U.S. Crude Oil, Natural Gas,

and Natural Gas Liquids Reserves

2006 Annual Report

DOE/EIA-0216(2007)

November 2007

Preface

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

Liquids Reserves 2006 Annual Report is the 30th

prepared by the Energy Information Administration

(EIA) to fulfill its responsibility to gather and report

annual proved reserves estimates. The EIA annual

res erves report series is the o nly 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, 2006, as well as production volumes

for the United States and producing States and State

subdivisions for the year 2006. Estimates are

presented for the following four categories of natural

gas : total gas (wet after leas e sep aratio n),

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 2006

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 2006; 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

pro vided 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, Toby

Engleman, 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 2006 Annual Report iii
Energy Information Administration

iv U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 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:

Aerial View of Dallas/Fort Worth International Airport.

Copyright 2007, Dallas/Fort Worth International Airport.

The DFW Airport Board has leased its 18,000 acres to Oklahoma City-based

Chesapeake Energy Corporation to begin natural gas exploration in the Barnett

Shale that lies below the Airport.
Contents

Page

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

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

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

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

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

New Form EIA-23 Element: Type Code . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

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

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

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

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

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

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

Dependence on Imports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

List of Appendices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

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

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

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

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

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

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

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

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

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

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

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

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

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

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

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

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

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

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

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

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U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report v
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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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

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

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

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

Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

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

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

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

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

Kansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 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, 1996-2006 . . . . . . . . . . . . 4

2. Reserves Changes, 1977-2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

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vi U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report
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3. U.S. Average Annual First Purchase Prices for Crude Oil, Domestic Wellhead Prices for Natural Gas, and the

Average Number of Active Rotary Drilling Rigs, 1977-2006 . . . . . . . . . . . . . . . . . . . . . . . . . . 10

4. U.S. Exploratory and Development Well Completions, 1973-2006 . . . . . . . . . . . . . . . . . . . . . . . . . 12

5. International Oil and Natural Gas Reserves as of December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . 18

6. Crude Oil Proved Reserves, Reserves Changes, and Production, 2006 . . . . . . . . . . . . . . . . . . . . . . 22

7. Reported Reserves in Nonproducing Status for Crude Oil, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . 27

8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 2006 . . . . . . . . . . . . . . . . . . 30

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

Wet After Lease Separation, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

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

Wet After Lease Separation, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

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

Wet After Lease Separation, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

12. Coalbed Natural Gas Proved Reserves and Production, 1989-2006 . . . . . . . . . . . . . . . . . . . . . . . . 39

13. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 2006 . . . . . . . . . . . . . . . . 42

14. Natural Gas Plant Liquids Proved Reserves and Production, 2006. . . . . . . . . . . . . . . . . . . . . . . . . 43

15. Lease Condensate Proved Reserves and Production, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Figures

1. U.S. Crude Oil Proved Reserves, 1996-2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

2. Components of Reserves Changes for Crude Oil, 1996-2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

3. U.S. Dry Natural Gas Proved Reserves, 1996-2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

4. Components of Reserves Changes for Dry Natural Gas, 1996-2006 . . . . . . . . . . . . . . . . . . . . . . . . 6

5. U.S. Natural Gas Liquids Proved Reserves, 1996-2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

6. Components of Reserves Changes for Natural Gas Liquids, 1996-2006 . . . . . . . . . . . . . . . . . . . . . . 8

7. U.S. Exploratory Well Completions, 1996-2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

8. U.S. Development Well Completions, 1996-2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

9. U.S. Total Discoveries of Dry Natural Gas per Exploratory Gas Well Completion, 1977-2006 . . . . . . . . . . . 14

10. U.S. Total Discoveries of Crude Oil per Exploratory Oil Well Completion, 1977-2006 . . . . . . . . . . . . . . . 14

11. Reserves-to-Production Ratios for Crude Oil, 1945-2006. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

12. Reserves-to-Production Ratios for Wet Natural Gas, 1945-2006 . . . . . . . . . . . . . . . . . . . . . . . . . . 16

13. Components of Proved Ultimate Recovery for Crude Oil and Lease Condensate, 1977-2006 . . . . . . . . . . . 17

14. Components of Proved Ultimate Recovery for Wet Natural Gas, 1977-2006 . . . . . . . . . . . . . . . . . . . . 17

15 Replacement of U.S. Crude Oil Production by Reserves Additions, 1996-2006 . . . . . . . . . . . . . . . . . . 21

16. Crude Oil Proved Reserves by Area, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

17. Changes in Crude Oil Proved Reserves by Area, 2005 to 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . 23

18. Replacement of U.S. Dry Natural Gas Production by Reserves Additions, 1996-2006 . . . . . . . . . . . . . . . 29

19. Dry Natural Gas Proved Reserves by Area, 2006. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

20. Changes in Dry Natural Gas Proved Reserves by Area, 2005 to 2006 . . . . . . . . . . . . . . . . . . . . . . . 31

21. Coalbed Natural Gas Proved Reserves, 1989-2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report vii

Executive Summary

Proved reserves of natural gas increased by 3 percent

in 2006, rising to over 211 trillion cubic feet, the

highest level since 1976. Additions to reserves

replaced 136 percent of the dry natural gas produced

in 2006. This was the eighth year in a row that U.S.

natural gas proved reserves have increased.

U.S. crude oil proved reserves declined 4 percent in

2006. The Gulf of Mexico Federal Offshore and

Alaska, two of the largest oil-producing areas,

respectively reported 10 and 7 percent declines in

cru de oil proved reserves. Th is was due to

downward revisions and fewer new discoveries.

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

Texas led the nation in natural gas reserves additions

in 2006 with a 9 percent increase in dry gas proved

reserves due to rapid development of Barnett Shale

reservoirs in the Newark East Field. Advances in

horizontal drilling and h ydraulic fracturing

technology and relatively high natural gas prices

supported this development. Alaska and Utah were

second and third for dry natural gas proved reserves

additions in 2006.

Total U.S. natural gas production increased in 2006

due to production increases in Texas (Barnett Shale),

Louisiana, and the Rocky Mountain states (Colorado,

Wyoming, Utah, and Montana). Gulf of Mexico

natural gas production declined the most with a 6

percent drop.

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 23,342

billion cubic feet in 2006. This was 35 percent more

than the prior 10-year average (17,255 billion cubic

feet) and 1 percent more than in 2005.

The majority of natural gas total discoveries in 2006

were from extensions to existing gas fields. Field

extensions were 21,778 billion cubic feet, 3 percent

more than in 2005 and 61 percent more than the

prior 10-year average (13,522 billion cubic feet).

New field discoveries were 409 billion cubic feet, 57

percent less than the volume discovered in 2005 and

75 percent less than the prior 10-year average (1,659

billion cubic feet).

New reservoir discoveries in old fields were 1,155

billion cubic feet, 4 percent less than 2005 and 44

percent less than the prior 10-year average (2,074

billion cubic feet).

Natural gas net revisions and adjustments were a net

loss of 1,093 billion cubic feet in 2006. The prior

occurrence of negative net revisions was in 1988. The

net of sales and acquisitions of dry natural gas

proved reserves was 2,996 billion cubic feet.

Coalbed natural gas reserves decreased 1 percent in

2006 and accounted for 9 percent of U.S. dry natural

gas reserves. Coalbed natural gas production

increased 2 percent in 2006 and accounted for 9

percent of U.S. dry natural gas production.

Other 2006 natural gas events of note:

• Natural gas prices at the wellhead declined 12

percent in 2006 to an average of $6.42 per

thousand cubic feet, as compared to $7.33 per

thousand cubic feet in 2005.

• Gas well completions (exploratory and

development) were up 17 percent from 2005.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report ix

As of December 31, 2006 proved reserves were:

Crude Oil (million barrels)

2005 21,757

2006 20,972

Decrease -3.6%

Dry Natural Gas (billion cubic feet)

2005 204,385

2006 211,085

Increase +3.3%

Natural Gas Liquids (million barrels)

2005 8,165

2006 8,472

Increase +3.8%
Crude Oil

U.S. crude oil proved reserves declined 4 percent in

2006. The Gulf of Mexico Federal Offshore and

Alaska, two of the largest U.S. oil-producing areas,

reported 10 and 7 percent declines in crude oil

proved reserves. This was due to downward

revisions and fewer new discoveries. Utah reported

the largest increase in crude oil reserves, adding 78

million barrels (a 30 percent increase from 2005),

followed by Colorado and New Mexico. Reserves

additions of crude oil did not keep pace with

production -- operators replaced only 52 percent of

2006 crude oil production with reserves additions.

U.S. crude oil production declined 5 percent in 2006

due mostly to lower Alaskan production. Part of the

decline resulted from an August 2006 shut-in of

producing wells in half of Prudhoe Bay Field for

inspection and repair of corrosion in the gathering

system. For the second year in a row Montana had

the largest annual oil production increase of any

State (6 million barrels; a 20 percent increase) owing

to continued development of the Bakken Formation

in the Elm Coulee Field. This relatively new and

important oil field is difficult to produce and

requires cutting-edge technology for economic

production.

Total discoveries of crude oil were 577 million

barrels in 2006, 49 percent less than the prior 10-year

average and 45 percent less than 2005's discoveries of

1,051 million barrels.

The majority of crude oil total discoveries in 2006

came from extensions to fields in Texas, Alaska, the

Gulf of Mexico Federal Offsh ore, Montana,

California, New Mexico, and Louisiana.

Op erators discovered 504 million barrels in

extensions in 2006, 37 percent less than in 2005 and

10 percent less than the prior 10-year average (558

million barrels).

New field discoveries accounted for 30 million

barrels of crude oil reserves additions. Seventy

percent of these discoveries (21 of 30 million barrels)

were in the Gulf of Mexico Federal Offshore. This

was 85 percent less than the new field discoveries of

2005 and only 7 percent of the prior 10-year average

(428 million barrels).

New reservoir discoveries in old fields were 43

million barrels, 5 percent more than 2005 and 71

percent less than the prior 10-year average (149

million barrels).

Reserves additions are the sum of total discoveries,

revisions, adjustments, sales, and acquisitions. In

2006, reserves additions were 867 million barrels, 59

percent less than the volume of reserves additions in

2005 and 54 percent less than the prior 10-year

average (1,876 million barrels).

Crude oil net revisions and adjustments were 96

million barrels, 88 percent less than the net revisions

and adjustments of 2005 and only 13 percent of the

prior 10-year average (759 million barrels). The net of

sales and acquisitions of crude oil proved reserves

was 194 million barrels.

Other 2006 crude oil events of note:

• The annual average domestic first purchase

price for crude oil increased 19 percent from

$50.28 per barrel in 2005 to $59.69 per barrel.

• Oil well completions (exploratory and

development) were up 28 percent from 2005.

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 4 percent in 2006. Operators replaced 138

percent of U.S. natural gas liquids production with

reserves additions.

Total proved reserves of liquid hydrocarbons (crude

oil plus natural gas liquids) were 29,444 million

barrels in 2006, a 2 percent decrease from the 2005

level. Natural gas liquids represented 29 percent of

total liquid hydrocarbon proved reserves in 2006.

Data

These estimates are based upon analysis of data from

Form EIA-23, Annual Survey of Domestic Oil and

Gas Reserves, filed by 1,501 operators of oil and gas

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

Origin of Natural Gas Liquids Production, filed by

operators of 496 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 2006 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 2006. 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

natural 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-23L to show how and why reserves

components c hanged du ring t he 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 on Form EIA-23S. 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 2006 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 estimates

from 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.

New Form EIA-23L Element: Type Code

For the 2006 survey, a new Form EIA-23L data element

called Type Code replaced the underutilized MMS Code.

The Type Codeis used to categorize proved reserves and

production from a field as either Conventional (C) or one

of four types of Unconventional reservoirs: Coal Bed

(CB); Chalk (CH); Shale (SH); or other Low Permeability

(LP) reservoirs (permeability of 0.1 millidarcy or less).

Type Code was added because the importance of

unconventional resources of natural gas and crude oil

to domestic energy supply continues to increase.

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 13,820 probable active operators and the

Form EIA-64A plant frame contained 491 probable

active natural gas processing plants in the United

States when the 2006 surveys were initiated.

For more details on the survey process, see Appendix

E, Summary of Data Collection Operations.

The 2006 survey sample consisted of 1,355 operators.

EIA sampled 872 operators with certainty; 173

Category I operators, 467 Category II operators, and

232 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 483 Noncertainty

operators as a systematic random sample of the

remaining operators. There were 11 Successor

operators in 2006. Fifty-eight (58) of the 1,355 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.

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

processing plant operators as of February 1, 2006.

Response rate was 100 percent from the operators

surveyed (see Table E5 in Apppendix E).

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 2006,

the Form EIA-23 National production estimates were

1.5 percent lower than the comparable Petroleum Supply

Annual (PSA) 2006 volumes for crude oil and lease

condensate combined, and were less than 1 percent

higher than the comparable Natural Gas Monthly,

October 2007 volume for 2006 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 2006 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, 2006:

 Crude Oil — 20,972 million barrels

 Dry Natural Gas — 211,085 billion cubic feet

 Natural Gas Liquids — 8,472 million barrels.

This Overview summarizes the 2006 proved reserves

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

liquids on a National level and provides historical

comparisons between 2006 and prior years. Table 1

lists the estimated annual reserve balances since 1996

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

Crude Oil

U.S. crude oil proved reserves declined 4 percent (785

million barrels) in 2006. Figure 1 shows the crude oil

proved reserves levels by major region and Figure 2

shows the components of reserves changes from 1996

through 2006.

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

declined slightly (1 percent) onshore in the lower 48

States in 2006, but declined more in Alaska (7 percent)

and the Gulf of Mexico Federal Offshore (10 percent).

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

577 million barrels in 2006, 49 percent less than the

prior 10-year average (1,135 million barrels) and 45

percent less than 2005’s discoveries of 1,051 million

barrels.

The majority of crude oil total discoveries in 2006 came

from extensions to fields in Texas, Alaska, the Gulf of

Mexico, and Montana.

Operators discovered 504 million barrels in extensions

in 2006, 37 percent less than in 2005 and 10 percent less

than the prior 10-year average (558 million barrels).

New field discoveries accounted for 30 million barrels

of crude oil total discoveries. This was 85 percent less

than the new field discoveries of 2005 (205 million

barrels), and only 7 percent of the prior 10-year average

(428 million barrels). Seventy percent of these

discoveries (21 of 30 million) were in the Gulf of Mexico

Federal Offshore.

New reservoir discoveries in old fields were 43 million

barrels in 2006, 5 percent more than 2005 and 71 percent

less than the prior 10-year average (149 million barrels).

Reserves additions are the sum of total discoveries,

revisions, adjustments, sales, and acquisitions. In 2006,

crude oil reserves additions were 867 million barrels, 59

percent less than in 2005 and 54 percent less than the

prior 10-year average (1,876 million barrels).

Crude oil net revisions and adjustments were 96

million barrels, 88 percent less than the net revisions

and adjustments of 2005 and 87 percent less than the

prior 10-year average (759 million barrels). The net of

sales and acquisitions of crude oil proved reserves was

194 million barrels.

U.S. crude oil production declined 5 percent in 2006

due mostly to lower Alaskan production. Part of the

decline resulted from an August 2006 shut-in of

producing wells in half of Prudhoe Bay Field for

inspection and repair of corrosion in the gathering

system. For the second year in a row Montana had the

largest annual oil production increase of any State (6

million barrels; a 20 percent increase) owing to

continued development of the Bakken Formation in the

Elm Coulee Field. Reserves additions of crude oil

replaced only 52 percent of 2006 crude oil production.

Dry Natural Gas

Natural gas proved reserves increased by 6,700 billion

cubic feet in 2006. 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 Federal

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 3
Energy Information Administration

4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table 1. Total U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids, 1996-2006

Revisionsa Net of Salesb New Reservoir Provedd Change

Net and and New Field Discoveries Total

c 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)

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

2006 94 2 96 194 504 30 43 577 1,652 20,972 -785

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

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

2006 743 -1,836 -1,093 2,996 21,778 409 1,155 23,342 18,545 211,085 +6,700

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

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

2006 173 -165 8 117 924 16 53 993 811 8,472 +307

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

2006 contained in the Petroleum Supply Annual 2006, DOE/EIA-0340(06) and the Natural Gas Annual 2006, DOE/EIA-0131(06).
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 5

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1996-2005 annual reports, DOE/EIA-0216.{20-29}

Figure 1. U.S. Crude Oil Proved Reserves, 1996-2006

Figure 2. Components of Reserves Changes for Crude Oil, 1996-2006
Energy Information Administration

6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Figure 4. Components of Reserves Changes for Dry Natural Gas, 1996-2006

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1996-2005 annual reports, DOE/EIA-0216.{20-29}

Figure 3. U.S. Dry Natural Gas Proved Reserves, 1996-2006
offshore gas reserves. Figure 4 shows the components

of reserves changes from 1996 through 2006.

Total discoveries of dry natural gas reserves, which is

the sum of field extensions, new field discoveries, and

new reservoir discoveries in old fields, were 23,342

billion cubic feet in 2006. This was 35 percent more than

the prior 10-year average (17,255 billion cubic feet) and

1 percent more than in 2005.

The majority of natural gas total discoveries in 2006

were from extensions to existing fields. Field

extensions were 21,778 billion cubic feet, 4 percent

more than in 2005 and 61 percent more than the prior

10-year average (13,522 billion cubic feet).

New field discoveries were 409 billion cubic feet, 57

percent less than the volume discovered in 2005 and 75

percent less than the prior 10-year average (1,659

billion cubic feet).

New reservoir discoveries in old fields were 1,155

billion cubic feet, 4 percent less than in 2005 and 44

percent less than the prior 10-year average (2,074

billion cubic feet).

Natural gas net revisions and adjustments were a net

loss of 1,093 billion cubic feet in 2006. The prior

occurrence of negative net revisions was in 1988. The

net of sales and acquisitions of dry natural gas proved

reserves was 2,996 billion cubic feet.

Total U.S. natural gas production increased slightly in

2006 due to production increases in Texas (Barnett

Shale), Louisiana, and the Rocky Mountain states

(Colorado, Wyoming, Utah, and Montana). Gulf of

Mexico natural gas production declined the most with

a 6 percent drop.

Coalbed natural gas reserves decreased 1 percent in

2006 and accounted for 9 percent of U.S. dry natural gas

reserves. Coalbed natural gas production increased 2

percent in 2006 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

4 percent in 2006. Operators replaced 138 percent of

U.S. natural gas liquids production with reserves

additions.

Total proved reserves of liquid hydrocarbons (crude oil

plus natural gas liquids) were 29,444 million barrels in

2006, a 2 percent decrease from the 2005 level. Natural

gas liquids represented 29 percent of total liquid

hydrocarbon proved reserves in 2006.

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 2006. 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 2006 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

895 million barrels,

 had average annual proved reserves additions

of 2,027 million barrels from total discoveries,

net revisions and adjustments, and net sales and

acquisitions, and

 had an average annual proved reserves decline

of 418 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 11 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 26,837 million barrels of total discoveries

accounted for 44 percent of reserves additions.

Compared to the averages of reserves changes since

1977, 2006 was a down year for crude oil discoveries.

Total discoveries of crude oil (577 million barrels) in

2006 were 36 percent less than the post-1976 U.S.

average (895 million barrels per year).

Looking at the components of total discoveries in 2006:

 Extensions in 2006 (504 million barrels) were

slightly less than the post-1976 average (525

million barrels),

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 7
Energy Information Administration

8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Figure 5. U.S. Natural Gas Liquids Proved Reserves, 1996-2006

Source: U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1996-2005 annual reports, DOE/EIA-0216.{20-29}

Figure 6. Components of Reserves Changes for Natural Gas Liquids, 1996-2006
 2006’s new field discoveries (30 million barrels)

were 87 percent less than the post-1976 average

for crude oil (230 million barrels), and

 New reservoir discoveries in old fields (43

million barrels) in 2006 were 69 percent less

than the post-1976 average (140 million barrels).

Revisions, Adjustments, Sales & Acquisitions were 290

million barrels in 2006. This was 74 percent less than

the post-1976 average of 1,132 million barrels per year.

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

 had average annual new reserves discoveries of

14,035 billion cubic feet,

 had average annual proved reserves additions

of 17,987 billion cubic feet from total

discoveries, net revisions and adjustments, and

net sales and acquisitions, and

 had an average annual production of 18,060

billion cubic feet, decreasing U.S. dry natural

gas reserves by an average 73 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 55 percent of all

reserves additions since 1977 while net revisions,

adjustments, sales, and acquisitions accounted for only

22 percent.

Compared to the averages of reserves changes since

1977, 2006 was an up year for dry natural gas total

discoveries. Operators reported 23,342 billion cubic

feet of total discoveries of dry natural gas proved

reserves, 66 percent more than the post-1976 average

(14,035 billion cubic feet).

The net of revisions, adjustments, sales, and

acquisitions was 1,903 billion cubic feet in 2006, 52

percent lower than the post-1976 U.S. average (3,951

billion cubic feet per year).

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 9

Table 2. Reserves Changes, 1977-2006

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. . . . . . . . . . . 5,960 199 11.9 6,911 230 11.4

New Reservoir Discoveries in Old Fields . . 3,998 133 8.0 4,186 140 6.9

Extensions . . . . . . . . . . . . . . . . 13,882 463 27.7 15,740 525 25.9

Total Discoveries . . . . . . . . . . . . . 23,840 795 47.6 26,837 895 44.1

Revisions, Adjustments, Sales & Acquisitionsa26,295 877 52.4 33,972 1,132 55.9

Total Reserves Additions . . . . . . . . . 50,135 1,671 100.0 60,809 2,027 100.0

Production . . . . . . . . . . . . . . . . 57,906 1,930 115.5 73,339 2,445 120.6

Net Reserves Change (since 1976). . . . . -7,771 -259 -15.5 -12,530 -418 -20.6

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. . . . . . . . . . . 54,258 1,809 9.9 54,522 1,817 10.1

New Reservoir Discoveries in Old Fields . . 70,441 2,348 12.8 70,902 2,363 13.1

Extensions . . . . . . . . . . . . . . . . 292,309 9,744 53.1 295,631 9,854 54.8

Total Discoveries . . . . . . . . . . . . . 417,008 13,900 75.7 421,055 14,035 78.0

Revisions, Adjustments, Sales & Acquisitionsa133,573 4,452 24.3 118,544 3,951 22.0

Total Reserves Additions . . . . . . . . . 550,581 18,353 100.0 539,599 17,987 100.0

Production . . . . . . . . . . . . . . . . 530,579 17,686 96.4 541,792 18,060 100.4

Net Reserves Change (since 1976). . . . . 20,002 667 3.6 -2,193 -73 -0.4

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 1977-2006 annual reports, DOE/EIA-0216.{1-29}
Energy Information Administration

10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 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, 1977-2006

Crude Oil Natural Gas

Year Current 2006 Constant Current 2006 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 36.77 38.16 5.46 5.67 1,192

2005 January 40.18 41.23 5.80 5.95 1,255

February 42.19 43.23 5.74 5.88 1,276

March 47.56 48.67 5.95 6.09 1,306

April 47.26 48.30 6.58 6.72 1,334

May 44.03 44.94 6.24 6.37 1,320

June 49.83 50.79 6.09 6.21 1,355

July 53.35 54.32 6.71 6.83 1,398

August 58.90 59.89 6.48 6.59 1,436

September 59.64 60.56 8.96 9.10 1,452

October 56.99 57.77 10.35 10.49 1,479

November 53.20 53.84 9.91 10.03 1,486

December 53.24 53.79 9.08 9.17 1,470

2005 Average 50.28 51.15 7.33 7.46 1,381

2006 January 57.85 58.32 8.66 8.73 1,473

February 55.69 56.05 7.28 7.33 1,533

March 55.64 55.92 6.52 6.55 1,551

April 62.52 62.75 6.59 6.61 1,597

May 64.40 64.55 6.19 6.20 1,635

June 64.65 64.71 5.80 5.81 1,665

July 67.71 67.69 5.82 5.82 1,681

August 67.21 67.09 6.51 6.50 1,738

September 59.37 59.17 5.51 5.49 1,739

October 53.26 52.99 5.03 5.00 1,734

November 52.42 52.06 6.43 6.39 1,706

December 55.03 54.55 6.65 6.59 1,718

2006 Average 59.69 59.69 6.42 6.42 1,649

Sources: Crude oil first purchase prices, natural gas wellhead prices, and number of rigs: Tables 9.1, 9.11, and 5.1, Monthly Energy

Review October 2007, DOE/EIA-0035(2007/10). 2006 constant dollars: U.S. Department of Commerce, Bureau of Economic Analysis,

Gross Domestic Product Implicit Price Deflators, October 2007.
For the eighth year in a row (and 12 out of the last 13

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 2006.

In 2006, the U.S. crude oil first purchase price started at

a monthly average of $57.85 per barrel in January, rose

to a high of $67.71 in July, and ended the year at $55.03

per barrel in December. The average annual U.S. crude

oil first purchase price increased from $50.28 in 2005 to

$59.69 per barrel in 2006.

Oil prices vary by region. The average annual 2006

crude oil first purchase price ranged from $64.23 per

barrel in Louisiana to $63.80 per barrel in Colorado,

$61.31 per barrel in Texas, $57.34 per barrel in

California, and a low of $51.85 per barrel in South

Dakota. {30}

The average annual wellhead natural gas price

decreased from $7.33 per thousand cubic feet in 2005 to

$6.42 in 2006. Monthly average natural gas prices

started at $8.66 per thousand cubic feet in January 2006,

declined to $5.03 in October, and ended the year at

$6.65 per thousand cubic feet in December 2006. {31}

Drilling: Also listed in Table 3 is the average number

of active rotary drilling rigs from 1977 to 2006. From

2005 to 2006, the annual average active rig count rose

from 1,381 to 1,649, a 19 percent increase.

Looking first at exploratory wells, there were 4,005

exploratory wells drilled in 2006 (Table 4). Of these, 14

percent were completed as oil wells, 39 percent were

completed as gas wells, and 47 percent were dry holes.

Exploratory oil and gas completions (excluding dry

holes) in 2006 were 8 percent more (Figure 7) than the

revised 2005 total.

Figures 9 and 10 show the average volume of

discoveries per exploratory well for dry natural gas

and oil, respectively, since 1977. The 2006 average

volume of oil discoveries per exploratory well

decreased 57 percent compared to 2005. The 2006

average volume of gas discoveries per exploratory well

decreased 1 percent compared to 2005.

The number of successful development wells increased

by 28 percent for oil and by 18 percent for gas from their

2005 levels (Figure 8). Including dry holes, there were

an estimated 49,507 exploratory and development

wells drilled in 2006. This is 22 percent more than in

2005 and 73 percent more than the average number of

wells drilled annually in the prior 10 years (28,630).

For the thirteenth 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 2006 and are expected to have an impact

on the energy industry in the future:

On December 13, 2005, ConocoPhillips Company

(ConocoPhillips) announced that it had agreed to

acquire Burlington Resources Incorporated for about

$35.6 billion of cash and stock. Additionally,

ConocoPhillips would assume approximately $1,078

million of Burlington Resources debt. Burlington’s

natural gas assets in North America would balance

political risks in [ConocoPhillips’] Venezuelan and

Russian ventures. {32}

On June 23, 2006, Anadarko Petroleum Corporation

agreed to acquire Kerr-McGee Corporation and

Western Gas Resources Incorporated for $21.1 billion

plus the assumption of about $2.2 billion of debt. The

resulting company would have industry-leading

positions in the deepwater Gulf of Mexico and the

Rockies. {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.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 11
Energy Information Administration

12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table 4. U.S. Exploratory and Development Well Completions,a1973-2006

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

2004 R 368 1,323 1,200 2,891 7,806 21,816 3,474 33,096

2005 R 448 1,532 1,358 3,338 9,668 27,014 4,063 40,745

2006 576 1,559 1,870 4,005 12,339 31,587 5,581 49,507

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 resources. 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 2007, DOE/EIA-0035(2007/10).
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 13

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

Figure 7. U.S. Exploratory Well Completions, 1996-2006

Figure 8. U.S. Development Well Completions, 1996-2006
Energy Information Administration

14 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 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, 1977-2006

Figure 10. U.S. Total Discoveries of Crude Oil per Exploratory Oil Well Completion, 1977-2006
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 and reserves development reached high

levels.

In 2006, U.S. crude oil proved reserves decreased and

oil production decreased, increasing the National

average R/P ratio from 12.6 to 12.7.

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

since 1945. After World War II, increased drilling and

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

drilling found fewer reserves than were produced, the

ratio became small er. R/ P ratios also vary

geographically, because of differences in development

history and reservoir conditions. The 2006 National

average R/P ratio for crude oil was 12.7-to-1. Areas

with relatively high R/P ratios are the Permian Basin of

Texas and New Mexico, and California, where

enhanced oil recovery techniques such as carbon

dioxide (CO2) injection or steamflooding have

improved 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 2005

to 2006 the U.S. average R/P ratio for natural gas

increased from 11.1 to 11.4 since proved reserves

increased more than production increased.

Different marketing, transportation, and production

characteristics for gas are seen when looking at

regional average R/P ratios as compared to the 2006

U.S. average R/P ratio of about 11.4-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. In fact, the proved

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

region, 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 2006. 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 2006 was 75,474 million barrels. This

substantially exceeds the 1977 proved reserves, but at

the end of 2006 there were still 22,312 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 11

percent of proved reserves additions of crude oil were

booked as new field discoveries from 1976 through 2006.

The other 89 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 551 trillion cubic feet of

gas was produced from 1977 through 2006 and there

are still 220,416 billion cubic feet of wet natural gas

proved reserves in 2006. Only 10 percent of proved

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 15
Energy Information Administration

16 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 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 (1977–2005){1-29}. 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, 1945-2006

Figure 12. Reserves-to-Production Ratios for Wet Natural Gas, 1945-2006
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 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 (1977–2005){1-29}. 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, 1977-2006

Figure 14. Components of Proved Ultimate Recovery for Wet Natural Gas, 1977-2006
Table 5. International Oil and Natural Gas Reserves as of December 31, 2006

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. . . . . . .

d

262,300 d262,275 1 Russia . . . . . . . . . . . . . . 1,680,000 1,688,755

2 Iranc. . . . . . . . . . . . . . . 136,270 133,000 2 Iranc. . . . . . . . . . . . . . . . 974,000 971,154

3 Iraqc. . . . . . . . . . . . . . . 115,000 125,100 3 Qatarc. . . . . . . . . . . . . . 910,500 906,000

4 Canadae. . . . . . . . . . . . 179,210 25,591 4 Saudia Arabiac. . . . . . . .

d

240,000 d240,000

5 Kuwaitc. . . . . . . . . . . . .

d

101,500 d100,110 5 United States . . . . . . . . . 211,085 211,085

6 United Arab Emiratesc. 97,800 70,560 6 United Arab Emiratesc. . 214,400 205,550

7 Russia. . . . . . . . . . . . . . 60,000 74,435 7 Nigeriac. . . . . . . . . . . . . 181,900 182,000

8 Venezuelac. . . . . . . . . . 80,012 52,945 8 Algeriac. . . . . . . . . . . . . 161,740 160,682

9 Libyac. . . . . . . . . . . . . . 41,464 34,970 9 Venezuelac. . . . . . . . . . 152,380 150,890

10 Nigeriac. . . . . . . . . . . . . 36,220 37,200 10 Iraqc. . . . . . . . . . . . . . . . 112,000 88,000

Top 10 Total. . . . . . . . . . . . . . 1,109,776 916,186 Top 10 Total . . . . . . . . . . . . . . 4,838,005 4,804,116

11 Kazakhstan. . . . . . . . . . 30,000 - 11 Turkmenistan . . . . . . . . . 100,000 -

12 United States . . . . . . . . 20,972 20,972 12 Kazakhstan . . . . . . . . . . 100,000 -

13 Qatarc. . . . . . . . . . . . . . 15,207 20,400 13 Indonesiac. . . . . . . . . . . 97,780 91,800

14 China . . . . . . . . . . . . . . 16,000 16,256 14 Australia . . . . . . . . . . . . . 30,370 152,359

15 Algeriac. . . . . . . . . . . . . 12,270 11,921 15 Norway . . . . . . . . . . . . . . 82,320 83,272

16 Brazil. . . . . . . . . . . . . . . 11,773 12,267 16 China . . . . . . . . . . . . . . . 80,000 55,606

17 Mexico . . . . . . . . . . . . . 12,352 11,656 17 Malaysia. . . . . . . . . . . . . 75,000 58,000

18 Angola . . . . . . . . . . . . . 8,000 9,330 18 Uzbekistan . . . . . . . . . . . 65,000 -

19 Norway . . . . . . . . . . . . . 7,849 7,070 19 Egypt . . . . . . . . . . . . . . . 58,500 66,364

20 Azerbaijan. . . . . . . . . . . 6,999 - 20 Canada. . . . . . . . . . . . . . 57,946 57,946

21 Sudan . . . . . . . . . . . . . . 5,000 6,615 21 Kuwaitc. . . . . . . . . . . . . .

d

55,000 d53,500

22 Oman . . . . . . . . . . . . . . 5,500 4,655 22 Libyac. . . . . . . . . . . . . . . 52,650 51,500

23 Ecuador . . . . . . . . . . . . 4,517 4,933 23 Netherlands . . . . . . . . . . 50,000 50,500

24 India . . . . . . . . . . . . . . . 5,625 3,812 24 Ukraine. . . . . . . . . . . . . . 39,000 -

25 Indonesiac. . . . . . . . . . 4,300 4,840 25 India . . . . . . . . . . . . . . . . 37,960 27,259

Top 25 Total. . . . . . . . . . . . . . 1,276,140 1,050,913 Top 25 Total . . . . . . . . . . . . . . 5,819,531 5,552,222

OPEC Total . . . . . . . . . . . . . . 902,343 853,321 OPEC Total . . . . . . . . . . . . . . . 3,152,350 3,101,076

World Total . . . . . . . . . . . . . . 1,317,447 1,144,358 World Total . . . . . . . . . . . . . . . 6,182,692 6,332,193

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).

d

Includes 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. 104, No.47 (December 18, 2006). Gulf Publishing Company, World

Oil, Vol.228, No. 9 (September, 2007).

Energy Information Administration

18 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report
reserve additions of natural gas were booked as new

field discoveries from 1976 through 2006. The other 90

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 6.3

quadrillion cubic feet of gas.

The United States ranked 12th in the world for proved

reserves of crude oil and 5th for natural gas in 2006. 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 2006. 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 26 billion. The Oil and Gas Journal

estimate includes a larger contribution of heavy oil

from Canadian tar sands. 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 2 percent in 2006 owing to an

increase in its estimate of Kazakstan and Iranian

reserves. The World Oil {36} estimate increased 3

percent in 2006 due to its larger estimate of Canadian

and Iranian reserves. For world gas reserves, the Oil &

Gas Journal reported a 1 percent increase, while World

Oil reported an 2 percent increase in 2006.

Several foreign cou ntries 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, Canada has

almost 5 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 2006:

 The U.S. consumed 99,873,000,000,000,000 Btu of

energy (99.9 quadrillion Btu). This was a

decrease of 0.82 quadrillion Btu from the 2005

level of consumption.

 62 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 (22 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 2006, 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 decreased from the 2005 total of 4.33

trillion cubic feet to 4.14 trillion cubic feet in 2006.

Imports satisfied approximately 19 percent of

consumption. Almost all of this gas was pipelined from

Canada. Some liquefied natural gas was imported from

Trinidad and Tobago, Nigeria, and Algeria.

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 2006 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.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 19
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 1996-2006 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 2006 Annual Report
3. Crude Oil Statistics

The United States had 20,972 million barrels of crude

oil proved reserves as of December 31, 2006. This is 4

percent (-785 million barrels) less than in 2005. The

principal factors contributing to the decline were lower

than average net revisions and adjustments and fewer

total discoveries.

The Gulf of Mexico Federal Offshore and Alaska, two

of the largest U.S. oil-producing areas, reported 10 and

7 percent declines in crude oil proved reserves.

Downward revisions exceeded revision increases in

these two areas in 2006.

Reserves additions of crude oil in the U.S. did not keep

pace with production. Operators replaced only 52

percent of 2006 crude oil production with reserves

additions (Figure 15).

Proved Reserves

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

as of December 31, 2006, by selected States and State

subdivisions.

Figure 16 maps 2006 crude oil proved reserves by area.

The following four areas account for 74 percent of U.S.

crude oil proved reserves:

Percent of

Area U.S. Oil Reserves

Texas 23

Alaska 18

Gulf of Mexico Federal Offshore 17

California 16

Area Total 74

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 21

Figure 15. Replacement of U.S. Crude Oil Production by Reserves Additions, 1996-2006.

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

.
Energy Information Administration

22 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

a

Includes 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 2006 contained in the

Petroleum Supply Annual 2006, DOE/EIA-0340(06).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 4,171 1 84 235 0 0 100 0 0 242 3,879

Lower 48 States . . . . . . . . . . . . . 17,586 93 1,506 1,353 982 1,176 404 30 43 1,410 17,093

Alabama. . . . . . . . . . . . . . . . . . . . 55 2 2 4 19 14 0 0 0 5 45

Arkansas . . . . . . . . . . . . . . . . . . . 40 5 3 5 0 0 0 0 0 6 37

California . . . . . . . . . . . . . . . . . . . 3,435 13 243 125 120 130 27 0 8 222 3,389

Coastal Region Onshore . . . . . 374 1 22 10 46 47 0 0 2 15 375

Los Angeles Basin Onshore. . . 300 6 83 23 47 49 6 0 6 16 364

San Joaquin Basin Onshore . . 2,556 6 115 76 27 34 16 0 0 176 2,448

State Offshore . . . . . . . . . . . . . 205 0 23 16 0 0 5 0 0 15 202

Colorado . . . . . . . . . . . . . . . . . . . 250 4 30 7 72 68 19 0 0 18 274

Florida . . . . . . . . . . . . . . . . . . . . . 59 1 0 20 0 0 0 0 0 2 38

Illinois. . . . . . . . . . . . . . . . . . . . . . 95 2 6 6 0 1 0 0 1 10 89

Indiana . . . . . . . . . . . . . . . . . . . . . 16 -5 1 2 0 3 0 0 0 1 12

Kansas. . . . . . . . . . . . . . . . . . . . . 281 9 23 20 1 1 3 1 1 35 263

Kentucky . . . . . . . . . . . . . . . . . . . 23 3 1 0 0 0 0 0 0 2 25

Louisiana . . . . . . . . . . . . . . . . . . . 432 13 47 31 44 39 23 0 2 53 428

North . . . . . . . . . . . . . . . . . . . . 68 8 5 8 2 2 3 0 0 8 68

South Onshore . . . . . . . . . . . . . 299 16 37 16 36 34 15 0 2 39 312

State Offshore . . . . . . . . . . . . . 65 -11 5 7 6 3 5 0 0 6 48

Michigan . . . . . . . . . . . . . . . . . . . 62 5 5 6 1 2 0 1 0 5 63

Mississippi . . . . . . . . . . . . . . . . . . 189 5 7 11 6 7 8 0 2 15 186

Montana . . . . . . . . . . . . . . . . . . . . 427 1 29 35 53 50 36 0 0 36 419

Nebraska . . . . . . . . . . . . . . . . . . . 16 0 1 1 0 0 0 0 0 2 14

New Mexico . . . . . . . . . . . . . . . . . 690 -2 66 45 64 90 26 0 0 56 705

East . . . . . . . . . . . . . . . . . . . . . 682 -5 65 43 64 90 26 0 0 55 696

West. . . . . . . . . . . . . . . . . . . . . 8 3 1 2 0 0 0 0 0 1 9

North Dakota . . . . . . . . . . . . . . . . 418 8 36 30 142 140 15 2 3 38 412

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

Oklahoma . . . . . . . . . . . . . . . . . . 630 -21 51 68 29 45 10 0 0 49 569

Pennsylvania . . . . . . . . . . . . . . . . 14 5 3 2 0 0 2 0 0 2 20

Texas . . . . . . . . . . . . . . . . . . . . . . 4,919 50 340 312 100 198 128 1 2 355 4,871

RRC District 1 . . . . . . . . . . . . . 65 5 7 3 20 24 8 0 0 10 76

RRC District 2 Onshore . . . . . . 62 12 7 9 2 2 1 0 0 8 65

RRC District 3 Onshore . . . . . . 179 11 21 20 7 10 9 1 1 25 180

RRC District 4 Onshore . . . . . . 40 7 2 15 1 0 1 0 0 4 30

RRC District 5 . . . . . . . . . . . . . 24 1 4 1 0 0 0 0 0 4 24

RRC District 6 . . . . . . . . . . . . . 168 8 8 36 0 18 6 0 0 15 157

RRC District 7B . . . . . . . . . . . . 80 -5 25 4 1 3 1 0 0 10 89

RRC District 7C . . . . . . . . . . . . 245 3 15 16 4 40 25 0 0 20 288

RRC District 8 . . . . . . . . . . . . . 1,731 2 119 102 42 75 44 0 1 111 1,717

RRC District 8A . . . . . . . . . . . . 2,164 2 107 88 18 25 30 0 0 129 2,093

RRC District 9 . . . . . . . . . . . . . 103 6 8 5 4 1 0 0 0 13 96

RRC District 10 . . . . . . . . . . . . 53 -2 17 11 1 0 3 0 0 6 53

State Offshore . . . . . . . . . . . . . 5 0 0 2 0 0 0 0 0 0 3

Utah . . . . . . . . . . . . . . . . . . . . . . . 256 0 55 12 42 76 16 2 0 17 334

West Virginia . . . . . . . . . . . . . . . . 21 2 6 4 0 0 0 0 0 2 23

Wyoming . . . . . . . . . . . . . . . . . . . 704 -2 72 51 32 37 19 2 0 43 706

Federal Offshore . . . . . . . . . . . . . 4,483 -3 471 555 257 272 71 21 24 431 4,096

Pacific (California) . . . . . . . . . . 441 0 29 6 0 0 2 0 1 26 441

Gulf of Mexico (Louisiana) . . . . 3,852 -2 397 520 202 215 68 21 18 347 3,500

Gulf of Mexico (Texas). . . . . . . 190 -1 45 29 55 57 1 0 5 58 155

Miscellaneousa. . . . . . . . . . . . . . 25 -3 3 0 0 2 0 0 0 1 26

U.S. Total . . . . . . . . . . . . . . . . . . 21,757 94 1,590 1,588 982 1,176 504 30 43 1,652 20,972

Table 6. Crude Oil Proved Reserves, Reserves Changes, and Production, 2006

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 2006

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 12/31/05 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/06
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 23

Figure 17. Changes in Crude Oil Proved Reserves by Area, 2005 to 2006

Figure 16. Crude Oil Proved Reserves by Area, 2006

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

Figure 17 maps the change in crude oil proved reserves

from 2005 to 2006 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 -48

Alaska -292

Gulf of Mexico Federal Offshore -387

California -46

Area Total -773

U.S. Total -785

The Gulf of Mexico had a 10 percent decrease in crude

oil proved reserves in 2006. Alaska declined 7 percent,

and Texas and California each declined 1 percent.

Figure 2 in Chapter 2 shows the components of the

changes in crude oil proved reserves for 2006 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 (see graph

below). They result from the drilling of exploratory

wells.

Total discoveries of crude oil were 577 million barrels

in 2006, 45 percent less than those of 2005 (1,051 million

barrels).

Only five areas had total discoveries of 35 million

barrels or more in 2006:

Percent of U.S.

Area Oil Total Discoveries

Texas 23

Federal Offshore Gulf of Mexico 20

Alaska 17

Montana 6

California 6

Area Total 72

The United States discovered an average of 1,135

million barrels of new crude oil proved reserves per

year in the prior 10 years. Total discoveries in 2006

were 49 percent lower than that average.

Extensions

Operators reported 504 million barrels of extensions in

2006, 37 percent less than in 2005. The highest volume

of extensions was reported in Texas (128 million

barrels). The second highest volume of 2006 extensions

was 100 million barrels in Alaska, followed by 69

million barrels in the Gulf of Mexico Federal Offshore

and 36 million barrels in Montana.

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

average of 558 million barrels of extensions per year.

The 2006 extensions were 10 percent less than that

average.

New Field Discoveries

New field discoveries accounted for 30 million barrels

of crude oil reserves additions. This was 85 percent less

than the new field discoveries of 2005. Seventy percent

of these discoveries (21 of 30 million barrels) were in

the Gulf of Mexico Federal Offshore.

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

average of 428 million barrels of reserves from new

field discoveries. Reserves from new field discoveries

in 2006 were only 7 percent of that average.

New Reservoir Discoveries in Old Fields

Operators reported 43 million barrels of crude oil

reserves from new reservoir discoveries in old fields in

2006. This is 5 percent more than in 2005. The majority

of the new reservoir discoveries in old fields (23 of 43

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 2006 Annual Report
In the prior 10 years, U.S. operators reported an annual

average of 149 million barrels of reserves from new

reservoir discoveries in old fields. Reserves from new

reservoir discoveries in old fields in 2006 were 71

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 1,590 million barrels of revision increases,

1,588 million barrels of revision decreases, and 94

million barrels of adjustments in 2006. Combined, there

were 96 million barrels of net revisions and

adjustments for crude oil in 2006.

In the prior 10 years, net revisions and adjustments

added an annual average of 759 million barrels. The

2006 net revisions and adjustments were 87 percent less

than that average.

Sales and Acquisitions

In the context of this report, Salesrepresents the volume

of crude oil proved reserves deducted from an

operator’s total reserves by sale or transfer of

operations of existing oil fields or properties to another

operator, instead of 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 for a given year. Since operators

have different engineering staffs and resources, or

different development plans or schedules, the estimate

of proved reserves for a field can change upon a change

in operatorship. Timing of the transfer of operations

can also impact these values.

In 2006, there were 982 million barrels of sales

transactions between operators and 1,176 million

barrels of acquisitions yielding a net difference of +194

million barrels.

Production

U.S. production of crude oil in 2006 was an estimated

1,652 million barrels. This volume, which does not

include lease condensate, was 5 percent lower than

2005’s production of 1,733 million barrels.

Part of the decline resulted from an August 2006

shut-in of producing wells in half of Alaska’s Prudhoe

Bay Field (still the largest producing U.S. oil field) for

inspection and repair of corrosion in the gathering

system.

In 2006, the Gulf of Mexico Federal Offshore remained

the largest oil producing area in the United States with

25 percent of the national total (405 million barrels of

production). Texas and Alaska were second and third,

with 21 and 15 percent of the national production total,

respectively. California was fourth with 13 percent.

For the second year in a row Montana had the largest

annual oil production increase of any State (6 million

barrels; a 20 percent increase) owing to continued

development of the Bakken Formation in the Elm

Coulee Field. This relatively new and important oil

field is difficult to produce and requires cutting-edge

technology for economic production.

The 2006 Form EIA-23 national production estimates

(1,652 million barrels of crude oil and 182 million

barrels of lease condensate) are 1.5 percent lower than

the comparable Petroleum Supply Annual (PSA) 2006

volumes for crude oil and lease condensate production

combined (1,862 million barrels).

Areas of Note: Large Discoveries

and Reserves Additions

The following State and area discussions summarize

notable activities during 2006 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 2006.

Utah

Utah reported the largest increase (78 million barrels)

of proved oil reserves in 2006. The majority of these

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 25
reserves additions were reported as acquisitions.

Utah’s production increased by 13 percent from 15 to

17 million barrels in 2006.

 Greater Aneth Field: On April 26, 2006,

Resolute Natural Resources Company and

Navajo Nation Oil and Gas Company

announced they had completed the purchase of

ExxonMobil’s assets in Greater Aneth Field in

southeast Utah. Their combined assets now

include 359 active producing wells and 289

active [CO2] injection wells in the Aneth,

McElmo Creek, and Ratherford Units. {40}

Colorado

Colorado reported a net increase of 24 million barrels of

crude oil proved reserves in 2006, primarily from

revision increases and extensions. Colorado’s

production decreased from 19 million barrels in 2005 to

18 million barrels in 2006.

 Wattenberg Field: Anadarko Petroleum

Corporation accelerated its infill drilling

program at its Wattenberg Field in northeast

Colorado in 2006 following the approval of

down-spacing which created a significant

increase in drill sites. {41} Although Wattenberg

Field is primarily a tight nonassociated natural

gas field (the 8th largest gas field in the U.S. in

2006, ranked by proved reserves), it produces

significant crude oil -- Wattenberg Field was the

16th largest oil field in the U.S. in 2006, ranked

by proved reserves. For a listing of the Top 100

U.S. oil and gas fields, see Appendix B.

New Mexico

New Mexico reported a net increase of 15 million

barrels of crude oil proved reserves in 2006. Extensions

and the net of sales and acquisitions provided the

majority of reserves additions. New Mexico’s

production declined from 58 million barrels in 2005 to

56 million barrels in 2006.

 Monument Field: On January 17, 2006 Apache

Corporation completed its purchase of

Amerada-Hess Corporation’s interest in eight

fields in the Permian Basin of west Texas and

New Mexico. Apache estimated the acquired

interests had proved reserves of 27 million

barrels of liquid hydrocarbons and 27 billion

cubic feet of natural gas equivalent at year-end

2005. {42}

Other Gain Areas

Pennsylvania: Pennsylvania reported a net increase of

6 million barrels of crude oil proved reserves in 2006.

Ohio: Ohio reported a net increase of 3 million barrels

of crude oil proved reserves in 2006.

Areas of Note:

Large Reserves Declines

The following areas had large declines in crude oil

proved reserves due to downward revisions or

unreplaced production.

Gulf of Mexico Federal Offshore

The Gulf of Mexico Federal Offshore crude oil proved

reserves declined 10 percent (-387 million barrels) in

2006. Crude oil production declined 1 percent from 409

million barrels in 2005 to 405 million barrels in 2006.

Alaska

Alaskan crude oil proved reserves declined 7 percent

(-292 million barrels) in 2006. Despite 100 million

barrels of extensions, net downward revisions

exceeded reserves additions. Alaska’s estimated 2006

production of 242 million barrels decreased 22 percent

from the 2005 level (312 million barrels). Part of the

decline resulted from an August 2006 shut-in of

producing wells in half of Alaska’s Prudhoe Bay Field

(still the largest producing U.S. oil field) for inspection

and repair of corrosion in the gathering system.

Oklahoma

There was a 10 percent decline (-61 million barrels) in

the crude oil proved reserves of Oklahoma in 2006.

Crude oil production from this area declined 4 percent

from its 2005 level.

Other Decline Areas

Discovery and development of new or existing oil

fields was also outpaced by crude oil production in the

following areas of the United States:

Texas: Proved oil reserves decreased by 1

percent (-48 million barrels).

California: Proved oil reserves decreased

by 1 percent (-46 million barrels).

Energy Information Administration

26 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report
Reserves in

Nonproducing Status

Not all proved reserves of crude oil reported in 2006

were producing. Operators reported 5,174 million

barrels of proved reserves in nonproducing status in

2006, 9 percent less than in 2005 (5,691 million barrels).

Nonproducing crude oil reserves (not including lease

condensate) are listed in Table 7.

Nonproducing reserves are those awaiting well

workovers, the drilling of extensions or additional

development wells, installation of production or

pipeline facilities, and depletion of other zones or

reservoirs before recompletion in reservoirs not

currently open to production.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 27

a

Includes 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).

b

Includes 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,” 2006.

Table 7. Reported Reserves in Nonproducing Status for Crude Oil, 2006a

(Million Barrels of 42 U.S. Gallons)

Nonproducing Nonproducing

Crude Oil Crude Oil

State and Subdivision Reserves State and Subdivision Reserves

Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 442

Lower 48 States . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,732

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

Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 496

Coastal Region Onshore . . . . . . . . . . . . . . . . . . . 85

Los Angeles Basin Onshore . . . . . . . . . . . . . . . . . 149

San Joaquin Basin Onshore. . . . . . . . . . . . . . . . . 228

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102

Florida . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Kansas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

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

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 198

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

South Onshore . . . . . . . . . . . . . . . . . . . . . . . . . . . 162

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

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

Montana. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159

East. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159

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

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

North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

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

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

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

Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,077

RRC District 1. . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

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

RRC District 3 Onshore . . . . . . . . . . . . . . . . . . . . 18

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

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

RRC District 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

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

RRC District 7C . . . . . . . . . . . . . . . . . . . . . . . . . . 120

RRC District 8. . . . . . . . . . . . . . . . . . . . . . . . . . . . 466

RRC District 8A. . . . . . . . . . . . . . . . . . . . . . . . . . . 386

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

RRC District 10. . . . . . . . . . . . . . . . . . . . . . . . . . . 9

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

Utah. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164

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

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

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 258

Federal Offshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,921

Pacific (California). . . . . . . . . . . . . . . . . . . . . . . . . 37

Gulf of Mexico (Louisiana)c. . . . . . . . . . . . . . . . . . 1,816

Gulf of Mexico (Texas) . . . . . . . . . . . . . . . . . . . . . 68

Miscellaneousb. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

U.S. Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,174

4. Natural Gas Statistics

Dry Natural Gas

Proved Reserves

The United States had 211,085 billion cubic feet of dry

natural gas proved reserves as of December 31, 2006

(Table 8), the highest level since 1976. Proved reserves

of natural gas increased by 3 percent from 2005 to 2006.

All natural gas proved reserves data shown in this

report exclude natural gas held in underground

storage.

Texas led the nation in natural gas reserves additions in

2006 with a 9 percent increase in dry gas proved

reserves due to rapid development of Barnett Shale

reservoirs in the Newark East Field. Advances in

horizontal drilling and hydraulic fracturing technology

and relatively high natural gas prices supported this

development. Alaska and Utah were second and third

for dry natural gas proved reserves additions in 2006.

Total U.S. reserves additions replaced 136 percent of

2006 dry gas production (Figure 18).

The proved reserves by State are shown on the map in

Figure 19. Eight areas accounted for 81 percent of the

Nation’s dry natural gas proved reserves:

Percent of

Area U.S. Gas Reserves

Texas 29

Wyoming 11

New Mexico 8

Oklahoma 8

Colorado 8

Gulf of Mexico Federal Offshore 7

Louisiana 5

Alaska 5

Area Total 81

Total U.S. natural gas production increased in 2006 due

to production increases in Texas (Barnett Shale),

Louisiana, and the Rocky Mountain states (Colorado,

Wyoming, Utah, and Montana). Texas had the largest

increase in production in 2006 (3 percent; 184 billion

cubic feet), while the Gulf of Mexico Federal Offshore

declined the most (6 percent; -168 billion cubic feet).

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 29

Figure 18. Replacement of U.S. Dry Natural Gas Production by Reserves Additions, 1996-2006.

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

30 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

a

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

b

Includes Federal offshore Alabama.

c

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

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

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

Information Administration production data for natural gas for 2006 contained in the Natural Gas Annual 2006, DOE/EIA-0131(06).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 8,171 -46 2,853 376 0 0 49 0 2 408 10,245

Lower 48 States . . . . . . . . . . . . . 196,214 789 17,980 22,293 22,850 25,846 21,729 409 1,153 18,137 200,840

Alabama. . . . . . . . . . . . . . . . . . . . 3,965 -11 234 208 188 253 146 0 7 287 3,911

Arkansas . . . . . . . . . . . . . . . . . . . 1,964 -26 101 113 4 5 491 7 32 188 2,269

California . . . . . . . . . . . . . . . . . . . 3,228 -74 156 419 274 252 176 0 4 255 2,794

Coastal Region Onshore . . . . . 268 -62 28 12 70 58 5 0 0 9 206

Los Angeles Basin Onshore. . . 176 0 7 29 35 38 4 0 0 8 153

San Joaquin Basin Onshore . . 2,694 -12 112 371 169 156 166 0 1 232 2,345

State Offshore . . . . . . . . . . . . . 90 0 9 7 0 0 1 0 3 6 90

Colorado . . . . . . . . . . . . . . . . . . . 16,596 52 1,178 1,524 1,539 1,540 1,980 14 26 1,174 17,149

Florida . . . . . . . . . . . . . . . . . . . . . 77 2 0 32 0 0 0 0 0 2 45

Kansas. . . . . . . . . . . . . . . . . . . . . 4,314 89 807 1,020 18 13 93 0 3 350 3,931

Kentucky . . . . . . . . . . . . . . . . . . . 2,151 -22 56 21 432 534 23 0 4 66 2,227

Louisiana . . . . . . . . . . . . . . . . . . . 10,447 86 1,191 1,417 500 738 1,026 27 185 1,309 10,474

North . . . . . . . . . . . . . . . . . . . . 6,695 -27 603 759 57 189 619 0 4 552 6,715

South Onshore. . . . . . . . . . . . . 3,334 135 526 607 388 523 328 10 148 674 3,335

State Offshore . . . . . . . . . . . . . 418 -22 62 51 55 26 79 17 33 83 424

Michigan . . . . . . . . . . . . . . . . . . . 2,910 112 460 291 48 27 86 1 5 197 3,065

Mississippi . . . . . . . . . . . . . . . . . . 755 -26 96 40 44 30 119 0 6 83 813

Montana. . . . . . . . . . . . . . . . . . . . 986 13 65 78 20 17 144 19 28 117 1,057

New Mexico . . . . . . . . . . . . . . . . . 18,201 91 1,273 1,203 6,248 6,278 793 35 140 1,426 17,934

East . . . . . . . . . . . . . . . . . . . . . 3,791 56 607 495 297 327 370 35 0 480 3,914

West. . . . . . . . . . . . . . . . . . . . . 14,410 35 666 708 5,951 5,951 423 0 140 946 14,020

New York . . . . . . . . . . . . . . . . . . . 349 33 22 38 55 52 5 45 0 50 363

North Dakota . . . . . . . . . . . . . . . . 453 18 70 31 53 40 30 1 3 52 479

Ohio . . . . . . . . . . . . . . . . . . . . . . . 898 129 49 112 11 83 17 0 0 78 975

Oklahoma . . . . . . . . . . . . . . . . . . 17,123 -149 1,515 1,868 821 1,202 2,051 0 12 1,601 17,464

Pennsylvania . . . . . . . . . . . . . . . . 2,782 -117 185 224 6 234 359 13 0 176 3,050

Texas . . . . . . . . . . . . . . . . . . . . . . 56,507 835 6,392 7,853 4,603 6,366 9,467 80 253 5,608 61,836

RRC District 1 . . . . . . . . . . . . . 1,161 77 36 182 0 4 74 2 0 109 1,063

RRC District 2 Onshore . . . . . . 2,073 207 209 511 138 195 321 9 18 323 2,060

RRC District 3 Onshore . . . . . . 3,192 -5 411 472 407 389 384 20 70 532 3,050

RRC District 4 Onshore . . . . . . 8,761 250 844 1,857 1,156 1,184 1,138 23 86 1,157 8,116

RRC District 5 . . . . . . . . . . . . . 9,557 84 2,318 683 661 804 1,953 4 0 783 12,593

RRC District 6 . . . . . . . . . . . . . 8,976 69 854 1,741 511 856 1,357 1 0 774 9,087

RRC District 7B . . . . . . . . . . . . 802 -61 197 67 48 57 681 0 0 90 1,471

RRC District 7C . . . . . . . . . . . . 5,123 25 170 634 111 231 691 0 0 369 5,126

RRC District 8 . . . . . . . . . . . . . 5,993 43 511 714 845 1,065 488 2 7 480 6,070

RRC District 8A . . . . . . . . . . . . 1,366 34 114 135 11 5 19 0 0 102 1,290

RRC District 9 . . . . . . . . . . . . . 4,328 4 139 183 516 1,318 1,535 0 0 407 6,218

RRC District 10 . . . . . . . . . . . . 4,910 95 573 639 128 198 826 2 0 450 5,387

State Offshore . . . . . . . . . . . . . 265 13 16 35 71 60 0 17 72 32 305

Utah . . . . . . . . . . . . . . . . . . . . . . . 4,295 -11 218 502 1,147 1,189 1,408 45 0 349 5,146

Virginia. . . . . . . . . . . . . . . . . . . . . 2,018 25 234 14 133 154 114 6 0 102 2,302

West Virginia . . . . . . . . . . . . . . . . 4,459 -251 298 188 745 886 229 3 5 187 4,509

Wyoming . . . . . . . . . . . . . . . . . . . 23,774 36 1,339 2,281 3,239 3,372 2,211 2 30 1,695 23,549

Federal Offshorea. . . . . . . . . . . . 17,831 -39 2,030 2,798 2,718 2,575 733 111 410 2,775 15,360

Pacific (California) . . . . . . . . . . 824 2 43 22 0 0 0 0 1 37 811

Gulf of Mexico (Louisiana)a. . . 13,665 -37 1,606 2,201 1,532 1,341 530 82 343 1,973 11,824

Gulf of Mexico (Texas). . . . . . . 3,342 -4 381 575 1,186 1,234 203 29 66 765 2,725

Miscellaneousb. . . . . . . . . . . . . . 131 -6 11 18 4 6 28 0 0 10 138

U.S. Total . . . . . . . . . . . . . . . . . . 204,385 743 20,833 22,669 22,850 25,846 21,778 409 1,155 18,545 211,085

Table 8. Dry Natural Gas Proved Reserves, Reserves Changes, and Production, 2006

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

Changes in Reserves During 2006

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 12/31/05 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/06
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 31

Figure 20. Changes in Dry Natural Gas Proved Reserves by Area, 2005 to 2006

Figure 19. Dry Natural Gas Proved Reserves by Area, 2006

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

Figure 20 maps the change in dry gas proved reserves

from 2005 to 2006 by area. Here’s how the top eight

areas fared, compared to the total United States:

Change in

U.S. Gas Reserves

Area (billion cubic feet)

Texas +5,329

Wyoming -225

New Mexico -267

Oklahoma +341

Colorado +553

Gulf of Mexico Federal Offshore -2,458

Louisiana +27

Alaska +2,074

Area Total +5,374

U.S. Total +6,700

Figure 4 in Chapter 2 shows the components of change

in dry natural gas proved reserves for 2006 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 (see graph below).

Total discoveries of dry natural gas reserves were

23,342 billion cubic feet in 2006, a 1 percent increase

from the level reported in 2005.

Seven areas reported total discoveries of dry natural

gas exceeding 1 trillion cubic feet in 2006:

2006 Total Discoveries

Area (Billion cubic feet)

Texas 9,800

Wyoming 2,243

Oklahoma 2,063

Colorado 2,020

Utah 1,453

Gulf of Mexico Federal Offshore 1,253

Louisiana 1,238

Area Total 20,070

U.S. Total 23,342

Extensions

The largest component of total discoveries in 2006 was

extensions of existing gas fields. Extensions were

21,778 billion cubic feet, 3 percent more than 2005 and

61 percent more than the prior 10-year average (13,522

billion cubic feet). Areas with the largest extensions

and their percentage of total extensions were:

Percent of

Area 2006 Extensions

Texas 43

Wyoming 10

Oklahoma 9

Colorado 9

Utah 6

Louisiana 5

New Mexico 4

Area Total 86

New Field Discoveries

New field discoveries were 409 billion cubic feet in

2006, 57 percent less than in 2005. The areas with the

largest new field discoveries were the Gulf of Mexico

Federal Offshore (111 billion cubic feet; 27 percent of

the total), Texas (80 billion cubic feet; 20 percent), Utah

(45 billion cubic feet; 11 percent) and New York (45

billion cubic feet; 11 percent). In the prior 10 years, U.S.

operators had reported an annual average of 1,659

billion cubic feet of reserves from new field discoveries.

Reserves from new field discoveries in 2006 were 75

percent less than the prior 10 year average.

New Reservoir Discoveries in Old Fields

New reservoir discoveries in old fields were 1,155

billion cubic feet, 4 percent less than 2005 (1,208 billion

cubic feet). The areas with the largest new reservoir

Energy Information Administration

32 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 33

a

Includes Federal offshore Alabama. b

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

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

Reserves.” They may differ from the official Energy Information Administration production data for natural gas for 2006 contained in the

Natural Gas Annual 2006, DOE/EIA-0131(06).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 8,237 -50 2,882 378 0 0 50 0 2 410 10,333

Lower 48 States . . . . . . . . . . . . . 205,071 996 18,758 23,361 23,904 27,082 22,784 425 1,195 18,963 210,083

Alabama. . . . . . . . . . . . . . . . . . . . 4,006 -2 238 213 192 259 150 0 7 290 3,963

Arkansas . . . . . . . . . . . . . . . . . . . 1,967 -28 101 114 4 5 492 7 33 188 2,271

California . . . . . . . . . . . . . . . . . . . 3,384 -73 163 440 287 266 186 0 4 268 2,935

Coastal Region Onshore . . . . . 277 -64 29 12 72 60 5 0 0 9 214

Los Angeles Basin Onshore. . . 186 -1 7 31 37 41 4 0 0 8 161

San Joaquin Basin Onshore . . 2,831 -9 118 390 178 165 176 0 1 244 2,470

State Offshore . . . . . . . . . . . . . 90 1 9 7 0 0 1 0 3 7 90

Colorado . . . . . . . . . . . . . . . . . . . 17,122 42 1,215 1,571 1,587 1,588 2,042 15 27 1,211 17,682

Florida . . . . . . . . . . . . . . . . . . . . . 87 1 0 35 0 0 0 0 0 3 50

Kansas. . . . . . . . . . . . . . . . . . . . . 4,598 103 862 1,090 19 14 100 0 3 374 4,197

Kentucky . . . . . . . . . . . . . . . . . . . 2,240 23 60 22 459 568 24 0 5 70 2,369

Louisiana . . . . . . . . . . . . . . . . . . . 10,679 95 1,222 1,453 519 762 1,049 29 192 1,346 10,710

North . . . . . . . . . . . . . . . . . . . . 6,768 -20 610 768 57 191 626 0 4 559 6,795

South Onshore. . . . . . . . . . . . . 3,478 134 548 632 404 544 341 11 154 701 3,473

State Offshore . . . . . . . . . . . . . 433 -19 64 53 58 27 82 18 34 86 442

Michigan . . . . . . . . . . . . . . . . . . . 2,961 112 467 295 48 27 88 1 5 201 3,117

Mississippi . . . . . . . . . . . . . . . . . . 758 -23 95 40 44 29 119 0 6 84 816

Montana. . . . . . . . . . . . . . . . . . . . 998 13 66 79 20 17 145 20 28 119 1,069

New Mexico . . . . . . . . . . . . . . . . . 19,344 138 1,369 1,292 6,612 6,645 851 39 147 1,525 19,104

East . . . . . . . . . . . . . . . . . . . . . 4,132 89 666 543 326 359 405 39 0 526 4,295

West. . . . . . . . . . . . . . . . . . . . . 15,212 49 703 749 6,286 6,286 446 0 147 999 14,809

New York . . . . . . . . . . . . . . . . . 349 32 22 38 55 52 5 45 0 49 363

North Dakota . . . . . . . . . . . . . . 508 20 79 34 60 45 34 1 4 58 539

Ohio . . . . . . . . . . . . . . . . . . . . . 898 128 49 112 11 83 18 0 0 78 975

Oklahoma. . . . . . . . . . . . . . . . . 18,146 -131 1,608 1,983 871 1,275 2,177 0 13 1,699 18,535

Pennsylvania . . . . . . . . . . . . . . 2,793 -117 186 225 6 235 361 14 0 177 3,064

Texas . . . . . . . . . . . . . . . . . . . . 60,178 891 6,708 8,348 4,906 6,807 10,090 84 265 5,964 65,805

RRC District 1 . . . . . . . . . . . . . 1,205 87 38 190 0 4 77 2 0 114 1,109

RRC District 2 Onshore . . . . . . 2,175 222 220 537 146 206 337 10 19 340 2,166

RRC District 3 Onshore . . . . . . 3,406 18 442 506 437 417 413 22 75 572 3,278

RRC District 4 Onshore . . . . . . 9,104 304 881 1,939 1,207 1,236 1,188 24 91 1,208 8,474

RRC District 5 . . . . . . . . . . . . . 9,611 72 2,328 686 664 807 1,962 4 0 786 12,648

RRC District 6 . . . . . . . . . . . . . 9,343 94 890 1,816 533 894 1,416 1 0 808 9,481

RRC District 7B . . . . . . . . . . . . 932 -95 222 76 54 65 770 0 0 101 1,663

RRC District 7C . . . . . . . . . . . . 5,702 49 190 708 124 258 772 0 0 412 5,727

RRC District 8 . . . . . . . . . . . . . 6,800 17 577 807 955 1,203 552 2 8 542 6,855

RRC District 8A . . . . . . . . . . . . 1,471 32 122 144 12 5 20 0 0 110 1,384

RRC District 9 . . . . . . . . . . . . . 4,734 -20 151 199 562 1,434 1,670 0 0 443 6,765

RRC District 10 . . . . . . . . . . . . 5,430 98 632 705 141 218 913 2 0 497 5,950

State Offshore . . . . . . . . . . . . . 265 13 15 35 71 60 0 17 72 31 305

Utah . . . . . . . . . . . . . . . . . . . . . . . 4,359 -21 220 509 1,161 1,204 1,426 46 0 353 5,211

Virginia. . . . . . . . . . . . . . . . . . . . . 2,018 25 234 14 133 154 114 6 0 102 2,302

West Virginia . . . . . . . . . . . . . . . . 4,572 -227 308 195 769 914 236 3 5 193 4,654

Wyoming . . . . . . . . . . . . . . . . . . . 24,722 14 1,391 2,370 3,365 3,503 2,297 1 31 1,761 24,463

Federal Offshorea. . . . . . . . . . . . 18,252 -11 2,084 2,871 2,772 2,624 751 114 420 2,841 15,750

Pacific (California) . . . . . . . . . . 825 1 43 22 0 0 0 0 1 37 811

Gulf of Mexico (Louisiana)a. . . 14,073 -10 1,658 2,272 1,581 1,384 547 85 353 2,036 12,201

Gulf of Mexico (Texas). . . . . . . 3,354 -2 383 577 1,191 1,240 204 29 66 768 2,738

Miscellaneousb. . . . . . . . . . . . . . 132 -8 11 18 4 6 29 0 0 9 139

U.S. Total . . . . . . . . . . . . . . . . . . 213,308 946 21,640 23,739 23,904 27,082 22,834 425 1,197 19,373 220,416

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 2006

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 12/31/05 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/06
Energy Information Administration

34 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

a

Includes Federal offshore Alabama. b

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

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

Reserves.” They may differ from the official Energy Information Administration production data for natural gas for 2006 contained in the

Natural Gas Annual 2006, DOE/EIA-0131(06).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 1,875 -49 32 267 0 0 46 0 2 192 1,447

Lower 48 States . . . . . . . . . . . . . 183,197 1,049 16,236 20,690 22,178 25,122 21,978 385 1,130 16,900 189,329

Alabama. . . . . . . . . . . . . . . . . . . . 3,977 -3 234 205 188 259 150 0 7 286 3,945

Arkansas . . . . . . . . . . . . . . . . . . . 1,921 -31 99 112 4 5 492 7 33 183 2,227

California . . . . . . . . . . . . . . . . . . . 799 -11 67 49 154 47 165 0 4 88 780

Coastal Region Onshore . . . . . 8 0 0 0 2 0 0 0 0 0 6

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

San Joaquin Basin Onshore . . 790 -11 65 49 152 47 165 0 1 87 769

State Offshore . . . . . . . . . . . . . 1 0 2 0 0 0 0 0 3 1 5

Colorado . . . . . . . . . . . . . . . . . . . 15,796 44 981 1,536 1,009 1,009 1,929 15 27 1,115 16,141

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

Kansas. . . . . . . . . . . . . . . . . . . . . 4,515 100 839 1,071 19 14 99 0 3 365 4,115

Kentucky . . . . . . . . . . . . . . . . . . . 2,210 24 53 22 459 568 24 0 5 70 2,333

Louisiana . . . . . . . . . . . . . . . . . . . 10,091 98 1,129 1,391 449 713 1,022 29 189 1,282 10,149

North . . . . . . . . . . . . . . . . . . . . 6,670 -18 597 757 57 190 626 0 4 550 6,705

South Onshore. . . . . . . . . . . . . 3,051 127 476 586 338 498 321 11 151 653 3,058

State Offshore . . . . . . . . . . . . . 370 -11 56 48 54 25 75 18 34 79 386

Michigan . . . . . . . . . . . . . . . . . . . 2,808 112 406 290 45 24 88 0 5 183 2,925

Mississippi . . . . . . . . . . . . . . . . . . 738 -23 94 39 39 29 112 0 4 81 795

Montana. . . . . . . . . . . . . . . . . . . . 837 12 15 60 1 0 123 20 28 100 874

New Mexico . . . . . . . . . . . . . . . . . 17,683 159 1,023 1,136 6,399 6,390 758 39 147 1,332 17,332

East . . . . . . . . . . . . . . . . . . . . . 2,569 110 332 408 121 112 312 39 0 340 2,605

West. . . . . . . . . . . . . . . . . . . . . 15,114 49 691 728 6,278 6,278 446 0 147 992 14,727

New York . . . . . . . . . . . . . . . . . . . 346 33 22 38 55 52 5 45 0 49 361

North Dakota . . . . . . . . . . . . . . . . 165 18 12 10 1 0 16 0 0 18 182

Ohio . . . . . . . . . . . . . . . . . . . . . . . 714 110 32 81 11 83 17 0 0 63 801

Oklahoma . . . . . . . . . . . . . . . . . . 17,337 -97 1,435 1,881 858 1,254 2,136 0 13 1,604 17,735

Pennsylvania . . . . . . . . . . . . . . . . 2,659 -129 183 214 6 235 337 14 0 166 2,913

Texas . . . . . . . . . . . . . . . . . . . . . . 53,175 875 5,953 7,636 4,751 6,401 9,768 80 241 5,370 58,736

RRC District 1 . . . . . . . . . . . . . 1,148 83 32 186 0 4 72 2 0 107 1,048

RRC District 2 Onshore . . . . . . 2,066 224 212 530 132 192 313 10 19 326 2,048

RRC District 3 Onshore . . . . . . 2,961 28 401 454 412 307 391 20 52 505 2,789

RRC District 4 Onshore . . . . . . 8,956 302 860 1,900 1,198 1,235 1,188 24 90 1,193 8,364

RRC District 5 . . . . . . . . . . . . . 9,560 72 2,316 685 664 807 1,961 4 0 780 12,591

RRC District 6 . . . . . . . . . . . . . 8,999 88 825 1,703 532 889 1,395 1 0 757 9,205

RRC District 7B . . . . . . . . . . . . 859 -94 212 72 53 62 765 0 0 90 1,589

RRC District 7C . . . . . . . . . . . . 4,665 42 110 653 108 138 673 0 0 336 4,531

RRC District 8 . . . . . . . . . . . . . 3,829 16 277 537 887 1,055 465 2 8 337 3,891

RRC District 8A . . . . . . . . . . . . 85 34 5 38 0 3 5 0 0 12 82

RRC District 9 . . . . . . . . . . . . . 4,608 -14 140 188 560 1,433 1,669 0 0 428 6,660

RRC District 10 . . . . . . . . . . . . 5,177 81 548 655 136 216 871 0 0 468 5,634

State Offshore . . . . . . . . . . . . . 262 13 15 35 69 60 0 17 72 31 304

Utah . . . . . . . . . . . . . . . . . . . . . . . 4,051 -22 184 472 1,145 1,199 1,382 40 0 323 4,894

Virginia. . . . . . . . . . . . . . . . . . . . . 2,018 25 234 14 133 154 114 6 0 102 2,302

West Virginia . . . . . . . . . . . . . . . . 4,553 -227 308 193 769 914 236 3 5 192 4,638

Wyoming . . . . . . . . . . . . . . . . . . . 24,338 5 1,365 2,335 3,362 3,502 2,286 0 31 1,714 24,116

Federal Offshorea. . . . . . . . . . . . 12,348 -11 1,559 1,887 2,317 2,264 690 87 388 2,206 10,915

Pacific (California) . . . . . . . . . . 49 0 8 0 0 0 0 0 0 2 55

Gulf of Mexico (Louisiana)a. . . 9,492 -10 1,274 1,445 1,261 1,150 487 58 329 1,574 8,500

Gulf of Mexico (Texas). . . . . . . 2,807 -1 277 442 1,056 1,114 203 29 59 630 2,360

Miscellaneousb. . . . . . . . . . . . . . 118 -12 9 18 4 6 29 0 0 8 120

U.S. Total . . . . . . . . . . . . . . . . . . 185,072 1,000 16,268 20,957 22,178 25,122 22,024 385 1,132 17,092 190,776

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

Wet After Lease Separation, 2006 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 2006

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 12/31/05 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/06
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 35

a

Includes Federal offshore Alabama. b

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

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

Reserves.” They may differ from the official Energy Information Administration production data for natural gas for 2006 contained in the

Natural Gas Annual 2006, DOE/EIA-0131(06).

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

Alaska . . . . . . . . . . . . . . . . . . . . . 6,362 -1 2,850 111 0 0 4 0 0 218 8,886

Lower 48 States . . . . . . . . . . . . . 21,874 -53 2,522 2,671 1,726 1,960 806 40 65 2,063 20,754

Alabama. . . . . . . . . . . . . . . . . . . . 29 1 4 8 4 0 0 0 0 4 18

Arkansas . . . . . . . . . . . . . . . . . . . 46 3 2 2 0 0 0 0 0 5 44

California . . . . . . . . . . . . . . . . . . . 2,585 -62 96 391 133 219 21 0 0 180 2,155

Coastal Region Onshore . . . . . 269 -64 29 12 70 60 5 0 0 9 208

Los Angeles Basin Onshore. . . 186 -1 7 31 37 41 4 0 0 8 161

San Joaquin Basin Onshore . . 2,041 2 53 341 26 118 11 0 0 157 1,701

State Offshore . . . . . . . . . . . . . 89 1 7 7 0 0 1 0 0 6 85

Colorado . . . . . . . . . . . . . . . . . . . 1,326 -2 234 35 578 579 113 0 0 96 1,541

Florida . . . . . . . . . . . . . . . . . . . . . 87 1 0 35 0 0 0 0 0 3 50

Kansas. . . . . . . . . . . . . . . . . . . . . 83 3 23 19 0 0 1 0 0 9 82

Kentucky . . . . . . . . . . . . . . . . . . . 30 -1 7 0 0 0 0 0 0 0 36

Louisiana . . . . . . . . . . . . . . . . . . . 588 -3 93 62 70 49 27 0 3 64 561

North . . . . . . . . . . . . . . . . . . . . 98 -2 13 11 0 1 0 0 0 9 90

South Onshore. . . . . . . . . . . . . 427 7 72 46 66 46 20 0 3 48 415

State Offshore . . . . . . . . . . . . . 63 -8 8 5 4 2 7 0 0 7 56

Michigan . . . . . . . . . . . . . . . . . . . 153 0 61 5 3 3 0 1 0 18 192

Mississippi . . . . . . . . . . . . . . . . . . 20 0 1 1 5 0 7 0 2 3 21

Montana. . . . . . . . . . . . . . . . . . . . 161 1 51 19 19 17 22 0 0 19 195

New Mexico . . . . . . . . . . . . . . . . . 1,661 -21 346 156 213 255 93 0 0 193 1,772

East . . . . . . . . . . . . . . . . . . . . . 1,563 -21 334 135 205 247 93 0 0 186 1,690

West. . . . . . . . . . . . . . . . . . . . . 98 0 12 21 8 8 0 0 0 7 82

New York . . . . . . . . . . . . . . . . . . . 3 -1 0 0 0 0 0 0 0 0 2

North Dakota . . . . . . . . . . . . . . . . 343 2 67 24 59 45 18 1 4 40 357

Ohio . . . . . . . . . . . . . . . . . . . . . . . 184 18 17 31 0 0 1 0 0 15 174

Oklahoma . . . . . . . . . . . . . . . . . . 809 -34 173 102 13 21 41 0 0 95 800

Pennsylvania . . . . . . . . . . . . . . . . 134 12 3 11 0 0 24 0 0 11 151

Texas . . . . . . . . . . . . . . . . . . . . . . 7,003 16 755 712 155 406 322 4 24 594 7,069

RRC District 1 . . . . . . . . . . . . . 57 4 6 4 0 0 5 0 0 7 61

RRC District 2 Onshore . . . . . . 109 -2 8 7 14 14 24 0 0 14 118

RRC District 3 Onshore . . . . . . 445 -10 41 52 25 110 22 2 23 67 489

RRC District 4 Onshore . . . . . . 148 2 21 39 9 1 0 0 1 15 110

RRC District 5 . . . . . . . . . . . . . 51 0 12 1 0 0 1 0 0 6 57

RRC District 6 . . . . . . . . . . . . . 344 6 65 113 1 5 21 0 0 51 276

RRC District 7B . . . . . . . . . . . . 73 -1 10 4 1 3 5 0 0 11 74

RRC District 7C . . . . . . . . . . . . 1,037 7 80 55 16 120 99 0 0 76 1,196

RRC District 8 . . . . . . . . . . . . . 2,971 1 300 270 68 148 87 0 0 205 2,964

RRC District 8A . . . . . . . . . . . . 1,386 -2 117 106 12 2 15 0 0 98 1,302

RRC District 9 . . . . . . . . . . . . . 126 -6 11 11 2 1 1 0 0 15 105

RRC District 10 . . . . . . . . . . . . 253 17 84 50 5 2 42 2 0 29 316

State Offshore . . . . . . . . . . . . . 3 0 0 0 2 0 0 0 0 0 1

Utah . . . . . . . . . . . . . . . . . . . . . . . 308 1 36 37 16 5 44 6 0 30 317

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

West Virginia . . . . . . . . . . . . . . . . 19 0 0 2 0 0 0 0 0 1 16

Wyoming . . . . . . . . . . . . . . . . . . . 384 9 26 35 3 1 11 1 0 47 347

Federal Offshorea. . . . . . . . . . . . 5,904 0 525 984 455 360 61 27 32 635 4,835

Pacific (California) . . . . . . . . . . 776 1 35 22 0 0 0 0 1 35 756

Gulf of Mexico (Louisiana)a. . . 4,581 0 384 827 320 234 60 27 24 462 3,701

Gulf of Mexico (Texas). . . . . . . 547 -1 106 135 135 126 1 0 7 138 378

Miscellaneousb. . . . . . . . . . . . . . 14 4 2 0 0 0 0 0 0 1 19

U.S. Total . . . . . . . . . . . . . . . . . . 28,236 -54 5,372 2,782 1,726 1,960 810 40 65 2,281 29,640

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

Wet After Lease Separation, 2006 (Billion Cubic Feet at 14.73 psia and 60° Fahrenheit)

Changes in Reserves During 2006

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 12/31/05 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/06
discoveries in old fields and their percentage of the

total were the Gulf of Mexico Federal Offshore (409

billion cubic feet; 35 percent of the total), Texas (253

billion cubic feet; 22 percent of the total), Louisiana (185

billion cubic feet; 16 percent of the total), and New

Mexico (140 billion cubic feet; 12 percent of the total).

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

annual average of 2,074 billion cubic feet of reserves

from new reservoirs discovered in old fields. Reserves

from new reservoirs discovered in old fields in 2006

were 44 percent less than that average.

Revisions and Adjustments

There were 20,833 billion cubic feet of revision

increases, 22,669 billion cubic feet of revision decreases,

and 743 billion cubic feet of adjustments in 2006. Net

revisions and adjustments were therefore a net loss of

1,093 billion cubic feet in 2006. The previous occurrence

of negative net revisions was in 1988. In the prior 10

years, operators reported net revisi ons and

adjustments of 4,535 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.

There were 22,850 billion cubic feet of sales transactions

between operators in 2006, and 25,846 billion cubic feet

of acquisitions. The net difference of 2,996 billion cubic

feet was added to the national total of dry natural gas

proved reserves in 2006.

Production

The estimated 2006 U.S. dry natural gas production

was 18,545 billion cubic feet (Table 8), a slight increase

from 2005 (18,458 billion cubic feet). Areas with the

largest production and their percentage of total

production were:

Percent of 2006 U.S.

Area Dry Gas Production

Texas 30

Gulf of Mexico Federal Offshore 15

Wyoming 9

Oklahoma 9

New Mexico 8

Louisiana 7

Colorado 6

Area Total 84

Wet Natural Gas

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

31, 2006 were 220,416 billion cubic feet, a 3 percent

increase over the volume reported in 2005 (Table 9). At

year-end 2006, proved wet natural gas reserves for the

lower 48 States had increased by 2 percent compared to

2005, while those of Alaska had increased by 25

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. See Appendix F for a discussion of

the methodology used to generate the wet and dry

natural gas reserves estimates tabulated in this report.

Nonassociated Natural Gas

Proved Reserves

Proved reserves of nonassociated (NA) natural gas, wet

after lease separation, in the United States increased by

3 percent (5,704 billion cubic feet) in 2006 to 190,776

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

wet natural gas proved reserves increased 3 percent to

a level of 189,329 billion cubic feet, while Alaska had a

23 percent decline to a level of 1,447 billion cubic feet.

Energy Information Administration

36 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report
Seven areas accounted for 81 percent of U.S. NA

natural gas proved reserves in 2006:

Percent of 2006 U.S.

Area NA Gas Reserves

Texas 31

Wyoming 13

Oklahoma 9

New Mexico 9

Colorado 8

Gulf of Mexico Federal Offshore 6

Louisiana 5

Area Total 81

Total Discoveries

NA wet natural gas total discoveries of 23,541 billion

cubic feet in 2006 were 2 percent more than the 2005

total of 23,055 billion cubic feet. Areas with the most

total discoveries of nonassociated natural gas in 2006

were Texas (10,089 billion cubic feet), Wyoming (2,317

billion cubic feet), Oklahoma (2,149 billion cubic feet),

Colorado (1,971 billion cubic feet), Utah (1,422 billion

cubic feet), Louisiana (1,240 billion cubic feet), and the

Gulf of Mexico Federal Offshore (1,165 billion cubic

feet).

Production

U.S. production of NA wet natural gas increased 2

percent from an estimated 16,827 billion cubic feet in

2005 to 17,092 billion cubic feet in 2006. The leading

producing areas were Texas (31 percent of the national

total), the Gulf of Mexico Federal Offshore (13 percent),

Wyoming (10 percent), Oklahoma (9 percent), New

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

Colorado (7 percent).

Associated-Dissolved Natural Gas

Proved Reserves

Proved reserves of associated-dissolved (AD) natural

gas, wet after lease separation, in the United States

increased 5 percent to 29,640 billion cubic feet in 2006

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

Alaska increased 40 percent to 8,886 billion cubic feet,

and decreased in the lower 48 States by 5 percent to

20,754 billion cubic feet.

The areas of the country with the largest AD wet

natural gas reserves and their percentage of the total

were:

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 37

Figure 21. Coalbed Natural Gas Proved Reserves, 1989-2006

Source: Energy Information Administration, Office of Oil and Gas.
Percent of 2006 U.S.

Area AD Gas Reserves

Alaska 30

Texas 24

Gulf of Mexico Federal Offshore 14

California 7

New Mexico 6

Area Total 81

These areas logically correspond to the areas of the

country with the largest volumes of crude oil reserves.

For the first time Alaska’s AD gas proved reserves

surpass those of Texas.

Production

U.S. production of AD wet natural gas decreased 6

percent from an estimated 2,432 billion cubic feet in

2005 to 2,281 billion cubic feet in 2006 (Table 11).

Production of AD wet natural gas in the lower 48 States

decreased from 2,174 billion cubic feet in 2005 to 2,063

billion cubic feet in 2006, a decline of 5 percent.

Although Alaska’s AD gas reserves were revised

significantly upward, its production declined 16

percent from 258 billion cubic feet in 2005 to 218 billion

cubic feet in 2006. The areas of the country with the

largest AD wet natural gas production and their

percentage of the total were:

Percent of 2006 U.S.

Area AD Gas Production

Gulf of Mexico Federal Offshore 26

Texas 26

Alaska 10

New Mexico 8

California 8

Area Total 78

Again, these areas logically correspond to the areas of

the country with the largest volumes of crude oil

production.

Coalbed Natural Gas

Proved Reserves

Proved reserves of coalbed natural gas decreased from

19,892 billion cubic feet in 2005 to 19,620 billion cubic

feet in 2006, a 1 percent decline (Figure 21). Coalbed

natural gas accounted for 9 percent of all 2006 dry

natural gas reserves (Table 12). Six States (Alabama,

Colorado, New Mexico, Utah, Virginia, and Wyoming)

currently have the vast majority (93 percent) of U.S.

coalbed natural gas proved reserves. Three of them

(Colorado, New Mexico, and Utah) reported declines

in their proved coalbed natural gas reserves in 2006.

Production

U.S. coalbed natural gas production increased 2

percent in 2006 to 1,758 billion cubic feet. It accounted

for 9 percent of U.S. dry natural 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 9 percent increase in dry natural gas

proved reserves in 2006 (5,329 billion cubic feet), the

largest of any State. Production also increased 3

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 May 2, 2006 Devon

Energy Corporation announced Devon's outlook

for the Barnett Shale has been greatly enhanced

by the results of its successful 20-acre infill well

pilot program. The company increased its

estimated recoveries for 20-acre infill horizontal

wells from 1.8 Bcfe per well to 2.0 Bcfe per well.

The increase is based upon the results to date of

29 horizontal infill wells drilled on its core

acreage. Ultimately, Devon expects to drill infill

wells on both its core and non-core acreage. {43}

Alaska

Alaska’s dry natural gas reserves increased by 25

percent (2,074 billion cubic feet) in 2006. This resulted

primarily from revision increases of associated

dissolved natural gas.

Energy Information Administration

38 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 39

Table 12. Coalbed Natural Gas Proved Reserves and Production for 1989–2006

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

New Eastern Western United

Year Alabama Colorado Mexico Utah Wyoming Virginia Statesa Statesb Othersc States

Reserves

1989 537 1,117 2,022 NA NA NA NA NA 0 3,676

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

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

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

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

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

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

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

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

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

1999 1,060 4,826 4,080 NA NA NA NA NA 3,263 13,229

2000 1,241 5,617 4,278 1,592 1,540 NA 1,399 41 -- 15,708

2001 1,162 6,252 4,324 1,685 2,297 NA 1,453 358 -- 17,531

2002 1,283 6,691 4,380 1,725 2,371 NA 1,488 553 -- 18,491

2003 1,665 6,473 4,396 1,224 2,759 NA 1,528 698 -- 18,743

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

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

2006 2,068 6,344 4,894 750 2,448 1,813 273 1,030 -- 19,620

Production

1989 23 12 56 NA NA NA NA NA 0 91

1990 36 26 133 NA NA NA NA NA 1 196

1991 68 48 229 NA NA NA NA NA 3 348

1992 89 82 358 NA NA NA NA NA 10 539

1993 103 125 486 NA NA NA NA NA 18 752

1994 108 179 530 NA NA NA NA NA 34 851

1995 109 226 574 NA NA NA NA NA 47 956

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

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

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

1999 108 432 582 NA NA NA NA NA 130 1,252

2000 109 451 550 74 133 NA 58 NA -- 1,379

2001 111 490 517 83 278 NA 69 NA -- 1,562

2002 117 520 471 103 302 NA 68 NA -- 1,614

2003 98 488 451 97 344 NA 71 NA -- 1,600

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

2005 113 515 514 75 336 NA 90 NA -- 1,732

2006 114 477 510 66 378 81 24 108 -- 1,758

a

Includes Illinois, Indiana, Ohio, Pennsylvania, Virginia, and West Virginia. In 2006, Virginia is individually listed.

b

Includes Arkansas, Kansas, Louisiana, Montana, and Oklahoma.

c

Includes Oklahoma, Pennsylvania, Utah, Virginia, West Virginia, and Wyoming. These states are individually listed or grouped in Eastern

States and Western States for 2000-2006.

NA -- Not applicable.

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

Utah’s dry natural gas reserves increased by 20 percent

(851 billion cubic feet) in 2006. This was the result of

development of the Greater Natural Buttes Field, a

tight natural gas play.

 Greater Natural Buttes Field: Kerr-McGee Oil &

Gas Onshore LP (KMG) a wholly-owned

subsidiary of Anadarko Petroleum Corporation

proposed to conduct infill drilling to develop the

hydrocarbon resources from oil and gas leases

within the Greater Natural Buttes Project Area

in Uintah County, Utah. KMG's plan is to drill

3,496 additional wells over a period of 10 years

on 40-acre and 20-acre surface spacing

throughout the project area. {44}

Areas of Note:

Large Reserves Declines

The qfollowing areas had large declines in dry natural

gas proved reserves due to downward revisions or

unreplaced production.

Gulf of Mexico Federal Offshore

The Gulf of Mexico Federal Offshore continues to

physically recover from the storm damage of

Hurricanes Katrina and Rita. However, proved dry

natural gas reserves in the Gulf of Mexico Federal

Offshore decreased by 14 percent (-2,458 billion cubic

feet) in 2006. Downward revisions of the reserves of

existing gas fields exceeded upward revisions by 778

billion cubic feet. Production also decreased by 6

percent from 2,906 billion cubic feet in 2005 to 2,738

billion cubic feet in 2006.

For a 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.

California

California’s proved dry natural gas reserves decreased

by 7 percent (-434 billion cubic feet) in 2006. Production

in California decreased 5 percent (-13 billion cubic feet)

in 2006.

Kansas

Kansas’ proved dry natural gas reserves decreased by 9

percent (-383 billion cubic feet) in 2006. Production in

Kansas decreased 8 percent (-30 billion cubic feet) in

2006.

Reserves in

Nonproducing Status

Nonproducing proved natural gas reserves (wet after

lease separation) of 66,714 billion cubic feet were

reported in 2006, 12 percent more than the 59,658

billion cubic feet reported in 2005 (Appendix D, Table

D10). About 35 percent of the reserves in nonproducing

status are located in Texas. Another 12 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 2006 Annual Report
5. Natural Gas Liquids Statistics

Natural Gas Liquids

Proved Reserves

U.S. natural gas liquids proved reserves increased 4

percent to 8,472 million barrels in 2006 (Table 13).

Reserves additions replaced 138 percent of 2006 natural

gas liquids production.

The reserves of seven areas accounted for 88 percent of

the Nation’s natural gas liquids proved reserves.

Percent of

Area U.S. NGL Reserves

Texas 39

Oklahoma 11

Utah and Wyoming 10

New Mexico 10

Gulf of Mexico Federal Offshore 8

Colorado 6

Alaska 4

Area Total 88

The volumes of natural gas liquids proved reserves and

production shown in Table 13 are the sum of the

natural gas plant liquid volumes listed in Table 14 and

the lease condensate volumes listed in Table 15.

Total Discoveries

Total discoveries of natural gas liquids reserves were

993 million barrels in 2006, an increase of 6 percent

from 2005 (937 million barrels) (see graph below).

Areas with the largest total discoveries were:

Percent of U.S.

Area NGL Total Discoveries

Texas 53

Utah and Wyoming 12

Oklahoma 11

Gulf of Mexico Federal Offshore 6

Colorado 6

New Mexico 5

Louisiana 5

Area Total 98

Extensions

Extensions were 924 million barrels in 2006, 7 percent

more than the 2005 volume of 863 million barrels. Areas

with the largest extensions were Texas (55 percent of

the National total), Utah and Wyoming (13 percent),

Oklahoma (11 percent), and Colorado (6 percent).

New Field Discoveries

New field discoveries in 2006 (16 million barrels) were

50 percent lower than in 2005 (32 million barrels). Areas

with the largest new field discoveries were the Gulf of

Mexico Federal Offshore (38 percent) and Texas (31

percent).

New Reservoir Discoveries in Old Fields

New reservoir discoveries in old fields in 2006 (53

million barrels) were 26 percent higher than they were

in 2005 (42 million barrels). Areas with the largest new

reservoir discoveries in old fields were the Gulf of

Mexico Federal Offshore (36 percent of the National

total), Louisiana (26 percent), and Texas (23 percent).

Revisions and Adjustments

In 2006, there were 845 million barrels of revision

increases, 1,010 million barrels of revision decreases,

and 173 million barrels of adjustments. The net of

revisions and adjustments was 8 million barrels.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 41
Energy Information Administration

42 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

a

This table is natural gas plant liquids (Table 14) plus lease condensate (Table 15). b

Includes Federal offshore Alabama.

c

Includes 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 . . . . . . . . . . . . . . . . . . . . . 352 0 0 0 0 0 0 0 0 14 338

Lower 48 States . . . . . . . . . . . . . 7,813 173 845 1,010 931 1,048 924 16 53 797 8,134

Alabama. . . . . . . . . . . . . . . . . . . . 61 9 5 5 17 5 3 0 0 5 56

Arkansas . . . . . . . . . . . . . . . . . . . 3 2 0 1 0 0 0 0 0 0 4

California . . . . . . . . . . . . . . . . . . . 137 8 8 19 17 18 8 0 0 11 132

Coastal Region Onshore . . . . . 16 5 3 1 7 6 1 0 0 1 22

Los Angeles Basin Onshore. . . 9 0 0 2 2 5 0 0 0 0 10

San Joaquin Basin Onshore . . 112 3 5 16 8 7 7 0 0 10 100

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

Colorado . . . . . . . . . . . . . . . . . . . 484 -14 34 41 70 62 54 0 1 32 478

Florida . . . . . . . . . . . . . . . . . . . . . 7 -2 0 2 0 0 0 0 0 0 3

Kansas. . . . . . . . . . . . . . . . . . . . . 224 8 44 54 1 1 6 0 0 19 209

Kentucky . . . . . . . . . . . . . . . . . . . 70 30 3 1 21 26 1 0 0 3 105

Louisiana . . . . . . . . . . . . . . . . . . . 292 -14 46 51 24 30 36 1 14 50 280

North . . . . . . . . . . . . . . . . . . . . 83 2 10 11 2 4 11 0 0 8 89

South Onshore. . . . . . . . . . . . . 168 -5 32 36 18 25 18 0 11 36 159

State Offshore . . . . . . . . . . . . . 41 -11 4 4 4 1 7 1 3 6 32

Michigan . . . . . . . . . . . . . . . . . . . 39 -1 10 3 1 0 1 0 0 3 42

Mississippi . . . . . . . . . . . . . . . . . . 7 0 1 0 0 0 1 0 0 1 8

Montana. . . . . . . . . . . . . . . . . . . . 9 1 1 1 0 0 1 0 0 1 10

New Mexico . . . . . . . . . . . . . . . . . 840 35 81 67 265 264 44 2 5 78 861

East . . . . . . . . . . . . . . . . . . . . . 271 23 47 38 27 26 28 2 0 37 295

West. . . . . . . . . . . . . . . . . . . . . 569 12 34 29 238 238 16 0 5 41 566

North Dakota . . . . . . . . . . . . . . . . 49 6 8 3 6 4 3 0 0 6 55

Oklahoma . . . . . . . . . . . . . . . . . . 839 13 88 96 38 61 105 0 1 81 892

Texas . . . . . . . . . . . . . . . . . . . . . . 3,080 53 331 441 243 346 505 5 12 313 3,335

RRC District 1 . . . . . . . . . . . . . 36 8 4 6 0 0 3 1 0 4 42

RRC District 2 Onshore . . . . . . 91 12 12 24 6 7 13 0 1 16 90

RRC District 3 Onshore . . . . . . 226 20 33 41 31 25 37 2 6 43 234

RRC District 4 Onshore . . . . . . 309 41 55 77 44 47 46 1 4 49 333

RRC District 5 . . . . . . . . . . . . . 48 -8 10 3 5 8 7 0 0 4 53

RRC District 6 . . . . . . . . . . . . . 333 16 37 72 20 37 57 0 0 31 357

RRC District 7B . . . . . . . . . . . . 90 -24 18 6 4 5 62 0 0 8 133

RRC District 7C . . . . . . . . . . . . 411 16 25 53 9 19 61 0 0 31 439

RRC District 8 . . . . . . . . . . . . . 575 -15 52 67 77 97 45 0 1 45 566

RRC District 8A . . . . . . . . . . . . 250 3 20 24 2 1 3 0 0 18 233

RRC District 9 . . . . . . . . . . . . . 285 -16 11 12 35 83 95 0 0 26 385

RRC District 10 . . . . . . . . . . . . 423 1 53 56 10 17 76 0 0 38 466

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

Utah and Wyoming . . . . . . . . . . . 879 -28 58 87 106 112 118 2 1 62 887

West Virginia . . . . . . . . . . . . . . . . 85 19 7 5 18 21 6 0 0 5 110

Federal Offshoreb. . . . . . . . . . . . 696 47 118 132 104 97 31 6 19 125 653

Pacific (California) . . . . . . . . . . 8 1 0 5 0 0 0 0 0 0 4

Gulf of Mexico (Louisiana)b. . . 603 44 99 107 84 72 26 6 18 102 575

Gulf of Mexico (Texas). . . . . . . 85 2 19 20 20 25 5 0 1 23 74

Miscellaneousc. . . . . . . . . . . . . . 12 1 2 1 0 1 1 0 0 2 14

U.S. Total . . . . . . . . . . . . . . . . . . 8,165 173 845 1,010 931 1,048 924 16 53 811 8,472

Table 13. Natural Gas Liquids Proved Reserves, Reserves Changes, and Production, 2006a

(Million Barrels of 42 U.S. Gallons)

Changes in Reserves During 2006

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 12/31/05 (+,–) (+) (–) (–) (+) (+) (+) (+) (–) 12/31/06
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 43

Table 14. Natural Gas Plant Liquids Proved Reserves and Production, 2006

(Million Barrels of 42 U.S. Gallons)

2006 2006 2006 2006

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska . . . . . . . . . . . . . . . . . . . . . . 338 14

Lower 48 States. . . . . . . . . . . . . . 6,795 615

Alabama . . . . . . . . . . . . . . . . . . . . 41 3

Arkansas . . . . . . . . . . . . . . . . . . . . 2 0

California. . . . . . . . . . . . . . . . . . . . 130 11

Coastal Region Onshore . . . . . 22 1

Los Angeles Basin Onshore . . . 8 0

San Joaquin Basin Onshore. . . 100 10

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

Colorado . . . . . . . . . . . . . . . . . . . . 382 26

Florida. . . . . . . . . . . . . . . . . . . . . . 3 0

Kansas . . . . . . . . . . . . . . . . . . . . . 204 18

Kentucky . . . . . . . . . . . . . . . . . . . . 104 3

Louisiana. . . . . . . . . . . . . . . . . . . . 176 28

North. . . . . . . . . . . . . . . . . . . . . 60 5

South Onshore . . . . . . . . . . . . . 94 19

State Offshore. . . . . . . . . . . . . . 22 4

Michigan . . . . . . . . . . . . . . . . . . . . 36 2

Mississippi. . . . . . . . . . . . . . . . . . . 2 0

Montana . . . . . . . . . . . . . . . . . . . . 10 1

New Mexico . . . . . . . . . . . . . . . . . 804 68

East . . . . . . . . . . . . . . . . . . . . . 264 32

West . . . . . . . . . . . . . . . . . . . . . 540 36

North Dakota. . . . . . . . . . . . . . . . . 51 6

Oklahoma . . . . . . . . . . . . . . . . . . . 732 67

Texas . . . . . . . . . . . . . . . . . . . . . . 2,913 260

RRC District 1. . . . . . . . . . . . . . 32 3

RRC District 2 Onshore . . . . . . 74 12

RRC District 3 Onshore . . . . . . 159 28

RRC District 4 Onshore . . . . . . 246 35

RRC District 5. . . . . . . . . . . . . . 42 3

RRC District 6. . . . . . . . . . . . . . 279 24

RRC District 7B. . . . . . . . . . . . . 131 8

RRC District 7C . . . . . . . . . . . . 404 29

RRC District 8. . . . . . . . . . . . . . 547 43

RRC District 8A. . . . . . . . . . . . . 231 18

RRC District 9. . . . . . . . . . . . . . 372 24

RRC District 10. . . . . . . . . . . . . 396 33

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

Utah and Wyoming . . . . . . . . . . . . 686 49

West Virginia. . . . . . . . . . . . . . . . . 109 5

Federal Offshorea. . . . . . . . . . . . . 399 67

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

Gulf of Mexico (Louisiana)a. . . 390 65

Gulf of Mexico (Texas) . . . . . . . 9 2

Miscellaneousb. . . . . . . . . . . . . . . 11 1

U.S. Total . . . . . . . . . . . . . . . . . . . 7,133 629

a

Includes Federal Offshore Alabama. b

Includes 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 2006 contained in the publications Petroleum Supply Annual 2006,

DOE/EIA-0340(2006) and Natural Gas Annual 2006, DOE/EIA-0131(2006).
Energy Information Administration

44 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table 15. Lease Condensate Proved Reserves and Production, 2006

(Million Barrels of 42 U.S. Gallons)

2006 2006 2006 2006

State and Subdivision Reserves Production State and Subdivision Reserves Production

Alaska . . . . . . . . . . . . . . . . . . . . . . 0 0

Lower 48 States. . . . . . . . . . . . . . 1,339 182

Alabama . . . . . . . . . . . . . . . . . . . . 15 2

Arkansas . . . . . . . . . . . . . . . . . . . . 2 0

California. . . . . . . . . . . . . . . . . . . . 2 0

Coastal Region Onshore . . . . . 0 0

Los Angeles Basin Onshore . . . 2 0

San Joaquin Basin Onshore. . . 0 0

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

Colorado . . . . . . . . . . . . . . . . . . . . 96 6

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

Kansas . . . . . . . . . . . . . . . . . . . . . 5 1

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

Louisiana. . . . . . . . . . . . . . . . . . . . 104 22

North. . . . . . . . . . . . . . . . . . . . . 29 3

South Onshore . . . . . . . . . . . . . 65 17

State Offshore. . . . . . . . . . . . . . 10 2

Michigan . . . . . . . . . . . . . . . . . . . . 6 1

Mississippi. . . . . . . . . . . . . . . . . . . 6 1

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

New Mexico . . . . . . . . . . . . . . . . . 57 10

East . . . . . . . . . . . . . . . . . . . . . 31 5

West . . . . . . . . . . . . . . . . . . . . . 26 5

North Dakota. . . . . . . . . . . . . . . . . 4 0

Oklahoma . . . . . . . . . . . . . . . . . . . 160 14

Texas . . . . . . . . . . . . . . . . . . . . . . 422 53

RRC District 1. . . . . . . . . . . . . . 10 1

RRC District 2 Onshore . . . . . . 16 4

RRC District 3 Onshore . . . . . . 75 15

RRC District 4 Onshore . . . . . . 87 14

RRC District 5. . . . . . . . . . . . . . 11 1

RRC District 6. . . . . . . . . . . . . . 78 7

RRC District 7B. . . . . . . . . . . . . 2 0

RRC District 7C . . . . . . . . . . . . 35 2

RRC District 8. . . . . . . . . . . . . . 19 2

RRC District 8A. . . . . . . . . . . . . 2 0

RRC District 9. . . . . . . . . . . . . . 13 2

RRC District 10. . . . . . . . . . . . . 70 5

State Offshore. . . . . . . . . . . . . . 4 0

Utah and Wyoming . . . . . . . . . . . . 201 13

West Virginia. . . . . . . . . . . . . . . . . 1 0

Federal Offshorea. . . . . . . . . . . . . 254 58

Pacific (California). . . . . . . . . . . 4 0

Gulf of Mexico (Louisiana)a. . . 185 37

Gulf of Mexico (Texas) . . . . . . . 65 21

Miscellaneousb. . . . . . . . . . . . . . . 3 1

U.S. Total . . . . . . . . . . . . . . . . . . . 1,339 182

a

Includes Federal Offshore Alabama. b

Includes 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” 2006.

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

There were 1,048 million barrels of acquisitions and 931

million barrels of sales in 2006. The net of these

transactions added 117 million barrels of natural gas

liquids proved reserves.

Production

Natural gas liquids production was an estimated 811

million barrels in 2006, an increase of 3 percent from

2005’s production (788 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 39

Gulf of Mexico Federal Offshore 15

Oklahoma 10

New Mexico 10

Utah and Wyoming 8

Louisiana 6

Area Total 88

Natural Gas Plant Liquids

Proved Reserves

Natural gas plant liquids proved reserves increased in

2006 to 7,133 million barrels, a 3 percent increase from

the 2005 level (6,903 million barrels) (Table 14). Six

areas accounted for about 83 percent of the Nation’s

natural gas plant liquids proved reserves:

Percent of

Area U.S. Gas Plant Liquids

Texas 41

New Mexico 11

Oklahoma 10

Utah and Wyoming 10

Gulf of Mexico Federal Offshore 6

Colorado 5

Area Total 83

Production

Natural gas plant liquids production increased 2

percent in 2006—from 614 million barrels in 2005 to

629 million barrels of production (Table 14).

At the time of the Form EIA-64A survey mailout, the

number of unique active U.S. natural gas processing

plants had increased from 489 in 2005 to 491 in 2006.

The top six areas for proved reserves of natural gas

plant liquids accounted for about 86 percent of the

Nation’s natural gas plant liquids production:

Percent of U.S.

Area Gas Plant Liquids Production

Texas 41

New Mexico 11

Oklahoma 11

Gulf of Mexico Federal Offshore 11

Utah and Wyoming 8

Colorado 4

Area Total 86

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 1,339 million barrels in 2006 (Table 15).

This was 6 percent higher than the volume reported in

2005 (1,262 million barrels). The reserves of five areas

accounted for about 86 percent of the Nation’s lease

condensate proved reserves.

Percent of U.S.

Area Condensate Reserves

Texas 32

Gulf of Mexico Federal Offshore 19

Utah and Wyoming 15

Oklahoma 12

Louisiana 8

Area Total 86

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report 45
Production

Production of lease condensate was 182 million barrels

in 2006, an increase of 5 percent from 2005’s production

(174 million barrels). The production of five areas

accounted for about 88 percent of the Nation’s lease

condensate production.

Percent of U.S.

Area Condensate Production

Gulf of Mexico Federal Offshore 32

Texas 29

Louisiana 12

Oklahoma 8

Utah and Wyoming 7

Area Total 88

Reserves in

Nonproducing Status

Like crude oil and natural gas, not all lease condensate

proved reserves were producing during 2006. Proved

reserves of 504 million barrels of lease condensate, an

increase of 17 percent from 2005’s level (430 million

barrels), were reported in nonproducing status in 2006

(Appendix D, Table D10). About 27 percent of the

nonproducing lease condensate reserves were located

in Texas and 26 percent were in the Gulf of Mexico

Federal Offshore.

Energy Information Administration

46 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report
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Energy Information Administration

48 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 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 2001 through 2006 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 2006 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

sm all operato rs for 2006 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 2001

through 2006 have changed from 191,743 billion cubic

feet to 220,416 billion cubic feet (Table A1). These

proved reserves are concentrated in the larger

companies. In 2006, the top 20 operators (Class 1-10 and

Class 11-20) producing companies had 61 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 19 percent in their natural gas proved

reserves from 2001 to 2006. The rest of the operators in

(Class 21-100, Class 101-500, and Class Other) had an

increase of 7 percent in their reserves in the same time

period. In 2006, the top 20 operators' natural gas

reserves had an increase of 6 percent from 2005.

Natural Gas Production

Wet natural gas production has increased from 19,259

billion cubic feet in 2005 to 19,373 billion cubic feet in

2006 (Table A2). In 2006, the top 20 producing

companies had 57 percent of the production of wet

natural gas. The next two size classes have 23 and 13

percent of the wet natural gas production, respectively.

The top 20 operators had a decrease of 9 percent in wet

natural gas production from 2001 to 2006. The rest of

the operators had a decrease of 3 percent from 2001 to

2006.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report A-1

0

50

100

150

200

250

300

2001 2002 2003 2004 2005 2006

1-10 11-20 21-100 101-500 Others

21-100

23%

101-500

14%

Others

6%

1-10

41%

11-20

16%
Crude Oil Proved Reserves

The 10 largest producing companies in 2006 had 54

percent of U.S. proved reserves of crude oil. The 20

largest oil and gas producing companies in 2006 had 64

percent of proved reserves of crude oil (Table A3),

Proved reserves of crude oil decreased 4 percent in

2006 from 2005.

Crude Oil Production

Crude oil production reported for 2005 to 2006 has

decreased from 1,733 million barrels to 1,652 million

barrels (Table A4). The 20 largest oil and gas producing

companies had 60 percent of U.S. production of crude

oil in 2006. In 2005 they accounted for 63 percent of

production.

Crude Oil and Natural Gas Fields

The number of fields in which Category I and Category

II operators were active increased during the 2001-2006

period (Table A5). From 2001-2006, the number of

fields in which the top 20 operators were active

increased by 1,174 fields (20 percent) while in 2006 the

number increased by 954 fields from 2005.

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 2006 operated production data.

Energy Information Administration

A-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

0

5

10

15

20

25

30

2001 2002 2003 2004 2005 2006

1-10 11-20 21-100 101-500 Others

1-10

47%

11-20

10%

21-100

18%

101-500

10%

Others

15%

`
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report A-3

Class 1-10 88,936 88,100 82,222 81,325 80,785 97,372 16,587 8,436 9,737.237

Percent of Total 46.4% 45.0% 41.7% 40.4% 37.9% 44.2% 20.5% 9.5%

Class 11-20 24,588 25,938 29,890 38,643 47,078 38,134 -8,944 13,546 3,813.421

Percent of Total 12.8% 13.3% 15.2% 19.2% 22.1% 17.3% -19.0% 55.1%

Class 21-100 50,055 50,633 53,098 50,149 52,061 52,064 3 2,009 650.802

Percent of Total 26.1% 25.9% 26.9% 24.9% 24.4% 23.6% 0.0% 4.0%

Class 101-500 19,046 19,723 20,030 20,912 21,737 21,877 141 2,831 54.693

Percent of Total 9.9% 10.1% 10.2% 10.4% 10.2% 9.9% 0.6% 14.9%

Class Other (13,320) 9,118 11,167 11,905 10,170 11,647 10,968 -678 1,850 0.823

Percent of Total 4.8% 5.7% 6.0% 5.1% 5.5% 5.0% -5.8% 20.3%

Category I (173) 162,144 169,056 173,325 173,225 178,269 189,644 11,375 27,500 1,102.582

Percent of Total 88.2% 88.6% 87.9% 88.6% 88.9% 82.6% -4.0% 7.7%

Category II (467) 13,346 11,051 11,983 12,494 11,838 27,294 15,456 13,948 58.446

Percent of Total 7.0% 5.7% 6.1% 6.2% 5.5% 12.4% 130.6% 104.5%

Category III (13,180) 9,342 11,184 11,937 10,437 11,826 10,989 -837 1,647 0.834

Percent of Total 4.9% 5.7% 6.1% 5.2% 5.5% 5.0% -7.1% 17.6%

Total Published 191,743 195,561 197,145 201,200 213,308 220,416 7,108 28,673 15.949

Table A1. Natural Gas Proved Reserves, Wet After Lease Separation, by Operator Production Size Class,

2001–2006

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

2005–2006 2001–2006 2006

Volume and Volume and Average

Percent Percent Reserves

Size Class 2001 2002 2003 2004 2005 2006 Change Change per Operator

Note: There were 13,180 active Category III operators in the 2006 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 700 Category III operators (Table E2). The "other" size class represents 13,320 operators in the

2006 frame (13,820 active operators minus the 500 largest operators).

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

A-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Class 1-10 9,019 8,996 8,220 7,617 7,068 7,956 888 -1,063 795.593

Percent of Total 43.7% 44.4% 40.6% 38.1% 36.7% 41.1% 12.6% -11.8%

Class 11-20 3,064 2,854 3,136 3,647 3,534 3,078 -456 14 307.847

Percent of Total 14.8% 14.1% 15.5% 18.2% 18.4% 15.9% -12.9% 0.5%

Class 21-100 4,949 4,763 5,275 4,982 4,832 4,492 -340 -457 56.154

Percent of Total 24.0% 23.5% 26.1% 24.9% 25.1% 23.2% -7.0% -9.2%

Class 101-500 2,609 2,475 2,386 2,559 2,506 2,605 99 -4 6.513

Percent of Total 12.6% 12.2% 11.8% 12.8% 13.0% 13.4% 4.0% -0.1%

Class Other (13,320) 1,000 1,161 1,215 1,213 1,318 1,241 -77 241 0.093

Percent of Total 4.8% 5.7% 6.0% 6.1% 6.8% 6.4% -5.8% 24.1%

Category I (173) 17,672 17,335 17,347 17,036 16,311 15,092 -1,219 -2,579 87.238

Percent of Total 85.6% 85.6% 85.7% 85.1% 84.7% 77.9% -7.5% -14.6%

Category II (467) 1,932 1,738 1,648 1,718 1,605 3,026 1,421 1,094 6.480

Percent of Total 9.4% 8.6% 8.1% 8.6% 8.3% 15.6% 88.5% 56.6%

Category III (13,180) 1,038 1,176 1,236 1,263 1,342 1,255 -88 216 0.095

Percent of Total 5.0% 5.8% 6.1% 6.3% 7.0% 6.5% -6.5% 20.8%

Total Published 20,642 20,248 20,231 20,017 19,259 19,373 114 -1,269 1.402

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 0.6% -6.1%

Table A2. Natural Gas Production, Wet After Lease Separation, by Operator Production Size Class,

2001–2006

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

2005–2006 2001–2006 2006

Volume and Volume and Average

Percent Percent Production

Size Class 2001 2002 2003 2004 2005 2006 Change Change per Operator

Note: There were 13,180 active Category III operators in the 2006 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 700 Category III operators (Table E2). The "other" size class represents 13,320 operators in the

2006 frame (13,820 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 2006 Annual Report A-5

Class 1-10 13,590 13,346 13,355 12,454 11,775 11,352 -424 -2,239 1,135.171

Percent of Total 60.5% 58.9% 61.0% 58.3% 54.1% 54.1% -3.6% -16.5%

Class 11-20 2,901 2,817 1,907 2,053 2,659 2,048 -612 -854 204.758

Percent of Total 12.9% 12.4% 8.7% 9.6% 12.2% 9.8% -23.0% -29.4%

Class 21-100 2,856 3,230 3,483 3,711 3,915 4,066 151 1,210 50.827

Percent of Total 12.7% 14.2% 15.9% 17.4% 18.0% 19.4% 3.9% 42.4%

Class 101-500 1,794 1,817 1,705 1,761 1,969 2,111 142 317 5.278

Percent of Total 8.0% 8.0% 7.8% 8.2% 9.1% 10.1% 7.2% 17.7%

Class Other (13,320) 1,305 1,468 1,440 1,393 1,439 1,395 -43 91 0.105

Percent of Total 5.8% 6.5% 6.6% 6.5% 6.6% 6.7% -3.0% 6.9%

Category I (173) 20,325 20,213 19,499 19,055 19,348 17,927 -1,420 -2,398 103.626

Percent of Total 90.6% 89.1% 89.1% 89.2% 88.9% 85.5% -7.3% -11.8%

Category II (467) 794 992 937 906 954 1,642 689 848 3.517

Percent of Total 3.5% 4.4% 4.3% 4.2% 4.4% 7.8% 72.2% 106.7%

Category III (13,180) 1,326 1,472 1,456 1,410 1,456 1,403 -53 76 0.106

Percent of Total 5.9% 6.5% 6.6% 6.6% 6.7% 6.7% -3.7% 5.8%

Total Published 22,446 22,677 21,891 21,371 21,757 20,972 -785 -1,474 1.518

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -3.6% -6.6%

Table A3. Crude Oil Proved Reserves by Operator Production Size Class, 2001–2006

(Million Barrels of 42 U.S. Gallons)

2005–2006 2001–2006 2006

Volume and Volume and Average

Percent Percent Reserves

Size Class 2001 2002 2003 2004 2005 2006 Change Change per Operator

Note: There were 13,180 active Category III operators in the 2006 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 700 Category III operators (Table E2). The "other" size class represents 13,320 operators in the

2006 frame (13,820 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 2006 Annual Report

Class 1-10 1,061 1,037 1,047 986 912 820 -91 -240 82.042

Percent of Total 55.4% 55.3% 55.8% 54.2% 52.6% 49.7% -10.0% -22.6%

Class 11-20 240 233 205 180 178 170 -7 -70 17.022

Percent of Total 12.5% 12.4% 10.9% 9.9% 10.3% 10.3% -4.2% -29.2%

Class 21-100 233 240 272 303 293 309 16 76 3.866

Percent of Total 12.2% 12.8% 14.5% 16.6% 16.9% 18.7% 5.6% 32.8%

Class 101-500 195 181 178 172 178 173 -5 -22 0.433

Percent of Total 10.2% 9.7% 9.5% 9.5% 10.3% 10.5% -2.7% -11.4%

Class Other (13,320) 186 184 175 178 173 179 6 -7 0.013

Percent of Total 9.7% 9.8% 9.3% 9.8% 10.0% 10.8% 3.6% -3.7%

Category I (173) 1,612 1,573 1,574 1,534 1,451 1,314 -138 -299 7.593

Percent of Total 84.2% 83.9% 83.9% 84.3% 83.7% 79.5% -9.5% -18.5%

Category II (467) 112 115 124 105 105 157 52 45 0.336

Percent of Total 5.8% 6.1% 6.6% 5.8% 6.1% 9.5% 49.2% 40.5%

Category III (13,180) 191 187 179 180 176 181 5 -10 0.014

Percent of Total 10.0% 10.0% 9.5% 9.9% 10.2% 11.0% 2.8% -5.0%

Total Published 1,915 1,875 1,877 1,819 1,733 1,652 -81 -263 0.120

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% -4.7% -13.7%

Table A4. Crude Oil Production by Operator Production Size Class, 2001–2006

(Million Barrels of 42 U.S. Gallons)

2005–2006 2001–2006 2006

Volume and Volume and Average

Percent Percent Production

Size Class 2001 2002 2003 2004 2005 2006 Change Change per Operator

Note: There were 13,180 active Category III operators in the 2006 sample frame. The reserves and production of Category III operators

were estimated from an adjusted sample of 700 Category III operators (Table E2). The "other" size class represents 13,320 operators in the

2006 frame (13,820 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 2006 Annual Report A-7

Class 1-10 3,794 3,596 3,689 3,409 3,738 4,667 929 873 466.700

Percent of Total 14.0% 12.9% 13.2% 12.4% 13.2% 16.4% 24.9% 23.0%

Class 11-20 2,212 2,392 2,492 3,352 2,488 2,513 25 301 251.300

Percent of Total 8.2% 8.6% 8.9% 12.2% 8.8% 8.8% 1.0% 13.6%

Class 21-100 7,195 7,947 8,168 8,071 9,196 8,433 -763 1,238 105.413

Percent of Total 26.5% 28.4% 29.3% 29.4% 32.6% 29.6% -8.3% 17.2%

Class 101-500 12,435 12,661 11,859 10,698 10,845 11,219 374 -1,216 28.048

Percent of Total 45.9% 45.3% 42.5% 39.0% 38.4% 39.4% 3.4% -9.8%

Rest 1,480 1,349 1,709 1,929 1,952 1,662 -290 182 11.871

Percent of Total 5.5% 4.8% 6.1% 7.0% 6.9% 5.8% -14.9% 12.3%

Category I 16,196 17,049 16,760 17,368 17,858 16,953 -905 757 97.994

Percent of Total 59.7% 61.0% 60.0% 63.3% 63.3% 59.5% -5.1% 4.7%

Category II 10,764 10,473 10,688 9,486 9,738 11,161 1,423 397 23.899

Percent of Total 39.7% 37.5% 38.3% 34.5% 34.5% 39.2% 14.6% 3.7%

Total 27,116 27,945 27,917 27,459 28,219 28,494 275 1,378 44.522

Percent of Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 1.0% 5.1%

Note: Includes only data from Category I and Category II operators. In 2006 there were 173 Category I operators and 467 Category II

operators. The "rest" size class had 140 operators in 2006.

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

Table A5. Operator Field Count by Operator Production Size Class, 2001–2006

2005–2006 2001–2006 2006 Average

Number and Number and Number of

Percent Percent Fields per

Size Class 2001 2002 2003 2004 2005 2006 Change Change Operator
Table A6. Top 50 U.S. Operators Ranked by Reported 2006 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 586 1 CONOCOPHILLIPS CO. . . . . . . . . . . . . . . . . . 4,033

2 CHEVRON CORP. . . . . . . . . . . . . . . . . . . . . . . . . 450 2 ANADARKO PETROLEUM CORP . . . . . . . . . 2,896

3 CONOCOPHILLIPS CO . . . . . . . . . . . . . . . . . . . . 401 3 BP PLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,739

4 SHELL OIL CO . . . . . . . . . . . . . . . . . . . . . . . . . . . 305 4 CHEVRON CORP . . . . . . . . . . . . . . . . . . . . . . 2,142

5 OCCIDENTAL PETROLEUM CORP . . . . . . . . . . 285 5 DEVON ENERGY CORP. . . . . . . . . . . . . . . . . 2,059

6 AERA ENERGY LLC . . . . . . . . . . . . . . . . . . . . . . 188 6 CHESAPEAKE ENERGY CORP. . . . . . . . . . . 1,999

7 ANADARKO PETROLEUM CORP. . . . . . . . . . . . 183 7 EXXONMOBIL CORP . . . . . . . . . . . . . . . . . . . 1,903

8 EXXONMOBIL CORP. . . . . . . . . . . . . . . . . . . . . . 131 8 SHELL OIL CO . . . . . . . . . . . . . . . . . . . . . . . . 1,619

9 APACHE CORP . . . . . . . . . . . . . . . . . . . . . . . . . . . 81 9 ENCANA OIL & GAS INC . . . . . . . . . . . . . . . . 1,540

10 PLAINS EXPLORATION & PRODUCTION CO . . . 59 10 XTO ENERGY INC . . . . . . . . . . . . . . . . . . . . . 1,360

Top 10 Volume Subtotal 2,669 Top 10 Volume Subtotal 22,290

Top 10 Percentage of U.S. Total 53% Top 10 Percentage of U.S. Total 42%

11 KINDER MORGAN ENERGY PARTNERS . . . . . . 57 11 DOMINION RESOURCES INC . . . . . . . . . . . . 1,202

12 AMERADA HESS CORP . . . . . . . . . . . . . . . . . . . . 57 12 EOG RESOURCES INC . . . . . . . . . . . . . . . . . 1,049

13 DOMINION RESOURCES INC. . . . . . . . . . . . . . . . 54 13 APACHE CORP. . . . . . . . . . . . . . . . . . . . . . . . 1,031

14 NOBLE ENERGY INC . . . . . . . . . . . . . . . . . . . . . . 52 14 WILLIAMS ENERGY INC . . . . . . . . . . . . . . . . . . 949

15 MARATHON OIL CO . . . . . . . . . . . . . . . . . . . . . . . 47 15 OCCIDENTAL PETROLEUM CORP . . . . . . . . . 866

16 MERIT ENERGY CO . . . . . . . . . . . . . . . . . . . . . . . 46 16 EL PASO ENERGY . . . . . . . . . . . . . . . . . . . . . . 823

17 MURPHY OIL CORP . . . . . . . . . . . . . . . . . . . . . . . 43 17 NEWFIELD EXPLORATION CO . . . . . . . . . . . . 715

18 XTO ENERGY INC . . . . . . . . . . . . . . . . . . . . . . . . . 40 18 SAMSON RESOURCES CO . . . . . . . . . . . . . . . 678

19 DEVON ENERGY CORP . . . . . . . . . . . . . . . . . . . . 38 19 MARATHON OIL CO . . . . . . . . . . . . . . . . . . . . . 670

20 EOG RESOURCES INC . . . . . . . . . . . . . . . . . . . . . 37 20 QUESTAR CORP . . . . . . . . . . . . . . . . . . . . . . . . 654

Top 20 Volume Subtotal 3,140 Top 20 Volume Subtotal 30,927

Top 20 Percentage of U.S. Total 62% Top 20 Percentage of U.S. Total 58%

21 PIONEER NATURAL RESOURCES USA INC. . . . 31 21 NOBLE ENERGY INC . . . . . . . . . . . . . . . . . . . . 569

22 CITY OF LONG BEACH . . . . . . . . . . . . . . . . . . . . . 31 22 PIONEER NATURAL RESOURCES USA INC. . 528

23 CHESAPEAKE ENERGY CORP . . . . . . . . . . . . . . 30 23 CIMAREX ENERGY CO . . . . . . . . . . . . . . . . . . . 432

24 CITATION OIL & GAS CORP. . . . . . . . . . . . . . . . . 30 24 MERIT ENERGY CO . . . . . . . . . . . . . . . . . . . . . 379

25 CONTINENTAL RESOURCES INC . . . . . . . . . . . . 27 25 ENERGEN RESOURCES CORP. . . . . . . . . . . . 291

26 HILCORP ENERGY CO . . . . . . . . . . . . . . . . . . . . . 26 26 ULTRA PETROLEUM INC . . . . . . . . . . . . . . . . . 288

27 ALLIANT ENERGY CORP . . . . . . . . . . . . . . . . . . . 26 27 EQUITABLE RESOURCES INC. . . . . . . . . . . . . 262

28 ENCORE OPERATING LP. . . . . . . . . . . . . . . . . . . 26 28 YATES PETROLEUM CORP . . . . . . . . . . . . . . . 258

29 ST MARY LAND & EXPLORATION CO . . . . . . . . . 25 29 HILCORP ENERGY CO . . . . . . . . . . . . . . . . . . . 257

30 DENBURY RESOURCES INC . . . . . . . . . . . . . . . . 24 30 HUNT OIL CO. . . . . . . . . . . . . . . . . . . . . . . . . . . 252

31 ENI PETROLEUM CO INC . . . . . . . . . . . . . . . . . . . 24 31 FOREST OIL CORP . . . . . . . . . . . . . . . . . . . . . . 251

32 FOREST OIL CORP . . . . . . . . . . . . . . . . . . . . . . . . 24 32 POGO PRODUCING CO . . . . . . . . . . . . . . . . . . 225

33 ENERGEN RESOURCES CORP. . . . . . . . . . . . . . 23 33 SANDRIDGE ENERGY INC . . . . . . . . . . . . . . . . 222

34 SWIFT ENERGY CO . . . . . . . . . . . . . . . . . . . . . . . 23 34 CABOT OIL & GAS CORP . . . . . . . . . . . . . . . . . 217

35 BERRY PETROLEUM CO . . . . . . . . . . . . . . . . . . . 21 35 THE HOUSTON EXPLORATION CO. . . . . . . . . 210

36 CIMAREX ENERGY CO . . . . . . . . . . . . . . . . . . . . . 21 36 AMERADA HESS CORP . . . . . . . . . . . . . . . . . . 207

37 POGO PRODUCING CO . . . . . . . . . . . . . . . . . . . . 20 37 MARINER ENERGY INC . . . . . . . . . . . . . . . . . . 204

38 EL PASO ENERGY . . . . . . . . . . . . . . . . . . . . . . . . 20 38 J - W OPERATING CO . . . . . . . . . . . . . . . . . . . . 196

39 STONE ENERGY CORP . . . . . . . . . . . . . . . . . . . . 18 39 UNIT CORP . . . . . . . . . . . . . . . . . . . . . . . . . . . . 192

40 HENRY PETROLEUM LP. . . . . . . . . . . . . . . . . . . . 16 40 HUNT PETROLEUM CORPORATION. . . . . . . . 188

41 W & T OFFSHORE INC . . . . . . . . . . . . . . . . . . . . . 15 41 BILL BARRETT CORP . . . . . . . . . . . . . . . . . . . . 184

42 ENERPLUS RESOURCES USA CORP . . . . . . . . . 14 42 KCS ENERGY INC . . . . . . . . . . . . . . . . . . . . . . . 183

43 NEWFIELD EXPLORATION CO . . . . . . . . . . . . . . 13 43 ENERGY PARTNERS LTD . . . . . . . . . . . . . . . . 181

44 ENCANA OIL & GAS INC . . . . . . . . . . . . . . . . . . . . 13 44 C N X GAS CO LLC . . . . . . . . . . . . . . . . . . . . . . 177

45 HEADINGTON RESOURCES INC . . . . . . . . . . . . . 12 45 FIDELITY EXPLORATION & PROD CO . . . . . . 171

46 LLOG EXPLORATION CO . . . . . . . . . . . . . . . . . . . 12 46 KAISER - FRANCIS OIL CO. . . . . . . . . . . . . . . . 171

47 ENDEAVOR ENERGY RESOURCES LP . . . . . . . 12 47 W & T OFFSHORE INC . . . . . . . . . . . . . . . . . . . 171

48 WALTER OIL & GAS CORP. . . . . . . . . . . . . . . . . . 12 48 WALTER OIL & GAS CORP. . . . . . . . . . . . . . . . 160

49 SANDRIDGE ENERGY INC . . . . . . . . . . . . . . . . . . 12 49 ST MARY LAND & EXPLORATION CO. . . . . . . 159

50 MARINER ENERGY INC . . . . . . . . . . . . . . . . . . . . 11 50 RANGE RESOURCES CORP . . . . . . . . . . . . . . 149

Top 50 Volume Subtotal 3,752 Top 50 Volume Subtotal 38,261

Top 50 Percentage of U.S. Total 75% 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

A-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report
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 (Table B3 and Table B4) rather

than by reserves (Table B1 and Table 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.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report B-1

Summary for the Top 100 Fields for 2006 Liquids and Gas

12/31/2006 12/31/2006 Estimated

Proved Nonproducing 2006

Rank Group Reserves Percent Reserves Percent Production Percent

Table B1. Top 100 U.S. Fields as Ranked by Liquids Proved Reserves (Million Barrels)

Top 10 6,666.1 29.9% 1,002.6 17.7% 374.6 20.4%

Top 20 8,966.2 40.2% 2,031.0 35.8% 507.5 27.7%

Top 50 12,247.5 54.9% 2,825.9 49.8% 760.8 41.5%

Top 100 14,523.3 65.1% 3,712.2 65.4% 945.4 51.6%

Others 7,787.7 34.9% 1,965.8 34.6% 888.6 48.4%

Total 22,311.0 100.0% 5,678.0 100.0% 1,834.0 100.0%

Table B2. Top 100 U.S. Fields as Ranked by Gas Proved Reserves (Billion Cubic Feet)

Top 10 62,526.4 28.4% 18,026.6 27.0% 3,739.2 19.3%

Top 20 82,049.8 37.2% 22,117.5 33.2% 5,141.9 26.5%

Top 50 107,692.0 48.9% 32,368.7 48.5% 7,218.2 37.3%

Top 100 127,076.2 57.7% 37,133.6 55.7% 8,728.6 45.1%

Others 93,339.8 42.3% 29,580.4 44.3% 10,644.4 54.9%

Total 220,416.0 100.0% 66,714.0 100.0% 19,373.0 100.0%

Table B3. Top 100 U.S. Fields as Ranked by Liquids Production (Million Barrels)

Top 10 n/a n/a n/a n/a 428.9 23.4%

Top 20 n/a n/a n/a n/a 600.3 32.7%

Top 50 n/a n/a n/a n/a 848.2 46.2%

Top 100 n/a n/a n/a n/a 1,022.6 55.8%

Others n/a n/a n/a n/a 811.4 44.2%

Total n/a n/a n/a n/a 1,834.0 100.0%

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 4,074.3 21.0%

Top 20 n/a n/a n/a n/a 5,333.8 27.5%

Top 50 n/a n/a n/a n/a 7,421.9 38.3%

Top 100 n/a n/a n/a n/a 9,141.7 47.2%

Others n/a n/a n/a n/a 10,231.3 52.8%

Total n/a n/a n/a n/a 19,373.0 100.0%
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 945 million

barrels of production, or 52 percent of the 2006 U.S.total

(Table 6 and Table 14).

Table B2. Top 100 Gas Fields

Ranked by Reserves

The top 100 gas fields by reserves had 127,076 billion

cubic feet of wet natural gas proved reserves or 58

percent of the total, as of December 31, 2006 (Table 9)

and 56 percent of the reported nonproducing reserves.

The Newark East (Barnett Shale) field in Texas became

the second largest in the country.

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 1,023

million barrels of production, or 56 percent of the 2006

U.S. total (Table 6 and Table 14).

Table B4. Top 100 Gas Fields

Ranked by Production

The top 100 gas fields had 9,142 billion cubic feet of

production, or 47 percent of the 2006 U.S. total (Table

9).

Energy Information Administration

B-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

LIQUIDS PROVED RESERVES

1-10

30%

11-20

10%

21-50

15%

51-100

10%

All Others

35%

`

WET GAS PROVED RESERVES

1-10

28%

11-20

9%

21-50

12%

51-100

9%

All Others

42%

LIQUIDS PRODUCTION

1-10

23%

11-20

9%

21-50

14%

51-100

10%

All Others

44%

`

WET GAS PRODUCTION

1-10

21%

11-20

7%

21-50

11%

51-100

9%

All Others

52%
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report B-3

Table B1. Top 100 U.S. Fields Ranked by Liquids Proved Reserves from Estimated 2006 Field Level Data

a

(Million Barrels of 42 U.S. Gallons)

2006 Estimated Rank Group

Production Proved Nonproducing Discovery

Num Field Name Location Volume Reserves Reserves Year

1 PRUDHOE BAY AK 92.1 1967

2 WASSON TX 24.7 1937

3 BELRIDGE SOUTH CA 38.9 1911

4 MISSISSIPPI CANYON BLK 807 (MARS-URSA) FG 61.6 1989

5 SPRABERRY TREND AREA TX 24.2 (1-10) 1949

6 KUPARUK RIVER AK 45.5 1969

7 MISSISSIPPI CANYON BLK 778 (THUNDER HORSE) FG 0.0 1999

8 MIDWAY-SUNSET CA 39.6 1901

9 ELK HILLS CA 17.2 1919

10 KERN RIVER CA 30.8 1899

Top 10 Volume Subtotal 374.6 6,666.1 1,002.6

Top 10 Percentage of U.S. Total 20.4% 29.9% 17.7%

11 GREEN CANYON BLK 743 (ATLANTIS) FG 0.0 1998

12 SLAUGHTER TX 11.6 1937

13 WILMINGTON CA 14.8 1932

14 ALPINE AK 41.7 1994

15 MILNE POINT AK 13.3 (11-20) 1982

16 WATTENBERG CO 11.1 1970

17 SALT CREEK WY 2.6 1889

18 GREEN CANYON BLK 826 (MAD DOG) FG 11.1 1998

19 LEVELLAND TX 8.2 1945

20 CYMRIC CA 18.5 1916

Top 20 Volume Subtotal 507.5 8,966.2 2,031.0

Top 20 Percentage of U.S. Total 27.7% 40.2% 35.8%

21 CEDAR HILLS ND & MT & SD 15.6 1951

22 LOST HILLS CA 11.9 1910

23 GREEN CANYON BLK 644 (HOLSTEIN) FG 11.4 1999

24 GREEN CANYON BLK 640 (TAHITI) FG 0.0 2002

25 ELM COULEE MT 19.0 2000

26 GREATER ANETH UT 3.5 1956

27 HONDO FP 5.6 1969

28 PESCADO FP 5.1 1970

29 YATES TX 9.5 1926

30 SHO-VEL-TUM OK 8.8 1905

31 HOBBS NM 4.7 1928

32 MISSISSIPPI CANYON BLK 84 (KING/HORN MT) FG 22.5 1993

33 ORION AK 2.5 2002

34 COWDEN NORTH TX 5.4 1930

35 GOLDSMITH TX 5.6 (21-50) 1935

36 NORTHSTAR AK 18.9 1984

37 INGLEWOOD CA 3.3 1924

38 POINT MCINTYRE AK 7.7 1988

39 ENDICOTT AK 5.2 1978

40 SACATE FP 4.1 1970

41 VENTURA CA 4.2 1916

42 SAN ARDO CA 3.2 1947

43 WEST SAK AK 6.6 1969

44 SEMINOLE TX 7.8 1936

45 MONUMENT BUTTE UT 3.5 1964

46 KELLY-SNYDER TX 11.3 1948

47 BOREALIS AK 5.7 2001

48 WARD-ESTES NORTH TX 2.2 1927

49 GREEN CANYON BLK 562 (K2) FG 8.7 1999

50 MISSISSIPPI CANYON BLK 383 (KEPLER) FG 29.7 1987

Top 50 Volume Subtotal 760.8 12,247.5 2,825.9

Top 50 Percentage of U.S. Total 41.5% 54.9% 49.8%
Energy Information Administration

B-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

51 VACUUM NM 5.8 1929

52 ROBERTSON NORTH TX 4.2 1956

53 MCELROY TX 5.0 1926

54 FULLERTON TX 4.3 1942

55 PENNEL MT 2.3 1955

56 SALT CREEK TX 4.5 1942

57 LAKE WASHINGTON LA 8.4 1931

58 COALINGA CA 5.7 1887

59 GREEN CANYON BLK 339 (FRONT RUNNER) FG 5.6 2001

60 FUHRMAN-MASCHO TX 2.9 1930

61 RANGELY CO 5.2 1902

62 WESTBROOK TX 1.8 1920

63 ARROYO GRANDE CA 0.6 1906

64 MISSISSIPPI CANYON BLK 696 (BLIND FAITH) FG 0.0 2005

65 MISSISSIPPI CANYON BLK 773 (DEVILS TOWER) FG 14.7 1999

66 LISBURNE AK 3.2 1967

67 ATWATER VALLEY BLK 575 (NEPTUNE (AT)) FG 0.0 1995

68 GIDDINGS TX 7.1 1960

69 GREEN CANYON BLK 652 FG 0.0 1999

70 ANTON-IRISH TX 3.2 1944

71 NATURAL BUTTES UT 1.5 1940

72 FITTS OK 1.8 1933

73 EAST TEXAS TX 4.3 1930

74 CEDAR LAKE TX 2.0 1939

75 AURORA AK 3.8 (51-100) 1969

76 HAWKINS TX 2.6 1940

77 HOWARD-GLASSCOCK TX 2.7 1925

78 POSTLE OK 1.7 1958

79 GARDEN BANKS BLK 388 (COOPER) FG 11.1 1989

80 MEANS TX 3.3 1934

81 PINEDALE WY 1.8 1955

82 TARN AK 7.6 1991

83 POLARIS AK 0.8 2000

84 KERN FRONT CA 1.6 1925

85 GREEN CANYON BLK 654 FG 0.0 2003

86 MISSISSIPPI CANYON BLK 20 FG 0.9 1982

87 GRAND ISLE BLK 43 FG 0.5 1956

88 MISSISSIPPI CANYON BLK 429 (ARIEL) FG 9.4 1995

89 GREEN CANYON BLK 680 (CONSTITUTION) FG 3.8 2001

90 ALTAMONT-BLUEBELL UT 2.7 1949

91 EUNICE MONUMENT NM 1.8 1929

92 BREA-OLINDA CA 1.2 1897

93 FULLER TX 0.6 1951

94 EAST BREAKS BLK 602 (NANSEN) FG 7.6 1999

95 GOLDEN TREND OK 2.0 1945

96 WELCH TX 1.6 1942

97 VIOSCA KNOLL BLK 786 (PETRONIUS) FG 17.0 1995

98 CARTHAGE TX 2.3 1936

99 SOUTH PASS BLK 62 FG 0.2 1965

100 JAY AL & FL 1.7 1951

Top 100 Volume Subtotal 945.4 14,523.3 3,712.2

Top 100 Percentage of U.S. Total 51.6% 65.1% 65.4%

Table B1. Top 100 U.S. Fields Ranked by Liquids Proved Reserves from Estimated 2006 Field Level Dataa

(Continued)

(Million Barrels of 42 U.S. Gallons)

2006 Estimated Rank Group

Production Proved Nonproducing Discovery

Num Field Name Location Volume Reserves Reserves Year

a

Includes 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 2006 Annual Report B-5

Table B2. Top 100 U.S. Fields Ranked by Gas Proved Reserves from Estimated 2006 Field Level Dataa

(Billion Cubic Feet)

2006 Estimated Rank Group

Production Proved Nonproducing Discovery

Num Field Name Location Volume Reserves Reserves Year

1 SAN JUAN BASIN GAS AREA CO & NM 1380.8 1927

2 NEWARK EAST TX 716.7 1981

3 PRUDHOE BAY AK 160.9 1967

4 PINEDALE WY 236.7 1955

5 HUGOTON GAS AREA KS & OK & TX 342.0 (1-10) 1922

6 JONAH WY 292.5 1977

7 NATURAL BUTTES UT 166.0 1940

8 WATTENBERG CO 176.0 1970

9 RATON BASIN GAS AREA CO & NM 109.6 1998

10 MADDEN WY 157.9 1968

Top 10 Volume Subtotal 3,739.2 62,526.4 18,026.6

Top 10 Percentage of U.S. Total 19.3% 28.4% 27.0%

11 PRB COALBED WY 377.0 1992

12 CARTHAGE TX 224.8 1936

13 ANTRIM MI 140.0 1965

14 NORTHSTAR AK 0.0 1984

15 SPRABERRY TREND AREA TX 81.5 (11-20) 1949

16 FOGARTY CREEK WY 161.7 1975

17 SAWYER TX 82.8 1960

18 LOWER MOBILE BAY AREA AL & FG 143.5 1979

19 FREESTONE TX 90.3 1949

20 VERNON LA 100.9 1967

Top 20 Volume Subtotal 5,141.9 82,049.8 22,117.5

Top 20 Percentage of U.S. Total 26.5% 37.2% 33.2%

21 ELM GROVE LA 113.0 1916

22 GRAND VALLEY CO 88.3 1985

23 OAKWOOD VA 63.0 1990

24 ELK HILLS CA 143.8 1919

25 PARACHUTE CO 81.8 1985

26 OAK HILL TX 94.6 1958

27 MAMM CREEK CO 95.1 1959

28 RULISON CO 65.4 1958

29 STRONG CITY DISTRICT OK 84.6 1966

30 PINON TX 40.8 1982

31 MISSISSIPPI CANYON BLK 807 (MARS-URSA) FG 83.9 1989

32 BALD PRAIRIE TX 57.0 1976

33 FARRAR TX 55.4 1963

34 STILES RANCH TX 44.0 1978

35 LAKE RIDGE WY 75.7 (21-50) 1981

36 HALEY TX 70.8 1983

37 RED OAK-NORRIS OK 55.8 1910

38 MESA UNIT WY 37.2 1981

39 PANOMA GAS AREA KS 49.7 1956

40 MOCANE-LAVERNE GAS AREA KS & OK & TX 63.8 1946

41 GOLDEN TREND OK 38.9 1945

42 DRUNKARDS WASH UT 57.2 1989

43 TEAGUE TX 62.2 1945

44 MAYFIELD NE OK 90.8 1951

45 BUFFALO WALLOW TX 63.3 1969

46 WATONGA-CHICKASHA TREND OK 39.6 1948

47 BEAR GRASS TX 38.6 1977

48 SAVELL TX 72.0 1997

49 BELUGA RIVER AK 55.4 1962

50 GIDDINGS TX 94.6 1960

Top 50 Volume Subtotal 7,218.2 107,692.0 32,368.7

Top 50 Percentage of U.S. Total 37.3% 48.9% 48.5%
Energy Information Administration

B-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table B2. Top 100 U.S. Fields Ranked by Gas Proved Reserves from Estimated 2006 Field Level Dataa

(Continued)

(Billion Cubic Feet)

2006 Estimated Rank Group

Production Proved Nonproducing Discovery

Num Field Name Location Volume Reserves Reserves Year

51 OVERTON TX 54.6 1973

52 PICEANCE CREEK CO 17.1 1930

53 NORA VA 25.8 1949

54 HONDO FP 20.3 1969

55 SHO-VEL-TUM OK 28.5 1905

56 CASPIANA LA 27.8 1925

57 WASSON TX 43.0 1937

58 WAMSUTTER WY 26.2 1958

59 CEDARDALE NE OK 28.9 1957

60 WILD ROSE WY 30.1 1975

61 MINDEN TX 37.7 1954

62 KINTA OK 61.6 1914

63 GOMEZ TX 38.1 1963

64 VERDEN OK 30.0 1948

65 DEW TX 32.6 1982

66 GURNEE COAL DEGAS AL 2.8 1990

67 B-43 AR 19.4 2005

68 ELK CITY OK 45.3 1947

69 ECHO SPRINGS WY 31.0 1976

70 DOWDY RANCH TX 33.6 1999

71 SLIGO LA 43.7 1922

72 BRUFF WY 34.5 1969

73 MISSISSIPPI CANYON BLK 731 (MENSA) FG 60.5 1986

74 EAST BREAKS BLK 602 (NANSEN) FG 61.6 1999

75 STANDARD DRAW WY 21.6 (51-100) 1979

76 MISSISSIPPI CANYON BLK 778 (THUNDER HORSE) FG 0.0 1999

77 NACONICHE CREEK TX 11.8 1978

78 OZONA NE TX 26.0 1966

79 BETHANY TX 26.0 1921

80 WAYNOKA NE OK 20.4 1956

81 CHEYENNE WEST OK 39.1 1971

82 WILBURTON OK 29.5 1941

83 EXSUN TX 46.7 1974

84 PINE HOLLOW SOUTH OK 18.1 1959

85 KUPARUK RIVER AK 20.9 1969

86 MISSISSIPPI CANYON BLK 383 (KEPLER) FG 77.9 1987

87 BOONSVILLE TX 28.8 1945

88 OZONA TX 22.4 1953

89 TIP TOP WY 18.9 1928

90 OKEENE NW OK 15.2 1956

91 CEMENT OK 35.2 1916

92 HEMPHILL TX 23.7 1961

93 CHARCO TX 21.4 1948

94 MOBILE BLK 823 FG 25.0 1983

95 CLEBURNE WEST TX 19.6 1992

96 COOK INLET NORTH AK 38.2 1962

97 CARTHAGE NORTH TX 16.6 1966

98 SOONER TREND OK 25.2 1938

99 EAKLY-WEATHERFORD TREND OK 20.4 1953

100 BROWN-BASSETT TX 27.3 1953

Top 100 Volume Subtotal 8,728.6 127,076.2 37,133.6

Top 100 Percentage of U.S. Total 45.1% 57.7% 55.7%

a

Total 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 2006 Annual Report B-7

Table B3. Top 100 U.S. Fields Ranked by Liquids Production from Estimated 2006 Field Level Dataa

(Million Barrels of 42 U.S. Gallons)

2006 Estimated Discovery

Num Field Name Location Production Volume Year

1 PRUDHOE BAY AK 92.1 1967

2 MISSISSIPPI CANYON BLK 807 (MARS-URSA) FG 61.6 1989

3 KUPARUK RIVER AK 45.5 1969

4 ALPINE AK 41.7 1994

5 MIDWAY-SUNSET CA 39.6 1901

6 BELRIDGE SOUTH CA 38.9 1911

7 KERN RIVER CA 30.8 1899

8 MISSISSIPPI CANYON BLK 383 (KEPLER) FG 29.7 1987

9 WASSON TX 24.7 1937

10 SPRABERRY TREND AREA TX 24.2 1949

Top 10 Volume Subtotal 428.9

Top 10 Percentage of U.S. Total 23.4%

11 MISSISSIPPI CANYON BLK 84 (KING/HORN MT) FG 22.5 1993

12 ELM COULEE MT 19.0 2000

13 NORTHSTAR AK 18.9 1984

14 CYMRIC CA 18.5 1916

15 ELK HILLS CA 17.2 1919

16 VIOSCA KNOLL BLK 786 (PETRONIUS) FG 17.0 1995

17 CEDAR HILLS ND & MT & SD 15.6 1951

18 WILMINGTON CA 14.8 1932

19 MISSISSIPPI CANYON BLK 773 (DEVILS TOWER) FG 14.7 1999

20 MILNE POINT AK 13.3 1982

Top 20 Volume Subtotal 600.3

Top 20 Percentage of U.S. Total 32.7%

21 LOST HILLS CA 11.9 1910

22 SLAUGHTER TX 11.6 1937

23 GREEN CANYON BLK 644 (HOLSTEIN) FG 11.4 1999

24 KELLY-SNYDER TX 11.3 1948

25 GREEN CANYON BLK 826 (MAD DOG) FG 11.1 1998

26 WATTENBERG CO 11.1 1970

27 GARDEN BANKS BLK 388 (COOPER) FG 11.1 1989

28 MISSISSIPPI CANYON BLK 582 (MEDUSA) FG 10.0 1998

29 YATES TX 9.5 1926

30 MISSISSIPPI CANYON BLK 429 (ARIEL) FG 9.4 1995

31 SHO-VEL-TUM OK 8.8 1905

32 GREEN CANYON BLK 562 (K2) FG 8.7 1999

33 LAKE WASHINGTON LA 8.4 1931

34 LEVELLAND TX 8.2 1945

35 GREEN CANYON BLK 65 (BULLWINKLE) FG 7.9 1983

36 SEMINOLE TX 7.8 1936

37 POINT MCINTYRE AK 7.7 1988

38 EAST BREAKS BLK 602 (NANSEN) FG 7.6 1999

39 TARN AK 7.6 1991

40 EWING BANK BLK 873 (N/A) FG 7.3 1985

41 GIDDINGS TX 7.1 1960

42 WEST SAK AK 6.6 1969

43 GARDEN BANKS BLK 171 (SALSA) FG 6.0 1988

44 VACUUM NM 5.8 1929

45 COALINGA CA 5.7 1887

46 BOREALIS AK 5.7 2001

47 HONDO FP 5.6 1969

48 GREEN CANYON BLK 339 (FRONT RUNNER) FG 5.6 2001

49 MISSISSIPPI CANYON BLK 755 (GOMEZ) FG 5.6 1986

50 GOLDSMITH TX 5.6 1935

Top 50 Volume Subtotal 848.2

Top 50 Percentage of U.S. Total 46.2%
Energy Information Administration

B-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table B3. Top 100 U.S. Fields Ranked by Liquids Production from Estimated 2006 Field Level Dataa

(Continued)

(Million Barrels of 42 U.S. Gallons)

2006 Estimated Discovery

Num Field Name Location Production Volume Year

51 COWDEN NORTH TX 5.4 1930

52 MISSISSIPPI CANYON BLK 522 (LEO) FG 5.2 1989

53 RANGELY CO 5.2 1902

54 ENDICOTT AK 5.2 1978

55 PESCADO FP 5.1 1970

56 MCELROY TX 5.0 1926

57 GREEN CANYON BLK 768 (TICONDEROGA) FG 5.0 2004

58 HOBBS NM 4.7 1928

59 SALT CREEK TX 4.5 1942

60 SAN JUAN BASIN GAS AREA CO & NM 4.4 1927

61 EAST TEXAS TX 4.3 1930

62 FULLERTON TX 4.3 1942

63 VENTURA CA 4.2 1916

64 ROBERTSON NORTH TX 4.2 1956

65 SACATE FP 4.1 1970

66 ALAMINOS CANYON BLK 25 (HOOVER) FG 4.1 1997

67 WEST DELTA BLK 30 FG 3.9 1949

68 AURORA AK 3.8 1969

69 GREEN CANYON BLK 680 (CONSTITUTION) FG 3.8 2001

70 VIOSCA KNOLL BLK 990 (POMPANO) FG 3.7 1981

71 GREATER ANETH UT 3.5 1956

72 MONUMENT BUTTE UT 3.5 1964

73 MAIN PASS BLK 61 FG 3.4 2001

74 BROOKELAND TX 3.4 1962

75 INGLEWOOD CA 3.3 1924

76 MEANS TX 3.3 1934

77 ANTON-IRISH TX 3.2 1944

78 LISBURNE AK 3.2 1967

79 SAN ARDO CA 3.2 1947

80 POINT PEDERNALES FP 3.0 1983

81 FUHRMAN-MASCHO TX 2.9 1930

82 MCKITTRICK CA 2.8 1887

83 JONAH WY 2.8 1977

84 ALTAMONT-BLUEBELL UT 2.7 1949

85 LOST SOLDIER WY 2.7 1916

86 DOLLARHIDE NM & TX 2.7 1945

87 HOWARD-GLASSCOCK TX 2.7 1925

88 MAIN PASS SA BLK 299 FG 2.7 1967

89 HAWKINS TX 2.6 1940

90 SALT CREEK WY 2.6 1889

91 OREGON BASIN WY 2.5 1912

92 GRAYBURG-JACKSON NM 2.5 1929

93 LOOKOUT BUTTE EAST MT 2.5 1986

94 MCARTHUR RIVER AK 2.5 1965

95 ORION AK 2.5 2002

96 NIAKUK AK 2.4 1984

97 JO-MILL TX 2.4 1953

98 MALLALIEU WEST MS 2.4 1946

99 PENNEL MT 2.3 1955

100 ELK BASIN MT & WY 2.3 1915

Top 100 Volume Subtotal 1,022.6

Top 100 Percentage of U.S. Total 55.8%

a

Includes 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 2006 Annual Report B-9

1 SAN JUAN BASIN GAS AREA CO & NM 1380.8 1927

2 NEWARK EAST TX 716.7 1981

3 PRB COALBED WY 377.0 1992

4 HUGOTON GAS AREA KS & OK & TX 342.0 1922

5 JONAH WY 292.5 1977

6 PINEDALE WY 236.7 1955

7 CARTHAGE TX 224.8 1936

8 WATTENBERG CO 176.0 1970

9 NATURAL BUTTES UT 166.0 1940

10 FOGARTY CREEK WY 161.7 1975

Top 10 Volume Subtotal 4,074.3

Top 10 Percentage of U.S. Total 21.0%

11 PRUDHOE BAY AK 160.9 1967

12 MADDEN WY 157.9 1968

13 ELK HILLS CA 143.8 1919

14 LOWER MOBILE BAY AREA AL & FG 143.5 1979

15 ANTRIM MI 140.0 1965

16 ELM GROVE LA 113.0 1916

17 RATON BASIN GAS AREA CO & NM 109.6 1998

18 VERNON LA 100.9 1967

19 MAMM CREEK CO 95.1 1959

20 GIDDINGS TX 94.6 1960

Top 20 Volume Subtotal 5,333.8

Top 20 Percentage of U.S. Total 27.5%

21 OAK HILL TX 94.6 1958

22 MAYFIELD NE OK 90.8 1951

23 FREESTONE TX 90.3 1949

24 GRAND VALLEY CO 88.3 1985

25 STRONG CITY DISTRICT OK 84.6 1966

26 MISSISSIPPI CANYON BLK 807 (MARS-URSA) FG 83.9 1989

27 SAWYER TX 82.8 1960

28 PARACHUTE CO 81.8 1985

29 SPRABERRY TREND AREA TX 81.5 1949

30 MISSISSIPPI CANYON BLK 383 (KEPLER) FG 77.9 1987

31 LAKE RIDGE WY 75.7 1981

32 SAVELL TX 72.0 1997

33 HALEY TX 70.8 1983

34 RULISON CO 65.4 1958

35 MOCANE-LAVERNE GAS AREA KS & OK & TX 63.8 1946

36 BUFFALO WALLOW TX 63.3 1969

37 OAKWOOD VA 63.0 1990

38 TEAGUE TX 62.2 1945

39 EAST BREAKS BLK 602 (NANSEN) FG 61.6 1999

40 KINTA OK 61.6 1914

41 VIOSCA KNOLL BLK 956 (RAM-POWELL) FG 61.0 1985

42 MISSISSIPPI CANYON BLK 731 (MENSA) FG 60.5 1986

43 YATES TX 59.2 1926

44 DRUNKARDS WASH UT 57.2 1989

45 BALD PRAIRIE TX 57.0 1976

46 PANOLA OK 56.2 1964

47 RED OAK-NORRIS OK 55.8 1910

48 FARRAR TX 55.4 1963

49 BELUGA RIVER AK 55.4 1962

50 OVERTON TX 54.6 1973

Top 50 Volume Subtotal 7,421.9

Table B4. Top 100 U.S. Fields Ranked by Gas Production from Estimated 2006 Field Level Dataa

(Billion Cubic Feet)

2006 Estimated Discovery

Num Field Name Location Production Volume Year
Energy Information Administration

B-10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table B4. Top 100 U.S. Fields Ranked by Gas Production from Estimated 2006 Field Level Dataa

(Continued)

(Billion Cubic Feet)

2006 Estimated Discovery

Num Field Name Location Production Volume Year

Top 50 Percentage of U.S. Total 38.3%

51 MCALLEN RANCH TX 54.2 1960

52 PANOMA GAS AREA KS 49.7 1956

53 EXSUN TX 46.7 1974

54 JUDGE DIGBY LA 45.8 1977

55 ELK CITY OK 45.3 1947

56 STILES RANCH TX 44.0 1978

57 SLIGO LA 43.7 1922

58 GARDEN BANKS BLK 668 (GUNNISON) FG 43.1 2000

59 WASSON TX 43.0 1937

60 PINON TX 40.8 1982

61 HAYNES TX 40.8 1954

62 LA PERLA TX 40.5 1958

63 WATONGA-CHICKASHA TREND OK 39.6 1948

64 CHEYENNE WEST OK 39.1 1971

65 VAQUILLAS RANCH TX 39.0 1978

66 GOLDEN TREND OK 38.9 1945

67 BEAR GRASS TX 38.6 1977

68 COOK INLET NORTH AK 38.2 1962

69 GOMEZ TX 38.1 1963

70 MINDEN TX 37.7 1954

71 MESA UNIT WY 37.2 1981

72 CEMENT OK 35.2 1916

73 BRUFF WY 34.5 1969

74 DOWDY RANCH TX 33.6 1999

75 DEW TX 32.6 1982

76 LAKE PASTURE TX 31.9 1939

77 BROOKELAND TX 31.6 1962

78 ECHO SPRINGS WY 31.0 1976

79 WILD ROSE WY 30.1 1975

80 VERDEN OK 30.0 1948

81 WILBURTON OK 29.5 1941

82 NAN-SU-GAIL TX 29.0 1957

83 CEDARDALE NE OK 28.9 1957

84 BOONSVILLE TX 28.8 1945

85 GARDEN BANKS BLK 877 (RED HAWK) FG 28.5 2001

86 SHO-VEL-TUM OK 28.5 1905

87 JAVELINA TX 28.1 1947

88 HOBBS NM 28.1 1928

89 CASPIANA LA 27.8 1925

90 ADA LA 27.5 1944

91 BROWN-BASSETT TX 27.3 1953

92 ROLETA TX 26.7 1955

93 CEDAR CREEK ND 26.4 1929

94 WAMSUTTER WY 26.2 1958

95 WILLOW SPRINGS TX 26.1 1938

96 OZONA NE TX 26.0 1966

97 BETHANY TX 26.0 1921

98 NORA VA 25.8 1949

99 SOONER TREND OK 25.2 1938

100 MOBILE BLK 823 FG 25.0 1983

a

Total 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.
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."{45}

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 2006 Annual Report C-1
Energy Information Administration

C-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table C1. U.S. Proved Reserves of Crude Oil, Dry Natural Gas, and Natural Gas Liquids,

in Metric Units, 1996 – 2006

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)

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

2006 14.9 0.3 15.3 30.8 80.1 4.8 6.8 91.7 262.6 3,334.3 -124.8

Dry Natural Gas (billion cubic meters)

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

2006 21.04 -51.99 -30.95 84.84 616.68 11.58 32.71 660.97 525.14 5,977.26 189.72

Natural Gas Liquids (million cubic meters)

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

2006 27.5 -26.2 1.3 18.6 146.9 2.5 8.4 157.9 128.9 1,346.9 48.8

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

b

Total 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, 1996–2006 annual reports, DOE/EIA–0216.{19–29}
Appendix D

Historical Reserves Statistics

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 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 2006.

All historical statistics included have previously been published in the annual reports of 1977 through 2005 of

the EIA publication U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves Annual Report, DOE EIA0216.{1-29}

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 2006 Annual Report

Table D1. U.S. Proved Reserves of Crude Oil, 1976–2006

(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 – – – – – – – – –

e

33,502 –

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

2006 94 2 96 194 504 30 43 577 1,652 20,972 -785

a

Includes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

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

c

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

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

eBased on following year data only.

fConsists 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 2006 annual reports, DOE/EIA-0216.{1-29}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report D-3

Table D2. U.S. Lower 48 Proved Reserves of Crude Oil, 1976–2006

(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 – – – – – – – – –

e

24,928 –

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

2006 93 153 246 194 404 30 43 477 1,410 17,093 -493

a

Includes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

bRevisions 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.

fConsists 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 2006 annual reports, DOE/EIA-0216.{1-29}
Energy Information Administration

D-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table D3. U.S. Proved Reserves of Dry Natural Gas, 1976–2006

(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 – – – – – – – – –

e

213,278 –

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

2006 743 -1,836 -1,093 2,996 21,778 409 1,155 23,342 18,545 211,085 6,700

a

Includes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

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

c

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

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

eBased on following year data only.

fConsists only of operator reported corrections and no other adjustments.

gAn 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 2006 annual reports, DOE/EIA-0216.{1-29}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report D-5

Table D4. U.S. Lower 48 Proved Reserves of Dry Natural Gas, 1976–2006

(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 – – – – – – – – –

e

180,838 –

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

2006 789 -4,313 -3,524 2,996 21,729 409 1,153 23,291 18,137 200,840 4,626

a

Includes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

bRevisions 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.

fConsists 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 2006 annual reports, DOE/EIA-0216.{1-29}
Energy Information Administration

D-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table D5. U.S. Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–2006

(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 – – – – – – – – –

e

208,033 –

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

2006 946 -2,099 -1,153 3,178 22,834 425 1,197 24,456 19,373 220,416 7,108

a

Includes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

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

c

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

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

eBased on following year data only.

fAn 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 2006 annual reports, DOE/EIA-0216.{3-29}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report D-7

Table D6. U.S. Lower 48 Proved Reserves of Wet Natural Gas, After Lease Separation, 1978–2006

(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 – – – – – – – – –

e

175,988 –

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

2006 996 -4,603 -3,607 3,178 22,784 425 1,195 24,404 18,963 210,083 5,012

a

Includes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

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

c

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

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

eBased 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 2006 annual reports, DOE/EIA-0216.{3-29}
Energy Information Administration

D-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table D7. U.S. Proved Reserves of Natural Gas Liquids, 1978–2006

(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 – – – – – – – – –

e

6,772 –

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

2006 173 -165 8 117 924 16 53 993 811 8,472 307

a

Includes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

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

c

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

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

eBased on following year data only.

fConsists 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 2006 annual reports, DOE/EIA-0216.{3-29}
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report D-9

Table D8. U.S. Lower 48 Proved Reserves of Natural Gas Liquids, 1978–2006

(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 – – – – – – – – –

e

6,749 –

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

2006 173 -165 8 117 924 16 53 993 797 8,134 321

a

Includes operator reported corrections for the years 1978 through 1981. After 1981 operators included corrections with revisions.

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

c

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

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

eBased on following year data only.

fConsists 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 2006 annual reports, DOE/EIA-0216.{3-29}
Energy Information Administration

D-10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2006

Gulf of Mexico Depth

Greater than Less than Deepwater

Year Total LouisianaaTexas 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

2006 406 348 58 318 87 78.5

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

2006 3,655 3,500 155 2,983 672 81.6
Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2006

(continued)

Gulf of Mexico Depth

Greater than Less than Deepwater

Year Total LouisianaaTexas 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

2006 2,805 2,036 769 1,112 1,692 39.6

Reserves

1992 27,050 20,006 7,044 3,273 23,777 12.1

1993 26,463 19,751 6,712 3,495 22,968 13.2

1994 27,626 21,208 6,418 4,772 22,854 17.3

1995 28,229 21,664 6,565 5,811 22,418 20.6

1996 28,153 22,119 6,034 6,389 21,764 22.7

1997 28,455 22,428 6,027 7,491 20,964 26.3

1998 26,937 21,261 5,676 7,575 19,362 28.1

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

2006 14,938 12,201 2,737 6,690 8,248 44.8

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report D-11
Energy Information Administration

D-12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2006

(continued)

Gulf of Mexico Depth

Greater than Less than Deepwater

Year Total LouisianaaTexas 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

2006 125 102 23 50 75 39.6

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

2006 649 575 74 291 358 44.8
Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2006

(continued)

Gulf of Mexico Depth

Greater than Less than Deepwater

Year Total LouisianaaTexas 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

2006 2,738 1,973 765 1,086 1,652 39.6

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

2006 14,549 11,824 2,725 6,516 8,033 44.8

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report D-13
Energy Information Administration

D-14 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table D9. Deepwater Production and Proved Reserves of the Gulf of Mexico Federal Offshore, 1992-2006

(continued)

Gulf of Mexico Depth

Greater than Less than Deepwater

Year Total LouisianaaTexas 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

2006 58 37 21 23 35 40.1

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 76 104 168 38.2

2006 249 185 64 90 159 36.2

a

Includes Federal Offshore Alabama.
Table D10. 2006 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 442 0 339 7 346

Lower 48 States . . . . . . . . . . . . . . . . . . . . . . . . . . 4,732 504 60,330 6,038 66,368

Alabama. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 244 1 245

Arkansas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0 615 8 623

California . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 496 0 282 488 770

Coastal Region Onshore. . . . . . . . . . . . . . . . . . 85 0 6 52 58

Los Angeles Basin Onshore . . . . . . . . . . . . . . . 149 0 0 63 63

San Joaquin Basin Onshore . . . . . . . . . . . . . . . 228 0 274 350 624

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . 34 0 2 23 25

Colorado . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102 40 5,828 857 6,685

Florida . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0 0 0 0

Kansas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 0 144 2 146

Kentucky . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 286 0 286

Louisiana . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 198 40 4,038 316 4,354

North . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 10 2,363 38 2,401

South Onshore . . . . . . . . . . . . . . . . . . . . . . . . . 162 27 1,473 252 1,725

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . 22 3 202 26 228

Michigan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 1 436 24 460

Mississippi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 0 143 6 149

Montana. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91 0 152 24 176

New Mexico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159 12 3,814 322 4,136

East. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159 10 668 318 986

West . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 2 3,146 4 3,150

New York . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 38 0 38

North Dakota . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53 1 17 29 46

Ohio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 0 115 8 123

Oklahoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90 55 4,838 110 4,948

Pennsylvania . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 603 36 639

Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,077 136 21,461 1,726 23,187

RRC District 1 . . . . . . . . . . . . . . . . . . . . . . . . . . 26 5 319 19 338

RRC District 2 Onshore . . . . . . . . . . . . . . . . . . 16 2 573 46 619

RRC District 3 Onshore . . . . . . . . . . . . . . . . . . 18 24 826 68 894

RRC District 4 Onshore . . . . . . . . . . . . . . . . . . 4 39 3,083 24 3,107

RRC District 5 . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 6,211 21 6,232

RRC District 6 . . . . . . . . . . . . . . . . . . . . . . . . . . 17 23 3,101 27 3,128

RRC District 7B. . . . . . . . . . . . . . . . . . . . . . . . . 5 0 830 4 834

RRC District 7C. . . . . . . . . . . . . . . . . . . . . . . . . 120 10 1,156 415 1,571

RRC District 8 . . . . . . . . . . . . . . . . . . . . . . . . . . 466 3 1,439 687 2,126

RRC District 8A. . . . . . . . . . . . . . . . . . . . . . . . . 386 1 3 353 356

RRC District 9 . . . . . . . . . . . . . . . . . . . . . . . . . . 9 3 2,257 13 2,270

RRC District 10 . . . . . . . . . . . . . . . . . . . . . . . . . 9 23 1,544 49 1,593

State Offshore. . . . . . . . . . . . . . . . . . . . . . . . . . 0 2 119 0 119

Utah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164 32 1,978 140 2,118

Virginia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 868 0 868

West Virginia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0 0 923 0 923

Wyoming . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 258 52 7,359 28 7,387

Federal Offshoreb. . . . . . . . . . . . . . . . . . . . . . . . . 1,921 135 6,121 1,911 8,032

Pacific (California). . . . . . . . . . . . . . . . . . . . . . . 37 4 47 99 146

Gulf of Mexico (Louisiana)b. . . . . . . . . . . . . . . 1,816 101 4,877 1,688 6,565

Gulf of Mexico (Texas) . . . . . . . . . . . . . . . . . . . 68 30 1,197 124 1,321

Miscellaneousc. . . . . . . . . . . . . . . . . . . . . . . . . . . 2 0 27 2 29

U.S. Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,174 504 60,669 6,045 66,714

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.

c

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

Source: Form EIA-23, "Annual Survey of Domestic Oil and Gas Reserves," 2006.

Energy Information Administration D-15

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 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 2006 by crude oil or

natural gas well operators who were active as of

December 31, 2006. 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 1999 and 2006, and depicts

the number of active operators, with 2002 showing the

largest in the series. The 2006 sampling frame consisted

of 173 Category I, 467 Category II, 232 Category III

Certainty, and 12,948 Category III Noncertainty

operators, for a total of 13,820 active operators. The

survey sample consisted of 872 operators selected with

certainty that included all of the Category I and II

Certainty operators, the 232 smaller operators that

were selected with certainty because of their size in

relation to the area or areas in which they operated, and

483 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 2006 survey is

summarized in Table E2. EIA makes a considerable

effort to gain responses from all operators. About 5.3

percent of those selected turned out to be nonoperators

(those that reported being nonoperators during the

report year and operators that could not be located). Of

the 58 nonoperators, 11 had successor operators that

had taken over the production of the nonoperator.

These successor operators were subsequently sampled.

The overall response rate for the 2006 survey was 95

percent. For the 69 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 2006 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 product ion data were requ ired by

State/subdivision areas for crude oil, natural gas, and

lease condensate. Proved reserves data for operators

were required only for those properties where

estimates existed in the respondent’s records.

All Category I and Category II operators were required

to file field level data on Schedule A, “Operated Proved

Reserves, Production, and Related Data by Field,” for

each oil and/or gas field in which the respondent

operated properties (Figure I4, Appendix I). All

Category I and those Category II operators who had

reserve estimates were required to file on a total

operated basis for crude oil, nonassociated natural gas,

associated-dissolved natural gas, and lease condensate.

The following data items were required to be filed:

proved reserves at the beginning and the end of the

report year, revision increases and revision decreases,

sales and acquisitions, extensions, new field

discoveries, new reservoirs in old fields, production,

indicated additional reserves of crude oil,

Energy Information Administration

E-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table E1. Comparison of the EIA-23 Sample and Sampling Frame, 1999-2006

Number of Operators

Operator Category 1999 2000 2001 2002 2003 2004 2005 2006

Certainty

Category I. . . . . . . . . . . . . 177 175 179 176 164 164 172 173

Category II . . . . . . . . . . . . 399 436 485 480 512 532 522 467

Category III. . . . . . . . . . . . 648 854 559 388 399 275 195 232

Sampled . . . . . . . . . . . . . 1,224 1,465 1,223 1,044 1,075 971 889 872

Percent Sampled . . . . . . . 100 100 100 100 100 100 100 100

Noncertainty

Sampled . . . . . . . . . . . . . . 1,305 1,311 644 533 479 370 505 483

Percent Sampled . . . . . . . 7 7 3 3 3 2 4 4

Total

Active Operators. . . . . . . . 22,089 22,102 22,519 22,823 20,923 20,670 15,158 13,820

Not Sampled . . . . . . . . . . 19,560 19,326 20,652 21,246 19,369 19,329 13,764 12,465

Sampled . . . . . . . . . . . . . . R2,529 2,776 1,867 1,577 1,554 1,341 1,394 1,355

Percent Sampled . . . . . . . R11 13 8 7 7 7 9 10

R=Revised data.

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

Table E2. Form EIA-23 Survey Response Statistics, 2006

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 . . . . . . . 173 0 1 -6 168 168 100.0 0 0.0

Category II . . . . . . . 467 3 -19 -11 440 427 97.0 13 3.0

Category III . . . . . . . 232 8 24 -17 247 224 90.7 23 9.3

Subtotal. . . . . . . . . 872 11 6 -34 855 819 95.8 36 4.2

Noncertainty . . . . . . . . 483 0 -6 -24 453 420 92.7 33 7.3

Total . . . . . . . . . . . . 1,355 11 0 -58 1,308 1,239 94.7 69 5.3

aSuccessor operators are those, not initially sampled, that have taken over the production of a sampled operator.

bNet of recategorized operators in the sample (excluding nonoperators).

c

Includes former operators reporting that they were not operators during the report year and operators that could not be located who are

treated as nonoperators.

dAdjusted sample equals original sample plus successor operators plus net category changes minus nonoperators.

eFor the 69 operators (13 Category II operators, 23 Category III operators, and 33 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” 2006.
nonproducing reserves, field discovery year, water

depth, and field location information.

Category II operators who did not have reserves

estimates were required to file the field location

information and report year production for the four

hydrocarbon types from properties where reserves

were not estimated. These respondents used Schedule

B, “Footnotes,” to provide clarification of reported data

items when required in the instructions, or electively to

provide narrative or detail to explain any data item

filed (Figure I5, Appendix I).

Crude oil and lease condensate volumes were reported

rounded to thousands of barrels of 42 U.S. gallons at

60 Fahrenheit, and natural gas volumes were reported

rounded to millions of cubic feet. All natural gas

volumes were requested to be reported at 60

Fahrenheit and a pressure base of 14.73 pounds per

square inch absolute. Other minor report preparation

standards were specified to assure that the filed data

could be readily processed.

Oil and Gas Field Coding

A major effort to create standardized codes for all

identified oil or gas fields throughout the United States

was implemented during the 1982 survey year.

Information from previous lists was reviewed and

reconciled with State lists and a consolidated list was

created. The publication of the Oil and Gas Field Code

Master List 2006, in January 2007, was the 25th annual

report and reflected data collected through December

2006. 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 2006, Form EIA-23 National estimates of

production were 1,834 million barrels for crude oil and

lease condensate or 28 million barrels (1.5 percent)

lower than that reported in the Petroleum Supply Annual

2006 for crude oil and lease condensate (1,862 million

barrels). Form EIA-23 National estimates of production

for dry natural gas were 18,545 billion cubic feet, 14

billion cubic feet (less than 1 percent) higher than the

Natural Gas Monthly, October 2007 for 2006 dry natural

gas production (18,531 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 2006 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 31, 2006. 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

operators (including both definite and probable

nonoperators) exist as a pool of names and addresses

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report E-3
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 Produ ction .” 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 2006 were required to complete

forms for the portion of 2006 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

221 operators of 491 plants were sent forms. This

number included 6 new plants, 2 reactivated plants,

and 1 successor plants, all identified after the initial

2006 survey mailing. A total of 5 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 2006 Annual Report

Table E3. Summary of the 2006 Operator Frame

Activity, Form EIA-23

Total 2005 Operator Frame. . . . . . . . . . . . . 68,616

Operators. . . . . . . . . . . . . . . . . . . . . . . 15,158

Nonoperators. . . . . . . . . . . . . . . . . . . . 53,458

Changes to 2005 Operator Status. . . . . . 2,574

From Nonoperator to Operatora. . . . . 1,761

From Operator to Nonoperator . . . . . . 813

New Operators . . . . . . . . . . . . . . . . . . 811

No Changes to 2005 Operator Status . . . 66,042

Operators. . . . . . . . . . . . . . . . . . . . . . . 13,007

Nonoperators. . . . . . . . . . . . . . . . . . . . 53,035

Additions to 2005 Operator Frame . . . . . 0

Operator . . . . . . . . . . . . . . . . . . . . . . . 0

Nonoperator. . . . . . . . . . . . . . . . . . . . . 0

Total 2006 Operator Frame. . . . . . . . . . . . 68,616

Operators. . . . . . . . . . . . . . . . . . . . . . . 16,106

Nonoperators. . . . . . . . . . . . . . . . . . . . 52,510

a

Includes operator frame activity through December 31, 2006.

BNo 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 19th 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 2006 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 2006,

the Form EIA-64A National estimates (Table E4) were

1 percent (6,819 thousand barrels) lower than the

Petroleum Supply Annual 2006 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 2006 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 March 1, 2007.

Energy Information Administration

E-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table E5. Form EIA-64A 2006 Plant Frame Activity

Frame as of 2005 survey mailing . . . . . . . 489

Additions . . . . . . . . . . . . . . . . . . . 58

Deletions . . . . . . . . . . . . . . . . . . . –56

Frame as of 2006 survey mailing . . . . . . . 491

Note: Includes operator frame activity through March 1, 2007.

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

Table E4. Natural Gas Processed and Liquids Extracted at Natural Gas Processing Plants, 2006

Volume of Natural Gas Delivered to Processing Plants

State Federal Out of State Natural Gas Total Liquids

Plant Location Production Production Production Processed Extracted

(million cubic feet) (thousand barrels)

Alaska . . . . . . . . . . . . . . . . . . 2,665,742 0 0 2,665,742 20,993

Alabama. . . . . . . . . . . . . . . . . 33,239 252,889 1,150 287,278 14,736

Arkansas . . . . . . . . . . . . . . . . 13,702 0 0 13,702 166

California . . . . . . . . . . . . . . . . 223,029 551 0 223,580 11,267

Colorado . . . . . . . . . . . . . . . . 750,835 0 201 751,036 26,111

Florida . . . . . . . . . . . . . . . . . . 1,973 0 1,999 3,972 357

Kansas. . . . . . . . . . . . . . . . . . 323,765 0 129,346 453,111 21,509

Kentucky . . . . . . . . . . . . . . . . 39,559 0 0 39,559 1,666

Louisiana . . . . . . . . . . . . . . . . 904,476 1,607,326 0 2,511,802 73,551

Michigan . . . . . . . . . . . . . . . . 33,213 0 0 33,213 2,335

Mississippi . . . . . . . . . . . . . . . 6,019 272,417 0 278,436 9,666

Montana. . . . . . . . . . . . . . . . . 12,685 0 0 12,685 1,043

North Dakota . . . . . . . . . . . . . 65,575 0 0 65,575 5,560

New Mexico . . . . . . . . . . . . . . 817,261 0 0 817,261 68,755

Oklahoma . . . . . . . . . . . . . . . 899,826 0 8,229 908,055 62,992

Texas. . . . . . . . . . . . . . . . . . . 3,953,075 0 37,787 3,990,862 261,087

Utah . . . . . . . . . . . . . . . . . . . . 190,119 0 3,717 193,836 2,418

West Virginia . . . . . . . . . . . . . 98,521 0 30,813 129,334 5,939

Wyoming . . . . . . . . . . . . . . . . 1,272,661 0 15,463 1,288,124 46,847

Miscellanousa. . . . . . . . . . . . 15,025 0 0 15,025 637

Total . . . . . . . . . . . . . . . . . . . 12,320,300 2,133,183 228,705 14,682,188 637,635

a

Includes Illinois, Ohio, and Pennsylvania.

Source: Form EIA-64A, “Annual Report of the Origin of Natural Gas Liquids Production,” 2006
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 2005. 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

2006 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 2005 for any product class.

 4 percent for each State/subdivision having less

than 1 percent of estimated U.S. reserves or

production in 2005 (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 2005.

 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

2005, and additionally, all coalbed methane and

Federal Offshore operators.

 Category III - Small Operators: Operators who

produced less than the Category II operators in

2005.

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.

 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.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report F-1
Table F1. 2006 EIA–23 Initial Number of Operators in Survey Sample

Number of Number of Number of

Certainty Multi–State Noncertainty Target Error

State and Subdivision Operators Operators Operators Oil Gas

Alabama Onshore 42 1 5 0.040 0.025

Alaska 7 0 0

Arkansas 64 10 9 0.040 0.025

California - Coastal Region Onshore 14 1 1 0.080 0.080

California - Los Angeles Basin Onshore 13 2 2 0.010 0.010

California - San Joaquin Basin Onshore 42 4 4 0.025 0.040

Colorado 121 2 18 0.025 0.010

Florida 4 0 0 0.025 0.025

Illinois 28 45 34 0.040 0.040

Indiana 23 7 33 0.040 0.080

Kansas 165 53 52 0.040 0.080

Kentucky 32 23 18 0.025 0.010

Louisiana-North 124 19 22 0.040 0.040

Louisiana-South Onshore 182 9 25 0.010 0.010

Michigan 33 6 3 0.010 0.010

Mississippi - Onshore 79 2 11 0.040 0.040

Montana 67 1 4 0.040 0.040

Nebraska 24 1 11 0.040 0.040

New Mexico - East 157 0 27 0.040 0.080

New Mexico - West 47 3 1 0.025 0.025

New York 15 2 7 0.025 0.010

North Dakota 65 0 6 0.080 0.040

Ohio 25 33 14 0.040 0.040

Oklahoma 268 131 79 0.040 0.040

Pennsylvania 46 18 12 0.025 0.025

Texas - RRC District 1 142 30 39 0.040 0.040

Texas - RRC District 2 Onshore 188 2 37 0.025 0.025

Texas - RRC District 3 Onshore 276 25 61 0.040 0.025

Texas - RRC District 4 Onshore 212 13 34 0.025 0.025

Texas - RRC District 5 107 3 20 0.040 0.010

Texas - RRC District 6 178 7 40 0.040 0.010

Texas - RRC District 7B 169 38 98 0.025 0.010

Texas - RRC District 7C 159 1 55 0.025 0.025

Texas - RRC District 8 189 1 46 0.040 0.025

Texas - RRC District 8A 174 9 54 0.010 0.010

Texas - RRC District 9 164 44 83 0.010 0.040

Texas - RRC District 10 141 15 31 0.025 0.025

Utah 56 3 2 0.040 0.010

Virginia 22 0 0 0.040 0.025

West Virginia 38 25 10 0.080 0.040

Wyoming 151 0 10 0.040 0.025

Offshore Areas 322 0 0 0.025 0.025

Other Statesa46 3 3 0.080 0.080

Total b1022 592 b383 0.010 0.010

a

Includes Arizona, Idaho, Iowa, Maryland, Missouri, Nevada, Oregon, South Dakota, Tennessee, and Washington.

bNonduplicative count of operators by States.

Note: Sampling rate was 10 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 2006 Annual Report
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 produc tion in the

State/subdivision. National totals were then obtained

by summation of the component totals.

Imputation and Estimation for

Reserves Data

There were 453 operators sampled proportional to size

(Table E2) that responded as Category III noncertainty

operators. Only 194 of these, located in 10 states, had

their data weighted and used to estimate the

production and reserves of the operators that were not

sam pled in those states. The remaining 259

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

2006 are summarized in Tables F2, F3, F4, and F5. The

reported data in Table F2 shows that those responding

operators accounted for 90.4 percent of the published

production for wet natural gas and 94.5 percent of the

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report F-3
reserves shown in Table 9. Data shown in Table F3

indicate that those responding operators accounted for

90.4 percent of the nonassociated natural gas

production and 94.3 percent of the reserves published

in Table 10. The reported data shown in Table F4

indicate that those responding operators accounted for

88.1 percent of published crude oil production and 93.9

percent of the reserves shown in Table 6. Additionally,

Table F5 indicates that those responding operators

accounted for 91.8 percent of the published production

and 94.5 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 2005 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 2005, 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

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.

Energy Information Administration

F-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report F-5

Table F2. Summary of Form EIA-23 Reported, Imputed, and Estimated Natural Gas Data for 2006,

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 . . . . . . . . . . . . . . . 168 427 224 420 9,485 10,724

Proved Reserves as of 12/31/05 . . . . . . 168,423,878 33,397,261 71,754 0 0 201,892,893

(+) Revision Increases . . . . . . . . . . . . 17,306,398 3,274,953 4,124 0 0 20,585,475

(-) Revision Decreases . . . . . . . . . . . . 17,759,712 4,661,005 32,328 0 0 22,453,045

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 20,900,422 3,012,204 45 0 0 23,912,671

(+) Acquisitions . . . . . . . . . . . . . . . . . . 22,445,453 4,625,322 0 0 0 27,070,775

(+) Extensions. . . . . . . . . . . . . . . . . . . 15,437,038 5,671,753 876 0 0 21,109,667

(+) New Field Discoveries. . . . . . . . . . 216,759 169,793 500 0 0 387,052

(+) New Reservoirs in Old Fields . . . . 753,295 373,524 45 0 0 1,126,864

(-) Production With

Proved Reserves Reported . . . . . 14,416,133 3,059,545 11,996 0 0 17,487,674

(-) Production Without

Proved Reserves Reported . . . . . 7,162 16,018 0 0 0 23,180

Proved Reserves as of 12/31/06 . . . . . . 171,509,399 36,823,576 64,038 0 0 208,397,013

Imputed and Estimated

Number of Operators . . . . . . . . . . . . . . . - - - 3,096 - 3,096

Proved Reserves as of 12/31/05 . . . . . . - - - - - -

(+) Revision Increases . . . . . . . . . . . . 0 0 0 1,627,948 1 1,627,949

(-) Revision Decreases . . . . . . . . . . . . 0 0 0 126,374 10 126,384

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 0 0 0 151,668 0 151,668

(+) Acquisitions . . . . . . . . . . . . . . . . . . 0 0 0 274 53 327

(+) Extensions. . . . . . . . . . . . . . . . . . . 0 0 0 4,616 373 4,989

(+) New Field Discoveries. . . . . . . . . . 0 0 0 617,444 0 617,444

(+) New Reservoirs in Old Fields . . . . 0 0 0 11,116 7 11,123

(-) Production With

Proved Reserves Reported . . . . . 0 0 0 20,108 17 20,125

(-) Production Without

Proved Reserves Reported . . . . . 15,013 32,045 298,476 345,534 1,152,454 1,843,522

Proved Reserves as of 12/31/06 . . . . . . 151,038 380,871 2,542,797 3,074,706 5,868,964 12,018,376

Total

Number of Operators . . . . . . . . . . . . . . . 168 427 224 3,516 9,485 13,820

Proved Reserves as of 12/31/05 . . . . . . 168,423,878 33,397,261 71,754 0 0 203,520,841

(+) Revision Increases . . . . . . . . . . . . 17,306,398 3,274,953 4,124 1,627,948 1 22,213,424

(-) Revision Decreases . . . . . . . . . . . . 17,759,712 4,661,005 32,328 126,374 10 22,579,429

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 20,900,422 3,012,204 45 151,668 0 24,064,339

(+) Acquisitions . . . . . . . . . . . . . . . . . . 22,445,453 4,625,322 0 274 53 27,071,102

(+) Extensions. . . . . . . . . . . . . . . . . . . 15,437,038 5,671,753 876 4,616 373 21,114,656

(+) New Field Discoveries. . . . . . . . . . 216,759 169,793 500 617,444 0 1,004,496

(+) New Reservoirs in Old Fields . . . . 753,295 373,524 45 11,116 7 1,137,987

(-) Production With

Proved Reserves Reported . . . . . 14,416,133 3,059,545 11,996 20,108 17 17,507,799

(-) Production Without

Proved Reserves Reported . . . . . 22,175 48,063 298,476 345,534 1,152,454 1,866,702

Proved Reserves as of 12/31/06 . . . . . . 171,660,437 37,204,447 2,606,835 3,074,706 5,868,964 220,415,389

Summary

Total Number of Operators . . . . . . . . . 168 427 224 3,516 9,485 13,820

Percent of Total . . . . . . . . . . . . . . . . . . 1.2% 3.1% 1.6% 25.4% 68.6% 100.0%

Total Production in 2006 . . . . . . . . . . . 14,438,308 3,107,608 310,472 365,642 1,152,471 19,374,501

Percent of Total . . . . . . . . . . . . . . . . . . 74.5% 16.0% 1.6% 1.9% 5.9% 100.0%

Total Proved Reserves 12/31/06 . . . . . 171,660,437 37,204,447 2,606,835 3,074,706 5,868,964 220,415,389

Percent of Total . . . . . . . . . . . . . . . . . . 77.9% 16.9% 1.2% 1.4% 2.7% 100.0%

aThere were 453 noncertainty responses, 194 were used with their sample weights and 259 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,” 2006.
Energy Information Administration

F-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table F3. Summary of Form EIA-23 Reported, Imputed, and Estimated Nonassociated Natural Gas Data

for 2006, 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 . . . . . . . . . . . . . . . 168 427 224 420 9,485 10,724

Proved Reserves as of 12/31/05 . . . . . . 143,717,198 31,216,588 58,006 0 0 174,991,792

(+) Revision Increases . . . . . . . . . . . . 12,441,499 2,935,760 2,497 0 0 15,379,756

(-) Revision Decreases . . . . . . . . . . . . 15,358,820 4,418,535 26,425 0 0 19,803,780

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 19,466,118 2,719,100 45 0 0 22,185,263

(+) Acquisitions . . . . . . . . . . . . . . . . . . 20,659,612 4,447,704 0 0 0 25,107,316

(+) Extensions. . . . . . . . . . . . . . . . . . . 14,858,938 5,497,594 876 0 0 20,357,408

(+) New Field Discoveries. . . . . . . . . . 182,556 165,085 0 0 0 347,641

(+) New Reservoirs in Old Fields . . . . 715,711 349,685 0 0 0 1,065,396

(-) Production With

Proved Reserves Reported . . . . . 12,557,479 2,858,572 10,440 0 0 15,426,491

(-) Production Without

Proved Reserves Reported . . . . . 6,747 17,023 0 0 0 23,770

Proved Reserves as of 12/31/06 . . . . . . 145,195,200 34,657,843 53,505 0 0 179,906,548

Imputed and Estimated

Number of Operators . . . . . . . . . . . . . . . - - - 3,096 - 3,096

Proved Reserves as of 12/31/05 . . . . . . - - - - - -

(+) Revision Increases . . . . . . . . . . . . 0 0 0 1,587,065 1 1,587,066

(-) Revision Decreases . . . . . . . . . . . . 0 0 0 110,025 11 110,036

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 0 0 0 147,410 0 147,410

(+) Acquisitions . . . . . . . . . . . . . . . . . . 0 0 0 274 53 327

(+) Extensions. . . . . . . . . . . . . . . . . . . 0 0 0 4,616 360 4,976

(+) New Field Discoveries. . . . . . . . . . 0 0 0 610,908 0 610,908

(+) New Reservoirs in Old Fields . . . . 0 0 0 11,116 6 11,122

(-) Production With

Proved Reserves Reported . . . . . 0 0 0 20,108 17 20,125

(-) Production Without

Proved Reserves Reported . . . . . 13,938 30,073 288,687 332,698 956,918 1,622,314

Proved Reserves as of 12/31/06 . . . . . . 141,076 361,290 2,450,640 2,953,006 4,964,260 10,870,272

Total

Number of Operators . . . . . . . . . . . . . . . 168 427 224 3,516 9,485 13,820

Proved Reserves as of 12/31/05 . . . . . . 143,717,198 31,216,588 58,006 0 0 176,578,857

(+) Revision Increases . . . . . . . . . . . . 12,441,499 2,935,760 2,497 1,587,065 1 16,966,822

(-) Revision Decreases . . . . . . . . . . . . 15,358,820 4,418,535 26,425 110,025 11 19,913,816

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 19,466,118 2,719,100 45 147,410 0 22,332,673

(+) Acquisitions . . . . . . . . . . . . . . . . . . 20,659,612 4,447,704 0 274 53 25,107,643

(+) Extensions. . . . . . . . . . . . . . . . . . . 14,858,938 5,497,594 876 4,616 360 20,362,384

(+) New Field Discoveries. . . . . . . . . . 182,556 165,085 0 610,908 0 958,549

(+) New Reservoirs in Old Fields . . . . 715,711 349,685 0 11,116 6 1,076,518

(-) Production With

Proved Reserves Reported . . . . . 12,557,479 2,858,572 10,440 20,108 17 15,446,616

(-) Production Without

Proved Reserves Reported . . . . . 20,685 47,096 288,687 332,698 956,918 1,646,084

Proved Reserves as of 12/31/06 . . . . . . 145,336,276 35,019,133 2,504,145 2,953,006 4,964,260 190,776,820

Summary

Total Number of Operators . . . . . . . . . 168 427 224 3,516 9,485 13,820

Percent of Total . . . . . . . . . . . . . . . . . . 1.2% 3.1% 1.6% 25.4% 68.6% 100.0%

Total Production in 2006 . . . . . . . . . . . 12,578,164 2,905,668 299,127 352,806 956,935 17,092,700

Percent of Total . . . . . . . . . . . . . . . . . . 73.6% 17.0% 1.8% 2.1% 5.6% 100.0%

Total Proved Reserves 12/31/06 . . . . . 145,336,276 35,019,133 2,504,145 2,953,006 4,964,260 190,776,820

Percent of Total . . . . . . . . . . . . . . . . . . 76.2% 18.4% 1.3% 1.5% 2.6% 100.0%

aThere were 453 noncertainty responses, 194 were used with their sample weights and 259 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,” 2006.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report F-7

Table F4. Summary of Form EIA-23 Reported, Imputed, and Estimated Crude Oil Data for 2006,

(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 . . . . . . . . . . . . . . . 168 427 224 420 9,485 10,724

Proved Reserves as of 12/31/05 . . . . . . 18,910,624 1,497,104 14,348 0 0 20,422,076

(+) Revision Increases . . . . . . . . . . . . 1,128,749 354,685 763 0 0 1,484,197

(-) Revision Decreases . . . . . . . . . . . . 1,363,587 140,374 3,200 0 0 1,507,161

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 817,259 166,859 0 0 0 984,118

(+) Acquisitions . . . . . . . . . . . . . . . . . . 957,488 217,684 48 0 0 1,175,220

(+) Extensions. . . . . . . . . . . . . . . . . . . 420,329 62,395 146 0 0 482,870

(+) New Field Discoveries. . . . . . . . . . 22,780 4,892 901 0 0 28,573

(+) New Reservoirs in Old Fields . . . . 25,315 14,750 17 0 0 40,082

(-) Production With

Proved Reserves Reported . . . . . 1,316,485 136,772 2,354 0 0 1,455,611

(-) Production Without

Proved Reserves Reported . . . . . 0 609 0 0 0 609

Proved Reserves as of 12/31/06 . . . . . . 17,968,311 1,707,959 14,762 0 0 19,691,032

Imputed and Estimated

Number of Operators . . . . . . . . . . . . . . . - - - 3,096 - 3,096

Proved Reserves as of 12/31/05 . . . . . . - - - - - -

(+) Revision Increases . . . . . . . . . . . . 0 0 0 20,747 5 20,752

(-) Revision Decreases . . . . . . . . . . . . 0 0 0 1,483 56 1,539

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 0 0 0 2,858 0 2,858

(+) Acquisitions . . . . . . . . . . . . . . . . . . 0 0 0 0 32 32

(+) Extensions. . . . . . . . . . . . . . . . . . . 0 0 0 0 20,084 20,084

(+) New Field Discoveries. . . . . . . . . . 0 0 0 528 4 532

(+) New Reservoirs in Old Fields . . . . 0 0 0 0 2,456 2,456

(-) Production With

Proved Reserves Reported . . . . . 0 0 0 0 19,787 19,787

(-) Production Without

Proved Reserves Reported . . . . . 1,398 6,311 12,331 20,040 137,036 177,116

Proved Reserves as of 12/31/06 . . . . . . 23,611 66,330 123,372 213,313 857,835 1,284,461

Total

Number of Operators . . . . . . . . . . . . . . . 168 427 224 3,516 9,485 13,820

Proved Reserves as of 12/31/05 . . . . . . 18,910,624 1,497,104 14,348 0 0 20,442,823

(+) Revision Increases . . . . . . . . . . . . 1,128,749 354,685 763 20,747 5 1,504,949

(-) Revision Decreases . . . . . . . . . . . . 1,363,587 140,374 3,200 1,483 56 1,508,700

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 817,259 166,859 0 2,858 0 986,976

(+) Acquisitions . . . . . . . . . . . . . . . . . . 957,488 217,684 48 0 32 1,175,252

(+) Extensions. . . . . . . . . . . . . . . . . . . 420,329 62,395 146 0 20,084 502,954

(+) New Field Discoveries. . . . . . . . . . 22,780 4,892 901 528 4 29,105

(+) New Reservoirs in Old Fields . . . . 25,315 14,750 17 0 2,456 42,538

(-) Production With

Proved Reserves Reported . . . . . 1,316,485 136,772 2,354 0 19,787 1,475,398

(-) Production Without

Proved Reserves Reported . . . . . 1,398 6,920 12,331 20,040 137,036 177,725

Proved Reserves as of 12/31/06 . . . . . . 17,991,922 1,774,289 138,134 213,313 857,835 20,975,493

Summary

Total Number of Operators . . . . . . . . . 168 427 224 3,516 9,485 13,820

Percent of Total . . . . . . . . . . . . . . . . . . 1.2% 3.1% 1.6% 25.4% 68.6% 100.0%

Total Production in 2006 . . . . . . . . . . . 1,317,883 143,692 14,685 20,040 156,823 1,653,123

Percent of Total . . . . . . . . . . . . . . . . . . 79.7% 8.7% 0.9% 1.2% 9.5% 100.0%

Total Proved Reserves 12/31/06 . . . . . 17,991,922 1,774,289 138,134 213,313 857,835 20,975,493

Percent of Total . . . . . . . . . . . . . . . . . . 85.8% 8.5% 0.7% 1.0% 4.1% 100.0%

aThere were 453 noncertainty responses, 194 were used with their sample weights and 259 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,” 2006.
Energy Information Administration

F-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table F5. Summary of Form EIA-23 Reported, Imputed, and Estimated Lease Condensate Data for 2006,

(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 . . . . . . . . . . . . . . . 168 427 224 420 9,485 10,724

Proved Reserves as of 12/31/05 . . . . . . 965,527 231,313 193 0 0 1,197,033

(+) Revision Increases . . . . . . . . . . . . 183,570 63,391 47 0 0 247,008

(-) Revision Decreases . . . . . . . . . . . . 149,518 55,065 31 0 0 204,614

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 152,665 17,784 0 0 0 170,449

(+) Acquisitions . . . . . . . . . . . . . . . . . . 132,420 33,364 0 0 0 165,784

(+) Extensions. . . . . . . . . . . . . . . . . . . 128,187 43,584 0 0 0 171,771

(+) New Field Discoveries. . . . . . . . . . 3,496 3,815 0 0 0 7,311

(+) New Reservoirs in Old Fields . . . . 10,875 8,570 0 0 0 19,445

(-) Production With

Proved Reserves Reported . . . . . 134,695 31,231 88 0 0 166,014

(-) Production Without

Proved Reserves Reported . . . . . 30 673 0 0 0 703

Proved Reserves as of 12/31/06 . . . . . . 987,311 280,052 190 0 0 1,267,553

Imputed and Estimated

Number of Operators . . . . . . . . . . . . . . . - - - 3,096 - 3,096

Proved Reserves as of 12/31/05 . . . . . . - - - - - -

(+) Revision Increases . . . . . . . . . . . . 0 0 0 16,382 1 16,383

(-) Revision Decreases . . . . . . . . . . . . 0 0 0 2,740 5 2,745

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 0 0 0 3,102 0 3,102

(+) Acquisitions . . . . . . . . . . . . . . . . . . 0 0 0 3 13 16

(+) Extensions. . . . . . . . . . . . . . . . . . . 0 0 0 0 10,753 10,753

(+) New Field Discoveries. . . . . . . . . . 0 0 0 2,075 0 2,075

(+) New Reservoirs in Old Fields . . . . 0 0 0 145 7 152

(-) Production With

Proved Reserves Reported . . . . . 0 0 0 275 10 285

(-) Production Without

Proved Reserves Reported . . . . . 68 156 2,537 2,761 9,566 15,088

Proved Reserves as of 12/31/06 . . . . . . 652 898 17,237 18,787 33,564 71,138

Total

Number of Operators . . . . . . . . . . . . . . . 168 427 224 3,516 9,485 13,820

Proved Reserves as of 12/31/05 . . . . . . 965,527 231,313 193 0 0 1,213,415

(+) Revision Increases . . . . . . . . . . . . 183,570 63,391 47 16,382 1 263,391

(-) Revision Decreases . . . . . . . . . . . . 149,518 55,065 31 2,740 5 207,359

(-) Sales . . . . . . . . . . . . . . . . . . . . . . . 152,665 17,784 0 3,102 0 173,551

(+) Acquisitions . . . . . . . . . . . . . . . . . . 132,420 33,364 0 3 13 165,800

(+) Extensions. . . . . . . . . . . . . . . . . . . 128,187 43,584 0 0 10,753 182,524

(+) New Field Discoveries. . . . . . . . . . 3,496 3,815 0 2,075 0 9,386

(+) New Reservoirs in Old Fields . . . . 10,875 8,570 0 145 7 19,597

(-) Production With

Proved Reserves Reported . . . . . 134,695 31,231 88 275 10 166,299

(-) Production Without

Proved Reserves Reported . . . . . 98 829 2,537 2,761 9,566 15,791

Proved Reserves as of 12/31/06 . . . . . . 987,963 280,950 17,427 18,787 33,564 1,338,691

Summary

Total Number of Operators . . . . . . . . . 168 427 224 3,516 9,485 13,820

Percent of Total . . . . . . . . . . . . . . . . . . 1.2% 3.1% 1.6% 25.4% 68.6% 100.0%

Total Production in 2006 . . . . . . . . . . . 134,793 32,060 2,625 3,036 9,576 182,090

Percent of Total . . . . . . . . . . . . . . . . . . 74.0% 17.6% 1.4% 1.7% 5.3% 100.0%

Total Proved Reserves 12/31/06 . . . . . 987,963 280,950 17,427 18,787 33,564 1,338,691

Percent of Total . . . . . . . . . . . . . . . . . . 73.8% 21.0% 1.3% 1.4% 2.5% 100.0%

aThere were 453 noncertainty responses, 194 were used with their sample weights and 259 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,” 2006.
Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report F-9

Table F6. Statistical Parameters of Reserves Estimation Equation by Region for 2006

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. . . . . . . . . . . . . . . . . . 6 10 - -0.1373 0.3427 -0.1486 0.2435 0.0000 0.0000

2 Pacific Coast States . . . . . . . . . . . 46 57 7 -0.1373 0.2897 -0.1486 0.4199 -0.1224 0.1432

2A Federal Offshore Pacific . . . . . . . . . 7 7 - -0.1373 0.2451 -0.1486 0.2284 0.0000 0.0000

3 Western Rocky Mountains . . . . . . . . 78 136 62 -0.1373 0.2014 -0.1486 0.3279 -0.1224 0.3288

4 Northern Rocky Mountains . . . . . . . . 163 170 52 -0.1373 0.2619 -0.1486 0.3508 -0.1224 0.2658

5 West Texas and East New Mexico . . . . 484 482 171 -0.1373 0.2612 -0.1486 0.3643 -0.1224 0.4047

6 Western Gulf Basin. . . . . . . . . . . . 508 839 561 -0.1373 0.3344 -0.1486 0.4438 -0.1224 0.4958

6A Gulf of Mexico . . . . . . . . . . . . . . 73 130 101 -0.1373 0.4985 -0.1486 0.8075 -0.1224 0.7175

7 Mid-Continent . . . . . . . . . . . . . . 293 378 141 -0.1373 0.2783 -0.1486 0.3686 -0.1224 0.2943

8 + 9 Michigan Basin and Eastern Interior . . . . 78 64 16 -0.1373 0.2028 -0.1486 0.1849 -0.1224 0.4602

10 + 11 Appalachians . . . . . . . . . . . . . . 26 80 13 -0.1373 0.1988 -0.1486 0.1785 -0.1224 0.2935

United States . . . . . . . . . . . . . . 1,762 2,353 1,124 -0.1373 0.3292 -0.1486 0.3940 -0.1224 0.4567

Source: Based on data filed on Form EIA-23,"Annual Survey of Domestic Oil and Gas Reserves, 2006".

Figure F1. Form EIA-23 Regional Boundaries
Both methods preserved an exact annual reserves

balance of the following form:

The algebraic allocation method used for all but six

states in the 2006 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

2006 than in 2005.

 One or more operators may have reported data

incorrectly on Schedule A in 2006 or 2005, but

not both, and the error was not detected by edit

processing.

 Operation of properties was transferred during

2006 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.

Energy Information Administration

F-10 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 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
 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 211,085   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

2006 survey was 4.2 percent and for the noncertainty

operators 7.3 percent. An imputation was made for the

production and reserves for the 33 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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report F-11
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 2006 survey is particularly likely to be deficient in

States where a large portion of total reserves and

production is accounted for by small operators. EIA is

continuing to work to remedy the under coverage

problem in those States where it occurred.

Imputation Errors

Some error, generally expected to be small, is an

inevitable result of the various estimations outlined.

These imputation errors have not yet been completely

addressed by EIA and it is possible that estimation

methods may be altered in future surveys. Nationally,

6.1 percent of the crude oil proved reserve estimates,

5.5 percent of the wet natural gas proved reserve

estimates, and 5.5 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.

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

Energy Information Administration

F-12 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report
Energy Information Administration F-13

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

United States. . . . . . . . . . . . . . . 5 1

Alabamab. . . . . . . . . . . . . . . . . . 0 0

Alaskaa. . . . . . . . . . . . . . . . . . . 0 0

Arkansasb. . . . . . . . . . . . . . . . . 0 0

Californiab. . . . . . . . . . . . . . . . . 0 0

Coloradob. . . . . . . . . . . . . . . . . 0 0

Floridaa. . . . . . . . . . . . . . . . . . . 0 0

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

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

Kansasb. . . . . . . . . . . . . . . . . . . 0 0

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

Louisianab. . . . . . . . . . . . . . . . . 0 0

Michiganb. . . . . . . . . . . . . . . . . 0 0

Mississippib. . . . . . . . . . . . . . . . 0 0

Montanab. . . . . . . . . . . . . . . . . . 0 0

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

New Mexicob. . . . . . . . . . . . . . 0 0

North Dakotab. . . . . . . . . . . . . . 0 0

Ohiob. . . . . . . . . . . . . . . . . . . . . 0 0

Oklahomab. . . . . . . . . . . . . . . . 0 0

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

Texasb. . . . . . . . . . . . . . . . . . . . 0 0

Utahb. . . . . . . . . . . . . . . . . . . . . 0 0

Virginiaa. . . . . . . . . . . . . . . . . . . 0 0

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

Wyomingb. . . . . . . . . . . . . . . . . 0 0

Federal Offshorea. . . . . . . . . . . 0 0

Miscellaneousc. . . . . . . . . . . . . 2 0

Table F7. Factors for Confidence Intervals (2S.E.) for Crude Oil Proved Reserves and Production, 2006

(Million Barrels of 42 U.S. Gallons)

2006 2006 2006 2006

State and Subdivision Reserves Production State and Subdivision Reserves Production

Table F8. Factors for Confidence Intervals (2S.E.) for Natural Gas Proved Reserves and Production,

Wet After Lease Separation, 2006 (Billion Cubic Feet at 14.73 psia and 60 Degrees Fahrenheit)

2006 2006 2006 2006

State and Subdivision Reserves Production State and Subdivision Reserves Production

United States. . . . . . . . . . . . . . . 59 5

Alabamab. . . . . . . . . . . . . . . . . . 0 0

Alaskaa. . . . . . . . . . . . . . . . . . . 0 0

Arkansasb. . . . . . . . . . . . . . . . . 0 0

Californiab. . . . . . . . . . . . . . . . . 0 0

Coloradob. . . . . . . . . . . . . . . . . 0 0

Floridaa. . . . . . . . . . . . . . . . . . . 0 0

Kansasb. . . . . . . . . . . . . . . . . . . 0 0

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

Louisianab. . . . . . . . . . . . . . . . . 0 0

Michiganb. . . . . . . . . . . . . . . . . 0 0

Mississippib. . . . . . . . . . . . . . . . 0 0

Montanab. . . . . . . . . . . . . . . . . . 0 0

New Mexicob. . . . . . . . . . . . . . . 0 0

New Yorkb. . . . . . . . . . . . . . . . . 0 0

North Dakotab. . . . . . . . . . . . . . 0 0

Ohiob. . . . . . . . . . . . . . . . . . . . . 0 0

Oklahomab. . . . . . . . . . . . . . . . 0 0

Pennsylvania. . . . . . . . . . . . . . . 7 1

Texasb. . . . . . . . . . . . . . . . . . . . 0 0

Utahb. . . . . . . . . . . . . . . . . . . . . 0 0

Virginiaa. . . . . . . . . . . . . . . . . . . 0 0

West Virginia . . . . . . . . . . . . . . . 10 1

Wyomingb. . . . . . . . . . . . . . . . . 0 0

Federal Offshorea c. . . . . . . . . . 0 0

Miscellaneousd. . . . . . . . . . . . . 4 0

aSampling rate was 100 percent in Alaska, Florida Onshore, Virginia, and Offshore areas. bSampling was not used. Estimates for each operator were made using an imputation function.

c

Includes Arizona, Missouri, Nevada, South Dakota, Tennessee, and Virginia.

Notes: Confidence intervals are associated with Table 6 reserves and production data.

Factors for confidence intervals for each State and the United States are independently estimated and do not add.

Source: Factor estimates based on data filed on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 2006.

aSampling rate was 100 percent in Alaska, Florida Onshore, Virginia, and Offshore areas. bSampling was not used. Estimates for each operator were made using an imputation function.

c

Includes Federal offshore Alabama. d

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

Notes: Confidence intervals are associated with Table 8 reserves and production data.

Factors for confidence intervals for each State and the United States are independently estimated and do not add.

Source: Factor estimates based on data filed on Form EIA-23, “Annual Survey of Domestic Oil and Gas Reserves,” 2006
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 2006 Form

EIA-64A survey, the national weighted average gas

equivalents ratio was computed to be 1,421 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 fi elds did not cau se

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 2006 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 tree diagram presented in Figure G1 outlines a

simplified version of the total resource base and its

components in two dimensions. 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”.

A three-dimensional diagram of the Total In-Place

Resource base is presented in Figure G2. This diagram

represents the total in-place resource base as mapped

over three axes: Probability, Activity, and Economics.

Included are definitions of proved, probable, possible,

and speculative reserves, developed or undeveloped

reserves, contingent resources (economic and

uneconomic), nonlinear probability distributions for

reserves, contingent resources, and undiscovered

initially-in-place resources.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 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)
Figure G2. Resource Base

Energy Information Administration

G-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Notes: Numeric subscripts (e.g. R50, IIP90) indicate the probability that the associated volume exists.

Drawing is not scaled to any volumetric estimates. Probability distributions in this diagram are nonlinear.

Source: Reserves and Production Division, Office of Oil and Gas, Energy Information Administration.
The terms in Figure G2 are consistent with the resource

definitions adopted by the Society of Petroleum

Engineers (SPE) as set forth in their 2007 document,

Petroleum Resources Management System, prepared by its

Oil and Gas Reserves Committee; reviewed and jointly

sponsored by the World Petroleum Council (WPC), the

American Association of Petroleum Geologists

(AAPG), and the Society of Petroleum Evaluation

Engineers (SPEE). {46}

Recoverable Resources

Discover ed 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.

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 th e 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 1,533 trillion cubic feet (Table G1).

Adding the 2006 U.S. proved reserves of 211 trillion

cubic feet yields a technically recoverable resource

target of 1,744 trillion cubic feet. This is about 94 times

the 2006 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 2006 the PGC mean

estimate of potential gas resources was 1,321 trillion

cubic feet, about 211 trillion cubic feet less than the

estimates 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 2006 oil production (Table

G1) was about 107 to 1, higher than the comparable gas

ratio.

Discovered Resources

In addition to cumulative production, which is the sum

of current year production and the production in all

prior years, estimates of discovered recoverable

resources include estimates of reserves. Broadly,

reserves are those volumes that are believed to be

economically 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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report G-3
Energy Information Administration

G-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Table G1. Mean Estimates of Technically Recoverable Oil and Gas Resources by Deposit Type and Location

Natural Gas

Crude Oil Natural Gas (Dry) Liquids

Area (billion barrels) (trillion cubic feet) (billion barrels)

Undiscovered Conventionally Reservoired Fields

Alaska Onshore + State Offshore 26.04 126.75 2.23

Alaska Federal Offshore 26.61a132.06 0.00a

Lower 48 States Onshore + State Offshore 18.24 178.21 5.56

Lower 48 States Federal Offshore 59.27a287.82 0.00a

Alaska Subtotal 52.65 258.81 2.23

Lower 48 States Subtotal 77.51 466.03 5.56

Technically Recoverable Resources in U.S.

Undiscovered Conventionally Reservoired Fields 130.16 724.84 7.79

Ultimate Recovery Appreciation

Alaska Onshore + State Offshore 6.96 12.30 0.41

Lower 48 States Onshore + State Offshore 31.70 442.50 17.85

U.S. Federal Offshore 6.88a30.91 0.00a

Technically Recoverable Resources in U.S.

from Ultimate Recovery Appreciation in Discovered

Conventionally Reservoired Fields 45.54 485.71 18.26

Continuous Type Deposits

Alaska Non-coal bed 0.00 0.00 0.00

Lower 48 States Non-coal bed 2.13 236.89 3.80

Alaska Coal bed 0.00 18.06 0.00

Lower 48 States Coal bed 0.00 67.32 0.00

Non-coal bed Subtotal 2.13 236.89 3.80

Coal bed Subtotal 0.00 85.38 0.00

Technically Recoverable Resources in U.S.

from Continuous Type Deposits 2.13 322.27 3.80

U.S. Totals All Sources

U.S. Onshore + State Offshore 85.07 1,082.03 29.85

Federal Offshore 92.76a450.79 0.00a

U.S. Technically Recoverable Resources 177.83 1,532.82 29.85

a The MMS jointly reports natural gas liquids with crude oil for the Federal Offshore.

Additional Notes: Proved Reserves are excluded from these estimates as are undiscovered oil resources in tar deposits and oil shales, and

undiscovered gas resources in geopressured brines and gas hydrates.

Zero (0) indicates either that none exists in this area or that no estimate of this resource has been made for this area, or in the instance of

Federal offshore natural gas liquids resources that they are jointly reported with crude oil.

Federal Onshore excludes Indian and Native lands even when Federally managed in trust.

Federal Offshore indicates MMS estimates for Federal Offshore jurisdictions (Outer Continental Shelf and deeper water areas seaward of

State Offshore).

Data Sources: National Oil and Gas Resource Assessment Team, 2007 Assessment Updates, United States Geological Survey, Washington

DC, December 2007 at <http://energy.cr.usgs.gov/oilgas/noga/ass_updates.html>

Resource Evaluation Division, Assessment of Undiscovered Technically Recoverable Oil and Gas Resources of the Nation's Outer

Continental Shelf, 2006, MMS Fact Sheet RED-2006-01b, Minerals Management Service, Washington, DC, February 2006 at

<http://www.mms.gov/revaldiv/PDFs/2006NationalAssessmentBrochure.pdf>.

The ultimate recovery appreciation estimates for Alaska and the Lower 48 States Onshore Plus State Waters were developed by the

Reserves and Production Division, Office of Oil and Gas, Energy Information Administration, based on data available as of year-end 2006.
and incorporate various definitions of terms such as

measured reserves, indicated reserves, inferred reserves,

probable reserves, and possible reserves. As used by the

different organizations, the definitions that attach to

these terms sometimes overlap, or the terms may

require a slightly different interpretation from one

organization to the next. Nevertheless, all kinds of

“other reserves” are generally less well known and

therefore less precisely quantifiable than proved

reserves, and their eventual recovery is less assured.

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.{47} They are similarly defined by the MMS,

although its system also subdivides them by degree of

development and producing status.{48} 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

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 judgm ent 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

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report G-5
from a well or several wells; geologic maps of the areal

extent, thickness, and continuity of the reservoir rocks

(inferred from well logs, geophysical, and geological

data); and reservoir pressure and temperature data.

Also involved are economic data including the current

price of crude oil and natural gas, and various

developmental and operating costs.

Reserve Estimation Techniques

Depending on the kinds and amounts of data available,

and a judgment on the reliability of those data, the

estimator will select one of several methods of making

a proved reserves estimate. Methods based on

production performance data are generally more

accurate than those based strictly on inference from

geological and engineering data. Such methods include

the Production Decline method (for crude oil or natural

gas reservoirs), the Material Balance method (for crude

oil reservoirs), the Pressure Decline method (which is

actually a material balance, for natural gas reservoirs),

and the Reservoir Simulation method (for crude oil or

natural gas reservoirs). The reservoir type and

production mechanisms and the types and amounts of

reliable data available determine which of these

methods is more appropriate for a given reservoir.

These methods are of comparable accuracy.

Methods not based upon production data include the

Volumetric method (for crude oil or natural gas

reservoirs) and the Nominal method. Of these, the

Volumetric method is the more accurate. Both methods,

however, are less accurate than those based on

production data. Table G2 summarizes the various

methods.

Judgmental Factors

in Reserve Estimation

The determination of rock and hydrocarbon fluid

properties involves judgment and is subject to some

uncertainty; however, the construction of the geologic

maps and cross sections and the determination of the

size of the reservoir are the major judgmental steps in

the Volumetric method, and are subject to the greatest

uncertainty. Estimates made using the Material Balance

method, the Reservoir Simulation method, or the

Pressure Decline method are based on the estimator's

judgment that the type of reservoir drive mechanism

has been identified and on the specification of

abandonment conditions. Estimates based on the

Production Decline method are subject to judgment in

constructing the trend line, and are based on the

estimator's assumption of reservoir performance

through abandonment.

Contributing to the degree of uncertainty inherent in

the above methods for estimating reserves are other

factors associated with economic considerations and

the perceived reservoir limits, which together influence

the final reserves estimate. A brief discussion of these

other factors follows.

Economic considerations: There has been continuing

debate about the effects of prices on proved reserves.

Although no all–inclusive statement can be made on

the impact of price, the points at issue can be discussed

and some general remarks can be made about some

circumstances where price may be a factor.

 Developed gas fields – In a gas reservoir, price

affects the economic limit (i.e., the production

rate required to meet operating costs) and,

therefore, the abandonment pressure. Thus, price

change has some effect on the conversion of

noneconomic hydrocarbon resources to the

category of proved reserves. In both nearly

depleted reservoirs and newly developed

Energy Information Administration

G-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

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.
reservoirs, the actual increase in the quantity of

proved reserves resulting from price rises is

generally limited in terms of national volumes

(even though the percentage increase for a given

reservoir may be great).

 Developed oil fields – In developed crude oil

reservoirs many of the same comments apply;

however, there is an additional consideration. If

the price is raised to a level sufficient to justify

initiation of an improved recovery project, and if

the improved recovery technique is effective,

then the addition to ultimate recovery from the

reservoir can be significant. Because of the

speculative nature of predicting prices and costs

many years into the future, proved reserves are

estimated on the basis of current prices, costs,

and operating practices in effect as of the date the

estimation was made.

 Successful exploration efforts – Price can have a

major impact on whether a new discovery is

produced or abandoned. For example, the

decision to set casing in a new onshore

discovery, or to install a platform as the result of

an offshore discovery, are both price–sensitive. If

the decision is made to set pipe or to install a

platform, the discoveries in both cases will add

to the proved reserves total. If such projects are

abandoned, they will make no contribution to

the proved reserves total.

Effect of operating conditions: Operating conditions

are subject to change caused by changes in economic

conditions, unforeseen production problems, new

production practices or methods, and the operator's

financial position. As with economic conditions,

operating conditions to be expected at the time of

abandonment are speculative. Thus, current operating

conditions are used in estimating proved reserves. In

considering the effect of operating conditions, a

distinction must be made between processes and

techniques that would normally be applied by a

prudent operator in producing his oil and gas, and

initiation of changes in operating conditions that

would require substantial new investment.

 Compression – Compression facilities are

normally installed when the productive capacity

or deliverability of a natural gas reservoir or its

individual wells declines. In other cases

compression is used in producing shallow,

low–pressure reservoirs or reservoirs in which

the pressure has declined to a level too low for

the gas to flow into a higher pressure pipeline.

The application of compression increases the

pressure and, when economical, is used to make

production into the higher pressure pipeline

possible. Compression facilities normally require

a significant investment and result in a change in

operating conditions. It increases the proved

reserves of a reservoir, and reasonably accurate

estimates of the increase can be made.

 Well stimulation – Procedures that increase

productive capacity (workovers, such as

acidizing or fracturing, and other types of

production practices) are routine field

operations. The procedures accelerate the rate of

production from the reservoir, or extend its life,

and they have only small effect on proved

reserves. Reasonable estimates of their

effectiveness can be made.

 Improved recovery techniques – These techniques

involve the injection of a fluid or fluids into a

reservoir to augment natural reservoir energy.

Because the response of a given reservoir to the

application of an improved recovery technique

cannot be accurately predicted, crude oil

production that may ultimately result from the

application of these techniques is classified as

“indicated additional reserves of crude oil”

rather than as proved reserves until response of

the reservoir to the technique has been

demonstrated. In addition, improved recovery

methods are not applicable to all crude oil

reservoirs. Initiation of improved recovery

techniques may require significant investment.

 Infill drilling – Infill drilling (drilling of additional

wells within a field/reservoir) may result in a

higher recovery factor, and, therefore, be

economically justified. Predictions of whether

infill drilling will be justified under current

economic conditions are generally based on the

expected production behavior of the infill wells.

Reservoir limits: The initial proved reserves estimate

made from the discovery well is subject to significant

uncertainty because one well provides little

information on the size of the reservoir. The area

proved by a discovery well is frequently estimated on

the basis of experience in a given producing region.

Where there is continuity of the producing formation

over wide geographic areas, a relatively large proved

area may be assigned. In some cases where reliable

geophysical and geological data are available, a

reasonable estimate of the extent of the reservoir can be

made by drilling a relatively small number of

delineation wells. Conversely, a relatively small

proved area may be assigned when the producing

formation is of limited continuity, owing to either

structural or lithological factors.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report G-7
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.

Unconventional Production and

Proved Reserves

For the 2006 survey, a new Form EIA-23L data element

called Type Code replaced the underutilized MMS Code.

The Type Codeis used to categorize proved reserves and

production from a field as either Conventional (C) or one

of four types of Unconventional reservoirs: Coal Bed

(CB); Chalk (CH); Shale (SH); or other Low Permeability

(LP) reservoirs (permeability of 0.1 millidarcy or less).

Type Code was added because the importance of

unconventional resources of natural gas and crude oil

to domestic energy supply continues to increase.

2006 was the first year the Type Code classification was

introduced, therefore, the results of the reported data

were considered incomplete for all sources of

unconventional proved reserves and production

except coalbed natural gas at the time of publication for

this report. EIA has reported coalbed natural gas

proved reserves and production separately since 1989

(see Table 12, Chapter 4).

In future reports, as operators familiarize themselves

with the Type Code, we expect increased coverage and

reliability from the reported volumes.

Energy Information Administration

G-8 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report
Appendix H

Maps of Selected State Subdivisions

Appendix H

Figure H1. Subdivisions of Alaska

Source: After U.S. Geological Survey.

Energy Information Administration

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 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 2006 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 2006 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 2006 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 2006 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 2006 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 2006 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 2006 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 2006 Annual Report I-1

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

Figure I1. Form EIA-23, Cover Page
Energy Information Administration

I-2 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Figure I2. Form EIA-23, Summary Report – Page 1

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report I-3

Figure I3. Form EIA-23, Summary Report – Page 2

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

I-4 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Figure I4. Form EIA-23, Detail Report – Schedule A

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

U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report I-5

Figure I5. Form EIA-23, Detail Report – Schedule B

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

I-6 U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 2006 Annual Report

Figure I6. Form EIA-64A

Source: Energy Information Administration, Offfice of Oil and Gas.
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 2006 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 2006 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 2006 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 2006 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 2006 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 2006 Annual Report