10-K 1 h92808e10-k.txt BURLINGTON RESOURCES INC. - DECEMBER 31, 2001 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 COMMISSION FILE NUMBER 1-9971 BURLINGTON RESOURCES INC. 5051 WESTHEIMER, SUITE 1400, HOUSTON, TEXAS 77056 TELEPHONE: (713) 624-9500 INCORPORATED IN THE STATE OF DELAWARE EMPLOYER IDENTIFICATION NO. 91-1413284 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: COMMON STOCK, PAR VALUE $.01 PER SHARE PREFERRED STOCK PURCHASE RIGHTS THE ABOVE SECURITIES ARE REGISTERED ON THE NEW YORK STOCK EXCHANGE. SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE 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 X 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 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. [ ] State the aggregate market value of the voting stock held by non-affiliates of the registrant: Common Stock aggregate market value as of January 31, 2002: $6,878,464,321 Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. Class: Common Stock, par value $.01 per share, on January 31, 2002, Shares Outstanding: 200,889,729 DOCUMENTS INCORPORATED BY REFERENCE List hereunder the following documents if incorporated by reference and the Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: Burlington Resources Inc. definitive proxy statement, to be filed not later than 120 days after the end of the fiscal year covered by this report, is incorporated by reference into Part III. -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- Below are certain definitions of key terms used in this Form 10-K.

Bbls Barrels BCF Billion Cubic Feet BCFE Billion Cubic Feet of Gas Equivalent MBbls Thousands of Barrels MMBbls Millions of Barrels MCF Thousand Cubic Feet MMCF Million Cubic Feet MCFE Thousand Cubic Feet of Gas Equivalent MMCFE Million Cubic Feet of Gas Equivalent MMBTU Million British Thermal Units TCF Trillion Cubic Feet TCFE Trillion Cubic Feet of Gas Equivalent 2-D Two Dimensional 3-D Three Dimensional DD&A Depreciation, Depletion and Amortization NGLs Natural Gas Liquids Deepwater Water Depths of 1,000 Feet or Greater in the Gulf of Mexico Shelf Shallow Waters of the Outer Continental Shelf in the Gulf of Mexico

Developed Acreage is the number of acres that are allocated or assignable to producing wells or wells capable of production. Development well is a well drilled within the proved area of an oil or natural gas field to the depth of a stratigraphic horizon known to be productive. Dry Hole is a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Exploratory well is a well drilled to find and produce oil or natural gas reserves that is not a development well. Farm-in or farm-out is an agreement whereby the owner of a working interest in an oil and gas lease assigns the working interest or a portion thereof to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in," while the interest transferred by the assignor is a "farm-out." Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition. Gross acres or gross wells are the total acres or wells in which a working interest is owned. Net acreage and net oil and gas wells are obtained by multiplying gross acreage and gross oil and gas wells by the Company's working interest percentage in the properties. Oil and NGLs are converted into cubic feet of gas equivalent based on 6 MCF of gas to one barrel of oil or NGLs. Productive well is a well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Proved reserves represent estimated quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, can be recovered in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if shown to be economically producible by either actual production or conclusive formation tests. Proved developed reserves are the portion of proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are the portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage, or from existing wells where a relatively major expenditure is required for completion. Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas. Working interest is the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production. Workover is operations on a producing well to restore or increase production. BURLINGTON RESOURCES INC. TABLE OF CONTENTS

PAGE PART I Items One and Two Business and Properties................................ 1 Employees.............................................. 13 Item Three Legal Proceedings...................................... 13 Item Four Submission of Matters to a Vote of Security Holders.... 14 PART II Item Five Market for Registrant's Common Equity and Related Stockholder Matters................................... 14 Item Six Selected Financial Data................................ 15 Items Seven and Seven A Management's Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures About Market Risk......... 15 Item Eight Financial Statements and Supplementary Financial Information........................................... 27 Item Nine Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................... 60 PART III Items Ten and Eleven Directors and Executive Officers of the Registrant and Executive Compensation................................ 61 Item Twelve Security Ownership of Certain Beneficial Owners and Management............................................ 61 Item Thirteen Certain Relationships and Related Transactions......... 61 PART IV Item Fourteen Exhibits, Financial Statement Schedules and Reports on Form 8-K.............................................. 62

PART I ITEMS ONE AND TWO BUSINESS AND PROPERTIES Burlington Resources Inc. ("BR") is a holding company engaged, through its principal subsidiaries, Burlington Resources Oil & Gas Company LP (formerly known as Burlington Resources Oil & Gas Company), The Louisiana Land and Exploration Company ("LL&E"), Burlington Resources Canada Ltd. (formerly known as Poco Petroleums Ltd.), Canadian Hunter Exploration Ltd. ("Hunter"), and their affiliated companies (collectively the "Company"), in the exploration for and the development, production and marketing of crude oil, NGLs and natural gas. On September 17, 2001, as part of a reorganization of the Company's Canadian subsidiaries, Burlington Resources Canada Inc., Burlington Resources Canada Energy Ltd. and another wholly-owned Canadian subsidiary of the Company, were amalgamated and are now known as Burlington Resources Canada Ltd. The Company is one of North America's largest producers of natural gas. On October 8, 2001, BR and Hunter entered into an agreement pursuant to which BR agreed to make an offer to purchase all of the outstanding shares of Hunter for cash consideration of C$53 per share representing an aggregate value of approximately U.S. $2.1 billion resulting in an excess purchase price of approximately $793 million which has been reflected as goodwill. On December 5, 2001, the transaction was consummated. This acquisition was funded primarily with proceeds from the issuance of $1.5 billion of fixed-rate notes and $400 million of commercial paper. The transaction was accounted for under the purchase method. The Hunter acquisition added a portfolio of attractive producing properties, long-lived reserves and exploration and exploitation potential. The assets acquired in the acquisition are primarily located in Canada's Western Canadian Sedimentary Basin, an area in which the Company operated prior to the Hunter acquisition. The most significant of the assets is the Deep Basin, North America's third-largest natural gas field, with approximately 1.5 million gross acres and 17 major producing horizons. The Hunter acquisition added estimated proved reserves of 1.3 TCFE along with approximately two million net undeveloped acres. The Hunter properties averaged net production of 364 MMCF of gas per day, 16.7 MBbls of NGLs per day and .5 MBbls of oil per day during December 2001, the period in which the Company owned and operated these assets. See Note 2 of Notes to Consolidated Financial Statements for more information related to this transaction. In October 2001, the Company announced its intent to sell certain non-core, non-strategic properties in order to improve the overall quality of its portfolio. As a result, in December 2001, the Company recorded a pretax impairment charge of $184 million ($116 million after tax) primarily related to these properties resulting in net properties held for sale of $338 million and related restructuring liabilities of $10 million. The $10 million restructuring liability is related to severance and other exit costs and is included in Accounts Payable at December 31, 2001. The held for sale properties are expected to be sold in 2002. The Company expects to use the proceeds from property sales to repay debt. In November 1999, BR consummated the acquisition of Poco Petroleums Ltd. valued at approximately $2.5 billion. In October 1997, BR completed a merger with LL&E valued at approximately $3 billion. Both transactions were accounted for under the pooling of interests method. To reflect the change in the characteristics of its oil and gas properties, in 2001, the Company began reporting its production volumes and reserves in three streams: natural gas, crude oil and NGLs. Under this methodology, gas production and reserves are reported after extracting liquids and eliminating non-hydrocarbon gases from the natural gas stream. This change had no financial impact and no material impact on total equivalent reserves or production volumes. Amounts for prior years have been reclassified to conform to current presentation. Following is a review of the Company's worldwide major operating areas. 1 NORTH AMERICA The Company's asset base is dominated by North American natural gas properties. Its extensive North American lease holdings extend from the USA's Gulf of Mexico to Canada's Mackenzie Delta region in the Northwest Territories of the Canadian Arctic and Alaska's north slope. Reflecting a diverse yet balanced portfolio, the Company's North American operations include a mix of production, exploitation and exploration assets. In 2001, oil and gas capital expenditures for the Company's USA operations totaled $583 million, and consisted of $403 million for development projects, $113 million for exploration and $67 million for proved reserve acquisitions. The Company's USA production in 2001 represented 67 percent of the Company's total or 1,121 MMCF of gas per day, 34.6 MBbls of NGLs per day and 44.0 MBbls of oil per day. At December 31, 2001, USA proved reserves totaled 7.7 TCFE and represented 66 percent of the Company's total. In 2001, oil and gas capital expenditures for the Company's Canadian operations totaled $2,282 million, and consisted of $288 million for development projects, $94 million for exploration and $1,900 million for proved reserve acquisitions, primarily the Hunter acquisition. The Company's Canadian production in 2001 represented 24 percent of the Company's total or 433 MMCF of gas per day, 12.5 MBbls of NGLs per day and 11.9 MBbls of oil per day. At December 31, 2001, Canadian proved reserves totaled 2.8 TCFE and represented 23 percent of the Company's total. USA San Juan Basin The San Juan Basin ("San Juan") is the Company's most prolific operating area in terms of reserves and production. The area's activities are centered in northwest New Mexico and southwest Colorado. San Juan encompasses nearly 7,500 square miles, or approximately 4.8 million acres, with the major portion located in the New Mexico counties of Rio Arriba and San Juan. The Company is a significant holder of productive leasehold acreage in this area with over 840,000 net acres under its control. The Company operates over 6,800 well completions in San Juan and holds interests in an additional 3,900 non-operated well completions. The Company also owns and operates the Val Verde gathering and processing system, consisting of one of San Juan's largest treating plants and approximately 460 miles of gathering lines with 12 compressor stations. In 2001, the Company invested $146 million in oil and gas capital that included investments for over 275 new wells and approximately 630 mechanical workovers. Over 170 of the new wells and 360 of the workovers were Company operated. The Company's net production from San Juan averaged approximately 629 MMCF of gas per day, 28.8 MBbls of NGLs per day and 1.4 MBbls of oil per day during 2001. A majority of the Company's growth in San Juan during the 1990's came from production of coalbed methane gas from the Fruitland Coal formation. Beginning in 1997, as the Fruitland Coal play matured, the Company began placing greater emphasis on increasing production from conventional gas-producing formations such as the Mesaverde, the Pictured Cliffs and the Dakota. The Mesaverde formation, which consists of the Lewis Shale, Cliffhouse, Menefee and Point Lookout sands, is the largest producing conventional formation in San Juan. In 2001, the Company continued its aggressive infill drilling program in San Juan's Mesaverde formation developing an additional 76 BCFE of reserves. In the last four years, the Company has added over 400 BCFE of reserves in the Mesaverde formation and developed just over one half of these reserves. The Company drilled 11 increased density wells in two areas in the Dakota formation and obtained production and pressure data in 2001. Based on this data, the Company presented a request for basin wide Dakota well spacing of 80 acres to the New Mexico Oil Conservation Division on October 18, 2001. San Juan is planning 15 of the 80-acre Dakota wells for 2002. Although the Company's production from the Fruitland Coal formation peaked in 1998, the Company continues to optimize coal gas production through the application of technology. The Company has an ongoing optimization program that consists of recavitating existing wells, adding compression and installing artificial 2 lift, where appropriate, to mitigate production decline. In 2001, net production from the Fruitland Coal averaged 253 MMCF of gas per day from approximately 1,400 wells. Development of the conventional horizons and minimizing production decline in the Fruitland Coal continue to be a primary focus for the Company in San Juan. In 2002, the Company will continue to exploit the San Juan reserve base with low-risk, high return development projects while setting up future exploitation opportunities by testing new ideas such as increased density drilling in the Fruitland Coal and Pictured Cliffs formations. Wind River Basin The Madden Field, located in the Wind River Basin ("Wind River"), covers more than 70,000 acres in Fremont and Natrona Counties, Wyoming. Production in this basin occurs from multiple horizons ranging in depth from 5,000 feet to over 25,000 feet. During 2001, the Company delineated the deep Madison reservoir with the testing of the Big Horn #6-27 wildcat, accelerated infill development with the drilling of the Big Horn #7-34 and #8-35 wells and continued construction of the Lost Cabin Gas Plant Train III. All gas produced from the Madison formation is sour and is currently processed at Lost Cabin Gas Plant Trains I and II which have a combined inlet capacity of 130 MMCF of gas per day. Completion of Lost Cabin Gas Plant Train III is expected during the third quarter of 2002, adding 180 MMCF of gas per day of inlet capacity. Total Lost Cabin Gas Plant inlet capacity will then be 310 MMCF of gas per day with plant tail gate capacity of 200 MMCF of gas per day. The Company owns a 49 percent working interest in the plant and approximately 42 percent of the Madison reservoir. In Wind River, the Company invested $30 million on approximately 30 drilling and workover projects in the deep Madison and shallower formations. The Company also invested $65 million on plant construction in 2001. Net production for Wind River averaged 74 MMCF of gas per day in 2001. Williston Basin The Williston Basin ("Williston") encompasses approximately 225,000 square miles and has multiple producing horizons. The Company controls over 3.6 million acres in Williston through both mineral and leasehold interests. Net production for Williston averaged 7 MMCF of gas per day and 14.0 MBbls of oil per day in 2001. Activities in Williston have been focused on the Cedar Creek Anticline. Production from the Cedar Creek Anticline was 9.6 MBbls of oil per day during 2001. The Company successfully unitized the Cedar Hills South Unit and initiated waterflood development during 2001. The Company also initiated a down-spacing pilot in the East Lookout Butte Unit during 2001. This pilot will test the feasibility of 160-acre infill wells to improve waterflood efficiency. In 2001, the Company invested $51 million on drilling and workover projects in Williston. Certain non-core producing assets in Williston are scheduled for divestiture during 2002. Anadarko Basin The Anadarko Basin ("Anadarko") encompasses over 30,000 square miles and contains some of the deepest producing formations in the world. The Company produces from multiple horizons in the basin, ranging in depth from 11,000 feet to over 21,000 feet. The Company controls over 250,000 net acres principally located in western Oklahoma. Net production for Anadarko averaged 97 MMCF of gas per day and 1.4 MBbls of NGLs per day in 2001. In 2001, the Company invested $45 million in Anadarko. Permian Basin In 2001, Permian Basin ("Permian") operations were focused primarily on the Waddell Ranch and Sonora areas. These areas comprise 62 percent of the Company's net production from this basin. The remainder of Permian operations were outsourced under property management agreements and are scheduled for divestiture in 2002. Net production for the entire Permian averaged 54 MMCF of gas per day, 2.3 MBbls of NGLs per day and 8.0 MBbls of oil per day in 2001. The Company spent $33 million in Permian during 2001. 3 Onshore Gulf Coast The Onshore Gulf Coast covers plays in south Louisiana and south and east Texas, with a net acreage position of more than 870,000 acres including 660,000 acres of mineral fee lands in south Louisiana where the Company owns the mineral rights and surface lands. Net production from these plays in 2001 averaged 134 MMCF of gas per day, .5 MBbls of NGLs per day and 7 MBbls of oil per day. The focus for south Louisiana centers on exploiting lower risk opportunities in and around core assets while exploring select higher risk, higher reward opportunities. In south Louisiana, the Company spent $59 million of oil and gas capital to participate in a total of 44 projects in 2001. Exploitation activities included the drilling of a deeper well on the northwest flank in Bay St. Elaine. An offset well was drilled resulting in accelerated development of the shallower pay encountered in the initial well. Additional drilling successes also occurred at the Pass Wilson and Ramos fields. Activity in south and east Texas in 2001 focused primarily on the development of assets in order to maintain production volumes. The Company invested approximately $6 million of oil and gas capital on four projects. Net production was 22 MMCF of gas per day at Armstrong Ranch in Jim Hogg County where the Company has drilled 11 wells over the past three years. The Company plans to divest substantially all of its south and east Texas assets in 2002 and focus on opportunities in south Louisiana with its significant land position and large 3-D seismic database. Gulf of Mexico Shelf Trend The Gulf of Mexico Shelf Trend ("Shelf") encompasses plays in the shallow waters of the Gulf of Mexico at water depths of less than 1,000 feet. Over the last three years, the Company has de-emphasized activity in the Shelf in favor of investments in other areas which have longer-life assets with more favorable cost structures and investment economics. Accordingly, capital investments in this area have been reduced from annual levels of over $200 million in 1998 to levels below $50 million in each of the last three years. During 2001, the Company participated in a total of 42 Shelf projects and produced an average of 109 MMCF of gas per day, .9 MBbls of NGLs per day and 6.7 MBbls of oil per day. The Company plans to divest substantially all of its Shelf assets in 2002 and will focus its Gulf Coast activities on onshore south Louisiana. Deepwater Gulf of Mexico The Company owns 176,000 net acres in the deepwater provinces of the Gulf of Mexico ("Deepwater"). The Company's exploration strategy for Deepwater focuses on exploring opportunities identified on Company owned leases, supplemented by third party generated prospects. The Company invested $78 million in Deepwater in 2001. Net production during 2001 averaged 12 MMCF of gas per day and 2.1 MBbls of oil per day from the non-operated Pluto project that was completed in late 1999. The Company plans to divest Pluto in early 2002. Alaska The Company was successful in the May 2001 Alaska State lease sale, purchasing 184,320 net acres of land for $2 million. These lands are located in the gas prone foothills south of Prudhoe Bay. CANADA Western Canadian Sedimentary Basin In the Western Canadian Sedimentary Basin, the Company is active in exploration, exploitation and production of oil and gas. A portfolio of opportunities is maintained ranging from conventional exploration and exploitation in Alberta and British Columbia, to frontier exploration in the Mackenzie Delta. Exploitation and exploration efforts in 2001 were focused primarily within the Mesozoic and Mississippian sections of Central Alberta, in and around the existing producing assets of Whitecourt/Wolf and O'Chiese. The multi-zone potential of these areas, ranging in depth from 4,100 feet to 10,500 feet, makes 4 them an attractive part of the basin, and core assets to the Company. Eleven exploration and 124 exploitation successes were realized in these asset areas, and will create additional drilling locations for 2002. A single well Banff discovery in the O'Chiese area has a gross potential of 40 BCF of gas with high deliverability and will attract more drilling in 2002. The development and exploitation program in the Wolf area resulted in the Wolf plant being loaded to capacity. Net production from these two assets averaged 225 MMCF of gas per day, 7.5 MBbls of NGLs per day and 2.3 MBbls of oil per day for 2001 with an investment of $172 million. Exploitation and exploration activities in eastern Alberta and southeast Saskatchewan in the shallow gas sands also resulted in 78 successes. Net production averaged 65 MMCF of gas per day, 2.7 MBbls of NGLs per day and 8.6 MBbls of oil per day with an investment of $60 million for 2001. Higher impact exploration opportunities have been pursued within the deeper Devonian section of western and northern Alberta and northeastern British Columbia. Active areas range from the Gregg Lakes/Berland area to the Hamburg area in Alberta, and the foothills trend of Bullmoose/Sikunka in northeast British Columbia. A successful 2001 development re-entry was drilled in the Gregg Lakes area, targeting the Cooking Lake formation to a total vertical depth of 18,000 feet. This is the second successful well in this field and one of the deepest horizontal wells in western Canada at 21,670 feet measured depth. Both wells are expected to be on production in 2002. Foothills exploration and development drilling in British Columbia was reduced in 2001 with only two gross wells being drilled. The Company will be reducing its capital exposure on this risky play trend in the future by utilizing farm-outs to evaluate the future potential of its lands. Exploration and development drilling in the Hamburg/Lady Fern area, for Slave Point reef targets using 3-D seismic data, continues to confirm the Company's interpretation of the geophysical signature and is expected to result in a number of additional locations for 2002. Net production from the area averaged 114 MMCF of gas per day, .9 MBbls of NGLs per day and 1.0 MBbls of oil per day for 2001. The Company invested $114 million here. Beaufort Basin The Northwest Territories Mackenzie Delta exploration program continued an aggressive pace in 2001. The Company and its partners, BP/Canada and Chevron, completed 181 kilometers ("km") of 2-D and 139 square km of 3-D seismic on our 540,000 gross acre exploration licenses. Plans are in place to shoot 310 square km of 3-D seismic in 2002 and begin drilling exploration wells in 2003. Because its costs are currently being carried by its partners, the Company incurred no expenditures here during 2001. OTHER INTERNATIONAL Other International operations are a combination of exploration projects and large field development operations. Key focus areas of operations are in the Northwest European Shelf, North Africa, Latin America, the Far East and West Africa. In 2001, oil and gas capital expenditures for Other International operations totaled $217 million and consisted of $135 million for development projects, $52 million for exploration and $30 million related to proved reserve acquisitions. Other International production in 2001 represented nine percent of the Company's total or 170 MMCF of gas per day and 7.3 MBbls of oil per day. At December 31, 2001, Other International proved reserves totaled 1.3 TCFE and represented 11 percent of the Company's total. Northwest European Shelf Other International development and production operations are currently focused in Northwest Europe, which provides the majority of production outside of the U.S. and Canada and includes assets in the East Irish Sea and in the United Kingdom ("U.K.") and Dutch sectors of the North Sea. The East Irish Sea assets became part of the portfolio in 1997 with the acquisition of ten licenses covering 267,000 acres. The Company has a 100 percent working interest in seven operated gas fields. First production from the two sweet gas fields at Dalton and Millom commenced in the third quarter of 1999 and at year-end 2001, the last of six producing wells drilled at Millom was being completed. Development of the sour gas fields is now underway with first production planned in 2004. In addition to offshore production facilities and 5 pipelines, a new onshore processing terminal is expected to be built to receive and process the sour gas prior to final sale. Net production from the East Irish Sea asset averaged 100 MMCF of gas per day during 2001. The Company invested $81 million in the East Irish Sea in 2001. The Company's remaining Northwest European Shelf operations consist of non-operated production from the Brae and T-Block complexes in the U.K. sector of the North Sea and from the CLAM joint venture in the Dutch sector. North Africa The Company's North African operations are concentrated in Algeria and offshore Egypt. Development operations are now underway in Algeria, with first production expected in the first half of 2003. The Company invested $62 million in Algeria in 2001. In Menzel Lejmat Block 405a, in Algeria's Berkine Basin, the Company is the operator and holds a 65 percent working interest. A total of 31 wells have been drilled, including ten wildcat exploration wells. Development of the two MLN Fields is now underway under a parliamentary decree and the Exploitation Permit, issued by the Algerian government in late 2000. During 2001, the Company signed a new Petroleum Sharing Contract ("PSC") with Sonatrach, the Algerian national oil company, for an additional exploration license, Block 402d, in the Berkine Basin. During 2002, 3-D seismic operations are expected to commence under this new PSC. The Company also holds a small interest in the Ourhoud Field in the northeast portion of the block. Ourhoud is currently under development by Sonatrach with first production expected in 2003. Exploitation License Agreements are presently being processed by Sonatrach for additional satellite fields to the MLN Field. In the future, applications will be filed for the southern MLSE Fields. Engineering design preparations were advanced in 2001 for the development of the non-operated Offshore North Sinai gas fields in Egypt for which a gas sales agreement exists with the Egyptian General Petroleum Corporation. Latin America During 2001, the Company pursued opportunities in the sub-Andean plays in South America. Across Ecuador and Peru, the Company farmed-in to three new exploration blocks, shot 200 km of 2-D seismic, drilled one well and concluded negotiations to acquire interests in one producing and one exploitation property. Additionally, the Company made substantial progress toward moving one existing block out of force majeure to enable exploration activities. The exploration farm-ins include a 23.9 percent interest in Peru Block 35 and a 20 percent interest in Peru Block 34. Blocks 34 and 35 have 2.8 million and 2.6 million acres, respectively, in the Ucayali Basin, and are located approximately 100 km north of Camisea. Interest in both blocks was obtained from Repsol, the operator, and Perez Companc. The Mashansha prospect will be drilled on Block 35 in 2002. BR also farmed-in to a 50 percent interest in Ecuador Block 23. The Compania General de Combustibles S.A. operated block is adjacent to Block 24, which is owned 100 percent by BR. Efforts continue to focus on indigenous issues in these two blocks to enable exploration efforts. A field geological study and a 200 km, 2-D seismic acquisition program were completed in Peru Block 87, in an effort to better define multiple prospects. Processing of the data will be completed in time to drill during the dry season of 2002, if warranted. The Guineyacu prospect on Peru Block 32 was drilled mid-year but found sub-economic quantities of oil and the block was subsequently released to the government. In Ecuador, the acquisition of a 25 percent interest in Ecuador Block 7 and a 32.5 percent interest in Ecuador Block 21 from Sipetrol and Clapsa provides production, development and exploration opportunities. This acquisition closed on February 8, 2002. Gross production from Block 7 averaged approximately 14.5 MBbls of oil per day in 2001. Exploration and exploitation opportunities also exist on the block. Development of the Yuralpa Field is underway on Block 21, with first production anticipated during 2003. 6 BR has a 25.7 percent interest in the Sierra Chata concession in the Neuquen Basin in Argentina as a result of the Hunter acquisition. The asset has a gross sales capacity of 178 MMCF of gas per day through 42 producing wells. Net production from this asset averaged 21 MMCF of gas per day during December 2001. Gas marketing efforts have largely focused on Chilean and Argentine markets, facilitated through existing infrastructure, which enables substantial flexibility. BR holds a 13.7 percent interest in the Casanare concession area in Colombia, which has maintained production of 1.5 MBbls of oil per day net, due to a development drilling and workover program. The interest in Casanare is scheduled for divestiture during 2002. Far East In the Far East, the Company continues to focus on selected basins in China. The Company is targeting exploration and exploitation opportunities to add to its existing leasehold position. In 2001, approval was received and work for the Panyu development project began. The Panyu development involves two offshore oil fields, Bootes and Ursa, located in Block 15/34. The Company holds a 24.5 percent non-operated interest in Block 15/34, located in the Pearl River Mouth Basin offshore China. These fields contain net proved reserves of 14.7 MMBbls of oil. Devon is the operator and first production is expected in 2003. The Company obtained the Chuanzhong Block in the Sichuan Basin onshore China in 2000. This natural gas project is currently in the appraisal phase of development and the Company holds a 100 percent operated interest. This project offers an opportunity to apply the Company's expertise in exploitation of tight gas reservoirs in a concession with substantial reserve potential. The project is currently in a pilot phase of drilling new wells and stimulating existing wells. Additional work is contingent on successful negotiation of a long-term gas marketing agreement. The Company invested $15 million in China in 2001. West Africa In West Africa, the Company has been targeting acquisitions of low working interests in a variety of new and untested deepwater plays that have the promise of high upside potential. The three blocks in Gabon that the Company holds with operator, Agip, did not initiate drilling in 2001 due to rig equipment problems. The license period for these blocks has been extended for a year and drilling is expected to occur in the second quarter of 2002. In 2001, the Company added to its exploration acreage portfolio in the region by entering into an agreement with BP to acquire their entire 20 percent interest in Block 21, deepwater Angola. The Company's entry into this block is expected in 2002. Together with its large acreage position in deepwater Gabon, the Company has now established a foothold in a number of plays in the area. The Company's approach is to learn from the exploration activities expected to occur in the coming year. 7 RESERVES The following table sets forth estimates by the Company's petroleum engineers of proved oil, NGL and gas reserves at December 31, 2001. These reserves have been reduced for royalty interests owned by others. To reflect the change in the characteristics of its oil and gas properties, in 2001, the Company began reporting its production volumes and reserves in three streams: natural gas, crude oil and NGLs. Under this methodology, gas reserves are reported after extracting liquids and eliminating non-hydrocarbon gases from the natural gas stream. This change had no material impact on total equivalent reserves.

DECEMBER 31, 2001 ---------------------------------------- PROVED PROVED TOTAL PROVED DEVELOPED UNDEVELOPED RESERVES --------- ----------- ------------ NORTH AMERICA USA Gas (BCF)........................................... 3,771 1,121 4,892 NGLs (MMBbls)....................................... 175.5 52.2 227.7 Oil (MMBbls)........................................ 163.7 80.6 244.3 Total USA (BCFE)............................... 5,806 1,918 7,724 Canada Gas (BCF)........................................... 1,758 378 2,136 NGLs (MMBbls)....................................... 39.3 8.4 47.7 Oil (MMBbls)........................................ 38.4 18.2 56.6 Total Canada (BCFE)............................ 2,224 538 2,762 OTHER INTERNATIONAL Gas (BCF)........................................... 478 419 897 Oil (MMBbls)........................................ 9.3 61.7 71.0 Total Other International (BCFE)............... 534 789 1,323 WORLDWIDE Gas (BCF)........................................... 6,007 1,918 7,925 NGLs (MMBbls)....................................... 214.8 60.6 275.4 Oil (MMBbls)........................................ 211.4 160.5 371.9 Total Worldwide (BCFE)......................... 8,564 3,245 11,808

For further information on reserves, including information on future net cash flows and the standardized measure of discounted future net cash flows, see "Supplementary Financial Information -- Supplemental Oil and Gas Disclosures." PRODUCTIVE WELLS Working interests in productive wells at December 31, 2001 follow.

GROSS NET ------ ------ NORTH AMERICA USA Gas.................................................... 11,493 6,881 Oil.................................................... 4,969 2,894 Canada Gas.................................................... 5,327 3,677 Oil.................................................... 2,228 1,431 OTHER INTERNATIONAL Gas.................................................... 145 24 Oil.................................................... 147 27 WORLDWIDE Gas.................................................... 16,965 10,582 Oil.................................................... 7,344 4,352

8 NET WELLS DRILLED Drilling activity in 2001 was principally in the Western Canadian Sedimentary, San Juan, Gulf Coast, Permian, Anadarko, Wind River and Williston Basins. The following table sets forth the Company's net productive and dry wells.

YEAR ENDED DECEMBER 31, ----------------------- 2001 2000 1999 ----- ----- ----- NORTH AMERICA USA Productive Exploratory.......................................... 6.0 1.2 9.3 Development.......................................... 271.0 159.6 183.1 Dry Exploratory.......................................... 8.5 3.9 9.4 Development.......................................... 10.1 5.2 4.4 ----- ----- ----- Total Net Wells -- USA............................ 295.6 169.9 206.2 ----- ----- ----- Canada Productive Exploratory.......................................... 22.9 56.5 67.4 Development.......................................... 158.8 73.4 30.6 Dry Exploratory.......................................... 13.4 44.1 3.6 Development.......................................... 48.3 17.0 4.2 ----- ----- ----- Total Net Wells -- Canada......................... 243.4 191.0 105.8 ----- ----- ----- OTHER INTERNATIONAL Productive Exploratory.......................................... 2.1 3.2 2.1 Development.......................................... 5.8 2.4 3.2 Dry Exploratory.......................................... 3.1 2.1 2.0 Development.......................................... .1 .1 -- ----- ----- ----- Total Net Wells -- Other International............ 11.1 7.8 7.3 ----- ----- ----- WORLDWIDE Productive Exploratory.......................................... 31.0 60.9 78.8 Development.......................................... 435.6 235.4 216.9 Dry Exploratory.......................................... 25.0 50.1 15.0 Development.......................................... 58.5 22.3 8.6 ----- ----- ----- Total Net Wells -- Worldwide...................... 550.1 368.7 319.3 ===== ===== =====

As of December 31, 2001, 41 gross wells, representing approximately 31 net wells, were being drilled. 9 ACREAGE Working interests in developed and undeveloped acreage at December 31, 2001 follow.

GROSS NET ---------- ---------- NORTH AMERICA USA Developed Acres........................................ 5,430,943 2,927,290 Undeveloped Acres...................................... 10,348,570 8,500,473 Canada Developed Acres........................................ 3,012,054 1,939,946 Undeveloped Acres...................................... 6,180,240 4,467,704 OTHER INTERNATIONAL Developed Acres........................................ 368,263 82,470 Undeveloped Acres...................................... 28,655,846 12,117,035 WORLDWIDE Developed Acres........................................ 8,811,260 4,949,706 Undeveloped Acres...................................... 45,184,656 25,085,212

CAPITAL EXPENDITURES Following are the Company's capital expenditures.

YEAR ENDED DECEMBER 31, ------------------------ 2001 2000 1999 ------ ------ ---- ($ MILLIONS) NORTH AMERICA USA Oil and Gas Activities................................. $ 583 $ 412 $488 Plants & Pipelines..................................... 70 56 14 Administrative......................................... 20 19 38 ------ ------ ---- Total USA......................................... 673 487 540 ------ ------ ---- Canada Oil and Gas Activities................................. 2,282 316 291 Plants & Pipelines..................................... 276 20 4 Administrative......................................... 5 4 4 ------ ------ ---- Total Canada...................................... 2,563 340 299 ------ ------ ---- OTHER INTERNATIONAL Oil and Gas Activities................................. 217 179 148 Administrative......................................... 1 6 2 ------ ------ ---- Total Other International......................... 218 185 150 ------ ------ ---- WORLDWIDE Oil and Gas Activities................................. 3,082 907 927 Plants & Pipelines..................................... 346 76 18 Administrative......................................... 26 29 44 ------ ------ ---- Total Worldwide................................... $3,454 $1,012 $989 ====== ====== ====

Worldwide capital expenditures for oil and gas activities in 2001 of $3,082 million include 27 percent for development, 8 percent for exploration and 65 percent for proved property acquisitions. Proved property acquisitions are primarily related to the Hunter acquisition. Included in capital expenditures for oil and gas activities are exploration costs expensed under the successful efforts method of accounting. 10 OIL AND GAS PRODUCTION AND PRICES The Company's average daily production represents its net ownership and includes royalty interests and net profit interests owned by the Company. In 2001, the Company began reporting its production volumes and reserves in three streams: natural gas, crude oil and NGLs. Under this methodology, gas production is reported after extracting liquids and eliminating non-hydrocarbon gases from the natural gas stream. Amounts for prior years have been reclassified to conform to current presentation. Following are the Company's production and prices.

YEAR ENDED DECEMBER 31, -------------------------- 2001 2000 1999 ------ ------ ------ NORTH AMERICA USA Production Gas (MMCF per day)................................... 1,121 1,265 1,321 NGLs (MBbls per day)................................. 34.6 36.1 33.6 Oil (MBbls per day).................................. 44.0 51.6 57.3 Average Sales Price Gas (per MCF)........................................ $ 3.94 $ 3.28 $ 2.43 NGLs (per Bbl)....................................... 11.41 14.60 8.95 Oil (per Bbl)........................................ $22.63 $24.18 $16.70 Canada Production Gas (MMCF per day)................................... 433 341 376 NGLs (MBbls per day)................................. 12.5 11.1 12.2 Oil (MBbls per day).................................. 11.9 12.5 13.7 Average Sales Price Gas (per MCF)........................................ $ 4.53 $ 4.10 $ 2.32 NGLs (per Bbl)....................................... 22.50 25.38 15.87 Oil (per Bbl)........................................ $26.51 $29.06 $17.70 OTHER INTERNATIONAL Production Gas (MMCF per day)................................... 170 118 86 Oil (MBbls per day).................................. 7.3 9.6 13.2 Average Sales Price Gas (per MCF)........................................ $ 2.45 $ 2.23 $ 1.93 Oil (per Bbl)........................................ $23.42 $27.73 $17.00 WORLDWIDE Production Gas (MMCF per day)................................... 1,724 1,724 1,783 NGLs (MBbls per day)................................. 47.1 47.2 45.8 Oil (MBbls per day).................................. 63.2 73.7 84.2 Average Sales Price Gas (per MCF)........................................ $ 3.94 $ 3.37 $ 2.41 NGLs (per Bbl)....................................... 14.35 17.14 10.79 Oil (per Bbl)........................................ $23.45 $25.44 $16.93

11 PRODUCTION UNIT COSTS Following are the Company's production unit costs. Production costs consist of production taxes and well operating costs.

YEAR ENDED DECEMBER 31, ------------------------ 2001 2000 1999 ------ ----- ----- (PER MCFE) NORTH AMERICA USA Average Production Costs............................... $ .69 $.57 $.49 DD&A Rates............................................. .75 .74 .64 Canada Average Production Costs............................... .65 .69 .53 DD&A Rates............................................. .77 .67 .55 OTHER INTERNATIONAL Average Production Costs............................... .21 .31 .54 DD&A Rates............................................. 1.05 .83 .89 WORLDWIDE Average Production Costs............................... .64 .57 .50 DD&A Rates............................................. $ .78 $.73 $.64

For additional financial information about segments and geographic areas, see Note 13 of Notes to Consolidated Financial Statements. OTHER MATTERS Competition. The Company actively competes for reserve acquisitions, exploration leases and sales of oil and gas, frequently against companies with substantially larger financial and other resources. In its marketing activities, the Company competes with numerous companies for the sale of oil, gas and NGLs. Competitive factors in the Company's business include price, contract terms, quality of service, pipeline access, transportation discounts and distribution efficiencies. Regulation of Oil and Gas Production, Sales and Transportation. The oil and gas industry is subject to regulation by numerous national, state and local governmental agencies and departments throughout the world. Compliance with these regulations is often difficult and costly and noncompliance could result in substantial penalties and risks. Most jurisdictions in which the Company operates also have statutes, rules, regulations or guidelines governing the conservation of natural resources, including the unitization or pooling of oil and gas properties and the establishment of maximum rates of production from oil and gas wells. Some jurisdictions also require the filing of drilling and operating permits, bonds and reports. The failure to comply with these statutes, rules and regulations could result in the imposition of fines and penalties and the suspension or cessation of operations in affected areas. The Company operates various gathering systems. The United States Department of Transportation and certain governmental agencies regulate the safety and operating aspects of the transportation and storage activities of these facilities by prescribing standards. The Federal Energy Regulation Commission ("FERC") has implemented policies allowing interstate pipeline companies to negotiate their rates with individual shippers. The Company will monitor the effects of these policies on its marketing efforts but does not expect that they will have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company. All of the Company's sales of its domestic gas are currently deregulated, although FERC may elect in the future to regulate certain sales. Environmental Regulation. Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect the Company's domestic exploration, development and production operations and the costs of those operations. In addition, certain of the Company's international operations are subject to environmental regulations adminis- 12 tered by foreign governments, including political subdivisions thereof, or by international organizations. These domestic and international laws and regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of permits to conduct exploration, drilling and production operations, the discharge and disposition of generated waste materials, the reclamation and abandonment of wells, sites and facilities and the remediation of contaminated sites. These laws and regulations may impose substantial liabilities for noncompliance and for any contamination resulting from the Company's operations and may require the suspension or cessation of operations in affected areas. Environmental requirements have a substantial impact on the oil and gas industry, and on the costs of doing business. The Company is committed to the protection of the environment throughout its operations and believes that it is in substantial compliance with applicable environmental laws and regulations. The Company believes that environmental stewardship is an important part of its daily business and will continue to make expenditures on a regular basis relating to environmental compliance. The Company also maintains insurance coverage for some environmental risks, although it is not fully insured against all such risks. The Company does not anticipate that it will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on the consolidated financial position or results of operations of the Company. However, because regulatory requirements frequently change and may become more stringent, there can be no assurance that future laws and regulations will not have a material adverse effect on the Company's consolidated financial position, results of operations or cash flows. Filings of Reserve Estimates With Other Agencies. During 2001, the Company filed estimates of oil and gas reserves for the year 2000 with the Department of Energy. These estimates differ by 5 percent or less from the reserve data presented. For information concerning proved oil, NGLs and gas reserves, see page 57. EMPLOYEES The Company had 2,167 and 1,783 employees at December 31, 2001 and 2000, respectively. At December 31, 2001, the Company had no union employees. ITEM THREE LEGAL PROCEEDINGS The Company and numerous other oil and gas companies have been named as defendants in various lawsuits alleging violations of the civil False Claims Act. These lawsuits have been consolidated by the United States Judicial Panel on Multidistrict Litigation for pre-trial proceedings in the matter of In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court for the District of Wyoming ("MDL-1293"). The plaintiffs contend that defendants underpaid royalties on natural gas and NGLs produced on federal and Indian lands through the use of below-market prices, improper deductions, improper measurement techniques and transactions with affiliated companies. Plaintiffs allege that the royalties paid by defendants were lower than the royalties required to be paid under federal regulations and that the forms filed by defendants with the Minerals Management Service ("MMS") of the United States Department of the Interior reporting these royalty payments were false, thereby violating the civil False Claims Act. The United States has intervened in certain of the MDL-1293 cases as to some of the defendants, including the Company. Various administrative proceedings are also pending before the MMS of the United States Department of the Interior with respect to the valuation of natural gas produced by the Company on federal and Indian lands. In general, these proceedings stem from regular MMS audits of the Company's royalty payments over various periods of time and involve the interpretation of the relevant federal regulations. Based on the Company's present understanding of the various governmental and False Claims Act proceedings described above, the Company believes that it has substantial defenses to these claims and intends to vigorously assert such defenses. However, in the event that the Company is found to have violated the civil False Claims Act, the Company could be subject to monetary damages and a variety of sanctions, including double damages, substantial monetary fines, civil penalties and a temporary suspension from entering into 13 future federal mineral leases and other federal contracts for a defined period of time. While the ultimate outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the consolidated financial position of the Company, although results of operations and cash flow could be significantly impacted in the reporting periods in which such matters are resolved. The Company has also been named as a defendant in the lawsuit styled UNOCAL Netherlands B.V., et al v. Continental Netherlands Oil Company B.V., et al, No. 98-854, in the Court of Appeal in The Hague in the Netherlands. Plaintiffs, who are working interest owners in the Q1 Block in the North Sea, have alleged that the Company and other former working interest owners in the adjacent Logger Field in the L16a Block unlawfully trespassed or were otherwise unjustly enriched by producing part of the oil from the adjoining Q1 Block. The plaintiffs claim that the defendants infringed upon plaintiffs' right to produce the minerals present in its license area and acted in violation of generally accepted standards by failing to inform plaintiffs of the overlap of the Logger Field into the Q-1 Block. For all relevant periods, the Company owned a 37.5% working interest in the Logger Field. Following a trial, the District Court in The Hague rendered a Judgment in favor of the defendants, including the Company, dismissing all claims. Plaintiffs thereafter appealed. On October 19, 2000, the Court of Appeal in The Hague issued an interim Judgment in favor of the plaintiffs and ordered that additional evidence be presented to the court relating to issues of both liability and damages. The Company and the other defendants are continuing to vigorously assert defenses against these claims and have presented additional evidence to the Court of Appeal. The Company has also asserted claims of indemnity against two of the defendants from whom it had acquired a portion of its working interest share. The Company is unable at this time to reasonably predict the outcome, or, in the event of an unfavorable outcome, to reasonably estimate the possible loss or range of loss, if any, in this lawsuit. In addition to the foregoing, the Company and its subsidiaries are named defendants in numerous other lawsuits and named parties in governmental and other proceedings arising in the ordinary course of business. While the outcome of these other lawsuits and proceedings cannot be predicted with certainty, management believes these other matters will not have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company. ITEM FOUR SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None PART II ITEM FIVE MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Company's common stock, par value $.01 per share ("Common Stock") is traded on the New York Stock Exchange under the symbol "BR." At December 31, 2001, the number of holders of Common Stock was 17,531. Information on Common Stock prices and quarterly dividends is shown on page 60. 14 ITEM SIX SELECTED FINANCIAL DATA The selected financial data for the Company set forth below for the five years ended December 31, 2001 should be read in conjunction with the consolidated financial statements.

2001 2000 1999 1998 1997 ------- ------ ------ ------ ------ (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) INCOME STATEMENT DATA Revenues....................................... $ 3,326 $3,147 $2,313 $2,225 $2,575 Operating Income (Loss)........................ 1,085 1,191 200 (439) 605 Net Income (Loss).............................. 561 675 (10) (338) 352 Basic Earnings (Loss) per Common Share......... 2.71 3.13 (.05) (1.60) 1.69 Diluted Earnings (Loss) per Common Share....... 2.70 3.12 (.05) (1.60) 1.67 Cash Dividends Declared per Common Share....... $ .55 $ .55 $ .46 $ .46 $ .39 BALANCE SHEET DATA Total Assets................................... $10,582 $7,506 $7,165 $7,060 $7,164 Long-term Debt................................. 4,337 2,301 2,769 2,684 2,317 Stockholders' Equity........................... $ 3,525 $3,750 $3,229 $3,312 $3,561 Common Shares Outstanding...................... 201 216 216 216 209

ITEMS SEVEN AND SEVEN A MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK FINANCIAL CONDITION AND LIQUIDITY The Company's long-term debt to total capital (total capital is defined as long-term debt and stockholders' equity) ratio at December 31, 2001 and December 31, 2000 was 55 percent and 38 percent, respectively. In February 2001, the Company, through its wholly-owned subsidiary, Burlington Resources Finance Company ("BRFC"), issued $400 million of 6.68% Notes due February 15, 2011. On July 18, 2001, the Company's Board of Directors authorized the Company to redeem or repurchase up to $1 billion principal amount of debt securities of the Company. In August 2001, the Company acquired notes with an aggregate principal amount of $710 million and a weighted average interest rate of 7.28% and issued $178 million of 6.4% Notes and $575 million of 7.2% Notes due August 15, 2011 and 2031, respectively. The transaction was accounted for as an exchange of debt instruments and reduced the Company's amount available under its shelf registration statement on file with the Securities and Exchange Commission ("SEC") from $1,500 million to $747 million. On October 8, 2001, the Company's Board of Directors authorized the Company to restore its shelf registration statement to $1,500 million. The Company expects to file such registration statement in the first half of 2002. In November 2001, the Company issued $500 million of 5.6% Notes due December 1, 2006, $500 million of 6.5% Notes due December 1, 2011 and $500 million of 7.4% Notes due December 1, 2031. These notes were issued through a private placement and the proceeds were used, along with cash on hand and the issuance of $400 million of commercial paper, to fund the Hunter acquisition. During 2001, the Company issued $348 million of net commercial paper. Commercial paper outstanding at December 31, 2001 was $675 million with a weighted average interest rate of approximately 3%. On October 1, 2001, the Company retired $150 million of 8 1/2% Notes. The Company also repaid $61 million of other debt during the year. On December 13, 2001, the Company's Board of Directors authorized the Company to redeem or repurchase an additional $700 million principal amount of debt securities. 15 Burlington Resources Capital Trust I, Burlington Resources Capital Trust II (collectively, the "Trusts"), BR and BRFC have a shelf registration statement on file with the SEC as mentioned above. Pursuant to such registration statement, BR may issue debt securities, shares of common stock or preferred stock. In addition, BRFC may issue debt securities and the Trusts may issue trust preferred securities. Net proceeds, terms and pricing of offerings of securities issued under the shelf registration statement will be determined at the time of the offerings. BRFC and the Trusts are wholly owned finance subsidiaries of BR and have no independent assets or operations other than transferring funds to BR's subsidiaries. Any debt issued by BRFC is fully and unconditionally guaranteed by BR. Any trust preferred securities issued by the Trusts are also fully and unconditionally guaranteed by BR. The Company had credit commitments in the form of revolving credit facilities ("revolvers") as of December 31, 2001. The revolvers which are comprised of agreements for $600 million, $400 million and $300 million are available to cover debt due within one year. Therefore, commercial paper, credit facility notes and fixed-rate debt due within one year are classified as long-term debt. Currently, there are no amounts outstanding under the revolvers, however, the Company's outstanding commercial paper reduces the amount of credit available under the revolvers. The $600 million revolver expires in December 2006 and the $400 million and $300 million revolvers expire in December 2002 unless renewed by mutual consent. At expiration of the agreements, the Company has the option to convert the outstanding balances on the $400 million and $300 million revolvers to one-year and five-year plus one day term notes, respectively. Under the covenants of the revolvers, Company debt cannot exceed 60 percent of capitalization (as defined in the agreements). Effective January 2, 2002, the Company entered into a $350 million bridge revolving credit facility in order to finance the acquisition of certain assets from ATCO Gas and Pipelines Ltd. Any advances under the facility are required to be used to finance this acquisition or to repay commercial paper issued in order to finance this acquisition. On January 2, 2002, the Company issued $346 million of commercial paper to fund the acquisition. The facility expires in July 2002. On December 13, 2001, the Company's Board of Directors authorized the Company to issue debt securities, either through a private placement or public offering, in order to refinance any outstanding amounts under the facility or commercial paper issued in connection with the acquisition. Net cash provided by operating activities in 2001 was $2,106 million compared to $1,598 million and $1,102 million in 2000 and 1999, respectively. The increase in 2001 was primarily due to higher operating income, excluding non-cash items, and lower working capital needs. Operating income was higher principally as a result of higher natural gas prices. The increase in 2000 compared to 1999 was primarily due to higher operating income resulting from higher commodity prices partially offset by working capital and other changes. The Company has various commitments primarily related to leases for office space, other property and equipment and demand charges on firm transportation agreements. The Company expects to fund these commitments with cash generated from operations. The following table summarizes the Company's contractual obligations at December 31, 2001.

PAYMENTS DUE BY PERIOD ---------------------------------------------------- LESS THAN AFTER 4 CONTRACTUAL OBLIGATION TOTAL 1 YEAR 1-2 YEARS 3-4 YEARS YEARS ------------------------------------------------- ------ --------- --------- --------- ------- (IN MILLIONS) Long-term debt(1)................................ $3,707 $ 100 $ 63 $500 $3,044 Commercial paper(1).............................. 675 675 -- -- -- Non-cancellable operating leases................. 192 33 54 39 66 Drilling rig commitments......................... 188 63 125 -- -- Transportation demand charges.................... 917 133 244 203 337 ------ ------ ---- ---- ------ Total Contractual Obligations.......... $5,679 $1,004 $486 $742 $3,447 ====== ====== ==== ==== ======

16 --------------- (1) See discussion of long-term debt commercial paper above and Note 6 of Notes to Consolidated Financial Statements. Certain of the Company's contracts require the posting of collateral upon request in the event that the Company's long-term debt is rated below investment grade or ceases to be rated. Those contracts primarily consist of hedging agreements, two Canadian transportation agreements and a natural gas purchase agreement. A few of the hedging agreements also require posting of collateral if the market value of the transactions thereunder exceed a specified dollar threshold that varies with the Company's credit rating. While the mark-to-market positions under the hedging agreements and the natural gas purchase agreement will fluctuate with commodity prices, as a producer, the Company's liquidity exposure due to its outstanding derivative instruments tends to increase when commodity prices increase. Consequently, the Company is most likely to have its largest unfavorable mark-to-market position in a high commodity price environment when it is least likely that a credit support requirement due to an adverse rating action would occur. At December 31, 2001, a rating change would have had no impact on the Company related to the hedging agreements, since the mark-to-market position under each of the respective agreements was favorable to the Company. In the case of the Canadian transportation agreements, the collateral required would be an amount equal to 12 months of estimated demand charges. That amount totaled approximately $9 million as of December 31, 2001. In the normal course of business, the Company has performance obligations which are supported by surety bonds or letters of credit. These obligations are primarily site restoration and dismantlement, royalty payments and exploration programs where governmental organizations require such support. Changes in credit rating also impact the cost of borrowing under the Company's revolvers, but have no impact on availability of credit under the agreements. The revolvers are filed as exhibits 10.18, 10.19 and 10.32 to this Form 10-K. The Company has investments in two entities that it accounts for under the equity method. The book values of the Company's interests in Lost Creek Gathering Company, L.L.C. ("Lost Creek") and CLAM Petroleum B.V. ("CLAM") are $8 million and $24 million, respectively. Lost Creek and CLAM have debt obligations in the amount of $53 million and $20 million, respectively, that are non-recourse to the Company. Management believes that even if the Company's share of the debt obligations of these entities were deemed obligations of the Company, the amounts would not have a material impact on the Company's liquidity. In December 2000, the Company's Board of Directors authorized the repurchase of up to $1 billion of the Company's Common Stock. During 2001, the Company repurchased 16.1 million shares of its Common Stock for approximately $684 million. Through December 31, 2001, the Company has repurchased approximately 16.3 million shares or $693 million of its Common Stock under this $1 billion authorization. The Company has certain other commitments and uncertainties related to its normal operations. Management believes that there are no other commitments or uncertainties that will have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company. CAPITAL EXPENDITURES AND RESOURCES Capital expenditures for 2001 totaled $3,454 million compared to $1,012 million and $989 million in 2000 and 1999, respectively. The Company invested $1,085 million on internal development and exploration of oil and gas properties during 2001 compared to $858 million and $792 million in 2000 and 1999, respectively. The Company invested $1,997 million for property acquisitions in 2001 compared to $49 million and $135 million in 2000 and 1999, respectively. The Company also invested $346 million on plants and pipelines in 2001 compared to $76 million and $18 million in 2000 and 1999, respectively. Property acquisitions and plants and pipelines in 2001 primarily include assets from the Hunter acquisition. See Note 2 of Notes to Consolidated Financial Statements for additional information. Capital expenditures for 2002, excluding proved property acquisitions, are projected to be approximately $1.3 billion. Capital expenditures are expected to be primarily 17 for internal development and exploration of oil and gas properties and plant and pipeline expenditures. Capital expenditures are expected to be funded from internal cash flows. In October 2001, the Company announced its intent to sell certain non-core, non-strategic properties in order to improve the overall quality of its portfolio. As a result, in December 2001, the Company recorded a pretax impairment charge of $184 million ($116 million after tax) primarily related to these properties resulting in net properties held for sale of $338 million and related restructuring liabilities of $10 million. The $10 million restructuring liability is related to severance and other exit costs and is included in Accounts Payable on the Consolidated Balance Sheet at December 31, 2001. The held for sale properties are expected to be sold in 2002. The Company expects to use the proceeds from property sales to repay debt. MARKETING North America (USA and Canada) The Company's marketing strategy is to maximize the value of its production by developing marketing flexibility from the wellhead to its ultimate sale. The Company's natural gas production is gathered, processed, exchanged and transported utilizing various firm and interruptible contracts and routes to access higher value market hubs. The Company's customers include local distribution companies, electric utilities, industrial users and marketers. The Company maintains the capacity to ensure its production can be marketed either at the wellhead or downstream at market sensitive prices. All of the Company's crude oil production is sold to third parties at the wellhead or transported to market hubs where it is sold or exchanged. NGLs are typically sold at field plants or transported to market hubs and sold to third parties. Downgrades or the inability of the Company's customers to maintain their credit rating or credit worthiness could result in an increase in the allowance for unrecoverable receivables from natural gas, NGLs or crude oil revenues or it could result in a change in the Company's assumption process of evaluating collectibility based on situations regarding specific customers and applicable economic conditions. Other International The Company's Other International production is marketed to third parties either directly by the Company or by the operators of the properties. Production is sold at the platforms or local sales points based on spot or contract prices. COMMODITY RISK Substantially all of the Company's crude oil, NGLs and natural gas production is sold on the spot market or under short-term contracts at market sensitive prices. Spot market prices for domestic crude oil and natural gas are subject to volatile trading patterns in the commodity futures market, including among others, the New York Mercantile Exchange ("NYMEX"). Quality differentials, worldwide political developments and the actions of the Organization of Petroleum Exporting Countries also affect crude oil prices. There is also a difference between the NYMEX futures contract price for a particular month and the actual cash price received for that month in a U.S. producing basin or at a U.S. market hub, which is referred to as the "basis differential." On January 1, 2001, the Company adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. SFAS No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. It requires enterprises to recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value. The requisite accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. In accordance with the transition provisions of SFAS No. 133, the Company recorded a net-of-tax cumulative-effect-type adjustment of $366 million loss in accumulated other comprehensive income to recognize at fair value all derivatives that are designated as cash flow hedging instruments. The Company 18 recorded cash flow hedge derivatives liabilities of $582 million ($361 million after tax) and $3 million after tax was recorded in current earnings as a cumulative effect of the change in accounting principle. The Company reclassified, as reductions to earnings during 2001, $322 million ($200 million after tax) from the transition adjustment that was recorded in accumulated other comprehensive income. The Company utilizes over-the-counter price and basis swaps as well as options to hedge its production in order to decrease its price risk exposure. The gains and losses realized as a result of these price and basis derivative transactions are substantially offset when the hedged commodity is delivered. In order to accommodate the needs of its customers, the Company also uses price swaps to convert natural gas sold under fixed price contracts to market sensitive prices. The Company uses a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of crude oil and natural gas may have on the fair value of the Company's derivative instruments. For example, at December 31, 2001, the potential decrease in fair value of derivative instruments assuming a 10 percent adverse movement (an increase in the underlying commodities prices) would result in a $72 million decrease in the net unrealized gain. The derivative instruments in place at December 31, 2001 hedged approximately 22 percent of the Company's projected production volumes through 2002. For purposes of calculating the hypothetical change in fair value, the relevant variables include the type of commodity, the commodity futures prices, the volatility of commodity prices and the basis and quality differentials. The hypothetical change in fair value is calculated by multiplying the difference between the hypothetical price (adjusted for any basis or quality differentials) and the contractual price by the contractual volumes. As more fully described in Note 1 of Notes to Consolidated Financial Statements, the Company periodically assesses the effectiveness of its derivative instruments in achieving offsetting cash flows attributable to the risks being hedged. Changes in basis differentials or notional amounts of the hedged transactions could cause the derivative instruments to fail the effectiveness test and result in the mark-to- market accounting for the affected derivative transactions which would be reflected in the Company's current period earnings. Credit and Market Risks The Company manages and controls market and counterparty credit risk through established formal internal control procedures which are reviewed on an ongoing basis. The Company attempts to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and, if necessary, through establishment of valuation reserves related to counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Historically, the Company has suffered minimal losses from credit risk. OIL AND GAS RESERVES The process of estimating quantities of natural gas, NGLs and crude oil reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in the financial statement disclosures. As described in Note 1 of Notes to Consolidated Financial Statements, the Company uses the units-of-production method to amortize its oil and gas properties. Changes in reserve quantities as described above will cause corresponding changes in depletion expense in periods subsequent to the quantity revision. See the Supplementary Financial Information for reserve data. 19 CARRYING VALUE OF LONG-LIVE ASSETS As more fully described in Note 1 of Notes to Consolidated Financial Statements, the Company performs an impairment analysis whenever events or changes in circumstances indicate an asset's carrying amount may not be recoverable. Cash flows used in the impairment analysis are determined based upon management's estimates of proved oil, NGLs and gas reserves, future oil, NGLs and gas prices and costs to extract these reserves. Downward revisions in estimated reserve quantities, increases in future cost estimates or depressed oil, NGLs and gas prices could cause the Company to reduce the carrying amounts of its properties. As described in Note 12 of Notes to Consolidated Financial Statements, the Company recorded a pretax impairment charge of $184 million and $225 million for the years ended December 31, 2001, and 1999, respectively. NATURAL GAS MEASUREMENT The Company records estimated amounts for natural gas revenues and natural gas purchase costs based on volumetric calculations under its natural gas sales and purchase contracts. Variances or imbalances resulting from such calculations are inherent in natural gas sales, production, operations, measurement and administration. Management does not believe that differences between actual and estimated natural gas revenues or purchase costs attributable to the unresolved variances or imbalances are material. FOREIGN CURRENCY RISK The Company's reported cash flows related to Canadian operations is based on cash flows measured in Canadian dollars and converted to the U.S. dollar equivalent based on the average of the Canadian and U.S. dollar exchange rates for the period reported. The Company's Canadian subsidiaries have no financial obligations that are denominated in U.S. dollars. DIVIDENDS On January 9, 2002, the Board of Directors declared a common stock quarterly cash dividend of $.1375 per share, payable April 1, 2002 to shareholders of record on March 8, 2002. Dividend levels are determined by the Board of Directors based on profitability, capital expenditures, financing and other factors. The Company declared cash dividends on Common Stock totaling approximately $113 million during 2001. RESULTS OF OPERATIONS Year Ended December 31, 2001 Compared With Year Ended December 31, 2000 The Company reported net income of $561 million or $2.70 diluted earnings per common share in 2001 compared to net income of $675 million or $3.12 diluted earnings per common share in 2000. Net income in 2001 included a non-cash after tax charge of $116 million or $.56 per diluted share primarily related to the impairment of oil and gas properties held for sale. The Company evaluates the impairment of its oil and gas properties on a field-by-field basis whenever events or changes in circumstances indicate an asset's carrying amount may not be recoverable. In December 2001, primarily as a result of the Company's decision to exit the Gulf of Mexico Shelf and divest of certain other properties, the Company recognized a pretax charge of $184 million ($116 million after tax) related to those properties. The Company also recognized a $6 million after tax restructuring charge or $.03 per share related to severance and other exit costs. Net income in 2001 also included an after tax gain of $12 million or $.06 per diluted share consisting of ineffectiveness of cash-flow and fair-value hedges and gains on derivative instruments which do not qualify for hedge accounting under Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. The Company adopted SFAS No. 133 effective January 1, 2001. For more discussion of SFAS No. 133, see Note 1 of Notes to Consolidated Financial Statements. The results of operations for 2001 include one month of activities related to the Canadian Hunter Exploration Ltd. ("Hunter") acquisition. To reflect the change in the characteristics of its oil and gas properties, in 2001, the Company began reporting its production volumes and reserves in three streams: natural gas, crude oil and NGLs. Under this 20 methodology, gas production is reported after extracting liquids and eliminating non-hydrocarbon gases from the natural gas stream. This change had no financial impact and no material impact on total equivalent production volumes. Amounts for prior years have been reclassified to conform to current presentation. Revenues increased $179 million to $3,326 million in 2001 compared to $3,147 million in 2000. Revenues in 2001 increased $267 million compared to 2000 as a result of higher gas prices partially offset by lower oil and NGL prices. Including a $.48 realized loss per MCF related to hedging activities, average gas prices increased $.57 per MCF in 2001 to $3.94 per MCF from $3.37 per MCF in 2000 which increased revenues $362 million. The increase in revenues related to higher gas prices was partially offset by a reduction in revenues due to lower average oil and NGL prices. Including a $1.10 realized loss per barrel related to hedging activities, average oil prices decreased $1.99 per barrel in 2001 to $23.45 per barrel from $25.44 per barrel in 2000 resulting in reduced revenues of $47 million. Average NGL prices decreased $2.79 per barrel in 2001 to $14.35 per barrel from $17.14 per barrel in 2000 resulting in reduced revenues of $48 million. A decline in oil sales volumes resulted in a decrease in revenues of $107 million in 2001 compared to 2000. Oil sales volumes decreased 10.5 MBbls per day in 2001 to 63.2 MBbls per day from 73.7 MBbls per day in 2000 reducing revenues $100 million. Gas sales volumes were the same as the prior year at 1,724 MMCF per day, however, due to one less day in 2001 compared to 2000, gas revenues were down $6 million. NGL sales volumes decreased slightly to 47.1 MBbls per day in 2001 from 47.2 MBbls per day in 2000, resulting in a reduction in revenues of $1 million. Oil sales volumes decreased primarily due to natural production declines and reduced capital spending in the Gulf Coast and Mid-Continent areas and property sales in 2000. Although total gas sales volumes were the same as the prior year, sales volumes were higher in Canada and East Irish Sea. Gas sales volumes were higher in Canada due to a successful drilling program and the Hunter acquisition and East Irish Sea was higher due to an additional interest acquired in the area. These increases were offset primarily due to lower sales volumes in the San Juan, Gulf of Mexico and south Louisiana areas. Gas sales volumes were lower in these areas due to lower capital spending in the Gulf of Mexico and natural declines in the other areas. Revenues in 2001 also included a $19 million gain related to ineffectiveness of cash-flow and fair-value hedges and gains on derivative instruments which do not qualify for hedge accounting. Costs and Expenses were $2,241 million in 2001 compared to $1,956 million in 2000. Costs and Expenses for 2001 included a $184 million charge primarily related to the impairment of oil and gas properties held for sale and a restructuring charge of $10 million for severance and other exit costs. Excluding the $194 million charges in 2001, costs and expenses increased $91 million. The increase was primarily due to a $35 million increase in production and processing expenses, a $26 million increase in depreciation, depletion and amortization ("DD&A"), a $21 million increase in exploration costs, a $9 million increase in transportation expense and an $8 million increase in taxes other than income taxes. Production and processing expenses increased primarily due to higher workover expense, higher service, electrical and lease fuel costs. DD&A increased due to a higher unit-of-production rates related to changes in production mix and higher finding costs. Exploration costs increased primarily due to higher drilling rig expenses of $29 million and higher exploratory dry hole costs of $28 million partially offset by lower geological and geophysical ("G&G") expenses of $23 million and lower lease impairment charges of $16 million. Transportation expense increased primarily due to higher tariffs and taxes other than income taxes increased primarily due to higher oil and gas revenues. Interest Expense was $190 million in 2001 compared to $197 million in 2000. The decrease was primarily due to higher capitalized interest during 2001. Other Expense (Income) -- Net was income of $12 million in 2001 compared to expense of $27 million in 2000. This increase was primarily due to higher interest income in 2001 as a result of excess cash on hand during the year, higher gains on sale of non-oil and gas assets and lower interest expense related to tax matters. Income tax expense was $349 million in 2001 compared to $292 million in 2000. The increase in tax expense was primarily due to lower tax benefits related to Section 29 credits and tax-accrual adjustments partially offset by lower tax on 2001 pretax income. The Section 29 tax credits were $24 million in 2001 compared to $52 million in 2000. Favorable tax-accrual adjustments were $21 million in 2001 compared to $56 million in 2000 primarily related to prior period activity. 21 Year Ended December 31, 2000 Compared With Year Ended December 31, 1999 The Company reported net income of $675 million or $3.12 diluted earnings per common share in 2000 compared to a net loss of $10 million or $.05 diluted loss per common share in 1999. The 1999 results included a non-cash after tax charge of $140 million or $.65 per share related to the impairment of oil and gas properties. In the fourth quarter of 1999, the Company determined that there would be performance related downward reserve adjustments associated with certain properties located on the Gulf of Mexico Shelf and in the Permian Basin. As a result, the Company recognized a pretax impairment charge of $225 million ($140 million after tax) related to those properties. The Company also recognized a $26 million after tax charge or $.12 per share related to severance and transaction costs associated with the acquisition of Poco Petroleums Ltd. ("Acquisition"). Revenues increased $834 million to $3,147 million in 2000 compared to $2,313 million in 1999. Revenues in 2000 increased $950 million compared to 2000 as a result of higher commodity prices. Including a $.45 realized loss per MCF related to hedging activities, average gas prices increased $.96 per MCF in 2000 to $3.37 per MCF from $2.41 per MCF in 1999, which increased revenues $611 million. Including a $2.62 realized loss per barrel related to hedging activities, average oil prices increased $8.51 per barrel in 2000 to $25.44 per barrel from $16.93 per barrel in 1999, which increased revenues $230 million. Average NGL prices increased $6.35 per barrel in 2000 to $17.14 per barrel from $10.79 per barrel in 1999, increasing revenues $109 million. A decline in oil and gas sales volumes partially offset by an increase in NGL sales volumes resulted in a decrease in revenues of $105 million in 2000 compared to 1999. Oil sales volumes decreased 10.5 MBbls per day in 2000 to 73.7 MBbls per day from 84.2 MBbls per day in 1999, reducing revenues $63 million. Gas sales volumes decreased 59 MMCF in 2000 to 1,724 per MMCF per day from 1,783 per MMCF per day compared to the prior year, reducing revenues $48 million. The decrease in revenues as a result of lower oil and gas sales volumes were partially offset by an increase in NGL sales volumes of 1.4 MBbls per day in 2000 to 47.2 MBbls per day from 45.8 MBbls per day in 1999, resulting in increased revenues of $6 million. Oil sales volumes decreased primarily due to natural production declines in the Gulf Coast area. Costs and Expenses were $1,956 million in 2000 compared to $2,113 million in 1999. Costs and expenses in 1999 included a $225 million charge related to the impairment of oil and gas properties and also a charge of $37 million related to severance and transaction costs associated with the Acquisition. Excluding the $262 million of charges in 1999, costs and expenses in 2000 increased $105 million compared to 1999. The increase was primarily due to a $73 million increase in DD&A, a $27 million increase in taxes other than income taxes and an $11 million increase in exploration costs partially offset by an $8 million decrease in transportation expenses. DD&A increased primarily due to a higher unit rate resulting from a change in production mix. Taxes other than income taxes increased primarily due to higher oil and gas revenues. Exploration costs increased primarily due to higher lease impairment expense of $19 million and higher exploratory dry hole costs of $7 million, partially offset by lower G&G expense of $15 million. Transportation expenses decreased due to lower Canadian production. Interest Expense was $197 million in 2000 compared to $211 million in 1999. The decrease was primarily due to lower outstanding fixed-rate debt partially offset by higher commercial paper borrowings during 2000. Other Expense (Income) -- Net was an expense of $27 million in 2000 compared to expense of $2 million in 1999. This increase is primarily due to foreign currency transaction losses and other miscellaneous expenses partially offset by interest income related to the settlement of a windfall profits tax matter. Income taxes were an expense of $292 million in 2000 compared to a benefit of $3 million in 1999. The increase in tax expense was primarily due to higher pretax income resulting in higher income taxes of $342 million, higher state taxes of $21 million and higher foreign taxes in excess of the U.S. statutory rate of $35 million partially offset by tax benefits resulting from Section 29 tax credits and tax-accrual adjustments. The Section 29 tax credits were $52 million in 2000 compared to $2 million in 1999. Tax-accrual adjustments were also $52 million in 2000 primarily related to prior period activity. 22 Acquisitions On October 8, 2001, BR and Hunter entered into an agreement pursuant to which BR agreed to make an offer to purchase all of the outstanding shares of Hunter for cash consideration of C$53 per share representing an aggregate value of approximately U.S. $2.1 billion resulting in an excess purchase price of approximately $793 million which has been reflected as goodwill. On December 5, 2001, the transaction was consummated. This acquisition was funded with cash on hand and proceeds from the issuances of $1.5 billion of fixed-rate notes and $400 million of commercial paper. The transaction was accounted for under the purchase method in accordance with SFAS No. 141. See Note 2 of Notes to Consolidated Financial Statements for more information related to this transaction. During the first quarter of 2001, the Company purchased from DIFCO Limited an additional 10 percent interest in 7 fields in the East Irish Sea for $25 million. The Company is the operator of the properties and now owns 100 percent of the assets. In January 2001, the Company's Canadian subsidiary, Burlington Resources Canada Energy Ltd., now known as Burlington Resources Canada Ltd. ("BRCL"), acquired approximately 37 billion cubic feet of gas equivalent ("BCFE") of proved reserves from Petrobank Energy and Resources Ltd. for $57 million. In December 2001, the Alberta Energy and Utility Board approved the application by ATCO Gas Pipelines Ltd., a regulated gas utility, to sell properties in the Viking-Kinsella area of Alberta, Canada to BRCL for approximately $346 million. The properties have net proved reserves of approximately 251 BCFE. The transaction was consummated on January 3, 2002. Legal Proceedings The Company and numerous other oil and gas companies have been named as defendants in various lawsuits alleging violations of the civil False Claims Act. These lawsuits have been consolidated by the United States Judicial Panel on Multidistrict Litigation for pre-trial proceedings in the matter of In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court for the District of Wyoming ("MDL-1293"). The plaintiffs contend that defendants underpaid royalties on natural gas and NGLs produced on federal and Indian lands through the use of below-market prices, improper deductions, improper measurement techniques and transactions with affiliated companies. Plaintiffs allege that the royalties paid by defendants were lower than the royalties required to be paid under federal regulations and that the forms filed by defendants with the Minerals Management Service ("MMS") reporting these royalty payments were false, thereby violating the civil False Claims Act. The United States has intervened in certain of the MDL-1293 cases as to some of the defendants, including the Company. Various administrative proceedings are also pending before the MMS of the United States Department of the Interior with respect to the valuation of natural gas produced by the Company on federal and Indian lands. In general, these proceedings stem from regular MMS audits of the Company's royalty payments over various periods of time and involve the interpretation of the relevant federal regulations. Based on the Company's present understanding of the various governmental and False Claims Act proceedings described above, the Company believes that it has substantial defenses to these claims and intends to vigorously assert such defenses. However, in the event that the Company is found to have violated the civil False Claims Act, the Company could be subject to monetary damages and a variety of sanctions, including double damages, substantial monetary fines, civil penalties and a temporary suspension from entering into future federal mineral leases and other federal contracts for a defined period of time. While the ultimate outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the consolidated financial position of the Company, although results of operations and cash flow could be significantly impacted in the reporting periods in which such matters are resolved. The Company has also been named as a defendant in the lawsuit styled UNOCAL Netherlands B.V., et al. v. Continental Netherlands Oil Company B.V., et al, No. 98-854, in the Court of Appeal in The Hague in the Netherlands. Plaintiffs, who are working interest owners in the Q-1 Block in the North Sea, have alleged that 23 the Company and other former working interest owners in the adjacent Logger Field in the L16a Block unlawfully trespassed or were otherwise unjustly enriched by producing part of the oil from the adjoining Q-1 Block. The plaintiffs claim that the defendants infringed upon plaintiffs' right to produce the minerals present in its license area and acted in violation of generally accepted standards by failing to inform plaintiffs of the overlap of the Logger Field into the Q-1 Block. For all relevant periods, the Company owned a 37.5% working interest in the Logger Field. Following a trial, the District Court in The Hague rendered a Judgment in favor of the defendants, including the Company, dismissing all claims. Plaintiffs thereafter appealed. On October 19, 2000, the Court of Appeal in The Hague issued an interim Judgment in favor of the plaintiffs and ordered that additional evidence be presented to the court relating to issues of both liability and damages. The Company and the other defendants are continuing to vigorously assert defenses against these claims. The Company has also asserted claims of indemnity against two of the defendants from whom it had acquired a portion of its working interest share. The Company is unable at this time to reasonably predict the outcome, or, in the event of an unfavorable outcome, to reasonably estimate the possible loss or range of loss, if any, in this lawsuit. In addition to the foregoing, the Company and its subsidiaries are named defendants in numerous other lawsuits and named parties in numerous governmental and other proceedings arising in the ordinary course of business. While the outcome of these other lawsuits and proceedings cannot be predicted with certainty, management believes these other matters will not have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company. OTHER MATTERS Recent Accounting Pronouncements The following SFAS's were issued in June 2001: SFAS No. 141, Business Combinations, SFAS No. 142, Goodwill and Other Intangible Assets, and SFAS No. 143, Accounting for Asset Retirement Obligations. In August 2001, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets was also issued. SFAS No. 141, requires the use of the purchase method of accounting for all business combinations, applies to all business combinations initiated after June 30, 2001 and to all business combinations accounted for by the purchase method that are completed after June 30, 2001. SFAS No. 142 requires that goodwill as well as other intangible assets with indefinite lives not be amortized but be tested annually for impairment and is effective for fiscal years beginning after December 15, 2001. SFAS No. 141 and No. 142 apply to the Company's accounting for the acquisition of Hunter. The Company is in the process of evaluating the impairment methodology for goodwill. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. SFAS No. 144 addresses financial accounting and reporting for the impairment of long-lived assets and long-lived assets to be disposed of. It supersedes, with exceptions, SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of and is effective for fiscal years beginning after December 15, 2001. The Company is currently assessing the impact of SFAS No. 143 and No. 144 and therefore, at this time cannot reasonably estimate the effect of these statements on its consolidated financial position, results of operations or cash flows. FORWARD-LOOKING STATEMENTS The Company, in discussions of its future plans, expectations, objectives and anticipated performance in periodic reports filed by the Company with the Securities and Exchange Commission (or documents incorporated by reference therein) may include projections or other forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 or Section 21E of the Securities Exchange Act of 1934, as amended. Such projections and forward-looking statements are based on assumptions which the Company believes are reasonable, but are by their nature inherently uncertain. In all cases, there can be no assurance 24 that such assumptions will prove correct or that projected events will occur, and actual results could differ materially from those projected. Some of the important factors that could cause actual results to differ from any such projections or other forward-looking statements follow. Changes in crude oil, NGL and natural gas prices (including basis differentials) from those assumed in preparing projections and forward-looking statements could cause the Company's actual financial results to differ materially from projected financial results and can also impact the Company's determination of proved reserves and the standardized measure of discounted future net cash flows relative to crude oil, NGL and natural gas reserves. In addition, periods of sharply lower commodity prices could affect the Company's production levels and/or cause it to curtail capital spending projects and delay or defer exploration, exploitation or development projects. Projections relating to the price received by the Company for natural gas and NGLs also rely on assumptions regarding the availability and pricing of transportation to the Company's key markets. In particular, the Company has contractual arrangements for the transportation of natural gas from the San Juan Basin eastward to Eastern and Midwestern markets or to market hubs in Texas, Oklahoma and Louisiana. The natural gas price received by the Company could be adversely affected by any constraints in pipeline capacity to serve these markets. Exploration and Production Risks. The Company's business is subject to all of the risks and uncertainties normally associated with the exploration for and development and production of crude oil, NGLs and natural gas. Reserves which require the use of improved recovery techniques for production are included in proved reserves if supported by a successful pilot project or the operation of an installed program. The process of estimating quantities of proved reserves is inherently uncertain and involves subjective engineering and economic determinations. In this regard, changes in the economic conditions (including commodity prices) or operating conditions (including, without limitation, exploration, development and production costs and expenses and drilling results from exploration and development activity) could cause the Company's estimated proved reserves or production to differ from those included in any such forward-looking statements or projections. Projecting future crude oil, NGL and natural gas production is imprecise. Producing oil and gas reservoirs eventually have declining production rates. Projections of production rates rely on certain assumptions regarding historical production patterns in the area or formation tests for a particular producing horizon. Actual production rates could differ materially from such projections. Production rates depend on a number of additional factors, including commodity prices, market demand and the political, economic and regulatory climate. Another major factor affecting the Company's production is its ability to replace depleting reservoirs with new reserves through acquisition, exploration or development programs. Exploration success is extremely difficult to predict with certainty, particularly over the short term where the timing and extent of successful results vary widely. Over the long term, the ability to replace reserves depends not only on the Company's ability to locate crude oil, NGL and natural gas reserves, but on the cost of finding and developing such reserves. Moreover, development of any particular exploration or development project may not be justified because of the commodity price environment at the time or because of the Company's finding and development costs for such project. No assurances can be given as to the level or timing of success that the Company will be able to achieve in acquiring or finding and developing additional reserves. Projections relating to the Company's production and financial results rely on certain assumptions about the Company's continued success in its acquisition and asset rationalization programs and in its cost management efforts. The Company's drilling operations are subject to various hazards common to the oil and gas industry, including explosions, fires, and blowouts, which could result in damage to or destruction of oil and gas wells or formations, production facilities and other property and injury to people. They are also subject to the 25 additional hazards of marine operations, such as capsizing, collision and damage or loss from severe weather conditions. Development Risk. A significant portion of the Company's development plans involve large projects in Algeria, the East Irish Sea, China, Wyoming, North Dakota, the Gulf of Mexico and other areas. A variety of factors affect the timing and outcome of such projects including, without limitation, approval by the other parties owning working interests in the project, receipt of necessary permits and approvals by applicable governmental agencies, the availability of the necessary drilling equipment, delivery schedules for critical equipment and arrangements for the gathering and transportation of the produced hydrocarbons. Foreign Operations Risk. The Company's operations outside of the U.S. are subject to risks inherent in foreign operations, including, without limitation, the loss of revenue, property and equipment from hazards such as expropriation, nationalization, war, insurrection and other political risks, increases in taxes and governmental royalties, renegotiation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations and other uncertainties arising out of foreign government sovereignty over the Company's international operations. Laws and policies of the U.S. affecting foreign trade and taxation may also adversely affect the Company's international operations. The Company's ability to market crude oil, NGL's and natural gas discovered or produced in its foreign operations, and the price the Company could obtain for such production, depends on many factors beyond the Company's control, including ready markets for crude oil, NGL's and natural gas, the proximity and capacity of pipelines and other transportation facilities, fluctuating demand for crude oil and natural gas, the availability and cost of competing fuels, and the effects of foreign governmental regulation of oil and gas production and sales. Pipeline and processing facilities do not exist in certain areas of exploration and, therefore, any actual sales of the Company's production could be delayed for extended periods of time until such facilities are constructed. Competition. The Company actively competes for property acquisitions, exploration leases and sales of crude oil, NGL's and natural gas, frequently against companies with substantially larger financial and other resources. In its marketing activities, the Company competes with numerous companies for gas purchasing and processing contracts and for natural gas and NGLs at several steps in the distribution chain. Competitive factors in the Company's business include price, contract terms, quality of service, pipeline access, transportation discounts and distribution efficiencies. Political and Regulatory Risk. The Company's operations are affected by foreign, national, state and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Changes in such laws and regulations, or interpretations thereof, could have a significant effect on the Company's operations or financial results. Potential Environmental Liabilities. The Company's operations are subject to various foreign, national, state and local laws and regulations covering the discharge of material into, and protection of, the environment. Such regulations affect the costs of planning, designing, operating and abandoning facilities. The Company expends considerable resources, both financial and managerial, to comply with environmental regulations and permitting requirements. Although the Company believes that its operations and facilities are in substantial compliance with applicable environmental laws and regulations, risks of substantial costs and liabilities are inherent in crude oil and natural gas operations. Moreover, it is possible that other developments, such as increasingly strict environmental laws, regulations and enforcement, and claims for damage to property or persons resulting from the Company's current or discontinued operations, could result in substantial costs and liabilities in the future. 26 ITEM EIGHT FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION BURLINGTON RESOURCES INC. CONSOLIDATED STATEMENT OF INCOME (LOSS)

YEAR ENDED DECEMBER 31, --------------------------- 2001 2000 1999 ------- ------- ------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) REVENUES.................................................... $3,326 $3,147 $2,313 ------ ------ ------ COSTS AND EXPENSES Taxes Other than Income Taxes............................. 166 158 131 Transportation Expense.................................... 249 240 248 Production and Processing................................. 505 470 465 Depreciation, Depletion and Amortization.................. 730 704 631 Exploration Costs......................................... 258 237 226 Impairment of Oil and Gas Properties...................... 184 -- 225 Merger Costs.............................................. -- -- 37 Administrative............................................ 149 147 150 ------ ------ ------ Total Costs and Expenses.................................... 2,241 1,956 2,113 ------ ------ ------ Operating Income............................................ 1,085 1,191 200 Interest Expense............................................ 190 197 211 Other Expense (Income) -- Net............................... (12) 27 2 ------ ------ ------ Income (Loss) Before Income Taxes and Cumulative Effect of Change in Accounting Principle............................ 907 967 (13) Income Tax Expense (Benefit)................................ 349 292 (3) ------ ------ ------ Income (Loss) Before Cumulative Effect of Change in Accounting Principle...................................... 558 675 (10) Cumulative Effect of Change in Accounting Principle -- Net.......................................... 3 -- -- ------ ------ ------ NET INCOME (LOSS)........................................... $ 561 $ 675 $ (10) ====== ====== ====== EARNINGS (LOSS) PER COMMON SHARE Basic Before Cumulative Effect of Change in Accounting Principle............................................. $ 2.70 $ 3.13 $ (.05) Cumulative Effect of Change in Accounting Principle -- Net...................................... .01 -- -- ------ ------ ------ NET INCOME (LOSS)...................................... $ 2.71 $ 3.13 $ (.05) ====== ====== ====== Diluted Before Cumulative Effect of Change in Accounting Principle............................................. $ 2.69 $ 3.12 $ (.05) Cumulative Effect of Change in Accounting Principle -- Net...................................... .01 -- -- ------ ------ ------ NET INCOME (LOSS)...................................... $ 2.70 $ 3.12 $ (.05) ====== ====== ======

See accompanying Notes to Consolidated Financial Statements. 27 BURLINGTON RESOURCES INC. CONSOLIDATED BALANCE SHEET

DECEMBER 31, ------------------ 2001 2000 ------- ------- (IN MILLIONS, EXCEPT SHARE DATA) ASSETS Current Assets Cash and Cash Equivalents................................. $ 116 $ 132 Accounts Receivable....................................... 398 809 Commodity Hedging Contracts and Other Derivatives......... 118 -- Inventories............................................... 50 45 Other Current Assets...................................... 33 25 ------- ------- 715 1,011 ------- ------- Oil and Gas Properties (Successful Efforts Method).......... 16,038 13,118 Other Properties............................................ 1,416 1,019 ------- ------- 17,454 14,137 Accumulated Depreciation, Depletion and Amortization........ 8,623 7,830 ------- ------- Properties -- Net......................................... 8,831 6,307 ------- ------- Commodity Hedging Contracts and Other Derivatives........... 5 -- ------- ------- Goodwill.................................................... 782 -- ------- ------- Other Assets................................................ 249 188 ------- ------- Total Assets....................................... $10,582 $ 7,506 ======= ======= Current Liabilities Accounts Payable.......................................... $ 599 $ 619 Commodity Hedging Contracts and Other Derivatives......... 3 -- Taxes Payable............................................. 6 55 Accrued Interest.......................................... 61 33 Dividends Payable......................................... 28 30 Other Current Liabilities................................. 14 21 ------- ------- 711 758 ------- ------- Long-term Debt.............................................. 4,337 2,301 ------- ------- Deferred Income Taxes....................................... 1,403 266 ------- ------- Commodity Hedging Contracts and Other Derivatives........... 15 -- ------- ------- Other Liabilities and Deferred Credits...................... 591 431 ------- ------- Commitments and Contingent Liabilities Preferred Stock, Par Value $.01 per Share (Authorized 75,000,000 Shares; One Share Issued)...................... -- -- Common Stock, Par Value $.01 per Share (Authorized 325,000,000 Shares; Issued 241,188,688 and 241,188,698 Shares for 2001 and 2000, respectively)................... 2 2 Paid-in Capital............................................. 3,944 3,944 Retained Earnings........................................... 1,332 884 Deferred Compensation -- Restricted Stock................... (9) (5) Accumulated Other Comprehensive Loss........................ (106) (70) Cost of Treasury Stock (40,395,695 and 25,619,893 Shares for 2001 and 2000, respectively).............................. (1,638) (1,005) ------- ------- Stockholders' Equity........................................ 3,525 3,750 ------- ------- Total Liabilities and Stockholders' Equity......... $10,582 $ 7,506 ======= =======

See accompanying Notes to Consolidated Financial Statements. 28 BURLINGTON RESOURCES INC. CONSOLIDATED STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, -------------------------------- 2001 2000 1999 ------- ------------- ------ (IN MILLIONS) CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss)......................................... $ 561 $ 675 $ (10) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided By Operating Activities Depreciation, Depletion and Amortization............... 730 704 631 Deferred Income Taxes.................................. 219 219 (12) Exploration Costs...................................... 258 237 226 Impairment of Oil and Gas Properties................... 184 -- 225 Changes in Derivative Fair Values...................... (25) -- -- Working Capital Changes, Net of Acquisition Accounts Receivable.................................... 467 (341) (31) Inventories............................................ 6 8 -- Other Current Assets................................... (3) 1 (4) Accounts Payable....................................... (187) 109 (13) Taxes Payable.......................................... (46) (33) 40 Accrued Interest....................................... 23 (3) 6 Other Current Liabilities.............................. (2) 4 (22) Changes in Other Assets and Liabilities................... (79) 18 66 ------- ------ ------ Net Cash Provided By Operating Activities......... 2,106 1,598 1,102 ------- ------ ------ CASH FLOWS FROM INVESTING ACTIVITIES Additions to Properties................................... (1,293) (941) (989) Acquisition of Hunter, net of cash acquired............... (2,087) -- -- Proceeds from Sales and Other............................. 1 19 (4) ------- ------ ------ Net Cash Used In Investing Activities............. (3,379) (922) (993) ------- ------ ------ CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-term Debt.............................. 2,247 70 632 Reduction in Long-term Debt............................... (211) (564) (528) Dividends Paid............................................ (116) (89) (127) Common Stock Purchases.................................... (684) (121) (9) Common Stock Issuances.................................... 41 92 21 Debt Issuance Costs and Other............................. (20) (21) (9) ------- ------ ------ Net Cash Provided By (Used In) Financing Activities...................................... 1,257 (633) (20) ------- ------ ------ INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............ (16) 43 89 CASH AND CASH EQUIVALENTS Beginning of Year......................................... 132 89 -- ------- ------ ------ End of Year............................................... $ 116 $ 132 $ 89 ======= ====== ======

See accompanying Notes to Consolidated Financial Statements. 29 BURLINGTON RESOURCES INC. CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

ACCUMULATED OTHER DEFERRED COMPREHENSIVE COST OF COMMON PAID-IN RETAINED COMPENSATION -- INCOME TREASURY STOCKHOLDERS' STOCK CAPITAL EARNINGS RESTRICTED STOCK (LOSS) STOCK EQUITY ------ ------- ------------- ---------------- ------------- -------- -------------- (IN MILLIONS, EXCEPT SHARE DATA) Balance, December 31, 1998...................... $2 $3,953 $ 440 $(2) $ (74) $(1,007) $3,312 -- ------ ------ --- ----- ------- ------ Comprehensive Income (Loss) Net Loss.................. (10) (10) Foreign Currency Translation............. 20 20 ------ ----- ------ Comprehensive Income (Loss)................ (10) 20 10 ------ ----- ------ Cash Dividends ($.46 per Share).................... (103) (103) Common Stock Purchases (250,000 Shares).......... (9) (9) Common Stock Issuances...... 7 7 Stock Option Activity and Other..................... 6 1 (1) 6 12 -- ------ ------ --- ----- ------- ------ Balance, December 31, 1999...................... 2 3,966 328 (3) (54) (1,010) 3,229 -- ------ ------ --- ----- ------- ------ Comprehensive Income (Loss) Net Income................ 675 675 Foreign Currency Translation............. (16) (16) ------ ----- ------ Comprehensive Income (Loss)................ 675 (16) 659 ------ ----- ------ Cash Dividends ($.55 per Share).................... (119) (119) Common Stock Purchases (3,505,000 Shares)........ (125) (125) Stock Option Activity and Other..................... (22) (2) 130 106 -- ------ ------ --- ----- ------- ------ Balance, December 31, 2000...................... 2 3,944 884 (5) (70) (1,005) 3,750 -- ------ ------ --- ----- ------- ------ Comprehensive Income (Loss) Net Income................ 561 561 Foreign Currency Translation............. (90) (90) Cumulative Effect of Change in Accounting Principle - Hedging..... (366) (366) Hedging Activities........ 420 420 ------ ----- ------ Comprehensive Income (Loss)................ 561 (36) 525 ------ ----- ------ Cash Dividends ($.55 per Share).................... (113) (113) Common Stock Purchases (16,092,000 Shares)....... (684) (684) Stock Option Activity....... 41 41 Issuance of Restricted Stock..................... (10) 10 -- Amortization of Restricted Stock..................... 6 6 -- ------ ------ --- ----- ------- ------ Balance, December 31, 2001...................... $2 $3,944 $1,332 $(9) $(106) $(1,638) $3,525 == ====== ====== === ===== ======= ======

See accompanying Notes to Consolidated Financial Statements. 30 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ACCOUNTING POLICIES Principles of Consolidation and Reporting The consolidated financial statements include the accounts of Burlington Resources Inc. ("BR") and its majority-owned subsidiaries (the "Company"). All significant intercompany transactions have been eliminated in consolidation. Investments in entities in which the Company has a significant ownership interest, generally 20 to 50 percent, or otherwise does not exercise control, are accounted for using the equity method. Under the equity method, the investments are stated at cost plus the Company's equity in undistributed earnings and losses. The consolidated financial statements for previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income or stockholders' equity. Cash and Cash Equivalents All short-term investments purchased with a maturity of three months or less are considered cash equivalents. Cash equivalents are stated at cost, which approximates market value. Inventories Inventories of materials, supplies and products are valued at the lower of average cost or market. Properties Oil and gas properties are accounted for using the successful efforts method. Under this method, all development costs and acquisition costs of proved properties are capitalized and amortized on a units-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively. Costs of drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful. Costs of unproved properties are capitalized and amortized on a composite basis, based on past success experience and average property lives. The Company evaluates the impairment of its oil and gas properties on a field-by-field basis whenever events or changes in circumstances indicate an asset's carrying amount may not be recoverable. Unamortized capital costs are reduced to fair value if the sum of the expected undiscounted future cash flows is less than the asset's net book value. Cash flows are determined based upon proved reserves using prices and costs consistent with those used for internal decision making. Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization. Gains or losses from the disposal of other properties are recognized currently. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major replacements and renewals are capitalized. Estimated dismantlement and abandonment costs for oil and gas properties are capitalized at their estimated net present value and amortized net of salvage value. The Company's abandonment liability, included in Other Liabilities and Deferred Credits in the Consolidated Balance Sheet, was $201 million and $147 million at December 31, 2001 and 2000, respectively. Other properties include gas plants, pipelines, buildings, data processing and telecommunications equipment, office furniture and 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. Revenue Recognition Gas revenues are recorded on the entitlement method. Under the entitlement method, revenue is recorded when title passes based on the Company's net interest. Gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total gas production. Any amount received in excess 31 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) of the Company's share is treated as a liability. If the Company receives less than it is entitled, the underproduction is recorded as a receivable. At December 31, 2001 and 2000, the Company had gas imbalance receivables of $39 million and $19 million, respectively. Functional Currency The assets, liabilities and operations of BR's Canadian subsidiaries are measured using the Canadian dollar as the functional currency. These assets and liabilities are translated into United States ("U.S.") dollars at end-of-period exchanges rates and are recorded in other comprehensive income. Revenue and expenses are translated into U.S. dollars at the average exchange rates in effect during the period. The assets, liabilities and results of operations of foreign entities other than BR's Canadian subsidiaries are measured using the U.S. dollar as the functional currency. For subsidiaries where the U.S. dollar is the functional currency, all foreign currency denominated assets and liabilities are remeasured into U.S. dollars at end-of-period exchange rates. Inventories, prepaid expenses and properties are exceptions to this policy and are remeasured at historical rates. Foreign currency revenues and expenses are remeasured at average exchange rates in effect during the year. Exceptions to this policy include all expenses related to balance sheet amounts that are remeasured at historical exchange rates. Exchange gains and losses arising from remeasured foreign currency denominated monetary assets and liabilities are included in Other Expense (Income) -- Net in the Consolidated Statement of Income (Loss). Included in net income for the years ended December 31, 2001, 2000 and 1999 are losses of $7 million, $4 million and a gain of $9 million, respectively. Derivative Instruments and Hedging Activities The Company enters into derivative contracts, primarily options and swaps, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. The Company also enters into derivative contracts to mitigate the risk of foreign currency exchange rate fluctuations. On January 1, 2001, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Effective with the adoption of SFAS No. 133, all derivatives are recognized on the balance sheet and measured at fair value. If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is either recognized in income along with an offsetting adjustment to the basis of the item being hedged for fair value hedges or deferred in other comprehensive income to the extent the hedge is effective for cash flow hedges. To qualify for hedge accounting, the derivative must qualify as either a fair-value, cash-flow or foreign-currency hedge. The hedging relationship between the hedging instruments and hedged items must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk both at the inception of the hedge and on an ongoing basis. The Company measures hedge effectiveness on a quarterly basis. Hedge accounting is discontinued prospectively when a hedging instrument becomes ineffective. The Company assesses hedge effectiveness based on total changes in the fair value of options used in cash flow hedges rather than changes of intrinsic value only. As a result, changes in the entire fair value of option contracts are deferred in accumulated other comprehensive income until the hedged transaction affects earnings to the extent such contracts are effective. Gains and losses deferred in accumulated other comprehensive income related to cash flow hedge derivatives that become ineffective remain unchanged until the related production is delivered. Adjustment to the carrying amounts of hedged production is discontinued in instances where the related fair-value hedging instrument becomes ineffective. The balance in the fair-value hedge adjustment account is recorded in income when the related production is delivered. If the Company determines that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately. 32 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Gains and losses on hedging instruments and adjustments of the carrying amounts of hedged production are included in crude oil and natural gas revenues and are included in realized prices in the period that the related production is delivered. Gains and losses on hedging instruments which represent hedge ineffectiveness and gains and losses on derivative instruments which do not qualify for hedge accounting are included in other revenues in the period in which they occur. The resulting cash flows are reported as cash flows from operating activities. Credit and Market Risks The Company manages and controls market and counterparty credit risk through established formal internal control procedures which are reviewed on an ongoing basis. The Company attempts to minimize credit risk exposure to counterparties through formal credit policies, monitoring procedures and, if necessary, through establishment of valuation reserves related to counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Income Taxes Income taxes are provided based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are provided to reflect the tax consequences in future years of differences between the financial statement and tax basis of assets and liabilities. Tax credits are accounted for under the flow-through method, which reduces the provision for income taxes in the year the tax credits are earned. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. Stock-based Compensation The Company uses the intrinsic value based method of accounting for stock-based compensation, as prescribed by Accounting Principles Board Opinion No. 25 and related interpretations. Under this method, the Company records no compensation expense for stock options granted when the exercise price for options granted is equal to the fair market value of the Company's stock on the date of the grant. Environmental Costs Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated. Reclassifications The Company's 2001 taxes other than income taxes include severance, ad valorem, payroll and miscellaneous taxes. To conform to current presentation, the Company reclassified $11 million of payroll and miscellaneous taxes from production and processing expenses and administrative expenses to taxes other than income taxes for each of the years ended December 31, 2000 and 1999. The Company also reclassified $15 million and $12 million of certain other non-corporate expenses from administrative expenses to production and processing expenses for years ended December 31, 2000 and 1999, respectively. These reclassifications had no effect on operating income. 33 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Earnings Per Common Share Basic earnings per common share ("EPS") is computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. The weighted average number of common shares outstanding for computing basic EPS was 207 million, 216 million and 216 million for the years ended December 31, 2001, 2000 and 1999, respectively. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. The weighted average number of common shares outstanding for computing diluted EPS, including dilutive stock options, was 208 million, 216 million and 217 million for the years ended December 31, 2001, 2000 and 1999, respectively. For the years ended December 31, 2001, 2000 and 1999, approximately 4 million shares attributable to the exercise of outstanding options were excluded from the calculation of diluted EPS because the effect was antidilutive. No adjustments were made to reported net income in the computation of EPS. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, NGL and gas reserve volumes and the future development, dismantlement and abandonment costs as well as estimates relating to certain gas, NGL and oil revenues and expenses. Actual results could differ from those estimates. 34 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 2. BUSINESS COMBINATIONS AND OTHER PROPERTY ACQUISITIONS Acquisition of Canadian Hunter Exploration Ltd. ("Hunter") On December 5, 2001, BR acquired all of the outstanding shares of Hunter for cash consideration of C$53 per share representing an aggregate value of approximately U.S. $2.1 billion resulting in an excess purchase price of approximately $793 million which has been reflected as goodwill. Through the acquisition, BR gains Hunter's significant interest in Canada's Deep Basin, North America's third-largest natural gas field, increasing its critical mass and enhancing its position as a leading North American natural gas producer. BR also obtains the exploration expertise of Hunter's workforce, gains additional cost optimization by eliminating duplicate efforts and increasing purchasing power and gains greater marketing flexibility in optimizing sales and accessing key market information. This acquisition was funded with cash on hand and proceeds from the issuances of $1.5 billion of fixed-rate notes and $400 million of commercial paper. The transaction was accounted for under the purchase method in accordance with SFAS No. 141. The results of operations of Hunter were included in the Company's financial statements effective December 5, 2001. The Company is in the process of evaluating the impairment methodology for goodwill. The purchase price was calculated as follows.

(IN MILLIONS) ------------- Calculation of Purchase Price for Assets Acquired: Cash paid for stock purchased.......................... $2,014 Cash settlement of employee stock options.............. 66 Other purchase price costs (e.g. fees, etc.)........... 17 Cash acquired.......................................... (10) ------ Total purchase price for common equity............ 2,087 ------ Plus fair market value of liabilities assumed: Current and other liabilities.......................... 308 Deferred tax........................................... 902 ------ Total liabilities................................. 1,210 ------ Total purchase price for assets acquired.................. $3,297 ======

The following is the allocation of the purchase price to specific assets and liabilities based on estimates of fair values and costs. All of the goodwill was assigned to the Company's Canadian reporting unit.

(IN MILLIONS) ------------- Current assets.............................................. $ 74 Other assets................................................ 45 Properties, plant and equipment............................. 2,385 Goodwill.................................................... 793 ------ 3,297 Current liabilities......................................... (105) Other liabilities........................................... (194) Long-term debt.............................................. (9) Deferred tax................................................ (902) ------ $2,087 ======

The purchase price allocation is preliminary in nature and is subject to changes as additional information becomes available. Management does not expect the final purchase price allocation to differ materially. Other purchase price costs relate primarily to professional fees of approximately $16 million and other direct transaction costs of approximately $1 million. 35 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table presents the unaudited pro forma results of the Company as though the acquisition had occurred on January 1, 2000. Pro forma results are not necessarily indicative of actual results.

2001 2000 ------ ------ (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues.................................................... $3,902 $3,648 Net income.................................................. 696 757 Basic earnings per common share............................. 3.36 3.51 Diluted earnings per common share........................... $ 3.34 $ 3.50

Other Acquisitions During the first quarter of 2001, the Company purchased from DIFCO Limited an additional 10 percent interest in 7 fields in the East Irish Sea for $25 million. The Company is the operator of the properties and now owns 100 percent of the assets. In January 2001, the Company's Canadian subsidiary, Burlington Resources Canada Energy Ltd., now known as Burlington Resources Canada Ltd. ("BRCL"), acquired approximately 37 billion cubic feet of gas equivalent ("BCFE") of proved reserves from Petrobank Energy and Resources Ltd. for $57 million. On August 16, 1999, the Company entered into a definitive agreement to acquire Poco Petroleums Ltd. ("Poco") (the "Acquisition"). The Acquisition was consummated on November 18, 1999 and accounted for under the pooling of interests method. Under the terms of the Acquisition, Poco shareholders received .25 BR common equivalent shares ("exchangeable shares"), totaling 38,393,135 shares, for each Poco share held. The exchangeable shares were Canadian securities, which began trading on the Toronto Stock Exchange on November 23, 1999 under the symbol BRX. These shares had the same voting rights, dividend entitlements and other attributes as shares of BR Common Stock and were exchangeable, at each shareholder's option, for BR Common Stock on a one for one basis. See Note 8 of Notes to Consolidated Financial Statements for disposition of remaining exchangeable shares. During the fourth quarter of 1999, the Company recorded a pretax charge of $37 million ($26 million after tax) for direct costs associated with the Acquisition. These costs consist of $10 million for severance related to certain executives and $27 million for direct transaction costs. At December 31, 2000, all costs had been paid. 3. OIL AND GAS AND OTHER PROPERTIES Oil and gas properties consisted of the following.

DECEMBER 31, ------------------ 2001 2000 ------- ------- (IN MILLIONS) Proved properties........................................... $15,638 $12,694 Unproved properties......................................... 400 424 ------- ------- 16,038 13,118 Accumulated depreciation, depletion and amortization........ 8,060 7,342 ------- ------- Net oil and gas properties........................ $ 7,978 $ 5,776 ======= =======

36 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Other properties consisted of the following.

DECEMBER 31, DEPRECIABLE --------------- LIFE-YEARS 2001 2000 ----------- ------ ------ (IN MILLIONS) Plants and pipeline systems................................. 10-20 $ 979 $ 630 Land, building, improvements and furniture and fixtures..... 0-40 145 143 Data processing & telecommunications equipment.............. 3-7 229 189 Other....................................................... 3-15 63 57 ------ ------ 1,416 1,019 Accumulated Depreciation.................................... 563 488 ------ ------ Net other properties.............................. $ 853 $ 531 ====== ======

4. INCOME TAXES The jurisdictional components of income (loss) before income taxes follow.

YEAR ENDED DECEMBER 31, ------------------------- 2001 2000 1999 ------ ------ ------- (IN MILLIONS) Domestic.................................................... $470 $673 $ (66) Foreign..................................................... 437 294 53 ---- ---- ----- Total............................................. $907 $967 $ (13) ==== ==== =====

The provision for income taxes follows.

YEAR ENDED DECEMBER 31, ------------------------- 2001 2000 1999 ------ ------ ------- (IN MILLIONS) Current Federal................................................... $ 25 $ 37 $ 4 State..................................................... 19 10 -- Foreign................................................... 86 26 5 ---- ---- ----- 130 73 9 ---- ---- ----- Deferred Federal................................................... 76 84 (44) State..................................................... 14 15 4 Foreign................................................... 129 120 28 ---- ---- ----- 219 219 (12) ---- ---- ----- Total............................................. $349 $292 $ (3) ==== ==== =====

Reconciliation of the federal statutory income tax rate to the effective income tax rate follows.

2001 2000 1999 ---- ----- ----- YEAR ENDED DECEMBER 31, ---------------------- U.S. statutory rate......................................... 35.0% 35.0% 35.0% State income taxes.......................................... 2.3 2.4 (16.7) Taxes on foreign income in excess of U.S. statutory rate.... 6.0 4.5 (66.5) Tax credits................................................. (2.7) (5.4) 15.9 Adjustments of prior year accruals.......................... (1.5) (5.8) 89.5 Merger costs................................................ -- -- (31.9) Other....................................................... (.7) (.5) (3.7) ---- ----- ----- Effective rate......................................... 38.4% 30.2% 21.6% ==== ===== =====

37 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Deferred income tax liabilities (assets) follow.

DECEMBER 31, -------------- 2001 2000 ------ ----- (IN MILLIONS) Deferred income tax liabilities Property, plant and equipment............................. $1,763 $ 740 Commodity hedging contracts and other derivatives......... 33 -- Other..................................................... 49 72 ------ ----- 1,845 812 ------ ----- Deferred income tax assets AMT credit carryforward................................... (347) (345) Deferred foreign tax credits.............................. (55) (66) Net operating loss carryforward........................... (2) -- Foreign tax credit carryforward........................... -- (2) Financial accruals and other.............................. (70) (166) ------ ----- (474) (579) ------ ----- Less valuation allowance.................................... 32 33 ------ ----- $1,403 $ 266 ====== =====

The net deferred income tax liabilities, as of December 31, 2001 and 2000, include deferred state income tax liabilities of approximately $49 million and $35 million, respectively. The net deferred income tax liabilities also include foreign tax liabilities of approximately $1,102 million and $124 million as of December 31, 2001 and 2000, respectively. No deferred U.S. income tax liability has been recognized on the undistributed earnings of controlled foreign corporations that have been retained for reinvestment. A valuation allowance is provided for uncertainties surrounding the realization of various tax credit carryforwards. The Alternative Minimum Tax ("AMT") credit carryforward, related primarily to nonconventional fuel tax credits, is available to offset future federal income tax liabilities. The AMT credit carryforward has no expiration date. The benefit of these tax credits is recognized in net income for accounting purposes and is reflected in the current tax provision to the extent the Company is able to utilize the credits for tax return purposes. The net operating loss carryforward primarily relates to foreign jurisdictions and will expire between 2003 and 2006 if not used. 5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES The Company enters into fixed-price gas swap agreements to fix the prices of anticipated future natural gas production and enters into variable-price gas swap agreements that convert fixed price physical sales contracts back to market sensitive prices. The Company enters into natural gas basis swap agreements to fix the sales price differential between the Company's marketing locations and NYMEX Henry Hub. The Company enters into natural gas option agreements to establish floor and ceiling prices on anticipated future natural gas production. The Company also enters into natural gas option agreements to establish floor and ceiling prices on anticipated future natural gas production while allowing the Company to participate in upward price movements above a specified non-participation range. Generally, the Company does not receive net premiums on its option hedging strategies. The Company enters into crude oil swap agreements to fix the price of anticipated future crude oil production and purchases call options agreements that allow the Company to participate in market price increases that exceed hedge prices established when the Company enters into a swap. The Company also enters into crude oil option agreements to establish floor and ceiling prices on anticipated future crude oil production while allowing the Company to participate in upward price movements above a specified non-participation range. Generally, the Company does not receive net premiums on its option hedging strategies. 38 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) As of December 31, 2001, the Company had the following natural gas volumes hedged. Natural Gas Fixed-Price Swaps

AVERAGE FAIR VALUE VOLUMES FIXED ASSET PRODUCTION PERIOD (MMBTU) PRICE (LIABILITY) ----------------- ---------- ------- ------------- (IN MILLIONS) 2002................................................ 20,489,913 $3.15 $ 9 2003................................................ 15,570,630 3.13 (1) 2004................................................ 15,613,289 3.24 (1) 2005................................................ 10,513,930 3.21 (2) 2006 to 2007................................................ 1,672,500 $3.21 $--

Natural Gas Basis Swaps

AVERAGE VOLUMES BASIS FAIR VALUE PRODUCTION PERIOD (MMBTU) DIFFERENTIAL ASSET ----------------- ---------- ------------ ------------- (IN MILLIONS) 2002............................................. 17,959,913 $(.13) $ 4 2003............................................. 15,570,630 (.28) 1 2004............................................. 15,613,289 (.27) -- 2005............................................. 10,513,930 (.29) -- 2006 to 2007............................................. 1,672,500 $(.15) $ --

Natural Gas Options

AVERAGE FAIR VALUE VOLUMES STRIKE ASSET PRODUCTION PERIOD OPTION TYPE (MMBTU) PRICE (LIABILITY) ----------------- --------------- ----------- ------- ------------- (IN MILLIONS) 2002...................................... Puts purchased 141,780,000 $ 3.07 $114 2002...................................... Puts sold 81,255,000 2.01 (11) 2002...................................... Calls sold 141,780,000 5.49 (6) 2002...................................... Calls purchased 30,250,000 $10.80 $ --

As of December 31, 2001, the fair value of the swap agreements the Company had entered into in order to convert the Company's fixed-price gas sales contracts to market sensitive positions was a $1 million liability offset by a $1 million asset basis adjustment to the carrying value of the fixed-price gas sales contracts. As of December 31, 2001, the Company had the following crude oil volumes hedged. The total notional amount of the crude oil call options is matched with a corresponding notional amount of fixed-price swaps. Crude Oil Swaps

AVERAGE VOLUMES FIXED PRODUCTION PERIOD (BARRELS) PRICE FAIR VALUE ----------------- ---------- ------- ------------- (IN MILLIONS) 2002........................................................ 180,000 $21.91 $ --

39 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Crude Oil Options

AVERAGE VOLUMES STRIKE FAIR VALUE PRODUCTION PERIOD OPTION TYPE (BARRELS) PRICE ASSET (LIABILITY) ----------------- --------------- --------- ------- ----------------- (IN MILLIONS) 2002..................................... Puts Purchased 1,810,000 $25.00 $ 10 2002..................................... Puts Sold 1,810,000 20.00 (4) 2002..................................... Calls Sold 1,810,000 32.17 -- 2002..................................... Calls Purchased 1,990,000 $36.36 $ --

The derivative assets and liabilities represent the difference between hedged values and market values on hedged volumes of the commodities as of December 31, 2001. Hedging activities reduced natural gas and crude oil revenues by $297 million and $25 million, respectively, during 2001. In addition, during 2001, gains of $19 million were recorded in revenues associated with ineffectiveness of cash-flow and fair-value hedges and gains on derivative instruments which do not qualify for hedge accounting. In addition to hedges of commodity prices, the Company also has foreign currency swaps to hedge its exposure to exchange rate fluctuations related to its Canadian subsidiaries. As of December 31, 2001, the Company had $8 million of liabilities related to foreign currency exchange rate hedges. In accordance with the transition provisions of SFAS No. 133, on January 1, 2001, the Company recorded a net-of-tax cumulative-effect-type loss adjustment of $366 million in accumulated other comprehensive income to recognize at fair value all derivatives that are designated as cash-flow hedging instruments. The Company recorded cash-flow hedge derivatives liabilities of $582 million ($361 million after tax), fair value hedge derivative assets of $16 million ($10 million after tax), related liability adjustments to book value of fair-value hedged items of $16 million ($10 million after tax) and a $3 million after tax non-cash gain was recorded in current earnings as a cumulative effect of accounting change. Changes in other comprehensive income for the year ended December 31, 2001 follow.

(IN MILLIONS) ------------- Cumulative effect of change in accounting principle -- January 1, 2001.......................... $(366) Reclassification adjustments for settled contracts... 200 Current period changes in fair value of settled contracts........................................... 153 Changes in fair value of outstanding hedging positions........................................... 67 ----- Accumulated other comprehensive income hedging activities -- December 31, 2001....................... $ 54 =====

Based on commodity prices and foreign exchange rates as of December 31, 2001, the Company expects to reclassify gains of $86 million ($54 million after tax) to earnings from the balance in accumulated other comprehensive income during the next twelve months. As of December 31, 2001, the Company had cash-flow hedge derivative assets of $109 million and liabilities of $10 million. The Company had liabilities and assets related to fair-value hedges of $4 million and $4 million, respectively. The Company also had assets totaling $10 million related to commodity derivative instruments that do not qualify for hedge accounting. 40 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 6. LONG-TERM DEBT Long-term debt follows.

DECEMBER 31, ---------------- 2001 2000 ------ ------ (IN MILLIONS) Commercial Paper............................................ $ 675 $ 327 Notes, 8 1/2%, due 2001..................................... -- 150 Notes, 8.54%, due 2001...................................... -- 15 Notes, 6.20%, due 2001...................................... -- 32 Notes, 8 1/4%, due 2002..................................... 100 100 Notes, 6.40%, due 2003...................................... 63 66 Notes, 7.12%, due 2005...................................... -- 39 Notes, 5.60%, due 2006...................................... 500 -- Notes, 6.60%, due 2007...................................... 94 100 Notes, 6.91%, due 2008...................................... -- 50 Debentures, 9 7/8%, due 2010................................ 150 150 Notes, 6.50%, due 2011...................................... 500 -- Notes, 6.68%, due 2011...................................... 400 -- Notes, 6.40%, due 2011...................................... 178 -- Notes, 7.00%, due 2011...................................... -- 75 Debentures, 7 5/8%, due 2013................................ 100 100 Debentures, 9 1/8%, due 2021................................ 150 150 Debentures, 7.65%, due 2023................................. 88 200 Debentures, 8.20%, due 2025................................. 150 150 Debentures, 6 7/8%, due 2026................................ 67 150 Debentures, 7 3/8%, due 2029................................ 92 450 Notes, 7.20%, due 2031...................................... 575 -- Notes, 7.40%, due 2031...................................... 500 -- Other, including discounts.................................. (45) (3) ------ ------ Total long-term debt.............................. $4,337 $2,301 ====== ======

Excluding commercial paper, the Company has debt maturities of $100 million due in 2002, $63 million due in 2003, $0 million due in 2004 and 2005, and $3,544 million due in 2006 and thereafter. The Company's commercial paper borrowings at December 31, 2001 and 2000 had weighted average interest rates of approximately 3 percent and 6 percent, respectively. The fair value of debt outstanding as of December 31, 2001 and 2000 approximates the carrying amount. Burlington Resources Capital Trust I, Burlington Resources Capital Trust II (collectively, the "Trusts"), BR and Burlington Resources Finance Company ("BRFC") have a shelf registration on file with the Securities and Exchange Commission ("SEC"). Pursuant to such registration statement, BR may issue debt securities, shares of common stock or preferred stock. In addition, BRFC may issue debt securities and the Trusts may issue trust preferred securities. Net proceeds, terms and pricing of offerings of securities issued under the shelf registration statement will be determined at the time of the offerings. BRFC and the Trusts are wholly owned finance subsidiaries of BR and have no independent assets or operations other than transferring funds to BR's subsidiaries. Any debt issued by BRFC is fully and unconditionally guaranteed by BR. Any trust preferred securities issued by the Trusts are also fully and unconditionally guaranteed by BR. In February 2001, BRFC issued $400 million of 6.68% Notes due February 15, 2011. In August 2001, BRFC acquired notes with an aggregate principal amount of $710 million and a weighted average interest rate 41 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) of 7.28% and issued $178 million of 6.4% Notes and $575 million of 7.2% Notes due August 15, 2011 and 2031, respectively. The transaction was accounted for as an exchange of debt instruments and reduced the Company's amount available under its shelf registration statement on file with the SEC from $1,500 million to $747 million. The Company had credit commitments in the form of revolving credit facilities ("revolvers") as of December 31, 2001. These revolvers are available to cover debt due within one year, therefore, commercial paper, credit facility notes and fixed-rate debt due within one year are classified as long-term debt. Currently, there are no amounts outstanding under the revolvers, however, the Company's outstanding commercial paper reduces the amount of credit available under the revolvers. The revolvers are comprised of agreements for $600 million, $400 million and $300 million. The $600 million revolver expires in December 2006 and the $400 million and $300 million revolvers expire in December 2002 unless renewed by mutual consent. At expiration of the agreements, the Company has the option to convert the outstanding balances on the $400 million and $300 million revolvers to one year and five-year plus one day term notes, respectively. At the Company's option, interest on borrowings under the $600 million and $400 million revolvers is based on the prime rate or Eurodollar rates. The other revolver bears interest at rates based on prime or Eurodollar rates also at the Company's option, however, the lenders have the option to provide bankers' acceptances in lieu of Eurodollar rate loans. Under the covenants of the revolvers, Company debt cannot exceed 60 percent of capitalization (as defined in the agreements). Outstanding borrowings of $127 million and $114 million as of December 31, 2001 and 2000, respectively, on Company-owned life insurance policies were reported as a reduction to the cash surrender value and are included as a component of Other Assets in the Company's consolidated balance sheet. 7. TRANSPORTATION ARRANGEMENTS WITH EL PASO NATURAL GAS COMPANY In 2001, 2000 and 1999, approximately 29 percent, 32 percent and 30 percent, respectively, of the Company's gas production was transported to direct sale customers through El Paso Natural Gas Company's ("EPNG") pipeline systems. These transportation arrangements are pursuant to EPNG's approved Federal Energy Regulatory Commission tariffs applicable to all shippers. The Company expects to continue to transport a substantial portion of its future gas production through EPNG's pipeline system. See Note 10 of Notes to Consolidated Financial Statements for demand charges paid to EPNG which provide the Company with firm and interruptible transportation capacity rights on interstate and intrastate pipeline systems. 42 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 8. CAPITAL STOCK Common Stock Activity

NUMBER OF SHARES -------------------------------------- ISSUED TREASURY OUTSTANDING ----------- ---------- ----------- BALANCE AT DECEMBER 31, 1998.......................... 241,083,924 25,420,562 215,663,362 Unexchanged Poco shares............................. 104,846 104,846 Treasury shares purchased........................... 250,000 (250,000) Shares issued under compensation plans, net of forfeitures...................................... (27,448) 27,448 Option exercises.................................... (424,089) 424,089 ----------- ---------- ----------- BALANCE AT DECEMBER 31, 1999.......................... 241,188,770 25,219,025 215,969,745 Unexchanged Poco shares............................. (72) (72) Treasury shares purchased........................... 3,505,000 (3,505,000) Shares issued under compensation plans, net of forfeitures...................................... (190,547) 190,547 Option exercises.................................... (2,913,585) 2,913,585 ----------- ---------- ----------- BALANCE AT DECEMBER 31, 2000.......................... 241,188,698 25,619,893 215,568,805 Unexchanged Poco shares............................. (10) (10) Treasury shares purchased........................... 16,092,000 (16,092,000) Shares issued under compensation plans, net of forfeitures...................................... (264,011) 264,011 Option exercises.................................... (1,052,187) 1,052,187 ----------- ---------- ----------- BALANCE AT DECEMBER 31, 2001.......................... 241,188,688 40,395,695 200,792,993 =========== ========== ===========

In December 2000, the Company's Board of Directors authorized the repurchase of up to $1 billion of the Company's Common Stock. During 2001, the Company repurchased 16.1 million shares of its Common Stock for approximately $684 million. Through December 31, 2001, the Company has repurchased approximately 16.3 million shares or $693 million of its Common Stock under this $1 billion authorization. Stock Compensation Plans The Company's 1993 Stock Incentive Plan (the "1993 Plan") succeeds its 1988 Stock Option Plan which expired by its terms in May 1993 but remains in effect for options granted prior to May 1993. The 1993 Plan provides for the grant of stock options, restricted stock, stock purchase rights and stock appreciation rights or limited stock appreciation rights. Under the 1993 Plan, options may be granted to officers and key employees at fair market value on the date of grant, are exercisable in whole or part by the optionee after completion of at least one year of continuous employment from the grant date and have a term of ten years. At December 31, 2001, 4,169,973 shares were available for grant under the 1993 Plan. In 1997, the Company adopted the 1997 Employee Stock Incentive Plan (the "1997 Plan") from which stock options and restricted stock ("Awards") may be granted to employees who are not eligible to participate in the 1993 Plan. The options are granted at fair market value on the grant date, become exercisable in whole or part by the optionee after completion of at least one year of continuous employment and have a term of ten years. The 1997 Plan limits Awards, in aggregate, to a maximum of 1.5 million shares annually, of which up to 150,000 shares annually may be restricted stock. The Company issued 256,700, 211,350 and 110,250 shares of restricted stock in 2001, 2000 and 1999, respectively, from the 1993 and 1997 Plans. The restrictions on this stock generally lapse on the third anniversary of the date of grant. The weighted average grant-date fair value of restricted stock granted in the years ended December 31, 2001, 2000, and 1999 was approximately $50.30, $34.62 and $36.47, respectively. 43 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Related compensation expense of $7 million, $4 million and $2 million was recognized for the years ended December 31, 2001, 2000 and 1999, respectively. The Company's 2000 Stock Option Plan for Non-Employee Directors provides for the annual grant of a nonqualified option for 2,000 shares of Common Stock immediately following the Annual Meeting of Stockholders to Directors who are not salaried officers of the Company. In addition, an option for 5,000 shares is granted upon a Director's initial election or appointment to the Board of Directors. The exercise price per share with respect to each option is the fair market value, as defined in the plan, of the Common Stock on the date the option is granted. The total number of shares of the Company's Common Stock for which options may be granted under the plan is 250,000. The Company's stock option activity follows.

WEIGHTED AVERAGE OPTIONS EXERCISE PRICE ---------- ---------------- Balance, December 31, 1998.................................. 9,145,082 $37.84 Granted................................................... 822,880 33.35 Exercised................................................. (424,089) 30.50 Cancelled................................................. (645,075) 38.32 ---------- Balance, December 31, 1999.................................. 8,898,798 37.80 Granted................................................... 1,432,925 34.55 Exercised................................................. (2,913,585) 31.73 Cancelled................................................. (837,044) 35.38 ---------- Balance, December 31, 2000.................................. 6,581,094 40.08 Granted................................................... 1,638,675 50.53 Exercised................................................. (1,052,187) 35.81 Cancelled................................................. (303,324) 47.00 ---------- Balance, December 31, 2001.................................. 6,864,258 $42.93 ==========

The following table summarizes information related to stock options outstanding and exercisable at December 31, 2001.

WEIGHTED AVERAGE OPTIONS RANGE OF WEIGHTED AVERAGE REMAINING OPTIONS WEIGHTED AVERAGE OUTSTANDING EXERCISE PRICES EXERCISE PRICE CONTRACTUAL LIFE EXERCISABLE EXERCISE PRICE ----------- --------------- ---------------- ---------------- ----------- ---------------- 381,768 .............. $19.51-27.38 $24.10 2.8 381,768 $24.10 3,134,212 .............. 29.10-43.56 37.24 6.1 2,610,953 37.76 3,348,278 .............. 43.88-52.03 50.40 6.7 1,845,353 50.20 --------- --------- 6,864,258 .............. $19.51-52.03 $42.93 6.2 4,838,074 $41.41 ========= =========

Exercisable stock options and weighted average exercise prices at December 31, 2000 and 1999 follow.

OPTIONS WEIGHTED AVERAGE EXERCISABLE EXERCISE PRICE ----------- ---------------- December 31, 2000........................................... 5,348,994 $41.36 December 31, 1999........................................... 7,638,364 $36.98

44 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The weighted average fair values of options granted during the years 2001, 2000 and 1999 were $11.33, $10.33 and $11.13, respectively. The fair values of employee stock options were calculated using a variation of the Black-Scholes stock option valuation model with the following weighted average assumptions for grants in 2001, 2000 and 1999: stock price volatility of 35 percent, 35 percent and 27 percent, respectively; risk free rate of return ranging from 4 percent to 5 percent; dividend yield of 1.32 percent, 1.46 percent and .88 percent, respectively; and an expected term of 3 years. If the fair value based method of accounting, as prescribed by SFAS No. 123, Accounting for Stock-Based Compensation, had been applied, the Company's pro forma net income (loss) and pro forma EPS are shown below. The fair value of stock options included in the pro forma amounts is not necessarily indicative of future effects on net income (loss) and EPS.

YEAR ENDED DECEMBER 31, ------------------------ 2001 2000 1999 ------ ------ ------ (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Net income (loss) -- as reported............................ $ 561 $ 675 $ (10) Net income (loss) -- pro forma.............................. 549 663 (41) Basic EPS -- as reported.................................... 2.71 3.13 (.05) Basic EPS -- pro forma...................................... 2.65 3.08 (.19) Diluted EPS -- as reported.................................. 2.70 3.12 (.05) Diluted EPS -- pro forma.................................... $2.64 $3.06 $(.19)

Preferred Stock and Preferred Stock Purchase Rights The Company is authorized to issue 75,000,000 shares of preferred stock, par value $.01 per share. As of December 31, 2001, one share of preferred stock was issued and designated as Special Voting Stock in connection with the Poco acquisition. On December 9, 1998, the Company's Board of Directors designated 3,250,000 of the authorized preferred shares as Series A Junior Participating Preferred Stock. Upon issuance, each one-hundredth of a share of Series A Junior Participating Preferred Stock will have dividend and voting rights approximately equal to those of one share of Common Stock of the Company. In addition, on December 9, 1998, the Board of Directors declared a dividend distribution of one Right for each outstanding share of Common Stock of the Company to shareholders of record on December 16, 1998. The Rights become exercisable if, without the Company's prior consent, a person or group acquires securities having 15 percent or more of the voting power of all of the Company's voting securities (an "Acquiring Person") or ten days following the announcement of a tender offer which would result in such ownership. Each Right, when exercisable, entitles the registered holder to purchase from the Company one-hundredth of a share of Series A Junior Participating Preferred Stock at a price of $200 per one hundredth of a share, subject to adjustment. If, after the Rights become exercisable, the Company were to be involved in a merger or other business combination in which its Common Stock was exchanged or changed or 50 percent or more of the Company's assets or earning power were sold, each Right would permit the holder to purchase, for the exercise price, stock of the acquiring company having a value of twice the exercise price. In addition, except for certain permitted offers, if any person or group becomes an Acquiring Person, each Right would permit the purchase, for the exercise price, of Common Stock of the Company having a value of twice the exercise price. Rights owned by an Acquiring Person are void. The Rights may be redeemed by the Company under certain circumstances until their expiration date for $.01 per Right. On November 8, 1999 (effective November 18, 1999), the Company's Board of Directors designated one of the authorized preferred shares as Special Voting Stock. The Special Voting Stock is entitled to a number of votes equal to the number of outstanding Exchangeable Shares of Burlington Resources Canada Inc. (other than Exchangeable Shares held by the Company), on all matters presented to the stockholders of the Company. Upon the liquidation, dissolution or winding up of the Company, the holder of the Special Voting Stock shall be entitled, prior and in preference to any distribution to the holders of Common Stock and after 45 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) the distribution to the holders of any class or series of Preferred Stock ranking senior to the Special Voting Stock of all amounts to which such holders are entitled, to receive the sum of $.01. Except as aforesaid, no dividends or distributions shall be payable to the holder of the Special Voting Stock. The Special Voting Stock is not convertible into any other class or series of the capital stock or to cash, property or other rights, and may not be redeemed. If the Special Voting Stock shall be purchased or otherwise acquired by the Company, it shall be deemed retired and shall be cancelled and may not thereafter be reissued or otherwise disposed of by the Company. As long as any Exchangeable Shares of Burlington Resources Canada Inc. are outstanding, the number of shares comprising the Special Voting Stock shall not be increased or decreased and no other term of the Special Voting Stock shall be amended, except upon the unanimous approval of all shares of Common Stock. On November 18, 1999, the one share of Special Voting Stock was issued to CIBC Mellon Trust Company, as trustee pursuant to the Voting and Exchange Trust Agreement among the Company, Burlington Resources Canada Inc. and CIBC Mellon Trust Company, for the benefit of the holders of the Exchangeable Shares of Burlington Resources Canada Inc. On September 14, 2001, all of the remaining outstanding exchangeable shares issued by the Company's subsidiary, Burlington Resources Canada Inc., in connection with the November 1999 acquisition of Poco Petroleums Ltd., were exchanged for BR Common Stock. The exchangeable shares had been trading on the Toronto Stock Exchange in Canada under the symbol "BRX". On September 17, 2001, as part of a reorganization of the Company's Canadian subsidiaries, Burlington Resources Canada Inc., Burlington Resources Canada Energy Ltd. (formerly Poco Petroleums Ltd.) and another wholly-owned Canadian subsidiary of the Company were amalgamated and are now known as Burlington Resources Canada Ltd. 9. RETIREMENT BENEFITS The Company's U.S. pension plans are non-contributory defined benefit plans covering all U.S. employees. The benefits are based on years of credited service and final average compensation. Contributions to the tax qualified plans are limited to amounts that are currently deductible for tax purposes. Contributions are intended to provide not only for benefits attributed to service-to-date but also for those expected to be earned in the future. Hunter also provides a pension plan and postretirement benefits to a closed group of employees and retirees. The Company provides postretirement medical, dental and life insurance benefits for a closed group of retirees and their dependents. The Company also provides limited retiree life insurance benefits to employees who retire under the pension plan. The postretirement benefit plans are unfunded, therefore, the Company funds claims on a cash basis. The Company has a discretionary defined contribution plan ("401K" plan). Under the 401K plan, an employee may elect to contribute from 1 to 13 percent of his/her eligible compensation subject to an Internal Revenue Service limit of $10,500 per year. The Company matches, with cash, from 6 to 8 percent of the employee's eligible contributions. The Company contributed $8 million to the 401K plan for each of the years ended December 31, 2001, 2000 and 1999 to match eligible contributions by employees. 46 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following tables set forth the amounts recognized in the Consolidated Balance Sheet and Statement of Income.

PENSION POSTRETIREMENT BENEFITS BENEFITS ----------- --------------- YEAR ENDED DECEMBER 31, ----------------------------- 2001 2000 2001 2000 ---- ---- ------ ------ (IN MILLIONS) Change in benefit obligation Benefit obligation at beginning of year................... $160 $161 $ 32 $ 24 Service cost.............................................. 9 9 -- -- Interest cost............................................. 11 11 3 3 Amendments................................................ -- -- -- -- Actuarial loss............................................ 1 1 9 8 Participant contributions................................. -- -- 2 -- Acquisition............................................... 12 -- -- -- Benefits paid............................................. (12) (22) (5) (3) ---- ---- ---- ---- Benefit obligation at end of year......................... 181 160 41 32 ---- ---- ---- ---- Change in plan assets Fair value of plan assets at beginning of year............ 156 171 -- -- Actual return on plan assets.............................. (4) 2 -- -- Employer contribution..................................... -- 5 3 3 Participant contributions................................. -- -- 2 -- Acquisition............................................... 15 -- -- -- Benefits paid............................................. (12) (22) (5) (3) ---- ---- ---- ---- Fair value of plan assets at end of year.................. 155 156 -- -- ---- ---- ---- ---- Funded status............................................... (26) (4) (41) (32) Unrecognized net actuarial gain............................. 21 2 16 7 Unrecognized net transition obligation...................... -- 1 -- -- Unrecognized prior service cost............................. 1 1 (6) (7) ---- ---- ---- ---- Net prepaid (accrued) benefit cost.......................... $ (4) $ -- $(31) $(32) ==== ==== ==== ====

PENSION BENEFITS POSTRETIREMENT BENEFITS -------------------- ------------------------ YEAR ENDED DECEMBER 31, ------------------------------------------------ 2001 2000 1999 2001 2000 1999 ---- ---- ---- ----- ----- ------ (IN MILLIONS) Benefit cost for the plans includes the following components Service cost.................................. $ 9 $ 9 $ 10 $-- $-- $-- Interest cost................................. 11 11 12 3 3 2 Expected return on plan assets................ (14) (13) (14) -- -- -- Recognized net actuarial loss................. -- -- 1 -- -- -- ---- ---- ---- --- --- -- Net benefit cost...................... $ 6 $ 7 $ 9 $ 3 $ 3 $2 ==== ==== ==== === === ==

47 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

PENSION BENEFITS POSTRETIREMENT BENEFITS ----------------------- ----------------------- YEAR ENDED DECEMBER 31, -------------------------------------------------- 2001 2000 1999 2001 2000 1999 ----- ----- ----- ----- ----- ----- Weighted average assumptions Discount rate......................... 7.25% 7.50% 7.75% 7.25% 7.50% 7.75% Expected return on plan assets........ 9.00% 9.00% 9.00% -- -- -- Rate of compensation increase......... 5.00% 5.00% 5.00% -- -- --

A 10 percent annual rate of increase in the per capita cost of pre-age 65 covered health care benefits was assumed for 2002. The rate is assumed to decrease gradually to 5 percent for 2007 and remain at that level thereafter. A 12 percent annual rate of increase in the per capita cost of post-age 65 covered health care benefits was assumed to decrease gradually to 5 percent for 2009 and remain at that level thereafter. Assumed health care cost trends have a significant effect on the amounts reported for the postretirement medical and dental care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects.

1-PERCENTAGE 1-PERCENTAGE POINT INCREASE POINT DECREASE -------------- -------------- (IN THOUSANDS) Effect on total service and interest cost................... $ 214 $ (183) Effect on postretirement benefit obligation................. $3,823 $(3,296)

10. COMMITMENTS AND CONTINGENT LIABILITIES Demand Charges The Company has entered into contracts which provide firm transportation capacity rights on interstate and intrastate pipeline systems. The remaining terms on these contracts range from 1 to 23 years and require the Company to pay transportation demand charges regardless of the amount of pipeline capacity utilized by the Company. The Company paid $128 million, $123 million and $122 million of demand charges of which $24 million, $27 million and $36 million were paid to EPNG for the years ended December 31, 2001, 2000 and 1999, respectively. All transportation costs including demand charges are included in transportation expense in the income statement. Future transportation demand charge commitments at December 31, 2001 follow.

YEAR ENDED DECEMBER 31, ----------------------- (IN MILLIONS) 2002........................................................ $133 2003........................................................ 126 2004........................................................ 118 2005........................................................ 108 2006........................................................ 95 Thereafter.................................................. 337 ---- Total............................................. $917 ====

Lease Obligations The Company has operating leases for office space and other property and equipment. The Company incurred lease rental expense of $23 million, $24 million and $24 million for the years ended December 31, 2001, 2000 and 1999, respectively. 48 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Future minimum annual rental commitments at December 31, 2001 follow.

YEAR ENDED DECEMBER 31, ----------------------- (IN MILLIONS) 2002........................................................ $ 33 2003........................................................ 29 2004........................................................ 25 2005........................................................ 21 2006........................................................ 18 Thereafter.................................................. 66 ---- Total............................................. $192 ====

Drilling Rig Commitments During 1998, the Company entered into agreements to lease two deep water drilling rigs through 2004 with remaining commitments of $188 million. This commitment will be utilized by drilling exploration wells, partner participation or subletting to extent possible. Legal Proceedings The Company and numerous other oil and gas companies have been named as defendants in various lawsuits alleging violations of the civil False Claims Act. These lawsuits have been consolidated by the United States Judicial Panel on Multidistrict Litigation for pre-trial proceedings in the matter of In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court for the District of Wyoming ("MDL-1293"). The plaintiffs contend that defendants underpaid royalties on natural gas and NGLs produced on federal and Indian lands through the use of below-market prices, improper deductions, improper measurement techniques and transactions with affiliated companies. Plaintiffs allege that the royalties paid by defendants were lower than the royalties required to be paid under federal regulations and that the forms filed by defendants with the Minerals Management Service ("MMS") reporting these royalty payments were false, thereby violating the civil False Claims Act. The United States has intervened in certain of the MDL-1293 cases as to some of the defendants, including the Company. Various administrative proceedings are also pending before the MMS of the United States Department of the Interior with respect to the valuation of natural gas produced by the Company on federal and Indian lands. In general, these proceedings stem from regular MMS audits of the Company's royalty payments over various periods of time and involve the interpretation of the relevant federal regulations. Based on the Company's present understanding of the various governmental and False Claims Act proceedings described above, the Company believes that it has substantial defenses to these claims and intends to vigorously assert such defenses. However, in the event that the Company is found to have violated the civil False Claims Act, the Company could be subject to monetary damages and a variety of sanctions, including double damages, substantial monetary fines, civil penalties and a temporary suspension from entering into future federal mineral leases and other federal contracts for a defined period of time. While the ultimate outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the consolidated financial position of the Company, although results of operations and cash flow could be significantly impacted in the reporting periods in which such matters are resolved. The Company has also been named as a defendant in the lawsuit styled UNOCAL Netherlands B.V., et al. v. Continental Netherlands Oil Company B.V., et al, No. 98-854, in the Court of Appeal in The Hague in the Netherlands. Plaintiffs, who are working interest owners in the Q-1 Block in the North Sea, have alleged that the Company and other former working interest owners in the adjacent Logger Field in the L16a Block 49 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) unlawfully trespassed or were otherwise unjustly enriched by producing part of the oil from the adjoining Q-1 Block. The plaintiffs claim that the defendants infringed upon plaintiffs' right to produce the minerals present in its license area and acted in violation of generally accepted standards by failing to inform plaintiffs of the overlap of the Logger Field into the Q-1 Block. For all relevant periods, the Company owned a 37.5% working interest in the Logger Field. Following a trial, the District Court in The Hague rendered a Judgment in favor of the defendants, including the Company, dismissing all claims. Plaintiffs thereafter appealed. On October 19, 2000, the Court of Appeal in The Hague issued an interim Judgment in favor of the plaintiffs and ordered that additional evidence be presented to the court relating to issues of both liability and damages. The Company and the other defendants are continuing to vigorously assert defenses against these claims. The Company has also asserted claims of indemnity against two of the defendants from whom it had acquired a portion of its working interest share. The Company is unable at this time to reasonably predict the outcome, or, in the event of an unfavorable outcome, to reasonably estimate the possible loss or range of loss, if any, in this lawsuit. In addition to the foregoing, the Company and its subsidiaries are named defendants in numerous other lawsuits and named parties in numerous governmental and other proceedings arising in the ordinary course of business. While the outcome of these other lawsuits and proceedings cannot be predicted with certainty, management believes these other matters will not have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company. 11. SUPPLEMENTAL CASH FLOW INFORMATION The following is additional information concerning supplemental disclosures of cash payments.

YEAR ENDED DECEMBER 31, ----------------------- 2001 2000 1999 ----- ----- ----- (IN MILLIONS) Interest paid............................................... $164 $195 $206 Income taxes paid -- net.................................... $136 $ 88 $ 13

The Company purchased all of the outstanding shares of Hunter for $2,087 million, net of cash acquired. In conjunction with the acquisition, liabilities were assumed as follows. Fair value of assets acquired............................... $3,297 Cash paid for the capital stock, net of cash acquired....... 2,087 ------ Liabilities assumed....................................... $1,210 ====== At December 31, 2001, 2000 and 1999, the Accounts Payable balance on the Consolidated Balance Sheet included payables for capital expenditures of $298 million, $232 million and $161 million, respectively. 12. IMPAIRMENT OF OIL AND GAS PROPERTIES In December 2001, primarily as a result of the Company's decision to exit the Gulf of Mexico Shelf and divest of certain other properties, the Company recognized a pretax impairment charge of $184 million primarily related to the impairment of oil and gas properties held for sale. The net book value of these properties at December 31, 2001 totaled approximately $338 million. In the fourth quarter of 1999, the Company determined there would be performance related downward reserve adjustments associated with certain properties located on the Gulf of Mexico shelf and in the Permian Basin. As a result, the Company recognized a pretax impairment charge of $225 million related to those properties. 50 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 13. SEGMENT AND GEOGRAPHIC INFORMATION The Company's reportable segments are USA, Canada and Other International. These segments are engaged principally in the exploration, development, production and marketing of oil, gas and NGLs. The accounting policies for the segments are the same as those described in Note 1 of Notes to Consolidated Financial Statements. Intersegment sales were $157 million and $85 million in 2001 and 2000, respectively. There were no intersegment sales in 1999. The following tables present information about reported segment operations.

YEAR ENDED DECEMBER 31, 2001 ---------------------------------------- NORTH AMERICA --------------- OTHER USA CANADA INTERNATIONAL TOTAL ------ ------ ------------- ------ (IN MILLIONS) Revenues............................................... $2,199 $ 938 $189 $3,326 Depreciation, depletion and amortization............... 453 170 86 709 Impairment of oil and gas properties................... 184 -- -- 184 Operating income....................................... 772 458 25 1,255 Additions to properties................................ $ 653 $2,558 $217 $3,428

YEAR ENDED DECEMBER 31, 2000 ---------------------------------------- NORTH AMERICA --------------- OTHER USA CANADA INTERNATIONAL TOTAL ------ ------ ------------- ------ (IN MILLIONS) Revenues............................................... $2,224 $ 752 $171 $3,147 Depreciation, depletion and amortization............... 504 123 58 685 Operating income....................................... 1,026 313 36 1,375 Additions to properties................................ $ 468 $ 336 $179 $ 983

YEAR ENDED DECEMBER 31, 1999 ---------------------------------------- NORTH AMERICA --------------- OTHER USA CANADA INTERNATIONAL TOTAL ------ ------ ------------- ------ (IN MILLIONS) Revenues............................................... $1,775 $ 407 $131 $2,313 Depreciation, depletion and amortization............... 450 110 57 617 Impairment of oil and gas properties................... 225 -- -- 225 Operating income (loss)................................ 307 131 (21) 417 Additions to properties................................ $ 502 $ 295 $148 $ 945

The following is a reconciliation of segment operating income to consolidated income (loss) before income taxes.

YEAR ENDED DECEMBER 31, ----------------------- 2001 2000 1999 ------ ------ ----- (IN MILLIONS) Total operating income for reportable segments.............. $1,255 $1,375 $ 417 Merger costs................................................ -- -- 37 Corporate expenses.......................................... 170 184 180 Interest expense............................................ 190 197 211 Other expense (income)-- net................................ (12) 27 2 ------ ------ ----- Consolidated income (loss) before income taxes.............. $ 907 $ 967 $ (13) ====== ====== =====

51 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following is a reconciliation of segment additions to properties to consolidated amounts.

YEAR ENDED DECEMBER 31, ------------------------- 2001 2000 1999 ------- ------- ----- (IN MILLIONS) Total additions to properties for reportable segments....... $3,428 $ 983 $945 Administrative additions.................................... 26 29 44 ------ ------ ---- Consolidated additions to properties........................ $3,454 $1,012 $989 ====== ====== ====

14. OTHER MATTERS Recent Accounting Pronouncements The following SFAS's were issued in June 2001: SFAS No. 141, Business Combinations, SFAS No. 142, Goodwill and Other Intangible Assets, and SFAS No. 143, Accounting for Asset Retirement Obligations. In August 2001, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets was also issued. SFAS No. 141, requires the use of the purchase method of accounting for all business combinations, applies to all business combinations initiated after June 30, 2001 and to all business combinations accounted for by the purchase method that are completed after June 30, 2001. SFAS No. 142 requires that goodwill as well as other intangible assets with indefinite lives not be amortized but be tested annually for impairment and is effective for fiscal years beginning after December 15, 2001. SFAS No. 141 and No. 142 apply to the Company's accounting for the Hunter acquisition. The Company is in the process of evaluating the impairment methodology for goodwill. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. SFAS No. 144 addresses financial accounting and reporting for the impairment of long-lived assets to be disposed of. It supersedes, with exceptions, SFAS No. 121, Accounting for the Impairment of Long-Lived Assets to Be Disposed Of and is effective for fiscal years beginning after December 15, 2001. The Company is currently assessing the impact of SFAS No. 143 and No. 144 and therefore, at this time cannot reasonably estimate the effect of these statements on its consolidated financial position, results of operations or cash flows. 15. SUBSEQUENT EVENTS On January 3, 2002, the Company consummated a property acquisition from ATCO Gas and Pipelines Ltd., a Canadian regulated gas utility, for approximately $346 million. 52 REPORT OF MANAGEMENT The management of BR is responsible for the preparation and integrity of all information contained in this Annual Report. The accompanying financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America. The financial statements include amounts that are management's best estimates and judgments. BR maintains a system of internal control and a program of internal auditing that provides management with reasonable assurance that BR's assets are protected and that published financial statements are reliable and free of material misstatement. Management is responsible for the effectiveness of internal controls. This is accomplished through established codes of conduct, accounting and other control systems, policies and procedures, employee selection and training, appropriate delegation of authority and segregation of responsibilities. The Audit Committee of the Board of Directors, composed solely of directors who are not officers or employees, meets regularly with the independent accountants, financial management, counsel and internal audit. To ensure complete independence, the independent accountants and internal audit have full and free access to the Audit Committee to discuss the results of their audits, the adequacy of internal controls and the quality of financial reporting. Our independent accountants provide an objective independent review by their audit of the Company's financial statements. Their audit is conducted in accordance with auditing standards generally accepted in the United States of America and includes a review of internal accounting controls to the extent deemed necessary for the purposes of their audit. /s/ STEVEN J. SHAPIRO /s/ JOSEPH P. MCCOY -------------------------------------------- -------------------------------------------- Steven J. Shapiro Joseph P. McCoy Senior Vice President and Vice President, Controller and Chief Financial Officer Chief Accounting Officer 53 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of Burlington Resources Inc. In our opinion, based on our audits and the report of other auditors, the accompanying consolidated balance sheet and the related consolidated statements of income, cash flows and stockholders' equity, present fairly, in all material respects, the financial position of Burlington Resources Inc. and its subsidiaries at December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements give retroactive effect to the merger of Poco Petroleums Ltd. on November 18, 1999 in a transaction accounted for as a pooling of interests, as described in Note 2 to the consolidated financial statements. We did not audit the financial statements of Poco Petroleums Ltd., which statements reflect total revenues of $407 million for the year ended December 31, 1999. Those statements were audited by other auditors whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for Poco Petroleums Ltd., is based solely on the report of the other auditors. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion. As discussed in Note 4 to the consolidated financial statements, the Company changed its method of accounting for its derivative instruments and hedging activities in connection with its adoption of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended. /s/ PRICEWATERHOUSECOOPERS LLP February 13, 2002 Houston, Texas 54 BURLINGTON RESOURCES INC. SUPPLEMENTARY FINANCIAL INFORMATION SUPPLEMENTAL OIL AND GAS DISCLOSURES -- UNAUDITED The supplemental data presented herein reflects information for all of the Company's oil and gas producing activities. Costs incurred for oil and gas property acquisition, exploration and development activities follow.

YEAR ENDED DECEMBER 31, 2001 ----------------------------------------------- NORTH AMERICA ----------------- OTHER USA CANADA(1) INTERNATIONAL WORLDWIDE ---- --------- ------------- --------- (IN MILLIONS) Property acquisition Unproved........................................ $ 14 $ 18 $ 4 $ 36 Proved.......................................... 67 1,900 30 1,997 Exploration....................................... 99 76 48 223 Development....................................... 403 288 135 826 ---- ------ ---- ------ Total costs incurred.................... $583 $2,282 $217 $3,082 ==== ====== ==== ======

--------------- (1) The amounts exclude deferred taxes of $902 million related to the Hunter acquisition.

YEAR ENDED DECEMBER 31, 2000 -------------------------------------------- NORTH AMERICA -------------- OTHER USA CANADA INTERNATIONAL WORLDWIDE ---- ------ ------------- --------- (IN MILLIONS) Property acquisition Unproved.......................................... $ 12 $ 21 $ 9 $ 42 Proved............................................ 6 14 29 49 Exploration......................................... 106 129 61 296 Development......................................... 288 152 80 520 ---- ---- ---- ---- Total costs incurred...................... $412 $316 $179 $907 ==== ==== ==== ====

YEAR ENDED DECEMBER 31, 1999 -------------------------------------------- NORTH AMERICA -------------- OTHER USA CANADA INTERNATIONAL WORLDWIDE ---- ------ ------------- --------- (IN MILLIONS) Property acquisition Unproved.......................................... $ 12 $ 18 $ 2 $ 32 Proved............................................ 69 66 -- 135 Exploration......................................... 88 67 66 221 Development......................................... 319 140 80 539 ---- ---- ---- ---- Total costs incurred...................... $488 $291 $148 $927 ==== ==== ==== ====

55 BURLINGTON RESOURCES INC. SUPPLEMENTARY FINANCIAL INFORMATION Results of operations for oil, NGL and gas producing activities, which exclude pipeline and processing activities, corporate general and administrative expenses, fixed-rate depreciation expense, and payroll and miscellaneous taxes, were as follow. Prior years have been restated to conform to current year presentation. Intersegment sales were $157 million and $85 million in 2001 and 2000, respectively. There were no intersegment sales in 1999.

YEAR ENDED DECEMBER 31, 2001 ------------------------------------------- NORTH AMERICA --------------- OTHER USA CANADA INTERNATIONAL WORLDWIDE ------ ------ ------------- --------- (IN MILLIONS) Revenues............................................. $2,122 $ 936 $189 $3,247 ------ ------ ---- ------ Production costs..................................... 401 137 17 555 Exploration costs.................................... 167 52 39 258 Operating expenses................................... 205 113 22 340 Depreciation, depletion and amortization............. 438 162 82 682 Impairment of oil and gas properties................. 184 -- -- 184 ------ ------ ---- ------ 1,395 464 160 2,019 ------ ------ ---- ------ Operating income..................................... 727 472 29 1,228 Income tax provision (benefit)....................... 264 234 (1) 497 ------ ------ ---- ------ Results of operations for oil and gas producing activities......................................... $ 463 $ 238 $ 30 $ 731 ====== ====== ==== ======

YEAR ENDED DECEMBER 31, 2000 ------------------------------------------- NORTH AMERICA --------------- OTHER USA CANADA INTERNATIONAL WORLDWIDE ------ ------ ------------- --------- (IN MILLIONS) Revenues............................................. $2,171 $ 748 $171 $3,090 ------ ------ ---- ------ Production costs..................................... 372 122 20 514 Exploration costs.................................... 104 92 42 238 Operating expenses................................... 225 89 15 329 Depreciation, depletion and amortization............. 487 118 54 659 ------ ------ ---- ------ 1,188 421 131 1,740 ------ ------ ---- ------ Operating income..................................... 983 327 40 1,350 Income tax provision................................. 256 157 23 436 ------ ------ ---- ------ Results of operations for oil and gas producing activities......................................... $ 727 $ 170 $ 17 $ 914 ====== ====== ==== ======

YEAR ENDED DECEMBER 31, 1999 ------------------------------------------- NORTH AMERICA --------------- OTHER USA CANADA INTERNATIONAL WORLDWIDE ------ ------ ------------- --------- (IN MILLIONS) Revenues............................................. $1,646 $ 481 $124 $2,251 ------ ------ ---- ------ Production costs..................................... 347 102 33 482 Exploration costs.................................... 141 39 46 226 Operating expenses................................... 208 100 23 331 Depreciation, depletion and amortization............. 435 107 54 596 Impairment of oil and gas properties................. 225 -- -- 225 ------ ------ ---- ------ 1,356 348 156 1,860 ------ ------ ---- ------ Operating income (loss).............................. 290 133 (32) 391 Income tax provision (benefit)....................... 94 63 (10) 147 ------ ------ ---- ------ Results of operations for oil and gas producing activities......................................... $ 196 $ 70 $(22) $ 244 ====== ====== ==== ======

56 BURLINGTON RESOURCES INC. SUPPLEMENTARY FINANCIAL INFORMATION The following table reflects estimated quantities of proved oil, NGL and gas reserves. These reserves have been estimated by the Company's petroleum engineers. The Company considers such estimates to be reasonable, however, due to inherent uncertainties, estimates of underground reserves are imprecise and subject to change over time as additional information becomes available. To reflect the change in the characteristics of its oil and gas properties, in 2001, the Company began reporting its production volumes and reserves in three streams: natural gas, crude oil and NGLs. Under this methodology, gas production and reserves are reported after extracting liquids and eliminating non-hydrocarbon gases from the natural gas stream. This change had no material impact on total equivalent reserves or production volumes. Amounts for prior years have been reclassified to conform to current presentation.

OIL (MMBBLS) ------------------------------------------ NORTH AMERICA -------------- OTHER USA CANADA INTERNATIONAL WORLDWIDE ----- ------ ------------- --------- PROVED DEVELOPED AND UNDEVELOPED RESERVES December 31, 1998...................................... 226.6 53.7 46.6 326.9 Revisions of previous estimates...................... (9.0) .6 .3 (8.1) Extensions, discoveries and other additions.......... 19.0 2.4 2.0 23.4 Production........................................... (20.9) (5.0) (4.8) (30.7) Purchase of reserves in place........................ .5 .2 -- .7 Sales of reserves in place........................... -- -- -- -- ----- ---- ---- ----- December 31, 1999...................................... 216.2 51.9 44.1 312.2 Revisions of previous estimates...................... .2 8.3 .9 9.4 Extensions, discoveries and other additions.......... 7.5 1.9 15.3 24.7 Production........................................... (18.8) (4.6) (3.5) (26.9) Purchases of reserves in place....................... .6 -- 14.7 15.3 Sales of reserves in place........................... (1.5) -- (1.5) (3.0) ----- ---- ---- ----- December 31, 2000...................................... 204.2 57.5 70.0 331.7 Revisions of previous estimates...................... (10.7) (.6) .4 (10.9) Extensions, discoveries and other additions.......... 66.7 2.9 2.5 72.1 Production........................................... (16.1) (4.3) (2.7) (23.1) Purchases of reserves in place....................... .4 1.2 .8 2.4 Sales of reserves in place........................... (.2) (.1) -- (.3) ----- ---- ---- ----- December 31, 2001...................................... 244.3 56.6 71.0 371.9 ===== ==== ==== ===== PROVED DEVELOPED RESERVES December 31, 1998.................................... 199.2 45.4 14.5 259.1 December 31, 1999.................................... 168.3 43.2 13.5 225.0 December 31, 2000.................................... 169.7 43.0 10.4 223.1 December 31, 2001.................................... 163.7 38.4 9.3 211.4

57

NGLS (MMBBLS) GAS (BCF) -------------------------- ------------------------------------------ NORTH AMERICA NORTH AMERICA TOTAL -------------- -------------- OTHER EQUIVALENT USA CANADA WORLDWIDE USA CANADA INTERNATIONAL WORLDWIDE (BCFE) ----- ------ --------- ----- ------ ------------- --------- ---------- 184.4 40.7 225.1 4,923 1,215 491 6,629 9,941 7.6 9.7 17.3 (76) (44) (1) (121) (66) 27.9 4.1 32.0 450 140 344 934 1,266 (12.3) (4.5) (16.8) (483) (137) (31) (651) (936) 5.0 1.2 6.2 121 45 -- 166 207 -- -- -- -- (8) -- (8) (8) ----- ----- ----- ----- ----- --- ----- ------ 212.6 51.2 263.8 4,935 1,211 803 6,949 10,404 (1.5) (8.8) (10.3) (72) (104) (9) (185) (190) 24.1 5.7 29.8 489 192 8 689 1,016 (13.2) (4.1) (17.3) (462) (124) (43) (629) (894) .2 .1 .3 5 18 -- 23 117 -- (.1) (.1) (11) (4) (30) (45) (64) ----- ----- ----- ----- ----- --- ----- ------ 222.2 44.0 266.2 4,884 1,189 729 6,802 10,389 5.8 (12.9) (7.1) 107 (66) (35) 6 (102) 9.6 4.8 14.4 253 165 58 476 995 (12.6) (4.6) (17.2) (409) (158) (62) (629) (871) 2.7 16.4 19.1 59 1,007 207 1,273 1,402 -- -- -- (2) (1) -- (3) (5) ----- ----- ----- ----- ----- --- ----- ------ 227.7 47.7 275.4 4,892 2,136 897 7,925 11,808 ===== ===== ===== ===== ===== === ===== ====== 143.6 32.5 176.1 3,835 970 243 5,048 7,659 168.3 41.6 209.9 3,907 983 289 5,179 7,788 177.6 35.5 213.1 3,903 960 251 5,114 7,731 175.5 39.3 214.8 3,771 1,758 478 6,007 8,564

58 BURLINGTON RESOURCES, INC. SUPPLEMENTARY FINANCIAL INFORMATION A summary of the standardized measure of discounted future net cash flows relating to proved oil, NGL and gas reserves is shown below. Future net cash flows are computed using year end commodity prices, costs and statutory tax rates (adjusted for tax credits and other items) that relate to the Company's existing proved oil, NGL and gas reserves.

2001 -------------------------------------------- NORTH AMERICA ---------------- OTHER USA CANADA INTERNATIONAL WORLDWIDE ------- ------ ------------- --------- (IN MILLIONS) Future cash inflows................................. $15,544 $6,206 $3,948 $25,698 Less related future Production costs............................... 4,612 1,606 1,042 7,260 Development costs.............................. 752 654 741 2,147 Income taxes................................... 2,701 1,433 621 4,755 ------- ------ ------ ------- Future net cash flows............................... 7,479 2,513 1,544 11,536 10% annual discount for estimated timing of cash flows............................................. 3,971 920 645 5,536 ------- ------ ------ ------- Standardized measure of discounted future net cash flows............................................. $ 3,508 $1,593 $ 899 $ 6,000 ======= ====== ====== =======

2000 --------------------------------------------- NORTH AMERICA ----------------- OTHER USA CANADA INTERNATIONAL WORLDWIDE ------- ------- ------------- --------- (IN MILLIONS) Future cash inflows................................ $52,400 $13,722 $3,895 $70,017 Less related future Production costs............. 7,732 1,394 926 10,052 Development costs............................. 670 656 632 1,958 Income taxes.................................. 14,959 4,655 773 20,387 ------- ------- ------ ------- Future net cash flows.............................. 29,039 7,017 1,564 37,620 10% annual discount for estimated timing of cash flows............................................ 15,173 2,879 764 18,816 ------- ------- ------ ------- Standardized measure of discounted future net cash flows............................................ $13,866 $ 4,138 $ 800 $18,804 ======= ======= ====== =======

1999 -------------------------------------------- NORTH AMERICA ---------------- OTHER USA CANADA INTERNATIONAL WORLDWIDE ------- ------ ------------- --------- (IN MILLIONS) Future cash inflows................................. $17,568 $4,184 $2,840 $24,592 Less related future Production costs.............. 4,778 1,140 778 6,696 Development costs.............................. 661 279 604 1,544 Income taxes................................... 3,281 685 423 4,389 ------- ------ ------ ------- Future net cash flows............................... 8,848 2,080 1,035 11,963 10% annual discount for estimated timing of cash flows............................................. 4,374 788 508 5,670 ------- ------ ------ ------- Standardized measure of discounted future net cash flows............................................. $ 4,474 $1,292 $ 527 $ 6,293 ======= ====== ====== =======

59 BURLINGTON RESOURCES INC. SUPPLEMENTARY FINANCIAL INFORMATION A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil, NGL and gas reserves follows.

2001 2000 1999 -------- ------- ------- (IN MILLIONS) January 1................................................... $ 18,804 $ 6,293 $ 5,144 -------- ------- ------- Revisions of previous estimates Changes in prices and costs............................... (22,694) 18,756 1,844 Changes in quantities..................................... 60 (157) (83) Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs..... 483 2,613 723 Purchases of reserves in place.............................. 1,147 191 168 Sales of reserves in place.................................. (15) (46) (6) Accretion of discount....................................... 2,879 825 628 Sales of oil and gas, net of production costs............... (2,692) (2,575) (1,769) Net change in income taxes.................................. 7,836 (8,023) (815) Changes in rate of production and other..................... 192 927 459 -------- ------- ------- Net change.................................................. (12,804) 12,511 1,149 -------- ------- ------- December 31................................................. $ 6,000 $18,804 $ 6,293 ======== ======= =======

QUARTERLY FINANCIAL DATA -- UNAUDITED

2001 2000 --------------------------------- --------------------------------- 4TH 3RD 2ND 1ST 4TH 3RD 2ND 1ST ------ ------ ------ ------ ------ ------ ------ ------ (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues........................... $ 611 $ 655 $ 917 $1,143 $ 999 $ 760 $ 680 $ 708 Operating Income (Loss)(a)......... (94) 143 425 611 485 318 201 187 Income Before Cumulative Effect of Change in Accounting Principle... (79) 73 231 333 -- -- -- -- Net Income (Loss)(a)............... (79) 73 231 336 304 200 94 77 Basic Earnings (Loss) per Common Share............................ (.39) .36 1.10 1.57 1.41 .93 .43 .36 Diluted Earnings (Loss) per Common Share............................ (.39) .36 1.10 1.56 1.41 .93 .43 .35 Cash Dividends Declared per Common Share............................ .14 .13 .14 .14 .14 .13 .14 .14 Common Stock Price Range High............................. 39.75 44.19 51.95 53.63 52.88 40.75 46.25 39.50 Low.............................. $32.75 $31.69 $37.55 $40.98 $34.31 $29.25 $34.50 $25.75

--------------- (a) During the fourth quarter of 2001, the Company recognized a non-cash, pretax charge of $184 million primarily related to the impairment of oil and gas properties held for sale. ITEM NINE CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 60 PART III ITEMS TEN AND ELEVEN DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT AND EXECUTIVE COMPENSATION Executive officers of the Registrant Bobby S. Shackouls, 51 -- Chairman of the Board, President and Chief Executive Officer, Burlington Resources Inc., July 1997 to present. President and Chief Executive Officer, Burlington Resources Inc., December 1995 to July 1997; President and Chief Executive Officer, Burlington Resources Oil & Gas Company, October 1994 to June 1998. Randy L. Limbacher, 43 -- Senior Vice President, Production, Burlington Resources Inc., April 2001 to present. President and Chief Executive Officer, BROG GP Inc., general partner of Burlington Resources Oil & Gas Company LP, December 2000 to present. President and Chief Executive Officer, Burlington Resources Oil & Gas Company, July 1998 to December 2000. Vice President, Gulf Coast Division, Burlington Resources Oil & Gas Company, February 1997 to June 1998; Vice President, Farmington Region, Burlington Resources Oil & Gas Company, June 1993 to January 1997. L. David Hanower, 42 -- Senior Vice President, Law and Administration, Burlington Resources Inc., July 1998 to present. Senior Vice President, Law, Burlington Resources Inc., April 1996 to June 1998, Vice President, Law, Burlington Resources Inc., April 1991 to April 1996; Senior Vice President, Law, Burlington Resources Oil & Gas Company, July 1993 to June 1998. Steven J. Shapiro, 49 -- Senior Vice President and Chief Financial Officer, Burlington Resources Inc., October 2000 to present. Senior Vice President, Chief Financial Officer and Director, Vastar Resources, Inc., 1993 to September 2000. John A. Williams, 57 -- Senior Vice President, Exploration, Burlington Resources Inc., April 2001 to present. Senior Vice President, Exploration, BROG GP Inc., general partner of Burlington Resources Oil & Gas Company LP, December 2000 to present. Senior Vice President, Exploration, Burlington Resources Oil & Gas Company, July 1998 to December 2000. Senior Vice President, Exploration, Burlington Resources Inc., October 1997 to June 1998; Senior Vice President, Exploration and Production, The Louisiana Land and Exploration Company, September 1995 to October 1997. A definitive proxy statement for the 2002 Annual Meeting of Stockholders (the "Proxy Statement") of the Company will be filed no later than 120 days after the end of the fiscal year with the Securities and Exchange Commission. The information set forth therein under "Election of Directors" and "Executive Compensation" is incorporated herein by reference. ITEM TWELVE SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information required is set forth under the caption "Stock Ownership of Management and Certain Other Holders" in the Proxy Statement and is incorporated herein by reference. ITEM THIRTEEN CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Any information required is set forth under the caption "Election of Directors" in the Proxy Statement and is incorporated herein by reference. 61 PART IV ITEM FOURTEEN EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

PAGE ---- FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION Consolidated Statement of Income.......................... 27 Consolidated Balance Sheet................................ 28 Consolidated Statement of Cash Flows...................... 29 Consolidated Statement of Stockholders' Equity............ 30 Notes to Consolidated Financial Statements................ 31 Report of Independent Accountants......................... 54 Supplemental Oil and Gas Disclosures -- Unaudited......... 55 Quarterly Financial Data -- Unaudited..................... 60 AMENDED EXHIBIT INDEX....................................... A-1

REPORTS ON FORM 8-K The Company filed a Form 8-K dated December 4, 2001, which included as an exhibit a Press Release also dated December 4, 2001 announcing the acceptance of its C$53 per share cash tender offer to acquire all the common shares of Canadian Hunter Exploration Ltd. by Canadian Hunter's shareholders. The financial statements and pro forma financial information for Canadian Hunter required to be filed pursuant to Item 7 of such Form 8-K are filed as exhibits 99.3, 99.4 and 99.5 in this Form 10-K. The Company filed a Form 8-K dated October 9, 2001, which included as an exhibit a Press Release also dated October 9, 2001 announcing the Company and Canadian Hunter Exploration Ltd. have entered into an agreement pursuant to which the Company will make an offer to holders of the outstanding shares of Canadian Hunter to acquire all such shares for cash consideration of C$53 per share, representing an aggregate value of approximately U.S. $2.1 billion in cash. 62 SIGNATURES REQUIRED FOR FORM 10-K Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Burlington Resources Inc. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. BURLINGTON RESOURCES INC. By /s/ BOBBY S. SHACKOULS ------------------------------------ Bobby S. Shackouls Chairman of the Board, President and Chief Executive 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 Burlington Resources Inc. and in the capacities and on the dates indicated. By /s/ BOBBY S. SHACKOULS Chairman of the Board, February 13, 2002 ----------------------------------------------------- President and Chief Bobby S. Shackouls Executive Officer /s/ STEVEN J. SHAPIRO Senior Vice President and February 13, 2002 -------------------------------------------------------- Chief Financial Officer Steven J. Shapiro /s/ JOSEPH P. MCCOY Vice President, February 13, 2002 -------------------------------------------------------- Controller and Chief Joseph P. McCoy Accounting Officer /s/ REUBEN V. ANDERSON Director February 13, 2002 -------------------------------------------------------- Reuben V. Anderson /s/ LAIRD I. GRANT Director February 13, 2002 -------------------------------------------------------- Laird I. Grant /s/ JOHN T. LAMACCHIA Director February 13, 2002 -------------------------------------------------------- John T. Lamacchia /s/ JAMES F. MCDONALD Director February 13, 2002 -------------------------------------------------------- James F. McDonald /s/ KENNETH W. ORCE Director February 13, 2002 -------------------------------------------------------- Kenneth W. Orce /s/ DONALD M. ROBERTS Director February 13, 2002 -------------------------------------------------------- Donald M. Roberts /s/ JOHN F. SCHWARZ Director February 13, 2002 -------------------------------------------------------- John F. Schwarz /s/ WALTER SCOTT, JR. Director February 13, 2002 -------------------------------------------------------- Walter Scott, Jr. /s/ WILLIAM E. WADE Director February 13, 2002 -------------------------------------------------------- William E. Wade BURLINGTON RESOURCES INC. AMENDED EXHIBIT INDEX The following exhibits are filed as part of this report.

EXHIBIT PAGE NUMBER DESCRIPTION NUMBER ------- ----------- ------ 3.1 Certificate of Incorporation of Burlington Resources Inc. as amended November 18, 1999 (Exhibit 3.1 to Form 10-K, filed March 17, 2000)............................................. * 3.2 By-Laws of Burlington Resources Inc. amended as of December 6, 2000..................................................... * 4.1 Form of Shareholder Rights Agreement dated as of December 16, 1998, between Burlington Resources Inc. and Bank Boston, N.A. which includes, as Exhibit A thereto, the form of Certificate of Designation specifying terms of the Series A Junior Participating Preferred Stock and, as Exhibit B thereto, the form of Rights Certificate (Exhibit 1 to Form 8-A, filed December 1998)................................... * 4.2 Indenture, dated as of June 15, 1990, between Burlington Resources Inc. and Citibank, N.A. (as Trustee), including Form of Debt Securities (Exhibit 4.2 to Form 8, filed February 1992).............................................. * 4.3 Indenture, dated as of October 1, 1991, between Burlington Resources Inc. and Citibank, N.A. (as Trustee), including Form of Debt Securities (Exhibit 4.3 to Form 8, filed February 1992).............................................. * 4.4 Indenture, dated as of April 1, 1992, between Burlington Resources Inc. and Citibank, N.A. (as Trustee), including Form of Debt Securities (Exhibit 4.4 to Form 8, filed March 1993)....................................................... * 4.5 Indenture, dated as of June 15, 1992, between The Louisiana Land and Exploration Company ("LL&E") and Texas Commerce Bank National Association (as Trustee) (Exhibit 4.1 to LL&E's Form S-3, as amended, filed November 1993)........... * 4.6 Indenture, dated as of February 12, 2001, between Burlington Resources Finance Company and Citibank, N.A. (as Trustee), including form of Debt Securities (Exhibit 4.1 to Form 8-K, filed February 2001)........................................ * +10.1 The 1988 Burlington Resources Inc. Stock Option Incentive Plan as amended (Exhibit 10.4 to Form 8, filed March 1993)....................................................... * +10.2 Burlington Resources Inc. Incentive Compensation Plan as amended and restated (Exhibit 10.29 to Form 10-Q, filed November 2000).............................................. * Amendment to Burlington Resources Inc. Incentive Compensation Plan dated December 2000 (Exhibit 10.2 to Form 10-K, filed February 2001).................................. * +10.3 Burlington Resources Inc. Senior Executive Survivor Benefit Plan dated as of January 1, 1989 (Exhibit 10.11 to Form 8, filed February 1989)........................................ * +10.4 Burlington Resources Inc. Deferred Compensation Plan as amended and restated (Exhibit 10.4 to Form 10-K, filed February 1997).............................................. * +10.5 Burlington Resources Inc. Supplemental Benefits Plan as amended and restated (Exhibit 10.5 to Form 10-K, filed February 1997).............................................. * +10.6 Employment Contract between Burlington Resources Inc. and Bobby S. Shackouls (Exhibit 10.7 to Form 10-K, filed February 1996).............................................. * Amendment to Employment Contract between Burlington Resources Inc. and Bobby S. Shackouls, dated July 9, 1997 (Exhibit 10.6 to Form 10-K, filed February 1998)............ * Amendment to Employment Contract between the Company and Bobby S. Shackouls (Exhibit 10.29 to Form 10-Q, filed August 1999)....................................................... * +10.7 Burlington Resources Inc. Compensation Plan for Non-Employee Directors as amended and restated (Exhibit 10.8 to Form 10-K, filed February 1997).................................. * +10.8 Amended and Restated Burlington Resources Inc. Executive Change in Control Severance Plan, formerly known as the Key Executive Severance Protection Plan (Exhibit 10.8 to Form 10-K, filed February 2001).................................. * +10.9 Burlington Resources Inc. Retirement Income Plan for Directors (Exhibit 10.21 to Form 8, filed February 1991).... * +10.10 Burlington Resources Inc. 1991 Director Charitable Award Plan, dated as of January 16, 1991 (Exhibit 10.22 to Form 8, filed February 1991)........................................ * 10.11 Master Separation Agreement and documents related thereto dated January 15, 1992 by and among Burlington Resources Inc., El Paso Natural Gas Company and Meridian Oil Holding Inc., including exhibits (Exhibit 10.24 to Form 8, filed February 1992).............................................. *

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EXHIBIT PAGE NUMBER DESCRIPTION NUMBER ------- ----------- ------ +10.12 Burlington Resources Inc. 1992 Stock Option Plan for Non-employee Directors (Exhibit 28.1 of Form S-8, No. 33-46518, filed March 1992)................................. * +10.13 Burlington Resources Inc. Key Executive Retention Plan and Amendments No. 1 and 2 (Exhibit 10.20 to Form 8, filed March 1993)....................................................... * Amendments No. 3 and 4 to the Burlington Resources Inc. Key Executive Retention Plan (Exhibit 10.17 to Form 10-K, filed February 1994).............................................. * +10.14 Burlington Resources Inc. 1992 Performance Share Unit Plan as amended and restated (Exhibit 10.17 to Form 10-K, filed February 1997).............................................. * +10.15 Burlington Resources Inc. 1993 Stock Incentive Plan (Exhibit 10.22 to Form 10-K, filed February 1994).................... * Amendment to Burlington Resources Inc. 1993 Stock Incentive Plan dated April 2000 (Exhibit 10.15 to Form 10-K, filed February 2001).............................................. * Amendment to Burlington Resources 1993 Stock Incentive Plan dated December 2000 (Exhibit 10.2 to Form 10-K, filed February 2001).............................................. * +10.16 Burlington Resources Inc. 1994 Restricted Stock Exchange Plan (Exhibit 10.23 to Form 10-K, filed February 1995)...... * Amendment to Burlington Resources Inc. 1994 Restricted Stock Exchange Plan dated December 2000 (Exhibit 10.2 to Form 10-K, filed February 2001).................................. * +10.17 Burlington Resources Inc. 1997 Performance Share Unit Plan, (Exhibit 10.21 to Form 10-K, filed February 1997)........... * 10.18 $400 million Short-term Revolving Credit Agreement, dated as of February 25, 1998, as Amended and Restated December 7, 2001, between Burlington Resources Inc. and JPMorgan Chase Bank, as agent.............................................. 10.19 $600 million Long-term Revolving Credit Agreement, dated as of February 25, 1998, as Amended and Restated December 7, 2001, between Burlington Resources Inc. and JPMorgan Chase Bank, as agent.............................................. +10.20 Form of Termination Agreement with Certain Senior Management Personnel as amended (Exhibit 10(a)(i) to LL&E's Form 10-K, filed March 1996)........................................... * +10.21 Form of The Louisiana Land and Exploration Company Deferred Compensation Arrangement for Selected Key Employees (Exhibit 10(g) to LL&E's Form 10-K, filed March 1991)................ * Amendment to the LL&E Deferred Compensation Arrangement for Selected Key Employees dated December 21, 1998 (Exhibit 10.26 to Form 10-K, filed February 1999).................... * +10.22 The LL&E Supplemental Excess Plan (Exhibit 10(j) to LL&E's Form 10-K, filed March 1993)................................................. * +10.23 Severance benefit agreement between Burlington Resources Inc. and John A. Williams, dated March 25, 1999 (Exhibit 10.28 to Form 10-Q, filed May 1999)......................... * +10.24 Form of agreement on pension related benefits with certain former Seattle holding company office employees (Exhibit 10.26 to Form 10-K, filed March 17, 2000)................... * +10.25 Poco Petroleums Ltd. Incentive Stock Option Plan (Form S-8 No. 333-91247, filed November 18, 1999)..................... * +10.26 Employee Savings Plan for Eligible Employees of Poco Petroleums Ltd. (Exhibit 4.4 to Form S-8 No. 333-95071, filed January 20, 2000)..................................... * +10.27 Burlington Resources Inc. Phantom Stock Plan for Non-Employee Directors (Exhibit 10.12 to Form 10-K, filed February 1996).............................................. * First Amendment to the Burlington Resources Inc. Phantom Stock Plan for Non-Employee Directors (Exhibit 10.29 to Form 10-Q, filed May 2000)....................................... * +10.28 Burlington Resources Inc. 2000 Stock Option Plan for Non-Employee Directors (Exhibit 10.30 to Form 10-Q, filed August 2000)................................................ * +10.29 Letter agreement regarding Steven J. Shapiro dated October 18, 2000 (Exhibit 10.29 to Form 10-K, filed February 2001)....................................................... * +10.30 Burlington Resources Inc. 2001 Performance Share Unit Plan (Exhibit 10.30 to Form 10-K, filed February 2001)........... * 10.31 Pre-Acquisition Agreement between Burlington Resources Inc. and Canadian Hunter Exploration Ltd. dated October 8, 2001 (Exhibit 99.2 to Form 8-K, filed October 2001).............. *

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EXHIBIT PAGE NUMBER DESCRIPTION NUMBER ------- ----------- ------ 10.32 Canadian Credit Agreement, dated as of March 31, 2000, as Amended and Restated December 7, 2001, among Burlington Resources Canada Ltd., Burlington Resources Inc. and J.P. Morgan Bank Canada, as agent................................ 10.33 $350 million Bridge Revolving Credit Agreement, dated as of January 2, 2002, between Burlington Resources Inc. and JPMorgan Chase Bank, as agent............................... 21.1 Subsidiaries of the Registrant.............................. 23.1 Consent of Independent Accountants -- PricewaterhouseCoopers LLP......................................................... 23.2 Consent of Independent Accountants -- KPMG.................. 23.3 Consent of Independent Accountants -- Ernst & Young LLP..... 99.1 Audit Opinion of KPMG....................................... 99.2 Audit Opinion of Ernst & Young LLP.......................... 99.3 Audited Consolidated Financial Statements of Canadian Hunter Exploration Ltd. for the year ended December 31, 2000....... 99.4 Unaudited Consolidated Financial Statements of Canadian Hunter Exploration Ltd. for the nine month period ended September 30, 2001.......................................... 99.5 Burlington Resources Inc. Pro Forma Income Statements for the nine months ended September 30, 2001 and the year ended December 31, 2000...........................................

*Exhibit incorporated herein by reference as indicated. +Exhibit constitutes a management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K. A-3