100 Glenborough Drive Suite 100 Houston, TX 77067-3610 nobleenergyinc.com 2 0 0 6 N O B L E E N E R G Y , I N C . A N N U A L R E P O R T ...a balanced company with a simplified business model. In 2006, we completed our transition to a simplified business model based on building a portfolio of high quality and long- lived assets with an inventory of lower risk development projects and an exploration program offering substantial long-term impact. Over the past four years, we have undertaken a number of steps that have led to the realization of the business model envisioned in 2003: • Several major international projects have been completed on time and within budget. • A large portfolio of lower risk, long-lived assets has been added. • The exploration portfolio has been strengthened. • Mature and declining assets have been sold. • Our global asset base is now balanced between International and North America. Going forward, we will pursue a broad array of projects, from lower risk development to high-growth exploration. S R O T C E R I D S R E C I F F O E V I T U C E X E N O I T A M R O F N I E T A R O P R O C CHARLES D. DAVIDSON (4) Chairman of the Board, President and Chief Executive Officer, Noble Energy, Inc. JEFFREY L. BERENSON (2) (3) President and Chief Executive Officer, Berenson & Company MICHAEL A. CAWLEY (1) (3) Trustee, President and Chief Executive Officer, The Samuel Roberts Noble Foundation, Inc. EDWARD F. COX (2) (3) (4) THOMAS J. EDELMAN (4) Partner, law firm of Patterson Belknap Webb & Tyler LLP Former Chairman of the Board and Chief Executive Officer, Patina Oil & Gas Corporation KIRBY L. HEDRICK (2) (3) (4) Former Executive Vice President, Phillips Petroleum Company BRUCE A. SMITH (1) (3) Chairman, President and Chief Executive Officer, Tesoro Corporation WILLIAM T. VAN KLEEF (1) (3) Former Executive Vice President and Chief Operating Officer, Tesoro Corporation COMMITTEE MEMBERSHIP (1) Audit Committee (2) Compensation, Benefits and Stock Options Committee (3) Corporate Governance and Nominating Committee (4) Environment, Health and Safety Committee CHARLES D. DAVIDSON ALAN R. BULLINGTON ROBERT K. BURLESON SUSAN M. CUNNINGHAM ARNOLD J. JOHNSON DAVID L. STOVER CHRIS TONG Chairman of the Board, President, Chief Executive Officer and Director Senior Vice President, International Senior Vice President, Business Administration Senior Vice President, Exploration and Corporate Reserves Vice President, General Counsel and Secretary Executive Vice President and Chief Operating Officer Senior Vice President and Chief Financial Officer ANNUAL MEETING The Annual Meeting of Stockholders of Noble Energy, Inc. will be held on Tuesday, April 24, 2007, at 9:30 a.m., Central Time, at the Company’s headquarters located at 100 Glenborough Drive, Suite 100, Houston, TX 77067-3610. All stockholders are cordially invited to attend. FORM 10-K The Company’s Annual Report on Form 10-K for the year ended December 31, 2006, as filed with the Securities and Exchange Commission, is included in this report. Additional copies are available without charge upon request by writing to the Chief Financial Officer, Noble Energy, Inc., 100 Glenborough Drive, Suite 100, Houston, Texas 77067-3610, via the Company’s Internet website: http://www.nobleenergyinc.com, or via the Securities and Exchange Commission’s Internet website: http://www.sec.gov. FORWARD LOOKING STATEMENT This 2006 Annual Report to stockholders contains forward-looking statements based on expectations, estimates and projections as of the date of this report. 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” in Noble Energy’s Form 10-K included in this report. NOBLE ENERGY, INC. Corporate Headquarters 100 Glenborough Drive Suite 100 Houston, Texas 77067-3610 (281) 872.3100 INVESTOR RELATIONS Greg Panagos Director of Investor Relations and Planning (281) 872.3100 Investor_Relations@nobleenergyinc.com www.nobleenergyinc.com INDEPENDENT PUBLIC ACCOUNTANTS KPMG LLP TRANSFER AGENT AND REGISTRAR Wells Fargo Bank, N. A. Shareowner Services 161 North Concord Exchange South St. Paul, MN 55075-1139 (800) 468.9716 stocktransfer@wellsfargo.com COMMON STOCK LISTED NEW YORK STOCK EXCHANGE Symbol - NBL 6 0 0 2 5 0 0 2 4 0 0 2 3 0 0 2 • Ticonderoga and Lorien commenced production in the deepwater Gulf of Mexico • Signed Niobrara joint venture agreement with Teton Energy Corporation • Sold Gulf of Mexico shelf assets • Commenced common stock repurchase program totaling $500 million • Raton and Redrock discoveries in the deepwater Gulf of Mexico • Agreed to acquire U.S. Exploration Holdings, Inc. with assets in the DJ basin • Acquired 50 percent working interest in the PH-77 license offshore Cameroon • Increased natural gas sales in Israel • Phase 2B liquids expansion project in Equatorial Guinea completed and production commenced • Swordfish commenced production in the deepwater Gulf of Mexico • Belinda discovery on Block ‘O’ offshore Equatorial Guinea • Acquired 30 percent working interest in exploration block offshore Suriname • Sanctioned Dumbarton field development in the North Sea • Commenced natural gas sales in Israel • Announced merger with Patina Oil & Gas Corporation, enhancing U.S. asset portfolio • Ticonderoga discovery and acquisition of additional ownership in Swordfish and Lorien in the deepwater Gulf of Mexico • Signed production contract for Block ‘O’ and farmed into Block ‘I’ offshore Equatorial Guinea • Commenced production from the Cheng Dao Xi field in South Bohai Bay offshore China • First full year of operations at the Machala power plant in Ecuador • Phase 2A condensate expansion project in Equatorial Guinea completed and operations commenced We simplified O U R B U S I N E S S M O D E L F O U N D AT I O N Our simplified business model is built on a portfolio of high quality, long-lived assets. Our largest asset in North America, the Wattenberg field, offers a stable base of long-lived production. Internationally, completed projects in Equatorial Guinea, Israel, China, Ecuador and Argentina will provide low-cost, high rate of return production for years to come. N E A R - T E R M G R O W T H We have a large inventory of high return and lower risk projects offering significant near-term growth. Assets located primarily in the Rocky Mountain and Mid- continent areas of North America, such as the Wattenberg field, Niobrara, the Piceance basin, Buffalo Wallow and Billy Rose, will provide growth for several years. LONG-TERM GROWTH With a broad-based, global exploration portfolio in regions including the deepwater Gulf of Mexico, West Africa, the Middle East and South America, we have exposure to substantial net, risked resource potential that could create a new phase of growth. 2006 PRODUCTION NORTH AMERICA (NORTHERN) NORTH AMERICA (SOUTHERN) WEST AFRICA MIDDLE EAST/EUROPE LATIN AMERICA/FAR EAST 18% 11% 33% 6% 32% In 2003, we relied on short-lived, high decline rate assets for over half of our production. Since then, we have successfully transitioned to a balanced and diversified mix of assets, as reflected in our 2006 production profile. LETTER TO SHAREHOLDERS 2006 was an outstanding year for Noble Energy in terms of both financial and operational results. Our earnings per share was $3.79, and our discretionary cash flow of $2.1 billion was a record for the company. Our strong cash flow and project inventory allowed us to carry out a capital investment program of over $1.8 billion, including acquisitions, while also initiating a $500 million share repurchase program. For the year, our production grew 28 percent to a record of 185,954 barrels oil equivalent per day (Boepd). The results of our investment program allowed us to add new reserves totaling 179 percent of our annual production. At year-end, our reserves totaled a record 835 million barrels oil equivalent (MMBoe). During the year, we significantly enhanced our asset portfolio by divesting of our legacy shallow water Gulf of Mexico assets, adding to our Rocky Mountain portfolio through the acquisition of U.S. Exploration Holdings, Inc. (USX), and expanding our deepwater Gulf of Mexico position. Our unit costs continued to improve resulting in a cost structure that was in the best quartile relative to our peers. Most importantly, our share price grew 22 percent, which led to our total shareholder return being the best in our peer group for the year. Our excellent performance in 2006 can be traced back, in part, to a new business model, which we developed and began implementing in 2003. The foundation of this model was to build a portfolio of high quality and long-lived assets that possessed an inventory of lower-risk development projects. By increasing our investment in these types of projects, we lowered the risk and gained predictability in our near-term production growth. This new model also anticipated a transition of our exploration program towards the pursuit of prospects that had long-term impact for the company. When we adopted this model, our international business was rapidly growing with the development of several high- quality projects. These included our development of a major gas field offshore Israel, a gas-to-power project in Ecuador, the development of a new oil field in the Bohai Bay of China and two phases of expansion of our major property in Equatorial Guinea. With these important projects, our international business has transitioned from a large consumer of cash flow to one that generates substantial free cash. Also at that time, our North American portfolio was still concentrated in the Gulf Coast, both onshore and offshore, which were areas dominated by high decline rate assets. We recognized that future investment opportunities in these areas, in particular in the Gulf of Mexico shelf, were limited, and we needed to enhance our North American portfolio with longer-lived assets that contained an inventory of development projects. The 2005 merger with Patina Oil & Gas Corporation (Patina) brought us the assets and project inventory that we were seeking. With the completion of this merger in mid-2005, we had access to an almost ten-year inventory of high-return development projects in the Mid-continent and Rocky Mountain regions. In addition, Patina’s expertise in developing unconventional natural gas resources allowed us to better exploit some of our legacy assets in the Rockies. At the time of the merger, we had already begun the process of strengthening our exploration portfolio by increasing our investments in the deepwater Gulf of Mexico. This led to several deepwater discoveries including the Lorien, Swordfish and Ticonderoga fields. All three of these new fields began delivering production starting in late 2005 through early 2006, and were significant contributors to our production growth this past year. We also began enhancing our international portfolio of exploration prospects. One 2006 GLOBAL RESERVES 3% 2007 CAPITAL PROGRAM Other Int’l 7% UK/MedSea 45% International North America 55% 11% West Africa International 45% 2% Corporate 55% North America 19% Other Onshore 13% Deepwater 13% Rockies Wattenberg 30% Rockies 13% 30% Wattenberg Deepwater 15% Other Onshore 19% Corporate 2% West Africa 11% UK/MedSea 7% Other Int’l 3% of the most notable areas where we expanded was in West Africa, where we obtained positions in two blocks in Equatorial Guinea. It was on one of these blocks, Block ‘O,’ that we made our Belinda discovery in late 2005. During 2006, we added to our West Africa position by securing additional acreage offshore nearby Cameroon. At the close of 2006, we find that our portfolio of assets has been significantly strengthened from what it was just a few years ago. Our proved reserves are more evenly balanced between domestic and international assets as are our unproven resources. We now have a higher quality portfolio of lower-risk development projects, primarily in the Mid- continent and Rocky Mountain areas of the U.S. Our deepwater exploration portfolio has been expanded, where we added two additional discoveries in 2006 at Redrock and Raton. We have balanced our growth between North America and International with both areas providing near-term growth as well as long-term opportunities. NORTH AMERICA OVERVIEW Our North America operations once again showed substantial growth in 2006. Production was over 121,000 Boepd, up 45 percent from 2005, reflecting a full year’s impact from the Patina assets and the impact of several new deepwater developments. Reserves reached an all-time high of 460 MMBoe, 55 percent of our total reserves, primarily through our organic programs and supplemented by smaller acquisitions. North America operations are organized into two regions: Northern and Southern. The Northern region contains the majority of our North American reserves, almost 75 percent, with our largest single asset company-wide being the Wattenberg field in the DJ basin of Colorado. With thousands of identified projects and a large undeveloped resource potential, Wattenberg is a high quality, long-lived asset acting as an important foundation in our business model. Our Wattenberg assets have also created follow-on opportunities for near-term growth, such as our USX acquisition and our joint venture with Teton Energy Corporation (Teton) in the Eastern DJ basin. In fact, we have completed our initial commitment to drill 20 wells in our joint venture acreage with Teton. Results have been encouraging, and we plan to move forward with additional drilling in 2007 on the 184,000 gross acres covered by the joint venture agreement. The Northern region has a number of other active investment programs that contributed to our growth in 2006, including the Piceance, Wind River and San Juan basins. In the Western Mid-continent, our greatest activity continues to be the Granite Wash development in the Texas Panhandle, where we have several years of locations to be drilled. Our Southern region, which is comprised of the deepwater Gulf of Mexico, the Gulf Coast and Eastern Mid-continent areas, is a significant contributor in terms of resource potential and production. Almost half of our 2006 North America production came from the Southern region, and our deepwater portfolio offers exposure to high impact exploration. In 2006, we streamlined our asset portfolio in the Southern region by selling our mature Gulf of Mexico shelf assets. These assets were experiencing steep decline rates and provided limited growth opportunities for a company of our size. Most of our North America exploration program is in the Southern region, where we added the Raton and Redrock discoveries in 2006. Development plans for those discoveries are currently under review. In 2006, most of our investment program in the Southern region was focused on completing our deepwater developments. All were completed on time and within budget, with Lorien being the latest development starting up as expected in May. For 2007, we see additional development opportunities at Lorien and Ticonderoga. We also expect to drill another two to four deepwater exploration wells in 2007. We continue with active onshore drilling programs in the Gulf Coast, Oklahoma, Kansas and Illinois. INTERNATIONAL OVERVIEW Growth continued in our international operations in 2006, with operating income increasing 36 percent to a record $707 million from $519 million in 2005. Higher commodity prices contributed to increased income, but production also increased to 64,900 Boepd from 62,200 Boepd in 2005. Our largest area of international operations continues to be Equatorial Guinea, where we have an interest in the Alba field. Operations in Equatorial Guinea generated a record $494 million of operating income. We expect to see significant production increases in Equatorial Guinea in 2007, with natural gas sales to a liquefied natural gas facility expected to start mid-year 2007. These sales are expected to average between 13,000 Boepd and 19,000 Boepd for 2007. Prices for incremental natural gas sales from the Alba field will be similar to those we currently receive there. In 2005, we announced a condensate and natural gas discovery at our offshore Belinda exploration well in Block ‘O.’ We have numerous other prospects and leads on Block ‘O’ and the adjacent Block ‘I.’ With six firm and two optional slots reserved on a drill ship in West Africa, we plan an expanded drilling program in 2007 and 2008 to appraise the Belinda discovery and test several other prospects on both blocks. Elsewhere in West Africa, we acquired a 50 percent interest in the PH-77 license offshore Cameroon. Noble Energy will operate PH-77, which covers 1.125 million gross acres off the coast of the Republic of Cameroon. Evaluation work is underway, with the intent of identifying drilling locations for 2007 and 2008. In Israel, our natural gas sales continued to increase in 2006, averaging about 93 million cubic feet per day (MMcfpd), net for the year, a 40 percent increase over 2005. The Israel Electric Corporation, Ltd, our primary customer, continues to convert power plants to burn natural gas, assuring continued growth in demand in 2007 and beyond. In July 2006, we acquired a 33 percent participating interest in two offshore licenses, 308 Michal and 309 Matan. We became the operator for both licenses and plan to drill an exploration well in 2007. In the North Sea, the Dumbarton development was completed and production began in January 2007. Dumbarton is expected to add approximately 9,000 Boepd, net to Noble Energy’s 30 percent interest. In the Bohai Bay of China, production remained strong throughout 2006, averaging over 4,200 Boepd, net. We have also identified additional field development opportunities and are working to gain approval of a major new phase in the development of the field. In South America, our natural gas-to-power project in Ecuador produced a record amount of electricity in 2006, generating approximately 866,000 megawatts of power. We also may drill our first exploration well offshore Suriname in late 2007 or early 2008, where we have a 30 percent interest in Block 30. ANNUAL SALES VOLUMES (MMBoe) ANNUAL DISCRETIONARY CASH FLOW (BILLIONS) 70 60 50 40 30 20 10 0 2.5 2.0 1.5 1.0 0.5 0.0 70 60 50 40 30 20 10 0 $2.5 $2.0 $1.5 $1.0 $0.5 $0.0 02 03 04 05 06 02 03 04 05 06 SUMMARY I hope it is apparent how dramatic Noble Energy’s change has been over these past few years. We believe the business model we have adopted is the best for our company and its shareholders. It takes advantage of the strengths and skills of our employees in continuing to build a high quality portfolio of producing assets and future investment opportunities. Today we believe our foundation is extremely solid, anchored in some of the best natural gas and oil regions in the world. We are pursuing a broad array of development projects that give greater certainty to our near-term growth while focusing our exploration efforts on prospects that can have a material impact on our company for years into the future. Yes – we still have a lot of work to do, but much has been accomplished in the last several years. In a world where demand for energy continues to grow, all of us at Noble Energy realize that we have very important responsibilities to our shareholders, customers, communities, and host countries. Our primary responsibility is to find and develop natural gas and oil as efficiently as possible, while delivering superior returns to our shareholders. We also recognize that in doing this, we must work to minimize the impacts our operations have on the environment while preserving the safety of all who are involved. It also goes, almost without saying, that compliance with laws and regulations is a given. I am proud that our employees take these responsibilities seriously. They have continued to do an outstanding job in carrying out their work with intensity, integrity and a focus on excellence. On behalf of the Board of Directors and all employees of Noble Energy, I want to thank all of our shareholders for their continued confidence and support. CHARLES D. DAVIDSON CHAIRMAN OF THE BOARD PRESIDENT AND CHIEF EXECUTIVE OFFICER O P E R AT I N G & F I N A N C I A L D ATA - 2 0 0 6 A N N U A L R E P O R T OPERATING DATA 2006 2005 2004 2003 2002 Year-End Proved Reserves Natural Gas (MMcf) 3,230,814 3,091,219 1,986,861 1,641,920 1,600,801 Crude Oil (MBbls) 296,090 290,830 193,464 183,219 201,478 Total (MBoe) 834,559 806,033 524,607 456,872 468,278 S A L E S V O L U M E S Natural Gas (Bcf) Crude Oil (MMBbls) [1] Total (MMBoe) AV E R A G E S A L E S P R I C E Natural Gas (per Mcf) Crude Oil (per Bbl) [2] 227.4 185.5 134.3 122.9 124.5 30.3 68.2 22.0 52.9 16.6 39.0 $ $ 5.55 54.47 $ $ 5.78 45.35 $ $ 4.76 34.48 $ $ 13.1 33.6 4.19 27.67 FINANCIAL DATA (In thousands, except per share amounts and ratios) 2006 2005 2004 2003 Revenues Net Income Basic Earnings per Common Share Basic Weighted Average Common Shares $ 2,940,082 $ 2,186,723 $ 1,351,051 $ 1,008,226 $ $ 678,428 3.86 $ $ 645,720 4.20 $ $ 328,710 2.82 $ $ 77,992 0.68 175,707 153,773 116,550 113,928 114,392 Cash Dividend per Common Share 0.28 0.15 0.10 0.09 0.08 Net Cash Provided by Operating Activities $ 1,730,306 $ 1,239,878 Capital Expenditures [3] $ 1,347,116 $ 890,010 $ $ 708,186 628,886 $ $ 602,770 502,073 $ $ 506,955 612,290 Total Assets $ 9,588,625 $ 8,878,033 $ 3,435,784 $ 2,820,800 $ 2,730,016 Long-term Debt, Net of Current Portion $ 1,800,810 $ 2,030,533 $ 880,256 $ 776,021 $ 977,116 Stockholders’ Equity $ 4,133,817 $ 3,090,144 $ 1,459,988 $ 1,073,573 $ 1,009,386 Total Debt-to-Book-Capital Ratio 30% 40% 38% 42% Debt per BOE $ 2.16 $ 2.52 $ 1.68 $ 1.70 $ 49% 2.09 [1] Includes Sales from Equity Investee Liquids in 2006, 2005 and 2004 of 2.9 MMBbls, 1.2 MMBbls and 0.3 MMBbls, respectively. [2] Excludes Equity Investee Liquids Sales Volumes and Prices. [3] Excludes Acquisitions. 10.6 31.4 2.89 24.22 2002 703,068 17,652 0.15 $ $ $ $ $ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One) ## 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 "" 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 (State of incorporation) 100 Glenborough Drive, Suite 100 Houston, Texas (Address of principal executive offices) 73-0785597 (I.R.S. employer identification number) 77067 (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 Common Stock, $3.33-1/3 par value Preferred Stock Purchase Rights Name of each exchange on which registered New York Stock Exchange 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. # Yes " 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. " Yes # 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. # Yes " 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. # 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 # Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Non-accelerated filer " Accelerated filer " " Yes # 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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Strategy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquisition and Divestiture Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Crude Oil and Natural Gas Properties and Activities. . . . . . . . . . . . . . . . . . . . . . . . . . . . Regulations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Geographical Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Offices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Title to Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Available Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Risk Factors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Unresolved Staff Comments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Submission of Matters to a Vote of Security Holders. . . . . . . . . . . . . . . . . . . . . . . . . . . . Executive Officers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 1A. Item 1B. Item 3. Item 4. Item 5. Item 6. Item 7. Item 7A. Item 8. Item 9. Item 9A. Item 9B. Item 10. Item 11. Item 12. Item 13. Item 14. Part II Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Management’s Discussion and Analysis of Financial Condition and Results of Operations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Quantitative and Qualitative Disclosures About Market Risk.. . . . . . . . . . . . . . . . . . . . Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Controls and Procedures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other Information. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Part III Directors, Executive Officers and Corporate Governance. . . . . . . . . . . . . . . . . . . . . . . . Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Certain Relationships and Related Transactions, and Director Independence. . . . . . Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Part IV Item 15. Exhibits, Financial Statements Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1 1 1 3 4 16 18 18 18 18 18 18 19 25 25 26 26 28 30 31 57 59 118 118 118 119 119 119 119 119 119 Items 1 and 2. Business and Properties. PART I 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 Developed Undeveloped Reserves Reserves U.S. Natural gas (Bcf) Crude oil (MMBbls) Total U.S. (MMBoe) International Natural gas (Bcf) Crude oil (MMBbls) Total International (MMBoe) Worldwide Natural gas (Bcf) Crude oil (MMBbls) Total Worldwide (MMBoe) 1,255 115 324 850 125 267 2,105 240 591 484 55 136 642 1 108 1,126 56 244 Total Proved Reserves 1,739 170 460 1,492 126 375 3,231 296 835 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 2 quantities, future producing rates, future net revenue, and the present value of such future net revenue. 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. 3 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 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 Production Volumes December 31, 2006 Proved Reserves Natural Gas Crude Oil (MBbls) (MMcf) Total Natural Gas Crude Oil Total (MBoe) (Bcf) (MMBbls) (MMBoe) Northern Region Rocky Mountains: Wattenberg Other Western Mid-continent Total Southern Region Deepwater Gulf Coast onshore Gulf of Mexico shelf Eastern Mid-continent Total Total North America 58,324 20,001 29,347 107,672 17,195 19,188 18,787 2,033 57,203 164,875 4,116 51 377 4,544 6,417 1,356 1,370 3,028 12,171 16,715 13,837 3,385 5,268 22,490 9,283 4,554 4,501 3,367 21,705 44,195 899 305 340 1,544 77 88 13 17 195 1,739 77 1 3 81 22 14 14 39 89 170 227 52 59 338 35 29 16 42 122 460 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 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. 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 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. 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 Production Volumes December 31, 2006 Proved Reserves Natural Gas Crude Oil (MBbls) (MMcf) 16,579 2,967 33,906 8,933 — 108 62,493 — — 62,493 6,519 1,357 — — 1,539 1,213 10,628 634 2,297 13,559 International West Africa North Sea Israel Ecuador China Argentina Total consolidated Equity investees: Condensate (MBbls) LPG (MBbls) Total Equity investee share of methanol sales (Kgal) Total Natural Gas Crude Oil (MMBbls) (MBoe) (Bcf) 945 19 360 168 — — 1,492 90 19 — — 9 8 126 9,282 1,852 5,651 1,489 1,539 1,231 21,044 634 2,297 23,975 109,942 Total (MMBoe) 248 22 60 28 9 8 375 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: Production Volumes (1) Natural Gas Crude Oil Natural Gas Crude Oil Per Bbl (2) Average Sales Price Per Mcf (2) MBbls MMcf Average Production Cost Per BOE (3) Year Ended December 31, 2006 U.S. West Africa (4) North Sea Israel Other International (5) Total Consolidated Operations Equity Investee (6) Total Year Ended December 31, 2005 U.S. West Africa (4) North Sea Israel Other International (5) Total Consolidated Operations Equity Investee (6) Total Year Ended December 31, 2004 U.S. West Africa (4) North Sea Israel Other International (5) Total Consolidated Operations Equity Investee (6) Total 164,875 16,579 2,967 33,906 9,041 227,368 — 227,368 125,543 23,938 3,394 24,228 8,389 185,492 — 185,492 88,077 16,747 4,130 17,573 7,782 134,309 — 134,309 16,715 6,519 1,357 — 2,752 27,343 2,931 30,274 9,468 6,492 1,964 — 2,866 20,790 1,183 21,973 7,951 3,364 2,459 — 2,506 16,280 327 16,607 $6.61 0.37 8.00 2.72 0.96 5.55 — $ 5.55 $ 7.43 0.25 5.93 2.68 1.10 5.78 — $ 5.78 $ 6.03 0.25 4.73 2.78 0.75 4.76 — $ 4.76 $ 50.68 62.51 67.43 — 52.05 54.47 45.83 $53.64 $46.67 42.51 52.68 — 42.37 45.35 43.43 $45.25 $32.64 38.16 38.90 — 31.06 34.48 32.01 $34.44 $ 8.12 2.86 10.08 1.60 9.74 6.97 — $ 7.39 2.93 7.54 2.11 7.15 6.06 — $ 5.84 3.38 6.13 2.46 5.67 5.20 — $ — (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: United States—Onshore United States—Offshore International Total Crude Oil Wells Gross 7,326 110 782 8,218 Net 5,635.7 47.5 108.4 5,791.6 Natural Gas Wells Gross 4,324 9 31 4,364 Net Gross 11,650 2,904.2 119 5.1 813 12.8 12,582 2,922.1 Total Net 8,539.9 52.6 121.2 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. Multiple Completions Non-producing (Shut-in) Crude Oil Wells Net Gross 8 1,921 5.9 1,279.9 Natural Gas Wells Net Gross 3.6 14 257.7 346 Total Gross 22 2,267 Net 9.5 1,537.6 Developed and Undeveloped Acreage—The developed and undeveloped acreage (including both leases and concessions) held at December 31, 2006 was as follows: U.S.: Onshore Offshore Total U.S. Israel Argentina Equatorial Guinea Cameroon Suriname Ecuador North Sea (1) China Total International Total Worldwide (2) Developed Acreage Undeveloped Acreage Gross Net Gross Net 1,416,429 173,105 1,589,534 123,552 113,325 45,376 — — 12,355 42,822 7,413 344,843 1,934,377 794,257 96,867 891,124 58,142 15,548 15,727 — — 12,355 3,921 4,225 109,918 1,001,042 1,343,010 486,698 1,829,708 468,264 — 850,395 1,125,000 4,596,160 851,771 574,293 — 8,465,883 10,295,591 780,622 227,601 1,008,223 195,660 — 299,428 562,500 1,378,848 851,771 243,692 — 3,531,899 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. 14 Drilling Activity—The results of crude oil and natural gas wells drilled for each of the last three fiscal years were as follows: Year Ended December 31, 2006 U.S. North Sea China Argentina Total Year Ended December 31, 2005 U.S. Equatorial Guinea North Sea Argentina Total Year Ended December 31, 2004 U.S. Equatorial Guinea North Sea China Argentina Ecuador Total Net Exploratory Wells Productive Dry Total Net Development Wells Total Productive Dry 9.0 6.3 — 0.4 — — — — 9.4 6.3 4.7 10.7 — — — 0.2 — — 10.9 4.7 8.5 10.7 0.3 — 0.7 0.3 — — — — — — 9.5 11.0 15.3 0.4 — — 15.7 15.4 — 0.2 — 15.6 19.2 0.3 1.0 — — — 20.5 666.6 1.8 1.1 7.6 677.1 488.1 0.3 — 7.7 496.1 62.4 2.4 0.1 1.7 10.0 3.0 79.6 5.5 — — — 5.5 25.9 — — — 25.9 8.7 — — — — — 8.7 672.1 1.8 1.1 7.6 682.6 514.0 0.3 — 7.7 522.0 71.1 2.4 0.1 1.7 10.0 3.0 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. 15 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. 16 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 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 17 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. 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. 18 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 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; 19 • 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; • 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 20 these requirements. If we are not able to fund our capital expenditures, interests in some properties might be reduced or forfeited as a result. 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 21 their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations. 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 Charles D. Davidson (1) David L. Stover (2) Chris Tong (3) Alan R. Bullington (4) Robert K. Burleson (5) Susan M. Cunningham (6) Arnold J. Johnson (7) Age 56 49 50 55 49 51 51 Position Chairman of the Board, President, Chief Executive Officer and Director Executive Vice President, Chief Operating Officer Senior Vice President, Chief Financial Officer Senior Vice President, International Senior Vice President, Business Administration and President, Noble Energy Marketing, Inc. Senior Vice President, Exploration and Corporate Reserves 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: 2005 First quarter Second quarter Third quarter Fourth quarter 2006 First quarter Second quarter Third quarter Fourth quarter High Low Dividends Per Share $ 34.35 39.22 47.52 47.79 $ 46.91 49.33 51.71 54.64 $ 28.06 31.66 38.81 35.96 $ 38.32 36.14 41.80 41.77 $ 0.025 0.025 0.050 0.050 $ 0.050 0.075 0.075 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 Shares Purchased Total Number Average Price as Part of Publicly Announced Plans Paid or Programs (1) Per Share of Shares Purchased Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in thousands) 1,664,700 1,387,300 1,164,600 4,216,600 $ 46.58 49.46 51.35 $ 48.84 1,664,700 1,387,300 1,164,600 4,216,600 $ 101,493 Period 10/01/06—10/31/06 11/01/06—11/30/06 12/01/06—12/31/06 Total (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 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. 28 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 to be issued upon exercise of outstanding options (a) Weighted-average exercise price of outstanding options, warrants and rights (b) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) 6,211,750 — 6,211,750 $24.24 — $24.24 5,177,323 — 5,177,323 Plan Category Equity compensation plans approved by security holders Equity compensation plans not approved by security holders Total 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. $300 $250 $200 $150 $100 $50 $0 12/01 12/02 12/03 12/04 12/05 12/06 Noble Energy, Inc. S & P 500 Peer Group Noble Energy, Inc. S & P 500 Peer Group 12/01 12/02 12/03 12/04 12/05 12/06 100.00 100.00 100.00 106.90 77.90 104.62 127.09 100.24 135.35 177.09 111.15 176.81 232.41 116.61 272.75 284.65 135.03 265.30 29 Item 6. Selected Financial Data 2006 Year ended December 31, 2004 (in thousands, except share amounts) 2005 (1) 2003 2002 Revenues and Income: Revenues Income from continuing operations Net income Per Share Data: Basic earnings per share— Income from continuing operations Net income Cash dividends Year-end stock price Basic weighted average shares $2,940,082 678,428 678,428 $ 2,186,723 645,720 645,720 $1,351,051 313,850 328,710 $1,008,226 89,892 77,992 $ 703,068 8,095 17,652 $ $ $ 3.86 3.86 0.275 49.07 4.20 4.20 0.15 40.30 $ 2.69 2.82 0.10 30.83 $ 0.79 0.68 0.085 22.22 0.07 0.15 0.08 18.78 outstanding 175,707 153,773 116,550 113,928 114,392 Financial Position: Property, plant, and equipment, net Goodwill Total assets Long-term obligations— Long-term debt Deferred income taxes Asset retirement obligations Derivative instruments Other deferred credits and noncurrent liabilities Shareholders’ equity Continuing Operations Information: Natural gas production (Mcfpd) Average realized price ($/Mcf) (2) Crude oil production (Bopd) Average realized price ($/Bbl) (2) Equity investee production (Bopd) Average realized price ($/Bbl) $7,170,757 781,290 9,588,625 $ 6,198,916 862,868 8,878,033 $2,180,715 — 3,435,784 $2,046,909 — 2,820,800 $ 2,128,140 — 2,730,016 1,800,810 1,758,452 127,689 328,875 2,030,533 1,201,191 278,540 757,509 880,256 180,415 175,415 9,678 776,021 161,912 101,804 7,400 977,116 201,939 — 337 274,720 4,113,817 279,971 3,090,144 69,479 1,459,988 72,776 1,073,573 69,483 1,009,386 622,927 5.55 74,915 54.47 8,032 45.83 $ $ $ 508,195 5.78 56,958 45.35 3,240 43.43 $ $ $ 366,965 4.76 44,481 34.48 894 32.01 $ $ $ 336,611 4.19 35,101 27.67 913 25.47 $ $ $ 341,008 2.89 28,232 24.22 882 17.82 $ $ $ (1) (2) Includes effect of Patina Merger. See Item 8. Financial Statements and Supplementary Data— Note 3—Acquisitions and Divestitures for additional information. Prices include effects of oil and gas hedging activities. See Item 8. Financial Statements and Supplementary Data—Note 12—Derivative Instruments and Hedging Activities. 30 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. We are an independent energy company engaged in the exploration, development, production and marketing of crude oil and natural gas. We have exploration, development and production operations domestically and internationally. 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. We also conduct business internationally, in West Africa (Equatorial Guinea and Cameroon), the Mediterranean Sea, Ecuador, the North Sea, China, Argentina and Suriname. Our accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be referred to in conjunction with the following discussion. EXECUTIVE OVERVIEW 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. Our Patina merger, purchase of U.S. Exploration and recent sale of Gulf of Mexico shelf properties have allowed us to achieve a strategic objective of enhancing our U.S. asset portfolio. The result is a company with assets and capabilities that include growing U.S. basins coupled with a significant portfolio of international properties. In 2006 our crude oil and natural gas sales volumes were 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. 2006 was a strong year for us, both financially and operationally. Significant financial information included the following: • net income of $678 million, a 5% increase over 2005 net income, and a 100% increase over 2004 net income; • pretax gain of $211 million on the sale of the Gulf of Mexico shelf properties; • recognition of a non-cash pretax charge of $399 million related to previously forecasted hedge production that was no longer probable of occurring due to the sale of Gulf of Mexico shelf properties (See Item 8—Financial Statements and Supplementary Information—Note 12— Derivative Instruments and Hedging Activities); • diluted earnings per share of $3.79, an 8% decrease from 2005 and a 37% increase over 2004; • cash flow provided by operating activities of $1.730 billion, a 40% increase over 2005 and a 144% increase over 2004; • cash flow used in investing activities of $1.098 billion, a 42% decrease from 2005 and an 87% increase over 2004; • cash flow used in financing activities of $589 million, as compared with $583 million provided by financing activities in 2004 and $3 million used in financing activities in 2004; and • completion of 80% of a newly implemented $500 million common stock repurchase program. Significant operational highlights included the following: • purchase of U.S. Exploration; • sale of Gulf of Mexico shelf properties; • commencement of production from the Ticonderoga deepwater Gulf of Mexico development (Green Canyon Block 768) on February 16, 2006; 31 • commencement of production from the Lorien deepwater Gulf of Mexico development (Green Canyon Block 199 ) on April 27, 2006; • Gulf of Mexico deepwater discoveries at Redrock prospect (Mississippi Canyon Block 204) and at Raton prospect (Mississippi Canyon Block 248); • Piceance Basin production growth of greater than 400% year-over-year from successful drilling and completion of 36 wells during 2006; • continued expansion of Niobrara Trend in eastern Colorado, Kansas and Nebraska with the completion of 20 commitment wells with Teton Energy Corporation earning a 75% working interest in approximately 184,000 acres; • acquisition of a 50% participating interest in the PH-77 license, offshore the Republic of Cameroon; • full year of production from the Phase 2B liquids expansion project in Equatorial Guinea; • overall daily sales volumes that were 29% higher than 2005 and 75% higher than 2004; • average realized crude oil prices that were 20% higher than 2005 and 58% higher than 2004; and • average realized natural gas prices that were 4% lower than 2005 and 17% higher than 2004. Portfolio Enhancements—During 2006, we continued to enhance our portfolio with significant purchases and divestitures of assets. 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. The sale of these non-core assets allows us to focus future investments and growth in areas with higher potential. Pretax cash proceeds from the sale totaled $506 million including proceeds received from parties who exercised preferential rights to purchase certain properties. The sale resulted in lower sales volumes of approximately 10,700 Boepd in 2006. 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 120 Bcf of natural gas. A pretax gain of $211 million from the sale is included in our results of operations. The asset disposition did not qualify for accounting as discontinued operations, in accordance with EITF 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations”. This is due to the migration of our investment and operations to the Gulf Coast onshore and deepwater Gulf of Mexico areas. On March 29, 2006, we purchased the common stock of 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 in Colorado’s Wattenberg field. This acquisition significantly expands our operations in one of our core areas. Proved reserves of U.S. Exploration are estimated to be approximately 248 Bcfe, of which 41% are proved developed and 55% are natural gas. Our consolidated operating and cash flow information includes financial results of U.S. Exploration after March 29, 2006. Common Stock Repurchase Program—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 and expect to fund the repurchases primarily from cash flows from operations. 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 subject to reevaluation in the event of changes in market conditions. During 2006, we repurchased 8.4 million shares of our common stock at an aggregate cost of $399 million. Adoption of SFAS 123(R)—We adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment,” (“SFAS 123(R)”) as of January 1, 2006. As a result, we recognized compensation expense of $12 million related to stock-based awards during 2006. This expense relates to stock-based awards made in 2006 and prior years that vest in 2006 and thereafter. As a result of this change in accounting method, our net income was reduced by $4 million, or $0.02 per diluted share, for 2006. In 32 addition, tax benefits of $26 million related to option exercises were included in cash flows from financing activities rather than cash flows from operating activities. For 2005, tax benefits of $15 million were included in cash flows from operating activities. Domestic Operations—Domestic operations benefited from a 45% increase in production and higher realized prices for crude oil in 2006. During 2006, our North America division continued to grow production despite the sale of Gulf of Mexico shelf properties. Onshore, significant activity continued in the Rocky Mountain and onshore Gulf coast areas. We completed significant deepwater developments in the Gulf of Mexico that added substantial new production during 2006. Significant operational highlights included the following: • overall daily sales volumes that were 45% higher than 2005 and 96% higher than 2004; • overall onshore daily sales volumes that were 46% higher than 2005 and 246% higher than 2004; • deepwater daily sales volumes that were 535% higher than 2005 and 263% higher than 2004; • average realized crude oil prices that were 9% higher than 2005 and 55% higher than 2004; • average realized natural gas prices that were 11% lower than 2005 and 10% higher than 2004; • exploration discoveries at Redrock and Raton in the Gulf of Mexico and completion of Raton appraisal well; • first production from the Ticonderoga deepwater Gulf of Mexico development first quarter 2006; • first production from the Lorien deepwater Gulf of Mexico development second quarter 2006; and • successful divestiture of Gulf of Mexico shelf assets. International Operations—International operations benefited from higher realized prices for crude oil and natural gas in 2006, and a 7% overall increase in production. During 2006, we participated in the drilling of six development wells in the North Sea, two development wells offshore in China and 58 development wells in Argentina. Significant operational highlights included the following: • overall daily sales volumes that were 7% higher than 2005 and 47% higher than 2004; • overall higher realized crude oil and natural gas prices; • full year of production from the Phase 2B liquids expansion project which included increasing processing capacity, storage and offloading facilities at the existing LPG plant in Equatorial Guinea; • increased natural gas infrastructure in Israel; and • significant progress at the Dumbarton development in the North Sea, which commenced production in January 2007. Recent Developments in Equatorial Guinea—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. 2007 OUTLOOK We expect crude oil and natural gas production from continuing operations to increase in 2007 compared to 2006. Factors which may impact our expected year-over-year increase in production include: • production contributions from the sale of natural gas from the Alba field in Equatorial Guinea to an LNG facility; • the contribution of production from the Dumbarton North Sea development, which commenced on January 20, 2007; • growing natural gas sales in Israel due to the planned conversion of additional power plants to use natural gas as fuel; 33 • growing production from the Piceance Basin, where we are continuing an active drilling program; • a full year of production from the acquisition of U.S. Exploration, which closed on March 29, 2006; • partially offset by loss of production from Gulf of Mexico shelf properties sold in July 2006 and natural production decline in certain fields. Factors which may impact our expected production profile include: • seasonal variations in rainfall in Ecuador that affect our natural gas-to-power project; • infrastructure development in Israel; • potential weather-related shut-ins in the Gulf of Mexico and Gulf Coast areas; • potential weather-related volume curtailments in the Northern region; and • capital expenditures, as discussed below, which are expected to result in near-term production. 2007 Budget—We have budgeted capital expenditures of $1.42 billion for 2007. Approximately 26% of the 2007 capital budget has been allocated to exploration opportunities and 74% has been allocated to production, development and other projects. Domestic spending is budgeted for $1.09 billion (77% of the 2007 capital budget), international expenditures are budgeted for $300 million (21%) and corporate expenditures are budgeted for $28 million (2%). The 2007 budget does not include the impact of possible asset purchases. We expect that the 2007 capital budget will be funded primarily from cash flows from operations. We will evaluate the level of capital spending throughout the year based upon drilling results, commodity prices, cash flows from operations and property acquisitions. CRITICAL ACCOUNTING POLICIES AND ESTIMATES The preparation of the consolidated financial statements requires our management to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. When alternatives exist among various accounting methods, the choice of accounting method can have a significant impact on reported amounts. The following is a discussion of the accounting policies, estimates and judgments which management believes are most significant in the application of generally accepted accounting principles used in the preparation of the consolidated financial statements. Purchase Price Allocation—As a result of the Patina Merger in May 2005 and the acquisition of U.S. Exploration in March 2006, we acquired assets and assumed liabilities in transactions accounted for as purchases. In connection with a purchase business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes must be recorded for any differences between the assigned values and tax bases of assets and liabilities. Any excess of purchase price over amounts assigned to assets and liabilities is recorded as goodwill. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the value attributed to assets acquired and liabilities assumed. In estimating the fair values of assets acquired and liabilities assumed we made various assumptions. The most significant assumptions related to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties, we prepared estimates of crude oil and natural gas reserves. We estimated future prices to apply to the estimated reserve quantities acquired, and estimated future operating and development costs, to arrive at estimates of future net revenues. For estimated proved reserves, the future net revenues were discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the merger. The market-based weighted average cost of capital rate was subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net revenues of probable and possible reserves were reduced by additional risk-weighting factors. 34 Estimated deferred taxes were based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the merger date, although such estimates may change in the future as additional information becomes known. While the estimates of fair value for the assets acquired and liabilities assumed have no effect on our cash flows, they can have an effect on the future results of operations. Generally, higher fair values assigned to crude oil and natural gas properties result in higher future depreciation, depletion and amortization expense, which results in a decrease in future net earnings. Also, a higher fair value assigned to crude oil and natural gas properties, based on higher future estimates of crude oil and natural gas prices, could increase the likelihood of an impairment in the event of lower commodity prices or higher operating costs than those originally used to determine fair value. An impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded. Certain data necessary to complete the final purchase price allocation for U.S. Exploration is not yet available, and includes, but is not limited to, final valuation of pre-acquisition contingencies, final tax returns that provide the underlying tax bases of assets and liabilities, and final appraisals of assets acquired and liabilities assumed. We expect to complete the valuation of assets and liabilities (including deferred taxes) for the purpose of allocation of the total purchase price amount to assets acquired and liabilities assumed during the twelve-month period following the acquisition date. Any future change in the value of net assets up until the one year period has expired will be offset by a corresponding increase or decrease in goodwill. Any change in deferred tax assets and liabilities as of the acquisition date based on information that becomes available later will be recorded as an increase or decrease in goodwill. Goodwill—As of December 31, 2006, the consolidated balance sheet included $781 million of goodwill, all of which has been assigned to the domestic reporting unit. Goodwill is not amortized to earnings but is tested, at least annually, for impairment at the reporting unit level. We conduct the goodwill impairment test as of December 31, 2006. Other events and changes in circumstances may also require goodwill to be tested for impairment between annual measurement dates. If the carrying value of goodwill is determined to be impaired, the amount of goodwill is reduced and a corresponding charge is made to earnings in the period in which the goodwill is determined to be impaired. The impairment assessment requires management to make estimates regarding the fair value of the reporting unit to which goodwill has been assigned. The fair value of the domestic reporting unit was determined using a combination of the income approach and the market approach. Under the income approach, the fair value of the reporting unit is estimated based on the present value of expected future cash flows. Under the market approach, the fair value is estimated based on market multiples of EBITDA (earnings before interest, taxes, and depreciation, depletion and amortization (“DD&A”)) and EBIT (earnings before interest and taxes). The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, as well as the success of future exploration for and development of unproved reserves, appropriate discount rates and other variables. Downward revisions of estimated reserve quantities, increases in future cost estimates, divestiture of a significant component of the reporting unit, or sustained decreases in natural gas or crude oil prices could lead to an impairment of all or a portion of goodwill in future periods. Under the market approach, we make certain judgments about the selection of comparable companies, comparable recent company and asset transactions and transaction premiums. Although we have based the fair value estimate on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and uncertain and actual results could differ from the estimate. In 2006, no goodwill impairment was recognized. When we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill to be included in that carrying amount is based on the 35 relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained. During 2006, we allocated $100 million of domestic reporting unit goodwill to the carrying amount of our Gulf of Mexico shelf properties sold in July 2006. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business. Reserves—All of the reserve data in this Form 10-K are estimates. Estimates of our crude oil and natural gas reserves are prepared by our engineers in accordance with guidelines established by the SEC. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. Estimates of proved crude oil and natural gas reserves significantly affect our DD&A expense. For example, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also trigger an impairment analysis to determine if the carrying amount of crude oil and natural gas properties exceeds fair value and could result in an impairment charge, which would reduce earnings. Oil and Gas Properties—We account for crude oil and natural gas properties under the successful efforts method of accounting. The alternative method of accounting for crude oil and natural gas properties is the full cost method. Under the successful efforts method, costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties are amortized to operations by the unit-of-production method based on proved developed crude oil and natural gas reserves on a property-by-property basis as estimated by our engineers. Application of the successful efforts method results in the expensing of certain costs including geological and geophysical costs, exploratory dry holes and delay rentals, during the periods the costs are incurred. Under the full cost method, these costs are capitalized as assets and charged to earnings in future periods as a component of DD&A expense. In addition, under the full cost method capitalized costs are accumulated in pools on a country-by-country basis. DD&A is computed on a country-by-country basis, and capitalized costs are limited on the same basis through the application of a ceiling test. We believe the successful efforts method is the most appropriate method to use in accounting for our crude oil and natural gas properties as this method is better aligned with our business strategy. If we had used the full cost method, our financial position and results of operations could have been significantly different. Exploratory Well Costs—In accordance with the successful efforts method of accounting, the costs associated with drilling an exploratory well may be capitalized temporarily, or “suspended,” pending a determination of whether commercial quantities of crude oil or natural gas have been discovered. We will carry the costs of an exploratory well as an asset if the well found a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive deepwater Gulf of Mexico or international projects, it may take more than one year to evaluate the future potential of the exploration well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities and access to such permits and approvals and believe they will be obtained. Management assesses the status of suspended exploratory well costs on a quarterly basis. These costs may be charged to exploration expense in future periods if we decide not to pursue additional exploratory or development activities. At 36 December 31, 2006, the balance of property, plant and equipment included $80 million of suspended exploratory well costs, $22 million of which had been capitalized for a period greater than one year. The wells relating to these suspended costs continue to be evaluated by various means including additional seismic work, drilling additional wells or evaluating the potential of the exploration wells. For more information, see Item 8—Financial Statements and Supplementary Data—Note 5—Capitalized Exploratory Well Costs. Impairment of Proved Oil and Gas Properties—We assess proved crude oil and natural gas properties for possible impairment when events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. We recognize an impairment loss as a result of a triggering event and when the estimated undiscounted future cash flows from a property are less than the carrying value. If an impairment is indicated, the cash flows are discounted at a rate approximate to our cost of capital and compared to the carrying value for determining the amount of the impairment loss to record. Estimated future cash flows are based on management’s expectations for the future and include estimates of crude oil and natural gas reserves and future commodity prices and operating costs. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment. We recorded approximately $9 million of impairments in 2006, primarily related to downward reserve revisions on domestic properties. Impairment of Unproved Oil and Gas Properties—We also perform periodic assessments of individually significant unproved crude oil and natural gas properties for impairment. Cash flows used in the impairment analysis are determined based upon management’s estimates of natural gas and crude oil reserves, future commodity prices and future costs to extract the reserves. Downward revisions in estimated reserve quantities, reductions in commodity prices, or increases in estimated costs could cause a reduction in the value of an unproved property and, therefore, could also cause a reduction in the carrying amounts of the property. If undiscounted future net cash flows are less than the carrying value of the property, indicating impairment, the cash flows are discounted at a rate approximate to our cost of capital and compared to the carrying value for determining the amount of the impairment loss to record. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors. Due to the volatility of natural gas and crude oil prices, these cash flow estimates are inherently imprecise. Management’s assessment of the results of exploration activities, availability of funds for future activities and the current and projected political climate in areas in which we operate also impact the amounts and timing of impairment provisions. During 2006, we recorded impairments of significant unproved oil and gas properties totaling approximately $1 million. Asset Retirement Obligation—Our asset retirement obligations (“ARO”) consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. SFAS No. 143, “Accounting for Asset Retirement Obligations,” requires that the discounted fair value of a liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. In periods subsequent to initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A. At December 31, 2006, the consolidated balance sheet included a liability for ARO of $196 million, including $65 million resulting 37 from hurricane damage. See Item 8—Financial Statements and Supplementary Data—Note 6—Asset Retirement Obligations. Involuntary Conversions—When an involuntary conversion occurs, such as the destruction of oil and gas producing assets by a hurricane, a loss is accrued by a charge to income if the amount of loss can be reasonably estimated. An asset relating to insurance recovery is recognized only when realization of the claim for recovery of a loss recognized in the financial statements is deemed probable. A gain (recovery of a loss not yet recognized in the financial statements or an amount recovered in excess of a loss recognized in the financial statements) is not recognized until the insurance reimbursement has been received. Management must make a number of estimates and assumptions relating to these gain and loss accruals. These include estimated costs of salvage, clean-up, restoration, redevelopment or abandonment and estimated amounts of insurance recoveries. The amount of an insurance recovery may be limited if total industry claims are in excess of the insurance carrier’s ceiling limitation per event. A significant amount of time may be necessary for an insurance carrier to review all related claims for an event and determine the company-specific claim limitation on the final recovery. In addition, we may continue to incur costs, submit claims and receive reimbursements over a multi-year period. The estimates involved in this process can have significant effects on reported amounts of net income. A decrease in the estimated amount of insurance recoveries will result in a decrease in the involuntary conversion gain, which will result in a decrease in net income. An increase in estimated costs of salvage, if not covered by insurance, will result in an increase in the involuntary conversion loss, which will result in a decrease in net income. Unreimbursed losses will have a negative effect on our cash flows. Derivative Instruments and Hedging Activities—We use various derivative instruments to minimize the impact of commodity price fluctuations on forecasted sales of crude oil and natural gas production. We also use derivative instruments in connection with purchases and sales of third-party production to lock in profits or limit exposure to commodity price risk. In addition, we have used derivative instruments in connection with acquisitions and certain price-sensitive projects. Management exercises significant judgment in determining types of instruments to be used, production volumes to be hedged, prices at which to hedge and the counterparties and the hedging counterparties’ creditworthiness. We account for derivative instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities, as amended”. For derivative instruments that qualify as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in accumulated other comprehensive income or loss (“AOCL”) until the hedged forecasted transaction is recognized in earnings. Therefore, prior to settlement of the derivative instruments, changes in the fair market value of those derivative instruments can cause significant increases or decreases in AOCL. For derivative instruments that do not qualify as cash flow hedges, changes in fair value are reported in current period net income and therefore can result in significant increases or decreases in current period net income. All hedge ineffectiveness is recognized in the current period in net income. Ineffectiveness is the amount of gains or losses from derivative instruments which are not offset by corresponding and opposite gains or losses on the expected future transaction. Regression analysis is performed on initial assessment of the hedge and subsequently every quarter thereafter in order to determine that the hedge instrument will be or has been highly effective in offsetting gains or losses on the future transaction. See Item 8—Financial Statements and Supplementary Data—Note 11—Derivatives and Hedging Activities. Income Tax Expense and Deferred Tax Assets—We are subject to income and other taxes in numerous taxing jurisdictions worldwide. For financial reporting purposes, we provide taxes at rates applicable for the appropriate tax jurisdictions. Estimates of amounts of income tax to be recorded involve interpretation of complex tax laws, assessment of the effects of foreign taxes on domestic taxes, and estimates regarding the timing and amounts of future repatriation of earnings from controlled foreign corporations. 38 The consolidated balance sheets include deferred tax assets. Deferred tax assets arise when expenses are recognized in the financial statements before they are recognized in the tax returns or when income items are recognized in the tax return before they are recognized in the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Ultimately, realization of a deferred tax asset depends on the existence of sufficient taxable income within the future periods to absorb future deductible temporary differences, loss carryforwards or credits. In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. As a result, we may determine, and we have determined in the past, that a deferred tax asset valuation allowance should be established. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense. Allowance for Doubtful Accounts—We assess the recoverability of all material trade and other receivables to determine their collectibility on a quarterly basis. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. In determining the amount of the reserve, management must analyze the aging of accounts receivable at the date of the consolidated financial statements and assess collectibility based on historic results, current collection trends and an evaluation of economic conditions. Over the last three years, we have increased the allowance by approximately $31 million to cover potentially uncollectible balances related to the Ecuador power operations. Certain entities purchasing electricity in Ecuador have been slow to pay amounts due us. We are pursuing various strategies to protect our interests including international arbitration and litigation. However, if estimates are inaccurate, we may incur gains or losses that could have a material effect on our results of operations. Retirement Plans—We sponsor a qualified defined benefit pension plan, a non-qualified defined benefit pension plan (“restoration plan”), and other postretirement benefit plans. The actuarial determination of the projected benefit obligation and related benefit expense requires that certain assumptions be made regarding such variables as expected return on plan assets, discount rates, rates of future compensation increases, estimated future employee turnover rates and retirement dates, distribution election rates, mortality rates, retiree utilization rates for health care services and health care cost trend rates. The selection of assumptions requires considerable judgment concerning future events and has a significant impact on the amount of the obligation recorded in the consolidated balance sheets and on the amount of expense included in the consolidated statements of operations. We base our determination of the asset return component of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of December 31, 2006, cumulative asset gains of approximately $2 million remained to be recognized in the calculation of the market-related value of assets. We utilize the services of an outside actuarial firm to assist in the calculations of the projected benefit obligation and related costs. The actuaries use historical data and forecasts to determine assumptions 39 regarding future events. In selecting the assumption for expected long-term rate of return on assets, we consider the average rate of earnings expected on the funds invested or to be invested to provide for plan benefits included in the projected benefit obligation. This includes considering the returns being earned by the plan assets and the rates of return expected to be available for reinvestment. It is assumed that the long-term asset mix will be consistent with the target asset allocation of 70% equity and 30% fixed income, with a range of plus or minus 10% acceptable degree of variation in the plan’s asset allocation. A 1% decrease in the expected return on plan assets assumption would have increased 2006 net periodic benefit cost by approximately $1 million. The expected return assumption used for 2006 was 8.25%. In accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” employers may look to rates of return on high quality fixed-income investments available as of the year-end measurement date and expected to be available during the period to maturity of the pension benefits in order to select a discount rate. In order to determine an appropriate December 31, 2006 discount rate, we performed an analysis of the Citigroup Pension Discount Curve (the “CPDC”) for each of our plans. The CPDC uses spot rates that represent the equivalent yield on high quality, zero coupon bonds for specific maturities. We used these rates to develop an equivalent single discount rate based on our plans’ expected future benefit payment streams and duration of plan liabilities. A 1% increase in the discount rate assumption would have decreased 2006 net periodic benefit cost by $4 million and decreased the benefit obligation for the combined plans by $25 million at December 31, 2006. A 1% decrease in the discount rate assumption would have increased 2006 net periodic benefit cost by $5 million and increased the benefit obligation for the combined plans by $31 million at December 31, 2006. The assumed discount rate was 5.5% for January through April 2006. The net periodic pension cost was remeasured at May 1, 2006 using a discount rate of 6.25%, due to changes in plan provisions. The assumed discount rate at December 31, 2006 was 5.75%. We adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R), as of December 31, 2006. The effect of adoption included a $25 million decrease in other assets, a $28 million increase in accrued benefit costs, a $20 million decrease in deferred tax liabilities and a $33 million (net of tax of $20 million) decrease in shareholders’ equity (effected by increasing AOCL). See Item 8—Financial Statements and Supplementary Data—Note 11—Employee Benefit Plans. Recently Issued Pronouncements—See Item 8—Financial Statements and Supplementary Data—Note 17— Recently Issued Pronouncements. LIQUIDITY AND CAPITAL RESOURCES Overview Our primary cash needs are to fund capital expenditures related to the acquisition, exploration and development of crude oil and natural gas properties, to repay outstanding borrowings or to pay other contractual commitments and for interest payments on debt. Our traditional sources of liquidity are cash on hand, cash flows from operations and available borrowing capacity under credit facilities. Funds may also be generated from occasional sales of non-strategic crude oil and natural gas properties. We have reduced our ratio of debt-to-book capital (defined as total debt divided by the sum of total debt plus equity) from 40% at December 31, 2005, to 30% at December 31, 2006. Significant changes in our financial position causing a change in the ratio of debt-to-book capital include: • a $230 million decrease in total debt from the balance at December 31, 2005; • a $678 million increase in retained earnings from current year net income; • a $63 million increase in capital in excess of par value from the exercise of stock options; and 40 • a $643 million increase in shareholders’ equity (effected by decreasing AOCL) primarily related to a decrease in deferred hedge losses. Cash Flows Operating Activities—Cash flows from operating activities totaled $1.730 billion in 2006, a $490 million increase over 2005. Factors contributing to the increase included: • a $536 million increase in oil and gas sales due to higher sales volumes; • a $250 million increase in oil and gas sales due to higher realized crude oil prices, offset by a $51 million decrease due to lower realized natural gas prices; • offset by a $141 million increase in total production costs (lease operating costs, production and ad valorem taxes and transportation expense), a $64 million increase in general and administrative expense, and a $30 million increase in interest expense. Cash flows from operating activities totaled $1.240 billion in 2005, a $532 million increase over 2004. Factors contributing to the increase included: • a $395 million increase in oil and gas sales due to higher sales volumes; • a $406 million increase in oil and gas sales due to higher realized crude oil and natural gas prices; • offset by a $112 million increase in total production costs (lease operating costs, production and ad valorem taxes and transportation expense), a $38 million increase in general and administrative expense, and a $35 million increase in interest expense. Cash flows from operating activities totaled $708 million in 2004, a $105 million increase over 2003. Factors contributing to the increase in cash flows from operating activities included: • a $144 million increase in oil and gas sales due to higher sales volumes; • a $183 million increase in oil and gas sales due to higher realized crude oil and natural gas prices; • offset by a $74 million increase in total production costs (lease operating costs, production and ad valorem taxes and transportation expense) and a $7 million increase in general and administrative expense. Investing Activities—Net cash used in investing activities totaled $1.098 billion in 2006, a $794 million decrease from 2005. Significant investing activities included: • $412 million used for the purchase of U.S. Exploration; • $1.357 billion used for capital expenditures; • partially offset by $520 million net proceeds from asset sales; and $155 million distributions received from equity method investees. Net cash used in investing activities totaled $1.892 billion in 2005, a $1.304 billion increase over 2004. Significant investing activities included: • $1.1 billion used for the Patina Merger; and • $786 million used for capital expenditures. Net cash used in investing activities totaled $588 million in 2004. Significant investing activities included: • $554 million used for capital expenditures; and • $104 million investments in equity method investees; • partially offset by $62 million net proceeds from asset sales. 41 Financing Activities—Net cash used in financing activities totaled $589 million in 2006. Significant financing activities included: • $230 million net reduction in short-term and long-term borrowings; • $49 million cash dividends paid on our common stock; • $399 million paid for repurchases of our common stock; • offset by $63 million proceeds from the exercise of stock options. Net cash provided by financing activities totaled $583 million in 2005. Significant financing activities included: • $539 million net increase in long-term borrowings; • $24 million cash dividends paid on our common stock; • offset by $68 million proceeds from the exercise of stock options. Net cash used in financing activities totaled $3 million in 2004. Significant financing activities included: • $54 million net reduction in long-term borrowings; • $12 million cash dividends paid on our common stock; • offset by $63 million proceeds from the exercise of stock options. Acquisition and Capital Expenditures Capital expenditure information (on an accrual basis) is as follows: Capital Expenditures Lease acquisition of unproved property Exploration expenditures Development expenditures Corporate and other expenditures Investments in equity method investees Total capital expenditures Year ended December 31, 2004 2005 2006 (in thousands) 53,652 203,035 1,054,780 35,069 580 1,347,116 16,793 161,515 662,585 21,478 27,639 890,010 44,685 100,847 399,217 22,639 61,498 628,886 Values preliminarily allocated to proved and unproved crude oil and natural gas properties acquired in the acquisition of U.S. Exploration were $413 million and $131 million, respectively. Values allocated to proved and unproved crude oil and natural gas properties acquired in the Patina Merger were $2.642 billion and $1.068 billion, respectively. Total capital expenditures during 2006 increased $457 million, or 51%, as compared with 2005. The increase was primarily due to development expenditures in the U.S. and North Sea. Total capital expenditures during 2005 increased $261 million, or 42%, as compared with 2004. Capital expenditures for 2005 included $275 million of post-merger exploration and development-related expenditures on Patina properties. Insurance Recoveries Hurricane Katrina in 2005 and Hurricane Ivan in 2004 caused substantial damage to our Main Pass assets. Since then we have committed significant resources to salvage and clean-up operations and restoration of production. As related to Hurricane Katrina, we have been notified by our insurance carrier that we should expect to recover no more than 50% of our total claim due to submission of total industry claims from Katrina damage in excess of a $1 billion ceiling limitation per event. However, we currently expect to 42 recover sufficient insurance proceeds to cover the expected salvage and clean-up costs and have offset anticipated insurance proceeds against the accrued salvage and clean-up expense except for a $1.0 million deductible. As of December 31, 2006, we have incurred $79 million (cumulative) in costs related to Hurricane Katrina damage, $16.5 million of which has been approved and reimbursed by our insurance carriers. As of December 31, 2006, we had recorded probable insurance claims of $64 million, the estimated remaining recovery for losses sustained from Hurricane Katrina. Total costs for clean-up and redevelopment are currently estimated at approximately $183 million. We expect to complete clean-up work during 2007 and receive final reimbursements thereafter. As of December 31, 2006, based upon work completed, we have incurred $203 million (cumulative) in costs related to Hurricane Ivan damage. Our insurance carriers have approved and reimbursed $176 million of these costs, with the balance pending subsequent review and approval. We expect to fully recover through insurance proceeds all salvage and clean-up expenses and a portion of our redevelopment capital. Future redevelopment expenditures will be capitalized as development costs, net of any remaining insurance proceeds. We carry up to $259 million property damage coverage per loss event. During first quarter 2006, our insurance carrier determined that its aggregation limit would be reduced from $1 billion to $500 million effective June 1, 2006. This insurance company modification, in response to large claims from losses caused by Hurricanes Katrina and Rita, increases the risk that we could recover less than our stated limits on any insured catastrophic loss event should the total aggregate losses realized by our carrier exceed its $500 million aggregation limit applicable to any single loss event. Although the insurance industry has reduced underwriting capacity for windstorm exposure in the Gulf of Mexico, we were able to secure $100 million additional insurance coverage applicable to specified deepwater properties, in the form of a package policy that covers property damage on an excess of loss limits basis, in addition to coverage for primary/contingent business interruption due solely to named windstorm loss events. The need for this package policy will be assessed annually and there is no assurance that we will elect to or be able to secure adequate insurance coverage for Gulf of Mexico windstorm exposure at policy expiration. Financing Activities long-term debt totaled $1.801 billion (net of unamortized discount) at Long-Term Debt—Our December 31, 2006. Maturities range from 2009 to 2097. Our principal source of liquidity is a $2.1 billion unsecured revolving credit facility (the “Credit Facility”). The Credit Facility, as amended in November 2006, (i) extends the maturity date of the Credit Facility to December 9, 2011, (ii) provides for Credit Facility fee rates that range from 5 basis points to 15 basis points per year depending upon our credit rating, (iii) makes available swingline loans up to an aggregate amount of $300 million and (iv) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 20 basis points to 70 basis points depending upon our credit rating and utilization of the Credit Facility. The Credit Facility contains customary representations and warranties and affirmative and negative covenants. The amendment to the Credit Facility eliminated the financial covenant requiring a 4.0 to 1.0 ratio of Earnings Before Interest, Taxes, Depreciation and Exploration Expense to interest expense. However, the Credit Facility continues to require that our total debt to capitalization ratio, expressed as a percentage, not exceed 60% at any time. A violation of this covenant could result in a default under the Credit Facility, which would permit the participating banks to restrict our ability to access the Credit Facility and require the immediate repayment of any outstanding advances under the Credit Facility. At December 31, 2006, the total debt to capitalization ratio was 30%, calculated for this purpose as total debt divided by the sum of total debt plus equity, with increases or decreases thereto as provided by the Credit Facility. 43 The Credit Facility is with certain commercial lending institutions and is available for general corporate purposes. At December 31, 2006, $1.155 billion in borrowings were outstanding under the Credit Facility. The weighted average interest rate applicable to borrowings under the Credit Facility at December 31, 2006 was 5.69%. Short-Term Borrowings—Our credit agreement is supplemented by short-term borrowings under various uncommitted credit lines used for working capital purposes. Uncommitted credit lines may be offered by certain banks from time to time at rates negotiated at the time of borrowing. There were no short-term borrowings outstanding at December 31, 2006. Debt Repayments—During 2006, we prepaid $105 million of term loans due January 2009. We also reduced the credit facility during 2006 with net payments of $125 million. See Item 8 — Financial Statements and Supplementary Data—Note 7 — Debt—Term Loans. We made cash interest payments of $118 million, $93 million and $47 million during 2006, 2005 and 2004, respectively. Dividends—Cash dividends totaled 27.5 cents per common share in 2006, 15 cents per common share in 2005 and 10 cents per common share in 2004. 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. The amount of future dividends will be determined on a quarterly basis at the discretion of the Board of Directors and will depend on earnings, financial condition, capital requirements and other factors. Exercise of Stock Options—We received $63 million, $68 million and $63 million from the exercise of stock options during 2006, 2005 and 2004, respectively. Proceeds received from the exercise of stock options fluctuate primarily based on the price at which our common stock trades on the NYSE in relation to the exercise price of the options issued. Of the $63 million received from the exercise of stock options during 2006, $46 million resulted from the exercise of Patina options that had been exchanged for Noble Energy options in the Patina Merger. Of the $68 million received from the exercise of stock options during 2005, $44 million resulted from the exercise of Patina options that had been exchanged for Noble Energy options in the Patina Merger. Off-Balance Sheet Arrangements We may enter into off-balance sheet arrangements and transactions that can give rise to material off- balance sheet obligations. As of December 31, 2006, the material off-balance sheet arrangements and transactions that we have entered into included drilling service contracts, operating lease agreements, undrawn letters of credit and derivative contracts. Other than the off-balance sheet arrangements listed above, we have no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See Contractual Obligations below for more information regarding off-balance sheet arrangements. 44 Contractual Obligations The following table summarizes certain contractual obligations that are reflected in the consolidated balance sheets and/or disclosed in the accompanying notes. See Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements. Payments Due by Period Total 2007 2008 and 2009 (in thousands) 2010 and 2011 2012 and Beyond Contractual Obligations: Long-term debt (excludes interest) (Note 7) (1) $ 1,805,000 $ - $ - $1,155,000 $650,000 Service contracts (Note 14)— Gulf of Mexico drilling rigs and services West Africa drilling rigs and services Northern region drilling rigs and 484,212 112,867 124,080 112,867 167,202 - 130,980 - 61,950 - services 135,481 75,988 53,017 6,476 - Operating lease obligations (Note 14)— Office buildings and facilities Oil and gas operations equipment Purchase obligations (Note 14) Other long-term liabilities (2)— Asset retirement obligations (Note 6) (3) Derivative instruments (Note 12) Total contractual obligations 51,967 6,787 16,052 10,237 5,168 16,052 12,177 1,619 - 11,568 - - 17,985 - - 196,189 545,396 $ 3,353,951 68,500 219,383 $ 632,275 17,245 325,071 $ 576,331 3,998 942 $1,308,964 106,446 - $836,381 (1) We anticipate cash payments for interest of $111 million for 2007, $221 million for 2008 and 2009, $221 million for 2010 and 2011 and $1.035 billion for the remaining years for a total of $1.588 billion. (2) The above amounts do not include our pension benefit obligation. See Item 8—Financial Statements and Supplementary Data—Note 11—Employee Benefit Plans. (3) Asset retirement obligations are discounted. We accrued approximately $11 million as of December 31, 2006, for an insurance contingency because of our membership in Oil Insurance Limited (OIL). OIL is an insurance pool which insures specific property, pollution liability and other catastrophic risks. As part of our membership, we are contractually committed to pay termination fees if we elect to withdraw from OIL. We do not anticipate withdrawing from OIL; however, the potential termination fee is calculated annually based on policyholders’ past losses and the liability reflecting this potential charge has been accrued as required. In January 2007, we entered into a five-year throughput and deficiency agreement with a financial commitment of $95 million. The transporting pipeline, the construction of which is subject to regulatory approval, is expected to be completed and operational in 2009. In addition, in the ordinary course of business, we maintain letters of credit in support of certain performance obligations of our subsidiaries. Outstanding letters of credit totaled approximately $14 million at December 31, 2006. 45 Other Contributions to Pension and Other Postretirement Benefit Plans—We made contributions to pension and other postretirement benefit plans of $36 million during 2006, $14 million during 2005, and $5 million during 2004. The actual returns on plan assets were $13 million in 2006, $6 million in 2005, and $8 million in 2004. The investment return has tended to follow market performance. In August 2006, the Pension Protection Act of 2006 (the Act) was signed into law. Certain provisions of this Act changed the calculation related to the maximum contribution amount deductible for income tax purposes and require that pension plans become fully funded over a seven-year period beginning in 2008. As a result of the contribution made to the pension plan in 2006, there are no required contributions expected during 2007. We expect to make contributions of $2 million to the restoration and medical and life plans in 2007. Income Taxes—We made cash payments for income taxes, net of refunds, of $115 million during 2006, $122 million during 2005 and $112 million during 2004. Contingencies—During 2006, 2005, and 2004 no significant payments were made to settle any legal proceedings. We regularly analyze current information and accrue for probable liabilities on the disposition of certain matters, as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. RESULTS OF OPERATIONS Net Income Net income for 2006 was $678 million, a 5% increase over 2005. Factors contributing to the increase in net income from 2005 to 2006 included: • a $753 million, or 34%, increase in revenues, driven primarily by a full year of Patina operations and nine months of U.S. Exploration operations; • an increase of $215 million in gains from asset sales; • offset by an increase in loss on derivative instruments of $360 million and a $232 million increase in DD&A. Net income for 2005 was $646 million, a 96% increase over 2004 net income of $329 million. Factors contributing to the increase in net income from 2004 to 2005 included: • an $836 million, or 62%, increase in revenues, driven primarily by the addition of Patina properties in May 2005; • offset by a $65 million increase in operating expense, an $82 million increase in DD&A, and a $61 million increase in exploration expense. 46 Natural Gas Information Natural gas sales increased 18% in 2006 compared to 2005 due to a 23% increase in daily natural gas production offset by a 4% decrease in average realized natural gas prices. Higher sales volumes had a positive effect of $239 million on natural gas sales. Lower realized sales prices had a negative effect of $51 million on natural gas sales. Natural gas sales increased 70% in 2005 compared to 2004 due to a 38% increase in daily natural gas production and a 21% increase in average realized natural gas prices. Of the $420 million increase in natural gas sales, $240 million of the increase was due to higher sales volumes and $180 million was due to higher realized sales prices. Natural gas sales are net of the effects of the settlement of derivative contracts that are accounted for as cash flow hedges. See Item 8—Financial Statements and Supplementary Data—Note 12—Derivative Instruments and Hedging Activities. Natural gas sales 2006 Year ended December 31, 2005 (in thousands) $ 1,023,644 $ 1,211,782 2004 $ 603,571 Average daily natural gas sales volumes and average realized sales prices were as follows: United States (1) West Africa (2) North Sea Israel Ecuador (3) Other International Total 2006 Year ended December 31, 2005 2004 Mcfpd 451,712 45,422 8,130 92,894 24,475 294 622,927 $/Mcf $ 6.61 0.37 8.00 2.72 — 0.96 $5.55 Mcfpd 343,953 65,581 9,299 66,377 22,795 190 508,195 $/Mcf Mcfpd $ 7.43 0.25 5.93 2.68 — 1.10 $5.78 240,647 45,755 11,286 48,015 20,875 387 366,965 $/Mcf $ 6.03 0.25 4.73 2.78 — 0.75 $ 4.76 (1) Reflects reductions of $0.25 per Mcf in 2006, $0.77 per Mcf in 2005, and $0.08 per Mcf in 2004 from hedging activities. (2) Natural gas in Equatorial Guinea is under contract for $0.25 per MMBtu through 2026 to a methanol plant and year-to-year to an LPG plant. Sales volumes declined in 2006 due to methanol plant turnaround followed by compressor maintenance and repairs. Each of these plants is owned by an affiliated entity accounted for under the equity method of accounting. The volumes sold by the LPG plant are included in the table below under crude oil information. For 2006, the price on an Mcf basis has been adjusted to reflect the Btu content on gas sales. (3) The natural gas-to-power project in Ecuador is 100% owned by one of our subsidiaries, and intercompany natural gas sales are eliminated for accounting purposes. Electricity sales of $72 million, $74 million, and $59 million are included in total revenues for 2006, 2005 and 2004, respectively. Factors contributing to the change in natural gas sales volumes in 2006 included: • additional domestic production from Patina properties; • additional domestic production from U.S. Exploration properties; • increases in deepwater Gulf of Mexico production at Swordfish, Ticonderoga and Lorien; 47 • increased demand from Israel Electric Corporation Limited, full year of sales to Bazan Oil Refinery and commencement of natural gas sales to the Reading power plant in Tel Aviv, Israel; • offset by the turnaround of the AMPCO methanol plant in Equatorial Guinea, which lasted 57 days, followed by reduced production levels caused by 35 days of compressor repairs. Factors contributing to the change in natural gas sales volumes in 2005 included: • additional domestic production from newly-acquired Patina properties; • increase in Phase 2A (Alba field expansion project) production and start-up of Phase 2B (liquids expansion project) in Equatorial Guinea; • higher production in Israel; • higher production in Ecuador; • offset by loss of production due to Gulf of Mexico hurricanes, and natural field decline in the Gulf of Mexico and North Sea. Crude Oil Information Crude oil sales increased 58% during 2006, compared to 2005, due to a 32% increase in consolidated daily crude oil production and a 20% increase in crude oil prices. Of the $547 million increase in crude oil sales, $297 million of the increase was due to higher sales volumes and $250 million was due to higher realized sales prices. Crude oil sales increased 68% during 2005, compared to 2004, due to a 28% increase in consolidated daily crude oil production and a 32% increase in crude oil prices. Of the $381 million increase in crude oil sales, $155 million of the increase was due to higher sales volumes and $226 million was due to higher realized sales prices. Crude oil sales are net of the effects of the settlement of derivative contracts that are accounted for as cash flow hedges. See Item 8—Financial Statements and Supplementary Data— Note 12—Derivative Instruments and Hedging Activities. Crude oil sales Year ended December 31, 2006 2004 2005 (in thousands) $ 942,778 $ 1,489,459 $ 561,404 Average daily crude oil sales volumes and average realized sales prices were as follows: United States (1) West Africa (2) North Sea (3) Other International (4) Total Consolidated Operations Equity Investees (5) Total 2006 Bopd $/Bbl 45,798 17,860 3,717 7,540 74,915 8,032 82,947 $ 50.68 62.51 67.43 52.05 54.47 45.83 $ 53.64 Year ended December 31, 2005 Bopd $/Bbl $ 46.67 25,941 42.51 17,786 52.68 5,380 42.37 7,851 45.35 56,958 43.43 3,240 $ 45.25 60,198 2004 Bopd $/Bbl 21,725 $ 32.64 38.16 9,190 6,718 38.90 31.06 6,848 34.48 44,481 32.01 894 $ 34.44 45,375 (1) Reflects reductions of $11.41 per Bbl in 2006, $8.03 per Bbl in 2005, and $3.05 per Bbl in 2004 from hedging activities. 48 (2) (3) Production averaged 17,326 Bopd in 2006. The variance between production and sales volumes is attributable to the timing of liquid hydrocarbon tanker liftings. Average realized sales prices reflect reductions of $9.93 per Bbl in 2005 from hedging activities. Production averaged 3,988 Bopd in 2006. The variance between production and sales volumes is attributable to the timing of liquid hydrocarbon tanker liftings. (4) Other international includes China and Argentina. Production averaged 7,491 Bopd in 2006. The variance between production and sales volumes is attributable to the timing of liquid hydrocarbon tanker liftings (5) 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. Factors contributing to the change in crude oil sales volumes in 2006 included: • timing of tanker liftings in Equatorial Guinea; • additional domestic production from Patina properties; • additional domestic production from U.S. Exploration properties; • increases in deepwater Gulf of Mexico production at Swordfish, Ticonderoga and Lorien; • full quarters of production from the Phase 2B liquids expansion project in Equatorial Guinea; and • natural field decline in the North Sea and timing of tanker liftings. Factors attributing to the change in crude oil sales volumes in 2005 included: • additional domestic production from newly-acquired Patina properties; • increase in Phase 2A (Alba field expansion project) production and start-up of Phase 2B (liquids expansion project) in Equatorial Guinea; • new production from the Swordfish development in the Gulf of Mexico; • increase in production in China; • offset by loss of production due to Gulf of Mexico hurricanes, and natural field decline in the North Sea. Derivative Instruments and Hedging Activities We use various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. Such instruments include variable to fixed price swaps, costless collars and basis swaps. Although these derivative instruments expose us to credit risk, we monitor the creditworthiness of counterparties and believe that losses from nonperformance are unlikely to occur. Hedging gains and losses related to crude oil and natural gas production are recorded in oil and gas sales. During 2006, 2005 and 2004, we recognized a reduction of revenues of $232 million, $238 million, and $61 million related to cash flow hedges in oil and gas sales. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk. 49 Income from Equity Method Investees We own a 45% interest in AMPCO LLC, which owns and operates a methanol production facility and related facilities in Equatorial Guinea and a 28% interest in Alba Plant LLC, which owns and operates an LPG processing plant. We account for investments in entities that we do not control but over which we exert significant influence using the equity method of accounting. Our share of operations of equity method investees was as follows: Net income (in thousands): AMPCO LLC and affiliates Alba Plant LLC Distributions/Dividends (in thousands): AMPCO LLC Alba Plant LLC Sales volumes: Methanol (Kgal) Condensate (Bopd) LPG (Bpd) Average realized prices: Methanol (per gallon) Condensate (per Bbl) LPG (per Bbl) Year ended December 31, 2005 2006 2004 $ 38,024 101,338 $ 56,896 33,916 $ 69,100 9,099 37,350 155,158 59,625 — 57,825 — 109,942 1,738 6,294 162,446 912 2,328 146,821 188 706 0.90 $ $ 66.60 $ 40.10 0.77 $ $ 55.76 $ 38.63 0.69 $ $ 37.25 $ 30.62 Net income from AMPCO, LLC in 2006 has declined relative to last year due to a 57-day shutdown of methanol production for the plant turnaround that occurred during May and June 2006. The turnaround was followed by 35 days of compressor repairs, which resulted in reduced methanol production levels. The increases in net income for Alba Plant LLC and in condensate and LPG sales volumes reflect the completion and ramp up to full production of the Phase 2B liquids expansion project at the Alba plant. 50 Costs and Expenses Production Costs—Production costs were as follows: Year Ended December 31, 2006 Oil and gas operating costs (1) Workover and repair expense Lease operating expense Production and ad valorem taxes Transportation expense Total production costs Year Ended December 31, 2005 Oil and gas operating costs (1) Workover and repair expense Lease operating expense Production and ad valorem taxes Transportation expense Total production costs Year Ended December 31, 2004 Oil and gas operating costs (1) Workover and repair expense Lease operating expense Production and ad valorem taxes Transportation expense Total production costs Total United States West Africa North Sea (in thousands) Israel Other Int’l/ Corporate (2) $ 270,136 46,951 317,087 108,979 28,542 $ 454,608 $ 205,348 46,793 252,141 85,960 20,728 $ 358,829 $ 203,833 14,027 217,860 78,703 16,764 $ 313,327 $ 136,087 13,734 149,821 65,428 9,350 $ 224,599 $ 136,471 16,635 153,106 28,022 19,808 $ 200,936 $ 85,013 16,635 101,648 21,806 8,631 $ 132,085 $ 26,557 — 26,557 — — $ 26,557 $ 30,661 — 30,661 — — $ 30,661 $ 20,811 — 20,811 — — $ 20,811 $ 11,655 — 11,655 — 7,010 $ 18,665 $ 12,244 259 12,503 — 6,562 $ 19,065 $ 8,803 — 8,803 — 10,480 $ 19,283 $9,066 — 9,066 — — $9,066 $8,504 — 8,504 — — $8,504 $7,203 — 7,203 — — $7,203 $ 17,510 158 17,668 23,019 804 $ 41,491 $ 16,337 34 16,371 13,275 852 $ 30,498 $ 14,641 — 14,641 6,216 697 $ 21,554 (1) Oil and gas operating costs include labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs. (2) Other international includes Ecuador, China, Argentina and Suriname. Oil and gas operating costs increased $66 million, or 33%, from 2005 to 2006 primarily as a result of our expanded operations. Three new deepwater Gulf of Mexico development projects came online between December 2005 and April 2006. Fiscal year 2006 represented a full year of Patina operations, and we acquired U.S. Exploration on March 29, 2006. In addition, the current high commodity price environment has resulted in higher service, contract labor and fuel costs. Insurance costs were also higher in 2006 due in part to increased rates for property damage coverage combined with the added costs of providing business interruption coverage on deepwater assets facing named windstorm exposure. Oil and gas operating costs increased $67 million, or 49% from 2004 to 2005. The 2005 increase primarily reflects expenses associated with properties acquired in the Patina Merger. Workover and repair expense increased $33 million during 2006 as compared with 2005 and decreased $3 million during 2005 as compared with 2004. Expense for 2006 includes workover expense of $6 million associated with Patina properties and $41 million associated with other North America properties. It also includes $30 million ($0.45 per BOE) of hurricane-related repair expense. 51 Production and ad valorem tax expense increased $30 million, or 38% during 2006 as compared with 2005 and increased $51 million, or almost tripled, during 2005 as compared with 2004. The 2006 increase reflects additional production from U.S. Exploration properties and a full year of Patina operations. Patina and U.S. Exploration properties have proportionately more production subject to such taxes. In addition, crude oil and natural gas revenues generally are taxed at higher rates as commodity prices rise. The 2005 increase primarily reflects increased production and higher realized commodity prices. Selected expenses on a per BOE basis were as follows: Oil and gas operating costs (1) Workover and repair expense (2) Lease operating expense Production and ad valorem taxes Transportation expense Total production costs Year ended December 31, 2004 2005 2006 $ 3.94 $ 3.53 $ 4.14 0.43 0.27 0.72 3.96 4.21 4.86 1.52 0.73 1.67 0.51 0.44 0.33 $ 5.20 $ 6.06 $ 6.97 (1) (2) Includes domestic business interruption insurance of $0.21 per BOE in 2006. Includes hurricane-related repair expense of $0.45 per BOE in 2006. The unit rates of total production costs per BOE, converting gas to oil on the basis of six Mcf per barrel, have been increasing year-over-year since 2004. The increases are due to rising third-party costs, including insurance, hurricane-related repair expense, and higher production taxes. Oil and Gas Exploration Expense – Exploration expense was as follows: Year Ended December 31, 2006 Dry hole expense Unproved lease amortization Seismic Staff expense Other Total exploration expense Year Ended December 31, 2005 Dry hole expense Unproved lease amortization Seismic Staff expense Other Total exploration expense Year Ended December 31, 2004 Dry hole expense Unproved lease amortization Seismic Staff expense Other Total exploration expense Total United States $ 70,325 18,836 37,676 38,861 2,226 $ 167,924 $ 98,015 17,855 21,761 34,945 5,850 $ 178,426 $ 46,192 19,280 23,360 22,990 5,179 $ 117,001 66,150 18,823 29,320 12,710 1,083 $ 128,086 $ 95,678 17,855 11,631 16,255 4,974 $ 146,393 $ 34,236 18,705 20,288 13,926 4,737 $ 91,892 West Africa North Sea (in thousands) $ 46 — 4,204 2,887 192 $ 7,329 $ 4,129 13 685 4,816 879 $ 10,522 $ 1,403 — 316 3,760 (16) $ 5,463 $ 932 — 1,544 2,690 819 $ 5,985 $ 4,676 — 2,115 260 163 $ 7,214 $ 6,789 50 550 3,374 402 $ 11,165 Israel Other Int’l/ Corporate (1) $ — — 3 250 33 $ 286 $ 2 — — 189 32 $ 223 $ 293 525 — 305 — $ 1,123 $ — — 3,464 18,198 39 $ 21,701 $ — — 8,270 12,051 41 $ 20,362 $ 198 — 407 5,125 (123) $ 5,607 (1) Other international includes Ecuador, China, Argentina and Suriname. 52 Exploration expense decreased $11 million, or 6% during 2006 as compared with 2005, and increased $61 million, or 52%, during 2005 as compared with 2004. In 2006, U.S. dry hole expense was $30 million less due to the reduction in the number of dry holes drilled. U.S. seismic expense increased $18 million due primarily to the expansion of our deepwater regional 3D seismic database. In addition, other international staff expense increased $8 million due to new venture activity. Exploration expense for 2006 included stock-based compensation expense of $1 million. The 2005 increase was due to higher dry hole expense in the U.S. where a total of 37 net wells were classified as dry holes and expensed during the year. Depreciation, Depletion and Amortization Expense – DD&A expense was as follows: United States West Africa North Sea Israel Other International, Corporate, and Other Total DD&A expense Year ended December 31, 2005 2004 2006 (in thousands) $ 311,153 27,121 9,888 11,188 31,194 $ 390,544 $ 543,431 23,620 8,123 13,947 33,487 $ 622,608 $ 240,058 13,925 18,244 9,058 26,818 $ 308,103 Unit rate of DD&A per BOE $ 9.54 $ 7.55 $ 7.97 Total DD&A expense has been increasing since 2004 primarily due to higher production volumes. The increase in the unit rate for 2006 as compared with 2005 was primarily due to the change in the mix of our production volumes. In particular, Gulf of Mexico deepwater production carries a unit rate which is higher than the company average. As deepwater production has increased from 3,627 Boepd, or 3% of 2005 total consolidated production volumes to 25,432 Boepd, or 14% of total consolidated production volumes in 2006, the unit rate has increased. During 2005, the unit rate decreased from 2004 due to an increase in low- cost production volumes in Equatorial Guinea and Israel. DD&A expense includes abandoned assets cost of $1 million, $11 million, and $15 million during 2006, 2005 and 2004, respectively. General and Administrative Expense General and administrative (“G&A”) expense was as follows: General and administrative expense (in thousands) Unit rate per BOE Year ended December 31, 2004 2005 2006 $ 61,852 $ 100,125 $ 164,541 $ 1.60 1.94 $ 2.52 $ G&A expense increased $64 million, or 64% during 2006 as compared with 2005 and $38 million, or 62%, during 2005 as compared with 2004. The 2006 increase was due to higher salaries and wages and the inclusion of a full year of G&A expense related to Patina operations. We are experiencing wage inflation due to the tight labor market which has resulted from the current high commodity price environment. The 2005 increase reflects additional costs incurred relating to the combining of our operations with those of Patina. G&A expense for 2006 includes stock-based compensation expense of $11 million (calculated under SFAS 123(R)). G&A expense for 2005 and 2004 includes stock-based compensation expense (calculated under APB 25) of $4 million and $1 million, respectively. 53 G&A includes actuarially-computed net periodic benefit expense related to pension and other postretirement benefit plans of $19 million, $11 million and $9 million during 2006, 2005 and 2004, respectively. Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows: Interest expense, net Capitalized interest Year ended December 31, 2004 2005 2006 (in thousands) $ 87,541 8,684 $ 53,460 8,168 $ 117,045 12,515 Interest expense, net of capitalized interest, has been increasing due to additional borrowings related to the Patina Merger and acquisition of U.S. Exploration and to increases in the interest rate applicable to the Credit Facility from 4.82% at December 31, 2005 to 5.69% at December 31, 2006. Interest is capitalized on development projects using an interest rate equivalent to the average rate paid on long-term debt. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis. The majority of the capitalized interest in 2006 relates to long lead-time projects in the North Sea and deepwater Gulf of Mexico. The majority of the capitalized interest in 2005 and 2004 relates to long lead-time projects in the deepwater Gulf of Mexico and internationally, primarily Phase 2A in Equatorial Guinea. (Gain) Loss on Derivative Instruments (Gain) loss on derivative instruments includes the following: Reclassified from AOCL Mark-to-market (gain) loss on derivatives not accounted for as cash flow hedges Ineffectiveness losses Total Year ended December 31, 2004 2006 2005 (in thousands) $ 398,517 $ (20,000 ) $ — (15,652) 9,502 $ 392,367 51,750 930 $ 32,680 — 272 $ 272 See Item 8—Financial Statements and Supplementary Data—Note 12—Derivative Instruments and Hedging Activities. Other Electricity Sales—Ecuador Integrated Power Project—Through our subsidiaries, EDC Ecuador Ltd. and MachalaPower Cia. Ltda., we have a 100% ownership interest in an integrated natural gas-to-power project. The project includes the Amistad natural gas field, offshore Ecuador, which supplies fuel to the Machala power plant. Electricity sales are included in other revenues and electricity generation expenses are included in other expense, net in the consolidated statements of operations. 54 Operating data is as follows: Electricity sales (in thousands) Electricity generation (in thousands) Operating income (in thousands) Power production (MW) Average power price ($/Kwh) Year ended December 31, 2004 2005 2006 $ 58,627 $ 74,228 $ 71,603 47,788 53,137 59,494 10,839 21,091 12,109 720,300 799,160 865,983 0.081 0.093 0.083 $ $ $ The volume of natural gas and electric power produced in Ecuador are related to thermal electricity demand in Ecuador which typically declines at the onset of the rainy season. When Ecuador has sufficient rainfall to allow hydroelectric power producers to provide base load power, we provide electricity only to meet peak demand. As seasonal rains subside, we experience increasing demand for thermal electricity. Electricity generation expense includes $15 million, $11 million and $5 million net increases in the allowance for doubtful accounts in 2006, 2005, and 2004, respectively. These increases have been made to cover potentially uncollectible balances related to the Ecuador power operations. Certain entities purchasing electricity in Ecuador have been slow to pay amounts due us. We are pursuing various strategies to protect our interests including international arbitration and litigation. Gathering, Marketing and Processing—NEMI, a wholly-owned subsidiary, marketed approximately 43% of our domestic natural gas production in 2006, as well as certain third-party natural gas. NEMI sells natural gas directly to end-users, natural gas marketers, industrial users, interstate and intrastate pipelines, power generators and local distribution companies. NEMI also markets certain third-party crude oil. Gathering, marketing and processing (“GMP”) proceeds are included in other revenues and GMP expenses are included in other expense, net in the consolidated statements of operations. NEMI’s gross margin from GMP activities was as follows: GMP proceeds GMP expenses Gross margin Year ended December 31, 2005 2004 2006 (in thousands) $ 55,261 28,067 $ 27,194 $ 49,250 37,699 $ 11,551 $ 27,876 18,664 $ 9,212 NEMI employs derivative instruments in connection with purchases and sales of third-party production to lock in profits or limit exposure to commodity price risk. Most of the purchases made by NEMI are on an index basis. However, purchasers in the markets in which NEMI sells often require fixed or NYMEX- related pricing. NEMI records gains and losses on derivative instruments using mark-to-market accounting. The net gain related to these contracts totaled $1 million during 2006 and $2 million during 2005. Gains (losses) were de minimis for 2004. GMP proceeds for 2005, includes a gain of $11 million for the sale of certain gas sales and transportation contractual assets. Deferred Compensation Expense—In connection with the Patina Merger, we acquired the assets and assumed the liabilities related to a deferred compensation plan. The assets of the deferred compensation plan are held in a rabbi trust and include shares of our common stock. Increases or decreases in the market value of the deferred compensation liability, including the shares of our common stock held by the rabbi trust, are included as deferred compensation expense and included in other expense, net in the consolidated statements of operations. We recorded deferred compensation expense of $28 million in 2006 and $18 million from the date of the Patina Merger through December 31, 2005. At December 31, 2006, 35% of the market value of the assets in the rabbi trust related to our common stock. 55 Impairment of Operating Assets—We recorded impairments of $9 million in 2006, $5 million in 2005, and $10 million in 2004, primarily related to downward reserve revisions on domestic properties. Impairment expense is included in other expense, net in the consolidated statements of operations. Income Taxes The income tax provision was as follows: Income tax provision (in thousands) Effective rate Year ended December 31, 2004 2005 2006 $199,158 $322,940 $417,789 38% 33% 39% Several factors resulted in an increase in our effective tax rate for 2006. The major factor was the allocation of $100 million of nondeductible goodwill to the sale of the Gulf of Mexico shelf properties. At December 31, 2005, we had recorded a deferred U.S. tax asset of $55 million for the future foreign tax credits associated with deferred foreign tax liabilities recorded by our foreign branch operations. The valuation allowance with respect to the deferred U.S. tax asset was $41 million at December 31, 2005. The tax asset was decreased to $53 million during 2006, and the valuation allowance was increased to $53 million due to changes in the forecast of limitations on the ability to claim foreign tax credits. There was also an increase in the UK tax rate during 2006. The UK Finance Act of 2006, enacted on July 19, increased the income tax rate on our UK operations retroactive to January 1, 2006 and increased our income tax provision by approximately $9 million in 2006. Partially offsetting these increases was a benefit from the realization of additional income from equity method investees which is a favorable permanent difference in calculating income tax expense. The decrease in the effective rate for 2005 was primarily due to our ability to claim a foreign tax credit for the income taxes paid by foreign branch operations, as well as to a benefit realized on the repatriation of foreign earnings under the American Jobs Creation Act of 2004. See Item 8—Financial Statements and Supplementary Data—Note 8—Income Taxes. Discontinued Operations During 2004, we completed an asset divestiture program including five domestic property packages. The sales price for the five property packages totaled $130 million. The consolidated financial statements have been reclassified for all periods previously presented to reflect the operations of the properties being sold as discontinued operations. Summarized results of discontinued operations were as follows: Oil and gas sales and royalties Realized gain Income before income taxes Key Statistics: Daily production Liquids (Bbls) Natural Gas (Mcf) Average realized price Liquids ($/Bbl) Natural Gas ($/Mcf) 56 Year ended December 31, 2004 (in thousands) $ 12,575 14,996 22,862 225 4,429 $ 33.96 6.03 $ Item 7A. Quantitative and Qualitative Disclosures About Market Risk. Commodity Price Risk Derivative Instruments Held for Non-Trading Purposes—We are exposed to market risk in the normal course of business operations. Management believes that we are well positioned with our mix of crude oil and natural gas reserves to take advantage of future price increases that may occur. However, the uncertainty of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, we have used derivative hedging instruments and may do so in the future as a means of managing our exposure to price changes. During the past three years we have entered into variable to fixed price swaps, costless collars, and variable to fixed price basis swaps related to our crude oil and natural gas production as follows: Natural Gas Collars NYMEX - Hedge MMBtupd Floor price range Ceiling price range Percent of daily worldwide production Crude Oil Collars NYMEX - Hedge Bopd Floor price range Ceiling price range Percent of daily worldwide production Brent - Hedge Bopd Floor price range Ceiling price range Percent of daily worldwide production Natural Gas Swaps NYMEX - Hedge MMBtupd Average price per MMBtu Percent of daily worldwide production Crude Oil Swaps NYMEX - Hedge Bopd Average price per Bbl Percent of daily worldwide production Brent - Hedge Bopd Average price per Bbl Percent of daily worldwide production Basis Swaps (1) CIG vs. NYMEX Hedge MMBtupd Average differential per MMBtu ANR vs. NYMEX Hedge MMBtupd Average differential per MMBtu Year ended December 31, 2005 2006 2004 12,082 $5.00 - $5.25 $8.00 - $10.20 2% 79,932 $5.00 - $5.75 $7.20 - $9.50 16% 120,284 $3.75 - $5.00 $5.16 - $9.65 33% 2,787 $29.00 - $60.00 $35.50 - $73.00 3% 15,519 $29.00 - $32.00 $37.25 - $46.15 26% 15,005 $24.00 - $28.00 $30.00 - $38.65 33% — — — — 5,000 $32.50 - $37.50 $49.50 - $56.50 8% 1,260 $37.50 - $37.50 $54.00 - $54.00 3% $ $ $ $ 170,000 6.49 27% $ 87,260 6.76 17% 16,600 40.47 18% — — — $ 58,685 1.49 11,726 1.14 — — — 8,793 39.62 15% — — — — — — — — — — — — — — — — — (1) Basis swaps have been combined with NYMEX natural gas fixed price swaps 57 At December 31, 2006, we had entered into future costless collar and fixed price swap transactions related to crude oil and natural gas production and basis swap transactions related to natural gas production. See Item 8. Financial Statements and Supplementary Data — Note 12—Derivative Instruments and Hedging Activities. As of December 31, 2006, we had a net unrealized loss of $167.2 million (pre-tax) related to crude oil and natural gas derivative instruments entered into for hedging purposes. A net unrealized loss of $104.3 million, net of tax, is recorded in AOCL in the shareholders’ equity section of our consolidated balance sheet. We will reclassify the loss to earnings as adjustments to revenue when future production occurs. Derivative Instruments Held for Trading Purposes—NEMI, from time to time, employs various derivative instruments in connection with purchases and sales of production. While most of the purchases are made for an index-based price, customers often require prices that are either fixed or related to NYMEX. In order to establish a fixed margin and mitigate the risk of price volatility, NEMI may convert a fixed or NYMEX sale to an index-based sales price (such as purchasing a NYMEX futures contract at the Henry Hub with an adjoining basis swap at a physical location). Due to the size of such transactions and certain restraints imposed by contract and by our internal guidelines, we believe we had no material market risk exposure from these derivative instruments as of December 31, 2006. Unrealized gains and losses are reflected in earnings as incurred. Interest Rate Risk We are exposed to interest rate risk related to our variable and fixed interest rate debt. As of December 31, 2006, we had $1.805 billion of debt outstanding of which $650 million was fixed-rate debt. We believe that anticipated near term changes in interest rates will not have a material effect on the fair value of our fixed-rate debt and will not expose us to the risk of earnings or cash flow loss. The remainder of our debt at December 31, 2006 was variable-rate debt and, therefore, exposes us to the risk of earnings or cash flow loss due to changes in market interest rates. At December 31, 2006, $1.155 billion of variable-rate debt was outstanding. A 10% change in the floating interest rates applicable to the December 31, 2006 balance would result in a change in annual interest expense of approximately $7 million. We occasionally enter into forward contracts or swap agreements to hedge exposure to interest rate risk. Changes in fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. At December 31, 2006, AOCL included $3 million, net of tax, related to a settled interest rate lock. This amount is being reclassified into earnings as adjustments to interest expense over the term of our 5¼% Senior Notes due April 2014. Foreign Currency Risk We have not entered into foreign currency derivatives. The U.S. dollar is considered the functional currency for each of our international operations. Transactions that are completed in a foreign currency are remeasured into U.S. dollars and recorded in the financial statements at the prevailing foreign exchange rates. Transaction gains or losses were not material in any of the periods presented and we do not believe we are currently exposed to any material risk of loss on this basis. Such gains or losses are included in other expense, net in the consolidated statements of operations. 58 Item 8. Financial Statements and Supplementary Data. INDEX TO FINANCIAL STATEMENTS Consolidated Financial Statements of Noble Energy, Inc. Management’s Report on Internal Control over Financial Reporting . . . . . . . . . . . . . . . . . . . . . . . . . . . Report of Independent Registered Public Accounting Firm (Financial Statements) . . . . . . . . . . . . . . Report of Independent Registered Public Accounting Firm (Internal Control Over Financial Reporting) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Balance Sheets as of December 31, 2006 and 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60 61 62 63 Consolidated Statements of Operations for each of the three years in the period ended December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64 Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 Consolidated Statements of Shareholders’ Equity for each of the three years in the period ended December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 Consolidated Statements of Comprehensive Income (Loss) for each of the three years in the period ended December 31, 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes to Consolidated Financial Statements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 68 Supplemental Oil and Gas Information (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107 Supplemental Quarterly Financial Information (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117 59 Management’s Report on Internal Control over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States. Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or processes may deteriorate. As of December 31, 2006, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control—Integrated Framework,” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2006, based on those criteria. Management included in its assessment of internal control over financial reporting all consolidated entities. KPMG LLP, the independent registered public accounting firm that audited our consolidated financial included in this Annual Report on Form 10-K, has issued an attestation report on statements internal control over financial reporting as of management’s assessment of the effectiveness of December 31, 2006 and is included herein. Noble Energy, Inc. 60 Report of Independent Registered Public Accounting Firm The Board of Directors and Shareholders of Noble Energy, Inc.: We have audited the accompanying consolidated balance sheets of Noble Energy, Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, shareholders’ equity, comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the financial statements of the Alba Plant LLC (Alba) and the Atlantic Methanol Production Company, LLC (AMPCO), the investments in which, as disclosed in Note 13 of the consolidated financial statements, are accounted for by the equity method of accounting. The Company’s investment in Alba as of December 31, 2006 was $146.1 million and the equity in earnings in Alba was $101.3 million for the year ended December 31, 2006. The Company’s investment in AMPCO as of December 31, 2005 was $214.2 million and the equity in earnings of AMPCO was $54.9 million and $66.8 million for the years ended December 31, 2005 and 2004, respectively. The financial statements of Alba and AMPCO were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Alba and AMPCO, are based solely on the report of other auditors. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Noble Energy, Inc. and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles. As discussed in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company changed its method of accounting for stock-based compensation. As also discussed in Note 2 to the consolidated financial statements, effective December 31, 2006, the Company changed its method of accounting for defined benefit pension and other postretirement plans. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Noble Energy, Inc.’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 23, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting. Houston, Texas February 23, 2007 KPMG LLP 61 Report of Independent Registered Public Accounting Firm The Board of Directors and Shareholders of Noble Energy, Inc.: We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Noble Energy, Inc. maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Noble Energy, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, management’s assessment that Noble Energy, Inc. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by COSO. Also, in our opinion, Noble Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by COSO. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Noble Energy, Inc. and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations, shareholders’ equity, other comprehensive income (loss), and cash flows for each of the years in the three-year period ended December 31, 2006, and our report dated February 23, 2007 expressed an unqualified opinion on those consolidated financial statements. KPMG LLP Houston, Texas February 23, 2007 62 Noble Energy, Inc. and Subsidiaries Consolidated Balance Sheets (in thousands, except share amounts) ASSETS Current Assets Cash and cash equivalents Accounts receivable - trade, net Probable insurance claims Deferred income taxes Other current assets Total current assets Plant, property and equipment Oil and gas properties (successful efforts method of accounting) Other plant, property and equipment Accumulated depreciation, depletion and amortization Total property, plant and equipment, net Other noncurrent assets Goodwill Total Assets LIABILITIES AND SHAREHOLDERS’ EQUITY Current Liabilities Accounts payable - trade Derivative instruments Income taxes Asset retirement obligations Other current liabilities Total current liabilities Deferred income taxes Asset retirement obligations Derivative instruments Other noncurrent liabilities Long-term debt Total Liabilities Commitments and Contingencies Shareholders’ Equity December 31, 2006 2005 $ 153,408 586,882 101,233 99,835 127,188 1,068,546 $ 110,321 566,206 142,311 237,045 119,628 1,175,511 8,867,639 79,646 8,947,285 (1,776,528) 7,170,757 568,032 781,290 $ 9,588,625 8,411,426 69,869 8,481,295 (2,282,379) 6,198,916 640,738 862,868 $ 8,878,033 $ 518,609 254,625 107,136 68,500 235,392 1,184,262 1,758,452 127,689 328,875 274,720 1,800,810 5,474,808 $ 519,971 445,939 65,136 60,331 148,768 1,240,145 1,201,191 278,540 757,509 279,971 2,030,533 5,787,889 Preferred stock - par value $1.00; 4,000,000 shares authorized, none issued Common stock - par value $3.33 1/3; 250,000,000 shares authorized; 188,808,087 and 184,893,510 shares issued, respectively Capital in excess of par value Deferred compensation Accumulated other comprehensive loss Treasury stock, at cost: 16,574,384 and 9,268,932 shares, respectively Retained earnings Total Shareholders’ Equity Total Liabilities and Shareholders’ Equity — — 629,360 2,041,048 — (140,509 ) (511,443 ) 2,095,361 4,113,817 $ 9,588,625 616,311 1,945,239 (5,288) (783,499) (148,476) 1,465,857 3,090,144 $ 8,878,033 The accompanying notes are an integral part of these financial statements 63 Noble Energy, Inc. and Subsidiaries Consolidated Statements of Operations (in thousands, except per share amounts) Year ended December 31, 2005 2004 2006 Revenues Oil and gas sales Income from equity method investees Other revenues Total Revenues Costs and Expenses Lease operating costs Production and ad valorem taxes Transportation costs Exploration costs Depreciation, depletion and amortization General and administrative Accretion of discount on asset retirement obligations Interest, net of amount capitalized Loss on derivative instruments Gain on sale of assets Other expense, net Total Costs and Expenses Income Before Taxes Income Tax Provision Income From Continuing Operations Discontinued Operations, Net of Tax Net Income Earnings Per Share Basic - Income from continuing operations Discontinued operations, net of tax Net Income Diluted - Income from continuing operations Discontinued operations, net of tax Net Income $2,701,241 139,362 99,479 2,940,082 $1,966,422 90,812 129,489 2,186,723 $ 1,164,975 78,199 107,877 1,351,051 317,087 108,979 28,542 167,924 622,608 164,541 10,797 117,045 392,367 (219,577) 133,552 1,843,865 217,860 78,703 16,764 178,426 390,544 100,125 11,214 87,541 32,680 (4,201 ) 108,407 1,218,063 153,106 28,022 19,808 117,001 308,103 61,852 9,352 53,460 272 (13,296) 100,363 838,043 1,096,217 417,789 678,428 — $ 678,428 968,660 322,940 645,720 — $ 645,720 513,008 199,158 313,850 14,860 $ 328,710 $ $ $ $ 3.86 — 3.86 3.79 — 3.79 $ $ $ $ 4.20 — 4.20 4.12 — 4.12 $ $ $ $ 2.69 0.13 2.82 2.65 0.13 2.78 Weighted average number of shares outstanding - Basic Weighted average number of shares outstanding - Diluted 175,707 179,044 153,773 156,759 116,550 118,452 The accompanying notes are an integral part of these financial statements 64 Noble Energy, Inc. and Subsidiaries Consolidated Statements of Cash Flows (in thousands) Year ended December 31, 2005 2006 2004 Cash Flows from Operating Activities Net income Adjustments to reconcile net income to net cash provided by operating activities: $ 678,428 $ 645,720 $ 328,710 Depreciation, depletion and amortization - oil and gas production Depreciation, depletion and amortization - electricity generation Dry hole expense Impairment of operating assets Amortization of unproved leasehold costs Stock-based compensation expense Non-cash effect of discontinued operations Gain on sale of assets Deferred income taxes Accretion of discount on asset retirement obligations Income from equity method investees Dividends received from equity method investees Deferred compensation expense Loss on derivative instruments Other Changes in operating assets and liabilities, net of acquisition: (Increase) in accounts receivable (Increase) in other current assets Decrease (increase) in probable insurance claims (Decrease) increase in accounts payable (Decrease) increase in other current liabilities Net Cash Provided by Operating Activities Cash Flows From Investing Activities Additions to property, plant and equipment U.S. Exploration acquisition, net of cash acquired Patina acquisition, net of cash acquired Proceeds from sale of property, plant and equipment Investments in equity method investees Distributions from equity method investees Net Cash Used in Investing Activities Cash Flows From Financing Activities Exercise of stock options Excess tax benefits from stock-based awards Cash dividends paid Purchase of treasury stock Proceeds from credit facilities Repayment of credit facilities Proceeds from term loans Repayment of term loans Repayment of Patina debt Issuance of long-term debt Repayment of notes Net Cash (Used in) Provided by Financing Activities Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Supplemental Disclosures of Cash Flow Information Cash paid during the year for: Interest (net of amount capitalized) Income taxes paid, net Non-cash financing and investing activities: 622,608 16,319 70,325 8,525 18,923 11,816 — (219,577) 194,261 10,797 (139,362) 37,350 28,189 415,298 37,400 (32,348) (4,954) 139,590 (11,151) (152,131) 1,730,306 (1,357,039) (412,257) — 519,567 (3,768) 155,158 (1,098,339) 62,613 26,106 (48,924) (398,675) 480,000 (605,000) — (105,000) — — — (588,880) 43,087 110,321 153,408 105,769 115,398 $ $ $ $ 390,544 16,476 98,015 5,368 17,855 3,467 — (4,201) 183,770 11,214 (90,812 ) 59,625 17,918 32,680 (33,870 ) (73,940) (28,254) (25,306 ) 20,747 (7,138) 1,239,878 (785,610 ) — (1,111,099 ) 13,179 (13,927) 4,969 (1,892,488 ) 67,657 — (23,655) — 3,335,333 (2,140,333 ) — (45,000) (610,865) — — 583,137 (69,473) 179,794 110,321 308,103 19,550 46,192 9,885 19,280 869 (14,996) (13,296) 20,205 9,352 (78,199) 57,825 — 272 (21,563) (99,886) (10,159) (3,146) 43,093 86,095 708,186 (553,643) — — 62,455 (104,062) 7,149 (588,101) 62,591 — (11,645) — 375,000 (619,753) 150,000 — — 197,688 (156,546) (2,665) 117,420 62,374 $ 179,794 83,860 121,687 $ 38,468 112,250 Issuance of common stock and options and liabilities assumed in Patina Merger — 3,783,306 — The accompanying notes are an integral part of these financial statements 65 Noble Energy, Inc. and Subsidiaries Consolidated Statements of Shareholders’ Equity (in thousands) Common Stock $ 404,960 — 11,910 Capital in Excess of Par Value $ 228,728 — 50,681 Deferred Compensation — Restricted Stock $ — — — Accumulated Other Comprehensive Loss $ (10,886) — — Treasury Stock at Cost Retained Earnings $ (75,956) $ 526,727 328,710 — — — Total Shareholders’ Equity $ 1,073,573 328,710 62,591 December 31, 2003 Net income Exercise of stock options Tax benefits related to exercise of stock options Issuance of restricted stock, net Amortization of restricted stock Cash dividends ($.10 per share) Oil and gas cash flow hedges: Realized amounts reclassified into earnings Unrealized change in fair value Interest rate cash flow hedges: Realized amounts reclassified into earnings Unrealized change in fair value Net change in minimum pension liability and other Comprehensive loss December 31, 2004 Net income Patina Merger Exercise of stock options Tax benefits related to exercise of stock options Issuance of restricted stock, net Amortization of restricted stock Cash dividends ($0.15 per share) Rabbi trust shares sold Other Oil and gas cash flow hedges: Realized amounts reclassified into earnings Unrealized amounts reclassified into earnings Unrealized change in fair value Interest rate cash flow hedges: Realized amounts reclassified into earnings Net change in minimum pension liability and other Comprehensive income loss December 31, 2005 Net income Adoption of SFAS 123(R), net of tax Stock—based compensation expense Exercise of stock options Tax benefits related to exercise of stock options Issuance of restricted stock, net Cash dividends ($0.275 per share) Purchases of treasury stock Rabbi trust shares sold Oil and gas cash flow hedges: Realized amounts reclassified into earnings Unrealized amounts reclassified into earnings Unrealized change in fair value Interest rate cash flow hedges: Realized amounts reclassified into earnings Net change in minimum pension liability and other Comprehensive income Adoption of SFAS 158, net of tax December 31, 2006 — 282 — — — — — — — 9,791 2,258 — — — — — — — $ 417,152 $ — $ $ 291,458 — 1,576,799 54,644 185,568 13,013 — 578 — — — — — — — — — 15,407 6,506 — — 90 335 — — — — — $ 616,311 $ — $ — — 12,829 $ 1,945,239 — (5,288) 11,816 49,784 — 220 — — — — — — — — 26,106 (220) — — 13,611 — — — — — — (2,540) 869 — — — — — — $ (1,671) $ — — — — (7,084) 3,467 — — — — — — — — $ (5,288) $ — 5,288 — — — — — — — — — — — — — — — — 39,840 (39,161) 348 (2,417) (2,511) (3,901) $ (14,787) $ — — — — — — — — — 154,500 33,638 (945,033) 492 (12,309) (768,712) $ (783,499) $ — — — — — — — — — — — — — — — — (11,645) — — — — — 9,791 — 869 (11,645) 39,840 (39,161) 348 (2,417) (2,511) $ (75,956) $ 843,792 — $ 645,720 $ — — (73,203) — $ 1,459,988 $ 645,720 1,689,164 67,657 — — — — 683 — — — — — — — — — (23,655) — — — — — — 15,407 — 3,467 (23,655) 773 335 154,500 33,638 (945,033) 492 — (12,309) $ (148,476) $ 1,465,857 — $ 678,428 $ — — — — — — $ 3,090,144 $ 678,428 — 11,816 62,613 — — — — — — — — (398,675) 35,708 — — (48,924) — — — — — — — 26,106 — (48,924) (398,675) 49,319 145,035 264,520 249,974 637 16,225 — — — — — 145,035 264,520 249,974 637 16,225 676,391 (33,401) $ (140,509) — $ 629,360 — $ 2,041,048 — $ — — — $ (511,443) $ 2,095,361 (33,401) $ 4,113,817 The accompanying notes are an integral part of these financial statements 66 Noble Energy, Inc. and Subsidiaries Consolidated Statements of Comprehensive Income (Loss) (in thousands) Net income Other comprehensive income (loss) items Oil and gas cash flow hedges: Realized amounts reclassified into earnings Less tax provision Unrealized amounts reclassified into earnings Less tax provision Unrealized change in fair value Less tax provision Interest rate cash flow hedges: Realized amounts reclassified into earnings Less tax provision Unrealized change in fair value Less tax provision Net change in minimum pension liability and other Less tax provision Other comprehensive income (loss) Comprehensive income (loss) Year ended December 31, 2005 $ 645,720 2006 $ 678,428 2004 $328,710 232,428 (87,393) 423,910 (159,390) 351,637 (101,663) 237,692 (83,192 ) 51,750 (18,112 ) (1,453,897 ) 508,864 758 (121) — — 25,002 (8,777) 757 (265 ) — — (18,937 ) 6,628 61,292 (21,452) — — (60,248) 21,087 535 (187) (3,718) 1,301 (3,863) 1,352 676,391 (768,712 ) (3,901) $ 1,354,819 $ (122,992 ) $ 324,809 The accompanying notes are an integral part of these financial statements 67 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Dollar amounts in tables, unless otherwise indicated, are in thousands, except per share amounts) Note 1—Nature of Operations Noble Energy, Inc. (“Noble Energy”, “we” or “us”) is an independent energy company engaged in the exploration, development, production and marketing of crude oil and natural gas. We have exploration, exploitation and production operations domestically and internationally. 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. Note 2—Summary of Significant Accounting Policies Basis of Presentation and Consolidation—Accounting policies used by Noble Energy and its subsidiaries conform to accounting principles generally accepted in the United States. Significant policies are discussed below. Our consolidated accounts include those of Noble Energy and its wholly-owned subsidiaries. We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. We carry equity method investments at our share of net assets plus loans and advances. Differences in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over the remaining useful life of the underlying assets. All significant intercompany balances and transactions have been eliminated upon consolidation. Use of Estimates—The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of crude oil and natural gas reserves are the most significant of our estimates. All of the reserve data in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. 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. See Supplemental Oil and Gas Information. Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment and goodwill; asset retirement obligations; valuation allowances for receivables and deferred income tax assets; valuation of derivative instruments; and assets and obligations related to employee benefits. Actual results could differ significantly from those estimates. Common Stock Split—On August 17, 2005, our Board of Directors approved a two-for-one split of Noble Energy common stock that was effected in the form of a stock dividend. The stock dividend was distributed on September 14, 2005 to shareholders of record as of August 31, 2005. All share and per share data except par value have been adjusted to reflect the effect of the stock split for all periods presented. Foreign Currency—The U.S. dollar is considered the functional currency for each of our international operations. Transactions that are completed in a foreign currency are remeasured into U.S. dollars and recorded in the financial statements at prevailing foreign exchange rates. Transaction gains or losses were not material in any of the periods presented and are included in other expense, net on the statements of operations. 68 Allowance for Doubtful Accounts—We routinely assess the recoverability of all material trade and other receivables to determine their collectibility. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. Changes in the allowance for doubtful accounts are as follows: Balance at beginning of period Charged to expense Collections of amounts previously charged to expense Deductions Balance at end of period Year ended December 31, 2004 2005 2006 (in thousands) $13,093 14,688 (2,700) (6,437 ) $18,644 $ 6,255 6,838 — — $ 13,093 $ 18,644 19,404 (2,607) (906) $ 34,535 Increases in the allowance of $15 million, $11 million and $5 million for 2006, 2005 and 2004, respectively, were made to cover potentially uncollectible balances related to Ecuador power operations and are included in electricity generation expense. Certain entities purchasing electricity in Ecuador have been slow to pay amounts due us. We are pursuing various strategies to protect our interests including international arbitration and litigation. The allowance was increased by $2 million, $1 million and $1 million in 2006, 2005 and 2004, respectively, to record various provisions related to our domestic business. In addition, in 2005 the allowance was decreased due to the final write-off of certain allowances recorded in prior years ($6 million). Materials and Supplies Inventories—Materials and supplies inventories, consisting principally of tubular goods and production equipment, are stated at the lower of cost or market, with cost being determined by the first-in, first-out method. Property, Plant and Equipment— Successful Efforts Method—We account for crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties are amortized to operations by the unit-of-production method based on proved developed crude oil and natural gas reserves on a property-by-property basis as estimated by our engineers. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated depreciation, depletion and amortization (“DD&A”) are eliminated from the accounts and the resulting gain or loss is recognized. Repairs and maintenance are expensed as incurred. Proved Property Impairment—In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we review proved oil and gas properties and other long-lived assets for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or sustained decrease in commodity prices. We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. When the carrying amounts of the properties exceed their estimated undiscounted future cash flows, the carrying amount of the properties is written down to their estimated fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity prices and operating expenses, timing of future production, future capital expenditures and a risk-adjusted discount rate. We recorded impairments of approximately $9 million in 2006, $5 million in 2005 and $10 million in 2004, primarily related to downward reserve revisions on domestic properties. 69 Unproved Property Impairment—We also periodically assess individually significant unproved properties for impairment of value and recognize a loss at the time of impairment by providing an impairment allowance. Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil and natural gas reserves, future commodity prices and future costs to extract the reserves. Cash flow estimates related to probable and possible reserves are reduced by additional risk-weighting factors. Other individually insignificant unproved properties are amortized on a composite method based on our experience of successful drilling and average holding period. During 2006, 2005, and 2004, we recorded impairments of individually significant unproved properties of approximately $1 million, $3 million, and $4 million, respectively, in exploration expense. Properties Acquired in Business Combinations—In determining the fair values of proved and unproved properties acquired in business combinations, we prepare estimates of crude oil and natural gas reserves. We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net revenues. For the fair value assigned to proved reserves, the future net revenues are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors. Exploration Costs—Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive deepwater Gulf of Mexico or international projects, it may take us more than one year to evaluate the future potential of the exploration well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities and access to such permits and approvals and believe they will be obtained. Management assesses the status of suspended exploratory well costs on a quarterly basis. See Note 5—Capitalized Exploratory Well Costs. Other Property—Other property includes autos, trucks, airplane, office furniture and computer equipment and other fixed assets. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets or group of assets, which range from five to seven years. 70 Balance Sheet and Statement of Operations Information Other balance sheet information is as follows: Other Current Assets Derivative instruments Materials and supplies inventories Prepaid expenses and other Total Other Noncurrent Assets Equity method investments Rabbi trust mutual fund investments Probable insurance claims Derivative instruments Intangible asset related to employee benefit plans Other assets Total Other Current Liabilities Accrued and other current liabilities Interest payable Total Other Noncurrent Liabilities Deferred compensation liabilities Accrued benefit costs Other Total Other revenues and other expense, net consist of the following: Other Revenues Electricity sales Gathering, marketing and processing Total Other Expense, net Electricity generation (1) Gathering, marketing and processing Deferred compensation expense Impairment of operating assets Other Total (1) See “Allowance for Doubtful Accounts” above. 71 December 31, 2005 2006 (in thousands) $ 35,242 46,973 44,973 $ 127,188 $ 29,258 33,802 56,568 $119,628 $ 373,372 100,767 46,500 2,862 — 44,531 $ 568,032 $420,362 39,676 112,800 17,259 3,827 46,814 $640,738 December 31, 2006 2005 (in thousands) $ 219,885 15,507 $ 235,392 $ 137,428 11,340 $ 148,768 $ 173,253 58,491 42,976 $ 274,720 $ 141,185 51,547 87,239 $ 279,971 2006 Year ended December 31, 2005 (in thousands) 2004 $71,603 27,876 $99,479 $74,228 55,261 $129,489 $58,627 49,250 $107,877 $59,494 18,664 28,189 8,525 18,680 $133,552 $53,137 28,067 17,918 5,368 3,917 $108,407 $47,788 37,699 — 9,885 4,991 $100,363 Goodwill—Goodwill represents the excess of the cost of an acquired entity over the net amounts assigned to assets acquired and liabilities assumed. We account for goodwill in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). Goodwill is not amortized to earnings but is tested annually during the fourth quarter or whenever events or changes in circumstances indicate that the carrying value may not be recoverable. During 2006, goodwill was increased by $38 million related to the acquisition of U.S. Exploration Holdings, Inc. (“U.S. Exploration”). It was reduced by $100 million allocated to the sale of Gulf of Mexico shelf properties and $20 million related to tax benefits associated with the exercise of fully-vested stock options assumed in conjunction with our merger (the “Patina Merger”) with Patina Oil & Gas Corporation (“Patina”) and other tax adjustments. See Note 3— Acquisitions and Divestitures. Income Taxes—Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax returns or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was passed. Fair Value of Financial Instruments— The following methods and assumptions were used to estimate the fair values for each class of financial instruments. The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between two willing parties. Cash, Cash Equivalents, Accounts Receivable and Accounts Payable—The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. Long-Term Debt—The fair value of long-term debt is estimated based on the quoted market prices for the same or similar issues. The carrying amounts and estimated fair values of debt instruments were as follows: Long-term debt See Note 7—Debt. December 31, 2006 2005 Carrying Amount Fair Value Carrying Amount Fair Value (in thousands) $1,800,810 $ 1,852,890 $2,030,533 $2,097,060 Derivative Instruments—The fair value estimates for commodity fixed price swaps, basis swaps and costless collars use market quotes and discount rates to determine discounted expected future cash flows as of the date of the estimate. See Note 12 — Derivative Instruments and Hedging Activities. Capitalization of Interest—We capitalize interest costs associated with the development and construction of significant properties or projects to bring them to a condition and location necessary for their intended use, which for crude oil and natural gas assets is at first production from the field. Interest is capitalized using an interest rate equivalent to the average rate we pay on long-term debt, including the credit facility and bonds. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis. Capitalized interest totaled $13 million, $9 million and $8 million for 2006, 2005 and 2004, respectively. 72 Statement of Cash Flows—For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash on hand and investments purchased with original maturities of three months or less. Basic Earnings Per Share and Diluted Earnings Per Share—Basic earnings per share (“EPS”) of common stock have been computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of common stock includes the effect of outstanding common stock equivalents. The following table summarizes the calculation of basic EPS and diluted EPS components: 2006 Year ended December 31, 2005 2004 Income Shares (in thousands, except per share amounts) Income Income Shares Shares Net income available to common shareholders Basic EPS Net income available to common $ 678,428 3.86 $ 175,707 $645,720 4.20 $ 153,773 $328,710 2.82 $ 116,550 shareholders $ 678,428 175,707 $645,720 153,773 $328,710 116,550 Effect of dilutive stock options and restricted stock awards Adjusted net income and shares Diluted EPS — $ 678,428 3.79 $ 3,337 179,044 — $645,720 4.12 $ 2,986 156,759 — $328,710 2.78 $ 1,902 118,452 The table below reflects the number of options, restricted stock and shares of Noble Energy common stock held in a rabbi trust excluded from the EPS calculation above for 2006 and 2005, as they were antidilutive. There were no antidilutive items for 2004. Year ended December 31, 2005 Stock options Restricted stock Noble Energy common stock held in rabbi trust Total excluded from diluted EPS calculation Year ended December 31, 2006 Stock options Restricted stock Noble Energy common stock held in rabbi trust Total excluded from diluted EPS calculation Weighted Outstanding Weighted Average Awards and Shares Exercise Price (in thousands, except per share amounts) 48 — 1,360 1,408 675 14 1,262 1,951 $41.47 — — $45.19 — — Accounting for Stock-Based Compensation—Through December 31, 2005, we accounted for stock-based compensation plans under the intrinsic value recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), and related Interpretations. As of January 1, 2006, we adopted SFAS No. 123(R), “Share-Based Payment” (“SFAS 123(R)”). SFAS 123(R) revised SFAS No. 123, “Accounting for Stock-Based Compensation” and nullified APB 25 and its related implementation guidance. SFAS 123(R) requires companies to measure the grant-date fair value of stock options and other stock-based compensation issued to employees and expense the fair value over the requisite service period of the award. SFAS 123(R) became effective for interim or annual periods beginning January 1, 2006. In accordance with the modified prospective transition method, prior period 73 amounts have not been restated. See Note 9—Stock Option and Restricted Stock Plans, Incentive Plan and Stockholder Rights. Accounting for Defined Benefit Pension and Other Postretirement Plans—In September 2006, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (“SFAS 158”). SFAS 158 requires plan sponsors of defined benefit pension and other postretirement benefit plans to recognize the funded status of their postretirement benefit plans in the statement of financial position, measure the fair value of plan assets and benefit obligations as of the date of the fiscal year-end statement of financial position, and provide additional disclosures. We adopted SFAS 158 as of December 31, 2006, and the effect of adoption on our financial condition at December 31, 2006 has been included in our consolidated balance sheets. The effect of adoption included a $25 million decrease in other assets, a $28 million increase in accrued benefit costs, a $20 million decrease in deferred tax liabilities and a $33 million (net of tax of $20 million) decrease in shareholders’ equity (effected by increasing AOCL). Adoption of SFAS 158 had no effect on our results of operations for the year ended December 31, 2006. SFAS 158’s provisions regarding the change in the measurement date of postretirement benefit plans are not applicable as we already use a measurement date of December 31. See Note 11—Employee Benefit Plans. Adoption of Staff Accounting Bulletin No. 108—In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108 (“SAB 108”). SAB 108 expresses the SEC staff’s views regarding the process of quantifying financial statement misstatements. The SEC staff believes registrants should quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. The SEC staff will not object if a registrant records a one-time cumulative effect adjustment to correct errors existing in prior years that previously had been considered immaterial, quantitatively and qualitatively, based on appropriate use of the registrant’s approach. SAB 108 describes the circumstances where this would be appropriate as well as required disclosures to investors. SAB 108 is effective for fiscal years ending on or after November 15, 2006. We adopted SAB 108 as of December 31, 2006. Adoption of SAB 108 had no effect on our financial position or results of operations. Treasury Stock—We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity. Revenue Recognition and Imbalances—We record revenues from the sales of crude oil and natural gas when the product is delivered at a fixed or determinable price, title has transferred and collectibility is reasonably assured. When we have an interest with other producers in properties from which natural gas is produced, we use the entitlements method to account for any imbalances. Imbalances occur when we sell more or less product than we are entitled to under our ownership percentage. Revenue is recognized only on the entitlement percentage of volumes sold. Any amount sold by us in excess of our entitlement is treated as a liability and is not recognized as revenue. Any amount of entitlement in excess of the amount sold by us is recognized as revenue and a receivable is accrued. We record the noncurrent portion of the liability in other deferred credits and noncurrent liabilities, and the current portion of the liability in other current liabilities. We record the noncurrent portion of the receivable in other assets and the current portion of the liabilities were $17 million and $35 million at receivable December 31, 2006 and 2005, respectively. Imbalance receivables were $18 million and $18 million at December 31, 2006 and 2005, respectively. in other current assets. Imbalance Revenues derived from electricity generation are recognized when power is transmitted or delivered, the price is fixed and determinable and collectibility is reasonably assured. 74 Noble Energy Marketing, Inc. (“NEMI”), a wholly-owned subsidiary, marketed approximately 43% of our domestic natural gas production in 2006. NEMI also engages in the purchase and sale of third-party crude oil and natural gas. We record third-party sales, net of cost of goods sold, as gathering, marketing and processing revenues when the product is delivered or the contract is net settled at a fixed or determinable price, title has transferred and collectibility is reasonably assured. Derivative Instruments and Hedging Activities—We use various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of commodity price fluctuations. Such instruments include variable to fixed NYMEX price swaps, costless collars and variable to fixed price basis swaps. Although these derivative instruments expose us to credit risk, we monitor the creditworthiness of counterparties and believe that losses from nonperformance are unlikely to occur. However, we are not able to predict sudden changes in counterparties’ creditworthiness. We account for derivative instruments and hedging activities in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities, as amended,” (“SFAS 133”). SFAS 133 established accounting and reporting standards requiring every derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded on the balance sheet as either an asset or liability measured at fair value. SFAS 133 requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Under cash flow hedge accounting, gains and losses are reflected in shareholders’ equity as accumulated other comprehensive income or loss (“AOCL”) until the hedged transaction is recognized in earnings. The derivative’s gains and losses are then offset against related results on the hedged transaction on the statements of operations. Gains and losses from derivative instruments related to crude oil and natural gas production and which qualify for hedge accounting treatment are recorded in oil and gas sales in the consolidated statements of operations upon sale of the associated products. SFAS 133 also requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Only derivative instruments that are expected to be highly effective in offsetting anticipated gains or losses on the hedged cash flows and that are subsequently documented to have been highly effective can qualify for hedge accounting. Effectiveness must be assessed both at inception of the hedge and on an ongoing basis. Any ineffectiveness in hedging instruments whereby gains or losses do not exactly offset anticipated gains or losses of hedged cash flows is measured and recognized in earnings in the period in which it occurs. We assess hedge effectiveness quarterly based on total changes in the derivative’s fair value and using regression analysis. A hedge is considered effective if the resulting R-squared is above 80% and the slope is 80 - 120. We record hedge ineffectiveness in loss on derivative instruments. See Note 12—Derivative Instruments and Hedging Activities. Related Party Transaction—Noble Energy entered into a consulting agreement with a former officer of Patina who now serves as a member of our Board of Directors. Pursuant to the consulting agreement, the Board member served as a consultant to the combined company for a period of 12 months following the merger (May 16, 2005) in exchange for a monthly retainer of $50,000. We paid total consulting fees of $225,806 during 2006 and $374,194 during 2005. Contingencies—We are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. We self-insure the medical and dental coverage provided to certain employees, certain workers’ compensation and the first $1.0 million of general liability coverage. Liabilities are accrued for self-insured claims, or when estimated losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss. 75 Electricity Generation—Ecuador Integrated Power Project—Through our subsidiaries, EDC Ecuador Ltd. and MachalaPower Cia. Ltda., we have a 100% ownership interest in an integrated natural gas-to-power project. The project includes the Amistad natural gas field, offshore Ecuador, which supplies natural gas to fuel the Machala power plant located in Machala, Ecuador. The revenues attributable to the natural gas- to-power project are included in “Other revenues” and the expenses (including DD&A) are included in “Other expense, net.” Concentration of Market Risk—During 2006, Trafigura Beheer B.V. was the largest single non-affiliated purchaser of production and accounted for 28% of crude oil sales, or 15% of total oil and gas sales. Shell Trading (US) Company accounted for 18% of 2006 crude oil sales or 10% of 2006 total oil and gas sales. During 2005, Glencore Energy U.K., Ltd. was the largest single non-affiliated purchaser of production and accounted for 24% of crude oil sales, or 11% of total oil and gas sales. During 2004, Marathon International Petroleum Supply Company (G.B.) Limited (“MIPSCO”), an affiliate of the operator of the Alba field in Equatorial Guinea, Marathon E. G. Production Ltd., accounted for 25% of crude oil sales, or 12% of total oil and gas sales. We believe the loss of any one purchaser would not have a material effect on our financial position or results of operation since there are numerous potential purchasers of our production. Reclassification—Certain reclassifications have been made to the 2005 and 2004 consolidated financial statements to conform to the 2006 presentation. These reclassifications are not material to the financial statements. Note 3—Acquisitions and Divestitures Sale of Gulf of Mexico Shelf Properties—On July 14, 2006, we completed the sale of our Gulf of Mexico shelf properties. The sale included essentially all of our properties in the Gulf of Mexico shelf except for our interest in the Main Pass area, which we have retained. Pretax cash proceeds from the sale totaled $506 million including proceeds received from parties who exercised preferential rights to purchase certain minor properties. We recorded a pretax gain of $211 million from the sale. The net book value of assets sold totaled $229 million. Asset retirement obligations of $45 million, related to the Gulf of Mexico shelf properties, were also included in the sale. In accordance with SFAS 142, we allocated $100 million of our domestic reporting unit goodwill to the sale. The asset disposition did not qualify for accounting as discontinued operations, in accordance with EITF 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations”. This is due to the migration of our investment and operations to the Gulf Coast onshore and deepwater Gulf of Mexico areas. As a result of the sale, we recognized a pretax charge of $399 million related to cash flow hedges which were reclassified from AOCL to earnings during the second quarter 2006. This reclassification reflected the mark-to-market value of the cash flow hedges that related to Gulf of Mexico shelf production. See Note 12—Derivative Instruments and Hedging Activities. Purchase of U.S. Exploration Holdings, Inc.—On March 29, 2006, we purchased the common stock of U.S. Exploration, a privately held corporation located in Billings, Montana, for a cash purchase price of $412 million plus liabilities assumed. U.S. Exploration’s reserves and production are located in Colorado’s Wattenberg field. The total purchase price was allocated preliminarily to the assets acquired and the liabilities assumed based on fair values at the acquisition date as follows: • $413 million to proved oil and gas properties; • $131 million to unproved oil and gas properties; • $38 million to goodwill; and • $172 million to deferred income taxes. 76 Certain data necessary to complete the final purchase price allocation is not yet available, and includes, but is not limited to, final appraisals of assets acquired and liabilities assumed and final tax returns that provide the underlying tax bases of assets and liabilities. We expect to complete the purchase price allocation during the twelve-month period following the acquisition date, during which time the preliminary allocation will be revised and goodwill will be adjusted, if necessary. Patina Merger—On May 16, 2005, we completed the Patina Merger. Patina was an independent energy company engaged in the acquisition, development and exploitation of crude oil and natural gas properties within the continental U.S. Patina’s properties and oil and gas reserves are principally located in relatively long-lived fields with established production histories. The properties are primarily concentrated in the Wattenberg field of Colorado’s D-J Basin, the Mid-continent region of western Oklahoma and the Texas Panhandle, and the San Juan Basin in New Mexico. We acquired the common stock of Patina for a total purchase price of approximately $4.9 billion, which was comprised primarily of cash and Noble Energy common stock, plus liabilities assumed. In exchange for Patina’s common stock and stock options held by Patina’s employees, we issued 55.7 million shares of stock valued at $1.7 billion, issued options valued at $105 million, paid $1.1 billion in cash to Patina shareholders and assumed debt of $611 million and deferred taxes of $1.1 billion. The total purchase price was allocated to the assets acquired and the liabilities assumed based on fair values at the merger date as follows: • $2.642 billion to proved oil and gas properties; • $1.068 billion to unproved oil and gas properties; • $875 million to goodwill; and • $1.108 billion to deferred income taxes. The amount of goodwill recorded in the Patina Merger has been reduced by $27 million ($15 million in 2006) for tax benefits associated with the exercise of fully-vested stock options assumed in conjunction with the merger. Pro Forma Financial Information—The following pro forma condensed combined financial information for the years ended December 31, 2005 and 2004 was derived from our historical financial statements and those of Patina and gives effect to the merger as if it had occurred on January 1, 2004. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have occurred had the merger taken place as of the dates indicated and is not intended to be a projection of future results. Revenues Income from continuing operations Net income Earnings per share: Basic Diluted Note 4—Effect of Gulf Coast Hurricanes Year ended December 31, 2005 2004 (in thousands, except per share amounts) $ 2,434,677 693,091 693,091 $ 1,913,786 387,566 402,426 $ $ 4.03 3.98 2.38 2.30 2005 Hurricane Activity—In August 2005, Hurricane Katrina moved through the Gulf of Mexico and caused the loss of the Main Pass 306D platform. The net book value of the platform was $15 million. Clean-up costs associated with the damage resulted in an increase to the Main Pass 306D asset retirement 77 obligation of $66 million. We accounted for the net book value of the destroyed platform and the increase in asset retirement costs as a loss on involuntary conversion. As of December 31, 2006, we have incurred $79 million (cumulative) in costs related to Hurricane Katrina damage, $16.5 million of which has been approved and reimbursed by our insurance carriers. During 2005, we were notified by one of our insurance carriers that its maximum exposure limit for losses incurred during Hurricane Katrina had been reached and that, consequently, our final insurance recovery will be limited. As of December 31, 2006, we have recorded probable insurance claims of $64 million, the estimated remaining recovery for losses sustained from Hurricane Katrina. Total Hurricane Katrina costs for clean-up, repair and redevelopment are currently estimated at approximately $183 million. We expect to complete clean-up work during 2007 and receive final reimbursements thereafter. Hurricane Rita struck the Gulf Coast in September 2005 and caused minor damage to our Gulf of Mexico assets. As of December 31, 2006, based upon work completed, we have incurred $8 million (cumulative) in costs related to Hurricane Rita damage. We expect our insurance carrier to approve and reimburse these costs subject to our $1 million deductible. 2004 Hurricane Activity—In September 2004, Hurricane Ivan caused infrastructure damage at Main Pass 293/305/306. The net book value of the property was $24 million. The remediation work began second quarter 2005, and we commenced production from undamaged platforms in the third quarter 2005. As of December 31, 2006, based upon work completed, we have incurred $203 million (cumulative) in costs related to Hurricane Ivan damage. Our insurance carriers have approved and reimbursed $176 million of these costs with the balance pending subsequent review and approval. We expect to complete clean-up work during 2007 and receive final reimbursements thereafter. Amounts related to involuntary conversions caused by Hurricanes Katrina and Ivan are as follows: Net book value of assets impaired or destroyed Increase in asset retirement obligation related to hurricane damage Loss on involuntary conversion of assets Income from probable insurance claims Net loss on involuntary conversion of assets Year ended December 31, $ 2005 14,500 66,000 80,500 $ 2004 23,978 130,000 153,978 (79,500) (152,978) $ 1,000 $ 1,000 Assets (liabilities) related to the hurricane insurance recoveries and included in the consolidated balance sheets consist of the following: Probable insurance claims—current Other assets (long-term portion of probable insurance claims) Total expected hurricane insurance recoveries Asset retirement obligations—current Asset retirement obligations—long-term Total asset retirement obligations related to hurricane damage December 31, 2006 2005 (in thousands) $ 101,233 46,500 $ 147,733 $ $ 142,311 112,800 255,111 $ $ (65,120 ) $ — (65,120 ) $ (42,016) (121,800) (163,816) 78 Note 5—Capitalized Exploratory Well Costs We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial, in which case the well costs are immediately charged to exploration expense. Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period: Capitalized exploratory well costs, beginning of period Additions to capitalized exploratory well costs pending determination of proved reserves Reclassified to property, plant and equipment based on determination of proved reserves Capitalized exploratory well costs charged to expense Capitalized exploratory well costs, end of period Year ended December 31, 2004 2005 2006 (in thousands) $ 62,724 $ 29,375 $ 35,228 62,580 33,671 45,011 (16,762) (687) $ 80,359 (52,138 ) (9,029) $ 35,228 (1,061) (10,601) $ 62,724 The following table provides an aging of capitalized exploratory well costs (suspended well costs) based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling: Capitalized exploratory well costs that have been capitalized for a period of one year or less Capitalized exploratory well costs that have been capitalized for a period greater than one year after completion of drilling Balance at end of period Number of projects that have exploratory well costs that have been capitalized for a period greater than one year after completion of drilling 2006 December 31, 2005 (in thousands) 2004 $ 58,493 $35,228 $ 44,986 21,866 $ 80,359 — $35,228 17,738 $ 62,724 4 — 4 Included in the capitalized exploratory well costs capitalized for more than one year at December 31, 2006 were four projects. One of the projects, Blocks O and I, which includes approximately $20 million, is located offshore Equatorial Guinea. Since drilling the initial well, additional seismic work has been completed and current plans are to drill an appraisal well in 2007 to further evaluate this apparent discovery. The remaining three projects, which total approximately $2 million, are all located in Alabama and are currently waiting on sales lines. The four projects as of December 31, 2004 that had exploratory costs greater than one year were reclassified to property, plant and equipment during 2005 when proved reserves were recorded. Note 6—Asset Retirement Obligations Asset retirement obligations consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. An asset retirement obligation and the related asset retirement cost are recorded when an asset is first constructed or purchased. The asset retirement cost is determined and discounted to present value using a credit-adjusted risk-free rate. After initial recording the liability is increased for the passage of time, with the increase being reflected as accretion 79 expense in the statement of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts continue to be amortized over the useful life of the related long-lived asset. Changes in asset retirement obligations were as follows: Asset retirement obligations, beginning of period Liabilities incurred in current period Liabilities transferred in sale of Gulf of Mexico shelf properties Liabilities settled in current period Revisions Accretion expense Asset retirement obligations, end of period Current portion Noncurrent portion Year ended December 31, 2006 (in thousands) $ 338,871 4,086 (44,521 ) (150,847 ) 37,803 10,797 $ 196,189 $ 68,500 127,689 Revisions during 2006 resulted from changes in estimated timing of actual abandonment and overall cost increases. The ending aggregate carrying amount at December 31, 2006 included $65 million, which we expect to be reimbursed by insurance, related to damage to the Main Pass assets caused by Hurricanes Ivan and Katrina in the Gulf of Mexico. See Note 4—Effect of Gulf Coast Hurricanes. Note 7—Debt Our debt consists of the following: $2.1 billion Credit Facility, due December 2011 5 ¼% Senior Notes, due April 2014 7 ¼% Notes, due October 2023 8% Senior Notes, due April 2027 7 ¼% Senior Debentures, due August 2097 Term Loans, due January 2009 Outstanding debt Unamortized discount Long-term debt December 31, 2006 2005 Debt Interest Rate Debt Interest Rate (in thousands, except percentages) 5.69 5.25 7.25 8.00 7.25 — $ 1,155,000 200,000 100,000 250,000 100,000 — 1,805,000 (4,190) $1,800,810 4.82 5.25 7.25 8.00 7.25 5.23 $ 1,280,000 200,000 100,000 250,000 100,000 105,000 2,035,000 (4,467) $2,030,533 All of our long-term debt is senior unsecured debt and is, therefore, pari passu with respect to the payment of both principal and interest. The indenture documents of each of the 7¼% Notes, the 8% Senior Notes and the 7¼% Senior Debentures provide that we may prepay the instruments by creating a defeasance trust. The defeasance provisions require that the trust be funded with securities sufficient, in the opinion of a nationally recognized accounting firm, to pay all scheduled principal and interest due under the respective agreements. Interest on each of these issues is payable semi-annually. Credit Facility—In November 2006, we amended our $2.1 billion unsecured five-year revolving credit facility (the “Credit Facility”). The Credit Facility, as amended, (i) extends the maturity date of the Credit Facility to December 9, 2011, (ii) provides for Credit Facility fee rates that range from 5 basis points to 15 80 basis points per year depending upon our credit rating, (iii) makes available swingline loans up to an aggregate amount of $300 million and (iv) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 20 basis points to 70 basis points depending upon our credit rating and utilization of the Credit Facility. The Credit Facility contains customary representations and warranties and affirmative and negative covenants. The amendment to the Credit Facility eliminated the financial covenant requiring a 4.0 to 1.0 ratio of Earnings Before Interest, Taxes, Depreciation and Exploration Expense to interest expense. However, the Credit Facility continues to require that our total debt to capitalization ratio, expressed as a percentage, not exceed 60% at any time. A violation of this covenant could result in a default under the Credit Facility, which would permit the participating banks to restrict our ability to access the Credit Facility and require the immediate repayment of any outstanding advances under the Credit Facility. The Credit Facility is with certain commercial lending institutions and is available for general corporate purposes. Certain lenders that are a party to the Credit Facility have in the past performed, and may in the future from time to time perform, investment banking, financial advisory, lending or commercial banking services for us, for which they have received, and may in the future receive, customary compensation and reimbursement of expenses. Debt issuance costs of approximately $3 million remain and are being amortized to expense over the life of the Credit Facility. The Credit Facility does not restrict the payment of dividends on Noble Energy common stock, except, if after giving effect thereto, an Event of Default shall have occurred and be continuing or been caused thereby. Debt Repayments—During 2006, we prepaid the $105 million balance remaining on the Term Loans due 2009. The Term Loans consisted of term loan agreements entered into between our subsidiary, Noble Energy Mediterranean Ltd., and several commercial lending institutions in 2004. The original amount of the Term Loans was $150 million, and we prepaid $45 million of the Term Loans in 2005. The interest rates on the Term Loans were based on a Eurodollar rate plus an effective range of 60 to 130 basis points depending upon our credit rating. Interest was payable periodically based on the tenor of the underlying Eurodollar rate selected at the time of a rate reset. Annual Maturities—Annual maturities of outstanding debt are as follows: 2007 2008 2009 2010 2011 Thereafter Total (in thousands) $ — — — — 1,155,000 650,000 $1,805,000 Short-Term Borrowings—Our credit agreement is supplemented by short-term borrowings under various uncommitted credit lines used for working capital purposes. Uncommitted credit lines may be offered by certain banks from time to time at rates negotiated at the time of borrowing. There were no short-term borrowings outstanding at December 31, 2006 or 2005. 81 Note 8—Income Taxes Components of income before income taxes are as follows: Domestic Foreign Total The income tax provision consists of the following: Year ended December 31, 2005 2006 (in thousands) $ 426,756 541,904 $968,660 $ 402,111 694,106 $ 1,096,217 $ 254,582 258,426 $513,008 2004 Year ended December 31, 2006 2005 2004 Current taxes: Federal State Foreign Total current Deferred taxes: Federal State Foreign Total deferred Total income tax provision Income tax provision associated with continuing operations Income tax provision associated with discontinued operations Total income tax provision (in thousands) $ 79,680 5,577 138,271 223,528 144,143 4,641 45,477 194,261 $417,789 $ 417,789 — $417,789 $ 48,293 — 90,877 139,170 $ 136,858 6,930 39,624 183,412 119,953 14,073 49,744 183,770 $ 322,940 $ 322,940 — $ 322,940 1,192 (702) 23,258 23,748 $ 207,160 $ 199,158 8,002 $ 207,160 A reconciliation of the federal statutory tax rate to the effective tax rate is as follows: Federal statutory rate Effect of: Earnings of equity method investees State taxes, net of federal benefit Difference between U.S. and foreign rates Nondeductible goodwill AJCA repatriation benefit Release of China valuation allowance Other, net Effective rate 2006 2005 2004 (amounts in percentages) 35.0 35.0 35.0 (4.2) 1.3 2.2 3.1 — — 0.7 38.1 (3.2 ) 1.3 3.5 — (3.7 ) — 0.4 33.3 (4.5) 0.7 10.1 — — (2.7) 0.2 38.8 82 Deferred tax assets and liabilities resulted from the following: Deferred tax assets: Foreign loss carryforward Foreign and state income tax accruals Accrued expenses Deferred income Allowance for doubtful accounts Fair value of derivative contracts Postretirement benefits Deferred compensation Foreign tax credits Future foreign tax credits from foreign branch deferred tax liabilities Other Total deferred tax assets Valuation allowance Net deferred tax assets Deferred tax liabilities: Property, plant and equipment, principally due to differences in depreciation, amortization, lease impairment and abandonments Other Total deferred tax liability Net deferred tax asset (liability) $ December 31, 2006 2005 (in thousands) $ 90,387 8,882 22,535 2,666 2,917 185,667 14,578 55,880 10,852 52,855 3,577 450,796 (73,584 ) 377,212 3,431 8,884 39,636 1,916 3,152 448,240 23,011 43,567 5,598 54,882 1,067 633,384 (48,386) 584,998 (2,034,877) (952 ) (2,035,829) (1,546,062) (3,082) (1,549,144) $ (1,658,617 ) $ (964,146) Net deferred tax liabilities were classified in the consolidated balance sheet as follows: 2006 2005 Deferred income tax asset Deferred income tax liability Net deferred tax liability $ (in thousands) 99,835 (1,758,452 ) 237,045 (1,201,191) $ (1,658,617 ) $ (964,146) $ In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that we will realize the benefits of these deductible differences at December 31, 2006. The amount of the deferred tax asset considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced. We have recognized deferred tax assets associated with foreign loss carryforwards. The tax effect of these carryforwards increased from $3 million in 2005 to $90 million in 2006 The foreign loss carryforward related to China was fully utilized in 2005. However, we incurred losses on our project in Suriname and on other new venture activities which are not yet commercial. Therefore, a valuation allowance of $10 million was provided against the tax benefits of those losses. In addition, we incurred a large taxable loss in the UK 83 during 2006 from accelerated write-offs allowed on our Dumbarton field development. No valuation allowance has been provided against this loss carryforward because we expect to utilize it in 2007, and the carryforward period is unlimited. Starting in 2005, we were able to claim a foreign tax credit for U.S. federal income tax purposes and expect to be in a credit position for the next several years. Therefore, we have recorded a deferred tax asset for certain foreign taxes paid in 2005 and 2006 that cannot be claimed as a credit in those years because of limitations imposed by the Internal Revenue Code. A valuation allowance of $7 million has been provided against this deferred tax asset. We have also recorded a deferred tax asset of $53 million for the future foreign tax credits associated with deferred tax liabilities recorded by foreign branch operations. A valuation allowance of $53 million has been provided against this deferred tax asset. Several factors resulted in an increase in our effective tax rate for 2006. The major factor was the allocation of $100 million of nondeductible goodwill to the sale of the Gulf of Mexico shelf properties. In addition, an increase in a deferred tax asset valuation allowance contributed to the increase in the effective rate. At December 31, 2005, we had recorded a deferred U.S. tax asset of $55 million for the future foreign tax credits associated with deferred foreign tax liabilities recorded by our foreign branch operations. The valuation allowance with respect to the deferred U.S. tax asset was $41 million at December 31, 2005. The tax asset was decreased to $53 million during 2006, and the valuation allowance was increased to $53 million due to changes in the forecast of limitations on the ability to claim foreign tax credits. There was also an increase in the UK tax rate during 2006. The UK Finance Act of 2006, enacted on July 19, increased the income tax rate on our UK operations retroactive to January 1, 2006 and increased our income tax provision by approximately $9 million in 2006. Partially offsetting these increases was a benefit from the realization of additional income from equity method investees which is a favorable permanent difference in calculating the income tax expense. The American Jobs Creation Act (“AJCA”), enacted in 2004, created a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing for an 85% dividends-received deduction for certain dividends from controlled foreign corporations. In July 2005, we completed an evaluation of the effects of the repatriation provision, and our Board of Directors approved a plan to repatriate $118 million in earnings of our methanol subsidiary during the third quarter 2005. Because we had provided U.S. tax on most of the methanol subsidiary’s earnings at 35% through December 31, 2004, repatriation under the Act resulted in a net tax benefit of $35 million recorded in the third quarter 2005. We have not recorded U.S. deferred income taxes on the remaining undistributed earnings of foreign subsidiaries as of December 31, 2006. As of December 31, 2006, the accumulated undistributed earnings of the consolidated foreign subsidiaries were approximately $543 million. Upon distribution of these earnings in the form of dividends or otherwise, we may be subject to U.S. income taxes and foreign withholding taxes. It is not practicable, however, to estimate the amount of taxes that may be payable on the eventual remittance of these earnings because of the possible application of U.S. foreign tax credits. Although we are currently claiming foreign tax credits, we may not be in a credit position when any future remittance of foreign earnings takes place. Note 9—Stock Option and Restricted Stock Plans, Incentive Plan and Stockholder Rights As discussed in Note 2—Summary of Significant Accounting Policies, effective January 1, 2006, we adopted the fair value recognition provisions for stock-based awards granted to employees using the modified prospective application method provided by SFAS 123(R). Accordingly, prior period amounts have not been restated. SFAS 123(R) requires companies to recognize in the statement of operations the grant-date fair value of stock options and other stock-based compensation issued to employees and was effective for interim or annual periods beginning January 1, 2006. We recognize the expense of all stock- based awards on a straight-line basis over the employee’s requisite service period (generally the vesting period of the award). 84 We recognized total stock-based compensation expense as follows: Stock-based compensation expense included in: General and administrative expense Exploration expense and other Total stock-based compensation expense Tax benefit recognized Year ended December 31, 2004 2005 2006 (in thousands) $ 10,720 1,096 $ 11,816 $ 4,008 — $ 4,008 $ 4,443 $ 1,403 $ 868 — $ 868 $ 269 As a result of adopting SFAS 123(R) on January 1, 2006, our income before income taxes, net income and earnings per share were lower than if we had continued to account for stock-based compensation under APB 25. The impact on our financial results related to the adoption of SFAS 123(R) is as follows: Decrease in income: Income before taxes Net income Basic earnings per share Diluted earnings per share Year ended December 31, 2006 (in thousands, except (per share amounts) $ 6,248 3,902 0.02 0.02 Prior to the adoption of SFAS 123(R), we presented tax benefits resulting from exercise of stock options or vesting of restricted stock as cash flows from operating activities within our consolidated statements of cash flows. SFAS 123(R) requires the cash flows resulting from the tax benefits resulting from tax deductions in excess of the compensation cost recognized for stock-based awards (excess tax benefits) to be classified as cash flows from financing activities. Tax benefits presented as cash flows from financing activities totaled $26 million in our 2006 consolidated statement of cash flows. This amount would have been presented as cash flows from operating activities if we had continued to account for stock-based compensation under APB 25. In addition, tax benefits of $15 million and $12 million related to the exercise of fully-vested options assumed in the Patina Merger reduced goodwill during 2006 and 2005, respectively. 85 The following table illustrates the effect on net income and earnings per share if we had applied the fair value recognition provisions of SFAS 123(R) to stock-based employee compensation in all periods presented. The actual and pro forma net income and earnings per share for 2006 below are the same since we adopted SFAS 123(R) as of January 1, 2006. The 2006 amounts are presented for comparison to prior years. Net income, as reported Add: Stock-based compensation cost recognized, net of tax Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of tax Pro forma net income Earnings per share: Basic - as reported Basic - pro forma Diluted - as reported Diluted - pro forma Year ended December 31, 2005 2004 (pro forma) 2006 (actual) (in thousands, except per share amounts) $ 645,720 2,605 $ 328,710 599 $ 678,428 7,373 (7,373) $ 678,428 (6,150 ) $ 642,175 (5,752) $ 323,557 $ 3.86 3.86 3.79 3.79 $ 4.20 4.18 4.12 4.10 $ 2.82 2.78 2.78 2.73 Total stock-based employee compensation expense determined under the fair value based method for all awards for 2005 and 2004 has been recalculated using revised expected term assumptions. The impact on pro forma earnings and pro forma earnings per share was not significant. Our stock option and restricted stock plans (the “Plans”) and incentive plan are described below. 1992 Stock Option and Restricted Stock Plan Under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the “1992 Plan”), the Compensation, Benefits and Stock Option Committee of the Board of Directors (the “Committee”) may grant stock options and award restricted stock to officers or other employees of Noble Energy and its subsidiaries. The maximum number of shares of common stock that may be issued under the 1992 Plan is 18,500,000 shares. At December 31, 2006, 8,231,995 shares of common stock were reserved for issuance, including 4,462,143 shares available for future grants and awards, under the 1992 Plan. 1992 Plan Stock Options—Stock options are issued with an exercise price equal to the market price of Noble Energy common stock on the date of grant, and are subject to such other terms and conditions as may be determined by the Committee. Unless granted by the Committee for a shorter term, the options expire ten years from the grant date. Option grants generally vest ratably over a three-year period. 1992 Plan Restricted Stock—Restricted stock awards made under the 1992 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Committee. Restricted Stock awards generally vest over periods of one to three years. 2004 Long-Term Incentive Plan Under the Noble Energy, Inc. 2004 Long-Term Incentive Plan (the “2004 LTIP”), the Committee may make incentive awards to key employees of Noble Energy and its subsidiaries. Incentive compensation is based upon the attainment of specific market and performance goals established by the Committee. Awards may be in the form of stock options or restricted stock or in the form of performance units or other 86 incentive measurements providing for the payment of bonuses in cash, or in any combination thereof, as determined by the Committee in its discretion. Stock options granted and restricted stock awarded under the 2004 LTIP are granted and awarded pursuant to the terms of the 1992 Plan. These awards are accounted for in accordance with the provisions of SFAS 123(R) which provides for the grant-date fair value of the awards to be recognized in the income statement over the service period. Our cash based performance units are accounted for under SFAS No. 5, “Accounting for Contingencies” and are excluded from the provisions of SFAS 123(R). 2005 Stock Plan for Non-Employee Directors The 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (the “2005 Plan”) provides for grants of stock options and awards of restricted stock to non-employee directors of Noble Energy. The 2005 Plan superseded and replaced the 1988 Nonqualified Stock Option Plan for Non-Employee Directors. The total number of shares of common stock that may be issued under the 2005 Plan is 800,000. At December 31, 2006, 785,600 shares of common stock were reserved for issuance, including 715,180 shares available for future grants and awards under the 2005 Plan. 2005 Plan Stock Options—The 2005 Plan provides for the granting to a non-employee director of 11,200 stock options on the date of election to the Board of Directors, annual grants of 2,800 options per non- employee director on February 1 of each year, and discretionary grants by the Board of Directors (up to a maximum of 11,200 options per non-employee director granted in any one year). Options are issued with an exercise price equal to the market price of Noble Energy common stock on the date of grant and may be exercised one year after the date of grant. The options expire ten years from the date of grant. 2005 Plan Restricted Stock—The 2005 Plan also provides for the granting to a non-employee director of 4,800 shares of restricted stock on the date of election to the Board of Directors, annual awards of 1,200 shares of restricted stock per non-employee director on February 1 of each year, and discretionary grants by the Board of Directors (up to a maximum of 4,800 shares of restricted stock per non-employee director awarded in any one year). Restricted stock is restricted for a period of at least one year from the date of grant. 1988 Nonqualified Stock Option Plan The 1988 Nonqualified Stock Option Plan for Non-Employee Directors of Noble Energy, Inc., as amended, (the “1988 Plan”) provided for the issuance of stock options to non-employee directors of Noble Energy. Options issued under the 1988 Plan may be exercised one year after grant and expire ten years from the grant date. The 1988 Plan provided for the granting of a fixed number of stock options to each non-employee director annually (10,000 stock options for the first calendar year of service and 5,000 stock options for each year thereafter) on February 1 of each year. The 1988 Plan was terminated in 2005. No options can be granted under the 1988 Plan after its termination. Patina Stock Option Plans Patina maintained a shareholder approved stock option plan for employees (the “Patina Employee Plan”) that provided for the issuance of options at prices not less than fair market value at the date of grant. Patina also maintained a shareholder approved stock grant and option plan for non-employee directors (the “Patina Directors’ Plan”). The Patina Directors’ Plan provided for stock options to be granted to each non-employee director upon appointment and upon annual re-election thereafter. Upon completion of the Patina Merger, all unvested stock options outstanding under the Patina Employee Plan and the Patina Directors’ Plan became fully vested, and all outstanding options were converted into options to purchase Noble Energy common stock. The Patina options expire five years from the date of grant. See Note 3— Acquisitions and Divestitures. 87 Stock Option Grants The fair value of each option award was estimated on the date of grant using a Black-Scholes-Merton option valuation model that uses the assumptions noted in the following table. The expected term represents the period of time that options granted are expected to be outstanding. The hypothetical midpoint scenario we use considers the actual exercise and post-vesting cancellation history of stock-based compensation historical trends to develop expectations for future periods. Expected volatility represents the extent to which our stock price is expected to fluctuate between the grant date and the anticipated term of the award. We used the historical volatility of Noble Energy common stock for the 5.5-year period ended prior to the date of grant. The risk-free rate is based on a weighting of five and seven year U.S. Treasury securities as of the year ended prior to the date of grant to arrive at an approximated 5.5-year risk free rate of return. The dividend yield represents the value of our stock’s annualized dividend as compared to our stock’s average price for the three-year period ended prior to the date of grant. It is calculated by dividing one full year of our expected dividends by our average stock price over the three-year period ended prior to the date of grant. Assumptions - Stock Option Grants Expected term (in years) Expected volatility Risk-free rate Expected dividend yield A summary of option activity follows: Outstanding at December 31, 2005 Granted Exercised Forfeited Canceled / expired Outstanding at December 31, 2006 Exercisable at December 31, 2006 5.5 2006 2004 2005 (weighted averages) 5.5 5.5 31.8% 21.5 % 21.4% 4.8% 4.6% 0.3% 0.4% 4.7% 0.8% Weighted Weighted Average Average Exercise Price Remaining Contractual Term (years) Aggregate Intrinsic Value (in thousands) $19.21 45.26 16.27 38.40 — $24.24 $20.39 4.7 3.6 $155,715 $140,829 Options 9,319,642 832,719 (3,848,521) (92,090) — 6,211,750 4,869,657 The weighted-average grant-date fair value of options granted during 2006, 2005 and 2004 was $16.09, $12.17, and $9.27, respectively. The total intrinsic value of options exercised during 2006, 2005 and 2004 was $118 million, $78 million, and $66 million, respectively. As of December 31, 2006, there was $11 million of total unrecognized compensation cost related to unvested stock options granted under the Plans. The cost is expected to be recognized over a weighted- average period of 1.4 years. We issue new shares of common stock to settle option exercises. Dividends are not paid on unexercised options. Options exercised during 2006 included 2,929,516 options held by Patina employees which had been converted into options for Noble Energy common stock at the date of the Patina Merger. 88 Restricted Stock Awards Awards of time-vested restricted stock are valued at the price of our common stock at the date of award. The fair values of market based restricted stock awards are estimated on the date of award using a Monte Carlo valuation model that uses the assumptions in the following table. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility represents the extent to which our stock price is expected to fluctuate between now and the award’s anticipated term. We use the historical volatility of Noble Energy common stock for the three-year period ended prior to the date of award. The risk-free rate is based on a three-year period from U.S. Treasury securities as of the year ended prior to the date of award. Assumptions - Market Based Restricted Stock Awards Number of simulations Expected volatility Risk-free rate 2006 100,000 2005 100,000 2004 100,000 28.4% 4.4% 29.6% 3.3 % 37.2% 2.5% A summary of restricted stock activity follows: Restricted stock at December 31, 2005 Awarded Vested Forfeited Outstanding at December 31, 2006 Subject to Service Conditions (shares) 123,246 12,039 (45,472) (16,718) 73,095 Weighted Average Subject to Grant Date Market Fair Value Conditions Weighted Average Grant Date Fair Value $ 33.79 45.45 33.44 33.44 $ 35.85 (shares) 133,515 77,563 — (6,828) 204,250 $ 23.60 39.51 — 34.59 $ 29.27 The total fair value of restricted stock that vested during 2006 was $2 million. As of December 31, 2006, there was $3 million of total unrecognized compensation cost related to unvested restricted stock awarded under the Plans. The cost is expected to be recognized over a weighted- average period of 1.7 years. Common stock dividends accrue on restricted stock grants and are paid upon vesting. We issue new shares of common stock when awarding restricted stock. Stockholder Rights Plan—We adopted a stockholder rights plan on August 27, 1997 designed to assure that our stockholders receive fair and equal treatment in the event of any proposed takeover of Noble Energy and to guard against partial tender offers and other abusive takeover tactics to gain control of Noble Energy without paying all stockholders a fair price. The rights plan was not adopted in response to any specific takeover proposal. Under the rights plan, we declared a dividend of one right (“Right”) on each share of Noble Energy common stock. Each Right will entitle the holder to purchase one one-hundredth of a share of a new Series A Junior Participating Preferred Stock, par value $1.00 per share, at an exercise price of $150 per share. The Rights are not currently exercisable and will become exercisable only in the event a person or group acquires beneficial ownership of 15% or more of Noble Energy common stock. The dividend distribution was made on September 8, 1997, to stockholders of record at the close of business on that date. The Rights will expire on September 8, 2007. 89 Note 10—Additional Shareholders’ Equity Information The following table reflects the activity in shares (as adjusted for the two-for-one stock split, effected in the form of a stock dividend, in third quarter 2005) of Noble Energy common stock and treasury stock: Common Stock: Shares at beginning of period Shares issued in Patina Merger Exercise of common stock options Restricted stock awards, net of forfeitures Shares at end of period Treasury Stock: Shares at beginning of period Shares repurchased Shares issued in Patina Merger Rabbi trust shares sold Shares at end of period Year Ended December 31, 2006 2005 184,893,510 — 3,848,521 66,056 188,808,087 125,144,834 55,670,408 3,903,889 174,379 184,893,510 9,268,932 8,373,400 — (1,067,948) 16,574,384 7,099,952 — 2,189,414 (20,434) 9,268,932 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 and expect to fund the repurchases primarily from cash flows from operations. 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 subject to reevaluation in the event of changes in market conditions. During 2006, we repurchased 8,373,400 shares of our common stock at an aggregate cost of $399 million. We repurchased an additional 1,790,000 shares of common stock at an aggregate cost of $89 million during the period January 1, 2007 through February 12, 2007. 90 Accumulated other comprehensive loss (AOCL) in the shareholders’ equity section of the balance sheet included: December 31, 2003 Cash flow hedges Realized amounts reclassified into earnings Unrealized change in fair value Net change in minimum pension liability and other December 31, 2004 Cash flow hedges Realized amounts reclassified into earnings Unrealized amounts reclassified into earnings Unrealized change in fair value Net change in minimum pension liability and other December 31, 2005 Cash flow hedges Realized amounts reclassified into earnings Unrealized amounts reclassified into earnings Unrealized change in fair value Net change in minimum pension liability and other Adoption of SFAS 158 December 31, 2006 Accumulated Other Comprehensive Loss Oil and Gas Cash Flow Hedges Interest Rate Lock Cash Flow Hedge Minimum Pension Liability and Other Total (in thousands) $ (7,618) $ (2,508) $ (760) $ (10,886) 39,840 (39,161) — (6,939) 154,500 33,638 (945,033) 348 (2,417) — (4,577) 492 — — (763,834) (4,085) — — (2,511) (3,271) 40,188 (41,578) (2,511) (14,787) — — — (12,309 ) (15,580 ) 154,992 33,638 (945,033) (12,309) (783,499) 145,035 264,520 249,974 — — $ (104,305) 637 — — — — $ (3,448) — — — 16,225 (33,401 ) 145,672 264,520 249,974 16,225 (33,401) $ (32,756 ) $ (140,509) The effective income tax rate applied to AOCL was increased from 35% at December 31, 2005 to 37.6% at December 31, 2006. Note 11—Employee Benefit Plans Pension Plan and Other Postretirement Benefit Plans—We have a noncontributory, tax-qualified defined benefit pension plan covering certain domestic employees. The benefits are based on an employee’s years of service and average earnings for the 60 consecutive calendar months of highest compensation. Our funding policy has been to make annual contributions equal to at least the minimum required contribution, but no greater than the maximum deductible for federal income tax purposes. During 2006 we contributed $34 million to the qualified defined benefit pension plan. We also have an unfunded, nonqualified restoration plan that provides the pension plan formula benefits that cannot be provided by the qualified pension plan because of pay deferrals and the compensation and benefit limitations imposed on the pension plan by ERISA. We sponsor other plans for the benefit of our employees and retirees, which include health care and life insurance benefits. We use a December 31 measurement date for the plans. Former Patina employees began participation in the pension plan and the restoration plan on January 1, 2006, with vesting service from their original Patina hire date and credited service for benefit accruals starting January 1, 2006. Additionally, all former Patina employees were covered under the health care and life insurance plans effective January 1, 2006. On December 31, 2006, we adopted SFAS 158 as discussed in Note 2—Summary of Significant Accounting Policies. SFAS 158 requires us to recognize the funded status (the difference between the fair value of plan 91 assets and the benefit obligation) of our defined benefit pension, restoration and other postretirement benefit plans in the December 31, 2006 consolidated balance sheet, with a corresponding adjustment to AOCL, net of tax. The adjustment to AOCL at adoption represents the unrecognized net actuarial loss, unrecognized prior service costs, and unrecognized net transition obligation remaining from the initial adoption of SFAS No. 87, “Employers’ Accounting for Pensions” (“SFAS 87”) and SFAS No. 106, “Employers’ Accounting for Post-Retirement Benefits Other Than Pensions” (“SFAS 106”). These amounts will be subsequently recognized as net periodic benefit cost pursuant to our historical accounting policy for amortizing such amounts. Further, actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic benefit cost in the same periods will be recognized as a component of AOCL. The incremental effects of adopting the provisions of SFAS 158 on our consolidated balance sheet at December 31, 2006 are presented in the following table. The adoption of SFAS 158 had no effect on our consolidated statements of operations for the year ended December 31, 2006, or for any prior period presented, and it will not affect our operating results in future periods. Had we not been required to adopt SFAS 158 at December 31, 2006, we would have recognized an additional minimum liability for the restoration plan pursuant to the provisions of SFAS 87. The effect of recognizing an additional minimum liability for the restoration plan is included in the table below in the column labeled “Prior to Adoption of SFAS 158.” Prior to Adoption of SFAS 158 $ 593,125 9,613,718 (233,246) (1,182,116) (1,778,579) (248,431) (5,466,500) 107,108 (4,147,218) December 31, 2006 Effect of Adoption of SFAS 158 (in thousands) $(25,093 ) (25,093 ) (2,146 ) (2,146) 20,127 (26,289 ) (8,308) 33,401 33,401 As Reported at December 31, 2006 $ 568,032 9,588,625 (235,392) (1,184,262) (1,758,452) (274,720) (5,474,808) 140,509 (4,113,817) Other noncurrent assets Total assets Other current liabilities Total current liabilities Deferred income tax liability Other noncurrent liabilities Total liabilities AOCL, net of tax Total shareholders’ equity 92 The following table presents amounts included in AOCL at December 31, 2006 that have not yet been recognized in net periodic benefit cost and the amounts that are expected to be recognized in net periodic benefit cost during the year ended December 31, 2007: Retirement and Restoration Plan Medical and Life Plan (in thousands) Net amounts included in AOCL that have not yet been recognized in net periodic benefit cost (pre-tax) Unrecognized net transition obligation Unrecognized prior service credit Unrecognized loss Total Amounts expected to be recognized in net periodic benefit cost in 2007 Unrecognized net transition obligation Unrecognized prior service credit Unrecognized loss Total $ 854 (5,372) 49,977 $ 45,459 $ 239 (516) 3,221 $ 2,944 $ — (6,672 ) 17,384 $ 10,712 $ — (926 ) 1,211 285 $ 93 Changes in the benefit obligation and plan assets of the pension, restoration and other postretirement benefit plans are as follows at December 31: Retirement and Restoration Medical and Life Plan Plan 2006 2005 2006 2005 (in thousands) Change in projected benefit obligation Benefit obligation at beginning of year Service cost Interest cost Amendments Employee contributions Actuarial (gain) loss Benefits paid Benefit obligation at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return on plan assets Employer contributions Employee contributions Benefits paid Fair value of plan assets at end of year Funded status Unrecognized net actuarial loss Unrecognized prior service cost (benefit) Unrecognized net transition obligation Net amount recognized Net amount recognized in statement of financial position consists of: Noncurrent assets Current liabilities Noncurrent liabilities Accrued benefit cost Intangible asset Pre-tax amount included in AOCL Net amount recognized Accumulated benefit obligation Information for pension plans with projected benefit obligations in excess of plan assets Projected benefit obligation Fair value of plan assets Information for pension plans with accumulated benefit obligations in excess of plan assets Accumulated benefit obligation Fair value of plan assets $ 168,301 11,781 9,550 (8,327) — 18 (6,169) $ 175,154 94,832 12,593 35,634 — (6,169) $136,890 $ (38,264) * * * * $ — (1,205) (37,059) * * * * $142,136 $132,746 6,372 7,807 614 — 26,158 (5,396) $168,301 81,115 5,725 13,388 — (5,396) $ 94,832 (73,469) 56,144 2,734 1,093 $ (13,498) * * * $ (43,679) 3,827 26,354 $ (13,498) $ 138,511 $ 27,223 2,207 1,377 (5,711) 272 (2,200) (795) $ 22,373 $ 11,715 963 943 — 223 14,113 (734) $ 27,223 — — — 511 523 223 272 (734) (795) — $ — $ (27,223) $ (22,373) 20,754 * (1,399) * * — * $ (7,868) $ — (941 ) (21,432) * * * * $ (7,868) — * * — * $ (7,868) — $ — $ $175,154 136,890 $ 168,301 94,832 $ — $ — $ 20,542 — $ 138,511 94,832 $ — $ — — — — — * Not applicable due to change in method of accounting for defined benefit pension and other postretirement plans. 94 Accrued benefit costs are included in other current liabilities ($2 million) and other long-term liabilities ($58 million) in the consolidated balance sheets. No plan assets are expected to be returned to us during 2007. Net periodic benefit cost recognized for the pension, restoration and other postretirement benefit plans is provided in the table below. Net periodic benefit cost includes plan design changes made effective May 1, 2006. Retirement and Restoration Plan 2005 2006 Medical and Life Plan 2005 2004 Service cost Interest cost Expected return on plan assets Transition obligation recognition Amortization of prior service cost Recognized net actuarial loss Net periodic benefit cost $ 11,781 9,550 (9,320) 239 (220) 2,912 $ 14,942 $ 6,372 7,807 (7,094) 24 398 1,034 $ 8,541 2006 2004 (in thousands) $ 6,248 7,303 (6,745) 25 353 560 $ 7,744 $ 2,207 1,377 — — (439) 1,170 $ 4,315 $ 963 $ 610 577 — — (236) 363 $ 2,430 $ 1,314 943 — — (236 ) 760 Additional Information Increase in minimum liability included in AOCL Weighted-average assumptions used to determine benefit obligations at December 31, Discount rate Rate of compensation increase Weighted-average assumptions used to determine net periodic benefit costs for year ended December 31, Discount rate (1) Expected long-term return on plan assets Rate of compensation increase * $ 21,638 $ 4,716 * $ — $ — 5.75% 5.50% 6.00% 5.00% 5.00% 4.00% 5.75% 5.50 % 5.75% — — — 5.50% / 6.25% 6.00% 6.25% 8.25% 8.25% 8.50% 5.00% 4.00% 4.00% 5.50% / 6.25% — — 5.75 % 6.25% — — — — *Not applicable due to change in method of accounting for defined benefit and other post retirement plans. (1) The net periodic benefit cost was remeasured at May 1, 2006 using a discount rate of 6.25%, due to changes in plan provisions. In selecting the assumption for expected long-term rate of return on assets, we consider the average rate of earnings expected on the funds to be invested to provide for plan benefits. This includes considering the plan’s asset allocation, historical returns on these types of assets, the current economic environment and the expected returns likely to be earned over the life of the plan. We assume the long-term asset mix will be consistent with a target asset allocation of 70% equity and 30% fixed income, with a range of plus or minus 10% acceptable degree of variation in the plan’s asset allocation. Based on these factors we expect pension assets will earn an average of 8.25% per annum over the life of the plan. In order to determine an appropriate discount rate at December 31, 2006, we performed an analysis of the Citigroup Pension Discount Curve (the “CPDC”) as of that date for each of our plans. The CPDC uses spot rates that represent the equivalent yield on high quality, zero coupon bonds for specific maturities. 95 We used these rates to develop an equivalent single discount rate based on our plans’ expected future benefit payment streams and duration of plan liabilities. A 1% increase in the discount rate would have resulted in a decrease in net periodic benefit cost of $4 million in 2006. A 1% decrease in the discount rate would have resulted in an increase in net periodic benefit cost of $5 million in 2006. Assumed health care cost trend rates were as follows at December 31: Health care cost trend rate assumed for next year Rate to which the cost trend rate is assumed to decline (ultimate trend rate) Year rate reaches ultimate trend rate 2006 2005 10 % 5 % 10% 5% 2012 2011 Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects: Effect on total service and interest cost components for 2006 Effect on year-end 2006 postretirement benefit obligation 1% Increase 1% Decrease (in thousands) $ 530 2,460 $ (451) (2,180) Weighted-average asset allocations by asset category for the tax-qualified defined benefit pension plan are as follows: Asset category Equity securities Fixed income Other Total Target Allocation 2007 Plan Assets 2005 2006 70% 30% — 100% 70% 28% 2% 73% 27% — 100 % 100 % The investment policy for the tax-qualified defined benefit pension plan is determined by an employee benefits committee (“the committee”) with input from a third-party investment consultant. Based on a review of historical rates of return achieved by equity and fixed income investments in various combinations over multi-year holding periods and an evaluation of the probabilities of achieving acceptable real rates of return, the committee has determined the target asset allocation deemed most appropriate to meet the immediate and future benefit payment requirements for the plan and to provide a diversification strategy which reduces market and interest rate risk. A 1% increase (decrease) in the expected return on plan assets would have resulted in a (decrease) increase, respectively, in net periodic benefit cost of $1 million in 2006. We base our determination of the asset return component of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of December 31, 2006, we had cumulative asset gains 96 of approximately $2 million, which remain to be recognized in the calculation of the market-related value of assets. Contributions—We contributed cash of $36 million to the tax-qualified defined benefit pension, restoration and other postretirement benefit plans during 2006. We expect to make additional cash contributions of approximately $2 million during 2007 (unaudited). Estimated Future Benefit Payments—As of December 31, 2006, the following future benefit payments are expected to be paid: Retirement and Restoration Medical and Life Plan Plan 2007 2008 2009 2010 2011 Years 2012 to 2016 (in thousands) $ 6,182 6,469 6,788 7,436 8,244 56,615 $ 941 1,107 1,297 1,423 1,918 13,612 The estimate of expected future benefit payments is based on the same assumptions used to measure the benefit obligation at December 31, 2006 and includes estimated future employee service. 401(k) Plan—We sponsor a 401(k) savings plan. Participation is voluntary and all regular employees are eligible to participate. We make contributions to match employee contributions up to the first 6% of compensation deferred into the plan. In addition, we made a profit sharing contribution for all employees hired on or after May 1, 2006 based on the employee’s age and salary. We made cash contributions of $4 million, $5 million and $2 million in 2006, 2005 and 2004, respectively. Deferred Compensation Plan—In connection with the Patina Merger, we acquired the assets and assumed the liabilities related to a Patina shareholder-approved non-qualified deferred compensation plan (“Patina deferred compensation plan”). This plan was available to officers and certain managers of Patina and allowed participants to defer all or a portion of their salary and annual bonuses (either in cash or common stock). Participant-directed investments are held in a rabbi trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Participants may elect to receive distributions in either cash or shares of Noble Energy common stock. We account for the deferred compensation plan in accordance with EITF 97-14, “Accounting for Deferred Compensation Arrangements Where Amounts Earned are Held in a Rabbi Trust and Invested.” Components of the rabbi trust are as follows: Rabbi trust assets: Mutual fund investments Noble Energy common stock (at market value) Total rabbi trust assets Liability under Patina deferred compensation plan December 31, 2006 2005 (in thousands) $ 100,767 54,027 $ 154,794 $ 39,676 87,410 $ 127,086 $ 154,794 $ 127,086 Number of shares of Noble Energy common stock held by rabbi trust 1,101,032 2,168,980 Assets of the rabbi trust, other than Noble Energy common stock, are invested in certain mutual funds that cover an investment spectrum ranging from equities to money market instruments. These mutual funds are 97 publicly quoted and reported at market value. We account for these investments in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” The mutual funds are included in other noncurrent assets in the accompanying consolidated balance sheets. Noble Energy common stock held by the rabbi trust has been classified as treasury stock in the shareholders’ equity section of the accompanying consolidated balance sheets. The amounts payable to the plan participants, including the market value of the shares of Noble Energy common stock that are reflected as treasury stock, are included in other noncurrent liabilities in the accompanying consolidated balance sheets. One million shares, or 91%, of the common stock held in the plan at December 31, 2006 and 2,060,000 shares or 95%, of the common stock held in the plan at December 31, 2005 were attributable to a member of our Board of Directors. Plan participants sold 1,067,948 shares of Noble Energy common stock during 2006 and 20,434 shares of Noble Energy common stock during 2005 and invested the proceeds in mutual funds. Distributions totaling $0.5 million and $1 million were made to Plan participants during 2006 and 2005, respectively. In accordance with EITF 97-14, all fluctuations in market value of the rabbi trust assets have been reflected in the accompanying consolidated statements of operations. Increases or decreases in the value of the rabbi trust assets, exclusive of the shares of Noble Energy common stock, have been included in other expense, net in the accompanying consolidated statements of operations. This amount totaled $12 million during 2006 and $3 million during 2005. Increases or decreases in the market value of the deferred compensation liability, including the shares of Noble Energy common stock held by the rabbi trust, while recorded as treasury stock, are also included in other expense, net in the accompanying consolidated statements of operations. Based on the changes in the total market value of the rabbi trust assets, we recorded deferred compensation expense of $28 million during 2006 and $18 million during 2005. Note 12—Derivative Instruments and Hedging Activities Cash Flow Hedges—We use various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations. We account for derivative instruments and hedging activities in accordance with SFAS 133 and have elected to designate the majority of our derivative instruments as cash flow hedges. Effects of cash flow hedges on oil and gas sales were as follows: Reduction of crude oil sales Reduction of natural gas sales Total Year ended December 31, 2004 2005 2006 (in thousands) $ 140,486 97,206 $ 237,692 $ 50,736 10,556 $ 61,292 $ 190,730 41,698 $ 232,428 We recognized net ineffectiveness losses of $10 million in 2006 and $1 million in 2005. The net ineffectiveness loss in 2004 was de minimis. If it becomes probable that the hedging instrument is no longer highly effective, the hedging instrument loses hedge accounting treatment. All current mark-to-market gains and losses are recorded in earnings and all accumulated gains or losses recorded in AOCL related to the hedging instrument are also reclassified to earnings. As a result of the impacts of Hurricanes Katrina and Rita on the timing of forecasted production during the fourth quarter of 2005, derivative instruments hedging approximately 6,000 barrels per day of crude oil and 40,000 MMBtu per day of natural gas no longer qualified for hedge accounting. Accordingly, beginning October 1, 2005 the changes in fair value of these derivative contracts were recognized in our results of operations, causing a mark-to-market gain of $20 million in 2005. In addition, the delay in the timing of production resulted in a loss of $52 million in fourth quarter 2005 related to amounts previously recorded in AOCL. In first quarter 2006, the changes in fair value of these 98 derivative contracts caused a mark-to-market gain of $39 million, and the delay in the timing of our production resulted in a loss of $25 million related to amounts previously recorded in AOCL. These gains and losses are included in loss on derivative instruments in the consolidated statements of operations. These derivative instruments were redesignated as cash flow hedges in February 2006. We have hedging instruments that were designated as cash flow hedges of production from our Gulf of Mexico shelf properties. We sold these shelf properties during the third quarter 2006. During the second quarter 2006, when it became probable that forecasted production would not occur due to the pending sale, we determined that deferral of losses in AOCL related to this forecasted production was no longer appropriate under SFAS 133. As a result, we reclassified a pretax charge of $399 million related to the cash flow hedges from AOCL to earnings. This amount is included in loss on derivative instruments in the consolidated statements of operations. We redesignated the majority of these instruments as cash flow hedges for other North America production. Future earnings will reflect only those changes in derivative fair value that occur after the date of redesignation and are deferred in AOCL until the forecasted production occurs. In addition, a mark-to-market gain of $3 million relating to a hedging instrument that was not redesignated is included in loss on derivative instruments during 2006. No gains or losses were reclassified from AOCL into earnings as a result of the discontinuance of hedge accounting treatment during 2004. At December 31, 2006, we had entered into future costless collar transactions related to crude oil and natural gas production as follows: Natural Gas Average price per MMBtu Production Period MMBtupd 2007 (NYMEX) 2007 (CIG) (1) 2007 (Brent) 2008 (NYMEX) 2008 (CIG) 2008 (Brent) 2009 (NYMEX) 2009 (CIG) 2009 (Brent) 2010 (NYMEX) 2010 (CIG) (1) Colorado Interstate Gas — 12,000 — — 14,000 — — 15,000 — — 15,000 Floor — $ 6.50 — — 6.75 — — 6.00 — — 6.25 Ceiling — $ 9.50 — — 8.70 — — 9.90 — — 8.10 Crude Oil Average price per Bbl Floor $ 60.00 — 45.00 60.00 — 45.00 60.00 — 45.00 55.00 — Ceiling $ 74.30 — 70.63 72.40 — 66.52 70.00 — 63.05 73.80 — Bopd 2,700 — 6,748 3,100 — 4,074 3,700 — 3,074 3,500 — At December 31, 2006, we had entered into future fixed price swap transactions related to crude oil and natural gas production as follows: Production Period 2007 (NYMEX) 2008 (NYMEX) Natural Gas Crude Oil MMBtupd 170,000(1) 170,000(1) Average Price per MMBtu $ 6.04 5.67 Bopd 17,100 16,500 Average price per Bbl $ 39.19 38.23 (1) Includes fixed price swaps of 140,000 MMBtupd of natural gas for 2007 and 150,000 MMBtupd of natural gas for 2008 for which cash flow hedge accounting was discontinued at June 30, 2006 due to the pending sale of Gulf of Mexico shelf properties. These swaps (with associated basis swaps) were redesignated as cash flow hedges in the second quarter 2006. 99 At December 31, 2006, we had entered into basis swap transactions related to natural gas production. These basis swaps have been combined with NYMEX commodity swaps and designated as cash flow hedges. The basis swaps are as follows: Production Period 2007 (CIG vs. NYMEX) 2007 (ANR (1) vs. NYMEX) 2007 (PEPL (2) vs. NYMEX) 2008 (CIG vs. NYMEX) 2008 (ANR vs. NYMEX) 2008 (PEPL vs. NYMEX) (1) ANR Pipeline (2) Panhandle Eastern Pipe Line Natural Gas Average Differential per MMBtu $ 2.02 1.17 1.11 1.66 1.01 0.98 MMBtupd 100,000 30,000 10,000 100,000 40,000 10,000 The costless collar, fixed price swap and basis swap contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed price or floor price. We would pay the counterparty if the settlement price for the scheduled trading day applicable for each calculation period is more than the fixed price or ceiling price. The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional quantity per calculation period and the excess, if any, of the floating price over the fixed or ceiling price in respect of each calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess, if any, of the fixed or floor price over the floating price in respect of each calculation period. Accumulated Other Comprehensive Loss—As of December 31, 2006 and 2005, the balance in AOCL included net deferred losses of $104 million and $764 million, respectively, related to the fair value of crude oil and natural gas derivative instruments accounted for as cash flow hedges. The net deferred losses are net of deferred income tax benefit of $63 million and $411 million, respectively. If commodity prices were to stay the same as they were at December 31, 2006, approximately $21 million of deferred losses, net of tax, related to the fair values of crude oil and natural gas derivative instruments included in AOCL at December 31, 2006 would be reclassified to earnings during the next twelve months as the forecasted transactions occur, and would be recorded as a reduction in oil and gas sales of approximately $34 million before tax. Any actual increase or decrease in revenues will depend upon market conditions over the period during which the forecasted transactions occur. All current crude oil and natural gas derivative instruments, except those described in the following paragraph, are designated as cash flow hedges. All forecasted transactions currently being hedged are expected to occur by December 2010. Other Derivative Instruments—In addition to the derivative instruments described above, NEMI, from time to time, employs derivative instruments in connection with purchases and sales of production in order to establish a fixed margin and mitigate the risk of price volatility. Most of the purchases are on an index basis; however, purchasers in the markets in which NEMI sells often require fixed or NYMEX-related pricing. NEMI may use a derivative instrument to convert the fixed or NYMEX sale to an index basis thereby determining the margin and minimizing the risk of price volatility. 100 Derivative instruments used in connection with purchases and sales of third-party production are reflected at fair value as either assets or liabilities in the consolidated balance sheets. We record gains and losses on derivative instruments using mark-to-market accounting. Under this accounting method, the changes in the market value of outstanding derivative instruments are recognized as gains or losses in the period of change. Gains and losses related to changes in fair value are included in gathering, marketing and processing revenues. We recorded a net gain of $1 million during 2006 and a net loss of $2 million during 2005 related to derivative instruments. Net gains and losses for 2004 were de minimis. Receivables/Payables Related to Crude Oil and Natural Gas Derivative Instruments—The fair values of derivative instruments included in the consolidated balance sheets are as follows: Derivative instruments (current asset) Derivative instruments (long-term asset) Derivative instruments (current liability) Derivative instruments (long-term liability) December 31, 2006 2005 (in thousands) $ 35,242 2,862 (254,625 ) (328,875 ) $ 29,258 17,259 (445,939) (757,509) Interest Rate Lock—We occasionally enter into forward contracts or swap agreements to hedge exposure to interest rate risk. Changes in fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense over the term of the related notes. At December 31, 2006, AOCL included a deferred loss of $3 million, net of tax, related to an interest rate swap which was settled in 2004. This amount is being reclassified into earnings as adjustments to interest expense over the term of the 5¼% senior notes due 2014. At December 31, 2005, the amount of deferred loss included in AOCL was $4 million, net of tax. The amounts amortized to interest expense were $0.8 million, $0.8 million and $0.5 million for the years ending December 31, 2006, 2005 and 2004, respectively. Note 13—Equity Method Investments Investments accounted for under the equity method consist primarily of the following: • 45% interest in Atlantic Methanol Production Company, LLC (“AMPCO, LLC”), which owns and operates a methanol production facility and related facilities in Equatorial Guinea; and • 28% interest in Alba Plant LLC, which owns and operates a liquefied petroleum gas processing plant. Construction of the Alba Plant was funded primarily through advances by Noble Energy and other owners in exchange for notes payable by the Alba Plant. The notes were scheduled to mature on December 31, 2011 and bore interest at the 90-day LIBOR rate plus 3%. The notes were repaid in 2006. Equity method investments are included in other noncurrent assets in the consolidated balance sheets, and our share of earnings is reported as income from equity method investments in the consolidated statements of operations. The carrying value of our equity method investments is $14 million higher than the underlying net assets of the investees. This basis difference is being amortized into income over the remaining useful lives of the underlying net assets. 101 Equity method investments are as follows: Equity method investments: Atlantic Methanol Production Company, LLC Alba Plant LLC Other Total equity method investments 2006 2005 (in thousands) $ 211,325 146,051 15,996 $ 373,372 $ 214,226 195,109 11,027 $ 420,362 Summarized, 100% combined financial information for equity method investees is as follows: Balance Sheet Information Current assets Noncurrent assets Current liabilities Noncurrent liabilities Statements of Operations Information Operating revenues Less cost of goods sold Gross margin Less other expense (income) Less income tax expense (benefit) Net income December 31, 2006 2005 (in thousands) $ 252,201 857,465 171,028 2,385 $ 274,484 877,402 119,912 450,156 Year ended December 31, 2005 2006 (in thousands) 2004 $ 702,556 202,304 500,252 47,487 23,451 $ 429,314 $ 464,000 136,508 327,492 35,798 67,142 $ 224,552 $ 263,256 104,987 158,269 (21,161) (5,597) $ 185,027 Our share of income taxes incurred directly by the equity method investees is reported in income from equity method investments and is not included in our income tax provision in the consolidated statements of operations. At December 31, 2006, retained earnings included $144 million related to the undistributed earnings of equity method investees. Note 14—Commitments and Contingencies 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. 102 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. 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. Non-Cancelable Leases and Other Commitments—We hold leases and other commitments for drilling rigs, buildings, equipment and other properties. Net rental expense was approximately $12 million, $10 million and $7 million for 2006, 2005 and 2004, respectively. Net minimum commitments as of December 31, 2006 consist of the following: Net Minimum Commitments 2007 2008 2009 2010 2011 2012 and thereafter Total Drilling Rig and Equipment Contracts $ 328,987 161,820 58,399 71,966 65,490 61,950 $ 748,612 103 Equipment Leases Building Leases (in thousands) $ 10,237 6,159 6,018 5,878 5,690 17,985 $ 51,967 $ 5,168 1,142 477 — — — $ 6,787 Total $ 344,392 169,121 64,894 77,844 71,180 79,935 $ 807,366 In January 2007, we entered into a five-year throughput and deficiency agreement with a financial commitment of $95 million. The transporting pipeline, the construction of which is subject to regulatory approval, is expected to be completed and operational in 2009. Note 15—Geographical Data We have operations throughout the world and manage our operations by country. The following information is grouped into five components that are all primarily in the business of natural gas and crude oil exploration and production: U.S.; West Africa (Equatorial Guinea and Cameroon); North Sea; Israel; and Other International, Corporate and Marketing. Other International includes Argentina, China, Ecuador and Suriname. Accounting policies for geographical segments are the same as those described in the summary of significant accounting policies. Transfers between segments are accounted for at market value. We do not consider interest income and expense or income tax benefit or expense in our evaluation of the performance of geographical segments. 104 Year Ended December 31, 2006 Revenues from third parties Intersegment revenue Income from equity method investments Total Revenues DD&A Loss on derivative instruments Impairment of operating assets Income from continuing operations before tax Investments in equity method investees Additions to long-lived assets Total assets at December 31, 2006 (1) Year Ended December 31, 2005 Revenues from third parties Intersegment revenue Income from equity method investments Total Revenues DD&A Loss on derivative instruments Impairment of operating assets Income from continuing operations before tax Investments in equity method investees Additions to long-lived assets Total assets at December 31, 2005 (2) Year Ended December 31, 2004 Revenues from third parties Intersegment revenue Income from equity method investments Total Revenues DD&A Loss on derivative instruments Impairment of operating assets Income from continuing operations before tax Investments in equity method investees Additions to long-lived assets Total assets at December 31, 2004 Total United States West Africa North Sea Israel (in thousands) Other Int’l, Corporate & Marketing $ 2,800,720 — 139,362 2,940,082 $ 1,510,689 425,901 — 1,936,590 622,608 392,367 8,525 543,431 392,367 8,525 $ 413,682 — 139,362 553,044 23,620 — — 1,096,217 631,087 493,777 373,372 1,916,139 9,588,625 — 1,615,435 7,224,920 373,372 35,121 960,357 $ 2,095,911 — 90,812 2,186,723 $ 913,564 460,808 — 1,374,372 390,544 32,680 5,368 311,153 32,680 5,368 $ 281,902 — 90,812 372,714 27,121 — — 968,660 585,988 309,239 420,362 4,382,005 8,878,033 — 4,345,604 6,577,853 420,362 2,738 877,409 $ 1,272,852 — 78,199 1,351,051 $ 335,329 455,068 — 790,397 308,103 272 9,885 240,058 272 9,885 $ 132,590 — 78,199 210,789 13,925 — — 513,008 294,412 162,576 377,384 469,445 3,435,784 — 280,280 1,299,547 377,384 114,188 809,675 $ 115,232 — — 115,232 8,123 — — 72,803 — 234,877 343,236 $ 123,584 — — 123,584 9,888 — — 88,524 — 15,287 146,311 $ 115,181 — — 115,181 18,244 — — 70,305 — 10,795 218,881 $ 92,373 — — 92,373 13,947 — — $ 668,744 (425,901) — 242,843 33,487 — — 71,318 (172,768) — 841 256,913 — 29,865 803,199 $ 65,050 — — 65,050 $ 711,811 (460,808) — 251,003 11,188 — — 46,468 — 5,928 266,312 31,194 — — (61,559) — 12,448 1,010,148 $ 48,855 — — 48,855 9,058 — — $ 640,897 (455,068) — 185,829 26,818 — — 32,088 (46,373) — (8,313) 273,347 — 72,495 834,334 (1) The domestic reporting unit includes goodwill of $781 million. (2) The domestic reporting unit includes goodwill of $863 million. Note 16—Discontinued Operations During 2004, we completed an asset divestiture program that had first been announced during July 2003. The asset divestiture program included five domestic property packages. The sales price for the five property packages totaled $130 million. Pursuant to SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” our consolidated financial statements were reclassified for all periods previously presented to reflect the operations and assets of the properties being sold as discontinued operations. The net income from discontinued operations was classified in the consolidated statements of operations as “Discontinued Operations, Net of Tax.” 105 Summarized results of discontinued operations are as follows: Oil and gas sales and royalties Realized gain Income before income taxes Year ended December 31, 2004 (in thousands) $ 12,575 14,996 22,862 Long-term debt is recorded at the consolidated level and is not allocated to components. Therefore, no interest expense was allocated to the discontinued operations. Note 17—Recently Issued Pronouncements SFAS 155—In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (“SFAS 155”). SFAS 155 permits an entity to measure at fair value any financial instrument that contains an embedded derivative that otherwise would require bifurcation. This Statement is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. We adopted SFAS 155 as of January 1, 2007. Adoption had no effect on our financial position or results of operations. SFAS 157—Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (“SFAS 157”), establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. SFAS 157 is effective for fair value measures already required or permitted by other standards for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We adopted SFAS 157 as of January 1, 2007. Adoption had no effect on our financial position or results of operations. SFAS 159—In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS 159”). SFAS 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS 159 is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. We are currently evaluating the provisions of SFAS 159 and assessing the impact it may have on our financial position and results of operations. FASB Staff Position AUG AIR-1—FASB Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities” (“FSP AUG AIR-1”), prohibits companies from accruing as a liability in annual and interim periods the future costs of periodic major overhauls and maintenance of plant and equipment (the “accrue-in-advance method”). Other previously acceptable methods of accounting for planned major overhauls and maintenance (the direct expense, built-in overhaul and deferral methods) will continue to be permitted. The new requirements apply to entities in all industries for fiscal years beginning after December 15, 2006, and must be retrospectively applied. We adopted FSP AUG AIR-1 as of January 1, 2007. Adoption had no effect on our financial position or results of operations. FIN 48—In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109”, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” It prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We adopted FIN 48 effective January 1, 2007. However, the FASB is in the process of issuing Proposed FSP FIN 48-a, “Implementation Guidance on Interpretation 48”. The 106 guidance will provide conditions for determining when a tax position is considered to be effectively settled through examination. Although the final amount of our adoption adjustment will depend on the guidance issued, we do not expect the final impact of adoption to have a material effect on our financial position. Supplemental Oil and Gas Information (Unaudited) In accordance with SFAS No. 69, “Disclosures about Oil and Gas Producing Activities” (“SFAS 69”), and regulations of the SEC, we are making the following supplemental disclosures about our crude oil and natural gas exploration and production operations. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. 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. 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. See Items 1 and 2. Business and Properties—Proved Reserves. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered. Our supplemental disclosures are grouped by geographic area and include the U.S., West Africa (Equatorial Guinea and Cameroon), Israel, Ecuador, North Sea, China, Argentina and Other International. Operations in Equatorial Guinea, Cameroon, Ecuador and China are conducted in accordance with the terms of production sharing contracts. The following definitions apply to the terms used in the paragraphs above: Reserve Estimate. The determination of an estimate of a quantity of oil or gas reserves that are thought to exist at a certain date, considering existing prices and reservoir conditions. Reserve Audit. The 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. The following definitions apply to our categories of proved reserves: Proved Reserves. 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. Proved Developed Reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. 107 Proved Undeveloped Reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. For complete definitions of proved natural gas, natural gas liquids and crude oil reserves, refer to Regulation S-X, Rule 4-10(a)(2), (3) and (4). 108 Proved Gas Reserves (Unaudited) The following reserve schedule was developed by our reserve engineers and sets forth the changes in estimated quantities of proved gas reserves: Proved reserves as of: December 31, 2003 Revisions of previous estimates (1) Extensions, discoveries and other additions (1)(2) Purchase of minerals in place Sale of minerals in place Production December 31, 2004 Revisions of previous estimates (3) Extensions, discoveries and other additions (4) Purchase of minerals in place (5) Sale of minerals in place Production December 31, 2005 Revisions of previous estimates (6) Extensions, discoveries and other additions (7) Purchase of minerals in place (8) Sale of minerals in place (9) Production December 31, 2006 Proved developed reserves as of: December 31, 2003 December 31, 2004 December 31, 2005 December 31, 2006 Natural Gas and Casinghead Gas (MMcf) United States West Africa Israel Ecuador North Sea Argentina Total 558,058 (7,452) 537,998 (4,130) 450,307 (15,441) 79,298 (27,398) 13,811 1,552 2,448 (937 ) 1,641,920 (53,806) 74,277 14,437 (30,127) (89,458) 519,735 18,644 400,288 — — (16,747) 917,409 7,732 — 75,081 — — — — (7,640) (17,573) 119,341 417,293 32,800 481 144,335 1,083,959 — (125,543) 1,641,130 (82,371) — — — (23,938) 901,203 57,543 — — — (24,228) 393,546 260 — — — (8,321) 143,820 32,927 314,140 141,610 (110,486) (164,830) 1,739,193 — 2,532 — (16,579) 944,699 — — — (33,906) 359,900 — — (8,933) 167,814 506,457 430,513 1,278,788 1,255,271 462,474 447,347 431,142 359,691 378,001 360,428 336,681 303,035 25,130 119,341 143,820 167,814 685 — (204) (4,130) 11,714 3,200 — — — (3,394) 11,520 10,485 — — — (2,967) 19,038 13,811 11,714 11,520 19,038 — — — (142 ) 1,369 (1,301 ) 550,331 14,437 (30,331) (135,690) 1,986,861 61,556 144,335 — — 1,083,959 — — (68 ) (185,492) — 3,091,219 19,122 278 — — (108 ) 170 314,140 144,142 (110,486) (227,323) 3,230,814 2,197 1,118 1,388,070 1,370,461 — 2,201,951 2,105,019 170 (1) (2) (3) (4) (5) (6) (7) (8) (9) Ecuador revisions and discoveries are due to additional drilling. In 2004, we entered into an additional natural gas contract with an LNG plant in Equatorial Guinea. We increased reserves based on minimum contractual volumes required to be taken under this agreement. Increases for Ecuador are due to better than expected performance. The increase in domestic proved reserves includes 57 Bcf in the Wattenberg field and 40 Bcf in the western Mid- continent area. Purchase of minerals in place is the result of the Patina Merger. See Note 3—Acquisitions and Divestitures. Increases for Ecuador and North Sea are due to better than expected performance. The increase in domestic proved reserves includes 140 Bcf in the Wattenberg field, 77 Bcf in the Piceance Basin and 55 Bcf in the western Mid-continent area. Purchase of minerals in place includes 128 Bcf acquired in the purchase of U.S. Exploration. See Note 3— Acquisitions and Divestitures. Sale of minerals in place is primarily due to sale of Gulf of Mexico shelf properties. See Note 3—Acquisitions and Divestitures. 109 Proved Oil Reserves (Unaudited) The following reserve schedule was developed by our reserve engineers and sets forth the changes in estimated quantities of proved oil reserves: Proved reserves as of: December 31, 2003 Revisions of previous estimates Extensions, discoveries and other additions (1) Purchase of minerals in place Sale of minerals in place Production December 31, 2004 Revisions of previous estimates Extensions, discoveries and other additions (2) Purchase of minerals in place (3) Sale of minerals in place Production December 31, 2005 Revisions of previous estimates Extensions, discoveries and other additions (4) Purchase of minerals in place (5) Sale of minerals in place (6) Production December 31, 2006 Proved developed reserves as of: December 31, 2003 December 31, 2004 December 31, 2005 December 31, 2006 United States Crude Oil and Condensate (MBbls) West Africa China Argentina North Sea Total 42,304 976 113,198 (1,104) 8,460 1,037 10,336 (1,438) 8,921 1,995 183,219 1,466 16,760 5,289 (2,190) (8,073) 55,066 4,192 — 4,414 — — — (2,116) (2,459) 9,336 278 (3,364) 108,730 (1,303) — 12,955 — — — — (1,964) (6,492) 20,605 100,935 (4,258) (396) 3,024 — — (1,421) 10,501 15 — — — (1,807) 8,709 12 — 138 — (6,519) 90,296 — 1,794 — — — — (1,539) (1,357) 8,976 18,852 11,272 90,594 — (9,468) 151,656 (193) 23,037 19,328 (6,971) (16,715) 170,142 34,246 32,390 114,223 114,505 113,198 108,730 100,935 90,296 8,460 9,336 7,650 18,852 10,336 10,501 8,709 8,976 — — — (1,085) 9,831 153 — — — (1,059) 8,925 112 — — — (1,213) 7,824 8,004 7,539 6,914 6,960 24,198 5,289 (4,306) (16,402) 193,464 3,335 24,227 90,594 — (20,790) 290,830 (4,723) 24,831 19,466 (6,971) (27,343) 296,090 174,244 168,496 238,431 239,589 (1) The increase in domestic proved reserves includes 14 MMBbl in the deepwater Gulf of Mexico Ticonderoga field. (2) The increase in total proved reserves includes 6 MMBbl in the Wattenberg field, 3 MMBbl in the deepwater Gulf of Mexico Lorien field and 13 MMBbl in the North Sea Dumbarton field. (3) Purchase of minerals in place is the result of the Patina Merger. See Note 3—Acquisitions and Divestitures. (4) The increase in domestic proved reserves includes 14 MMBbl in the Wattenberg field. (5) (6) Purchase of minerals in place includes 18 MMBbl acquired in the purchase of U.S. Exploration. See Note 3—Acquisitions and Divestitures. Sale of minerals in place is primarily due to the sale of Gulf of Mexico shelf properties. See Note 3— Acquisitions and Divestitures. 110 Results of Operations for Oil and Gas Producing Activities (Unaudited) Aggregate results of continuing operations in connection with crude oil and natural gas producing activities are as follows: United States West Africa Israel Ecuador North Sea (in thousands) China Argentina Other Int’l Total Year Ended December 31, 2006 Revenues Production costs (1) Transportation E&P corporate Exploration expenses DD&A Impairment of operating assets Accretion expense Income before income taxes Income tax expense Results of continuing operations from producing activities (excluding corporate overhead and interest costs) Company’s share of Alba Plant LLC’s results of operations from producing activities Year Ended December 31, 2005 Revenues Production costs (1) Transportation E&P corporate Exploration expenses DD&A Impairment of operating assets Accretion expense Income before income taxes Income tax expense Results of continuing operations from producing activities (excluding corporate overhead and interest costs) Company’s share of Alba Plant LLC’s results of operations from producing activities Year Ended December 31, 2004 Revenues Production costs (1) Transportation E&P corporate Exploration expenses DD&A Impairment of operating assets Accretion expense Income (loss) before income taxes Income tax expense Results of continuing operations from producing activities (excluding corporate overhead and interest costs) Company’s share of Alba Plant LLC’s results of operations from producing activities $1,936,590 $ 413,682 $ 92,373 9,066 — 111 286 13,911 — 452 68,547 19,810 26,556 — 4,656 7,329 23,402 — 104 351,635 125,493 338,655 20,729 60,710 113,015 561,948 8,525 8,861 824,147 313,011 3,021 — 3,102 228 11,611 $ 33,575 $ 115,232 $85,913 17,336 803 250 (227) 11,617 — — 56,134 18,524 11,655 7,010 3,346 10,499 8,045 — 1,159 73,518 42,111 221 15,392 3,848 — $ 57,451 22,260 — 699 584 14,068 — — 19,840 6,944 $ — $ 2,734,816 428,549 — 28,542 — 74,043 1,169 142,668 10,954 644,602 — 8,525 — 10,797 — (12,123) 1,397,090 527,641 (2,100) $ 511,136 $ 226,142 $ 48,737 $ 11,544 $ 31,407 $37,610 $ 12,896 $(10,023) $ 869,449 $ — $ 101,338 $ — $ — $ — $ — $ — $ — $ 101,338 $1,374,374 $ 281,901 $ 65,050 8,504 — 188 223 11,120 — 281 44,734 7,752 30,659 — 435 5,463 26,978 — 51 218,315 76,518 216,478 9,350 34,162 130,018 328,645 5,368 9,590 640,763 140,916 341 3,000 — 2,611 $ 31,868 $ 123,583 $85,352 12,502 910 567 (142) 13,115 — — 58,400 19,272 12,503 6,562 2,591 5,985 9,866 — 1,134 84,942 36,834 158 13,512 3,378 12,246 — $ 36,162 16,294 (58 ) 120 1,606 11,122 — — 7,078 2,478 $ — $ 1,998,290 299,940 — 16,764 — 40,934 260 11,216 154,710 413,092 — — 5,368 11,214 — 1,056,268 (11,476) (717) 286,431 $ 499,847 $ 141,797 $ 36,982 $ 10,134 $ 48,108 $39,128 $ 4,600 $(10,759) $ 769,837 $ — $ 33,916 $ — $ — $ — $ — $ — $ 790,397 $ 132,590 $ 48,855 7,203 — 163 598 9,549 — 163 125,018 8,631 15,599 73,971 259,365 9,885 8,021 20,811 — 596 7,214 13,925 — 6 2,184 — 2,750 239 15,338 $ 24,043 $ 115,181 $45,398 10,119 697 — 265 10,466 — — 8,803 10,480 2,302 11,115 18,215 — 1,140 — — $ 32,554 11,407 — — 1,325 10,263 — — $ $ — $ 33,916 — $ 1,189,018 185,545 — 19,808 — (77) 21,333 95,708 981 — 337,121 — 9,885 — 9,330 289,907 106,603 90,038 46,011 31,179 9,896 3,532 1,810 63,126 28,542 23,851 4,012 9,559 5,763 (904) (330) 510,288 202,307 $ 183,304 $ 44,027 $ 21,283 $ 1,722 $ 34,584 $19,839 $ 3,796 $ (574) $ 307,981 $ — $ 9,099 $ — $ — $ — $ — $ — $ — $ 9,099 (1) Production costs consist of oil and gas operations expense, production and ad valorem taxes, plus general and administrative expense supporting oil and gas operations. 111 Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (1) (Unaudited) Costs incurred in connection with crude oil and natural gas acquisition, exploration and development are as follows: United States West Africa Israel Ecuador North Sea (in thousands) China Argentina Other Int’l Total Year Ended December 31, 2006 Property acquisition costs Proved (2) Unproved (2) Total acquisition costs Exploration costs Development costs (3) (4) Total consolidated operations Company’s share of Alba Plant LLC’s development costs Year Ended December 31, 2005 Property acquisition costs Proved (2) Unproved (2) Total acquisition costs Exploration costs Development costs (3) (4) (5) Total consolidated operations Company’s share of Alba Plant LLC’s development costs Year Ended December 31, 2004 Property acquisition costs $ 514,294 $ 157,141 671,435 204,787 784,877 1,000 1,000 286 13,869 $1,661,099 $ 53,480 $ 15,155 7,971 $ — $ — $ 25,500 33,471 13,076 6,933 831 — 831 — 18,185 228 48 231,484 276 $ 250,500 — $ — — — (227) 7,590 $ 7,363 $ $ — $ — $ 522,265 184,472 706,737 247,873 — 1,058,860 $14,643 $10,954 $ 2,013,470 — — 584 14,059 — — 10,954 $ — $ 580 $ — $ — $ — $ — $ — $ — $ 580 $2,642,572 $ 1,084,545 3,727,117 164,820 657,858 — — 223 5,928 $4,549,795 $ 20,864 $ 6,151 — $ — $ — $ — — 18,126 2,738 140 140 6,308 19,729 $ (1,319) $ 26,177 — — 341 (1,660) — $ — — — (142) 2,980 $ 2,838 $ — $ — $ 2,642,572 1,084,935 3,727,507 202,498 698,451 $12,855 $11,095 $ 4,628,456 250 250 11,216 (371 ) — — 1,606 11,249 $ — $ 27,639 $ — $ — $ — $ — $ — $ — $ 27,639 Proved Unproved $ Total acquisition costs Exploration costs Development costs (3) (4) (5) Total consolidated operations Company’s share of Alba Plant LLC’s development costs — $ — $ — $ 85,785 $ 25,547 111,332 106,985 174,179 — 598 (5,887) $ 392,496 $121,828 $ (5,289) 14,459 14,459 7,214 100,155 — — 239 50,727 4,651 4,651 12,256 9,509 $ 50,966 $ 26,416 — $ — — — 265 12,412 $ 12,677 $ — $ — $ 85,785 44,681 130,466 129,863 351,995 $11,673 $ 1,557 $ 612,324 24 24 1,325 10,324 — — 981 576 $ — $ 61,498 $ — $ — $ — $ — $ — $ — $ 61,498 (1) (2) (3) Costs incurred include capitalized and expensed items. Includes amounts allocated from the U.S. Exploration acquisition (2006) and the Patina Merger (2005). See Note 3—Acquisitions and Divestitures. U.S. development costs include $4 million, $39 million and $5 million related to asset retirement obligations in 2006, 2005 and 2004 respectively. U.S. asset retirement costs of $33 million in 2006, $66 million in 2005, and $130 million in 2004 were incurred as a result of hurricane damage and are excluded from the costs incurred schedule above as we expect to recover the costs from insurance proceeds. See Note 4—Effect of Gulf Coast Hurricanes. (4) Worldwide development costs include $768 million, $471 million and $179 million spent to develop proved undeveloped reserves in 2006, 2005, and 2004, respectively. Worldwide development costs also include $191 million spent on a floating production, storage and offloading vessel in the Dumbarton field in 2006. North Sea development costs include $5 million and $3 million related to asset retirement obligations in 2005 and 2004 respectively. (5) 112 Capitalized Costs Relating to Oil and Gas Producing Activities (Unaudited) Aggregate capitalized costs relating to crude oil and natural gas producing activities, including asset retirement costs and related accumulated DD&A, are as follows: Unproved oil and gas properties Proved oil and gas properties (1) Total oil and gas properties Accumulated DD&A Net capitalized costs Company’s share of Alba Plant LLC’s net capitalized costs December 31, 2006 2005 (in thousands) $ 972,895 7,886,079 8,858,974 (1,725,431 ) $ 7,133,543 124,454 $ $ 1,066,888 7,335,188 8,402,076 (2,239,596) $ 6,162,480 $ 134,067 (1) Proved oil and gas properties at December 31, 2006 and 2005 include asset retirement costs of $49 million and $131 million, respectively. 113 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited) The following information is based on our best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2006, 2005 and 2004 in accordance with SFAS 69. The standard requires the use of a 10% discount rate. This information is not the fair market value nor does it represent the expected present value of future cash flows of our proved oil and gas reserves: United West States Africa Israel Ecuador North Sea (in millions) China Argentina Total December 31, 2006 Future cash inflows (1) Future production costs (2) Future development costs Future income tax expenses Future net cash flows 10% annual discount forestimated timing of cash flows Standardized measure ofdiscounted future netcash flows December 31, 2005 Future cash inflows (1) Future production costs (2) Future development costs Future income tax expenses Future net cash flows 10% annual discount forestimated timing of cash flows Standardized measure ofdiscounted future netcash flows December 31, 2004 Future cash inflows (1) Future production costs (2) Future development costs Future income tax expenses Future net cash flows 10% annual discount forestimated timing of cash flows Standardized measure ofdiscounted future netcash flows $ 18,948 $ 4,904 $ 972 146 90 187 549 738 80 1,348 2,738 4,551 2,846 3,422 8,129 $ 629 162 12 130 325 $ 1,225 327 35 435 428 $ 460 117 3 103 237 $ 348 70 25 74 179 $ 27,486 6,111 3,091 5,699 12,585 3,966 1,132 215 170 95 65 55 5,698 $ 4,163 $ 1,606 $ 334 $ 155 $ 333 $ 172 $ 124 $ 6,887 $ 22,931 $ 5,436 $ 1,031 154 88 182 607 5,099 1,887 4,645 11,300 556 92 1,589 3,199 $ 539 47 12 142 338 $ 1,267 352 184 381 350 $ 453 118 3 101 231 $ 415 172 34 58 151 $ 32,072 6,498 2,300 7,098 16,176 5,201 1,554 236 162 138 60 54 7,405 $ 6,099 $ 1,645 $ 371 $ 176 $ 212 $ 171 $ 97 $ 8,771 $ 5,429 $ 4,358 $ 1,089 133 88 264 604 490 83 1,704 2,081 1,135 364 1,219 2,711 $ 377 42 16 129 190 $ 439 153 23 109 154 $ 362 131 3 64 164 $ 300 179 30 29 62 $ 12,354 2,263 607 3,518 5,966 1,104 1,079 249 82 33 53 24 2,624 $ 1,607 $ 1,002 $ 355 $ 108 $ 121 $ 111 $ 38 $ 3,342 (1) The standardized measure of discounted future net cash flows for 2006, 2005 and 2004 does not include cash flows relating to anticipated future methanol or power sales. (2) Production costs include oil and gas operations expense, production and ad valorem taxes, transportation costs and general and administrative expense supporting oil and gas operations. 114 Future cash inflows are computed by applying year-end prices, adjusted for location and quality differentials on a property-by-property basis, to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year- end. The discounted future cash flow estimates do not include the effects of derivative instruments. Average prices per region are as follows: United West Africa States Israel Ecuador North Sea China Argentina Total December 31, 2006 Average crude oil price per Bbl Average natural gas price per Mcf December 31, 2005 Average crude oil price per Bbl Average natural gas price per Mcf December 31, 2004 Average crude oil price per Bbl Average natural gas price per Mcf $ 57.02 $51.49 $ — $ — $57.81 $51.25 $44.35 $54.87 5.32 0.27 2.70 3.75 7.11 — 0.85 3.48 $ 58.20 $51.62 $ — $ — $58.47 $52.01 $46.51 $55.39 8.59 0.25 2.62 3.75 5.39 — — 5.16 $ 41.25 $37.97 $ — $ — $40.93 $34.45 $30.45 $38.48 6.07 0.25 2.61 3.16 4.84 — 0.84 2.47 We estimate that a $1.00 per Bbl change or a $.10 per Mcf change in the average crude oil price or the average natural gas price, respectively, from the year-end price at December 31, 2006 would change the discounted future net cash flows before income taxes by approximately $162 million or $153 million, respectively. Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions. Future development costs include $922 million, $556 million and $501 million that we expect to spend in 2007, 2008 and 2009, respectively, to develop proved undeveloped reserves. Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to proved crude oil and natural gas reserves, less the tax bases of the properties involved. The future income tax expenses give effect to tax credits and allowances, but do not reflect the impact of general and administrative costs and exploration expenses of ongoing operations. Imbalance receivables and liabilities are as follows: Imbalance receivables Imbalance liabilities Year ended December 31, 2004 2005 2006 (in thousands) $ 18,100 34,600 $ 18,389 16,750 $ 21,200 16,100 Imbalance receivables and imbalance liabilities have been excluded from the standardized measure of discounted future net cash flows. 115 Sources of Changes in Discounted Future Net Cash Flows (Unaudited) Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to proved crude oil and natural gas reserves are as follows: Standardized measure of discounted future netcash flows at the beginning of the year Sales of oil and gas produced, net of production costs Net changes in prices and production costs Extensions, discoveries and improved recovery, less related costs Changes in estimated future development costs Development costs incurred during the period Revisions of previous quantity estimates Purchases of minerals in place Sales of minerals in place Accretion of discount Net change in income taxes Change in timing of estimated future production and other Aggregate change in standardized measure of discounted future net cash flows Standardized measure of discounted future net cash flows at the end of the year Year ended December 31, 2004 2005 2006 (in millions) $ 8,771 $ 3,342 $ 2,512 (2,177) (2,788) 769 (558) 1,076 (92) 573 (579) 1,274 777 (159) (1,563 ) 2,160 1,173 (912) 751 273 4,720 — 519 (2,099 ) 407 (1,014) 861 839 99 92 (70) 219 (207) 406 (380) (15) (1,884) 5,429 830 $ 6,887 $ 8,771 $ 3,342 116 Supplemental Quarterly Financial Information (Unaudited) Supplemental quarterly financial information is as follows: 2006 (1) Revenues Income from continuing operations before taxes Income from continuing operations Net income Basic earnings per share: Income from continuing operations Net income Diluted earnings per share: Income from continuing operations Net income 2005 (2) Revenues Income from continuing operations before taxes Income from continuing operations Net income Basic earnings per share: Income from continuing operations Net income Diluted earnings per share: Income from continuing operations Net income Quarter Ended Mar. 31, June 30, Sept. 30, Dec. 31, (in thousands except per share amounts) $ 711,997 349,353 226,087 226,087 $ 772,580 (44,865) (30,705) (30,705) $ 741,319 544,966 318,064 318,064 $ 714,186 246,763 164,982 164,982 1.28 1.28 1.26 1.26 (0.17) (0.17) (0.17) (0.17) 1.80 1.80 1.75 1.75 0.95 0.95 0.94 0.94 $ 368,212 174,482 109,968 109,968 $ 485,443 224,405 136,877 136,877 $ 632,088 241,136 176,956 176,956 $ 700,980 328,637 221,919 221,919 0.93 0.93 0.92 0.92 0.94 0.94 0.91 0.91 1.01 1.01 0.99 0.99 1.27 1.27 1.18 1.18 (1) (2) First quarter 2006 includes a mark-to-market gain of $39 million due to a loss of cash flow hedge accounting treatment for certain derivative instruments, and a loss of $25 million related to amounts previously recorded in AOCL due to a delay in the timing of production. Second quarter 2006 includes a loss of $399 million related to amounts previously recorded in AOCL due to the sale of Gulf of Mexico shelf properties. Third quarter 2006 includes a gain of $204 million from the sale of Gulf of Mexico shelf properties. Fourth quarter 2006 includes an additional gain of $7 million from the sale of Gulf of Mexico Shelf properties. See Note 3—Acquisitions and Divestitures and Note 12— Derivative Instruments and Hedging Activities. Fourth quarter 2005 includes discontinuation of hedge accounting treatment on certain derivatives resulting in a mark-to-market gain of $20 million ($13 million, net of tax) recognized in our consolidated results of operations. In addition, a loss of $52 million ($34 million, net of tax) associated with the discontinued hedge accounting treatment, which had been previously deferred in AOCL, was reclassified to earnings in fourth quarter 2005 as an increase in other expense, net in the consolidated statement of operations. See Note 4—Effect of Gulf Coast Hurricanes and Note 12—Derivative Instruments and Hedging Activities. 117 Item 9. None. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. Item 9A. Controls and Procedures. Evaluation of Disclosure Controls and Procedures We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports we file or furnish to the SEC under the Securities Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Our principal executive officer and principal financial officer have evaluated the effectiveness of our “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this Annual Report on Form 10-K. Based upon their evaluation, they have concluded that our disclosure controls and procedures are effective. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all potential future conditions. Management’s Annual Report on Internal Control Over Financial Reporting See Item 8. Management’s Report on Internal Control Over Financial Reporting. Changes in Internal Control over Financial Reporting Our management is also responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls were designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of the consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States. Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Our management has assessed the effectiveness of our internal controls over financial reporting as of December 31, 2006. Based on our assessment, our internal controls over financial reporting were effective. Management included all consolidated entities of Noble Energy in its assessment. There were no changes in internal controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. Item 9B. Other Information. None. 118 PART III Item 10. Directors, Executive Officers and Corporate Governance. The information required by this item is incorporated herein by reference to the 2007 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2006. Item 11. Executive Compensation. The information required by this item is incorporated herein by reference to the 2007 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2006. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. The information required by this item is incorporated herein by reference to the 2007 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2006. Item 13. Certain Relationships and Related Transactions, and Director Independence. The information required by this item is incorporated herein by reference to the 2007 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2006. Item 14. Principal Accounting Fees and Services. The information required by this item is incorporated herein by reference to the 2007 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2006. Item 15. Exhibits, Financial Statements Schedules. (a) The following documents are filed as a part of this report: PART IV (3) Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report. 119 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SIGNATURES Date: February 23, 2007 Date: February 23, 2007 Date: February 23, 2007 NOBLE ENERGY, INC. (Registrant) By: /s/ Charles D. Davidson Charles D. Davidson, Chairman of the Board, President, Chief Executive Officer and Director By: /s/ Chris Tong Chris Tong, Senior Vice President, Chief Financial Officer By: /s/ Frederick B. Bruning Frederick B. Bruning, Chief Accounting Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Signature Capacity in which signed Date /s/ Charles D. Davidson Charles D. Davidson /s/ Chris Tong Chris Tong Chairman of the Board, President, Chief Executive Officer and Director (Principal Executive Officer) February 23, 2007 Senior Vice President, Chief Financial Officer (Principal Financial Officer) February 23, 2007 /s/ Frederick B. Bruning Frederick B. Bruning Chief Accounting Officer (Principal Accounting Officer) February 23, 2007 /s/ Jeffrey L. Berenson Jeffrey L. Berenson /s/ Michael A. Cawley Michael A. Cawley /s/ Edward F. Cox Edward F. Cox /s/ Thomas J. Edelman Thomas J. Edelman Director Director Director Director 120 February 23, 2007 February 23, 2007 February 23, 2007 February 23, 2007 /s/ Kirby L. Hedrick Kirby L. Hedrick /s/ Bruce A. Smith Bruce A. Smith /s/ William T. Van Kleef William T. Van Kleef Director Director February 23, 2007 February 23, 2007 Director February 23, 2007 121 Exhibit Number INDEX TO EXHIBITS Exhibit ** 3.1 — Certificate of Incorporation, as amended, of the Registrant as currently in effect (filed as Exhibit 3.2 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1987 and incorporated herein by reference). 3.2 — Composite copy of Bylaws of the Registrant as currently in effect (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Event: January 29, 2002) dated February 8, 2002 and incorporated herein by reference). 4.1 — Certificate of Designations of Series A Junior Participating Preferred Stock of the Registrant dated August 27, 1997 (filed as Exhibit A of Exhibit 4.1 to the Registrant’s Registration Statement on Form 8-A filed on August 28, 1997 and incorporated herein by reference). 4.2 — Certificate of Designations of Series B Mandatorily Convertible Preferred Stock of the Registrant dated November 9, 1999 (filed as Exhibit 3.4 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999 and incorporated herein by reference). 4.3 — Indenture dated as of October 14, 1993 between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee, relating to the Registrant’s 7 1/4% Notes Due 2023, including form of the Registrant’s 7 1/4% Notes Due 2023 (filed as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1993 and incorporated herein by reference). 4.4 — Indenture relating to Senior Debt Securities dated as of April 1, 1997 between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee (filed as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997 and incorporated herein by reference). 4.5 — First Indenture Supplement relating to $250 million of the Registrant’s 8% Senior Notes Due 2027 dated as of April 1, 1997 between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee (filed as Exhibit 4.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997 and incorporated herein by reference). 4.6 — Second Indenture Supplement, between the Company and U.S. Trust Company of Texas, N.A. as trustee, relating to $100 million of the Registrant’s 7 1/4% Senior Debentures Due 2097 dated as of August 1, 1997 (filed as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997 and incorporated herein by reference). 4.7 — Rights Agreement, dated as of August 27, 1997, between the Registrant and Liberty Bank and Trust Company of Oklahoma City, N.A., as Right’s Agent (filed as Exhibit 4.1 to the Registrant’s Registration Statement on Form 8-A filed on August 28, 1997 and incorporated herein by reference). 4.8 — Amendment No. 1 to Rights Agreement dated as of December 8, 1998, between the Registrant and Bank One Trust Company, as successor Rights Agent to Liberty Bank and Trust Company of Oklahoma City, N.A. (filed as Exhibit 4.2 to the Registrant’s Registration Statement on Form 8-A/A (Amendment No. 1) filed on December 14, 1998 and incorporated herein by reference). 122 Exhibit Number Exhibit ** 4.9 — Third Indenture Supplement relating to $200 million of the Registrant’s 5.25% Notes due 2014 dated April 19, 2004 between the Company and the Bank of New York Trust Company, N.A., as successor trustee to U.S. Trust Company of Texas, N.A. (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-4 (Registration No. 333-116092) and incorporated herein by reference). 10.1 * — Restoration of Retirement Income Plan for Certain Participants in the Noble Energy, Inc. Retirement Plan dated September 21, 1994, effective as of May 19, 1994 (filed as Exhibit 10.5 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1994 and incorporated herein by reference). 10.2 * — Amendment No. 1 to the Restoration of Retirement Income Plan for Certain Participants in the Noble Affiliates Retirement Plan executed March 26, 2002 (filed as Exhibit 10.2 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002 and incorporated herein by reference). 10.3 * — Noble Energy, Inc. Restoration Trust effective August 1, 2002 (filed as Exhibit 10.3 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002 and incorporated herein by reference). 10.4 * — Noble Energy, Inc. Deferred Compensation Plan (formerly known as the Noble Affiliates Thrift Restoration Plan dated May 9, 1994) as restated effective August 1, 2001 (filed as Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002 and incorporated herein by reference). 10.5 * — Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended, dated April 25, 2005, and approved by the stockholders of the Company on April 29, 2003 (filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 and incorporated herein by reference). 10.6 * — Form of Nonqualified Stock Option Agreement under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: February 1, 2005) filed February 7, 2005 and incorporated herein by reference). 10.7 * — Form of Restricted Stock Agreement under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Event: February 1, 2005) filed February 7, 2005 and incorporated herein by reference). 10.8 * — 1988 Nonqualified Stock Option Plan for Non-Employee Directors of the Registrant, as amended and restated, effective as of April 27, 2004 (filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 and incorporated herein by reference). 10.9 * — Noble Energy, Inc. Non-Employee Director Fee Deferral Plan dated April 25, 2002 and effective as of April 23, 2002 (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002 and incorporated herein by reference). 10.10* — Form of Indemnity Agreement entered into between the Registrant and each of the Registrant’s directors and bylaw officers (filed as Exhibit 10.18 to the Registrant’s Annual Report of Form 10-K for the year ended December 31, 1995 and incorporated herein by reference). 123 Exhibit Number Exhibit ** 10.11 — Guaranty of the Registrant dated October 28, 1982, guaranteeing certain obligations of Samedan (filed as Exhibit 10.12 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1993 and incorporated herein by reference). 10.12 — Stock Purchase Agreement dated as of July 1, 1996, between Samedan Oil Corporation and Enterprise Diversified Holdings Incorporated (filed as Exhibit 2.1 to the Registrant’s Current Report on Form 8-K (Date of Event: July 31, 1996) dated August 13, 1996 and incorporated herein by reference). 10.13 — Noble Preferred Stock Remarketing and Registration Rights Agreement dated as of November 10, 1999 by and among the Registrant, Noble Share Trust, The Chase Manhattan Bank, and Donaldson, Lufkin & Jenrette Securities Corporation (filed as Exhibit 10.15 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999 and incorporated herein by reference). 10.14* — Letter agreement dated February 1, 2002 between the Registrant and Charles D. Davidson, terminating Mr. Davidson’s employment agreement and entering into the attached Change of Control Agreement (filed as Exhibit 10.17 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001 and incorporated herein by reference). 10.15* — Form of Change of Control Agreement entered into between the Registrant and each of the Registrant’s officers, with schedule setting forth differences in Change of Control Agreements (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 and incorporated herein by reference). 10.16 — 364-day Credit Agreement dated as of November 27, 2002 among the Registrant, as borrower, JPMorgan Chase Bank, as the administrative agent for the lenders, Wachovia Bank, National Association, as the syndication agent for the lenders, Societe Generale, Citibank, N.A., Deutsche Bank Ag New York Branch, and The Royal Bank of Scotland PLC, as co-documentation agents, and certain commercial lending institutions, as lenders, (filed as Exhibit 10.19 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002 and incorporated herein by reference). 10.17 — 364-day Credit Agreement dated as of October 30, 2003 among the Registrant, as borrower, JPMorgan Chase Bank, as the administrative agent for the lenders, Wachovia Bank, National Association, as the syndication agent for the lenders, Societe Generale, Deutsche Bank Ag New York Branch, and The Royal Bank of Scotland PLC, as co- documentation agents, and certain commercial lending institutions, as lenders (filed as Exhibit 10.20 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference). 10.18 — Term Loan Agreement dated as of January 30, 2004 among Noble Energy Mediterranean Ltd., as borrower, Sumitomo Mitsui Banking Corporation, as initial lender and agent for the lenders, and certain commercial lending institutions, as lenders (filed as Exhibit 99.1 to the Registrant’s Current Report on Form 8-K (Date of Event: January 30, 2004) filed May 10, 2004 and incorporated herein by reference). 10.19 — Guaranty of the Company dated January 30, 2004 guaranteeing obligations of Noble Energy Mediterranean, Ltd. under the Term Loan Agreement dated January 30, 2004 (filed as Exhibit 99.2 to the Registrant’s Current Report on Form 8-K (Date of Event: January 30, 2004) filed May 10, 2004 and incorporated herein by reference). 124 Exhibit Number Exhibit ** 10.20 — Term Loan Agreement dated as of February 2, 2004 among Noble Energy Mediterranean Ltd., as borrower, Bank One, NA, as agent for the lenders, and certain commercial lending institutions, as lenders (filed as Exhibit 99.3 to the Registrant’s Current Report on Form 8-K (Date of Event: January 30, 2004) filed May 10, 2004 and incorporated herein by reference). 10.21 — Guaranty of the Company dated February 2, 2004 guaranteeing obligations of Noble Energy Mediterranean, Ltd. under the Term Loan Agreement dated February 2, 2004 (filed as Exhibit 99.4 to the Registrant’s Current Report on Form 8-K (Date of Event: January 30, 2004) filed May 10, 2004 and incorporated herein by reference). 10.22 — Term Loan Agreement dated as of February 4, 2004 among Noble Energy Mediterranean Ltd., as borrower, The Royal Bank of Scotland Finance (Ireland), as agent for the lenders and as the initial lender (filed as Exhibit 99.5 to the Registrant’s Current Report on Form 8-K (Date of Event: January 30, 2004) filed May 10, 2004 and incorporated herein by reference). 10.23 — Guaranty of the Company dated February 4, 2004 guaranteeing obligations of Noble Energy Mediterranean, Ltd. under the Term Loan Agreement dated February 4, 2004 (filed as Exhibit 99.6 to the Registrant’s Current Report on Form 8-K (Date of Event: January 30, 2004) filed May 10, 2004 and incorporated herein by reference). 10.24* — Noble Energy, Inc. 2004 Long-Term Incentive Plan effective as of January 1, 2004 (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 and incorporated herein by reference). 10.25* — Form of Performance Units Agreement under the Noble Energy, Inc. 2004 Long-Term Incentive Program (filed as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K (Date of Event: February 1, 2005) filed February 7, 2005 and incorporated herein by reference). 10.26 — Purchase and Sale Agreement, dated February 7, 2006, among Noble Energy Production, Inc., U.S. Exploration Holdings, LLC, U.S. Exploration Holdings, Inc. and United States Exploration, Inc., filed herewith (filed as Exhibit 10.28 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2005 and incorporated herein by reference). 10.27 — $2.1 billion Five-Year Credit Agreement, dated December 9, 2005, among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, Wachovia Bank, National Association and The Royal Bank of Scotland PLC, as co-syndication agents, Deutsche Bank Securities Inc. and Citibank, N.A., as co-documentation agents, and certain other commercial lending institutions named therein (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: December 9, 2005), filed December 14, 2005 and incorporated herein by reference). 10.28 — $2.1 billion Five-Year Credit Agreement, dated November 30, 2006, among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, Wachovia Bank, National Association and The Royal Bank of Scotland PLC, as co-syndication agents, Deutsche Bank Securities Inc., Citibank, N.A. and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as co-documentation agents, and certain other commercial lending institutions named therein (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: November 30, 2006), filed December 6, 2006 and incorporated herein by reference). 125 Exhibit Number Exhibit ** 10.29* — Noble Energy, Inc. 2005 Non-Employee Director Fee Deferral Plan, dated December 5, 2005 and effective as of January 1, 2005 (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: December 5, 2005), filed December 8, 2005 and incorporated herein by reference). 10.30* — Amendment No. 1 to the Noble Energy, Inc. Non-Employee Director Fee Deferral Plan, dated December 5, 2005 and effective as of January 1, 2005 (filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K (Date of Event: December 5, 2005), filed December 8, 2005 and incorporated herein by reference). 10.31* — Consulting Agreement, dated May 9, 2005 but commencing May 16, 2005, by and between Noble Energy, Inc. and Thomas J. Edelman (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: May 16, 2005), filed May 20, 2005 and incorporated herein by reference). 10.32* — 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: April 26, 2005) filed April 29, 2005 and incorporated herein by reference). 10.33* — Form of Stock Option Agreement under the Noble Energy, Inc. 2005 Non-Employee Director Stock Plan (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and incorporated herein by reference). 10.34* — Form of Restricted Stock Agreement under the Noble Energy, Inc. 2005 Non-Employee Director Stock Plan (filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and incorporated herein by reference). 10.35* — Form of Restricted Stock Agreement under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan entered into by certain executive officers and key employees of the Company on May 16, 2005 and August 1, 2005, respectively (filed as Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and incorporated herein by reference). 10.36 — Purchase and Sale Agreement dated May 15, 2006 by and between the Company and Coldren Resources LP (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006 and incorporated herein by reference). 10.37* — Noble Energy, Inc. Change of Control Severance Plan for Executives (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: October 24, 2006) filed October 30, 2006 and incorporated herein by reference). 12.1 — Computation of ratio of earnings to fixed charges. 21 — Subsidiaries, filed herewith. 23.1 — Consent of Independent Registered Public Accounting Firm—KPMG LLP, filed herewith. 23.2 — Consent of Independent Registered Public Accounting Firm—PricewaterhouseCoopers LLP, filed herewith. 23.3 23.4 31.1 — Consent of Independent Registered Public Accounting Firm—UHY LLP, filed herewith. — Consent of Netherland, Sewell & Associates, Inc., filed herewith. — Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241). 126 Exhibit Number Exhibit ** 31.2 — Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241). 32.1 — Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350). 32.2 — Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350). 99.1 — Report of Independent Public Accounting Firm—PricewaterhouseCoopers LLP, filed herewith. 99.2 99.3 — Report of Independent Public Accounting Firm—UHY LLP, filed herewith. — Report of Netherland, Sewell & Associates, Inc, filed herewith. * Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto. ** Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the Senior Vice President and Chief Financial Officer, Noble Energy, Inc., 100 Glenborough Drive, Suite 100, Houston, Texas 77067. 127 In this report, the following abbreviations are used: GLOSSARY Barrel(s) Thousand barrels Million barrels Barrels per day Thousand barrels per day Barrels oil per day Barrels oil equivalent Thousand barrels oil equivalent Million barrels oil equivalent Barrels oil equivalent per day Thousand gallons Kilowatt Kilowatt hours Megawatt Thousand cubic feet Million cubic feet Billion cubic feet Trillion cubic feet Thousand cubic feet per day Million cubic feet per day Thousand cubic feet equivalent Million cubic feet equivalent Billion cubic feet equivalent British thermal unit Million British thermal units Bbl(s) MBbls MMBbls Bpd MBpd Bopd Boe MBoe MMBoe Boepd Kgal KW KWh MW Mcf MMcf Bcf Tcf Mcfpd MMcfpd Mcfe MMcfe Bcfe BTU MMBtu MMBtupd Million British thermal units per day Btupcf MT MTpd LNG LPG NGL British thermal unit per cubic foot Metric tons Metric tons per day Liquefied natural gas Liquefied petroleum gas Natural Gas Liquid 128 ...a balanced company with a simplified business model. In 2006, we completed our transition to a simplified business model based on building a portfolio of high quality and long- lived assets with an inventory of lower risk development projects and an exploration program offering substantial long-term impact. Over the past four years, we have undertaken a number of steps that have led to the realization of the business model envisioned in 2003: • Several major international projects have been completed on time and within budget. • A large portfolio of lower risk, long-lived assets has been added. • The exploration portfolio has been strengthened. • Mature and declining assets have been sold. • Our global asset base is now balanced between International and North America. Going forward, we will pursue a broad array of projects, from lower risk development to high-growth exploration. S R O T C E R I D S R E C I F F O E V I T U C E X E N O I T A M R O F N I E T A R O P R O C CHARLES D. DAVIDSON (4) Chairman of the Board, President and Chief Executive Officer, Noble Energy, Inc. JEFFREY L. BERENSON (2) (3) President and Chief Executive Officer, Berenson & Company MICHAEL A. CAWLEY (1) (3) Trustee, President and Chief Executive Officer, The Samuel Roberts Noble Foundation, Inc. EDWARD F. COX (2) (3) (4) THOMAS J. EDELMAN (4) Partner, law firm of Patterson Belknap Webb & Tyler LLP Former Chairman of the Board and Chief Executive Officer, Patina Oil & Gas Corporation KIRBY L. HEDRICK (2) (3) (4) Former Executive Vice President, Phillips Petroleum Company BRUCE A. SMITH (1) (3) Chairman, President and Chief Executive Officer, Tesoro Corporation WILLIAM T. VAN KLEEF (1) (3) Former Executive Vice President and Chief Operating Officer, Tesoro Corporation COMMITTEE MEMBERSHIP (1) Audit Committee (2) Compensation, Benefits and Stock Options Committee (3) Corporate Governance and Nominating Committee (4) Environment, Health and Safety Committee CHARLES D. DAVIDSON ALAN R. BULLINGTON ROBERT K. BURLESON SUSAN M. CUNNINGHAM ARNOLD J. JOHNSON DAVID L. STOVER CHRIS TONG Chairman of the Board, President, Chief Executive Officer and Director Senior Vice President, International Senior Vice President, Business Administration Senior Vice President, Exploration and Corporate Reserves Vice President, General Counsel and Secretary Executive Vice President and Chief Operating Officer Senior Vice President and Chief Financial Officer ANNUAL MEETING The Annual Meeting of Stockholders of Noble Energy, Inc. will be held on Tuesday, April 24, 2007, at 9:30 a.m., Central Time, at the Company’s headquarters located at 100 Glenborough Drive, Suite 100, Houston, TX 77067-3610. All stockholders are cordially invited to attend. FORM 10-K The Company’s Annual Report on Form 10-K for the year ended December 31, 2006, as filed with the Securities and Exchange Commission, is included in this report. Additional copies are available without charge upon request by writing to the Chief Financial Officer, Noble Energy, Inc., 100 Glenborough Drive, Suite 100, Houston, Texas 77067-3610, via the Company’s Internet website: http://www.nobleenergyinc.com, or via the Securities and Exchange Commission’s Internet website: http://www.sec.gov. FORWARD LOOKING STATEMENT This 2006 Annual Report to stockholders contains forward-looking statements based on expectations, estimates and projections as of the date of this report. 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” in Noble Energy’s Form 10-K included in this report. NOBLE ENERGY, INC. Corporate Headquarters 100 Glenborough Drive Suite 100 Houston, Texas 77067-3610 (281) 872.3100 INVESTOR RELATIONS Greg Panagos Director of Investor Relations and Planning (281) 872.3100 Investor_Relations@nobleenergyinc.com www.nobleenergyinc.com INDEPENDENT PUBLIC ACCOUNTANTS KPMG LLP TRANSFER AGENT AND REGISTRAR Wells Fargo Bank, N. A. Shareowner Services 161 North Concord Exchange South St. Paul, MN 55075-1139 (800) 468.9716 stocktransfer@wellsfargo.com COMMON STOCK LISTED NEW YORK STOCK EXCHANGE Symbol - NBL 100 Glenborough Drive Suite 100 Houston, TX 77067-3610 nobleenergyinc.com 2 0 0 6 N O B L E E N E R G Y , I N C . A N N U A L R E P O R T