UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

x                              ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

or

o                                 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from          to          

Commission file number: 001-07964

NOBLE ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware

 

73-0785597

(State of incorporation)

 

(I.R.S. employer identification number)

100 Glenborough Drive, Suite 100

 

 

Houston, Texas

 

77067

(Address of principal executive offices)

 

(Zip Code)

 

(Registrant’s telephone number, including area code)

(281) 872-3100

Securities registered pursuant to section 12(b) of the Act:

Title of each class

 

Name of each exchange on which registered

Common Stock, $3.33-1/3 par value

 

New York Stock Exchange

Preferred Stock Purchase Rights

 

New York Stock Exchange

 

Securities registered pursuant to section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. x Yes o No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes x No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
 
o Yes x No

Aggregate market value of Common Stock held by nonaffiliates as of June 30, 2006: $8,136,291,163. Number of shares of Common Stock outstanding as of February 12, 2007: 170,405,901.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s definitive proxy statement for the 2007 Annual Meeting of Stockholders to be held on April 24, 2007, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2006, are incorporated by reference into Part III.

 




TABLE OF CONTENTS

Part I

Items 1 and 2.

Business and Properties.

1

 

General

1

 

Strategy

1

 

Proved Reserves

1

 

Acquisition and Divestiture Activities

3

 

Crude Oil and Natural Gas Properties and Activities

4

 

Regulations

16

 

Competition

18

 

Geographical Data

18

 

Employees

18

 

Offices

18

 

Title to Properties

18

 

Available Information

18

Item 1A.

Risk Factors.

19

Item 1B.

Unresolved Staff Comments.

25

Item 3.

Legal Proceedings.

25

Item 4.

Submission of Matters to a Vote of Security Holders.

26

 

Executive Officers

26

Part II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

28

Item 6.

Selected Financial Data

30

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations.

31

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk.

57

Item 8.

Financial Statements and Supplementary Data.

59

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

116

Item 9A.

Controls and Procedures.

117

Item 9B.

Other Information.

117

Part III

Item 10.

Directors, Executive Officers and Corporate Governance.

118

Item 11.

Executive Compensation.

118

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

118

Item 13.

Certain Relationships and Related Transactions, and Director Independence.

118

Item 14.

Principal Accounting Fees and Services

118

Part IV

Item 15.

Exhibits, Financial Statements Schedules

118

 




PART I

Items 1 and 2.                 Business and Properties.

This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. For more information, see Item 1A. Risk Factors – Disclosure Regarding Forward-Looking Statements of this Form 10-K.

General

Noble Energy, Inc. (“Noble Energy”, “we” or “us”) is a Delaware corporation, formed in 1969, that has been publicly traded on the New York Stock Exchange (“NYSE”) since 1980. We are an independent energy company that has been engaged in the exploration, development, production and marketing of crude oil and natural gas since 1932. In this report, unless otherwise indicated or where the context otherwise requires, information includes that of Noble Energy and its subsidiaries. Exploration activities include geophysical and geological evaluation and exploratory drilling on properties for which we have exploration rights. We operate throughout major basins in the U.S. including Colorado’s Wattenberg field, the Mid-continent region of western Oklahoma and the Texas Panhandle, the San Juan Basin in New Mexico, the Gulf Coast and the Gulf of Mexico. In addition, we conduct business internationally in West Africa (Equatorial Guinea and Cameroon), the Mediterranean Sea, Ecuador, the North Sea, China, Argentina, and Suriname.

Strategy

We are a worldwide producer of crude oil and natural gas. Our strategy is to achieve growth in earnings and cash flow through the development of a high quality portfolio of producing assets that is balanced between domestic and international projects. In 2005, we completed a merger (the “Patina Merger”) with Patina Oil & Gas Corporation (“Patina”). In 2006, we acquired U.S. Exploration Holdings, Inc. (“U.S. Exploration”) and sold substantially all of our Gulf of Mexico shelf properties, except for the Main Pass area. (See Acquisition and Divestiture Activities.) These transactions have allowed us to achieve a strategic objective of enhancing our U.S. asset portfolio which has resulted in a company with assets and capabilities that include growing U.S. basins coupled with a significant portfolio of international properties. Our 2006 crude oil and natural gas production volume was 29% higher than 2005 and 75% higher than 2004. Our reserve base is balanced between domestic and international sources at 55% domestic and 45% international. We are now a larger, more diversified company with greater opportunities for both domestic and international growth.

Proved Reserves

As of December 31, 2006, we had estimated proved reserves of 3.2 Tcf of natural gas and 296 MMBbls of crude oil. On a combined basis, these proved reserves were equivalent to 835 MMBoe, of which 55% were located in the U.S. and 45% were located internationally. Our proved reserves have increased 4% since December 31, 2005 and 59% over the past three years. At December 31, 2006, 71% of reserves were proved developed reserves.

1




Proved reserves estimates at December 31, 2006 were as follows:

 

 

December 31, 2006

 

 

 

Proved

 

Proved

 

Total

 

 

 

Developed

 

Undeveloped

 

Proved

 

 

 

Reserves

 

Reserves

 

Reserves

 

U.S.

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

 

1,255

 

 

 

484

 

 

 

1,739

 

 

Crude oil (MMBbls)

 

 

115

 

 

 

55

 

 

 

170

 

 

Total U.S. (MMBoe)

 

 

324

 

 

 

136

 

 

 

460

 

 

International

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

 

850

 

 

 

642

 

 

 

1,492

 

 

Crude oil (MMBbls)

 

 

125

 

 

 

1

 

 

 

126

 

 

Total International (MMBoe)

 

 

267

 

 

 

108

 

 

 

375

 

 

Worldwide

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

 

2,105

 

 

 

1,126

 

 

 

3,231

 

 

Crude oil (MMBbls)

 

 

240

 

 

 

56

 

 

 

296

 

 

Total Worldwide (MMBoe)

 

 

591

 

 

 

244

 

 

 

835

 

 

 

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. For additional information regarding estimates of crude oil and natural gas reserves, including estimates of proved and proved developed reserves, the standardized measure of discounted future net cash flows, and the changes in discounted future net cash flows, see Item 8. Financial Statements and Supplementary Data. – Supplemental Oil and Gas Information (Unaudited) and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates – Reserves.

Engineers in our Houston and Denver offices perform all reserve estimates for our different geographical regions. These reserve estimates are reviewed and approved by senior engineering staff and Division management with final approval by the Senior Vice President with responsibility for corporate reserves. During each of the years 2006, 2005 and 2004, we retained Netherland, Sewell & Associates, Inc. (“NSAI”), independent third-party reserve engineers, to perform reserve audits of proved reserves. A “reserve audit”, as we use the term, is a process involving an independent third-party engineering firm’s extensive visits, collection of any and all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of reserve estimates. Our use of the term “reserve audit” is intended only to refer to the collective application of the procedures which NSAI was engaged to perform. The term “reserve audit” may be defined and used differently by other companies.

The reserve audit for 2006 included a detailed review of 14 of our major international, deepwater and domestic properties, which covered approximately 80% of our total proved reserves. The reserve audit for 2005 included a detailed review of 11 of our major international, deepwater and domestic properties, which covered approximately 72% of our total proved reserves. The reserve audit for 2004 included a detailed review of 11 of our major international, deepwater and domestic properties, which covered approximately 78% of our total proved reserves.

In connection with the 2006 reserve audit, NSAI performed its own estimates of our proved reserves. In order to perform their estimates of proved reserves, NSAI examined our estimates with respect to reserve quantities, future producing rates, future net revenue, and the present value of such future net revenue.

2




NSAI also examined our estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent Securities and Exchange Commission (“SEC”) staff interpretations and guidance. In the conduct of the reserve audit, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of the examination something came to the attention of NSAI which brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until they had satisfactorily resolved their questions relating thereto or had independently verified such information or data. NSAI determined that our estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(2) of Regulation S-X. NSAI issued an unqualified audit opinion on our proved reserves at December 31, 2006, based upon their evaluation. Their opinion concluded that our estimates of proved reserves were, in the aggregate, reasonable.

The properties that NSAI audits include our most significant properties and are chosen by senior engineering staff and Division management with final approval by the Senior Vice President with responsibility for corporate reserves. We usually include all deepwater fields, all international properties that require reports by requirement of the host government, all properties that require sanctioning by our Board of Directors, and other major properties. No significant properties were excluded from the December 31, 2006 reserve audit.

When compared on a field-by-field basis, some of our estimates are greater and some are less than the estimates of NSAI. Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and external estimates are to be expected. On a quantity basis, the NSAI estimates ranged from plus 31,617 MBoe to minus 10,120 MBoe as compared with our estimates. On a percentage basis, the NSAI estimates ranged from 13% above our estimates to 30% below our estimates. Differences between our estimates and those of NSAI are reviewed for accuracy but are not further analyzed unless the aggregate variance is greater than 10%. At December 31, 2006, reserves differences, in the aggregate, were less than 9,243 MBoe, or 1%.

Since January 1, 2006, no crude oil or natural gas reserve information has been filed with, or included in any report to any federal authority or agency other than the SEC and the Energy Information Administration (“EIA”) of the U.S. Department of Energy. We file Form 23, including reserve and other information, with the EIA.

Acquisition and Divestiture Activities

We maintain an ongoing portfolio optimization program. We may engage in acquisitions of additional crude oil or natural gas properties or related assets through either direct acquisitions of the assets or acquisitions of entities owning the assets. We may also divest non-core assets in order to maintain a balanced portfolio with high-quality, core properties.

On July 14, 2006, we sold substantially all of our Gulf of Mexico shelf properties except for the Main Pass area, which continues to undergo repair work after suffering significant hurricane damage in 2004 and 2005. As of March 1, 2006, the effective date of the sale, proved reserves for the assets sold totaled approximately 7 MMBbls of crude oil and 110 Bcf of natural gas. Gulf of Mexico deepwater and Gulf Coast onshore areas remain core areas and are more aligned with our long-term business strategies. See Item 8. Financial Statements and Supplementary Data – Note 3 - Acquisitions and Divestitures.

On March 29, 2006, we acquired U.S. Exploration, a privately held corporation located in Billings, Montana for $412 million plus liabilities assumed. U.S. Exploration’s reserves and production are located

3




in Colorado’s Wattenberg field. This acquisition significantly expands our operations in one of our core areas. Proved reserves of U.S. Exploration at the time of acquisition were approximately 234 Bcfe, of which 38% were proved developed and 55% were natural gas. Proved crude oil and natural gas properties were valued at $413 million and unproved properties were valued at $131 million. See Item 8. Financial Statements and Supplementary Data – Note 3 - Acquisitions and Divestitures.

On May 16, 2005 we acquired Patina for a total purchase price of $4.9 billion. Patina’s long-lived crude oil and natural gas reserves provide a significant inventory of low-risk opportunities that balanced our portfolio. Patina’s proved reserves at the time of acquisition were estimated to be approximately 1.6 Tcfe, of which 72% were proved developed and 67% were natural gas. Proved crude oil and natural gas properties were valued at $2.6 billion and unproved properties were valued at $1.1 billion. See Item 8. Financial Statements and Supplementary Data – Note 3 - Acquisitions and Divestitures.

Crude Oil and Natural Gas Properties and Activities

We search for crude oil and natural gas properties, seek to acquire exploration rights in areas of interest and conduct exploratory activities. These activities include geophysical and geological evaluation and exploratory drilling, where appropriate, on properties for which we have acquired exploration rights. Our properties consist primarily of interests in developed and undeveloped crude oil and natural gas leases. We also own NGL processing plants and pipeline systems.

North America

We have been engaged in exploration, exploitation and development activities throughout onshore North America since 1932 and in the Gulf of Mexico since 1968. The Patina Merger and the acquisition of U.S. Exploration have significantly increased the breadth of our onshore operations, especially in the Rocky Mountain and Mid-continent regions. These two purchases have provided us with a multi-year inventory of exploitation and development opportunities. North America operations accounted for 65% of our 2006 production volumes and 55% of total proved reserves at December 31, 2006. Approximately 62% of the proved reserves are natural gas and 38% are crude oil. Our onshore North America portfolio at December 31, 2006 included 1,416,429 gross developed acres and 1,343,101 gross undeveloped acres. Offshore, in the Gulf of Mexico, we hold interests in 111 blocks. The following discussion includes activities related to U.S. Exploration properties from March 29, 2006 through December 31, 2006.

4




Production volumes and estimates of proved reserves for our significant North American operating areas were as follows:

 

 

Year Ended December 31, 2006

 

December 31, 2006

 

 

 

Production Volumes

 

Proved Reserves

 

 

 

Natural Gas

 

Crude Oil

 

Total

 

Natural Gas

 

Crude Oil

 

Total

 

 

 

(MMcf)

 

(MBbls)

 

(MBoe)

 

(Bcf)

 

(MMBbls)

 

(MMBoe)

 

Northern Region

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Rocky Mountains:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Wattenberg

 

 

58,324

 

 

 

4,116

 

 

 

13,837

 

 

 

899

 

 

 

77

 

 

 

227

 

 

Other

 

 

20,001

 

 

 

51

 

 

 

3,385

 

 

 

305

 

 

 

1

 

 

 

52

 

 

Western Mid-continent

 

 

29,347

 

 

 

377

 

 

 

5,268

 

 

 

340

 

 

 

3

 

 

 

59

 

 

Total

 

 

107,672

 

 

 

4,544

 

 

 

22,490

 

 

 

1,544

 

 

 

81

 

 

 

338

 

 

Southern Region

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deepwater

 

 

17,195

 

 

 

6,417

 

 

 

9,283

 

 

 

77

 

 

 

22

 

 

 

35

 

 

Gulf Coast onshore

 

 

19,188

 

 

 

1,356

 

 

 

4,554

 

 

 

88

 

 

 

14

 

 

 

29

 

 

Gulf of Mexico shelf

 

 

18,787

 

 

 

1,370

 

 

 

4,501

 

 

 

13

 

 

 

14

 

 

 

16

 

 

Eastern Mid-continent

 

 

2,033

 

 

 

3,028

 

 

 

3,367

 

 

 

17

 

 

 

39

 

 

 

42

 

 

Total

 

 

57,203

 

 

 

12,171

 

 

 

21,705

 

 

 

195

 

 

 

89

 

 

 

122

 

 

Total North America

 

 

164,875

 

 

 

16,715

 

 

 

44,195

 

 

 

1,739

 

 

 

170

 

 

 

460

 

 

 

Northern Region—The Northern region includes our operations in the Rocky Mountain area as well as activities in the western Mid-continent area. The Rocky Mountain area includes the D-J (Wattenberg field), San Juan, Wind River, and Piceance Basins, as well as the Niobrara, Bowdoin and Siberia Ridge fields. The addition of Patina and U.S. Exploration assets, particularly in the Wattenberg field, combined with our legacy operations in the Bowdoin field, the Niobrara trend, the Wind River Basin and Piceance Basin have made the Rocky Mountains one of our core operating areas. In the western Mid-continent area (the Texas Panhandle and parts of Oklahoma, Kansas, Arkansas, and Alabama), the area of greatest activity continues to be the Granite Wash development in the Texas Panhandle, where we are continuing with multi-well programs in the Buffalo Wallow and Billy Rose fields. In 2006, we drilled or participated in 649 gross wells in the Northern region. We also performed or participated in 706 deepening, refrac and recompletion projects in this region. Activity in the Northern region, excluding the acquisition of U.S. Exploration, was responsible for 80% of our 2006 company-wide proved reserves additions. We are currently running 13 drilling rigs and 33 completion/workover units. We plan to invest approximately $753 million, or 71% of budgeted domestic capital, on approximately 1,900 projects in the Northern region during 2007.

Wattenberg Field—The Wattenberg field is the most active field in the Northern region. In 2006, daily production from this field averaged 160 MMcf per day and 11 MBbls per day and accounted for 31% of total domestic production volumes. Wattenberg field proved reserves accounted for 49% of domestic proved reserves at December 31, 2006. At December 31, 2006, we had working interests in approximately 4,600 gross (4,089 net) producing crude oil and natural gas wells in the Wattenberg field.

We acquired working interests in the Wattenberg field through the Patina Merger and acquisition of U.S. Exploration. Located in the D-J Basin of north central Colorado, the Wattenberg field provides us with a substantial future project inventory. One of the most attractive features of the field is the presence of multiple productive formations. In a section 4,500 feet thick, there may be up to eight potentially productive formations. Three of the formations, the Codell, Niobrara and J-Sand, are considered “blanket” zones in the area of our holdings, while others, such as the D-Sand, Dakota and the shallower Shannon, Sussex and Parkman, are more localized. While these zones may be present, any particular property’s productivity is dependent on the reservoir properties peculiar to its location. Such productivity may be uneconomic. Our operated working interest at December 31, 2006 was approximately 97%.

5




Drilling in the Wattenberg field is considered lower risk from the perspective of finding crude oil and natural gas reserves, with 100% of the wells drilled in 2006 encountering sufficient quantities of reserves to be completed as economic producers. In May 1998, the Colorado Oil and Gas Conservation Commission (“COGCC”) adopted the “Greater Wattenberg Area Special Well Location Rule 318A” which allows all formations in the Wattenberg field to be drilled, produced and commingled from any or all of ten “potential drilling locations” on a 320-acre parcel. A “commingled” well is one which produces crude oil from two or more formations or zones through a common string of casing and tubing. In December 2005, the COGCC amended Rule 318A providing for an effective well density of one well per 20 acres in a designated portion of the Greater Wattenberg Area to more effectively drain the reservoir. The amendment applies only to the Niobrara, Codell and J-Sand formations and became effective in March 2006.

We are currently running seven drilling rigs and 26 completion units in the Wattenberg field. Our current field activities are focused primarily on the development of J-Sand and Codell reserves through drilling new wells or deepening within existing wellbores, recompleting the Codell formation within existing J-Sand wells, refracing or trifracing existing Codell wells and refracing or recompleting the Niobrara formation within existing Codell wells. A refrac consists of the restimulation of a producing formation within an existing wellbore to enhance production and add incremental reserves. These projects and continued success with our production enhancement program, along with the U.S. Exploration acquisition, allowed us to increase production and add proved reserves to what is considered a mature field. During 2006, we added approximately 223 Bcfe of proved reserves in the Wattenberg field, approximately 63% of which was natural gas, and grew production from an average of 124 MMcfe per day for 2005 to 227 MMcfe per day for 2006.

During 2006, we drilled or participated in 48 wells and deepened nine wells to the J-Sand formation in the Wattenberg field. We plan to drill or deepen approximately 107 wells to the J-Sand in 2007.

We performed or participated in 179 Codell refracs in the Wattenberg field during 2006. We plan to perform approximately 46 Codell refrac projects in 2007.

We performed or participated in 160 Codell trifracs in the Wattenberg field during 2006. The trifrac program, which is effectively a refrac of a refrac, continues to have encouraging results. We plan to perform approximately 150 trifracs in 2007.

We performed or participated in 294 Niobrara recompletions in the Wattenberg field during 2006. We plan to perform approximately 554 Niobrara projects in 2007.

We also performed or participated in 38 Codell recompletions and drilled or participated in 259 Codell wells in the D-J Basin in 2006. We plan to drill or participate in 513 Codell wells and 30 Codell recompletions in 2007.

During 2006, numerous projects, including well workovers, reactivations, and commingling of zones, were performed. These projects, combined with the new drills, deepenings and refracs, were an integral part of the 2006 Wattenberg field development program. We had a significant inventory of these projects at year-end 2006.

Other Rocky Mountain areas include:

Piceance Basin—The Piceance Basin in western Colorado is another rapidly growing area for us. We have a 9,258-acre (gross) position and are currently running two drilling rigs and one completion unit. We drilled or participated in 49 development wells during 2006, all of which were successful. Our 2006 activity resulted in the addition of 77 Bcfe of proved reserves. Average daily production was 7.5 MMcfe per day in 2006. We plan to drill 74 wells during 2007. Our working interest at December 31, 2006 was approximately 89%.

6




San Juan Basin—The San Juan Basin is located in northwestern New Mexico and southwestern Colorado. During 2006 we drilled or participated in 12 development wells, all of which were successful. Our operated working interest at December 31, 2006 was approximately 80%.

Niobrara Trend—The Niobrara trend is located in eastern Colorado and extends into Kansas and Nebraska. We drilled or participated in 99 development wells with a 91% success rate during 2006. The wells drilled included 20 commitment wells drilled pursuant to an acreage earning agreement with Teton Energy Corporation. Under the terms of the agreement, we earned a 75% working interest in approximately 184,000 acres in the D-J Basin by drilling the commitment wells. Going forward, we will split all costs associated with future drilling according to each party’s working interest. The acreage included in this agreement is a potential eastward extension of the Niobrara producing trend in Yuma County, Colorado. We plan to drill 150 wells in the Niobrara Trend in 2007, including 90 on the Teton acreage. Our overall operated working interest in the Niobrara Trend at December 31, 2006 was approximately 96%.

Bowdoin Field—The Bowdoin field is located in north central Montana. During 2006, we drilled or participated in 25 development wells, all of which were successful. We plan to drill 25 new wells and recomplete 150 wells during 2007. Our operated working interest at December 31, 2006 was approximately 65%.

Wind River Basin—At Iron Horse in the Wind River Basin located in central Wyoming, we drilled or participated in six wells in 2006. We plan to drill eight wells during 2007. Our operated working interest at December 31, 2006 was approximately 57%.

Western Mid-continent areas include:

Buffalo Wallow—A significant area of activity in our Northern region is the Buffalo Wallow field, located in the Texas Panhandle. The primary producing horizons, which generally produce natural gas, are comprised of various intervals in the Granite Wash sequence at approximately 11,000 feet. The productive intervals include a series of stratigraphically trapped sands with an average gross interval of 700 feet. The field has historically been developed on 40-acre spacing. In late 2004, the Texas Railroad Commission approved down-spacing of the field to allow development on 20-acre locations. We drilled or participated in 98 development wells in the Buffalo Wallow field in 2006, all of which were successful. Our 2006 activity resulted in the addition of 53 Bcfe of proved reserves. We plan to drill 60 wells during 2007. Our operated working interest at December 31, 2006 was approximately 85%.

Billy Rose—The Billy Rose field is also located in the Texas Panhandle. During 2006, we drilled or participated in 18 development wells, all of which were successful. We plan to drill 12 wells during 2007. Our operated working interest at December 31, 2006 was approximately 85%.

Southern RegionThe Southern region includes the Gulf Coast onshore, West and East Texas, Louisiana, and the deepwater Gulf of Mexico, as well as the eastern Mid-continent area (Oklahoma, Kansas, Illinois and Indiana). The Gulf Coast and deepwater Gulf of Mexico are core domestic operating areas. Activity in the Southern region was responsible for approximately 18% of our 2006 company-wide proved reserves additions. During 2006, we sold essentially all of our Gulf of Mexico shelf properties except for the Main Pass area. The sale of our shelf properties allows us to migrate future investments and growth from the Gulf of Mexico shelf to the nearby onshore Gulf Coast and deepwater Gulf of Mexico which are areas of higher potential. We plan to invest approximately $306 million, or 29% of budgeted domestic capital, in the Southern region during 2007, with approximately 60% in the deepwater Gulf of Mexico, and the remaining equally to the Gulf Coast and the eastern Mid-continent areas.

DeepwaterDuring 2006, we continued to focus on the growth of our deepwater Gulf of Mexico business, bringing three new subsea development projects online between December 2005 and April 2006. Cycle time from project sanction to first production was 19 months or less for each of these three projects.

7




Additionally, we drilled two operated exploration wells and one operated exploration appraisal well. We have committed to an additional 24-month exclusive term for the Ocean Quest deepwater drilling rig owned by Diamond Offshore, and committed to an initial 18-month term for use of the Ensco 8501 dynamically-positioned deepwater rig currently under construction and scheduled for service in 2009.

Three new deepwater developments are on stream. Swordfish (Viosca Knoll Block 917, 961, and 962) is a 2001 deepwater discovery, located in approximately 4,500 feet of water and consisting of three subsea wells tied back via dual flowlines to Anadarko’s Neptune spar in Viosca Knoll Block 826. We are the operator on Swordfish. Swordfish achieved first production December 2005. Ticonderoga (Green Canyon Block 768) is a 2004 deepwater discovery, located in approximately 5,300 feet of water and consisting of 2 subsea wells tied back to Anadarko’s Constitution spar in Green Canyon Block 680. We have a non-operated position in the development. Ticonderoga achieved first production February 2006. Lorien (Green Canyon Block 199) is a 2003 deepwater discovery, located in approximately 2,200 feet of water and consisting of two subsea wells tied back to the Green Canyon 65 platform. We are the operator on Lorien. Lorien achieved first production April 2006.

We had two deepwater discoveries in 2006. Redrock (Mississippi Canyon Block 204 #1) drilled to a total measured depth of 23,365 feet and is located in 3,334 feet of water. The well encountered high quality hydrocarbon pay and is under review to determine commerciality. We are operator for Redrock. Raton (Mississippi Canyon Block 248 #1) drilled to a total measured depth of 20,106 feet and is located in approximately 3,400 feet of water. Plans are to sidetrack and complete this well and begin a subsea tieback to a nearby host during 2007 with anticipated first production in 2008. A second well at Raton (Mississippi Canyon 292 #5) was drilled during 2006 to appraise deeper shows seen in the 248 #1 well. The 292 #5 well was temporarily abandoned and is pending final commercial evaluation. We are operator for Raton.

We were successful in two lease sales during 2006, winning eight new deepwater leases totaling $14.5 million, net, in the Central and Western planning areas, all operated leases. We expanded our deepwater exploration geoscience staff and regional 3D seismic database to help fuel inventory growth through future lease sales. Aggressive expansion of the seismic database will continue during 2007.

Deepwater Gulf of Mexico accounted for 21% of 2006 domestic production volumes and 8% of domestic proved reserves at December 31, 2006.

Gulf Coast OnshoreDuring 2006, we drilled or participated in 56 wells. Of these 56 wells, 13 were in the Noble-operated South Central Robertson Unit located in West Texas, which increased production 432 Bopd from the previous year. Our 2006 activity resulted in the addition of 34 Bcfe of proved reserves. We plan to drill or participate in 36 wells during 2007. The Gulf Coast onshore accounted for 10% of 2006 domestic production volumes and 6% of domestic proved reserves at December 31, 2006.

Gulf of Mexico ShelfThe Gulf of Mexico Shelf accounted for 10% of 2006 domestic production volumes. Substantially all of these non-core assets were sold during 2006.

Eastern Mid-continent areas include:

Central Oklahoma—During 2006, we drilled or participated in 110 wells, 107 of which were successful. We plan to drill 64 wells during 2007.

Illinois/Indiana—We drilled or participated in 31 development wells in 2006, 29 of which were successful. We plan to drill or participate in 43 wells in Illinois in 2007.

Other—During 2006, we drilled or participated in an additional 20 wells in the Southern region including wells drilled in Kansas and other parts of Oklahoma.

Shale PlaysWe continue to selectively increase our acreage position in resource plays, including shale plays. We have accumulated over 186,000 acres in the New Albany, Caney, Fayetteville and Floyd shales.

8




We continue to evaluate three New Albany Shale wells drilled in the Illinois basin. Additional New Albany wells are being considered in the first quarter of 2007 to provide additional data in evaluating project potential.

International

Our international operations are significant to our business, accounting for 35% of consolidated production volumes in 2006, and 45% of total proved reserves at December 31, 2006. International proved reserves are approximately 66% natural gas and 34% crude oil. Operations in Equatorial Guinea, Cameroon, Ecuador and China are conducted in accordance with the terms of production sharing contracts.

International production volumes and estimates of proved reserves were as follows:

 

 

Year Ended December 31, 2006

 

December 31, 2006

 

 

 

Production Volumes

 

Proved Reserves

 

 

 

Natural Gas

 

Crude Oil

 

Total

 

Natural Gas

 

Crude Oil

 

Total

 

 

 

(MMcf)

 

(MBbls)

 

(MBoe)

 

(Bcf)

 

(MMBbls)

 

(MMBoe)

 

International

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

West Africa

 

 

16,579

 

 

 

6,519

 

 

 

9,282

 

 

 

945

 

 

 

90

 

 

 

248

 

 

North Sea

 

 

2,967

 

 

 

1,357

 

 

 

1,852

 

 

 

19

 

 

 

19

 

 

 

22

 

 

Israel

 

 

33,906

 

 

 

 

 

 

5,651

 

 

 

360

 

 

 

 

 

 

60

 

 

Ecuador

 

 

8,933

 

 

 

 

 

 

1,489

 

 

 

168

 

 

 

 

 

 

28

 

 

China

 

 

 

 

 

1,539

 

 

 

1,539

 

 

 

 

 

 

9

 

 

 

9

 

 

Argentina

 

 

108

 

 

 

1,213

 

 

 

1,231

 

 

 

 

 

 

8

 

 

 

8

 

 

Total consolidated

 

 

62,493

 

 

 

10,628

 

 

 

21,044

 

 

 

1,492

 

 

 

126

 

 

 

375

 

 

Equity investees:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Condensate (MBbls)

 

 

 

 

 

634

 

 

 

634

 

 

 

 

 

 

 

 

 

 

 

 

 

 

LPG (MBbls)

 

 

 

 

 

2,297

 

 

 

2,297

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

62,493

 

 

 

13,559

 

 

 

23,975

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Equity investee share of methanol sales (Kgal)

 

 

 

 

 

 

 

 

 

 

109,942

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

West Africa (Equatorial Guinea and Cameroon)—Our operations in Equatorial Guinea accounted for 51% of 2006 international production volumes and 66% of international proved reserves at December 31, 2006. At December 31, 2006, we held 45,376 gross developed acres and 850,395 gross undeveloped acres in Equatorial Guinea and 1,125,000 gross undeveloped acres in Cameroon.

We began investing in Equatorial Guinea in the early 1990’s. Activities center around our 34% working interest in the offshore Alba field, which is one of our most significant assets. Operations include the Alba field and related methanol plant (located on Bioko Island), onshore LPG processing plant, and condensate production facilities. With the completion of expansion projects (Phase 2A and 2B), the current condensate capacity is 21,000 Bpd, net to our interest, and the current LPG capacity is 5,600 Bpd, net to our interest. The methanol plant was originally designed to produce commercial grade methanol at a rate of 2,500 MTpd. As a result of various upgrade efforts, the plant is now capable of producing up to 3,000 MTpd.

We sell our share of natural gas production from the Alba field to the LPG plant and the methanol plant. The LPG plant is owned by Alba Plant LLC, in which we have a 28% interest, accounted for by the equity method. The LPG plant purchases natural gas from the Alba field under an annual contract. The methanol plant is owned by Atlantic Methanol Production Company, LLC (“AMPCO”), in which we have a 45% interest accounted for by the equity method. The methanol plant purchases natural gas from the Alba field

9




under a contract that runs through 2026. AMPCO subsequently markets the produced methanol to domestic and international customers. In addition, we, along with Marathon Oil Corporation (our Alba field partner) and GEPetrol (the national oil company of Equatorial Guinea), have entered into a natural gas sales contract with an LNG plant currently under construction. The contract runs through 2023. The LNG plant is expected to begin production in 2007. We have no ownership interest in the LNG plant. We sell our share of condensate produced in the Alba field and from the LPG plant under short-term contracts at market-based prices. We have a direct ownership interest of 34% in the condensate production facilities.

In 2005, we expanded our activities in Equatorial Guinea with exploration activities in Blocks O and I (45% and 40% working interest, respectively) on which we are the technical operator. In October 2005, we announced a discovery on Block O with successful test results from the O-1 (“Belinda”) exploration well, and during 2006, we continued exploration work on Blocks O and I. We have contracted a rig and expect to begin a drilling program on these blocks, consisting of four wells, during 2007, with drilling scheduled to begin on Block O.

Effective November 2006, the government of Equatorial Guinea enacted a new hydrocarbons law (the “2006 Hydrocarbons Law”) governing petroleum operations in Equatorial Guinea. The governmental agency responsible for the energy industry was given the authority to renegotiate any contract for the purpose of adapting any terms and conditions that are inconsistent with the new law. At this time we are uncertain what economic impact this law will have on our operations in Equatorial Guinea.

During 2006, we acquired a 50% participating interest in the PH-77 license, offshore the Republic of Cameroon, on which we are the operator. We expect to drill one exploration well on this acreage in 2007.

We plan to invest approximately $145 million, or 51% of budgeted international capital, in West Africa in 2007.

Israel—Our operations in Israel accounted for 24% of 2006 international production volumes and 16% of international proved reserves at December 31, 2006. At December 31, 2006, we held 123,552 gross developed acres and 468,264 gross undeveloped acres located about 20 miles offshore Israel in water depths ranging from 700 feet to 5,000 feet. Our exploration agreement in Israel covers three licenses and two leases and we are the operator.

We have been operating in the Mediterranean Sea, offshore Israel, since 1998, and our 47% working interest in the Mari-B field is one of our core international assets. The Mari-B field is the first offshore natural gas production facility in the State of Israel. Natural gas sales began in 2004 and have been increasing steadily as the Israel natural gas infrastructure has developed. The Israel Electric Corporation Limited (IEC) is our largest purchaser, and sales of natural gas to the Reading power plant in Tel Aviv commenced second quarter 2006. Sales to the Bazan Oil Refinery also began in 2005. Our 2006 gas production volume (93 MMcfpd) was 40% higher than 2005 and almost double 2004 production volume. Onshore pipeline construction is underway, which should allow the IEC power plants at Gezer and Hagit, along with the Delek IPP and associated desalinization plant, and a paper mill to consume gas by the end of 2007.

During 2007 we will complete construction of a permanent onshore receiving terminal for distribution of natural gas from the Mari-B field to purchasers. Currently, we are drilling an additional well in the Mari-B field (Mari-B #7) to further enhance field deliverability. In 2006, we acquired a 33% participating interest in additional exploration acreage offshore northern Israel. We are in the process of securing a rig and intend to drill one exploration well on this acreage in 2007.

North Sea—Our operations in the North Sea (the Netherlands, Norway and the UK) accounted for 8% of 2006 international production volumes and 6% of international proved reserves at December 31, 2006. At December 31, 2006, we held 42,822 gross developed acres and 574,293 gross undeveloped acres.

10




Our operations in the North Sea comprise another core international asset, and we have been conducting business there since 1996. We have working interests in 17 licenses with working interests ranging from 7% to 100% and are the operator of three blocks. During 2006 we continued to make progress on the non-operated Dumbarton development (30% working interest) in Blocks 15/20a and 15/20b in the UK sector of the North Sea. Dumbarton is a re-development of the Donan Field and is located in 140 meters of water, 225 kilometers northeast of Aberdeen, Scotland. Development included the drilling of six development wells in 2006 and subsea tie-back to the GP III, a floating production, storage and offloading vessel in which we own a 30% interest. First production commenced in January 2007.

In 2007, in addition to bringing the Dumbarton development on production, exploration efforts will continue as we and our partners finish an appraisal well on the Flyndre Block (22.5% working interest) and begin exploration efforts at Selkirk (30.5% working interest). We plan to invest approximately $73 million, or approximately 5% of budgeted capital, in the North Sea during 2007.

In January 2007, we were successful in obtaining a 40% participating interest in Norwegian License PL 406 and a 20% participating interest in Norwegian License PL 407. Combined, these license areas cover portions of 11 offshore Norway blocks encompassing approximately 1,640 square kilometers. We are establishing an office in Norway and will begin working with the operator of each license area to further study this acreage.

Ecuador—Our operations in Ecuador accounted for 6% of 2006 international production volumes and 7% of international proved reserves at December 31, 2006. The concession covers 12,355 gross developed acres and 851,771 gross undeveloped acres.

We have been operating in Ecuador since 1996. We are currently utilizing the natural gas from the Amistad field (offshore Ecuador) to generate electricity through a 100%-owned natural gas-fired power plant, located near the city of Machala. The Machala power plant, which began operating in 2002, is a single cycle generator with a capacity of 130 MW from twin turbines. It is the only natural gas-fired commercial power generator in Ecuador and currently one of the lowest cost producers of thermal power in the country. The Machala power plant connects to the Amistad field via a 40-mile pipeline. During 2006, the power production totaled 865,983 MW.

China—Our operations in China accounted for 6% of 2006 international production volumes and 2% of international proved reserves at December 31, 2006. At December 31, 2006, we held 7,413 gross developed acres and no undeveloped acres in China.

We have been engaged in exploration and development activities in China since 1996. We are operator of the Cheng Dao Xi field (57% working interest), which is located in the shallow water of the southern Bohai Bay. Production began in 2003. During 2006, we completed two additional development wells which are now contributing to production and added almost 2 MMBbls in proved reserves. Our share of crude oil production is sold into the local Chinese market pursuant to a long-term contract at market-based prices.

In 2007 we will continue to work with our Chinese partner (Shengli) to obtain governmental approval of the Supplemental Development Plan, designed to further develop the Cheng Dao Xi field through additional drilling and facilities construction.

Argentina—Our operations in Argentina accounted for 5% of 2006 international production volumes and 2% of international proved reserves at December 31, 2006. At December 31, 2006, we held 113,325 gross developed acres and no undeveloped acres in Argentina.

We have conducted business in Argentina since 1996. Our producing properties are located in southern Argentina in the El Tordillo field (13% working interest), which is characterized by secondary recovery crude oil production. During 2006, we participated in the drilling of 58 gross (7.6 net) development wells in the El Tordillo field and plan to continue development drilling in 2007.

11




Suriname—Suriname, a country located on the northern coast of South America, represents a new exploration project for us. In 2005 we entered into a participation agreement on Block 30 (30% working interest). Block 30 (non-operated) covers approximately 4.6 million acres with two-thirds of the block in water depth greater than 600 feet. A seismic program was completed in 2006 and interpretation work is currently underway.

Production Volumes, Price and Cost Data—Production volumes, price and cost data for continuing operations are as follows:

 

 

 

 

 

 

 

 

 

 

Average

 

 

 

Production Volumes (1)

 

Average Sales Price

 

Production Cost

 

 

 

Natural Gas

 

Crude Oil

 

Natural Gas

 

Crude Oil

 

 

 

 

 

MMcf

 

MBbls

 

Per Mcf (2)

 

Per Bbl (2)

 

Per BOE (3)

 

Year Ended December 31, 2006

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 

164,875

 

 

 

16,715

 

 

 

$

6.61

 

 

 

$

50.68

 

 

 

$

8.12

 

 

West Africa (4)

 

 

16,579

 

 

 

6,519

 

 

 

0.37

 

 

 

62.51

 

 

 

2.86

 

 

North Sea

 

 

2,967

 

 

 

1,357

 

 

 

8.00

 

 

 

67.43

 

 

 

10.08

 

 

Israel

 

 

33,906

 

 

 

 

 

 

2.72

 

 

 

 

 

 

1.60

 

 

Other International (5)

 

 

9,041

 

 

 

2,752

 

 

 

0.96

 

 

 

52.05

 

 

 

9.74

 

 

Total Consolidated Operations

 

 

227,368

 

 

 

27,343

 

 

 

5.55

 

 

 

54.47

 

 

 

6.97

 

 

Equity Investee (6)

 

 

 

 

 

2,931

 

 

 

 

 

 

45.83

 

 

 

 

 

Total

 

 

227,368

 

 

 

30,274

 

 

 

$

5.55

 

 

 

$

53.64

 

 

 

 

 

 

Year Ended December 31, 2005

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 

125,543

 

 

 

9,468

 

 

 

$

7.43

 

 

 

$

46.67

 

 

 

$

7.39

 

 

West Africa (4)

 

 

23,938

 

 

 

6,492

 

 

 

0.25

 

 

 

42.51

 

 

 

2.93

 

 

North Sea

 

 

3,394

 

 

 

1,964

 

 

 

5.93

 

 

 

52.68

 

 

 

7.54

 

 

Israel

 

 

24,228

 

 

 

 

 

 

2.68

 

 

 

 

 

 

2.11

 

 

Other International (5)

 

 

8,389

 

 

 

2,866

 

 

 

1.10

 

 

 

42.37

 

 

 

7.15

 

 

Total Consolidated Operations

 

 

185,492

 

 

 

20,790

 

 

 

5.78

 

 

 

45.35

 

 

 

6.06

 

 

Equity Investee (6)

 

 

 

 

 

1,183

 

 

 

 

 

 

43.43

 

 

 

 

 

Total

 

 

185,492

 

 

 

21,973

 

 

 

$

5.78

 

 

 

$

45.25

 

 

 

 

 

 

Year Ended December 31, 2004

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 

88,077

 

 

 

7,951

 

 

 

$

6.03

 

 

 

$

32.64

 

 

 

$

5.84

 

 

West Africa (4)

 

 

16,747

 

 

 

3,364

 

 

 

0.25

 

 

 

38.16

 

 

 

3.38

 

 

North Sea

 

 

4,130

 

 

 

2,459

 

 

 

4.73

 

 

 

38.90

 

 

 

6.13

 

 

Israel

 

 

17,573

 

 

 

 

 

 

2.78

 

 

 

 

 

 

2.46

 

 

Other International (5)

 

 

7,782

 

 

 

2,506

 

 

 

0.75

 

 

 

31.06

 

 

 

5.67

 

 

Total Consolidated Operations

 

 

134,309

 

 

 

16,280

 

 

 

4.76

 

 

 

34.48

 

 

 

5.20

 

 

Equity Investee (6)

 

 

 

 

 

327

 

 

 

 

 

 

32.01

 

 

 

 

 

Total

 

 

134,309

 

 

 

16,607

 

 

 

$

4.76

 

 

 

$

34.44

 

 

 

$

 

 

 

(1)                Includes effect of crude oil sales in excess of (less than) volumes produced of 195 MBbls in Equatorial Guinea, (99) MBbls in the North Sea and 18 MBbls in other international in 2006. The variance between production from the field and  sales volumes is attributable to the timing of liquid hydrocarbon tanker liftings.

(2)                Average natural gas sales prices for the U.S. reflect reductions of $0.25 per Mcf (2006), $0.77 per Mcf (2005) and $0.08 per Mcf (2004) from hedging activities. Average crude oil sales prices for the U.S. reflect reductions of $11.41 per Bbl (2006), $8.03 per Bbl (2005) and $3.05 per Bbl (2004) from

12




hedging activities. Average crude oil sales prices for Equatorial Guinea reflect a reduction of $9.93 (2005) from hedging activities.

(3)                Average production costs include oil and gas operating costs, workover and repair expense, production and ad valorem taxes, and transportation expense.

(4)                Natural gas in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant through 2026 and annually to an LPG plant. Sales from the Alba field to these plants are based on a BTU equivalent and then converted to a dry gas equivalent volume. Both of these plants are owned by affiliated entities accounted for under the equity method of accounting. The volumes produced by the LPG plant are included in the crude oil information. For 2006, the price on an Mcf basis has been adjusted to reflect the Btu content of gas sales.

(5)                Other International natural gas production volumes include Ecuador and Argentina. Although Ecuador natural gas production volumes are included in Other International production, they are excluded from average natural gas sales prices. The natural gas-to-power project in Ecuador is 100% owned by us, and intercompany natural gas sales are eliminated. Natural gas production volumes associated with the gas-to-power project were 8,933 MMcf for 2006, 8,320 MMcf for 2005, and 7,640 MMcf for 2004. Other International oil production includes China and Argentina.

(6)                Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. LPG volumes were 6,294 Bopd, 2,328 Bopd, and 706 Bopd for 2006, 2005, and 2004, respectively.

Revenues from sales of crude oil and natural gas and from gathering, marketing and processing have accounted for 90% or more of consolidated revenues for each of the last three fiscal years.

At December 31, 2006, we operated properties accounting for approximately 66% of our total production. Being the operator of a property improves our ability to directly influence production levels and the timing of projects, while also enhancing our control over operating expenses and capital expenditures.

Productive Wells—The number of productive crude oil and natural gas wells in which we held an interest as of December 31, 2006 is as follows:

 

 

Crude Oil Wells

 

Natural Gas Wells

 

Total

 

 

 

Gross

 

Net

 

  Gross  

 

    Net    

 

Gross

 

Net

 

United States—Onshore

 

 

7,326

 

 

5,635.7

 

 

4,324

 

 

 

2,904.2

 

 

11,650

 

8,539.9

 

United States—Offshore

 

 

110

 

 

47.5

 

 

9

 

 

 

5.1

 

 

119

 

52.6

 

International

 

 

782

 

 

108.4

 

 

31

 

 

 

12.8

 

 

813

 

121.2

 

Total

 

 

8,218

 

 

5,791.6

 

 

4,364

 

 

 

2,922.1

 

 

12,582

 

8,713.7

 

 

Productive wells are producing wells and wells capable of production. A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. One or more completions in the same borehole are counted as one well in this table.

13




The following table summarizes multiple completions and non-producing wells as of December 31, 2006. Included in non-producing wells are productive wells awaiting additional action, pipeline connections or shut-in for various reasons.

 

 

Crude Oil Wells

 

Natural Gas Wells

 

Total

 

 

 

Gross

 

Net

 

  Gross  

 

    Net    

 

Gross

 

Net

 

Multiple Completions

 

 

8

 

 

5.9

 

 

14

 

 

 

3.6

 

 

 

22

 

 

9.5

 

Non-producing (Shut-in)

 

 

1,921

 

 

1,279.9

 

 

346

 

 

 

257.7

 

 

 

2,267

 

 

1,537.6

 

 

Developed and Undeveloped AcreageThe developed and undeveloped acreage (including both leases and concessions) held at December 31, 2006 was as follows:

 

 

Developed Acreage

 

Undeveloped Acreage

 

 

 

Gross

 

Net

 

Gross

 

Net

 

U.S.:

 

 

 

 

 

 

 

 

 

Onshore

 

1,416,429

 

794,257

 

1,343,010

 

780,622

 

Offshore

 

173,105

 

96,867

 

486,698

 

227,601

 

Total U.S.

 

1,589,534

 

891,124

 

1,829,708

 

1,008,223

 

Israel

 

123,552

 

58,142

 

468,264

 

195,660

 

Argentina

 

113,325

 

15,548

 

 

 

Equatorial Guinea

 

45,376

 

15,727

 

850,395

 

299,428

 

Cameroon

 

 

 

1,125,000

 

562,500

 

Suriname

 

 

 

4,596,160

 

1,378,848

 

Ecuador

 

12,355

 

12,355

 

851,771

 

851,771

 

North Sea (1)

 

42,822

 

3,921

 

574,293

 

243,692

 

China

 

7,413

 

4,225

 

 

 

Total International

 

344,843

 

109,918

 

8,465,883

 

3,531,899

 

Total Worldwide (2)

 

1,934,377

 

1,001,042

 

10,295,591

 

4,540,122

 

 

(1)                The North Sea includes acreage in the UK, the Netherlands and Norway.

(2)                If production is not established, approximately 217,932 gross acres (102,927 net acres), 535,025 gross acres (244,217 net acres), and 375,147 gross acres (152,530 net acres) will expire during 2007, 2008 and 2009, respectively.

Developed acreage is acreage spaced or assignable to productive wells. A gross acre is an acre in which a working interest is owned. A net acre is deemed to exist when the sum of fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas regardless of whether or not such acreage contains proved reserves.

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Drilling ActivityThe results of crude oil and natural gas wells drilled for each of the last three fiscal years were as follows:

 

 

Net Exploratory Wells

 

Net Development Wells

 

 

 

Productive

 

Dry

 

Total

 

Productive

 

Dry

 

Total

 

Year Ended December 31, 2006

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 

6.3

 

 

9.0

 

 

15.3

 

 

 

666.6

 

 

5.5

 

 

672.1

 

 

North Sea

 

 

 

 

0.4

 

 

0.4

 

 

 

1.8

 

 

 

 

1.8

 

 

China

 

 

 

 

 

 

 

 

 

1.1

 

 

 

 

1.1

 

 

Argentina

 

 

 

 

 

 

 

 

 

7.6

 

 

 

 

7.6

 

 

Total

 

 

6.3

 

 

9.4

 

 

15.7

 

 

 

677.1

 

 

5.5

 

 

682.6

 

 

Year Ended December 31, 2005

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 

4.7

 

 

10.7

 

 

15.4

 

 

 

488.1

 

 

25.9

 

 

514.0

 

 

Equatorial Guinea

 

 

 

 

 

 

 

 

 

0.3

 

 

 

 

0.3

 

 

North Sea

 

 

 

 

0.2

 

 

0.2

 

 

 

 

 

 

 

 

 

Argentina

 

 

 

 

 

 

 

 

 

7.7

 

 

 

 

7.7

 

 

Total

 

 

4.7

 

 

10.9

 

 

15.6

 

 

 

496.1

 

 

25.9

 

 

522.0

 

 

Year Ended December 31, 2004

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

U.S.

 

 

10.7

 

 

8.5

 

 

19.2

 

 

 

62.4

 

 

8.7

 

 

71.1

 

 

Equatorial Guinea

 

 

 

 

0.3

 

 

0.3

 

 

 

2.4

 

 

 

 

2.4

 

 

North Sea

 

 

0.3

 

 

0.7

 

 

1.0

 

 

 

0.1

 

 

 

 

0.1

 

 

China

 

 

 

 

 

 

 

 

 

1.7

 

 

 

 

1.7

 

 

Argentina

 

 

 

 

 

 

 

 

 

10.0

 

 

 

 

10.0

 

 

Ecuador

 

 

 

 

 

 

 

 

 

3.0

 

 

 

 

3.0

 

 

Total

 

 

11.0

 

 

9.5

 

 

20.5

 

 

 

79.6

 

 

8.7

 

 

88.3

 

 

 

A productive well is an exploratory or development well that is not a dry hole. A dry hole is an exploratory or development well determined to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as an oil or gas well.

An exploratory well is a well drilled to find and produce crude oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir. A development well, for purposes of the table above and as defined in the rules and regulations of the SEC, is a well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas, or in the case of a dry hole, to the reporting of abandonment to the appropriate agency.

At December 31, 2006, we were drilling or completing 171 gross (143.0 net) development wells and 13 gross (6.7 net) exploration wells. These wells are located onshore in Argentina and North America (Alabama, Colorado, Illinois, Indiana, Kansas, Louisiana, Nebraska, Oklahoma, Texas and Wyoming) and offshore Gulf of Mexico and Israel. The drilling cost of these wells will be approximately $99 million if all are dry and approximately $159 million if all are completed as producing wells.

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Marketing Activities

Natural Gas Marketing

Natural gas produced in the U.S. is sold under short-term or long-term contracts at market-based prices. In Equatorial Guinea and Israel, we sell natural gas to end-users under long-term contracts at negotiated prices. At December 31, 2006, approximately 24% of natural gas production was made pursuant to long-term contracts.

Crude Oil and Condensate Marketing

Crude oil and condensate produced in the U.S. and foreign locations is generally sold under short-term contracts at market-based prices adjusted for location and quality. In China, we sell crude oil into the local market under a long-term contract. Crude oil and condensate are distributed through pipelines and by trucks or tankers to gatherers, transportation companies and end-users.

Noble Energy Marketing, Inc.

We market portions of our domestic natural gas production through Noble Energy Marketing, Inc. (“NEMI”), a wholly-owned subsidiary. NEMI seeks opportunities to enhance the value of our domestic natural gas production by marketing directly to end-users and aggregating natural gas to be sold to natural gas marketers and pipelines. NEMI also engages in the purchase and sale of third-party crude oil and natural gas production. Such third-party production may be purchased from non-operators who own working interests in our wells or from other producers’ properties in which we own no interest. We have a long-term natural gas sales contract with NEMI, whereby we receive an index price for all natural gas sold to NEMI. The contract does not specify scheduled quantities or delivery points and expires on May 31, 2009. We sold approximately 43% of our domestic natural gas production to NEMI in 2006.

Significant Purchaser

Trafigura Beheer B.V. (“Trafigura”) was the largest single non-affiliated purchaser of 2006 production. Trafigura purchased our share of condensate from the Alba field in Equatorial Guinea and a portion of our share of crude oil in Argentina. Sales to Trafigura accounted for 28% of 2006 crude oil sales, or 15% of 2006 total oil and gas sales. Shell Trading (US) Company accounted for 18% of 2006 crude oil sales, or approximately 10% of total oil and gas sales, and purchased a portion of our share of North America crude oil production. No other single non-affiliated purchaser accounted for 10% or more of oil and gas sales in 2006.  We believe that the loss of any one purchaser would not have a material effect on our financial position or results of operations since there are numerous potential purchasers of our production.

Hedging Activities

Commodity prices remained volatile during 2006. Prices for crude oil and natural gas are affected by a variety of factors that are beyond our control. We have used derivative instruments, and expect to do so in the future, to achieve a more predictable cash flow by reducing our exposure to commodity price fluctuations. For additional information, see Item 1A. Risk Factors—Hedging transactions may limit our potential gains, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and Item 8. Financial Statements and Supplementary Data—Note 12 - Derivative Instruments and Hedging Activities.

Regulations

Governmental Regulation

Exploration for, and production and sale of, crude oil and natural gas are extensively regulated at the international, federal, state and local levels. Crude oil and natural gas development and production

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activities are subject to various laws and regulations (and orders of regulatory bodies pursuant thereto) governing a wide variety of matters, including, among others, allowable rates of production, prevention of waste and pollution and protection of the environment. Laws affecting the crude oil and natural gas industry are under constant review for amendment or expansion and frequently increase the regulatory burden on companies. Our ability to economically produce and sell crude oil and natural gas is affected by a number of legal and regulatory factors, including federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations. Many of these governmental bodies have issued rules and regulations that are often difficult and costly to comply with, and that carry substantial penalties for failure to comply. These laws, regulations and orders may restrict the rate of crude oil and natural gas production below the rate that would otherwise exist in the absence of such laws, regulations and orders. The regulatory burden on the crude oil and natural gas industry increases its costs of doing business and consequently affects our profitability.

Environmental Matters

As a developer, owner and operator of crude oil and natural gas properties, we are subject to various federal, state, local and foreign country laws and regulations relating to the discharge of materials into, and the protection of, the environment. We must take into account the cost of complying with environmental regulations in planning, designing, drilling, operating and abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products, water and air pollution control procedures, and the remediation of petroleum-product contamination. Under state and federal laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by us or prior owners or operators in accordance with current laws or otherwise, to suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or cleanups to prevent future contamination. The U.S. Environmental Protection Agency and various state agencies have limited the disposal options for hazardous and non-hazardous wastes. The owner and operator of a site, and persons that treated, disposed of or arranged for the disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original conduct, for the release of a hazardous substance into the environment. The Environmental Protection Agency, state environmental agencies and, in some cases, third parties are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such action. Furthermore, certain wastes generated by our crude oil and natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements. See Item 1A. Risk Factors—We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.

Federal and state occupational safety and health laws require us to organize information about hazardous materials used, released or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards.

Certain state or local laws or regulations and common law may impose liabilities in addition to, or restrictions more stringent than, those described herein.

We have made and will continue to make expenditures in our efforts to comply with environmental requirements. We do not believe that we have, to date, expended material amounts in connection with such activities or that compliance with such requirements will have a material adverse effect upon our capital expenditures, earnings or competitive position. Although such requirements do have a substantial impact upon the crude oil and natural gas industry, they do not appear to affect us any differently, or to any greater or lesser extent, than other companies in the industry.

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Competition

The crude oil and natural gas industry is highly competitive. We encounter competition from other crude oil and natural gas companies in all areas of operations, including the acquisition of seismic and lease rights on crude oil and natural gas properties and for the labor and equipment required for exploration and development of those properties. Our competitors include major integrated crude oil and natural gas companies and numerous independent crude oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well established companies. Such companies may be able to pay more for seismic and lease rights on crude oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See Item 1A. Risk Factors. We face significant competition and many of our competitors have resources in excess of our available resources.

Geographical Data

We have operations throughout the world and manage our operations by country. Information is grouped into five components that are all primarily in the business of crude oil and natural gas exploration, development and production: U.S., West Africa, North Sea, Israel, and Other International, Corporate and Marketing. For more information, see Item 8. Financial Statements and Supplementary Data—Note 15—Geographical Data.

Employees

Our total number of employees increased during the year from 1,171 at December 31, 2005 to 1,243 at December 31, 2006. The 2006 year-end employee count includes 121 foreign nationals working as employees in Ecuador, China, Israel, the UK and Equatorial Guinea.

Offices

Our principal corporate office, including our offices for domestic and international operations, is located at 100 Glenborough Drive, Suite 100, Houston, Texas 77067-3610. We maintain additional offices in Ardmore, Oklahoma and Denver, Colorado and in China, Cameroon, Ecuador, Equatorial Guinea, Israel and the UK.

Title to Properties

We believe that our title to the various interests set forth above is satisfactory and consistent with generally accepted industry standards, subject to exceptions that are not so material as to detract substantially from the value of the interests or materially interfere with their use in our operations. Individual properties may be subject to burdens such as royalty, overriding royalty and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, net profits interest, liens incident to operating agreements and for current taxes, development obligations under crude oil and natural gas leases or capital commitments under production sharing contracts or exploration licenses.

Available Information

Our website address is www.nobleenergyinc.com. Available on this website under “Investor Relations—Investor Relations Menu—SEC Filings,” free of charge, are our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Forms 3, 4 and 5 filed on behalf of directors and

18




officers and amendments to those reports as soon as reasonably practicable after such materials are electronically filed with or furnished to the SEC.

Also posted on our website, and available in print upon request by any stockholder to the Investor Relations Department, are charters for our Audit Committee; Compensation, Benefits and Stock Option Committee; Corporate Governance and Nominating Committee; and Environment, Health and Safety Committee. Copies of the Code of Business Conduct and Ethics, and the Code of Ethics for Chief Executive and Senior Financial Officers (the “Codes”) are also posted on our website under the “Corporate Governance” section. Within the time period required by the SEC and the NYSE, as applicable, we will post on our website any modifications to the Codes and any waivers applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002.

In 2006, we submitted the annual certification of our Chief Executive Officer regarding compliance with the NYSE’s corporate governance listing standards, pursuant to Section 303A.12(a) of the NYSE Listed Company Manual.

Item 1A. Risk Factors.

Crude oil and natural gas prices are volatile and a substantial reduction in these prices could adversely affect our results and the price of our common stock.

Our revenues, operating results and future rate of growth depend highly upon the prices we receive for our crude oil and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. The markets and prices for crude oil and natural gas depend on factors beyond our control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and economic conditions, and other factors, including:

·       worldwide and domestic supplies of crude oil and natural gas;

·       actions taken by foreign oil and gas producing nations;

·       political conditions and events (including instability or armed conflict) in crude oil producing or natural gas producing regions;

·       the level of global crude oil and natural gas inventories;

·       the price and level of foreign imports;

·       the price and availability of alternative fuels;

·       the availability of pipeline capacity;

·       the availability of crude oil transportation and refining capacity;

·       weather conditions;

·       domestic and foreign governmental regulations and taxes; and

·       the overall economic environment.

Significant declines in crude oil and natural gas prices for an extended period may have the following effects on our business:

·       limiting our financial condition, liquidity, ability to finance planned capital expenditures and results of operations;

·       reducing the amount of crude oil and natural gas that we can produce economically;

·       causing us to delay or postpone some of our capital projects;

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·       reducing our revenues, operating income and cash flow;

·       reducing the carrying value of our crude oil and natural gas properties; or

·       limiting our access to sources of capital, such as equity and long-term debt.

Estimates of crude oil and natural gas reserves are not precise.

There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value, including many factors that are beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. The estimates depend on a number of factors and assumptions that may vary considerably from actual results, including:

·       historical production from the area compared with production from other areas;

·       the assumed effects of regulations by governmental agencies;

·       assumptions concerning future crude oil and natural gas prices;

·       future operating costs;

·       severance and excise taxes;

·       development costs; and

·       workover and remedial costs.

For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of those reserves based on risk of recovery and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserve estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates.

Additionally, because some of our reserve estimates are calculated using volumetric analysis, those estimates are less reliable than the estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. In addition, realization or recognition of proved undeveloped reserves will depend on our development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.

Failure to fund continued capital expenditures could adversely affect our properties.

Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, our revolving bank credit facility and debt and equity issuances. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of crude oil and natural gas, and our success in finding, developing and producing new reserves. If revenue were to decrease as a result of lower crude oil and natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves, resulting in a decrease in production over time. If our cash flow from operations is not sufficient to meet our obligations and fund our capital budget, we may not be able to access debt, equity or other methods of financing on an economic basis to meet these requirements. If we are not able to fund our capital expenditures, interests in some properties might be reduced or forfeited as a result.

20




We may be unable to make attractive acquisitions or integrate acquired businesses and/or assets, and any inability to do so may disrupt our business.

One aspect of our business strategy calls for acquisitions of businesses and assets that complement or expand our current business. We cannot provide assurance that we will be able to identify attractive acquisition opportunities. Even if we do identify attractive opportunities, we cannot provide assurance that we will be able to complete the acquisition of them or do so on commercially acceptable terms. Additionally, if we acquire another business, we could have difficulty integrating its operations, systems, management and other personnel and technology with our own. These difficulties could disrupt ongoing business, distract management and employees, increase expenses and adversely affect results of operations. Even if these difficulties could be overcome, we cannot provide assurance that the anticipated benefits of any acquisition would be realized.

Our international operations may be adversely affected by economic and political developments.

We have significant international crude oil and natural gas operations. These operations may be adversely affected by political and economic developments, including the following:

·       war, terrorist acts and civil disturbances, such as currently occurring in Israel and other countries in the Middle East;

·       loss of revenue, property and equipment as a result of actions taken by foreign crude oil and natural gas producing nations, such as expropriation or nationalization of assets and renegotiation, modification or nullification of existing contracts, such as may occur pursuant to the new hydrocarbons law recently enacted by the government of Equatorial Guinea;

·       changes in taxation policies, including the effects of additional oil profits taxes recently imposed by China and Ecuador and the increase in the Supplementary Charge imposed by the UK on North Sea income;

·       laws and policies of the United States and foreign jurisdictions affecting foreign investment, taxation, trade and business conduct;

·       foreign exchange restrictions;

·       international monetary fluctuations; and

·       other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.

We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.

From time to time, in varying degrees, political developments and federal and state laws and regulations affect our operations. In particular, price controls, taxes and other laws relating to the crude oil and natural gas industry, changes in these laws and changes in administrative regulations have affected and in the future could affect crude oil and natural gas production, operations and economics. We cannot predict how agencies or courts will interpret existing laws and regulations or the effect these adoptions and interpretations may have on our business or financial condition.

Our business is subject to laws and regulations promulgated by international, federal, state and local authorities relating to the exploration for, and the development, production and marketing of, crude oil and natural gas, as well as safety matters. Legal requirements are frequently changed and subject to interpretation and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations.

21




Our operations are subject to complex international, federal, state and local environmental laws and regulations including in the case of federal laws, the Comprehensive Environmental Response, Compensation and Liability Act, as amended, the Resource Conservation and Recovery Act, as amended, the Oil Pollution Act of 1990 and the Clean Water Act. Environmental laws and regulations change frequently and the implementation of new, or the modification of existing, laws or regulations could harm us. The discharge of natural gas, crude oil, or other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties and may require us to incur substantial costs of remediation.

Exploration, development and production risks and natural disasters could result in liability exposure or the loss of production and revenues.

Our operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil and natural gas, including:

·       pipeline ruptures and spills;

·       fires;

·       explosions, blowouts and cratering;

·       formations with abnormal pressures;

·       equipment malfunctions;

·       hurricanes; and

·       other natural disasters.

Any of these can result in loss of hydrocarbons, environmental pollution and other damage to our properties or the properties of others.

Exploration and development drilling may not result in commercially productive reserves.

We do not always encounter commercially productive reservoirs through our drilling operations. The wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in those wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that crude oil or natural gas is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry holes or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

·       unexpected drilling conditions;

·       title problems;

·       pressure or irregularities in formations;

·       equipment failures or accidents;

·       adverse weather conditions;

·       compliance with environmental and other governmental requirements; and

·       increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment.

22




The unavailability or high cost of drilling rigs, equipment, supplies, personnel and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment and supplies are substantially greater and their availability may be limited. As a result of increasing levels of exploration and production in response to strong demand for crude oil and natural gas, the demand for oilfield services has risen and the costs of these services are increasing, while the quality of these services may suffer. Additionally, these services may not be available on commercially reasonable terms.

We may not have enough insurance to cover all of the risks we face, which could result in significant financial exposure.

Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters and other unfortuitous events such as blowouts, cratering, fire and explosion and loss of well control which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property and the environment. In accordance with industry practices, we maintain insurance against many, but not all, potential perils confronting our operations and in coverage amounts and deductible levels that we believe to be prudent. Consistent with that profile, our insurance program is structured to provide us financial protection from unfavorable loss severity resulting from damages to or the loss of physical assets or loss of human life, liability claims of third parties, and business interruption  (loss of production) attributed to certain assets. Although we believe the coverages and amounts of insurance carried are adequate, we may not have sufficient protection against some of the risks we face, either because insurance is not available on commercially reasonable terms or actual losses exceed coverage limits. If an event occurs that is not covered by insurance or not fully protected by insured limits, it could have an adverse impact on our financial condition, results of operations and cash flows.

We face significant competition and many of our competitors have resources in excess of our available resources.

We operate in the highly competitive areas of crude oil and natural gas exploration, exploitation, acquisition and production. We face intense competition from a large number of independent, technology-driven companies as well as both major and other independent crude oil and natural gas companies in a number of areas such as:

·       seeking to acquire desirable producing properties or new leases for future exploration;

·       marketing our crude oil and natural gas production; and

·       seeking to acquire the equipment and expertise necessary to operate and develop properties.

Many of our competitors have financial and other resources substantially in excess of those available to us. This highly competitive environment could have an adverse impact on our business.

Our level of indebtedness may limit our financial flexibility.

As of December 31, 2006, we had long-term indebtedness of $1.805 billion, with $1.155 billion drawn under our bank credit facility. Our long-term indebtedness represented 30% of our total book capitalization at December 31, 2006.

Our level of indebtedness affects our operations in several ways, including the following:

·       a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;

·       we may be at a competitive disadvantage as compared to similar companies that have less debt;

·       the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrow additional funds, pay dividends and make certain

23




investments and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

·       additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants;

·       changes in the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing, and lower ratings will increase the interest rate and fees we pay on our revolving credit facility; and

·       we may be more vulnerable to general adverse economic and industry conditions.

We may incur additional debt in order to fund our exploration and development activities. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, crude oil and natural gas prices and financial, business and other factors will affect our operations and our future performance. Many of these factors are beyond our control and we may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings and equity financing may not be available to pay or refinance such debt.

Hedging transactions may limit our potential gains.

In order to manage our exposure to price risks in the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. Our hedges, consisting of a series of contracts, are limited in duration, usually for periods of one to four years. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains if crude oil and natural gas prices rise over the price established by the arrangements. In trying to manage our exposure to price risk, we may end up hedging too much or too little, depending upon how our crude oil or natural gas volumes and our production mix fluctuate in the future. In addition, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected; there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; the counterparties to our future contracts fail to perform under the contracts; or a sudden unexpected event materially impacts crude oil or natural gas prices. We cannot assure that our hedging transactions will reduce the risk or minimize the effect of any decline in crude oil or natural gas prices.

Provisions in our Certificate of Incorporation, Stockholder Rights Plan and Delaware law may inhibit a takeover of us.

Under our Certificate of Incorporation, our Board of Directors is authorized to issue shares of our common or preferred stock without approval of our stockholders. Issuance of these shares could make it more difficult to acquire us without the approval of our Board of Directors as more shares would have to be acquired to gain control. We also have a stockholder rights plan, commonly known as a “poison pill,” that entitles our stockholders to acquire additional shares of our company, or a potential acquirer of our company, at a substantial discount from market value in the event of an attempted takeover without the approval of our Board. Finally, Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. These provisions may deter hostile takeover attempts that could result in an acquisition of us that would have been financially beneficial to our stockholders.

Disclosure Regarding Forward-Looking Statements

This annual report on Form 10-K and the documents incorporated by reference in this report contain forward-looking statements within the meaning of the federal securities laws. Forward-looking statements

24




give our current expectations or forecasts of future events. These forward-looking statements include, among others, the following:

·       our growth strategies;

·       our ability to successfully and economically explore for and develop crude oil and natural gas resources;

·       anticipated trends in our business;

·       our future results of operations;

·       our liquidity and ability to finance our exploration and development activities;

·       market conditions in the oil and gas industry;

·       our ability to make and integrate acquisitions; and

·       the impact of governmental regulation.

Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.

Item 1B.               Unresolved Staff Comments.

None.

Item 3.                        Legal Proceedings.

The ruling by the Colorado Supreme Court in Rogers v. Westerman Farm Co. in July 2001 resulted in uncertainty regarding the deductibility of certain post-production costs from payments to be made to royalty interest owners. In January 2003, Patina was named as a defendant in a lawsuit, which plaintiff sought to certify as a class action, based upon the Rogers ruling alleging that Patina had improperly deducted certain costs in connection with its calculation of royalty payments relating to its Wattenberg field operations and seeking monetary damages (Jack Holman, et al v. Patina Oil & Gas Corporation; Case No. 03-CV-09; District Court, Weld County, Colorado). In May 2004, the plaintiff filed an amended complaint narrowing the class of potential plaintiffs, and thereafter filed a motion seeking to certify the narrowed class as described in the amended complaint. Patina filed an answer to the amended complaint. A motion seeking class certification was heard on September 22, 2005 and granted on October 13, 2005. The Colorado Supreme Court denied our petition for review on November 23, 2005. The matter was set for trial scheduled to commence April 24, 2007. In October 2006, we received service in an additional lawsuit styled Wardell Family Partnership and Glen Droegemueller v. Noble Energy, Inc. et al; Case No. 06-CV-734, District Court, Weld County, Colorado, involving royalty and overriding royalty interest owners in the same field and not a member of the Holman class. The plaintiffs sought to certify the lawsuit as a class action and allegations were made of a similar nature as the Holman lawsuit. An answer was timely filed. Through a mediation process, we and the attorneys representing the Holman class and Wardell putative class have entered into an agreement in principle to settle both cases, and the April 24, 2007 trial date in the Holman lawsuit has been vacated. Such a settlement will have to be approved by the Court with notice of the settlement going to all members of the Holman class and Wardell putative class.

25




The Illinois Environmental Protection Agency (IEPA) issued a notice of violation to Equinox Oil Company on September 25, 2001 alleging violation of air emission and permitting regulations for a facility known as the Zif Gas Plant located near Clay City, Illinois. Elysium Energy, LLC acquired Equinox, and Elysium subsequently was acquired by Patina. The facility is a small amine-processing unit used to treat and remove hydrogen sulfide from natural gas prior to transportation. The notice of violation alleges violation of permit requirements under the Clean Air Act dating back to 1986 as well as excessive hydrogen sulfide emissions at the plant. We are cooperatively working with the IEPA staff to address this matter and have received a permit to allow the installation of remediation equipment. On January 17, 2007, the IEPA re-issued written notices of these alleged violations in the name of Equinox’s successors in interest, and our subsidiaries, Elysium and Noble Energy Production, Inc. No action will be pursued against Equinox. On February 12, 2007, a compliance commitment agreement was submitted to the IEPA wherein Noble Energy Production and Elysium have agreed to pay a late permit fee, install an incineration/caustic scrubber emissions control system at the site, and fund a supplemental environmental project in the nearby community. The matter will remain open until the emissions control system is constructed and operating within IEPA parameters, which is not expected to occur until the third quarter of 2007.

We are involved in various legal proceedings, including the foregoing matters, in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. The company is defending itself vigorously in all such matters and we do not believe that the ultimate disposition of such proceedings will have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Item 4.                        Submission of Matters to a Vote of Security Holders.

There were no matters submitted to a vote of security holders during the fourth quarter of 2006.

Executive Officers

The following table sets forth certain information, as of February 23, 2007, with respect to our executive officers.

Name

 

Age

 

Position

Charles D. Davidson (1)

 

56

 

Chairman of the Board, President, Chief Executive Officer and Director

David L. Stover (2)

 

49

 

Executive Vice President, Chief Operating Officer

Chris Tong (3)

 

50

 

Senior Vice President, Chief Financial Officer

Alan R. Bullington (4)

 

55

 

Senior Vice President, International

Robert K. Burleson (5)

 

49

 

Senior Vice President, Business Administration and President, Noble Energy Marketing, Inc.

Susan M. Cunningham (6)

 

51

 

Senior Vice President, Exploration and Corporate Reserves

Arnold J. Johnson (7)

 

51

 

Vice President, General Counsel and Secretary

 

(1)          Charles D. Davidson was elected President and Chief Executive Officer of Noble Energy in October 2000 and Chairman of the Board in April 2001. Prior to October 2000, he served as President and Chief Executive Officer of Vastar Resources, Inc. from March 1997 to September 2000 (Chairman from April 2000) and was a Vastar Director from March 1994 to September 2000. From

26




September 1993 to March 1997, he served as a Senior Vice President of Vastar. From 1972 to October 1993, he held various positions with ARCO.

(2)          David L. Stover was elected Executive Vice President and Chief Operating Officer of Noble Energy on August 1, 2006 and is currently responsible for all of Noble Energy’s exploration and production activities. Prior thereto, he served as Senior Vice President of Noble Energy responsible for the North America Division from July 2004 through July 2006. He served as Noble Energy’s Vice President of Business Development from December 2002 through June 2004. Previous to his employment with Noble Energy, he was employed by BP America, Inc. as Vice President, Gulf of Mexico Shelf from September 2000 to August 2002. Prior to joining BP, Mr. Stover was employed by Vastar, as Area Manager for Gulf of Mexico Shelf from April 1999 to September 2000, and prior thereto, as Area Manager for Oklahoma/Arklatex from January 1994 to April 1999. From 1979 to 1994, he held various positions with ARCO.

(3)          Chris Tong was elected a Senior Vice President and Chief Financial Officer of Noble Energy on January 1, 2005. Prior to January 1, 2005, he had served as Senior Vice President and Chief Financial Officer for Magnum Hunter Resources, Inc. since August 1997. Prior thereto, he was Senior Vice President of Finance of Tejas Acadian Holding Company and its subsidiaries including Tejas Gas Corp., Acadian Gas Corporation and Transok, Inc., all of which were wholly-owned subsidiaries of Tejas Gas Corporation. Mr. Tong held these positions since August 1996, and served in other treasury positions with Tejas beginning August 1989. From 1980 to 1989, Mr. Tong served in various energy lending capacities with several commercial banking institutions. Prior to his banking career, Mr. Tong served over a year with Superior Oil Company as a Reservoir Engineering Assistant.

(4)          Alan R. Bullington was elected a Vice President of Noble Energy on April 24, 2001 and a Senior Vice President of Noble Energy on July 27, 2004 and is currently responsible for Noble Energy’s International Division. Prior thereto, he served as Vice President and General Manager, International Division of Samedan Oil Corporation beginning January 1, 1998. Prior thereto, he served as Manager-International Operations and Exploration and as Manager-International Operations. Prior to his employment with Samedan in 1990, he held various management positions within the exploration and production division of Texas Eastern Transmission Company.

(5)          Robert K. Burleson was elected a Senior Vice President of Noble Energy on July 27, 2004 and is currently responsible for Business Administration. Prior thereto, he served as Vice President of Noble Energy since April 24, 2001 and has been responsible for Business Administration since April 2002. He has also served as President of Noble Gas Marketing, Inc. (now Noble Energy Marketing, Inc.) since June 14, 1995. Prior thereto, he served as Vice President-Marketing for Noble Gas Marketing since its inception in 1994. Previous to his employment with Noble Energy, he was employed by Reliant Energy as Director of Business Development for its interstate pipeline, Reliant Gas Transmission.

(6)          Susan M. Cunningham was elected a Senior Vice President of Noble Energy in April 2001 and is currently responsible for Exploration and Corporate Reserves. Prior to joining Noble Energy, Ms. Cunningham was Texaco’s Vice President of worldwide exploration from April 2000 to March 2001. From 1997 through 1999, she was employed by Statoil, beginning in 1997 as Exploration Manager for deepwater Gulf of Mexico, appointed a Vice President in 1998 and responsible, in 1999, for Statoil’s West Africa exploration efforts. She joined Amoco in 1980 as a geologist and held various exploration and development positions until 1997.

(7)          Arnold J. Johnson was elected Vice President, General Counsel and Secretary of Noble Energy on February 1, 2004. Prior thereto, he served as Associate General Counsel and Assistant Secretary of Noble Energy from January 2001 through January 2004. Previous to his employment with Noble Energy, he served as Senior Counsel for BP America, Inc. from October 2000 to January 2001. Mr. Johnson held several positions as an attorney for Vastar and ARCO from March 1989 through September 2000, most recently as Assistant General Counsel and Assistant Secretary of Vastar from 1997 through 2000. From 1980 to March 1989, he held various positions with ARCO.

27




PART II

Item 5.                        Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Common Stock. Our common stock, $3.33 1/3 par value, is listed and traded on the NYSE under the symbol “NBL.” The declaration and payment of dividends are at the discretion of our Board of Directors and the amount thereof will depend on our results of operations, financial condition, contractual restrictions, cash requirements, future prospects and other factors deemed relevant by the Board of Directors.

Stock Prices and Dividends by Quarters. The high and low sales price per share of common stock on the NYSE and quarterly dividends paid per share were as follows:

 

 

 

 

 

Dividends

 

 

 

High

 

Low

 

Per Share

 

2005

 

 

 

 

 

 

 

 

 

First quarter

 

$

34.35

 

$

28.06

 

 

$

0.025

 

 

Second quarter

 

39.22

 

31.66

 

 

0.025

 

 

Third quarter

 

47.52

 

38.81

 

 

0.050

 

 

Fourth quarter

 

47.79

 

35.96

 

 

0.050

 

 

2006

 

 

 

 

 

 

 

 

 

First quarter

 

$

46.91

 

$

38.32

 

 

$

0.050

 

 

Second quarter

 

49.33

 

36.14

 

 

0.075

 

 

Third quarter

 

51.71

 

41.80

 

 

0.075

 

 

Fourth quarter

 

54.64

 

41.77

 

 

0.075

 

 

 

On January 23, 2007, the Board of Directors declared a quarterly cash dividend of 7.5 cents per common share, which was paid February 20, 2007 to shareholders of record on February 5, 2007.

Transfer Agent and Registrar. The transfer agent and registrar for the common stock is Wells Fargo Bank, N.A., 161 North Concord Exchange, South St. Paul, MN, 55075.

Stockholders’ Profile. Pursuant to the records of the transfer agent, as of February 12, 2007, the number of holders of record of common stock was 860.

Stock Repurchases. The following table summarizes repurchases of common stock occurring fourth quarter 2006.

 

 

 

 

 

Total Number of

 

Approximate Dollar

 

 

 

 

 

 

 

Shares Purchased

 

Value of Shares that

 

 

 

Total Number

 

Average Price

 

as Part of Publicly

 

May Yet Be

 

 

 

of Shares

 

Paid

 

Announced Plans

 

Purchased Under the

 

Period

 

Purchased

 

Per Share

 

or Programs (1)

 

Plans or Programs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(in thousands)

 

 

10/01/06—10/31/06

 

 

1,664,700

 

 

 

$

46.58

 

 

 

1,664,700

 

 

 

 

 

 

11/01/06—11/30/06

 

 

1,387,300

 

 

 

49.46

 

 

 

1,387,300

 

 

 

 

 

 

12/01/06—12/31/06

 

 

1,164,600

 

 

 

51.35

 

 

 

1,164,600

 

 

 

 

 

 

Total

 

 

4,216,600

 

 

 

$

48.84

 

 

 

4,216,600

 

 

 

$

101,493

 

 

 

(1)                On May 16, 2006, we announced that our Board of Directors had authorized the repurchase of up to $500 million of common stock. We may buy shares from time to time on the open market or in negotiated purchases. The timing and amounts of any repurchases will be at management’s discretion and in accordance with securities laws and other legal requirements. The repurchase program is

28




subject to reevaluation in the event of changes in market conditions. As of February 15, 2007, we had repurchased or committed to repurchase a total of 10.2 million shares with an aggregate cost of  $492 million. The repurchase program is not subject to an expiration date.

Equity Compensation Plan Information. The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2006.

 

 

 

 

 

Number of securities

 

 

 

 

 

 

 

remaining available

 

 

 

 

 

Weighted-average

 

for future issuance

 

 

 

Number of securities

 

exercise price of

 

under equity

 

 

 

to be issued upon

 

outstanding

 

compensation plans

 

 

 

exercise of

 

options, warrants

 

(excluding securities

 

Plan Category

 

outstanding options

 

and rights

 

reflected in column (a))

 

 

 

(a)

 

(b)

 

(c)

 

Equity compensation plans approved by security holders

 

 

6,211,750

 

 

 

$

24.24

 

 

 

5,177,323

 

 

Equity compensation plans not approved by security holders

 

 

 

 

 

 

 

 

 

 

Total

 

 

6,211,750

 

 

 

$

24.24

 

 

 

5,177,323

 

 

 

Stock Performance Graph. This graph shows our cumulative total shareholder return over the five-year period from December 31, 2001, to December 31, 2006. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index and our peer group of companies. At December 31, 2006 (after certain industry consolidation during 2006), our peer group of companies consisted of Anadarko Petroleum Corp., Apache Corp., Chesapeake Energy Corp., Devon Energy Corp., EOG Resources Inc., Forest Oil Corp., Houston Exploration Company, Murphy Oil Corp., Newfield Exploration Company, Pioneer Natural Resources Company, Pogo Producing Company, Stone Energy Corp., and XTO Energy Inc. The comparison assumes $100 was invested on December 31, 2001, in our common stock, in the S&P 500 Index and in our peer group and assumes that all of the dividends were reinvested.

GRAPHIC

29




 

 

12/01

 

12/02

 

12/03

 

12/04

 

12/05

 

12/06

 

Noble Energy, Inc.

 

100.00

 

106.90

 

127.09

 

177.09

 

232.41

 

284.65

 

S & P 500

 

100.00

 

77.90

 

100.24

 

111.15

 

116.61

 

135.03

 

Peer Group

 

100.00

 

104.62

 

135.35

 

176.81

 

272.75

 

265.30

 

 

Item 6.                        Selected Financial Data

 

Year ended December 31,

 

 

 

2006

 

2005 (1)

 

2004

 

2003

 

2002

 

 

 

(in thousands, except share amounts)

 

Revenues and Income:

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

2,940,082

 

$

2,186,723

 

$

1,351,051

 

$

1,008,226

 

$

703,068

 

Income from continuing operations

 

678,428

 

645,720

 

313,850

 

89,892

 

8,095

 

Net income

 

678,428

 

645,720

 

328,710

 

77,992

 

17,652

 

Per Share Data:

 

 

 

 

 

 

 

 

 

 

 

Basic earnings per share—

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

$

3.86

 

$

4.20

 

$

2.69

 

$

0.79

 

$

0.07

 

Net income

 

3.86

 

4.20

 

2.82

 

0.68

 

0.15

 

Cash dividends

 

0.275

 

0.15

 

0.10

 

0.085

 

0.08

 

Year-end stock price

 

49.07

 

40.30

 

30.83

 

22.22

 

18.78

 

Basic weighted average shares outstanding

 

175,707

 

153,773

 

116,550

 

113,928

 

114,392

 

Financial Position:

 

 

 

 

 

 

 

 

 

 

 

Property, plant, and equipment, net

 

$

7,170,757

 

$

6,198,916

 

$

2,180,715

 

$

2,046,909

 

$

2,128,140

 

Goodwill

 

781,290

 

862,868

 

 

 

 

Total assets

 

9,588,625

 

8,878,033

 

3,435,784

 

2,820,800

 

2,730,016

 

Long-term obligations—

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

1,800,810

 

2,030,533

 

880,256

 

776,021

 

977,116

 

Deferred income taxes

 

1,758,452

 

1,201,191

 

180,415

 

161,912

 

201,939

 

Asset retirement obligations

 

127,689

 

278,540

 

175,415

 

101,804

 

 

Derivative instruments

 

328,875

 

757,509

 

9,678

 

7,400

 

337

 

Other deferred credits and noncurrent liabilities

 

274,720

 

279,971

 

69,479

 

72,776

 

69,483

 

Shareholders’ equity

 

4,113,817

 

3,090,144

 

1,459,988

 

1,073,573

 

1,009,386

 

Continuing Operations Information:

 

 

 

 

 

 

 

 

 

 

 

Natural gas production (Mcfpd)

 

622,927

 

508,195

 

366,965

 

336,611

 

341,008

 

Average realized price ($/Mcf) (2)

 

$

5.55

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