1 0 0 6 89

Colorado . . . . . . . . . . . . . . . . . . . 1,293 8 17 26 691 701 115 0 0 91 1,326

Florida . . . . . . . . . . . . . . . . . . . . . 88 2 0 0 0 0 0 0 0 3 87

Kansas. . . . . . . . . . . . . . . . . . . . . 80 0 12 5 0 3 2 0 0 9 83

Kentucky . . . . . . . . . . . . . . . . . . . 19 0 16 8 0 0 4 0 0 1 30

Louisiana . . . . . . . . . . . . . . . . . . . 557 56 116 79 44 34 19 0 4 75 588

North . . . . . . . . . . . . . . . . . . . . 107 11 8 22 1 1 4 0 0 10 98

South Onshore. . . . . . . . . . . . . 389 42 101 53 37 25 13 0 4 57 427

State Offshore . . . . . . . . . . . . . 61 3 7 4 6 8 2 0 0 8 63

Michigan . . . . . . . . . . . . . . . . . . . 193 -9 8 24 0 0 2 0 0 17 153

Mississippi . . . . . . . . . . . . . . . . . . 20 1 4 2 1 0 1 0 0 3 20

Montana. . . . . . . . . . . . . . . . . . . . 130 0 20 14 1 2 39 0 0 15 161

New Mexico . . . . . . . . . . . . . . . . . 1,578 -20 226 122 129 159 180 0 0 211 1,661

East . . . . . . . . . . . . . . . . . . . . . 1,488 -19 210 120 125 154 177 0 0 202 1,563

West. . . . . . . . . . . . . . . . . . . . . 90 -1 16 2 4 5 3 0 0 9 98

New York . . . . . . . . . . . . . . . . . . . 0 3 0 0 0 0 0 0 0 0 3

North Dakota . . . . . . . . . . . . . . . . 320 -15 49 25 1 4 46 5 1 41 343

Ohio . . . . . . . . . . . . . . . . . . . . . . . 208 -30 23 9 0 0 0 0 7 15 184

Oklahoma . . . . . . . . . . . . . . . . . . 899 -40 177 184 58 78 48 0 1 112 809

Pennsylvania . . . . . . . . . . . . . . . . 125 7 6 12 0 0 17 0 0 9 134

Texas . . . . . . . . . . . . . . . . . . . . . . 6,547 85 776 506 575 857 427 2 5 615 7,003

RRC District 1 . . . . . . . . . . . . . 45 0 6 2 1 1 14 0 1 7 57

RRC District 2 Onshore . . . . . . 76 -1 39 24 3 7 36 0 1 22 109

RRC District 3 Onshore . . . . . . 441 4 57 38 5 9 47 1 2 73 445

RRC District 4 Onshore . . . . . . 165 -1 27 19 22 11 5 0 0 18 148

RRC District 5 . . . . . . . . . . . . . 58 1 5 6 5 3 1 0 0 6 51

RRC District 6 . . . . . . . . . . . . . 402 13 27 49 0 4 5 0 0 58 344

RRC District 7B . . . . . . . . . . . . 76 0 6 7 1 3 8 0 0 12 73

RRC District 7C . . . . . . . . . . . . 994 10 88 85 190 178 111 1 0 70 1,037

RRC District 8 . . . . . . . . . . . . . 2,736 50 274 218 167 372 129 0 0 205 2,971

RRC District 8A . . . . . . . . . . . . 1,186 10 189 30 122 248 2 0 1 98 1,386

RRC District 9 . . . . . . . . . . . . . 110 13 13 9 10 19 9 0 0 19 126

RRC District 10 . . . . . . . . . . . . 249 -13 43 17 46 2 60 0 0 25 253

State Offshore . . . . . . . . . . . . . 9 -1 2 2 3 0 0 0 0 2 3

Utah . . . . . . . . . . . . . . . . . . . . . . . 290 5 55 34 0 0 15 4 0 27 308

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

West Virginia . . . . . . . . . . . . . . . . 20 0 1 2 0 0 1 0 0 1 19

Wyoming . . . . . . . . . . . . . . . . . . . 362 -1 46 31 18 82 4 0 0 60 384

Federal Offshorea . . . . . . . . . . . . 6,361 1 834 843 98 88 46 108 61 654 5,904

Pacific (California) . . . . . . . . . . 412 0 416 19 0 0 0 0 0 33 776

Gulf of Mexico (Louisiana)a . . . 5,063 0 301 517 81 81 40 104 39 449 4,581

Gulf of Mexico (Texas) . . . . . . . 886 1 117 307 17 7 6 4 22 172 547

Miscellaneousb . . . . . . . . . . . . . . 12 7 0 4 0 0 10 0 0 11 14

U.S. Total . . . . . . . . . . . . . . . . . . 27,649 126 3,281 2,034 1,655 2,071 1,032 119 79 2,432 28,236

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

Wet After Lease Separation, 2005 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 2005

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 12/31/04 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/05
New Reservoir Discoveries in Old Fields

New reservoir discoveries in old fields were 1,208

billion cubic feet, less than 1 percent more than 2004

(1,206 billion cubic feet). The areas with the largest new

reservoir discoveries in old fields and their percentage

of the total were Gulf of Mexico Federal Offshore (546

billion cubic feet; 45 percent of the total), Texas (340

billion cubic feet; 28 percent of the total), and Louisiana

(188 billion cubic feet; 16 percent of the total).

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

annual average of 2,198 billion cubic feet of reserves

from new reservoirs discovered in old fields. Reserves

from new reservoirs discovered in old fields in 2005

were 45 percent less than that average.

Revisions and Adjustments

There were 22,353 billion cubic feet of revision

increases, 19,654 billion cubic feet of revision decreases,

and 1,887 billion cubic feet of adjustments in 2005.

Combined, there were 4,586 billion cubic feet of net

revisions and adjustments in 2005, excluding reserves

additions from net sales and acquisitions. This is 7

percent less than the average volume of net revisions

and adjustments of the prior 10 years (4,908 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 property 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 transfer of

operations of an existing gas field or property.

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 2005, there were 9,130 billion cubic feet of sales

transactions between operators, and 11,674 billion

cubic feet of acquisitions. The net difference of 2,544

billion cubic feet was added to the National total of dry

natural gas reserves in 2005.

Production

The estimated 2005 U.S. dry natural gas production

was 18,458 billion cubic feet (Table 8), a decrease of 4

percent from 2004 (19,168 billion cubic feet). Areas with

the largest production and their percentage of total

production were:

Percent of 2005 U.S.

Area Dry Gas Production

Texas 29

Gulf of Mexico Federal Offshore 16

Wyoming 9

Oklahoma 9

New Mexico 8

Louisiana 7

Colorado 6

Wet Natural Gas

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

31, 2004 were 213,308 billion cubic feet, a 6 percent

increase over the volume reported in 2004 (Table 9). At

year-end 2005, proved wet natural gas reserves for the

lower 48 States had increased by 6 percent compared to

2004, while those of Alaska had decreased by 3 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

7 percent (11,521 billion cubic feet) in 2005 to 185,072

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

wet natural gas proved reserves increased 7 percent to

a level of 183,197 billion cubic feet, while Alaska had a 6

percent decline to a level of 1,875 billion cubic feet.

Seven areas accounted for 82 percent of U.S. NA

natural gas proved reserves in 2005:

Energy Information Administration

36 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report
Percent of 2005 U.S.

Area NA Gas Reserves

Texas 29

Wyoming 13

New Mexico 10

Oklahoma 9

Colorado 9

Gulf of Mexico Federal Offshore 7

Louisiana 5

Area Total 82

Total Discoveries

NA wet natural gas total discoveries of 23,055 billion

cubic feet in 2005 were 15 percent more than the 2004

total of 20,064 billion cubic feet. Areas with the most

total discoveries of nonassociated natural gas in 2005

were Texas (10,309 billion cubic feet), Wyoming (2,076

billion cubic feet), Oklahoma (1,929 billion cubic feet),

Colorado (1,773 billion cubic feet), Louisiana (1,767

billion cubic feet), and the Gulf of Mexico Federal

Offshore (1,652 billion cubic feet).

Production

U.S. production of NA wet natural gas decreased 3

percent from an estimated 17,275 billion cubic feet in

2004 to 16,827 billion cubic feet in 2005. The leading

producing areas were: Texas (31 percent), the Gulf of

Mexico Federal Offshore (14 percent), Wyoming (10

percent), Oklahoma (9 percent), New Mexico (8

percent), Louisiana (7 percent), and Colorado (6

percent).

Associated-Dissolved Natural Gas

Proved Reserves

Proved reserves of associated-dissolved (AD) natural

gas, wet after lease separation, in the United States

increased 2 percent to 28,236 billion cubic feet in 2005

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

the lower 48 States increased by 3 percent to 21,874

billion cubic feet, and in Alaska decreased 2 percent to

6,362 billion cubic feet. The areas of the country with

the largest AD wet natural gas reserves and their

percentage of the total were:

Percent of 2005 U.S.

Area AD Gas Reserves

Texas 25

Alaska 23

Gulf of Mexico Federal Offshore 18

California 9

New Mexico 6

Area Total 81

These areas logically correspond to the areas of the

country with the largest volumes of crude oil reserves.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 37

Figure 21. Coalbed Natural Gas Proved Reserves, 1989-2005

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

U.S. production of AD wet natural gas decreased 11

percent from an estimated 2,742 billion cubic feet in

2004 to 2,432 billion cubic feet in 2005 (Table 11).

Production of AD wet natural gas in the lower 48 States

decreased from 2,467 billion cubic feet in 2004 to 2,174

billion cubic feet in 2005, a decline of 12 percent. The

areas of the country with the largest AD wet natural gas

production and their percentage of the total were:

Percent of 2005 U.S.

Area AD Gas Production

Gulf of Mexico Federal Offshore 26

Texas 25

Alaska 11

New Mexico 9

California 8

Area Total 79

Again, these areas logically correspond to the areas of

the country with the largest volumes of crude oil

production.

Energy Information Administration

38 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table 12. Coalbed Natural Gas Proved Reserves and Production, 1989–2005

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

New Eastern Western United

Year Alabama Colorado Mexico Utah Wyoming Statesa Statesb Othersc States

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 2000-2004.

NA = Not applicable.

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

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

2005 1,773 6,772 5,249 902 2,446 1,822 928 -- 19,892

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

2005 113 515 514 75 336 90 89 -- 1,732
Coalbed Natural Gas

Proved Reserves

Proved reserves of coalbed natural gas increased to

19,892 billion cubic feet in 2005, 8 percent higher than

the 2004 level (18,390 billion cubic feet) (Figure 21).

Coalbed natural gas accounted for 10 percent of all 2005

dry natural gas reserves (Table 12). Five States

(Colorado, New Mexico, Wyoming, Alabama and

Utah) currently have the vast majority (86 percent) of

U.S. coalbed natural gas proved reserves. Two of them

(Alabama and Utah) reported declines in their proved

coalbed natural gas reserves in 2005.

Production

U.S. coalbed natural gas production increased less than

1 percent in 2005 to 1,732 billion cubic feet. It accounted

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

Areas of Note:

Large Discoveries and

Reserves Additions

The following State or area discussions summarize

notable activities during the year concerning expected

new field reserves, development plans, and possible

production rates as 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.

Texas

Texas had a 13 percent increase in dry natural gas

proved reserves in 2005 (6,552 billion cubic feet), the

largest of any State. Production also increased 2

percent. This resulted primarily from extensions in the

Newark East Field in north central Texas and natural

gas fields in the Permian Basin of west Texas.

Newark East Field: On July 26, 2005 Devon

Energy Corporation announced that it had

reached a significant milestone in the life of the

Barnett Shale natural gas field in north Texas.

The company reported that cumulative gross

production from Devon's operated wells reached

one trillion cubic feet (Tcf) of natural gas in

June. Devon operates 1,830 wells in the Barnett

Shale.

The company acquired its initial interest in the

Barnett Shale by purchasing Mitchell Energy &

Development Corp. in January 2002. Devon has

drilled nearly 1,000 additional wells since the

acquisition and has increased daily production

by over 200 million cubic feet (Mmcf) per day.

{42}

Colorado

Colorado’s dry natural gas reserves increased by 13

percent (1,853 billion cubic feet) in 2005. This was the

result of revision increases on the Colorado side of the

largest natural gas area in the United States, the San

Juan Basin Gas Area of Colorado and New Mexico.

Wyoming

Wyoming’s dry natural gas reserves increased by 5

percent (1,142 billion cubic feet) in 2005. This was the

result of development in deep, tight natural gas plays.

Pinedale Field: On August 10, 2005, Ultra

Petroleum Corporation (Ultra) confirmed that

the Wyoming Oil & Gas Conservation

Commission voted to approve 10-acre density

drilling of Lance Pool (Lance and Mesaverde

Formation) wells on Ultra’s Pinedale Anticline

acreage in the Stewart Point and Mesa areas of

the Pinedale Anticline. {43}

Jonah Field: EnCana Corporation increased its

estimate of the gas in place in the Jonah Field

using specialized core analysis, with original gas

in place now estimated at 350 billion to 400

billion cubic feet per square mile. In 2005,

EnCana also initiated 24-hour-a-day fracturing

operations. {44}

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 10 percent (-1,805 billion

cubic feet) in 2005. Production also decreased by 25

percent from 3,874 billion cubic feet in 2004 to 2,906

billion cubic feet in 2005.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 39
The large proved natural gas reserves drop

experienced in the Gulf of Mexico was primarily due to

storm damage in August and September of 2005 from

Hurricanes Katrina and Rita. These storms destroyed

113 offshore platforms and seriously damaged offshore

pipelines and coastal oil and natural gas processing

facilities, impacting the Nation's oil and gas

production.

For more complete assessment of the 2005 hurricane

damage effects, readers should consult the joint report

prepared by the Energy Information Administration,

Office of Oil and Gas and the U.S. Department of

Energy, Office of Fossil Energy entitled “Impact of the

2005 Hurricanes on the Natural Gas Industry in the Gulf

of Mexico Region.”which was published in July 2006.

Kansas

Kansas’ proved dry natural gas reserves decreased by 7

percent (-338 billion cubic feet) in 2005. Production in

Kansas increased 1 percent (+4 billion cubic feet) in

2005.

New Mexico

New Mexico’s proved dry natural gas reserves

decreased by 2 percent (-311 billion cubic feet) in 2005.

Production in New Mexico decreased 2 percent (-34

billion cubic feet) in 2005.

Reserves in

Nonproducing Status

Nonproducing proved natural gas reserves (wet after

lease separation) of 59,658 billion cubic feet were

reported in 2005, 16 percent more than the 51,412

billion cubic feet reported in 2004 (Appendix D, Table

D10). About 31 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 2005 Annual Report
5. Natural Gas Liquids Statistics

Natural Gas Liquids

Proved Reserves

U.S. natural gas liquids proved reserves increased 3

percent to 8,165 million barrels in 2005 (Table 13).

Reserve additions replaced 130 percent of 2005 natural

gas liquids production.

The reserves of seven areas account for 87 percent of

the Nation’s natural gas liquids proved reserves.

Percent of

Area U.S. NGL Reserves

Texas 38

Utah and Wyoming 11

Oklahoma 10

New Mexico 10

Gulf of Mexico Federal Offshore 8

Colorado 6

Alaska 4

Area Total 87

The volumes of natural gas liquids proved reserves and

production shown in Table 13 are the sum of the

natural gas plant liquid volumes listed in Table 14 and

the lease condensate volumes listed in Table 15.

Total Discoveries

Total discoveries of natural gas liquids reserves were

937 million barrels in 2005, an increase of 15 percent

from 2004 (814 million barrels). Areas with the largest

total discoveries were:

Percent of U.S.

Area NGL Total Discoveries

Texas 54

Oklahoma 10

Utah and Wyoming 8

Gulf of Mexico Federal Offshore 8

New Mexico 6

Louisiana 6

Colorado 6

Extensions

Extensions were 863 million barrels in 2005, 18 percent

more than the 2004 volume of 734 million barrels. Areas

with the largest extensions were Texas (57 percent of

the National total), Oklahoma (10 percent), Utah and

Wyoming (9 percent), and New Mexico (6 percent).

New Field Discoveries

New field discoveries in 2005 (32 million barrels) were

23 percent higher than in 2004 (26 million barrels).

Areas with the largest new field discoveries were the

Gulf of Mexico Federal Offshore (66 percent) and Texas

(25 percent).

New Reservoir Discoveries in Old Fields

New reservoir discoveries in old fields in 2005 (42

million barrels) were 22 percent lower than they were

in 2004 (54 million barrels). Areas with the largest new

reservoir discoveries in old fields were the Gulf of

Mexico Federal Offshore (50 percent of the National

total), Louisiana (29 percent), and Texas (17 percent).

Revisions and Adjustments

In 2005, there were 968 million barrels of revision

increases, 947 million barrels of revision decreases, and

-89 million barrels of adjustments. The net of revisions

and adjustments was -68 million barrels.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 41
Energy Information Administration

42 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

aThis table is natural gas plant liquids (Table 14) plus lease condensate (Table 15). bIncludes Federal offshore Alabama.

cIncludes 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 2005 contained in the publications Petroleum Supply

Annual 2005, DOE/EIA-0340(05) and Natural Gas Annual 2005 DOE/EIA-0131(05).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 369 0 0 0 0 0 0 0 0 17 352

Lower 48 States . . . . . . . . . . . . . 7,559 -89 968 947 440 596 863 32 42 771 7,813

Alabama. . . . . . . . . . . . . . . . . . . . 50 0 2 1 14 28 1 0 0 5 61

Arkansas . . . . . . . . . . . . . . . . . . . 3 0 0 0 0 0 0 0 0 0 3

California . . . . . . . . . . . . . . . . . . . 122 -6 31 6 8 10 5 0 0 11 137

Coastal Region Onshore . . . . . 19 -3 2 1 0 0 0 0 0 1 16

Los Angeles Basin Onshore. . . 8 0 1 1 0 1 0 0 0 0 9

San Joaquin Basin Onshore . . 95 -3 28 4 8 9 5 0 0 10 112

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

Colorado . . . . . . . . . . . . . . . . . . . 465 -19 55 54 33 49 51 1 0 31 484

Florida . . . . . . . . . . . . . . . . . . . . . 12 -5 0 0 0 0 0 0 0 0 7

Kansas. . . . . . . . . . . . . . . . . . . . . 271 -25 12 20 2 3 5 0 0 20 224

Kentucky . . . . . . . . . . . . . . . . . . . 72 -9 8 2 0 0 3 1 0 3 70

Louisiana . . . . . . . . . . . . . . . . . . . 263 20 42 37 11 15 40 0 12 52 292

North . . . . . . . . . . . . . . . . . . . . 74 -3 7 4 1 2 15 0 0 7 83

South Onshore. . . . . . . . . . . . . 153 19 30 28 7 10 22 0 7 38 168

State Offshore . . . . . . . . . . . . . 36 4 5 5 3 3 3 0 5 7 41

Michigan . . . . . . . . . . . . . . . . . . . 48 -7 3 3 1 1 1 0 0 3 39

Mississippi . . . . . . . . . . . . . . . . . . 6 1 1 1 0 1 0 0 0 1 7

Montana. . . . . . . . . . . . . . . . . . . . 6 3 1 1 0 0 1 0 0 1 9

New Mexico . . . . . . . . . . . . . . . . . 864 -12 96 106 58 78 55 0 0 77 840

East . . . . . . . . . . . . . . . . . . . . . 274 -14 33 32 39 54 33 0 0 38 271

West. . . . . . . . . . . . . . . . . . . . . 590 2 63 74 19 24 22 0 0 39 569

North Dakota . . . . . . . . . . . . . . . . 43 2 5 3 0 2 5 0 0 5 49

Oklahoma . . . . . . . . . . . . . . . . . . 790 16 159 149 25 35 89 0 2 78 839

Texas . . . . . . . . . . . . . . . . . . . . . . 2,801 27 344 371 249 316 491 8 7 294 3,080

RRC District 1 . . . . . . . . . . . . . 36 2 2 3 2 2 3 0 0 4 36

RRC District 2 Onshore . . . . . . 79 6 9 12 9 14 16 1 1 14 91

RRC District 3 Onshore . . . . . . 221 3 36 38 8 9 36 4 3 40 226

RRC District 4 Onshore . . . . . . 326 -16 44 47 30 34 41 1 2 46 309

RRC District 5 . . . . . . . . . . . . . 53 -15 6 4 1 1 11 0 1 4 48

RRC District 6 . . . . . . . . . . . . . 304 -4 23 33 17 35 53 0 0 28 333

RRC District 7B . . . . . . . . . . . . 43 -10 16 6 3 13 44 0 0 7 90

RRC District 7C . . . . . . . . . . . . 383 -4 35 43 23 24 68 1 0 30 411

RRC District 8 . . . . . . . . . . . . . 499 12 47 68 41 64 106 1 0 45 575

RRC District 8A . . . . . . . . . . . . 197 24 36 14 21 42 5 0 0 19 250

RRC District 9 . . . . . . . . . . . . . 235 38 29 46 19 25 47 0 0 24 285

RRC District 10 . . . . . . . . . . . . 420 -9 61 55 75 53 61 0 0 33 423

State Offshore ............. 5 0 0 2 0 0 0 0 0 0 3

Utah and Wyoming . . . . . . . . . . . 927 -85 81 72 4 15 79 0 0 62 879

West Virginia . . . . . . . . . . . . . . . . 85 -16 12 1 0 2 7 0 0 4 85

Federal Offshoreb . . . . . . . . . . . . 721 26 114 119 35 41 29 21 21 123 696

Pacific (California) . . . . . . . . . . 8 0 0 0 0 0 0 0 0 0 8

Gulf of Mexico (Louisiana)b . . . 615 29 89 102 34 37 27 21 19 98 603

Gulf of Mexico (Texas) . . . . . . . 98 -3 25 17 1 4 2 0 2 25 85

Miscellaneousc . . . . . . . . . . . . . . 10 0 2 1 0 0 1 1 0 1 12

U.S. Total . . . . . . . . . . . . . . . . . . 7,928 -89 968 947 440 596 863 32 42 788 8,165

Table 13. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 2005a

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 2005

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 12/31/04 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/05
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 43

Table 14. Natural Gas Plant Liquids Proved Reserves and Production, 2005

(Million Barrels of 42 U.S. Gallons)

2005 2005 2005 2005

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska . . . . . . . . . . . . . . . . . . . . . . 352 17

Lower 48 States.............. 6,551 597

Alabama . . . . . . . . . . . . . . . . . . . . 31 2

Arkansas .................... 2 0

California. . . . . . . . . . . . . . . . . . . . 135 11

Coastal Region Onshore . . . . . 16 1

Los Angeles Basin Onshore . . . 9 0

San Joaquin Basin Onshore. . . 110 10

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

Colorado . . . . . . . . . . . . . . . . . . . . 386 26

Florida ...................... 7 0

Kansas . . . . . . . . . . . . . . . . . . . . . 218 19

Kentucky . . . . . . . . . . . . . . . . . . . . 69 3

Louisiana. . . . . . . . . . . . . . . . . . . . 191 29

North. . . . . . . . . . . . . . . . . . . . . 57 4

South Onshore . . . . . . . . . . . . . 103 20

State Offshore. . . . . . . . . . . . . . 31 5

Michigan . . . . . . . . . . . . . . . . . . . . 36 3

Mississippi................... 2 0

Montana .................... 9 1

New Mexico . . . . . . . . . . . . . . . . . 781 70

East . . . . . . . . . . . . . . . . . . . . . 237 33

West . . . . . . . . . . . . . . . . . . . . . 544 37

North Dakota. . . . . . . . . . . . . . . . . 45 5

Oklahoma . . . . . . . . . . . . . . . . . . . 697 65

Texas ...................... 2,723 247

RRC District 1. . . . . . . . . . . . . . 31 3

RRC District 2 Onshore . . . . . . 72 11

RRC District 3 Onshore . . . . . . 148 26

RRC District 4 Onshore . . . . . . 238 33

RRC District 5. . . . . . . . . . . . . . 40 3

RRC District 6. . . . . . . . . . . . . . 264 22

RRC District 7B. . . . . . . . . . . . . 89 7

RRC District 7C . . . . . . . . . . . . 391 27

RRC District 8. . . . . . . . . . . . . . 559 43

RRC District 8A. . . . . . . . . . . . . 248 19

RRC District 9. . . . . . . . . . . . . . 276 23

RRC District 10. . . . . . . . . . . . . 367 30

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

Utah and Wyoming . . . . . . . . . . . . 710 50

West Virginia. . . . . . . . . . . . . . . . . 84 4

Federal Offshorea . . . . . . . . . . . . . 416 61

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

Gulf of Mexico (Louisiana)a . . . 407 59

Gulf of Mexico (Texas) ....... 9 2

Miscellaneousb ............... 9 1

U.S. Total ................... 6,903 614

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 2005 contained in the publications Petroleum Supply Annual 2005,

DOE/EIA-0340(2005) and Natural Gas Annual 2005, DOE/EIA-0131(2005).

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

44 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table 15. Lease Condensate Proved Reserves and Production, 2005

(Million Barrels of 42 U.S. Gallons)

2005 2005 2005 2005

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska ...................... 0 0

Lower 48 States.............. 1,262 174

Alabama . . . . . . . . . . . . . . . . . . . . 30 3

Arkansas .................... 1 0

California.................... 2 0

Coastal Region Onshore ..... 0 0

Los Angeles Basin Onshore . . . 0 0

San Joaquin Basin Onshore. . . 2 0

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

Colorado . . . . . . . . . . . . . . . . . . . . 98 5

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

Kansas ..................... 6 1

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

Louisiana. . . . . . . . . . . . . . . . . . . . 101 23

North. . . . . . . . . . . . . . . . . . . . . 26 3

South Onshore . . . . . . . . . . . . . 65 18

State Offshore. . . . . . . . . . . . . . 10 2

Michigan .................... 3 0

Mississippi................... 5 1

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

New Mexico . . . . . . . . . . . . . . . . . 59 7

East . . . . . . . . . . . . . . . . . . . . . 34 5

West . . . . . . . . . . . . . . . . . . . . . 25 2

North Dakota................. 4 0

Oklahoma . . . . . . . . . . . . . . . . . . . 142 13

Texas . . . . . . . . . . . . . . . . . . . . . . 357 47

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

RRC District 2 Onshore . . . . . . 19 3

RRC District 3 Onshore . . . . . . 78 14

RRC District 4 Onshore . . . . . . 71 13

RRC District 5.............. 8 1

RRC District 6. . . . . . . . . . . . . . 69 6

RRC District 7B............. 1 0

RRC District 7C . . . . . . . . . . . . 20 3

RRC District 8. . . . . . . . . . . . . . 16 2

RRC District 8A............. 2 0

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

RRC District 10. . . . . . . . . . . . . 56 3

State Offshore.............. 3 0

Utah and Wyoming . . . . . . . . . . . . 169 12

West Virginia................. 1 0

Federal Offshorea . . . . . . . . . . . . . 280 62

Pacific (California)........... 8 0

Gulf of Mexico (Louisiana)a . . . 196 39

Gulf of Mexico (Texas) . . . . . . . 76 23

Miscellaneousb ............... 3 0

U.S. Total ................... 1,262 174

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” 2005.

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

There were 596 million barrels of acquisitions and 440

million barrels of sales in 2005. The net of these

transactions added 156 million barrels of natural gas

liquids proved reserves.

Production

Natural gas liquids production was an estimated 788

million barrels in 2005, a decrease of 5 percent from

2004’s production (827 million barrels).

Six areas accounted for about 88 percent of the Nation’s

natural gas liquids production.

Percent of

Area U.S. NGL Production

Texas 37

Gulf of Mexico Federal Offshore 16

Oklahoma 10

New Mexico 10

Utah and Wyoming 8

Louisiana 7

Area Total 88

Natural Gas Plant Liquids

Proved Reserves

Natural gas plant liquids proved reserves increased in

2005 to 6,903 million barrels, a 3 percent increase from

the 2004 level (6,707 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 39

New Mexico 11

Utah and Wyoming 10

Oklahoma 10

Gulf of Mexico Federal Offshore 6

Colorado 6

Area Total 82

Production

Natural gas plant liquids production decreased 5

percent in 2005—from 645 million barrels in 2004 to

614 million barrels of production (Table 14).

The number of active gas plants increased in 2005.

According to survey results from Form EIA-64A, the

number of unique active U.S. natural gas processing

plants increased from 493 in 2004 to 508 in 2005.

The top six areas for proved reserves of natural gas

plant liquids accounted for about 84 percent of the

Nation’s natural gas plant liquids production:

Percent of U.S.

Area Gas Plant Liquids Production

Texas 40

New Mexico 11

Oklahoma 11

Gulf of Mexico Federal Offshore 10

Utah and Wyoming 8

Colorado 4

Area Total 84

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 1,262 million barrels in 2005 (Table 15).

This was 3 percent higher than the volume reported in

2004 (1,221 million barrels). The reserves of five areas

accounts for about 82 percent of the Nation’s lease

condensate proved reserves.

Percent of U.S.

Area Condensate Reserves

Texas 28

Gulf of Mexico Federal Offshore 22

Utah and Wyoming 13

Oklahoma 11

Louisiana 8

Area Total 82

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 45
Production

Production of lease condensate was 174 million barrels

in 2005, a decrease of 4 percent from 2004’s production

(182 million barrels). The production of five areas

account for about 90 percent of the Nation’s lease

condensate production.

Percent of U.S.

Area Condensate Production

Gulf of Mexico Federal Offshore 36

Texas 27

Louisiana 13

Oklahoma 7

Utah and Wyoming 7

Area Total 90

Reserves in

Nonproducing Status

Like crude oil and natural gas, not all lease condensate

proved reserves were producing during 2005. Proved

reserves of 430 million barrels of lease condensate, an

increase of 5 percent from 2004’s level (409 million

barrels), were reported in nonproducing status in 2005

(Appendix D, Table D10). About 29 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 2005 Annual Report
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Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report 47
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Energy Information Administration

48 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report
Appendix A

Operator Level Data

Appendix A

Operator Level Data

This appendix provides a series of tables of the proved

reserves and production by production size class for

the years 2000 through 2005 for crude oil and natural

gas well operators. The tables show the volumetric

change and percent change from the previous year and

from 2000. In addition they show the 2005 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 14,658 small

operators. We estimated production and reserves for

small operators for 2005 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 2000

through 2005 have changed from 186,510 billion cubic

feet to 213,308 billion cubic feet (Table A1). These

proved reserves are concentrated in the larger

companies. In 2005, 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

24 and 10 percent of the U.S. natural gas proved

reserves, respectively. The top 20 operators had an

increase of 23 percent in their natural gas proved

reserves from 2000 to 2005. The rest of the operators in

(Class 21-100, Class 101-500, and Class Other) had an

increase of 3 percent in their reserves in the same time

period. In 2005, the top 20 operators' natural gas

reserves had an increase of 7 percent from 2004.

Natural Gas Production

Wet natural gas production has decreased from 20,017

billion cubic feet in 2004 to 19,259 billion cubic feet in

2005 (Table A2). In 2005, the top 20 producing

companies had 55 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 a decrease of 7 percent in wet

natural gas production from 2000 to 2005. The rest of

the operators had a decrease of 1 percent from 2000 to

2005. The top 20 operators' wet natural gas production

had a decrease of 6 percent in 2005 from 2004.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report A-1
Crude Oil Proved Reserves

The 10 largest producing companies in 2005 had 54

percent of U.S. proved reserves of crude oil. While the

10 largest producing companies in 2005 had 54 percent

of U.S. proved reserves of natural gas. The 20 largest oil

and gas producing companies in 2005 had 66 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 increased 2 percent in

2005 from 2004. The top 20 producing companies

proved reserves of crude oil during 2005 remained the

same from 2004. The top 20 class had a decrease of 6

percent in their crude oil proved reserves from 2000 to

2005.

Crude Oil Production

Crude oil production reported for 2000 to 2005 has

decreased from 1,819 million barrels to 1,733 million

barrels (Table A4). The 20 largest oil and gas producing

companies had 63 percent of U.S. production of crude

oil in 2005. In 2000 they accounted for 67 percent of

production.

This is in contrast to wet natural gas where these same

companies produced 55 percent of the total. U.S.

production of crude oil declined by 8 percent from 2000

to 2005. The top 20 operators had a decline of 14 percent

in their oil production during the same period. U.S.

production of crude oil declined 5 percent from 2004 to

2005. 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 2000-2005

period (Table A5). From 2000-2005, the number of

fields in which the top 20 operators were active

increased by 859 fields (16 percent) while in 2005 the

number decreased by 535 fields from 2004.

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 2005 operated production data.

Energy Information Administration

A-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report A-3

Operators Formerly in the Ranks of the Top 50 Reported for the U.S. 1999-2005

Number 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 Gruy Petroleum Management Co Cimarex Energy Co

17 Helmerich & Payne Inc Cimarex Energy Co

18 Howell Petroleum Corp Anadarko Petroleum Corp

19 HS Resources Inc Kerr-McGee Corp

20 Louis Dreyfus Natural Gas Corp Dominion Resources Inc

21 Mitchell Energy & Development Corp Devon Energy Corp

22 Nuevo Energy Co Plains Explor & Prod Co

23 Ocean Energy Inc Devon Energy Corp

24 Patina Oil & Gas Corp Noble Energy Inc

25 Phillips Petroleum Co ConocoPhillips Co

26 Prize Operating Co Cimarex Energy Co

27 River Gas Corp ConocoPhillips Co

28 Santa Fe Snyder Corp Devon Energy Corp

29 Stocker Resources Inc Plains Explor & Prod Co

30 Texaco Inc ChevronTexaco Inc

31 Tom Brown Inc Encana Oil & Gas Inc

32 Union Pacific Resources Anadarko Petroleum Corp

33 Unocal Corp Chevron Texaco Inc

34 Vastar Resources Inc BP Plc

35 Westport Resources Corp Kerr-McGee Corp
Energy Information Administration

A-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Class 1-10 81,437 88,936 88,100 82,222 81,325 80,785 -540 -652 8,078.512

Percent of Total 43.7% 46.4% 45.0% 41.7% 40.4% 37.9% -0.7% -0.8%

Class 11-20 22,590 24,588 25,938 29,890 38,643 47,078 8,435 24,488 4,707.841

Percent of Total 12.1% 12.8% 13.3% 15.2% 19.2% 22.1% 21.8% 108.4%

Class 21-100 48,832 50,055 50,633 53,098 50,149 52,061 1,912 3,229 650.767

Percent of Total 26.2% 26.1% 25.9% 26.9% 24.9% 24.4% 3.8% 6.6%

Class 101-500 22,620 19,046 19,723 20,030 20,912 21,737 825 -884 54.341

Percent of Total 12.1% 9.9% 10.1% 10.2% 10.4% 10.2% 3.9% -3.9%

Class Other (14,658) 11,030 9,118 11,167 11,905 10,170 11,647 1,477 617 0.795

Percent of Total 5.9% 4.8% 5.7% 6.0% 5.1% 5.5% 14.5% 5.6%

Category I (172) 162,144 169,056 173,325 173,225 178,269 189,644 11,375 27,500 1,102.582

Percent of Total 86.9% 88.2% 88.6% 87.9% 88.6% 88.9% 6.4% 17.0%

Category II (522) 13,123 13,346 11,051 11,983 12,494 11,838 -656 -1,286 22.678

Percent of Total 7.0% 7.0% 5.7% 6.1% 6.2% 5.5% -5.3% -9.8%

Category III (14,464) 11,243 9,342 11,184 11,937 10,437 11,826 1,389 583 0.818

Percent of Total 6.0% 4.9% 5.7% 6.1% 5.2% 5.5% 13.3% 5.2%

Total Published 186,510 191,743 195,561 197,145 201,200 213,308 12,108 26,798 14.072

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 6.0% 14.4%

Table A1. Natural Gas Proved Reserves, Wet After Lease Separation, by Operator Production Size Class,

2000–2005

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

2004–2005 2000–2005 2005

Volume and Volume and Average

Percent Percent Reserves

Size Class 2000 2001 2002 2003 2004 2005 Change Change per Operator

R = Revised

Note: There were 14,464 active Category III operators in the 2005 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 661 Category III operators (Table E2). The "other" size class represents 14,658 operators in the

2005 frame (15,158 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 2005 Annual Report A-5

Class 1-10 8,495 9,019 8,996 8,220 7,617 7,068 -548 -1,426 706.833

Percent of Total 42.1% 43.7% 44.4% 40.6% 38.1% 36.7% -7.2% -16.8%

Class 11-20 2,886 3,064 2,854 3,136 3,647 3,534 -112 648 353.437

Percent of Total 14.3% 14.8% 14.1% 15.5% 18.2% 18.4% -3.1% 22.5%

Class 21-100 4,965 4,949 4,763 5,275 4,982 4,832 -150 -133 60.402

Percent of Total 24.6% 24.0% 23.5% 26.1% 24.9% 25.1% -3.0% -2.7%

Class 101-500 2,780 2,609 2,475 2,386 2,559 2,506 -52 -274 6.266

Percent of Total 13.8% 12.6% 12.2% 11.8% 12.8% 13.0% -2.0% -9.9%

Class Other (14,658) 1,038 1,000 1,161 1,215 1,213 1,318 105 280 0.090

Percent of Total 5.1% 4.8% 5.7% 6.0% 6.1% 6.8% 8.6% 26.9%

Category I (172) 17,096 17,672 17,335 17,347 17,036 16,311 -724 -784 94.834

Percent of Total 84.8% 85.6% 85.6% 85.7% 85.1% 84.7% -4.3% -4.6%

Category II (522) 1,921 1,932 1,738 1,648 1,718 1,605 -113 -316 3.075

Percent of Total 9.5% 9.4% 8.6% 8.1% 8.6% 8.3% -6.6% -16.5%

Category III (14,464) 1,147 1,038 1,176 1,236 1,263 1,342 80 195 0.093

Percent of Total 5.7% 5.0% 5.8% 6.1% 6.3% 7.0% 6.3% 17.0%

Total Published 20,164 20,642 20,248 20,231 20,017 19,259 -758 -905 1.271

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -3.8% -4.5%

Table A2. Natural Gas Production, Wet After Lease Separation, by Operator Production Size Class,

2000–2005

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

2004–2005 2000–2005 2005

Volume and Volume and Average

Percent Percent Production

Size Class 2000 2001 2002 2003 2004 2005 Change Change per Operator

R = Revised

Note: There were 14,464 active Category III operators in the 2005 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 661 Category III operators (Table E2). The "other" size class represents 14,658 operators in the

2005 frame (15,158 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 2005 Annual Report

Class 1-10 12,367 13,590 13,346 13,355 12,454 11,775 -679 -592 1,177.522

Percent of Total 56.1% 60.5% 58.9% 61.0% 58.3% 54.1% -5.4% -4.8%

Class 11-20 3,172 2,901 2,817 1,907 2,053 2,659 607 -512 265.939

Percent of Total 14.4% 12.9% 12.4% 8.7% 9.6% 12.2% 29.6% -16.2%

Class 21-100 2,505 2,856 3,230 3,483 3,711 3,915 204 1,410 48.934

Percent of Total 11.4% 12.7% 14.2% 15.9% 17.4% 18.0% 5.5% 56.3%

Class 101-500 2,286 1,794 1,817 1,705 1,761 1,969 208 -317 4.923

Percent of Total 10.4% 8.0% 8.0% 7.8% 8.2% 9.1% 11.8% -13.9%

Class Other (14,658) 1,716 1,305 1,468 1,440 1,393 1,439 46 -277 0.098

Percent of Total 7.8% 5.8% 6.5% 6.6% 6.5% 6.6% 3.3% -16.2%

Category I (172) 19,421 20,325 20,213 19,499 19,055 19,348 292 -74 112.486

Percent of Total 88.1% 90.6% 89.1% 89.1% 89.2% 88.9% 1.5% -0.4%

Category II (522) 873 794 992 937 906 954 48 81 1.827

Percent of Total 4.0% 3.5% 4.4% 4.3% 4.2% 4.4% 5.3% 9.3%

Category III (14,464) 1,751 1,326 1,472 1,456 1,410 1,456 46 -295 0.101

Percent of Total 7.9% 5.9% 6.5% 6.6% 6.6% 6.7% 3.3% -16.9%

Total Published 22,045 22,446 22,677 21,891 21,371 21,757 386 -288 1.435

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 1.8% -1.3%

Table A3. Crude Oil Proved Reserves by Operator Production Size Class, 2000–2005

(Million Barrels of 42 U.S. Gallons)

2004–2005 2000–2005 2005

Volume and Volume and Average

Percent Percent Reserves

Size Class 2000 2001 2002 2003 2004 2005 Change Change per Operator

R = Revised

Note: There were 14,464 active Category III operators in the 2005 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 661 Category III operators (Table E2). The "other" size class represents 14,658 operators in the

2005 frame (15,158 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 2005 Annual Report A-7

Class 1-10 961 1,061 1,037 1,047 986 912 -75 -49 91.179

Percent of Total 51.1% 55.4% 55.3% 55.8% 54.2% 52.6% -7.6% -5.1%

Class 11-20 304 240 233 205 180 178 -3 -127 17.766

Percent of Total 16.2% 12.5% 12.4% 10.9% 9.9% 10.3% -1.4% -41.7%

Class 21-100 214 233 240 272 303 293 -10 79 3.661

Percent of Total 11.4% 12.2% 12.8% 14.5% 16.6% 16.9% -3.2% 37.0%

Class 101-500 211 195 181 178 172 178 6 -33 0.445

Percent of Total 11.2% 10.2% 9.7% 9.5% 9.5% 10.3% 3.4% -15.6%

Class Other (14,658) 190 186 184 175 178 173 -5 -17 0.012

Percent of Total 10.1% 9.7% 9.8% 9.3% 9.8% 10.0% -2.8% -9.0%

Category I (172) 1,572 1,612 1,573 1,574 1,534 1,451 -83 -121 8.438

Percent of Total 83.6% 84.2% 83.9% 83.9% 84.3% 83.7% -5.4% -7.7%

Category II (522) 111 112 115 124 105 105 0 -6 0.202

Percent of Total 5.9% 5.8% 6.1% 6.6% 5.8% 6.1% -0.2% -5.0%

Category III (14,464) 197 191 187 179 180 176 -3 -21 0.012

Percent of Total 10.5% 10.0% 10.0% 9.5% 9.9% 10.2% -1.8% -10.6%

Total Published 1,880 1,915 1,875 1,877 1,819 1,733 -86 -147 0.114

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -4.7% -7.8%

Table A4. Crude Oil Production by Operator Production Size Class, 2000–2005

(Million Barrels of 42 U.S. Gallons)

2004–2005 2000–2005 2005

Volume and Volume and Average

Percent Percent Production

Size Class 2000 2001 2002 2003 2004 2005 Change Change per Operator

R = Revised

Note: There were 14,464 active Category III operators in the 2005 sample frame. The reserves and production of Category III operators were

estimated from an adjusted sample of 661 Category III operators (Table E2). The "other" size class represents 14,658 operators in the 2005 frame

(15,158 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 2005 Annual Report

Class 1-10 3,444 3,794 3,596 3,689 3,409 3,738 329 294 373.800

Percent of Total 13.0% 14.0% 12.9% 13.2% 12.4% 13.2% 9.7% 8.5%

Class 11-20 1,923 2,212 2,392 2,492 3,352 2,488 -864 565 248.800

Percent of Total 7.2% 8.2% 8.6% 8.9% 12.2% 8.8% -25.8% 29.4%

Class 21-100 7,084 7,195 7,947 8,168 8,071 9,196 1,125 2,112 114.950

Percent of Total 26.7% 26.5% 28.4% 29.3% 29.4% 32.6% 13.9% 29.8%

Class 101-500 12,580 12,435 12,661 11,859 10,698 10,845 147 -1,735 27.113

Percent of Total 47.4% 45.9% 45.3% 42.5% 39.0% 38.4% 1.4% -13.8%

Rest 1,529 1,480 1,349 1,709 1,929 1,952 23 423 10.062

Percent of Total 5.8% 5.5% 4.8% 6.1% 7.0% 6.9% 1.2% 27.7%

Category I 16,174 16,196 17,049 16,760 17,368 17,858 490 1,684 103.826

Percent of Total 60.9% 59.7% 61.0% 60.0% 63.3% 63.3% 2.8% 10.4%

Category II 10,146 10,764 10,473 10,688 9,486 9,738 252 -408 18.655

Percent of Total 38.2% 39.7% 37.5% 38.3% 34.5% 34.5% 2.7% -4.0%

Total 26,560 27,116 27,945 27,917 27,459 28,219 760 1,659 40.661

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 2.8% 6.2%

Note: Includes only data from Category I and Category II operators. In 2005 there were 172 Category I operators and 522 Category II

operators. The “rest” size class had 194 operators in 2005.

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

Table A5. Operator Field Count by Operator Production Size Class, 2000–2005

2004–2005 2000–2005 2005 Average

Number and Number and Number of

Percent Percent Fields per

Size Class 2000 2001 2002 2003 2004 2005 Change Change Operator
Table A6. Top 50 U.S. Operators Ranked by Reported 2005 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 825 1 BP PLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,465

2 CHEVRON CORP. . . . . . . . . . . . . . . . . . . . . . . . . 478 2 CHEVRON CORP ...................... 2,355

3 CONOCOPHILLIPS . . . . . . . . . . . . . . . . . . . . . . . 346 3 CONOCOPHILLIPS..................... 2,110

4 SHELL OIL CO . . . . . . . . . . . . . . . . . . . . . . . . . . . 324 4 EXXONMOBIL CORP ................... 2,057

5 OCCIDENTAL OIL & GAS CORP. . . . . . . . . . . . . 283 5 DEVON ENERGY CORP................. 2,002

6 AERA ENERGY LLC . . . . . . . . . . . . . . . . . . . . . . 199 6 BURLINGTON RESOURCES INC ......... 1,942

7 EXXONMOBIL CORP. . . . . . . . . . . . . . . . . . . . . . 145 7 CHESAPEAKE ENERGY CORP........... 1,657

8 KERR-MCGEE CORP . . . . . . . . . . . . . . . . . . . . . 133 8 SHELL OIL CO ........................ 1,608

9 APACHE CORP . . . . . . . . . . . . . . . . . . . . . . . . . . . 91 9 ANADARKO PETROLEUM CORP ......... 1,471

10 AMERADA HESS CORP . . . . . . . . . . . . . . . . . . . . 72 10 ENCANA CORP........................ 1,419

Top 10 Volume Subtotal 2,896 Top 10 Volume Subtotal 20,086

Top 10 Percentage of U.S. Total 55% Top 10 Percentage of U.S. Total 38%

11 PLAINS EXPLORATION & PRODUCTION CO . . . 59 11 KERR-MCGEE CORP ................... 1,371

12 KINDER MORGAN, INC . . . . . . . . . . . . . . . . . . . . . 57 12 XTO ENERGY INC ..................... 1,342

13 DEVON ENERGY CORP . . . . . . . . . . . . . . . . . . . . 54 13 APACHE CORP........................ 1,110

14 BURLINGTON RESOURCES INC . . . . . . . . . . . . . 52 14 E O G RESOURCES INC ................ 1,066

15 ANADARKO PETROLEUM CORP. . . . . . . . . . . . . 52 15 DOMINION RESOURCES INC ............ 1,040

16 MARATHON OIL CORP . . . . . . . . . . . . . . . . . . . . . 50 16 EL PASO ENERGY . . . . . . . . . . . . . . . . . . . . . . 826

17 MERIT ENERGY CO . . . . . . . . . . . . . . . . . . . . . . . 47 17 OCCIDENTAL OIL & GAS CORP. . . . . . . . . . . . 809

18 MURPHY OIL CORP . . . . . . . . . . . . . . . . . . . . . . . 46 18 MARATHON OIL CORP . . . . . . . . . . . . . . . . . . . 741

19 NOBLE ENERGY INC . . . . . . . . . . . . . . . . . . . . . . 37 19 WILLIAMS ENERGY INC . . . . . . . . . . . . . . . . . . 719

20 XTO ENERGY INC . . . . . . . . . . . . . . . . . . . . . . . . . 37 20 NEWFIELD EXPLORATION CO . . . . . . . . . . . . 690

Top 20 Volume Subtotal 3,387 Top 20 Volume Subtotal 29,800

Top 20 Percentage of U.S. Total 65% Top 20 Percentage of U.S. Total 56%

21 E O G RESOURCES INC . . . . . . . . . . . . . . . . . . . . 32 21 SAMSON RESOURCES CO . . . . . . . . . . . . . . . 633

22 CITY OF LONG BEACH . . . . . . . . . . . . . . . . . . . . . 31 22 PIONEER NATURAL RESOURCES . . . . . . . . . 630

23 DOMINION RESOURCES INC. . . . . . . . . . . . . . . . 29 23 QUESTAR CORP . . . . . . . . . . . . . . . . . . . . . . . . 594

24 CITATION OIL & GAS CORP. . . . . . . . . . . . . . . . . 28 24 NOBLE ENERGY INC . . . . . . . . . . . . . . . . . . . . 538

25 CHESAPEAKE ENERGY CORP . . . . . . . . . . . . . . 28 25 CIMAREX ENERGY CO. . . . . . . . . . . . . . . . . . . 455

26 DENBURY RESOURCES INC . . . . . . . . . . . . . . . . 28 26 MERIT ENERGY CO . . . . . . . . . . . . . . . . . . . . . 425

27 PIONEER NATURAL RESOURCES . . . . . . . . . . . 25 27 ENERGEN RESOURCES CORP. . . . . . . . . . . . 303

28 HILCORP ENERGY CO . . . . . . . . . . . . . . . . . . . . . 24 28 HOUSTON EXPLORATION CO. . . . . . . . . . . . . 295

29 NEWFIELD EXPLORATION CO . . . . . . . . . . . . . . 24 29 YATES PETROLEUM CORP . . . . . . . . . . . . . . . 282

30 POGO PRODUCING CO . . . . . . . . . . . . . . . . . . . . 23 30 AMERADA HESS CORP . . . . . . . . . . . . . . . . . . 264

31 WHITING PETROLEUM CORP . . . . . . . . . . . . . . . 23 31 FOREST OIL CORP . . . . . . . . . . . . . . . . . . . . . . 261

32 BERRY PETROLEUM CO . . . . . . . . . . . . . . . . . . . 21 32 POGO PRODUCING CO . . . . . . . . . . . . . . . . . . 259

33 ENCORE OPERATING LP. . . . . . . . . . . . . . . . . . . 21 33 HUNT OIL CO. . . . . . . . . . . . . . . . . . . . . . . . . . . 245

34 VINTAGE PETROLEUM INC . . . . . . . . . . . . . . . . . 20 34 EQUITABLE RESOURCES INC. . . . . . . . . . . . . 238

35 CIMAREX ENERGY CO . . . . . . . . . . . . . . . . . . . . . 19 35 CABOT OIL & GAS CORP . . . . . . . . . . . . . . . . . 230

36 FOREST OIL CORP . . . . . . . . . . . . . . . . . . . . . . . . 19 36 TOTALFINAELF SA . . . . . . . . . . . . . . . . . . . . . . 226

37 CONTINENTAL RESOURCES INC . . . . . . . . . . . . 19 37 HILCORP ENERGY CO . . . . . . . . . . . . . . . . . . . 222

38 NANCE PETROLEUM CORP. . . . . . . . . . . . . . . . . 19 38 ULTRA PETROLEUM INC . . . . . . . . . . . . . . . . . 208

39 ENDEAVOR ENERGY RESOURCES . . . . . . . . . . 18 39 WALTER OIL & GAS CORP. . . . . . . . . . . . . . . . 179

40 ENI PETROLEUM CO INC . . . . . . . . . . . . . . . . . . . 18 40 COLUMBIA NATURAL RESOURCES LLC . . . . 176

41 EL PASO ENERGY . . . . . . . . . . . . . . . . . . . . . . . . 18 41 STONE ENERGY CORP . . . . . . . . . . . . . . . . . . 174

42 NEXEN PETROLEUM USA INC. . . . . . . . . . . . . . . 17 42 VINTAGE PETROLEUM INC . . . . . . . . . . . . . . . 170

43 SWIFT ENERGY OPERATING LLC. . . . . . . . . . . . 16 43 W & T OFFSHORE INC . . . . . . . . . . . . . . . . . . . 162

44 HENRY PETROLEUM LP. . . . . . . . . . . . . . . . . . . . 15 44 RED WILLOW PRODUCTION CO . . . . . . . . . . . 162

45 ENERGEN RESOURCES CORP. . . . . . . . . . . . . . 15 45 FIDELITY EXPLORATION & PROD CO . . . . . . 157

46 STONE ENERGY CORP . . . . . . . . . . . . . . . . . . . . 14 46 C N X GAS CO LLC . . . . . . . . . . . . . . . . . . . . . . 151

47 HEADINGTON RESOURCES INC . . . . . . . . . . . . . 13 47 KAISER - FRANCIS OIL CO. . . . . . . . . . . . . . . . 148

48 ENCANA CORP . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 48 KCS ENERGY INC . . . . . . . . . . . . . . . . . . . . . . . 147

49 BREITBURN ENERGY CO LP . . . . . . . . . . . . . . . . 12 49 ENERGY PARTNERS LTD . . . . . . . . . . . . . . . . 143

50 CASTLE PEAK RESOURCES LLC . . . . . . . . . . . . 11 50 UNIT CORP . . . . . . . . . . . . . . . . . . . . . . . . . . . . 142

Top 50 Volume Subtotal 3,999 Top 50 Volume Subtotal 38,019

Top 50 Percentage of U.S. Total 77% Top 50 Percentage of U.S. Total 72%

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 2005 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.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report B-1

Summary for the Top 100 Fields for 2005 Liquids and Gas

12/31/2005 12/31/2005 Estimated

Proved Nonproducing 2005 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 7,459.9 32.4% 1,818.5 29.7% 410.3 21.5%

Top 20 9,884.9 42.9% 2,430.7 39.7% 597.4 31.3%

Top 50 13,307.3 57.8% 3,399.7 55.5% 822.5 43.1%

Top 100 15,721.9 68.3% 4,298.8 70.2% 1,029.8 54.0%

Others 7,297.1 31.7% 1,822.2 29.8% 877.2 46.0%

Total 23,019.0 100.0% 6,121.0 100.0% 1,907.0 100.0%

Table B2. Top 100 U.S. Fields as Ranked by Gas Proved Reserves (Billion Cubic Feet)

Top 10 63,050.8 29.6% 16,914.5 28.4% 4,019.3 20.9%

Top 20 81,644.4 38.3% 21,769.8 36.5% 5,414.0 28.1%

Top 50 105,810.6 49.6% 29,792.6 49.9% 7,189.1 37.3%

Top 100 124,975.2 58.6% 35,807.1 60.0% 8,614.2 44.7%

Others 88,332.8 41.4% 23,850.9 40.0% 10,644.8 55.3%

Total 213,308.0 100.0% 59,658.0 100.0% 19,259.0 100.0%

Table B3. Top 100 U.S. Fields as Ranked by Liquids Production (Million Barrels)

Top 10 n/a n/a n/a n/a 501.8 26.3%

Top 20 n/a n/a n/a n/a 683.3 35.8%

Top 50 n/a n/a n/a n/a 931.7 48.9%

Top 100 n/a n/a n/a n/a 1,099.7 57.7%

Others n/a n/a n/a n/a 807.3 42.3%

Total n/a n/a n/a n/a 1,907.0 100.0%

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 4,193.2 21.8%

Top 20 n/a n/a n/a n/a 5,476.0 28.4%

Top 50 n/a n/a n/a n/a 7,407.7 38.5%

Top 100 n/a n/a n/a n/a 9,011.3 46.8%

Others n/a n/a n/a n/a 10,247.7 53.2%

Total n/a n/a n/a n/a 19,259.0 100.0%
Table B1. Top 100 Liquids Fields Ranked by

Reserves

The top 100 liquids fields by reserves had 15,722

million barrels of proved reserves accounting for 68

percent of the total United States as of December 31,

2005, (Table 6 and Table 14) and 70 percent of the

reported nonproducing reserves. In the top 20 liquids

fields for 2005 there are five fields, which are in the

deep water of the Gulf of Mexico Federal Offshore and

two are currently nonproducing.

The top 100 liquids fields by reserves had 1,030 million

barrels of production, or 54 percent of the 2005 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 Elm Coulee field in Montana

moving to 24th in 2005.

Table B2. Top 100 Gas Fields Ranked by Reserves

The top 100 gas fields by reserves had 124,975 billion

cubic feet of wet natural gas proved reserves or 58

percent of the total, as of December 31, 2005 (Table 9)

and 60 percent of the reported nonproducing reserves.

The top 100 gas fields by reserves had 8,614 billion

cubic feet of production, or 45 percent of the 2005 U.S.

total (Table 9).

Table B3. Top 100 Liquids Fields Ranked by

Production

The top 100 liquids fields by production had 1,100

million barrels of production, or 58 percent of the 2005

U.S. total (Table 6 and Table 14).

Table B4. Top 100 Gas Fields Ranked by Production

The top 100 gas fields had 9,011 billion cubic feet of

production, or 47 percent of the 2005 U.S. total (Table

9).

A Quarter Century of Change

For a historical perspective of the way the largest 100 oil

fields have changed over the course of 25 years, a table

of the One Hundred Largest Fields as of December 31,

1979 has been added to this appendix (Table B5).

Energy Information Administration

B-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report B-3

Table B1. Top 100 U.S. Fields Ranked by Liquids Proved Reserves from Estimated 2005 Field Level Dataa

(Million Barrels of 42 U.S. Gallons)

Rank Group 2005 Estimated

Discovery Proved Nonproducing Production

Num Field Name Location Year Reserves Reserves Volume

1 PRUDHOE BAY AK 1967 (1-10) 118.9

2 WASSON TX 1954 (1-10) 56.2

3 KUPARUK RIVER AK 1969 (1-10) 47.7

4 BELRIDGE SOUTH CA 1911 (1-10) 37.4

5 MISSISSIPPI CANYON BLK 778 (THUNDER HORSE) FG 1999 (1-10) 0.0

6 MISSISSIPPI CANYON BLK 807 (MARS-URSA) FG 1989 (1-10) 67.0

7 SPRABERRY TREND AREA TX 1952 (1-10) 22.7

8 MIDWAY-SUNSET CA 1901 (1-10) 42.4

9 GREEN CANYON BLK 699 (ATLANTIS) FG 1998 (1-10) 0.0

10 ELK HILLS CA 1919 (1-10) 18.1

Top 10 Volume Subtotal 7,459.9 1,818.5 410.3

Top 10 Percentage of U.S. Total 32.4% 29.7% 21.5%

11 KERN RIVER CA 1899 (11-20) 33.0

12 SLAUGHTER TX 1937 (11-20) 13.0

13 ALPINE AK 1994 (11-20) 42.9

14 MILNE POINT AK 1982 (11-20) 16.0

15 GREEN CANYON BLK 644 (HOLSTEIN) FG 1999 (11-20) 16.6

16 CEDAR HILLS ND & MT & SD 1951 (11-20) 22.6

17 GREEN CANYON BLK 826 (MAD DOG) FG 1999 (11-20) 8.6

18 WATTENBERG CO 1970 (11-20) 10.9

19 LEVELLAND TX 1945 (11-20) 8.4

20 WILMINGTON CA 1935 (11-20) 15.0

Top 20 Volume Subtotal 9,884.9 2,430.7 597.4

Top 20 Percentage of U.S. Total 42.9% 39.7% 31.3%

21 CYMRIC CA 1916 (21-50) 18.5

22 SALT CREEK WY 1917 (21-50) 2.4

23 LOST HILLS CA 1910 (21-50) 11.4

24 ELM COULEE MT 2000 (21-50) 15.9

25 GREEN CANYON BLK 640 (TAHITI) FG 2002 (21-50) 0.0

26 HONDO FP 1969 (21-50) 6.2

27 WEST SAK AK 1969 (21-50) 4.4

28 PESCADO FP 1970 (21-50) 4.9

29 YATES TX 1926 (21-50) 8.9

30 SHO-VEL-TUM OK 1905 (21-50) 8.1

31 HOBBS NM 1928 (21-50) 4.8

32 COWDEN NORTH TX 1930 (21-50) 6.0

33 NORTHSTAR AK 1984 (21-50) 22.8

34 MISSISSIPPI CANYON BLK 84 (KING/HORN MT) FG 1993 (21-50) 22.5

35 KELLY-SNYDER TX 1948 (21-50) 11.8

36 POINT MCINTYRE AK 1988 (21-50) 12.3

37 INGLEWOOD CA 1924 (21-50) 2.9

38 GOLDSMITH TX 1946 (21-50) 5.1

39 SACATE FP 1970 (21-50) 3.9

40 ORION AK 2002 (21-50) 2.8

41 SAN ARDO CA 1947 (21-50) 3.5

42 ENDICOTT AK 1978 (21-50) 6.5

43 VACUUM NM 1929 (21-50) 7.2

44 PINEDALE WY 1955 (21-50) 3.5

45 SEMINOLE TX 1936 (21-50) 8.4

46 VENTURA CA 1916 (21-50) 3.9

47 GREATER ANETH UT 1956 (21-50) 3.6

48 BOREALIS AK 2001 (21-50) 7.0

49 FULLERTON TX 1942 (21-50) 4.5

50 WARD-ESTES NORTH TX 1927 (21-50) 1.4

Top 50 Volume Subtotal 13,307.3 3,399.7 822.5

Top 50 Percentage of U.S. Total 57.8% 55.5% 43.1%
Energy Information Administration

B-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

51 ROBERTSON NORTH TX 1956 (51-100) 4.1

52 MONUMENT BUTTE UT 1964 (51-100) 3.4

53 MCELROY TX 1926 (51-100) 4.9

54 GREEN CANYON BLK 339 (FRONT RUNNER) FG 2001 (51-100) 8.4

55 HAWKINS TX 1940 (51-100) 2.5

56 GREEN CANYON BLK 562 (K2) FG 1999 (51-100) 1.6

57 MISSISSIPPI CANYON BLK 383 (KEPLER) FG 1987 (51-100) 33.6

58 BELRIDGE NORTH CA 1912 (51-100) 3.7

59 SALT CREEK TX 1968 (51-100) 4.9

60 PENNEL MT 1955 (51-100) 1.9

61 RANGELY CO 1902 (51-100) 5.2

62 GREEN CANYON BLK 680 (CONSTITUTION) FG 2001 (51-100) 0.0

63 WESTBROOK TX 1920 (51-100) 2.5

64 LAKE WASHINGTON LA 1931 (51-100) 6.2

65 ARROYO GRANDE CA 1906 (51-100) 0.6

66 MISSISSIPPI CANYON BLK 20 FG 1982 (51-100) 0.0

67 COALINGA CA 1887 (51-100) 5.9

68 MISSISSIPPI CANYON BLK 696 (BLIND FAITH) FG 2001 (51-100) 0.0

69 JAY AL & FL 1951 (51-100) 1.9

70 POSTLE OK 1958 (51-100) 1.6

71 GIDDINGS TX 1960 (51-100) 8.2

72 LISBURNE AK 1967 (51-100) 2.9

73 ATWATER VALLEY BLK 575 (NEPTUNE (AT)) FG 1995 (51-100) 0.0

74 MEANS TX 1934 (51-100) 3.5

75 MISSISSIPPI CANYON BLK 773 (DEVILS TOWER) FG 2000 (51-100) 5.4

76 CEDAR LAKE TX 1939 (51-100) 2.5

77 VIOSCA KNOLL BLK 786 (PETRONIUS) FG 1996 (51-100) 12.2

78 AURORA AK 1969 (51-100) 3.3

79 HOWARD-GLASSCOCK TX 1925 (51-100) 2.8

80 ANTON-IRISH TX 1944 (51-100) 4.1

81 TARN AK 1991 (51-100) 8.1

82 WASSON 72 TX 1940 (51-100) 2.5

83 KERN FRONT CA 1925 (51-100) 1.5

84 FUHRMAN-MASCHO TX 1930 (51-100) 2.4

85 ALTAMONT-BLUEBELL UT 1949 (51-100) 2.9

86 POLARIS AK 2000 (51-100) 1.3

87 GREEN CANYON BLK 654 (SHENZI) FG 2003 (51-100) 0.0

88 MISSISSIPPI CANYON BLK 582 (MEDUSA) FG 2000 (51-100) 8.7

89 GOLDEN TREND OK 1945 (51-100) 2.0

90 EWING BANK BLK 873 (LOBSTER/OYSTER) FG 1991 (51-100) 8.1

91 GREEN CANYON BLK 518 (K2) FG 1999 (51-100) 0.0

92 GARDEN BANKS BLK 171 (SALSA) FG 1988 (51-100) 7.6

93 EAST TEXAS TX 1930 (51-100) 4.5

94 EAST BREAKS BLK 602 (NANSEN) FG 1999 (51-100) 9.1

95 FULLER TX 1951 (51-100) 0.7

96 FOSTER TX 1984 (51-100) 2.3

97 PATRICK DRAW WY 1959 (51-100) 0.6

98 DOLLARHIDE NM & TX 1945 (51-100) 2.9

99 WELCH TX 1981 (51-100) 1.7

100 JONAH WY 1977 (51-100) 2.6

Top 100 Volume Subtotal 15,721.9 4,298.8 1,029.8

Top 100 Percentage of U.S. Total 68.3% 70.2% 54.0%

Table B1. Top 100 U.S. Fields Ranked by Liquids Proved Reserves from Estimated 2005 Field Level Dataa

(Continued)

(Million Barrels of 42 U.S. Gallons)

Rank Group 2005 Estimated

Discovery Proved Nonproducing Production

Num Field Name Location Year Reserves Reserves Volume

aIncludes lease condensate.

Notes: The U.S. total production estimate of 1,907 million barrels and the U.S. total reserves estimate of 23,019 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 2005 Annual Report B-5

Table B2. Top 100 U.S. Fields Ranked by Gas Proved Reserves from Estimated 2005 Field Level Dataa

(Billion Cubic Feet)

Rank Group 2005 Estimated

Discovery Proved Nonproducing Production

Num Field Name Location Year Reserves Reserves Volume

1 SAN JUAN BASIN GAS AREA CO & NM 1927 (1-10) 1397.0

2 PINEDALE WY 1955 (1-10) 457.3

3 NEWARK EAST TX 2002 (1-10) 496.5

4 HUGOTON GAS AREA KS & OK & TX 1922 (1-10) 480.7

5 PRUDHOE BAY AK 1967 (1-10) 193.0

6 JONAH WY 1977 (1-10) 273.1

7 WATTENBERG CO 1970 (1-10) 179.1

8 MADDEN WY 1968 (1-10) 163.7

9 ANTRIM MI 1965 (1-10) 164.9

10 CARTHAGE TX 1981 (1-10) 214.1

Top 10 Volume Subtotal 63,050.8 16,914.5 4,019.3

Top 10 Percentage of U.S. Total 29.6% 28.4% 20.9%

11 RATON BASIN GAS AREA CO & NM 1998 (11-20) 120.9

12 NATURAL BUTTES UT 1940 (11-20) 133.6

13 PRB COALBED WY 1992 (11-20) 336.1

14 VERNON LA 1967 (11-20) 115.1

15 LOWER MOBILE BAY AREA AL & FG 1979 (11-20) 139.1

16 SPRABERRY TREND AREA TX 1952 (11-20) 78.7

17 SAWYER TX 1960 (11-20) 75.1

18 ELK HILLS CA 1919 (11-20) 136.2

19 FOGARTY CREEK WY 1975 (11-20) 166.4

20 ELM GROVE LA 1916 (11-20) 93.6

Top 20 Volume Subtotal 81,644.4 21,769.8 5,414.0

Top 20 Percentage of U.S. Total 38.3% 36.5% 28.1%

21 OAKWOOD VA 1990 (21-50) 54.5

22 GRAND VALLEY CO 1985 (21-50) 63.0

23 BIG SANDY KY & WV 1926 (21-50) 45.6

24 MAMM CREEK CO 1959 (21-50) 95.5

25 MISSISSIPPI CANYON BLK 807 (MARS-URSA) FG 1989 (21-50) 93.2

26 OAK HILL TX 1958 (21-50) 97.9

27 WASSON TX 1954 (21-50) 78.1

28 PARACHUTE CO 1985 (21-50) 51.3

29 STRONG CITY DISTRICT OK 1966 (21-50) 81.5

30 RULISON CO 1958 (21-50) 54.7

31 BALD PRAIRIE TX 1976 (21-50) 54.5

32 FARRAR TX 2002 (21-50) 53.2

33 GOLDEN TREND OK 1945 (21-50) 41.4

34 HALEY TX 1983 (21-50) 43.2

35 LAKE RIDGE WY 1981 (21-50) 17.6

36 RED OAK-NORRIS OK 1910 (21-50) 57.1

37 OAKS TX 1975 (21-50) 36.5

38 FREESTONE TX 1949 (21-50) 80.9

39 DRUNKARDS WASH UT 1989 (21-50) 62.1

40 MOCANE-LAVERNE GAS AREA KS & OK & TX 1946 (21-50) 64.0

41 MAYFIELD NE OK 1951 (21-50) 105.4

42 PANOMA GAS AREA KS 1956 (21-50) 71.7

43 GIDDINGS TX 1960 (21-50) 106.0

44 BELUGA RIVER AK 1962 (21-50) 61.2

45 BUFFALO WALLOW TX 1969 (21-50) 51.5

46 WATONGA-CHICKASHA TREND OK 1948 (21-50) 50.0

47 OVERTON TX 1973 (21-50) 49.0

48 STANDARD DRAW WY 1979 (21-50) 22.5

49 HONDO FP 1969 (21-50) 18.0

50 PINON TX 1982 (21-50) 14.4

Top 50 Volume Subtotal 105,810.6 29,792.6 7,189.1

Top 50 Percentage of U.S. Total 49.6% 49.9% 37.3%
Energy Information Administration

B-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table B2. Top 100 U.S. Fields Ranked by Gas Proved Reserves from Estimated 2005 Field Level Dataa

(Continued)

(Billion Cubic Feet)

Rank Group 2005 Estimated

Discovery Proved Nonproducing Production

Num Field Name Location Year Reserves Reserves Volume

51 KINTA OK 1914 (51-100) 45.7

52 SLIGO LA 1922 (51-100) 46.6

53 STILES RANCH TX 1978 (51-100) 24.3

54 DEW TX 1982 (51-100) 38.2

55 DOWDY RANCH TX 1999 (51-100) 41.7

56 GOMEZ TX 1963 (51-100) 43.3

57 MISSISSIPPI CANYON BLK 383 (KEPLER) FG 1987 (51-100) 0.0

58 WAMSUTTER WY 1997 (51-100) 30.1

59 COOK INLET NORTH AK 1962 (51-100) 44.5

60 SHO-VEL-TUM OK 1905 (51-100) 31.1

61 ECHO SPRINGS WY 1976 (51-100) 30.8

62 PICEANCE CREEK CO 1930 (51-100) 5.9

63 MISSISSIPPI CANYON BLK 778 (THUNDER HORSE) FG 1999 (51-100) 0.0

64 CEDARDALE NE OK 1957 (51-100) 27.2

65 BEAR GRASS TX 1977 (51-100) 27.6

66 EAST BREAKS BLK 602 (NANSEN) FG 1999 (51-100) 67.3

67 TEAGUE TX 1945 (51-100) 30.5

68 NORA VA 1949 (51-100) 2.7

69 WILD ROSE WY 1975 (51-100) 24.4

70 ELK CITY OK 1947 (51-100) 30.1

71 VERDEN OK 1948 (51-100) 27.5

72 MIMMS CREEK TX 1978 (51-100) 47.1

73 BRUFF WY 1969 (51-100) 33.5

74 EXSUN TX 1974 (51-100) 43.1

75 OZONA NE TX 1966 (51-100) 24.7

76 WILBURTON OK 1941 (51-100) 34.7

77 KUPARUK RIVER AK 1969 (51-100) 6.6

78 NACONICHE CREEK TX 1978 (51-100) 9.7

79 OZONA TX 1962 (51-100) 23.1

80 VAQUILLAS RANCH TX 1978 (51-100) 45.6

81 BETHANY TX 1921 (51-100) 29.0

82 WAYNOKA NE OK 1956 (51-100) 18.5

83 CHEYENNE WEST OK 1971 (51-100) 35.6

84 HOLLY LA 1928 (51-100) 22.1

85 WILLOW SPRINGS TX 1938 (51-100) 27.8

86 MOBILE BLK 823 FG 1983 (51-100) 23.9

87 MINDEN TX 1954 (51-100) 20.7

88 BROWN-BASSETT TX 1953 (51-100) 26.4

89 BOONSVILLE TX 1945 (51-100) 27.1

90 HUXLEY TX 1946 (51-100) 15.2

91 CASPIANA LA 1925 (51-100) 14.9

92 MISSISSIPPI CANYON BLK 731 (MENSA) FG 1987 (51-100) 54.1

93 CHARCO TX 1948 (51-100) 29.9

94 CEMENT OK 1916 (51-100) 34.1

95 EAKLY-WEATHERFORD TREND OK 1953 (51-100) 21.0

96 GOLDSMITH TX 1946 (51-100) 16.6

97 VIOSCA KNOLL BLK 956 (RAM-POWELL) FG 1985 (51-100) 71.1

98 STRATTON TX 1937 (51-100) 18.4

99 BLOCKER TX 1954 (51-100) 13.7

100 DAVIDSON RANCH TX 1964 (51-100) 17.4

Top 100 Volume Subtotal 124,975.2 35,807.1 8,614.2

Top 100 Percentage of U.S. Total 58.6% 60.0% 44.7%

aTotal wet gas after lease separation.

Note: The U.S. total production estimate of 19,259 billion cubic feet and the U.S. total reserves estimate of 213,308 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 2005 Annual Report B-7

Table B3. Top 100 U.S. Fields Ranked by Liquids Production from Estimated 2005 Field Level Dataa

(Million Barrels of 42 U.S. Gallons)

Discovery 2005 Estimated

Num Field Name Location Year Production Volume

1 PRUDHOE BAY AK 1967 118.9

2 MISSISSIPPI CANYON BLK 807 (MARS-URSA) FG 1989 67.0

3 WASSON TX 1954 56.2

4 KUPARUK RIVER AK 1969 47.7

5 ALPINE AK 1994 42.9

6 MIDWAY-SUNSET CA 1901 42.4

7 BELRIDGE SOUTH CA 1911 37.4

8 MISSISSIPPI CANYON BLK 383 (KEPLER) FG 1987 33.6

9 KERN RIVER CA 1899 33.0

10 NORTHSTAR AK 1984 22.8

Top 10 Volume Subtotal 501.8

Top 10 Percentage of U.S. Total 26.3%

11 SPRABERRY TREND AREA TX 1952 22.7

12 CEDAR HILLS ND & MT & SD 1951 22.6

13 MISSISSIPPI CANYON BLK 84 (KING/HORN MT) FG 1993 22.5

14 CYMRIC CA 1916 18.5

15 ELK HILLS CA 1919 18.1

16 GREEN CANYON BLK 644 (HOLSTEIN) FG 1999 16.6

17 MILNE POINT AK 1982 16.0

18 ELM COULEE MT 2000 15.9

19 WILMINGTON CA 1935 15.0

20 GARDEN BANKS BLK 387 (LLANO) FG 1990 13.5

Top 20 Volume Subtotal 683.3

Top 20 Percentage of U.S. Total 35.8%

21 SLAUGHTER TX 1937 13.0

22 POINT MCINTYRE AK 1988 12.3

23 VIOSCA KNOLL BLK 786 (PETRONIUS) FG 1996 12.2

24 KELLY-SNYDER TX 1948 11.8

25 LOST HILLS CA 1910 11.4

26 WATTENBERG CO 1970 10.9

27 GARDEN BANKS BLK 783 (MAGNOLIA) FG 1999 9.3

28 EAST BREAKS BLK 602 (NANSEN) FG 1999 9.1

29 YATES TX 1984 8.9

30 MISSISSIPPI CANYON BLK 582 (MEDUSA) FG 2000 8.7

31 GREEN CANYON BLK 826 (MAD DOG) FG 1999 8.6

32 GREEN CANYON BLK 339 (FRONT RUNNER) FG 2001 8.4

33 SEMINOLE TX 1936 8.4

34 LEVELLAND TX 1945 8.4

35 GIDDINGS TX 1960 8.2

36 SHO-VEL-TUM OK 1905 8.1

37 EWING BANK BLK 873 (LOBSTER/OYSTER) FG 1991 8.1

38 TARN AK 1991 8.1

39 GARDEN BANKS BLK 171 (SALSA) FG 1988 7.6

40 VACUUM NM 1929 7.2

41 BOREALIS AK 2001 7.0

42 ENDICOTT AK 1978 6.5

43 HONDO FP 1969 6.2

44 LAKE WASHINGTON LA 1931 6.2

45 GARDEN BANKS BLK 668 (GUNNISON) FG 2000 6.1

46 COWDEN NORTH TX 1930 6.0

47 COALINGA CA 1887 5.9

48 MISSISSIPPI CANYON BLK 773 (DEVILS TOWER) FG 2000 5.4

49 ALAMINOS CANYON BLK 25 (HOOVER) FG 1997 5.3

50 GREEN CANYON BLK 158 (BRUTUS) FG 1992 5.3

Top 50 Volume Subtotal 931.7

Top 50 Percentage of U.S. Total 48.9%
Energy Information Administration

B-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table B3. Top 100 U.S. Fields Ranked by Liquids Production from Estimated 2005 Field Level Dataa

(Continued)

(Million Barrels of 42 U.S. Gallons)

Discovery 2005 Estimated

Num Field Name Location Year Production Volume

51 RANGELY CO 1902 5.2

52 GOLDSMITH TX 1946 5.1

53 SALT CREEK TX 1968 4.9

54 MCELROY TX 1926 4.9

55 PESCADO FP 1970 4.9

56 HOBBS NM 1928 4.8

57 MAIN PASS BLK 61 FG 2001 4.6

58 GREEN CANYON BLK 243 (ASPEN) FG 2001 4.5

59 EAST TEXAS TX 1930 4.5

60 FULLERTON TX 1942 4.5

61 WEST SAK AK 1969 4.4

62 ROBERTSON NORTH TX 1956 4.1

63 ANTON-IRISH TX 1944 4.1

64 VENTURA CA 1916 3.9

65 SACATE FP 1970 3.9

66 EUGENE IS BLK 330 FG 1971 3.9

67 BELRIDGE NORTH CA 1912 3.7

68 GREATER ANETH UT 1956 3.6

69 PINEDALE WY 1955 3.5

70 VIOSCA KNOLL BLK 990 (POMPANO) FG 1981 3.5

71 SAN ARDO CA 1947 3.5

72 MEANS TX 1934 3.5

73 MONUMENT BUTTE UT 1964 3.4

74 AURORA AK 1969 3.3

75 NIAKUK AK 1984 3.0

76 INGLEWOOD CA 1924 2.9

77 ALTAMONT-BLUEBELL UT 1949 2.9

78 DOLLARHIDE NM & TX 1945 2.9

79 LISBURNE AK 1967 2.9

80 MCARTHUR RIVER AK 1965 2.8

81 HOWARD-GLASSCOCK TX 1925 2.8

82 ORION AK 2002 2.8

83 OREGON BASIN WY 1912 2.7

84 JONAH WY 1977 2.6

85 JO-MILL TX 1953 2.6

86 MCKITTRICK CA 1887 2.6

87 GRAYBURG JACKSON NM 1929 2.6

88 CEDAR HILLS MT 1951 2.6

89 POINT PEDERNALES FP 1983 2.5

90 WASSON 72 TX 1940 2.5

91 WESTBROOK TX 1920 2.5

92 BROOKELAND TX 1962 2.5

93 HUNTINGTON BEACH CA 1964 2.5

94 HAWKINS TX 1940 2.5

95 CEDAR LAKE TX 1939 2.5

96 WEST DELTA BLK 30 FG 1949 2.4

97 FUHRMAN-MASCHO TX 1930 2.4

98 SALT CREEK WY 1917 2.4

99 SHIP SHOAL BLK 169 FG 1960 2.3

100 VIOSCA KNOLL BLK 825 (NEPTUNE) FG 1988 2.3

Top 100 Volume Subtotal 1,099.7

Top 100 Percentage of U.S. Total 57.7%

aIncludes lease condensate.

Notes: The U.S. total production estimate of 1,907 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 2005 Annual Report B-9

1 SAN JUAN BASIN GAS AREA CO & NM 1927 1,397.0

2 NEWARK EAST TX 2002 496.5

3 HUGOTON GAS AREA KS & OK & TX 1922 480.7

4 PINEDALE WY 1955 457.3

5 PRB COALBED WY 1992 336.1

6 JONAH WY 1977 273.1

7 CARTHAGE TX 1981 214.1

8 PRUDHOE BAY AK 1967 193.0

9 WATTENBERG CO 1970 179.1

10 FOGARTY CREEK WY 1975 166.4

Top 10 Volume Subtotal 4,193.2

Top 10 Percentage of U.S. Total 21.8%

11 ANTRIM MI 1965 164.9

12 MADDEN WY 1968 163.7

13 LOWER MOBILE BAY AREA AL & FG 1979 139.1

14 ELK HILLS CA 1919 136.2

15 NATURAL BUTTES UT 1940 133.6

16 RATON BASIN GAS AREA CO & NM 1998 120.9

17 VERNON LA 1967 115.1

18 GIDDINGS TX 1960 106.0

19 MAYFIELD NE OK 1951 105.4

20 OAK HILL TX 1958 97.9

Top 20 Volume Subtotal 5,476.0

Top 20 Percentage of U.S. Total 28.4%

21 MAMM CREEK CO 1959 95.5

22 ELM GROVE LA 1916 93.6

23 MISSISSIPPI CANYON BLK 807 (MARS-URSA) FG 1989 93.2

24 STRONG CITY DISTRICT OK 1966 81.5

25 FREESTONE TX 1949 80.9

26 SPRABERRY TREND AREA TX 1952 78.7

27 WASSON TX 1954 78.1

28 SAWYER TX 1960 75.1

29 INDIAN BASIN NM 1963 73.0

30 PANOMA GAS AREA KS 1956 71.7

31 VIOSCA KNOLL BLK 956 (RAM-POWELL) FG 1985 71.1

32 EAST BREAKS BLK 602 (NANSEN) FG 1999 67.3

33 MOCANE-LAVERNE GAS AREA KS & OK & TX 1946 64.0

34 GRAND VALLEY CO 1985 63.0

35 DRUNKARDS WASH UT 1989 62.1

36 BELUGA RIVER AK 1962 61.2

37 RED OAK-NORRIS OK 1910 57.1

38 RULISON CO 1958 54.7

39 OAKWOOD VA 1990 54.5

40 BALD PRAIRIE TX 1976 54.5

41 MISSISSIPPI CANYON BLK 731 (MENSA) FG 1987 54.1

42 FARRAR TX 2002 53.2

43 BUFFALO WALLOW TX 1969 51.5

44 YATES TX 1984 51.3

45 PARACHUTE CO 1985 51.3

46 WATONGA-CHICKASHA TREND OK 1948 50.0

47 OVERTON TX 1973 49.0

48 SAVELL TX 1997 47.3

49 MIMMS CREEK TX 1978 47.1

50 SLIGO LA 1922 46.6

Top 50 Volume Subtotal 7,407.7

Top 50 Percentage of U.S. Total 38.5%

Table B4. Top 100 U.S. Fields Ranked by Gas Production from Estimated 2005 Field Level Dataa

(Billion Cubic Feet)

Discovery 2005 Estimated

Num Field Name Location Year Production Volume
Energy Information Administration

B-10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table B4. Top 100 U.S. Fields Ranked by Gas Production from Estimated 2005 Field Level Dataa

(Continued)

(Billion Cubic Feet)

Discovery 2005 Estimated

Num Field Name Location Year Production Volume

51 KINTA OK 1914 45.7

52 VAQUILLAS RANCH TX 1978 45.6

53 BIG SANDY KY & WV 1926 45.6

54 COOK INLET NORTH AK 1962 44.5

55 LA PERLA TX 1999 44.3

56 GOMEZ TX 1963 43.3

57 HALEY TX 1983 43.2

58 EXSUN TX 1974 43.1

59 DOWDY RANCH TX 1999 41.7

60 GOLDEN TREND OK 1945 41.4

61 DEW TX 1982 38.2

62 OAKS TX 1975 36.5

63 CHEYENNE WEST OK 1971 35.6

64 GARDEN BANKS BLK 668 (GUNNISON) FG 2000 35.2

65 WILBURTON OK 1941 34.7

66 CEMENT OK 1916 34.1

67 HAYNES TX 1999 34.0

68 BRUFF WY 1969 33.5

69 MISSISSIPPI CANYON BLK 657 (COULOMB) FG 1988 33.1

70 PANOLA OK 1964 31.6

71 GARDEN BANKS BLK 877 (RED HAWK) FG 2003 31.3

72 SHO-VEL-TUM OK 1905 31.1

73 ECHO SPRINGS WY 1976 30.8

74 TEAGUE TX 1945 30.5

75 ELK CITY OK 1947 30.1

76 BLOCK 31 TX 1945 30.1

77 WAMSUTTER WY 1997 30.1

78 CHARCO TX 1948 29.9

79 BETHANY TX 1921 29.0

80 LAKE PASTURE TX 1939 28.5

81 SOONER TREND OK 1942 28.4

82 GARDEN BANKS BLK 171 (SALSA) FG 1988 28.2

83 WILLOW SPRINGS TX 1938 27.8

84 BEAR GRASS TX 1977 27.6

85 VERDEN OK 1948 27.5

86 CEDARDALE NE OK 1957 27.2

87 BOONSVILLE TX 1945 27.1

88 JUDGE DIGBY LA 1977 27.0

89 BROWN-BASSETT TX 1953 26.4

90 ADA LA 1944 26.3

91 AMACKER-TIPPETT TX 1953 25.7

92 KNOX OK 1916 25.4

93 LOS MOGOTES TX 1960 25.1

94 OZONA NE TX 1966 24.7

95 WILD ROSE WY 1975 24.4

96 STILES RANCH TX 1978 24.3

97 MOBILE BLK 823 FG 1983 23.9

98 CEDAR CREEK ND 1929 23.8

99 BOONEVILLE AR 1958 23.6

100 OZONA TX 1962 23.1

Top 100 Volume Subtotal 9,011.3

Top 100 Percentage of U.S. Total 46.8%

aTotal wet gas after lease separation.

Note: The U.S. total production estimate of 19,259 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 2005 Annual Report B-11

Table B5. The One Hundred Largest Fields in the U.S. as of December 31, 1979

(Thousands of barrels of 42 U.S. Gallons)

Cumulative Proved Crude Original-Oil-InYear of Production Oil Reserves Place Estimated

Rank Field Location Discovery 12/31/79 12/31/79 12/31/79

1 Prudhoe Bay Alaska 1968 982,397 8,417,603 23,800,000

2 Yates Texas District 8 1926 769,050 1,230,950 4,000,000

3 East Texas Texas District 6 1930 4,635,076 964,924 7,000,000

4 Wasson Texas District 8A 1936 1,301,678 599,402 4,747,792

5 Elk Hills Cal.-San Joaquin 1919 435,874 576,506 2,780,321

6 Kern River Cal.-San Joaquin 1899 793,365 436,635 4,062,000

7 Wilmington Cal.-Los Angeles 1936 1,952,447 424,553 9,693,100

8 Midway-Sunset Cal.-San Joaquin 1901 1,423,402 406,398 6,190,000

9 Kuparuk River Alaska 1969 0 320,000 3,200,000

10 Slaughter Texas District 8A 1936 798,413 276,487 1,810,000

Top 10 Total 13,091,702 13,653,458 67,283,213

Top 10 Percentage of U.S. 10.8% 50.5% 14.6%

11 Sho-Vel-Tum Oklahoma 1915 1,143,712 229,730 3,100,000

12 Seminole Texas District 8A 1936 308,661 227,683 1,148,180

13 Kelly-Snyder Texas District 8A 1948 1,053,195 212,877 2,160,886

14 Tom O'Connor Texas District 2 1934 604,245 195,206 1,376,019

15 Beta Cal.-Los Angeles 1977 0 150,000 625,000

16 Belridge South Cal.-San Joaquin 1911 262,054 137,946 1,400,000

17 Levelland Texas District 8A 1945 313,690 131,110 1,012,000

18 Hastings, West Texas District 3 1934 519,570 130,796 925,129

19 South Pass, Block 61 Louisiana-South 1968 58,188 126,873 456,900

20 Panhandle Texas District 10 1921 1,333,374 116,626 6,060,000

Top 20 Total 18,688,391 15,312,305 85,547,327

Top 20 Percentage of U.S. 15.5% 56.6% 18.6%

21 Hawkins Texas District 6 1940 699,323 108,945 1,355,909

22 San Ardo Cal.-Coastal 1947 336,788 103,212 1,450,000

23 Rangely Colorado 1902 615,898 100,369 1,681,575

24 Cowden, North Texas District 8 1930 355,690 95,005 1,208,750

25 Hondo Cal.-Coastal 1969 0 94,000 606,300

26 McArthur River Alaska 1965 418,926 92,074 1,336,000

27 Conroe Texas District 3 1931 642,022 91,360 1,206,568

28 Tule Elk Cal.-San Joaquin 1973 1,861 88,139 300,000

29 South Pass, Block 27 Louisiana-South 1954 298,320 85,747 880,650

30 Miss. Canyon, Block 194 Louisiana-South 1975 915 84,363 189,935

31 Spraberry Trend Texas Dist. 7C, 8, 8A 1949 485,814 83,328 8,888,250

32 Jay Florida & Alabama 1970 262,917 83,022 728,292

33 Mount Poso Cal.-San Joaquin 1926 194,151 82,099 498,750

34 Bay Marchand, Block 2 Louisiana-South 1949 533,545 80,809 1,570,571

35 Fullerton Texas District 8 1941 257,973 78,814 1,329,410

36 Santa Clara Offshore Cal.-Coastal 1973 0 78,500 349,000

37 Eugene Is., Block 330 Louisiana-South 1971 167,970 76,361 485,713

38 Huntington Beach Cal.-Los Angeles 1920 990,674 74,326 6,000,000

39 So. Marsh Is., Block 130 Louisiana-South 1973 25,758 70,205 202,000

40 Salt Creek Texas District 8A 1950 178,486 69,514 471,000

41 Salt Creek & S. Salt Creek Wyoming 1906 576,534 66,626 1,517,580

42 Vacuum New Mexico 1929 318,925 62,539 1,425,726

43 Oregon Basin Wyoming 1927 296,371 62,075 905,600

44 Hobbs New Mexico 1928 248,927 59,923 841,469

45 Ventura Cal.-Coastal 1917 841,842 58,158 3,500,000

46 Dos Cuadras Cal.-Coastal 1968 158,359 56,641 750,000

47 Delhi Louisiana-North 1944 193,577 55,956 467,178

48 Elk Basin Wyo. & Mont. 1915 467,343 55,847 997,601

49 South Pass, Block 24 Louisiana-South 1950 419,229 55,082 1,004,672

50 Ship Shoal, Block 207 Louisiana-South 1967 69,381 54,259 287,779

Top 50 Total 28,745,910 17,619,603 127,983,605

Top 50 Percentage of U.S. 23.8% 65.1% 27.8%
Energy Information Administration

B-12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

51 Sooner Trend Oklahoma 1942 238,713 53,617 1,202,778

52 Anton Irish Texas District 8A 1944 124,390 53,610 450,000

53 Midland Farms Texas District 8 1945 179,620 52,891 719,550

54 Coalinga Cal.-San Joaquin 1887 662,299 51,701 4,505,000

55 Goldsmith Texas District 8 1934 579,930 49,357 1,823,130

56 Thompson Texas District 3 1931 337,750 49,141 732,052

57 Wichita County Regular Texas District 9 1910 525,650 48,350 2,000,000

58 Lost Soldier-Wertz Wyoming 1916 241,247 48,323 663,877

59 Howard Glasscock Texas District 8 1925 341,009 47,726 1,421,100

60 Diamond M Texas District 8A 1948 221,747 45,991 616,510

61 Grand Isle, Block 43 Louisiana-South 1956 227,539 45,599 483,437

62 Eunice New Mexico 1929 334,198 44,601 2,000,260

63 Main Pass, Block 41 Louisiana-South 1957 176,209 41,676 453,990

64 Neches Texas District 6 1953 81,040 40,984 198,073

65 Granite Point Alaska 1965 79,135 38,865 413,000

66 Talco Texas District 6 1936 251,984 38,016 739,000

67 Painter Reservoir Wyoming 1977 1,848 37,652 132,000

68 Andector Texas District 8 1946 151,853 37,387 301,000

69 West Delta, Block 30 Louisiana-South 1954 388,266 37,146 642,926

70 Caillou Island Louisiana-South 1930 567,124 37,141 1,133,163

71 McKittrick Cal.-San Joaquin 1887 230,569 37,131 994,170

72 McElroy Texas District 8 1926 473,218 36,986 2,544,167

73 Cat Canyon E Cal.-Coastal 1908 61,468 36,382 369,000

74 Lake Pasture Texas District 2 1953 62,420 35,964 251,818

75 Empire New Mexico 1924 186,522 34,628 390,202

76 Middle Ground Shoal Alaska 1962 124,740 33,974 563,000

77 Brea-Olinda Cal.-Los Angeles 1897 359,075 33,925 1,400,000

78 Fairway Texas Districts 5 & 6 1960 159,487 33,505 414,216

79 So. Marsh Is., Block 128 Louisiana-South 1974 21,587 33,413 123,000

80 Ryckman Creek Wyoming 1976 3,798 33,202 95,000

81 South Pass, Block 62 Louisiana-South 1965 77,074 33,170 208,533

82 Van Texas District 5 1929 481,125 31,836 892,820

83 Cowden, South Texas District 8 1932 155,913 31,164 763,250

84 Cogdell Texas District 8 1949 234,193 30,987 523,818

85 Golden Trend Oklahoma 1946 426,931 30,724 1,170,000

86 Yowlumne Cal.-San Joaquin 1974 29,541 30,459 220,000

87 Cymric Cal.-San Joaquin 1916 147,756 30,098 852,726

88 Santa Maria Valley Cal.-Coastal 1934 175,216 29,784 1,127,000

89 West Delta, Block 79 Louisiana-South 1968 80,496 29,692 206,954

90 Giddings Texas District 3 1960 11,382 29,258 505,333

91 Webster Texas District 3 1937 517,482 29,104 740,699

92 Smackover Arkansas 1922 525,555 29,089 1,512,127

93 West Ranch Texas District 2 1934 332,799 28,588 693,527

94 Long Beach Cal.-Los Angeles 1921 892,802 28,373 3,317,300

95 Prentice Texas District 8A 1950 116,789 28,211 559,202

96 Good Hope Louisiana-South 1944 64,710 28,111 151,260

97 Teapot Dome Wyoming 1923 13,739 28,061 275,000

98 Baxterville Mississippi 1944 193,641 27,844 680,500

99 E. Kansas Stripper Kansas 1919 317,631 27,704 881,814

100 Main Pass Blk 306 Louisiana-South 1969 54,170 27,649 248,486

Total 100 Total 40,989,290 19,458,393 171,289,373

Top 100 Percentage of U.S. 34.0% 71.9% 37.2%

Total United States 120,730,299 27,051,289 460,022,500

Table B5. The One Hundred Largest Fields in the U.S. as of December 31, 1979 (Continued)

(Thousands of barrels of 42 U.S. Gallons)

Cumulative Proved Crude Original-Oil-InYear of Production Oil Reserves Place Estimated

Rank Field Location Discovery 12/31/79 12/31/79 12/31/79

Source: American Petroleum Institute, Reserves of Crude Oil, Natural Gas Liquids, and Natural Gas in the United States and Canada as of December 31, 1979, Volume 34, June 1980.
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."{44}

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 2005 Annual Report C-1
Energy Information Administration

C-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table C1. U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids,

in Metric Units, 1995 – 2005

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)

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

2005 35.1 90.5 125.6 44.2 128.0 32.6 6.5 167.1 275.5 3,459.1 61.4

Dry Natural Gas (billion cubic meters)

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 -3.23 21.07 17.84 52.22 515.31 21.49 34.15 570.95 542.78 5,451.36 98.23

2005 53.43 76.43 129.86 72.04 596.07 26.67 34.21 656.95 522.67 5,787.54 336.18

Natural Gas Liquids (million cubic meters)

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

2005 -14.1 3.3 -10.8 24.8 137.2 5.1 6.7 149.0 125.3 1,298.1 37.7

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, 1995–2005 annual reports, DOE/EIA–0216.{19–28}
Appendix D

Historical Reserves Statistics

Energy Information Administration 

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report D-1

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 2005. 

All historical statistics included have previously been published in the annual reports of 1977 through 2004 of the 

EIA publication U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves Annual Report, DOE EIA-0216.{1-28} 

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

D-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table D1. U.S. Proved Reserves of Crude Oil, 1976–2005

(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

2005 221 569 790 278 805 205 41 1,051 1,733 21,757 386

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 2005 annual reports, DOE/EIA-0216.{1-28}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report D-3

Table D2. U.S. Lower 48 Proved Reserves of Crude Oil, 1976–2005

(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

2005 223 467 690 278 749 205 41 995 1,421 17,586 542

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 2005 annual reports, DOE/EIA-0216.{1-28}
Energy Information Administration

D-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table D3. U.S. Proved Reserves of Dry Natural Gas, 1976–2005

(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

2005 1,887 2,699 4,856 2,544 21,050 942 1,208 23,200 18,458 204,385 11,872

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 2005 annual reports, DOE/EIA-0216.{1-28}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report D-5

Table D4. U.S. Lower 48 Proved Reserves of Dry Natural Gas, 1976–2005

(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

2005 1,889 2,560 4,449 2,542 20,988 920 1,198 23,106 17,989 196,214 12,108

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 2005 annual reports, DOE/EIA-0216.{1-28}
Energy Information Administration

D-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table D5. U.S. Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–2005

(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

2005 1,693 2,715 4,408 2,674 22,069 973 1,243 24,285 19,259 213,308 12,108

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 2005 annual reports, DOE/EIA-0216.{3-28}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report D-7

Table D6. U.S. Lower 48 Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–2005

(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

2005 1,694 2,575 4,269 2,672 22,007 951 1,233 24,191 18,788 205,071 12,344

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 2005 annual reports, DOE/EIA-0216.{3-28}
Energy Information Administration

D-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table D7. U.S. Proved Reserves of Natural Gas Liquids, 1978–2005

(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

2005 -89 21 -68 156 863 32 42 937 788 8,165 237

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 2005 annual reports, DOE/EIA-0216.{3-28}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report D-9

Table D8. U.S. Lower 48 Proved Reserves of Natural Gas Liquids, 1978–2005

(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

2005 -89 21 -68 156 863 32 42 937 771 7,813 254

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 2005 annual reports, DOE/EIA-0216.{3-28}
Energy Information Administration

D-10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2005

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

2005 409 342 67 305 104 75.0

Reserves

1992 1,835 1,643 192 557 1,278 30.4

1993 2,072 1,880 192 824 1,248 39.8

1994 2,127 1,922 205 877 1,250 41.2

1995 2,518 2,269 249 1,241 1,277 49.3

1996 2,567 2,357 210 1,311 1,256 51.1

1997 2,949 2,587 362 1,682 1,267 57.0

1998 2,793 2,483 310 1,611 1,182 57.8

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

2005 4,042 3,851 191 3,272 770 81.0
Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2005

(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

2005 2,968 2,056 912 1,070 1,898 36.1

Reserves

1992 27,050 20,006 7,044 3,273 23,777 12.1

1993 26,463 19,751 6,712 3,495 22,968 13.2

1994 27,626 21,208 6,418 4,772 22,854 17.3

1995 28,229 21,664 6,565 5,811 22,418 20.6

1996 28,153 22,119 6,034 6,389 21,764 22.7

1997 28,455 22,428 6,027 7,491 20,964 26.3

1998 26,937 21,261 5,676 7,575 19,362 28.1

1999 26,062 20,172 5,890 7,726 18,336 29.6

2000 26,891 20,466 6,425 8,731 18,160 32.5

2001 27,100 20,290 6,810 11,229 15,871 41.4

2002 25,347 19,113 6,234 10,540 14,807 41.6

2003 22,522 17,168 5,354 10,041 12,481 44.6

2004 19,288 15,144 4,144 8,591 10,698 44.5

2005 17,427 14,073 3,354 8,042 9,385 46.1

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report D-11
Energy Information Administration

D-12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2005

(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 32.9

2005 123 98 25 44 79 35.8

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 32.9

2005 688 603 85 248 440 36.0
Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2005

(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

2005 2,906 1,997 909 1,069 1,837 36.8

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

2005 17,007 13,665 3,342 8,043 8,964 47.3

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report D-13
Energy Information Administration

D-14 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2005

(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

2005 62 39 23 26 36 41.9

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

2005 272 196 76 104 92 38.2

aIncludes Federal Offshore Alabama.

Source: Based on data reported on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves.”
Table D10. 2005 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 (million bbls) (million bbls) (bcf) (bcf) (bcf)

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 595 0 542 14 556

Lower 48 States . . . . . . . . . . . . . . . . . . . . . . . . . . 5,096 430 52,845 6,257 59,102

Alabama. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 2 161 2 163

Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 0 410 10 420

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 455 0 222 828 1,050

Coastal Region Onshore. . . . . . . . . . . . . . . . . . 70 0 2 47 49

Los Angeles Basin Onshore . . . . . . . . . . . . . . . 112 0 0 71 71

San Joaquin Basin Onshore . . . . . . . . . . . . . . . 238 0 220 681 901

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . 35 0 0 29 29

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 36 4,336 654 4,990

Florida . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 0 0 0 0

Kansas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 0 161 5 166

Kentucky . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 0 113 0 113

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193 35 3,547 274 3,821

North . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 9 2,102 39 2,141

South Onshore . . . . . . . . . . . . . . . . . . . . . . . . . 148 24 1,285 207 1,492

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . 28 2 160 28 188

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 2 396 25 421

Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87 0 104 6 110

Montana. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88 0 85 25 110

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 171 10 4,049 272 4,321

East. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 171 8 593 269 862

West . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 2 3,456 3 3,459

New York . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 26 0 26

North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56 1 24 30 54

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 0 124 8 132

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101 47 4,454 72 4,526

Pennsylvania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 420 36 456

Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 828 101 17,096 1,106 18,202

RRC District 1 . . . . . . . . . . . . . . . . . . . . . . . . . . 15 2 352 16 368

RRC District 2 Onshore . . . . . . . . . . . . . . . . . . 16 3 564 34 598

RRC District 3 Onshore . . . . . . . . . . . . . . . . . . 19 22 845 59 904

RRC District 4 Onshore . . . . . . . . . . . . . . . . . . 17 30 3,429 44 3,473

RRC District 5 . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 3,981 19 4,000

RRC District 6 . . . . . . . . . . . . . . . . . . . . . . . . . . 3 15 2,684 24 2,708

RRC District 7B. . . . . . . . . . . . . . . . . . . . . . . . . 3 0 312 5 317

RRC District 7C. . . . . . . . . . . . . . . . . . . . . . . . . 31 2 1,151 132 1,283

RRC District 8 . . . . . . . . . . . . . . . . . . . . . . . . . . 333 1 1,354 303 1,657

RRC District 8A. . . . . . . . . . . . . . . . . . . . . . . . . 374 1 3 407 410

RRC District 9 . . . . . . . . . . . . . . . . . . . . . . . . . . 9 2 1,097 15 1,112

RRC District 10 . . . . . . . . . . . . . . . . . . . . . . . . . 6 21 1,290 46 1,336

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 34 2 36

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 13 1,379 78 1,457

Virginia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 696 0 696

West Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 586 1 587

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 249 49 7,847 64 7,911

Federal Offshoreb . . . . . . . . . . . . . . . . . . . . . . . . . 2,687 134 6,581 2,761 9,342

Pacific (California). . . . . . . . . . . . . . . . . . . . . . . 32 8 48 50 98

Gulf of Mexico (Louisiana)b . . . . . . . . . . . . . . . 2,591 95 5,235 2,578 7,813

Gulf of Mexico (Texas) . . . . . . . . . . . . . . . . . . . 64 31 1,298 133 1,431

Miscellaneousc . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 0 28 0 28

U.S. Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,691 430 53,387 6,271 59,658

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," 2005.

Energy Information Administration D-15

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 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 2005 by crude oil or

natural gas well operators who were active as of

December 31, 2005. 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 1998 and 2005, and depicts

the number of active operators, with 2002 showing the

largest in the series. The 2005 sampling frame consisted

of 172 Category I, 522 Category II, 195 Category III

Certainty, and 14,269 Category III Noncertainty

operators, for a total of 15,158 active operators. The

survey sample consisted of 889 operators selected with

certainty that included all of the Category I and II

Certainty operators, the 195 smaller operators that

were selected with certainty because of their size in

relation to the area or areas in which they operated, and

505 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 2005 survey is

summarized in Table E2. EIA makes a considerable

effort to gain responses from all operators. About 3.4

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 47 nonoperators, 8 had successor operators that had

taken over the production of the nonoperator. These

successor operators were subsequently sampled. The

overall response rate for the 2005 survey was 96

percent. For the 51 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 2005 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 2005 Annual Report

Table E1. Comparison of the EIA-23 Sample and Sampling Frame, 1997-2005

Number of Operators

Operator Category 1998 1999 2000 2001 2002 2003 2004 2005

Certainty

Category I. . . . . . . . . . . . . 178 177 175 179 176 164 164 172

Category II . . . . . . . . . . . . 420 399 436 485 480 512 532 522

Category III. . . . . . . . . . . . 862 648 854 559 388 399 275 195

Sampled ............. 1,460 1,224 1,465 1,223 1,044 1,075 971 889

Percent Sampled . . . . . . . 100 100 100 100 100 100 100 100

Noncertainty

Sampled .............. 1,459 1,305 1,311 644 533 479 370 505

Percent Sampled ....... 7 7 7 3 3 3 2 4

Total

Active Operators........ 23,620 22,089 22,102 22,519 22,823 20,923 20,670 15,158

Not Sampled .......... 20,701 19,560 19,326 20,652 21,246 19,369 19,329 13,764

Sampled .............. 2,919 R2,529 2,776 1,867 1,577 1,554 1,341 1,394

Percent Sampled . . . . . . . 12 R11 13 8 7 7 7 9

R=Revised data.

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

Table E2. Form EIA-23 Survey Response Statistics, 2005

Original Netb Responding Nonrespondinge

Sample Successora Category Non-c Adjustedd Operators Operators

Operator Category Selected Operators Changes operators Sample Number Percent Number Percent

Certainty

Category I . . . . . . . 172 0 7 -6 173 171 98.8 2 1.2

Category II . . . . . . . 522 7 -40 -22 467 444 95.1 23 4.9

Category III . . . . . . . 195 0 44 -7 232 224 96.6 8 3.4

Subtotal. . . . . . . . . 889 7 11 -35 872 839 96.2 33 3.8

Noncertainty . . . . . . . . 505 1 -11 -12 483 465 96.3 18 3.7

Total ............ 1,394 8 0 -47 1,355 1,304 96.2 51 3.8

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 51 operators (2 Category I operators, 23 Category II operators, 8 Category III operators, and 18 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” 2005.
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 2005, in December 2005, was the 24th annual

report and reflected data collected through December

2005. 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 2005, Form EIA-23 National estimates of

production were 1,907 million barrels for crude oil and

lease condensate or 17 million barrels (less than 1

percent) higher than that reported in the Petroleum

Supply Annual 2005 for crude oil and lease condensate

(1,890 million barrels). Form EIA-23 National estimates

of production for dry natural gas were 18,458 billion

cubic feet, 214 billion cubic feet (less than 2 percent)

higher than the Natural Gas Monthly, October 2006 for

2005 dry natural gas production (18,244 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 HPDI, LLC., 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 2005 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, 2005. Of these, 15,158

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 2005 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, 2006. In

addition, plant operators whose plants were shut down

or dismantled during 2005 were required to complete

forms for the portion of 2005 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

222 operators of 489 plants were sent forms. This

number included 4 new plants, 3 reactivated plants,

and 12 successor plants, all identified after the initial

2005 survey mailing. A total of 18 plants were reported

as nonoperating according to the Form EIA-64A

Energy Information Administration

E-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table E3. Summary of the 2005 Operator Frame

Activity, Form EIA-23

Total 2004 Operator Frame............. 68,616

Operators....................... 20,670

Nonoperators.................... 47,946

Changes to 2004 Operator Status...... 8,020

From Nonoperator to Operatora . . . . . 625

From Operator to Nonoperator ...... 6,766

New Operators . . . . . . . . . . . . . . . . . . 629

No Changes to 2004 Operator Status . . . 61,347

Operators....................... 14,265

Nonoperators.................... 47,082

Additions to 2004 Operator Frame ..... 0

Operator ....................... 0

Nonoperator..................... 0

Total 2005 Operator Frame............ 68,616

Operators....................... 15,158

Nonoperators.................... 53,458

a

Includes operator frame activity through December 31, 2005.

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.
definition. For the 18th 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 2005 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 2005,

the Form EIA-64A National estimates (Table E4) were

1 percent (6,819 thousand barrels) lower than the

Petroleum Supply Annual 2005 volume of 626,703

thousand barrels 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 2005 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, 2006.

Energy Information Administration

E-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table E5. Form EIA-64A 200554 Plant Frame Activity

Frame as of 2004 survey mailing . . . . . . . 488

Additions . . . . . . . . . . . . . . . . . . . 86

Deletions . . . . . . . . . . . . . . . . . . . –85

Frame as of 2005 survey mailing . . . . . . . 489

Note: Includes operator frame activity through February 15, 2006.

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

Table E4. Natural Gas Processed and Liquids Extracted at Natural Gas Processing Plants, 2005

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 .................. 3,089,229 0 0 3,089,229 23,700

Alabama................. 31,268 222,739 1,150 255,157 9,748

Arkansas ................ 16,756 0 0 16,756 177

California ................ 225,532 698 0 226,230 11,101

Colorado ................ 730,948 0 0 730,948 25,603

Florida .................. 2,069 0 1,515 3,584 359

Kansas.................. 354,621 0 122,035 476,656 22,165

Kentucky ................ 38,792 0 0 38,792 1,411

Louisiana ................ 918,697 1,608,939 0 2,527,636 73,035

Michigan ................ 34,545 0 0 34,545 2,631

Mississippi ............... 4,773 287,250 0 292,023 10,076

Montana................. 10,057 0 0 10,057 851

North Dakota ............. 63,240 0 0 63,240 5,250

New Mexico .............. 893,586 0 0 893,586 69,261

Oklahoma ............... 862,602 0 2,809 865,411 59,958

Texas................... 3,742,719 0 38,846 3,781,565 249,001

Utah .................... 183,490 0 4,034 187,524 2,250

West Virginia ............. 100,118 0 30,137 130,255 5,676

Wyoming ................ 1,261,446 0 16,641 1,278,087 47,024

Miscellanousa ............ 14,399 0 0 14,399 607

Total ................... 12,578,887 2,119,626 217,167 14,915,680 619,884

aIncludes Illinois, Ohio, and Pennsylvania.

Source: Form EIA-64A, “Annual Report of the Origin of Natural Gas Liquids Production,” 2005
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 2004. 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

2004 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

2005 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 2004 for any product class.

4 percent for each State/subdivision having less

than 1 percent of estimated U.S. reserves or

production in 2004 (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 2004.

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

2004, and additionally, all coalbed methane and

Federal Offshore operators.

Category III - Small Operators: Operators who

produced less than the Category II operators in

2004.

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 2005 Annual Report F-1
Table F1. 2005 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 36 3 6 0.040 0.025

Alaska 9 0 0

Arkansas 63 6 16 0.040 0.025

California - Coastal Region Onshore 16 3 2 0.080 0.080

California - Los Angeles Basin Onshore 13 3 3 0.010 0.010

California - San Joaquin Basin Onshore 42 3 6 0.025 0.040

Colorado 116 1 19 0.025 0.010

Florida - Onshore 4 0 0 0.025 0.025

Illinois 26 16 33 0.040 0.040

Indiana 21 4 28 0.040 0.080

Kansas 161 55 76 0.040 0.080

Kentucky 26 5 15 0.025 0.010

Louisiana-North 105 18 25 0.040 0.040

Louisiana-South Onshore 175 14 30 0.010 0.010

Michigan 37 5 1 0.010 0.010

Mississippi - Onshore 80 4 19 0.040 0.040

Montana 65 7 11 0.040 0.040

Nebraska 19 1 10 0.040 0.040

New Mexico - East 151 1 28 0.040 0.080

New Mexico - West 54 1 5 0.025 0.025

New York 15 4 10 0.025 0.010

North Dakota 60 2 9 0.080 0.040

Ohio 18 34 15 0.040 0.040

Oklahoma 262 118 104 0.040 0.040

Pennsylvania 43 26 19 0.025 0.025

Texas - RRC District 1 116 3 31 0.040 0.040

Texas - RRC District 2 Onshore 157 1 27 0.025 0.025

Texas - RRC District 3 Onshore 231 4 35 0.040 0.025

Texas - RRC District 4 Onshore 182 0 27 0.025 0.025

Texas - RRC District 5 94 1 10 0.040 0.010

Texas - RRC District 6 152 5 27 0.040 0.010

Texas - RRC District 7B 130 18 69 0.025 0.010

Texas - RRC District 7C 144 2 46 0.025 0.025

Texas - RRC District 8 186 0 47 0.040 0.025

Texas - RRC District 8A 157 0 43 0.010 0.010

Texas - RRC District 9 129 6 59 0.010 0.040

Texas - RRC District 10 146 18 37 0.025 0.025

Utah 54 1 2 0.040 0.010

Virginia 19 0 1 0.040 0.025

West Virginia 35 27 13 0.080 0.040

Wyoming 157 1 13 0.040 0.025

Offshore Areas 328 0 2 0.025 0.025

Other Statesa 49 8 2 0.080 0.080

Total b889 429 b345 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 9 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 2005 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 483 operators sampled proportional to size

(Table E2) that responded as Category III noncertainty

operators. Only 108 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 2005 Annual Report F-3
sampled in those states. The remaining 375

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

(Table F2-F5).

The data reported by operator category on Form

EIA-23 and data imputed and estimated for report year

2005 are summarized in Tables F2, F3, F4, and F5. The

reported data in Table F2 shows that those responding

operators accounted for 93.0 percent of the published

production for wet natural gas and 94.9 percent of the

reserves shown in Table 9. Data shown in Table F3

indicate that those responding operators accounted for

94.3 percent of the nonassociated natural gas

production and 95.2 percent of the reserves published

in Table 10. The reported data shown in Table F4

indicate that those responding operators accounted for

89.3 percent of published crude oil production and 92.7

percent of the reserves shown in Table 6. Additionally,

Table F5 indicates that those responding operators

accounted for 96.0 percent of the published production

and 95.6 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 2005 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report F-5

Table F2. Summary of Form EIA-23 Reported, Imputed, and Estimated Natural Gas Data for 2005,

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 . . . . . . . . . . . . . . . 171 444 224 465 10,758 12,062

Proved Reserves as of 12/31/04 . . . . . . 177,781,473 12,857,956 950,248 0 0 191,589,677

(+) Revision Increases . . . . . . . . . . . . 20,796,982 1,410,837 57,877 0 0 22,265,696

(-) Revision Decreases . . . . . . . . . . . . 17,935,043 1,597,926 57,101 0 0 19,590,070

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 6,374,619 2,603,091 660,888 0 0 9,638,598

(+) Acquisitions . . . . . . . . . . . . . . . . . . 10,827,491 1,430,381 366 0 0 12,258,238

(+) Extensions. . . . . . . . . . . . . . . . . . . 17,879,868 3,001,598 32,396 0 0 20,913,862

(+) New Field Discoveries.......... 843,867 101,153 750 0 0 945,770

(+) New Reservoirs in Old Fields .... 855,547 334,831 4,812 0 0 1,195,190

(-) Production With

Proved Reserves Reported . . . . . 16,238,784 1,354,507 31,345 0 0 17,624,636

(-) Production Without

Proved Reserves Reported . . . . . 27,291 280,136 10,772 0 0 318,199

Proved Reserves as of 12/31/05 . . . . . . 188,448,418 13,600,037 297,115 0 0 202,345,570

Imputed and Estimated

Number of Operators . . . . . . . . . . . . . . . - - - 3,096 - 3,096

Proved Reserves as of 12/31/04 . . . . . . - - - - - -

(+) Revision Increases . . . . . . . . . . . . 0 0 0 0 1,099,743 1,099,743

(-) Revision Decreases . . . . . . . . . . . . 0 0 0 0 1,057,068 1,057,068

(-) Sales ....................... 0 0 0 0 0 0

(+) Acquisitions . . . . . . . . . . . . . . . . . . 0 0 0 0 46,214 46,214

(+) Extensions. . . . . . . . . . . . . . . . . . . 0 0 0 0 1,157,034 1,157,034

(+) New Field Discoveries. . . . . . . . . . 0 0 0 0 28,436 28,436

(+) New Reservoirs in Old Fields . . . . 0 0 0 0 45,646 45,646

(-) Production With

Proved Reserves Reported . . . . . 0 0 0 0 88,506 88,506

(-) Production Without

Proved Reserves Reported . . . . . 478 214,866 77,445 292,789 644,976 1,230,554

Proved Reserves as of 12/31/05 . . . . . . 3,150 1,958,093 727,348 2,688,591 5,592,087 10,969,269

Total

Number of Operators . . . . . . . . . . . . . . . 171 444 224 3,561 10,758 15,158

Proved Reserves as of 12/31/04 . . . . . . 177,781,473 12,857,956 950,248 0 0 191,589,677

(+) Revision Increases . . . . . . . . . . . . 20,796,982 1,410,837 57,877 0 1,099,743 23,365,439

(-) Revision Decreases . . . . . . . . . . . . 17,935,043 1,597,926 57,101 0 1,057,068 20,647,138

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 6,374,619 2,603,091 660,888 0 0 9,638,598

(+) Acquisitions . . . . . . . . . . . . . . . . . . 10,827,491 1,430,381 366 0 46,214 12,304,452

(+) Extensions. . . . . . . . . . . . . . . . . . . 17,879,868 3,001,598 32,396 0 1,157,034 22,070,896

(+) New Field Discoveries.......... 843,867 101,153 750 0 28,436 974,206

(+) New Reservoirs in Old Fields .... 855,547 334,831 4,812 0 45,646 1,240,836

(-) Production With

Proved Reserves Reported . . . . . 16,238,784 1,354,507 31,345 0 88,506 17,713,142

(-) Production Without

Proved Reserves Reported . . . . . 27,769 495,002 88,217 292,789 644,976 1,548,753

Proved Reserves as of 12/31/05 . . . . . . 188,451,568 15,558,130 1,024,463 2,688,591 5,592,087 213,314,839

Summary

Total Number of Operators . . . . . . . . . 171 444 224 3,561 10,758 15,158

Percent of Total . . . . . . . . . . . . . . . . . . 1.1% 2.9% 1.5% 23.5% 71.0% 100.0%

Total Production in 2005 . . . . . . . . . . . 16,266,553 1,849,509 119,562 292,789 733,482 19,261,895

Percent of Total . . . . . . . . . . . . . . . . . . 84.4% 9.6% 0.6% 1.5% 3.8% 100.0%

Total Proved Reserves 12/31/05 ..... 188,451,568 15,558,130 1,024,463 2,688,591 5,592,087 213,314,839

Percent of Total . . . . . . . . . . . . . . . . . . 88.3% 7.3% 0.5% 1.3% 2.6% 100.0%

aThere were 483 noncertainty responses, 108 were used with their sample weights and 375 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,” 2005.
Energy Information Administration

F-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table F3. Summary of Form EIA-23 Reported, Imputed, and Estimated Nonassociated Natural Gas Data

for 2005, 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 . . . . . . . . . . . . . . . 171 444 224 465 10,758 12,062

Proved Reserves as of 12/31/04 . . . . . . 153,620,162 11,511,742 866,490 0 0 165,998,394

(+) Revision Increases . . . . . . . . . . . . 17,869,998 1,251,566 38,198 0 0 19,159,762

(-) Revision Decreases . . . . . . . . . . . . 16,209,272 1,471,283 55,071 0 0 17,735,626

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 4,954,763 2,386,307 644,280 0 0 7,985,350

(+) Acquisitions . . . . . . . . . . . . . . . . . . 8,970,692 1,261,064 366 0 0 10,232,122

(+) Extensions. . . . . . . . . . . . . . . . . . . 17,078,539 2,869,903 31,715 0 0 19,980,157

(+) New Field Discoveries.......... 734,462 91,400 500 0 0 826,362

(+) New Reservoirs in Old Fields .... 792,116 327,197 250 0 0 1,119,563

(-) Production With

Proved Reserves Reported . . . . . 14,213,209 1,211,812 25,092 0 0 15,450,113

(-) Production Without

Proved Reserves Reported . . . . . 27,535 374,381 16,166 0 0 418,082

Proved Reserves as of 12/31/05 . . . . . . 163,700,253 12,261,351 213,076 0 0 176,174,680

Imputed and Estimated

Number of Operators . . . . . . . . . . . . . . . - - - 3,096 - 3,096

Proved Reserves as of 12/31/04 . . . . . . - - - - - -

(+) Revision Increases . . . . . . . . . . . . 0 0 0 0 918,560 918,560

(-) Revision Decreases . . . . . . . . . . . . 0 0 0 0 877,877 877,877

(-) Sales ....................... 0 0 0 0 0 0

(+) Acquisitions .................. 0 0 0 0 0 0

(+) Extensions. . . . . . . . . . . . . . . . . . . 0 0 0 0 1,060,156 1,060,156

(+) New Field Discoveries. . . . . . . . . . 0 0 0 0 27,953 27,953

(+) New Reservoirs in Old Fields . . . . 0 0 0 0 42,222 42,222

(-) Production With

Proved Reserves Reported . . . . . 0 0 0 0 81,488 81,488

(-) Production Without

Proved Reserves Reported . . . . . 437 204,569 69,421 274,427 328,985 877,839

Proved Reserves as of 12/31/05 . . . . . . 2,880 1,867,050 663,740 2,533,670 3,837,363 8,904,703

Total

Number of Operators . . . . . . . . . . . . . . . 171 444 224 3,561 10,758 15,158

Proved Reserves as of 12/31/04 . . . . . . 153,620,162 11,511,742 866,490 0 0 165,998,394

(+) Revision Increases . . . . . . . . . . . . 17,869,998 1,251,566 38,198 0 918,560 20,078,322

(-) Revision Decreases . . . . . . . . . . . . 16,209,272 1,471,283 55,071 0 877,877 18,613,503

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 4,954,763 2,386,307 644,280 0 0 7,985,350

(+) Acquisitions . . . . . . . . . . . . . . . . . . 8,970,692 1,261,064 366 0 0 10,232,122

(+) Extensions. . . . . . . . . . . . . . . . . . . 17,078,539 2,869,903 31,715 0 1,060,156 21,040,313

(+) New Field Discoveries.......... 734,462 91,400 500 0 27,953 854,315

(+) New Reservoirs in Old Fields .... 792,116 327,197 250 0 42,222 1,161,785

(-) Production With

Proved Reserves Reported . . . . . 14,213,209 1,211,812 25,092 0 81,488 15,531,601

(-) Production Without

Proved Reserves Reported . . . . . 27,972 578,950 85,587 274,427 328,985 1,295,921

Proved Reserves as of 12/31/05 . . . . . . 163,703,133 14,128,401 876,816 2,533,670 3,837,363 185,079,383

Summary

Total Number of Operators . . . . . . . . . 171 444 224 3,561 10,758 15,158

Percent of Total . . . . . . . . . . . . . . . . . . 1.1% 2.9% 1.5% 23.5% 71.0% 100.0%

Total Production in 2005 . . . . . . . . . . . 14,241,181 1,790,762 110,679 274,427 410,473 16,827,522

Percent of Total . . . . . . . . . . . . . . . . . . 84.6% 10.6% 0.7% 1.6% 2.4% 100.0%

Total Proved Reserves 12/31/05 ..... 163,703,133 14,128,401 876,816 2,533,670 3,837,363 185,079,383

Percent of Total . . . . . . . . . . . . . . . . . . 88.5% 7.6% 0.5% 1.4% 2.1% 100.0%

aThere were 483 noncertainty responses, 108 were used with their sample weights and 375 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,” 2005.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report F-7

Table F4. Summary of Form EIA-23 Reported, Imputed, and Estimated Crude Oil Data for 2005,

(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 . . . . . . . . . . . . . . . 171 444 224 465 10,758 12,062

Proved Reserves as of 12/31/04 . . . . . . 18,904,950 1,000,002 32,900 0 0 19,937,852

(+) Revision Increases . . . . . . . . . . . . 1,288,553 114,446 3,416 0 0 1,406,415

(-) Revision Decreases . . . . . . . . . . . . 825,873 62,647 1,052 0 0 889,572

(-) Sales ....................... 693,197 132,840 610 0 0 826,647

(+) Acquisitions .................. 995,428 87,712 11 0 0 1,083,151

(+) Extensions................... 664,379 84,594 571 0 0 749,544

(+) New Field Discoveries.......... 202,861 2,863 60 0 0 205,784

(+) New Reservoirs in Old Fields . . . . 30,778 6,805 304 0 0 37,887

(-) Production With

Proved Reserves Reported . . . . . 1,443,868 86,443 2,595 0 0 1,532,906

(-) Production Without

Proved Reserves Reported . . . . . 18 15,740 571 0 0 16,329

Proved Reserves as of 12/31/05 . . . . . . 19,124,038 1,014,950 33,005 0 0 20,171,993

Imputed and Estimated

Number of Operators . . . . . . . . . . . . . . . - - - 3,096 - 3,096

Proved Reserves as of 12/31/04 . . . . . . - - - - - -

(+) Revision Increases . . . . . . . . . . . . 0 0 0 0 135,588 135,588

(-) Revision Decreases . . . . . . . . . . . . 0 0 0 0 86,380 86,380

(-) Sales ....................... 0 0 0 0 0 0

(+) Acquisitions . . . . . . . . . . . . . . . . . . 0 0 0 0 20,839 20,839

(+) Extensions. . . . . . . . . . . . . . . . . . . 0 0 0 0 57,298 57,298

(+) New Field Discoveries. . . . . . . . . . 0 0 0 0 1,165 1,165

(+) New Reservoirs in Old Fields . . . . 0 0 0 0 2,410 2,410

(-) Production With

Proved Reserves Reported . . . . . 0 0 0 0 14,910 14,910

(-) Production Without

Proved Reserves Reported. . . . . . . . . 0 21,959 9,723 31,682 107,890 171,254

Proved Reserves as of 12/31/05 . . . . . . 0 195,457 90,771 286,228 1,011,829 1,584,285

Total

Number of Operators . . . . . . . . . . . . . . . 171 444 224 3,561 10,758 15,158

Proved Reserves as of 12/31/04 . . . . . . 18,904,950 1,000,002 32,900 0 0 19,937,852

(+) Revision Increases . . . . . . . . . . . . 1,288,553 114,446 3,416 0 135,588 1,542,003

(-) Revision Decreases . . . . . . . . . . . . 825,873 62,647 1,052 0 86,380 975,952

(-) Sales ....................... 693,197 132,840 610 0 0 826,647

(+) Acquisitions .................. 995,428 87,712 11 0 20,839 1,103,990

(+) Extensions................... 664,379 84,594 571 0 57,298 806,842

(+) New Field Discoveries.......... 202,861 2,863 60 0 1,165 206,949

(+) New Reservoirs in Old Fields . . . . 30,778 6,805 304 0 2,410 40,297

(-) Production With

Proved Reserves Reported . . . . . 1,443,868 86,443 2,595 0 14,910 1,547,816

(-) Production Without

Proved Reserves Reported . . . . . 18 37,699 10,294 31,682 107,890 187,583

Proved Reserves as of 12/31/05 . . . . . . 19,124,038 1,210,407 123,776 286,228 1,011,829 21,756,278

Summary

Total Number of Operators . . . . . . . . . 171 444 224 3,561 10,758 15,158

Percent of Total . . . . . . . . . . . . . . . . . . 1.1% 2.9% 1.5% 23.5% 71.0% 100.0%

Total Production in 2005 . . . . . . . . . . . 1,443,886 124,142 12,889 31,682 122,800 1,735,399

Percent of Total . . . . . . . . . . . . . . . . . . 83.2% 7.2% 0.7% 1.8% 7.1% 100.0%

Total Proved Reserves 12/31/05 . . . . . 19,124,038 1,210,407 123,776 286,228 1,011,829 21,756,278

Percent of Total . . . . . . . . . . . . . . . . . . 87.9% 5.6% 0.6% 1.3% 4.7% 100.0%

aThere were 483 noncertainty responses, 108 were used with their sample weights and 375 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,” 2005.
Energy Information Administration

F-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report

Table F5. Summary of Form EIA-23 Reported, Imputed, and Estimated Lease Condensate Data for 2005,

(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 . . . . . . . . . . . . . . . 171 444 224 465 10,758 12,062

Proved Reserves as of 12/31/04 . . . . . . 1,060,796 106,883 5,013 0 0 1,172,692

(+) Revision Increases . . . . . . . . . . . . 190,327 20,601 441 0 0 211,369

(-) Revision Decreases . . . . . . . . . . . . 200,335 20,985 522 0 0 221,842

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 48,196 17,673 3,493 0 0 69,362

(+) Acquisitions .................. 102,520 16,388 0 0 0 118,908

(+) Extensions................... 101,703 32,560 337 0 0 134,600

(+) New Field Discoveries. . . . . . . . . . 4,326 758 0 0 0 5,084

(+) New Reservoirs in Old Fields . . . . 10,029 7,055 0 0 0 17,084

(-) Production With

Proved Reserves Reported ..... 148,830 14,255 254 0 0 163,339

(-) Production Without

Proved Reserves Reported . . . . . 134 3,643 302 0 0 4,079

Proved Reserves as of 12/31/05 . . . . . . 1,073,140 131,490 1,522 0 0 1,206,152

Imputed and Estimated

Number of Operators . . . . . . . . . . . . . . . - - - 3,096 - 3,096

Proved Reserves as of 12/31/04 . . . . . . - - - - - -

(+) Revision Increases . . . . . . . . . . . . 0 0 0 0 10,773 10,773

(-) Revision Decreases . . . . . . . . . . . . 0 0 0 0 10,474 10,474

(-) Sales ....................... 0 0 0 0 0 0

(+) Acquisitions .................. 0 0 0 0 0 0

(+) Extensions. . . . . . . . . . . . . . . . . . . 0 0 0 0 7,502 7,502

(+) New Field Discoveries. . . . . . . . . . 0 0 0 0 212 212

(+) New Reservoirs in Old Fields . . . . 0 0 0 0 480 480

(-) Production With

Proved Reserves Reported . . . . . 0 0 0 0 236 236

(-) Production Without

Proved Reserves Reported . . . . . 0 886 424 1,310 5,218 7,838

Proved Reserves as of 12/31/05 . . . . . 0 5,142 2,595 7,737 38,488 53,962

Total

Number of Operators . . . . . . . . . . . . . . . 171 444 224 3,561 10,758 15,158

Proved Reserves as of 12/31/04 . . . . . . 1,060,796 106,883 5,013 0 0 1,172,692

(+) Revision Increases . . . . . . . . . . . . 190,327 20,601 441 0 10,773 222,142

(-) Revision Decreases . . . . . . . . . . . . 200,335 20,985 522 0 10,474 232,316

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 48,196 17,673 3,493 0 0 69,362

(+) Acquisitions .................. 102,520 16,388 0 0 0 118,908

(+) Extensions................... 101,703 32,560 337 0 7,502 142,102

(+) New Field Discoveries. . . . . . . . . . 4,326 758 0 0 212 5,296

(+) New Reservoirs in Old Fields . . . . 10,029 7,055 0 0 480 17,564

(-) Production With

Proved Reserves Reported ..... 148,830 14,255 254 0 236 163,575

(-) Production Without

Proved Reserves Reported . . . . . 134 4,529 726 1,310 5,218 11,917

Proved Reserves as of 12/31/05 . . . . . . 1,073,140 136,632 4,117 7,737 38,488 1,260,114

Summary

Total Number of Operators . . . . . . . . . 171 444 224 3,561 10,758 15,158

Percent of Total . . . . . . . . . . . . . . . . . . 1.1% 2.9% 1.5% 23.5% 71.0% 100.0%

Total Production in 2005 ........... 148,964 18,784 980 1,310 5,454 175,492

Percent of Total . . . . . . . . . . . . . . . . . . 84.9% 10.7% 0.6% 0.7% 3.1% 100.0%

Total Proved Reserves 12/31/05 . . . . . 1,073,140 136,632 4,117 7,737 38,488 1,260,114

Percent of Total . . . . . . . . . . . . . . . . . . 85.2% 10.8% 0.3% 0.6% 3.1% 100.0%

aThere were 483 noncertainty responses, 108 were used with their sample weights and 375 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,” 2005.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report F-9

Table F6. Statistical Parameters of Reserves Estimation Equation by Region for 2005

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 9 0 -0.1230 0.3407 -0.1351 0.4496 0.0000 0.0000

2 Pacific Coast States . . . . . . . . . . . 42 58 5 -0.1230 0.2583 -0.1351 0.3330 -0.1170 0.3456

2A Federal Offshore Pacific ......... 6 5 0 -0.1230 0.2183 -0.1351 0.3590 0.0000 0.0000

3 Western Rocky Mountains . . . . . . . . 76 144 58 -0.1230 0.2175 -0.1351 0.3000 -0.1170 0.2023

4 Northern Rocky Mountains . . . . . . . . 173 174 48 -0.1230 0.2514 -0.1351 0.3191 -0.1170 0.2604

5 West Texas and East New Mexico . . . . 475 492 166 -0.1230 0.2386 -0.1351 0.3397 -0.1170 0.4877

6 Western Gulf Basin. . . . . . . . . . . . 500 847 583 -0.1230 0.3159 -0.1351 0.4036 -0.1170 0.4989

6A Gulf of Mexico . . . . . . . . . . . . . . 75 140 111 -0.1230 0.4105 -0.1351 0.6535 -0.1170 0.6868

7 Mid-Continent . . . . . . . . . . . . . . 286 384 149 -0.1230 0.2112 -0.1351 0.3210 -0.1170 0.2687

8 + 9 Michigan Basin and Eastern Interior . . . . 77 60 17 -0.1230 0.1989 -0.1351 0.2087 -0.1170 0.2604

10 + 11 Appalachians . . . . . . . . . . . . . . 25 76 10 -0.1230 0.2140 -0.1351 0.1784 -0.1170 0.2551

United States .............. 1,743 2,389 1,147 -0.1230 0.3034 -0.1351 0.3684 -0.1170 0.4567

Source: Based on data filed on Form EIA-23,"Annual Survey of Domestic Oil and Gas Reserves, 2005".

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 six

states in the 2005 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

2005 than in 2004.

One or more operators may have reported data

incorrectly on Schedule A in 2005 or 2004, 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 2005 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

2005 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 Vs and its sampling error by

S.E.(Vs), the confidence interval can be expressed as:

Vs k S.E.(Vs)

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:

Vs 2 S.E.(Vs)

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.(Vs) 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 204,853   billion

cubic feet. The sampling error of Vs is equal to the

sampling error of the noncertainty estimate Vsr 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

2005 survey was 3.8 percent and for the noncertainty

operators 3.7 percent. An imputation was made for the

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report F-11
production and reserves for the 51 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 2005 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,

7.3 percent of the crude oil proved reserve estimates,

5.1 percent of the wet natural gas proved reserve

estimates, and 4.3 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 2005 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 2005 Form

EIA-64A survey, the national weighted average gas

equivalents ratio was computed to be 1,414 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 2005 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 2005 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 2005 U.S. proved reserves of 204 trillion

cubic feet yields a technically recoverable resource

target of 1,635 trillion cubic feet. This is about 89 times

the 2005 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 2005 oil production (Table

G1) was about 101 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,

Energy Information Administration

G-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 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.{45} They are similarly defined by the MMS,

although its system also subdivides them by degree of

development and producing status.{46} 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.{45}

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 2005 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 2005 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

Energy Information Administration

G-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 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 2005 Annual Report G-7
Energy Information Administration

G-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report
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 2005 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 2005 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 2005 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 2005 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 2005 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 2005 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 2005 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 2005 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 2005 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 2005 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 2005 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 2005 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 2005 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 2005 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 2005 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)

Lease Condensate: A mixture consisting primarily of

pentanes and heavier hydrocarbons which is

recovered as a liquid from natural gas in lease or

field separation facilities, exclusive of products

recovered at natural gas processing plants or

facilities.

Lease Separator: A lease separator is a facility

installed at the surface for the purpose of (a)

separating gases from produced crude oil and water

at the temperature and pressure conditions of the

separator, and/or (b) separating gases from that

portion of the produced natural gas stream which

liquefies at the temperature and pressure conditions

of the separator.

Natural Gas: A mixture of hydrocarbon compounds

and small quantities of various nonhydrocarbons

existing in the gaseous phase or in solution with

crude oil in natural underground reservoirs at

reservoir conditions. The principal hydrocarbons

normally contained in the mixture are methane,

ethane, propane, butane, and pentanes. Typical

nonhydrocarbon gases which may be present in

reservoir natural gas are water vapor, carbon

dioxide, helium, hydrogen sulfide, and nitrogen.

Under reservoir conditions, natural gas and the

liquefiable portions occur either in a single gaseous

phase in the reservoir or in solution with crude oil,

and are not distinguishable at the time as separate

substances. (See Natural Gas, Associated--Dissolved

and Natural Gas, Nonassociated)

Natural Gas, Associated--Dissolved: The combined

volume of natural gas which occurs in crude oil

reservoirs either as free gas (associated) or as gas in

solution with crude oil (dissolved).

Natural Gas, “Dry”: The actual or calculated

volumes of natural gas which remain after:

1. The liquefiable hydrocarbon portion has been

removed from the gas stream (i.e., gas after

lease, field, and/or plant separation)

2. Any volumes of nonhydrocarbon gases have

been removed where they occur in sufficient

quantity to render the gas unmarketable.

Natural Gas, Nonassociated: Natural gas not in

contact with significant quantities of crude oil in a

reservoir.

Natural Gas Liquids: Those hydrocarbons in natural

gas which are separated from the gas through the

processes of absorption, condensation, adsorption, or

other methods in gas processing or cycling plants.

Generally such liquids consist of propane and

heavier hydrocarbons and are commonly referred to

as condensate, natural gasoline, or liquefied

petroleum gases. Where hydrocarbon components

lighter than propane are recovered as liquids, these

components are included with natural gas liquids.

Natural Gas Processing Plant: A facility designed to

recover natural gas liquids from a stream of natural

gas which may or may not have passed through

lease separators and/or field separation facilities.

Another function of the facility is to control the

quality of the processed natural gas stream. Cycling

plants are considered natural gas processing plants.

Natural Gas, Wet After Lease Separation: The

volume of natural gas remaining after removal of

lease condensate in lease and/or field separation

facilities, if any, and after exclusion of

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

Energy Information Administration

Glossary-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report
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

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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report Glossary-3
removal of lease condensate; and less (3)

nonhydrocarbon gases where they occur in sufficient

quantity to render the gas unmarketable. Volumes of

gas withdrawn from gas storage reservoirs and

native gas, which has been transferred to the storage

category, are not considered production. This is not

the same as marketed production, since the latter

excludes vented and flared gas.

Production, Natural Gas Liquids: The volume of

natural gas liquids removed from natural gas in lease

separators, field facilities, gas processing plants or

cycling plants during the report year.

Production, Plant Liquids: The volume of liquids

removed from natural gas in natural gas processing

plants or cycling plants during the report year.

Proved Reserves of Crude Oil: Proved reserves of

crude oil as of December 31 of the report year are the

estimated quantities of all liquids defined as crude

oil, which geological and engineering data

demonstrate with reasonable certainty to be

recoverable in future years from known reservoirs

under existing economic and operating conditions.

Reservoirs are considered proved if economic

producibility is supported by actual production or

conclusive formation test (drill stem or wire line), or

if economic producibility is supported by core

analyses and/or electric or other log interpretations.

The area of an oil reservoir considered proved

includes (1) that portion delineated by drilling and

defined by gas--oil and/or oil--water contacts, if any;

and (2) the immediately adjoining portions not yet

drilled, but which can be reasonably judged as

economically productive on the basis of available

geological and engineering data. In the absence of

information on fluid contacts, the lowest known

structural occurrence of hydrocarbons is considered

to be the lower proved limit of the reservoir.

Volumes of crude oil placed in underground storage

are not to be considered proved reserves.

Reserves of crude oil which can be produced

economically through application of improved

recovery techniques (such as fluid injection) are

included in the “proved” classification when

successful testing by a pilot project, or the operation

of an installed program in the reservoir, provides

support for the engineering analysis on which the

project or program was based.

Estimates of proved crude oil reserves do not include

the following: (1) oil that may become available from

known reservoirs but is reported separately as

“indicated additional reserves”; (2) natural gas

liquids (including lease condensate); (3) oil, the

recovery of which is subject to reasonable doubt

because of uncertainty as to geology, reservoir

characteristics, or economic factors; (4) oil that may

occur in undrilled prospects; and (5) oil that may be

recovered from oil shales, coal, gilsonite, and other

such sources. It is not necessary that production,

gathering or transportation facilities be installed or

operative for a reservoir to be considered proved.

Proved Reserves of Lease Condensate: Proved

reserves of lease condensate as of December 31 of the

report year are the volumes of lease condensate

expected to be recovered in future years in

conjunction with the production of proved reserves

of natural gas as of December 31 of the report year,

based on the recovery efficiency of lease and/or field

separation facilities installed as of December 31 of

the report year. (See Lease Condensate and Proved

Reserves of Natural Gas)

Proved Reserves of Natural Gas: Proved reserves of

natural gas as of December 31 of the report year are

the estimated quantities which analysis of geological

and engineering data demonstrate with reasonable

certainty to be recoverable in future years from

known reservoirs under existing economic and

operating conditions.

Reservoirs are considered proved if economic

producibility is supported by actual production or

conclusive formation test (drill stem or wire line), or

if economic producibility is supported by core

analyses and/or electric or other log interpretations.

The area of a gas reservoir considered proved

includes: (1) that portion delineated by drilling and

defined by gas--oil and/or gas--water contacts, if

any; and (2) the immediately adjoining portions not

yet drilled, but which can be reasonably judged as

economically productive on the basis of available

geological and engineering data. In the absence of

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

Energy Information Administration

Glossary-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report
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 at a specified

point in time. It measures the maximum recoverable

volume known at that time and is a dynamic quantity

that is expected to change over time for any field,

group of fields, State, or Country. In most instances,

therefore, an estimate of Proved Ultimate Recovery

does not represent the all-time maximum recoverable

volume of resources for a given field or area.

Also, the proved ultimate recovery of a field, a group

of fields, a State, or a Country grows (appreciates)

over time in most instances.

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.

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.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2005 Annual Report Glossary-5
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 2005 Annual Report