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)

(Registrant’s telephone number, including area code)

(281) 872-3100

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

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):

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.

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.

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

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.

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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

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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.

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

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%.

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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%.

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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 Region—The 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.

Deepwater—During 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.

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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 Onshore—During 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 Shelf—The 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 Plays—We 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.

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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:

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

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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.

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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.

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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:

(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

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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:

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.

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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.

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

(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 Activity—The results of crude oil and natural gas wells drilled for each of the last three fiscal years were as follows: