10-K405 1 h82500e10-k405.txt BURLINGTON RESOURCES INC. - DATED 12/31/2000 1 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 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, 2000 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. [X] 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, 2001: $9,135,733,279 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, 2001, Shares Outstanding: 215,974,782 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. -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 2 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 NGLs Natural Gas Liquids DD&A Depreciation, Depletion and Amortization Shallow Waters of the Outer Continental Shelf in the Gulf of Shelf Mexico Deepwater Water Depths of 1,000 Feet or Greater in the Gulf of Mexico

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. 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 is converted into cubic feet of gas equivalent based on 6 MCF of gas to one barrel of oil. 3 BURLINGTON RESOURCES INC. TABLE OF CONTENTS

PAGE PART I Items One and Two Business and Properties................................ 1 Employees.............................................. 12 Item Three Legal Proceedings...................................... 12 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................................ 14 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........................................... 22 Item Nine Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................... 50 PART III Items Ten and Eleven Directors and Executive Officers of the Registrant and Executive Compensation................................ 50 Item Twelve Security Ownership of Certain Beneficial Owners and Management............................................ 50 Item Thirteen Certain Relationships and Related Transactions......... 50 PART IV Item Fourteen Exhibits, Financial Statement Schedules and Reports on Form 8-K.............................................. 51

4 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"), and Burlington Resources Canada Energy Ltd. (formerly known as Poco Petroleums Ltd.), and their affiliated companies (collectively the "Company"), in the exploration for and the development of and production and marketing of crude oil and natural gas. The Company is one of the largest holders of natural gas reserves and one of the largest producers of oil and gas in North America. In 1998, BR formed two separate business units, Burlington Resources North America ("BRNA") and Burlington Resources International ("BRI"). BRNA was formed as a separate business unit to reinforce the value creation potential of the Company's high quality North America assets and BRI was formed to affirm BR's commitment to a global presence as a key element of its long-term growth strategy. In November 1999, BR consummated the acquisition of Poco Petroleums Ltd., a corporation existing under the laws of the Province of Alberta, Canada (the "Acquisition"). The Acquisition was 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 as poolings of interests. The Company's operations are conducted through the two business units previously mentioned. Following is a review of the business units and a discussion of the major areas of activity within each business unit. BURLINGTON RESOURCES NORTH AMERICA The Company's asset base is dominated by North American natural gas properties. Its extensive North American lease holdings extend from the Gulf of Mexico to Canada's Mackenzie Delta region in the Northwest Territories of the Canadian Arctic. Reflecting a diverse yet balanced portfolio, The Company's North American operations include a mix of production, exploitation and exploration opportunities. In 2000, oil and gas capital expenditures for North American operations totaled $728 million, and consisted of $268 million for exploration, $440 million for development projects and $20 million for proved reserve acquisitions. The Company's North American production in 2000 represented 93 percent of the Company's total or 1,838 MMCF of gas per day and 68.6 MBbls of oil per day. At December 31, 2000, North American proved reserves totaled 9.1 TCFE and represented 88 percent of the Company's total. San Juan Basin The San Juan Basin ("San Juan") is the most prolific operating area of the Company 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 1 million net acres under its control. The Company operates over 6,500 wells in San Juan and holds interests in an additional 3,900 non-operated wells. The Company also operates the Val Verde gathering and processing system, consisting of one of San Juan's largest treating plants and approximately 420 miles of gathering lines with 14 compressor stations. In 2000, the Company invested $127 million in oil and gas capital that included investments for over 200 new wells and approximately 600 mechanical workovers. Over 140 of the new wells and 500 of the workovers were Company operated. Net production from the Company's interest in San Juan averaged approximately 845 MMCF of gas per day and 1.4 MBbls of oil per day in 2000. Prior to 1998, a majority of the Company's growth in San Juan 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 forma- 1 5 tions 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 2000, the Company continued its aggressive infill drilling program in San Juan's Mesaverde formation developing an additional 95 BCFE of reserves. In the last 3 years, the Company has added over 400 BCFE in the Mesaverde formation and developed just under one half of these reserves. In San Juan's Dakota formation, the Company continued to test new areas for opportunities, principally by deepening proposed Mesaverde wells to the Dakota during 2000. This approach improves the economics of testing the Dakota by reducing the cost as compared to drilling a stand alone well. It also allows strategic testing of geological and petrophysical assumptions across a wide geographic area which maximizes follow-up potential for 2001 and beyond. 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 lift, where appropriate, to mitigate production decline. In 2000, net production from the Fruitland Coal averaged 376 MMCF of gas per day from approximately 1,500 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 2001, 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 Dakota formation, a Pictured Cliffs extension pilot, and drilling Fruitland Coal opportunities outside of the prolific fairway. Western Canadian Sedimentary Basin In the Western Canadian Sedimentary Basin ("Canadian Sedimentary Basin"), the Company explores for and exploits, and produces oil and gas. The majority of the exploitation efforts are in central Alberta along a 300-mile trend that runs northwest from Calgary. The exploration program is focused within the Foothills/Monkman, Devonian, and Hamburg areas of western Alberta. The Company's Canadian program is pursued through its portfolio of opportunities ranging from frontier exploration in the MacKenzie Delta to exploitation efforts in the Whitecourt and O'Chiese areas. In 2000, the Company invested $316 million of oil and gas capital in its Canadian operating areas. Of this amount, approximately 53% was focused on development programs with the remaining 47% devoted to exploration opportunities. Operational activity resulted in drilling over 230 wells and conducting over 80 workovers. Net production averaged 397 MMCF of gas per day and 17 MBbls of oil per day in 2000. During 2000, exploitation efforts were primarily concentrated within the Whitecourt/Wolf and O'Chiese areas. These areas have multiple producing horizons ranging in depth from 4,100 feet to 10,500 feet. Net production averaged 207 MMCF of gas per day and 4.5 MBbl of oil per day in 2000. The Company invested $136 million in these areas in 2000. Additional exploitation efforts were focused in southeastern Saskatchewan and eastern Alberta. This program consisted of shallow gas infill drilling. Also in this area, the Company is a partner in a tertiary recovery project that currently produces 4.2 MBbl of oil per day net. Total investment in this area for the year 2000 was $51 million. Net production from this area averaged 74 MMCF of gas per day and 10.6 MBbls of oil per day in 2000. The Company's higher potential exploration gas plays are located in the Foothills/Monkman and deep Devonian areas. The use of 2-D and 3-D seismic technology has allowed the Company to pursue the deeper Devonian formations. In 2000, the Company invested total capital of $113 million in this area and drilled a total of 17 wells. Net production for this area averaged 89 MMCF of gas per day in 2000. The northern gas region, located near Hamburg, is an exploration play that is currently utilizing 3-D seismic technology to maximize returns. In 2000, the Company invested $18 million in this area, drilling six wells at a 67% success rate. 2 6 Beaufort Basin The Beaufort Basin, located in the MacKenzie Delta of the Northwest Territories, is the Company's frontier exploration play in Canada. The Company currently controls over 420,000 net acres possessing hydrocarbon potential. In 2000, the Company acquired seismic information and formed a partnership with BP Amoco and Chevron. This group will jointly pursue future exploration with plans to drill an initial exploration well during the 2001/2002 winter drilling season. Wind River Basin The Madden Field, located in the Wind River Basin ("Wind River"), covers more than 70,000 acres in Freemont and Natrona Counties, Wyoming. Production in this basin occurs from multiple horizons ranging in depth from 5,000 feet to over 25,000 feet. Company gas production is divided between the deep Madison formation, representing 60%, and shallower formations representing 40%. In the deep Madison formation during 2000, the Company completed and delivered the Big Horn #5-6 at rates in excess of 40 MMCF of gas per day, drilled and logged the Big Horn #6-27 wildcat to a total depth of 25,855 feet, and commenced 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. Construction of Lost Cabin Gas Plant Train III should be complete by 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. The Company owns a 49 percent working interest in the plant. In Wind River, the Company invested $30 million on over 40 drilling and workover projects in the deep Madison and shallower formations. The Company also invested $51 million on plant construction in 2000. Net production for Wind River averaged 82 MMCF of gas per day in 2000. The Company is a partner in the recently constructed and commissioned Lost Creek Pipeline, a 124 mile, 24-inch gathering pipeline in the Wind River. This project has mitigated gas transportation issues related to pipeline capacity constraints and is currently flowing about 90 MMCF of gas per day out of the Madden Field area to major interstate pipelines near Wamsutter, Wyoming. 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 16 MBbls of oil per day in 2000. Activities in Williston have been focused on the Cedar Creek Anticline, particularly on the operated East Lookout Butte Unit and Cedar Hills Field. Production from the Cedar Creek Anticline was 9.7 MBbls of oil per day. The Company completed horizontal waterflood development during 2000 at the East Lookout Butte Unit. The Company should initiate similar waterflood development in 2001 at the Cedar Hills Field. In 2000, the Company invested $13 million on drilling and workover projects in Williston. 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 Anadarko. Anadarko horizons range in depth from less than 1,000 feet to over 26,000 feet. The Company controls over 250,000 net acres principally located in western Oklahoma. Net production for Anadarko averaged 107 MMCF of gas per day in 2000. The Company invested $13 million in 2000 in Anadarko. Permian Basin In 2000, in the Permian Basin ("Permian"), operations were focused primarily on the Waddell Ranch. Net production for the Company in Permian averaged 64 MMCF of gas per day and 9.1 MBbls of oil per day in 2000. The Company controls 40,000 net acres at this property, providing oil and gas from multiple formations. The Company spent $19 million in Permian in 2000. Additionally, the Company traded Permian properties with reserves of 39 BCFE for Anadarko properties with reserves of 45 BCFE. The Company's gas 3 7 production increased by 2 MMCF per day and oil production decreased by 1.4 MBbls per day as a result of the trade. The Anadarko properties provide an excellent fit to the existing core Anadarko properties. 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 2000 averaged over 150 MMCF of gas per day and 8 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 $39 million of oil and gas capital to participate in a total of 43 projects in 2000. Successful exploitation activities included continued development of the 1998 Lafitte Field discovery in Jefferson parish. During 2000, four wells were drilled in the Lafitte Field, increasing net production to 12 MMCF of gas per day and 1.4 MBbls of oil per day. Development operations also continued at the Pass Des Illettes Field and the non-operated Calliou Island Field. In south and east Texas, the focus in 2000 was growing key assets through exploitation while exploring high risk, high reward opportunities. The Company invested $38 million of oil and gas capital on 15 projects. Key projects are ongoing at the Armstrong Ranch in Jim Hogg County where, over the past two years, the Company has drilled a total of nine wells and increased net production to 27 MMCF of gas per day. This play is still expanding with at least two additional wells to be drilled in 2001. 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. The Company owns over 460,000 net leasehold acres in the trend. Oil and gas capital funding for the Shelf has been reduced from annual levels of over $200 million in 1998 to levels below $50 million in 1999 and 2000. This reduced level of funding has resulted in a rapid decline in production. Net production averaged over 150 MMCF of gas per day and 6.3 MBbls of oil per day in 2000. Activity in 2000 was focused on low risk, high return development projects at South Timbalier 190/203, Vermillion 84 and Green Canyon 18. During 2000, the Company participated in a total of 60 projects. The Company also reduced its operating cost through a property management agreement completed with a third party contractor to manage daily production operations for the Company-operated properties on the Shelf. Deepwater Gulf of Mexico Deepwater Gulf of Mexico ("Deepwater") remains a key high potential, high risk exploration area for the Company. The Company's exploration strategy for Deepwater focuses on exploring the opportunities identified on Company-owned leases, supplemented by key third party generated prospects. The Company owns 275,000 net acres in the deepwater provinces of the Gulf of Mexico. Production for 2000 was from the non-operated Pluto project that was completed in late 1999. Net production averaged 22 MMCF of gas per day and 4.6 MBbls of oil per day in 2000. The Company invested $62 million in Deepwater in 2000. BURLINGTON RESOURCES INTERNATIONAL 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 2000, oil and gas capital expenditures for International operations totaled $179 million and consisted of $70 million for exploration, $80 million for development projects and $29 million related to proved reserve acquisitions. BR International's production in 2000 represented seven percent of the Company's total or 122 MMCF of gas per day and 9.6 MBbls of oil per day. At December 31, 2000, International's proved reserves totaled 1.2 TCFE and represented 12 percent of the Company's total. 4 8 Northwest European Shelf Development operations are currently focused in the Northwest European Shelf, which provides the majority of production outside of North America and includes assets in the East Irish Sea and 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 90 percent working interest in seven operated gas fields. First production from the two sweet gas fields at Dalton and east Millom occurred in the third quarter of 1999. The second phase, development of the sweet gas at west Millom, began in 2000 and, at year end, two of five planned wells had been completed and were producing. Development options for five additional sour gas fields in the area are under evaluation at this time. 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 of the North Sea. North Africa The Company's North African operations are concentrated in Algeria and offshore Egypt. Development operations are underway primarily in Algeria with first production in Algeria expected in 2002. The Company invested $45 million in Algeria in 2000. In the Berkine Basin in Algeria on the Menzel Lejmat Block 405, the Company is the operator and holds a 65 percent working interest. A total of 25 wells have been drilled, eight of which were wildcat exploration wells. The Company has made at least five separate field discoveries on the block -- MLN, MLC, MLNW, MLW and MLSE, and has a portion of the giant Ourhoud Field in the northeast portion of the block. Ourhoud is currently under development by Sonatrach, the Algerian national oil company. During 2000, the Company moved into a new phase of operations with governmental approval of the first phase of development at the MLN Field and the granting of an Exploitation License Agreement ("ELA"). In 2001, development will be fully underway at MLN. Additional ELA's will be filed on the remaining discoveries in the future. Latin America Building on existing assets and extracting value from ongoing operations were the focus for Company assets in Latin America during 2000. Ongoing exploration and production activities in 2000 included work in Peru, Ecuador, Colombia, Venezuela and Suriname. The Company's continued focus in Latin America has provided the opportunity to leverage off of its growing knowledge and resource base in the sub-Andean plays. Net production from the Casanare Association contract in Colombia continues to provide a steady production rate of 1.6 MBbls of oil per day for the Company. The Company participated in drilling two development wells in this area in 2000 with four additional development wells to be drilled in 2001. In Peru, exploration efforts on Block 32 are continuing toward the commencement of drilling the Guineayacu 1-X well. The Company holds a 58% interest in the block. Also in Peru, the Company has farmed into Block 87 for an 85% interest where a 200 kilometer ("km") 2-D seismic program is planned to begin in 2001. In Venezuela, the Company and its joint venture partners agreed to minimize additional capital exposure in the Delta Centro Association Agreement through early termination and payment of its approximately $9 million obligation under the agreement. The Company held a 35% interest and operatorship of the block. Far East The Company's focus in the Far East is to grow selected basins into core producing areas. The Company is targeting oil exploration and acquisition opportunities in offshore China to add to its existing leasehold position. In 2000, the Company signed an agreement for a 100% working interest on exploration Block C/A 16/21 (2,241 square km) in the Pearl River Mouth Basin of the South China Sea. Exploration 3-D seismic covering 5 9 897 square km was acquired in 1999. The exploration block is on trend with existing production. One exploration well is planned for 2001. During 2000, the Company opened a field office in Shekou, China. The Company acquired two additional licenses in the Pearl River Mouth Basin of the South China Sea. Block 15/34 is a 50 percent owned non-operated block with discovered fields, Bootes and Ursa. Block 26/06 is a Company-operated exploration block with a 50 percent working interest. These assets were acquired for $29 million and contain proved reserves of 15 MMBbls of oil. West Africa In West Africa, the Company is seeking to build its exploration inventory and geological knowledge base by participating, as a non-operator, in high potential exploration projects with experienced operators in West Africa. In order to expose the Company to shorter cycle times, blocks and licenses that are mature in the exploration phase are being targeted. In 2000, the Company entered into an agreement with AGIP Gabon S.A. to earn a 25% interest in the M'Polo, Chaillu and Meboun exploration and production sharing contracts. The three contiguous AGIP-operated blocks cover 5.3 million acres in offshore Gabon. Eighteen thousand km of 2-D seismic have been shot over the blocks and the partnership is currently evaluating a 3,100 square km 3-D seismic survey shot in early 2000. The production sharing contracts require a total of six wells to be drilled by mid-year 2003; two of those wells are planned to be drilled in the second half of 2001. 6 10 RESERVES The following table sets forth estimates by the Company's petroleum engineers of proved oil and gas reserves at December 31, 2000. These reserves have been reduced for royalty interests owned by others.

DECEMBER 31, 2000 ---------------------------------------- PROVED PROVED TOTAL PROVED DEVELOPED UNDEVELOPED RESERVES --------- ----------- ------------ NORTH AMERICA USA Gas (BCF)........................................... 4,779 1,201 5,980 Oil (MMBbls)........................................ 169.7 34.5 204.2 Total USA (BCFE)............................... 5,797 1,408 7,205 Canada Gas (BCF)........................................... 1,180 282 1,462 Oil (MMBbls)........................................ 54.8 18.4 73.2 Total Canada (BCFE)............................ 1,509 392 1,901 INTERNATIONAL Gas (BCF)........................................... 274 521 795 Oil (MMBbls)........................................ 10.4 59.6 70.0 Total International (BCFE)..................... 336 879 1,215 WORLDWIDE Gas (BCF)........................................... 6,233 2,004 8,237 Oil (MMBbls)........................................ 234.9 112.5 347.4 Total Worldwide (BCFE)......................... 7,642 2,679 10,321

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." CAPITAL EXPENDITURES Following are the Company's capital expenditures.

YEAR ENDED DECEMBER 31, ------------------------ 2000 1999 1998 ------ ---- ------ ($ MILLIONS) NORTH AMERICA USA Oil and Gas Activities................................. $ 412 $488 $ 921 Plants & Pipelines..................................... 56 14 60 Administration......................................... 19 38 45 ------ ---- ------ Total USA......................................... 487 540 1,026 ------ ---- ------ Canada Oil and Gas Activities................................. 316 291 671 Plants & Pipelines..................................... 20 4 1 Administration......................................... 4 4 2 ------ ---- ------ Total Canada...................................... 340 299 674 ------ ---- ------ INTERNATIONAL Oil and Gas Activities................................. 179 148 136 Administration......................................... 6 2 3 ------ ---- ------ Total International............................... 185 150 139 ------ ---- ------ WORLDWIDE Oil and Gas Activities................................. 907 927 1,728 Plants & Pipelines..................................... 76 18 61 Administration......................................... 29 44 50 ------ ---- ------ Total Worldwide................................... $1,012 $989 $1,839 ====== ==== ======

7 11 Capital expenditures for oil and gas activities in 2000 of $907 million include 57 percent for development, 37 percent for exploration and 6 percent for proved property acquisitions. Included in capital expenditures for oil and gas activities are exploration costs expensed under the successful efforts method of accounting. NET WELLS DRILLED Drilling activity in 2000 was principally in the Western Canadian Sedimentary, San Juan, Gulf Coast, Permian, Anadarko and Williston Basins. The following table sets forth the Company's net productive and dry wells.

YEAR ENDED DECEMBER 31, ----------------------- 2000 1999 1998 ----- ----- ----- NORTH AMERICA USA Productive Exploratory.......................................... 1.2 9.3 16.3 Development.......................................... 159.6 183.1 297.7 Dry Exploratory.......................................... 3.9 9.4 27.5 Development.......................................... 5.2 4.4 12.5 ----- ----- ----- Total Net Wells -- USA............................ 169.9 206.2 354.0 ----- ----- ----- Canada Productive Exploratory.......................................... 56.5 67.4 71.2 Development.......................................... 73.4 30.6 72.2 Dry Exploratory.......................................... 44.1 3.6 7.3 Development.......................................... 17.0 4.2 8.4 ----- ----- ----- Total Net Wells -- Canada......................... 191.0 105.8 159.1 ----- ----- ----- INTERNATIONAL Productive Exploratory.......................................... 3.2 2.1 3.5 Development.......................................... 2.4 3.2 1.8 Dry Exploratory.......................................... 2.1 2.0 2.0 Development.......................................... .1 -- -- ----- ----- ----- Total Net Wells -- International.................. 7.8 7.3 7.3 ----- ----- ----- WORLDWIDE Productive Exploratory.......................................... 60.9 78.8 91.0 Development.......................................... 235.4 216.9 371.7 Dry Exploratory.......................................... 50.1 15.0 36.8 Development.......................................... 22.3 8.6 20.9 ----- ----- ----- Total Net Wells -- Worldwide...................... 368.7 319.3 520.4 ===== ===== =====

As of December 31, 2000, 34 gross wells, representing approximately 23 net wells, were being drilled. 8 12 PRODUCTIVE WELLS Working interests in productive wells at December 31, 2000 follow.

GROSS NET ------ ----- NORTH AMERICA USA Oil.................................................... 5,432 2,917 Gas.................................................... 11,223 6,684 Canada Oil.................................................... 1,977 1,406 Gas.................................................... 2,899 2,037 INTERNATIONAL Oil.................................................... 140 24 Gas.................................................... 100 12 WORLDWIDE Oil.................................................... 7,549 4,347 Gas.................................................... 14,222 8,733

ACREAGE Working interests in developed and undeveloped acreage at December 31, 2000 follow.

GROSS NET ---------- ---------- NORTH AMERICA USA Developed Acres........................................ 5,534,021 2,989,904 Undeveloped Acres...................................... 10,981,058 8,856,187 Canada Developed Acres........................................ 1,778,434 1,140,539 Undeveloped Acres...................................... 4,247,108 2,427,922 INTERNATIONAL Developed Acres........................................ 155,357 26,520 Undeveloped Acres...................................... 39,078,842 17,028,302 WORLDWIDE Developed Acres........................................ 7,467,812 4,156,963 Undeveloped Acres...................................... 54,307,008 28,312,411

9 13 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. The Company's average natural gas price includes amounts from sale of NGLs, less the actual costs incurred to gather, treat and process the hydrocarbons. Following are the Company's production and prices.

YEAR ENDED DECEMBER 31, -------------------------- 2000 1999 1998 ------ ------ ------ NORTH AMERICA USA Production Gas (MMCF per day)................................... 1,441 1,487 1,580 Oil (MBbls per day).................................. 51.6 57.3 66.2 Average Sales Price Gas (per MCF)........................................ $ 3.25 $ 2.49 $ 2.19 Oil (per Bbl)........................................ $24.18 $16.70 $13.34 Canada Production Gas (MMCF per day)................................... 397 429 430 Oil (MBbls per day).................................. 17.0 19.4 21.8 Average Sales Price Gas (per MCF)........................................ $ 3.96 $ 1.76 $ 2.12 Oil (per Bbl)........................................ $27.80 $18.36 $12.44 INTERNATIONAL Production Gas (MMCF per day)................................... 122 88 67 Oil (MBbls per day).................................. 9.6 13.2 16.5 Average Sales Price Gas (per MCF)........................................ $ 2.16 $ 1.93 $ 2.56 Oil (per Bbl)........................................ $27.73 $17.00 $13.16 WORLDWIDE Production Gas (MMCF per day)................................... 1,960 2,004 2,077 Oil (MBbls per day).................................. 78.2 89.9 104.5 Average Sales Price Gas (per MCF)........................................ $ 3.32 $ 2.33 $ 2.19 Oil (per Bbl)........................................ $25.40 $17.12 $13.13

10 14 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, ------------------------ 2000 1999 1998 ----- ----- ------ (PER MCFE) NORTH AMERICA USA Average Production Costs............................... $.58 $.52 $ .48 DD&A Rates............................................. .76 .65 .59 Canada Average Production Costs............................... .67 .51 .44 DD&A Rates............................................. .65 .54 .77 INTERNATIONAL Average Production Costs............................... .31 .54 .71 DD&A Rates............................................. .82 .88 1.06 WORLDWIDE Average Production Costs............................... .58 .52 .48 DD&A Rates............................................. $.74 $.64 $.66]

For additional financial information about segments and geographic areas, see Note 12 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, subject to court review, allowing interstate pipeline companies to negotiate their rates with individual shippers. The FERC is also considering allowing the interstate pipeline companies to negotiate tariffed terms and conditions of service. The Company will monitor the effects of these programs on its marketing efforts but does not expect that these actions will have a material adverse effect on the consolidated financial position or results of operations 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 11 15 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 administered 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 operations or financial condition. Filings of Reserve Estimates With Other Agencies. During 2000, the Company filed estimates of oil and gas reserves for the year 1999 with the Department of Energy. These estimates differ by 5 percent or less from the reserve data presented. For information concerning proved oil and gas reserves, see page 47. EMPLOYEES The Company had 1,783 and 1,997 employees at December 31, 2000 and 1999, respectively. Currently, the Company has 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") 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 oil and 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 12 16 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 and numerous other oil and gas companies have also been named as defendants in a lawsuit styled as United States of America ex rel. J. Benjamin Johnson, Jr., et al. v. Shell Oil Company, et al. in the United States District Court for the Eastern District of Texas alleging violations of the civil False Claims Act with respect to the valuation of oil. This suit alleges that the Company underpaid royalties for crude oil produced on federal and Indian lands. The Company has entered into an agreement to pay $8.5 million, plus attorneys fees, in settlement of all claims against it. The District Court has entered an order approving the settlement and dismissing the case against the Company. 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. 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. 13 17 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." The exchangeable shares, issued by the Company's subsidiary, Burlington Resources Canada Inc., in connection with the November 1999 acquisition of Poco Petroleums Ltd., are traded on The Toronto Stock Exchange in Canada under the symbol "BRX." At December 31, 2000, the number of holders of Common Stock was 17,856 and the number of holders of the exchangeable shares was 113. Information on Common Stock prices and quarterly dividends is shown on page 49. ITEM SIX SELECTED FINANCIAL DATA The selected financial data for the Company set forth below for the five years ended December 31, 2000 should be read in conjunction with the consolidated financial statements. The financial data include the effect of the implementation of Emerging Issues Task Force Issue No. 00-10 ("EITF No. 00-10"). See Other Matters on page 19.

2000 1999 1998 1997 1996 ------ ------ ------ ------ ------ (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) INCOME STATEMENT DATA Revenues........................................ $3,147 $2,313 $2,225 $2,575 $2,647 Operating Income (Loss)......................... 1,191 200 (439) 605 643 Net Income (Loss)............................... 675 (10) (338) 352 354 Basic Earnings (Loss) per Common Share.......... 3.13 (.05) (1.60) 1.69 1.72 Diluted Earnings (Loss) per Common Share........ 3.12 (.05) (1.60) 1.67 1.70 Cash Dividends Declared per Common Share........ $ .55 $ .46 $ .46 $ .39 $ .37 BALANCE SHEET DATA Total Assets.................................... $7,506 $7,165 $7,060 $7,164 $6,790 Long-term Debt.................................. 2,301 2,769 2,684 2,317 2,223 Stockholders' Equity............................ $3,750 $3,229 $3,312 $3,561 $3,331 Common Shares Outstanding....................... 216 216 216 209 209

14 18 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 total debt to total capital ratio at December 31, 2000 and December 31, 1999 was 38 percent and 47 percent, respectively. During 2000, the Company repaid $183 million of fixed-rate debt and $381 million of bank-funded floating rate debt. The Company also had net commercial paper issuances of $70 million during 2000. Commercial paper outstanding at December 31, 2000 was $327 million. In December 2000, the Company's Board of Directors authorized the Company to expend up to $500 million to redeem or repurchase long-term debt securities of the Company. The Company had unused credit commitments in the form of revolving credit facilities ("revolvers") as of December 31, 2000. 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. The revolvers are comprised of agreements for $600 million, $400 million and $332 million. The $600 million revolver expires in February 2003 and the $400 million and $332 million revolvers expire in March 2001 unless renewed by mutual consent. The Company has the option to convert the outstanding balances on the $400 million and $332 million revolvers to one year term notes at expiration of the agreements. In addition, the Company has a $1 billion shelf registration statement on file with the Securities and Exchange Commission. On February 12, 2001, the Company issued $400 million of fixed-rate debt with an interest rate of 6.68 percent due February 2011. This issuance reduces the Company's amount available under its shelf registration statement to $600 million. The net proceeds are expected to be used by a Canadian subsidiary for general corporate purposes, including the repayment of commercial paper and a pending property acquisition. In July 1998, the Company's Board of Directors approved the repurchase of two million shares of its Common Stock. During the first six months of 2000, the Company completed the 1998 program by repurchasing 1,315,000 shares of its Common Stock for $39 million. In May 2000, the Company's Board of Directors approved the repurchase of two million additional shares of its Common Stock. In 2000, the Company repurchased two million shares of its Common Stock under this authorization for $77 million. In December 2000, the Company's Board of Directors authorized the repurchase of up to $1 billion of the Company's Common Stock. During December 2000, the Company repurchased 190,000 shares of its Common Stock for $9 million under its latest authorization. In aggregate, during 2000, the Company repurchased 3,505,000 shares of its Common Stock for $125 million. Net cash provided by operating activities in 2000 was $1,598 million compared to $1,102 million in 1999. The increase was primarily due to higher operating income partially offset by working capital and other changes. Operating income was higher principally as a result of higher commodity prices. The Company and its subsidiaries are named defendants in numerous lawsuits and named parties in numerous governmental and other proceedings arising in the ordinary course of business. While the outcome of lawsuits and other proceedings cannot be predicted with certainty, management believes these matters will not have a material adverse effect on the consolidated financial position of the Company, although results of operations and cash flows could be significantly impacted in the reporting periods in which such matters are resolved. 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. 15 19 CAPITAL EXPENDITURES AND RESOURCES Capital expenditures for 2000 totaled $1,012 million compared to $989 million and $1,839 million in 1999 and 1998, respectively. The Company invested $858 million on internal development and exploration of oil and gas properties during 2000 compared to $792 million and $1,291 million in 1999 and 1998, respectively. The Company invested $49 million for property acquisitions in 2000 compared to $135 million and $437 million in 1999 and 1998, respectively. MARKETING North America 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. International The Company's 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 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." 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. At December 31, 2000, 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 increase in the net unrealized amount. 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. 16 20 FOREIGN CURRENCY RISK The Company's reported cash flows related to Canadian operations is based on cash flows measured in Canadian dollars 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 subsidiary has financial obligations that are denominated in U.S. dollars. A decrease in value of 10 percent in Canadian dollars relative to the U.S. dollar from the year-end exchange rate would result in a foreign currency loss of $17 million based on December 31, 2000 amounts. DIVIDENDS On January 17, 2001, the Board of Directors declared a common stock quarterly cash dividend of $.1375 per share, payable April 2, 2001 to shareholders of record on March 9, 2001. 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 $119 million during 2000. RESULTS OF OPERATIONS 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. 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. 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 ($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 were $3,147 million in 2000 compared to $2,313 million in 1999. Average gas prices, including the $.40 loss per MCF related to hedging activities, increased 42 percent to $3.32 per MCF and average oil prices, including the $2.46 loss per barrel related to hedging activities, increased 48 percent to $25.40 per barrel in 2000 resulting in increased revenues of $713 million and $237 million, respectively. Oil sales volumes decreased 13 percent in 2000 to 78.2 MBbls per day and gas sales volumes decreased two percent to 1,960 MMCF per day which decreased revenues $72 million and $33 million, respectively. 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 production taxes and a $11 million increase in exploration costs partially offset by a $8 million decrease in transportation expenses. DD&A increased primarily due to a higher unit rate resulting from a change in production mix. Production 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 geological and geophysical ("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. 17 21 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 changes in foreign currency exchange rates 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 as 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 of $50 million and an adjustment of prior period tax accruals of $45 million. Year Ended December 31, 1999 Compared With Year Ended December 31, 1998 The Company reported a net loss of $10 million or $.05 diluted loss per common share in 1999 compared to a net loss of $338 million or $1.60 diluted loss per common share in 1998. The 1999 and 1998 results included non-cash after tax charges of $140 million or $.65 per share and $390 million or $1.85 per share, respectively, related to the impairment of oil and gas properties. 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. 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 ($140 million after tax) related to those properties. In the fourth quarter of 1998, the market experienced a weakness in commodity prices. The Company subjected all properties to impairment testing and subsequently recognized a pretax impairment charge related to certain Canadian properties of $706 million ($390 million after tax). The 1999 results also included a $26 million after tax charge or $.12 per share related to severance and transaction costs associated with the Acquisition. Revenues were $2,313 million in 1999 compared to $2,225 million in 1998. Average oil prices, including the $.19 loss per barrel related to hedging activities, increased 30 percent to $17.12 per barrel in 1999 and average gas prices, including the $.05 gain per MCF related to hedging activities, increased 6 percent to $2.33 per MCF which increased revenues $131 million and $102 million, respectively. Oil sales volumes decreased 14 percent in 1999 to 89.9 MBbls per day and gas sales volumes decreased 4 percent to 2,004 MMCF per day which decreased revenues $70 million and $58 million, respectively. Oil sales volumes decreased primarily due to natural production declines in the Gulf Coast, Mid-Continent and North Sea areas. Costs and Expenses were $2,113 million in 1999 compared to $2,664 million in 1998. Costs and expenses in 1999 and 1998 included a $225 million and a $706 million charge, respectively, related to the impairment of oil and gas properties. Costs and expenses in 1999 also included a charge of $37 million related to severance and transaction costs associated with the Acquisition. Excluding the $262 million of charges in 1999 and the $706 million charge in 1998, costs and expenses in 1999 decreased $107 million compared to 1998. The decrease was primarily due to a $111 million decrease in exploration costs and a $48 million decrease in DD&A partially offset by a $29 million increase in transportation expenses and a $20 million increase in production taxes. Exploration costs decreased primarily due to lower exploratory spending resulting in lower G&G expenses of $58 million and lower exploratory dry hole expense of $69 million partially offset by higher impairment expense of $13 million. DD&A decreased due to lower production volumes and a lower unit rate resulting in reduced expenses of $38 million and $16 million, respectively, partially offset by higher fixed-rate expense of $6 million. Transportation expenses increased primarily due to tariff increases and production taxes were higher primarily due to higher oil and gas revenues. Interest Expense was $211 million in 1999 compared to $193 million in 1998. The increase was primarily due to higher outstanding fixed-rate debt and higher outstanding commercial paper borrowings during 1999. 18 22 Other Expense (Income) -- Net was an expense of $2 million in 1999 compared to income of $8 million in 1998. The decrease in other income is primarily due to lower interest income in 1999. Income taxes were a benefit of $3 million or a rate of 22 percent in 1999 compared to a benefit of $286 million or a rate of 46 percent in 1998. The decreased tax benefit in 1999 compared to 1998 was primarily the result of substantially higher pretax income and higher taxes on foreign income in excess of U.S. statutory rates partially offset by adjustments of prior years' tax accruals of approximately $11 million. OTHER MATTERS Adoption of Statement of Financial Accounting Standards ("SFAS") No. 133 On January 1, 2001, the Company adopted SFAS No. 133, as amended, Accounting for Derivative Instruments and Hedging Activities. 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 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 expects to reclassify as reductions to earnings during the next twelve months $571 million ($354 million after tax) from the transition adjustment that was recorded in accumulated other comprehensive income. The Company does not expect to be in violation of any debt covenants or other contracts as a result of implementing SFAS No. 133. Adoption of Emerging Issues Task Force Issue No. 00-10 ("EITF No. 00-10") In the fourth quarter of 2000, the Company adopted EITF No. 00-10, Accounting for Shipping and Handling Fees and Costs. EITF No. 00-10 addresses how shipping and handling fees should be classified in the income statement. As a result of EITF No. 00-10, the Company has reclassified its transportation expenses from oil and gas revenues to costs and expenses for all periods presented. Acquisitions of Properties On January 17, 2001, BR announced that its Canadian subsidiary, Burlington Resources Canada Energy Ltd., closed its transaction with Petrobank Energy and Resources Ltd. and entered into an agreement with ATCO Gas to acquire properties in the Western Canadian Sedimentary Basin for a total of approximately $385 million. The properties have net proved reserves of approximately 297 BCFE. Consummation of the transaction with ATCO Gas is dependent on government and regulatory approval. On February 15, 2001, BR entered into an agreement with DIFCO Limited to exercise a preferential right to purchase an additional 10% interest in 7 fields in the East Irish Sea. The purchase price will be $25 million and the deal will close by the end of the first quarter 2001. BR is the operator of the fields and already owns 90% of the assets. FORWARD-LOOKING STATEMENTS The Company, in discussions of its future plans, objectives and expected performance in periodic reports filed by the Company with the Securities and Exchange Commission (or documents incorporated by reference therein) and in written and oral presentations made by the Company, 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 19 23 on assumptions which the Company believes are reasonable, but are by their nature inherently uncertain. In all cases, there can be no assurance 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 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 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 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 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 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 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 20 24 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, 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 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 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 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 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 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. 21 25 ITEM EIGHT FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION BURLINGTON RESOURCES INC. CONSOLIDATED STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, ------------------------------- 2000 1999 1998 ------ ------------- ------ (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) REVENUES.................................................... $3,147 $2,313 $2,225 ------ ------ ------ COSTS AND EXPENSES Production Taxes.......................................... 147 120 100 Transportation Expense.................................... 240 248 219 Production and Processing................................. 463 460 469 Depreciation, Depletion and Amortization.................. 704 631 679 Exploration Costs......................................... 237 226 337 Impairment of Oil and Gas Properties...................... -- 225 706 Merger Costs.............................................. -- 37 -- Administrative............................................ 165 166 154 ------ ------ ------ Total Costs and Expenses.................................... 1,956 2,113 2,664 ------ ------ ------ Operating Income (Loss)..................................... 1,191 200 (439) Interest Expense............................................ 197 211 193 Other Expense (Income) -- Net............................... 27 2 (8) ------ ------ ------ Income (Loss) Before Income Taxes........................... 967 (13) (624) Income Tax Expense (Benefit)................................ 292 (3) (286) ------ ------ ------ NET INCOME (LOSS)........................................... $ 675 $ (10) $ (338) ====== ====== ====== BASIC EARNINGS (LOSS) PER COMMON SHARE...................... $ 3.13 $ (.05) $(1.60) ====== ====== ====== DILUTED EARNINGS (LOSS) PER COMMON SHARE.................... $ 3.12 $ (.05) $(1.60) ====== ====== ======

See accompanying Notes to Consolidated Financial Statements. 22 26 BURLINGTON RESOURCES INC. CONSOLIDATED BALANCE SHEET

DECEMBER 31, ----------------------- 2000 1999 ------- ------------ (IN MILLIONS, EXCEPT SHARE DATA) ASSETS Current Assets Cash and Cash Equivalents................................. $ 132 $ 89 Accounts Receivable....................................... 809 473 Inventories............................................... 45 53 Other Current Assets...................................... 25 26 ------- ------- 1,011 641 ------- ------- Oil and Gas Properties (Successful Efforts Method).......... 13,118 12,834 Other Properties............................................ 1,019 935 ------- ------- 14,137 13,769 Accumulated Depreciation, Depletion and Amortization........ 7,830 7,412 ------- ------- Properties -- Net......................................... 6,307 6,357 ------- ------- Deferred Income Taxes....................................... -- 32 ------- ------- Other Assets................................................ 188 135 ------- ------- Total Assets....................................... $ 7,506 $ 7,165 ======= ======= LIABILITIES Current Liabilities Accounts Payable.......................................... $ 619 $ 444 Taxes Payable............................................. 55 93 Accrued Interest.......................................... 33 36 Dividends Payable......................................... 30 -- Other Current Liabilities................................. 21 19 Current Maturities of Long-term Debt...................... -- 51 ------- ------- 758 643 ------- ------- Long-term Debt.............................................. 2,301 2,769 ------- ------- Deferred Income Taxes....................................... 266 98 ------- ------- Other Liabilities and Deferred Credits...................... 431 426 ------- ------- Commitments and Contingent Liabilities STOCKHOLDERS' EQUITY 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 241,188,698 and 241,188,770 Shares for 2000 and 1999, respectively)................... 2 2 Paid-in Capital............................................. 3,944 3,966 Retained Earnings........................................... 884 328 Deferred Compensation -- Restricted Stock................... (5) (3) Accumulated Other Comprehensive Loss........................ (70) (54) Cost of Treasury Stock (25,619,893 and 25,219,025 Shares for 2000 and 1999, respectively).............................. (1,005) (1,010) ------- ------- Stockholders' Equity........................................ 3,750 3,229 ------- ------- Total Liabilities and Stockholders' Equity......... $ 7,506 $ 7,165 ======= =======

See accompanying Notes to Consolidated Financial Statements. 23 27 BURLINGTON RESOURCES INC. CONSOLIDATED STATEMENT OF CASH FLOWS

YEAR ENDED DECEMBER 31, -------------------------------- 2000 1999 1998 ------ ------------- ------- (IN MILLIONS) CASH FLOWS FROM OPERATING ACTIVITIES Net Income (Loss)......................................... $ 675 $ (10) $ (338) Adjustments to Reconcile Net Income (Loss) to Net Cash Provided By Operating Activities Depreciation, Depletion and Amortization............... 704 631 679 Deferred Income Taxes.................................. 219 (12) (304) Exploration Costs...................................... 237 226 337 Gain on Sales of Oil and Gas Properties................ -- -- (13) Impairment of Oil and Gas Properties................... -- 225 706 Working Capital Changes Accounts Receivable.................................... (341) (31) (19) Inventories............................................ 8 -- -- Other Current Assets................................... 1 (4) 7 Accounts Payable....................................... 109 (13) 4 Taxes Payable.......................................... (33) 40 (18) Accrued Interest....................................... (3) 6 (1) Other Current Liabilities.............................. 4 (22) (3) Other..................................................... 18 66 (57) ------ ------- ------- Net Cash Provided By Operating Activities......... 1,598 1,102 980 ------ ------- ------- CASH FLOWS FROM INVESTING ACTIVITIES Additions to Properties................................... (941) (989) (1,839) Short-term Investments.................................... -- -- 83 Proceeds from Sales and Other............................. 19 (4) 241 ------ ------- ------- Net Cash Used In Investing Activities............. (922) (993) (1,515) ------ ------- ------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-term Debt.............................. 70 632 410 Reduction in Long-term Debt............................... (564) (528) (15) Dividends Paid............................................ (89) (127) (97) Common Stock Purchases.................................... (121) (9) (15) Common Stock Issuances.................................... 92 21 152 Other..................................................... (21) (9) (52) ------ ------- ------- Net Cash Provided By (Used In) Financing Activities...................................... (633) (20) 383 ------ ------- ------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............ 43 89 (152) CASH AND CASH EQUIVALENTS Beginning of Year......................................... 89 -- 152 ------ ------- ------- End of Year............................................... $ 132 $ 89 $ -- ====== ======= =======

See accompanying Notes to Consolidated Financial Statements. 24 28 BURLINGTON RESOURCES INC. CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

ACCUMULATED DEFERRED OTHER COST OF COMMON PAID-IN RETAINED COMPENSATION -- COMPREHENSIVE TREASURY STOCKHOLDERS' STOCK CAPITAL EARNINGS RESTRICTED STOCK LOSS STOCK EQUITY ------ ------- ------------- ---------------- ------------- -------- -------------- (IN MILLIONS, EXCEPT SHARE DATA) Balance, December 31, 1997...................... $2 $3,772 $ 876 $-- $(51) $(1,038) $3,561 -- ------ ----- --- ---- ------- ------ Comprehensive Loss Net Loss.................. (338) (338) Foreign Currency Translation............. (23) (23) ----- ---- ------ Comprehensive Loss...... (338) (23) (361) ----- ---- ------ Cash Dividends ($.46 per Share).................... (98) (98) Common Stock Purchases (435,000 Shares).......... (15) (15) Common Stock Issuances...... 188 188 Stock Option Activity and Other..................... (7) (2) 46 37 -- ------ ----- --- ---- ------- ------ Balance, December 31, 1998...................... 2 3,953 440 (2) (74) (1,007) 3,312 -- ------ ----- --- ---- ------- ------ Comprehensive Income Net Loss.................. (10) (10) Foreign Currency Translation............. 20 20 ----- ---- ------ Comprehensive Income.... (10) 20 10 ----- ---- ------ Cash Dividends ($.46 per Share).................... (103) (103) Common Stock Purchases (250,000 Shares).......... (9) (9) Common Stock Issuances...... 7 7 Stock Option Activity and Other..................... 6 1 (1) 6 12 -- ------ ----- --- ---- ------- ------ Balance, December 31, 1999...................... 2 3,966 328 (3) (54) (1,010) 3,229 -- ------ ----- --- ---- ------- ------ Comprehensive Income Net Income................ 675 675 Foreign Currency Translation............. (16) (16) ----- ---- ------ Comprehensive Income.... 675 (16) 659 ----- ---- ------ Cash Dividends ($.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 == ====== ===== === ==== ======= ======

See accompanying Notes to Consolidated Financial Statements. 25 29 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. Due to the nature of financial reporting, management makes estimates and assumptions in preparing the consolidated financial statements. Actual results could differ from estimates. The consolidated financial statements include certain reclassifications that were made to conform to current presentation. 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. Short-term Investments Short-term investments consist of highly-liquid debt securities with a maturity of more than three months. The securities are available for sale and are carried at fair value based on quoted market prices. Unrealized gains and losses, net of tax, are included as a component of other comprehensive income. Realized gains and losses are based on specific identification of the securities sold. 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. In addition, unamortized capital costs at a field level are reduced to fair value if the sum of expected undiscounted future cash flows is less than net book value. 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 was $147 million and $154 million at December 31, 2000 and 1999, respectively. 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. Functional Currency The assets, liabilities and operations of BR's Canadian subsidiaries are measured using the Canadian dollar as the functional currency. The foreign exploration and production operations of BR other than in Canada are considered an extension of the Company's domestic operations. The assets, liabilities and results 26 30 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) of operations of these locations are therefore measured using the United States dollar as the functional currency. Foreign currency transaction losses of $4 million in 2000, gains of $9 million in 1999 and losses of $17 million in 1998 are included in net income. Foreign currency translation adjustments are reported as other comprehensive income. Hedging and Related Activities In order to mitigate the risk of market price fluctuations, the Company utilizes options and swaps to hedge future crude oil and natural gas production. Changes in the market value of these contracts and premiums paid for option contracts are deferred until the hedged item is recognized in income. If the contract is not a hedge, changes in market value are recorded currently in income. To qualify as a hedge, these transactions must be designated as a hedge and changes in their fair value must correlate with changes in the price of anticipated future production such that the Company's exposure to the effects of commodity price changes is reduced. These hedging instruments are measured for effectiveness on an enterprise-wide basis both at the inception of the contract and on an ongoing basis. If these instruments are terminated prior to maturity, resulting gains or losses continue to be deferred until the hedged item is recognized in income. The Company also enters into swap agreements to convert fixed price gas sales contracts to market-sensitive contracts. Gains or losses resulting from these transactions are included in revenue as the related physical production is delivered. See Note 13 of Notes to Consolidated Financial Statements for a discussion of the Company's adoption of Statement of Financial Accounting Standards ("SFAS") No. 133. Treasury lock agreements are used to hedge interest rate exposure on specific anticipated debt issuances of the Company. Accordingly, the differential paid or received by the Company on maturity of a treasury lock agreement is recognized as an adjustment to interest expense over the term of the underlying financing transaction. 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. 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. 27 31 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 216 million, 216 million and 211 million for the years ended December 31, 2000, 1999 and 1998, 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 216 million, 217 million and 211 million for the years ended December 31, 2000, 1999 and 1998, respectively. For the years ended December 31, 2000, 1999 and 1998, 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. 2. BUSINESS COMBINATION On August 16, 1999, the Company entered into a definitive agreement to acquire Poco Petroleums Ltd. ("Poco"), a corporation existing under the laws of the Province of Alberta, Canada (the "Acquisition"). The Acquisition was consummated on November 18, 1999. 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 are Canadian securities, which began trading on the Toronto Stock Exchange on November 23, 1999 under the symbol BRX. These shares have the same voting rights, dividend entitlements and other attributes as shares of BR Common Stock and are exchangeable, at each shareholder's option, for BR Common Stock on a one for one basis. The Acquisition was accounted for as a pooling of interests. 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. INCOME TAXES The jurisdictional components of income (loss) before income taxes follow.

YEAR ENDED DECEMBER 31, ------------------------- 2000 1999 1998 ------ ------ ------- (IN MILLIONS) Domestic.................................................... $673 $(66) $ 113 Foreign..................................................... 294 53 (737) ---- ---- ----- Total............................................. $967 $(13) $(624) ==== ==== =====

28 32 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The provision for income taxes follows.

YEAR ENDED DECEMBER 31, ------------------------- 2000 1999 1998 ------ ------ ------- (IN MILLIONS) Current Federal................................................... $ 37 $ 4 $ 10 State..................................................... 10 -- 5 Foreign................................................... 26 5 3 ---- ---- ----- 73 9 18 ---- ---- ----- Deferred Federal................................................... 84 (44) (1) State..................................................... 15 4 1 Foreign................................................... 120 28 (304) ---- ---- ----- 219 (12) (304) ---- ---- ----- Total............................................. $292 $ (3) $(286) ==== ==== =====

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

2000 1999 1998 ---- ----- ---- YEAR ENDED DECEMBER 31, --------------------- U.S. statutory rate......................................... 35.0% 35.0% 35.0% State income taxes.......................................... 2.4 (16.7) (.4) Taxes on foreign income in excess of U.S. statutory rate.... 4.5 (66.5) 6.9 Tax credits................................................. (5.4) 15.9 5.1 Adjustments of prior year accruals.......................... (5.8) 89.5 -- Merger costs................................................ -- (31.9) -- Other....................................................... (.5) (3.7) (.7) ---- ----- ---- Effective rate......................................... 30.2% 21.6% 45.9% ==== ===== ====

Deferred income tax liabilities (assets) follow.

DECEMBER 31, ------------- 2000 1999 ----- ----- (IN MILLIONS) Deferred income tax liabilities Property, plant and equipment............................. $ 740 $ 488 Other..................................................... 72 132 ----- ----- 812 620 ----- ----- Deferred income tax assets AMT credit carryforward................................... (345) (302) Deferred foreign tax credits.............................. (66) (75) Net operating loss carryforward........................... -- (37) Foreign tax credit carryforward........................... (2) (2) Financial accruals and other.............................. (166) (175) ----- ----- (579) (591) ----- ----- Less valuation allowance.................................... 33 37 ----- ----- $ 266 $ 66 ===== ===== Net Canadian deferred income tax asset...................... $ -- $ (32) ===== ===== Net deferred income tax liability........................... $ 266 $ 98 ===== =====

29 33 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The net deferred income tax liabilities, as of December 31, 2000 and 1999, include deferred state income tax liabilities of approximately $35 million and $21 million, respectively. The net deferred income tax liabilities also include foreign tax liabilities of approximately $124 million and $56 million as of December 31, 2000 and 1999, 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 certain non-Canadian deferred foreign tax credits. 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 foreign tax credit carryforward is available to offset future federal income taxes and will expire between 2001 and 2003 if not used. 4. COMMODITY HEDGING AND RELATED ACTIVITIES Natural Gas Swaps The Company enters into gas swap agreements to fix the price of anticipated future natural gas production. As of December 31, 2000, the Company had the following volumes hedged.

TOTAL HEDGED UNREALIZED VOLUME HEDGE/STRIKE OPPORTUNITY LOSS PRODUCTION PERIOD (MMBTU) PRICE (IN MILLIONS) ----------------- ------------ ------------ ---------------- 2001................................................ 93,475,000 $2.37 $ 500 2002................................................ 4,125,000 2.82 9 2003 to 2007........................................ 4,412,500 $3.06 $ 3

The Company also enters into swap agreements that, when matched against fixed price gas sales, convert our production back to a market sensitive position. These arrangements are recorded as a revision to gas price in the period the production is sold. As of December 31, 2000, the unrealized opportunity gain on these positions was approximately $21 million, which is offset by the opportunity loss on the fixed-price contracts. Natural Gas Basis Swaps The Company enters into natural gas basis swap agreements to fix the sales price differential between the Company's marketing locations and Henry Hub. These transactions are accounted for as hedges of the Company's underlying production. As of December 31, 2000, the Company had 59,025,000 MMBTU of year 2001 natural gas production hedged. As of December 31, 2000, the unrealized opportunity loss on these positions was approximately $33 million. Crude Oil Swaps The Company enters into crude oil swap agreements to fix the price of anticipated future crude oil production. As of December 31, 2000, the Company had the following volumes hedged.

TOTAL HEDGED UNREALIZED VOLUME HEDGE/STRIKE OPPORTUNITY LOSS PRODUCTION PERIOD (BBLS) PRICE (IN MILLIONS) ----------------- ------------ ------------ ------------------ 2001................................................ 16,425,000 $19.96 $81 2002................................................ 180,000 $21.91 $--

30 34 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Crude Oil Options The Company purchases call option agreements that allow the Company to participate in market price increases that exceed hedge prices established when the Company enters into a swap. Approximately 67 percent of the 16,425,000 Bbls of year 2001 hedged crude oil production was matched with call options that strike at an average price of $19.72 per Bbl. All of the year 2002 hedged crude oil production was matched with call options that strike at an average price of $19.89 per Bbl. The unrealized opportunity gain on these positions as of December 31, 2000 was $58 million. Hedging Gains and Losses The unrealized opportunity gains and losses represent the difference between hedged prices and market prices on hedged volumes of the commodities at December 31, 2000. Gains or losses resulting from these transactions are included in revenues as the related physical production is delivered. Hedging activities reduced oil and gas revenues $356 million, and increased oil and gas revenues $32 million and $60 million in 2000, 1999 and 1998, respectively. See Note 13 of Notes to Consolidated Financial Statements for a discussion of the Company's adoption of SFAS No. 133. 5. LONG-TERM DEBT Long-term debt follows.

DECEMBER 31, ---------------- 2000 1999 ------ ------ (IN MILLIONS) Commercial Paper............................................ $ 327 $ 267 Credit Facility Notes....................................... -- 332 Capitalized Lease Obligations............................... -- 56 Notes, 9 5/8%, due 2000..................................... -- 150 Notes, 8 1/2%, due 2001..................................... 150 150 Notes, 8.54%, due 2001...................................... 15 40 Notes, 6.20%, due 2001...................................... 32 34 Notes, 8 1/4%, due 2002..................................... 100 100 Notes, 6.40%, due 2003...................................... 66 69 Notes, 7.12%, due 2005...................................... 39 47 Notes, 6.60%, due 2007...................................... 100 103 Notes, 6.91%, due 2008...................................... 50 50 Debentures, 9 7/8%, due 2010................................ 150 150 Notes, 7.00%, due 2011...................................... 75 75 Debentures, 7 5/8%, due 2013................................ 100 100 Debentures, 9 1/8%, due 2021................................ 150 150 Debentures, 7.65%, due 2023................................. 200 200 Debentures, 8.20%, due 2025................................. 150 150 Debentures, 6 7/8%, due 2026................................ 150 150 Debentures, 7 3/8%, due 2029................................ 450 450 Other, including discounts -- net........................... (3) (3) ------ ------ 2,301 2,820 Less current maturities..................................... -- 51 ------ ------ Total long-term debt.............................. $2,301 $2,769 ====== ======

31 35 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company has debt maturities of $533 million, $108 million, $74 million, $8 million, $20 million and $1,561 million due in 2001, 2002, 2003, 2004, 2005 and thereafter, respectively. The Company's commercial paper borrowings at December 31, 2000 and 1999 had average interest rates of 6 percent and 7 percent, respectively. The fair value of debt outstanding as of December 31, 2000 and 1999 approximates the carrying amount. The Company had unused credit commitments in the form of revolving facilities ("revolvers") as of December 31, 2000. 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. The revolvers are comprised of agreements for $600 million, $400 million and $332 million. The $600 million revolver expires in February 2003 and the $400 million and $332 million revolvers expire in March 2001 unless renewed by mutual consent. The Company has the option to convert the outstanding balances on the $400 million and $332 million revolvers to one year term notes at expiration of the agreements. In addition, the Company has a $1 billion shelf registration statement on file with the Securities and Exchange Commission. On February 12, 2001, the Company issued $400 million of fixed-rate debt with an interest rate of 6.68 percent due February 2011. This issuance reduces the Company's amount available under its shelf registration statement to $600 million. The net proceeds are expected to be used by a Canadian subsidiary for general corporate purposes, including the repayment of commercial paper and a pending property acquisition. 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, Eurodollar rates or bankers' acceptances in Canada, also at the Company's option. Under the covenants of the revolvers, Company debt cannot exceed 60 percent of capitalization (as defined in the agreements). Also, under the covenants of notes of the Company's Canadian subsidiary, the Company must limit debt to less than 3.5 times earnings before interest, taxes, DD&A and exploration costs and maintain net worth in excess of a specified amount. Outstanding borrowings of $114 million and $103 million as of December 31, 2000 and 1999, 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. 6. TRANSPORTATION ARRANGEMENTS WITH EL PASO NATURAL GAS COMPANY In 2000, 1999 and 1998, approximately 29 percent, 27 percent and 29 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 9 for demand charges paid to EPNG which provide the Company with firm and interruptible transportation capacity rights on interstate and intrastate pipeline systems. 7. CAPITAL STOCK 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. 32 36 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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, 2000, 4,937,951 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 one million shares annually. The Company issued 211,350, 110,250 and 24,625 shares of restricted stock in 2000, 1999 and 1998, respectively, from these plans. The Company's stock option activity follows.

WEIGHTED AVERAGE OPTIONS EXERCISE PRICE ---------- ---------------- Balance, December 31, 1997.................................. 10,488,335 $36.98 Granted................................................... 1,125,050 36.77 Exercised................................................. (1,578,818) 24.42 Cancelled................................................. (889,485) 44.69 ---------- 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 ==========

The following table summarizes information related to stock options outstanding and exercisable at December 31, 2000.

WEIGHTED AVERAGE OPTIONS RANGE OF WEIGHTED AVERAGE REMAINING OPTIONS WEIGHTED AVERAGE OUTSTANDING EXERCISE PRICES EXERCISE PRICE CONTRACTUAL LIFE EXERCISABLE EXERCISE PRICE ----------- --------------- ---------------- ---------------- ----------- ---------------- 3,350,504.. .............. $19.51-39.94 $32.92 6.2 2,168,404 $32.18 3,230,590.. .............. 40.63-52.03 47.51 6.0 3,180,590 47.62 --------- --------- 6,581,094.. .............. $19.51-52.03 $40.08 6.1 5,348,994 $41.36 ========= =========

Exercisable stock options and weighted average exercise prices at December 31, 1998 and 1997 follow.

OPTIONS WEIGHTED AVERAGE EXERCISABLE EXERCISE PRICE ----------- ---------------- December 31, 1999........................................... 7,638,364 $36.98 December 31, 1998........................................... 5,255,473 $37.22

33 37 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The weighted average fair values of options granted during the years 2000, 1999 and 1998 were $10.33, $11.13 and $16.54, 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 2000, 1999 and 1998: stock price volatility of 35 percent, 27 percent and 25 percent, respectively; risk free rate of return ranging from 5 percent to 7 percent; dividend yield of 1.46 percent, .88 percent and .33 percent, respectively; and an expected term of between 3 and 6 years. If the fair value based method of accounting had been applied, the Company's net income and EPS would have been reduced to the pro forma amounts indicated below. The fair value of stock options included in the pro forma amounts is not necessarily indicative of future effects on net income and EPS.

YEAR ENDED DECEMBER 31, ------------------------ 2000 1999 1998 ----- ------ ------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Net income (loss) -- as reported............................ 675 $ (10) $ (338) Net income (loss) -- pro forma.............................. 663 (41) (357) Basic EPS -- as reported.................................... 3.13 (.05) (1.60) Basic EPS -- pro forma...................................... 3.08 (.19) (1.69) Diluted EPS -- as reported.................................. 3.12 (.05) (1.60) Diluted EPS -- pro forma.................................... 3.06 $(.19) $(1.69)

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, 2000, 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 34 38 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. 8. RETIREMENT BENEFITS The Company's pension plans are non-contributory defined benefit plans covering all United States 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. 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. 35 39 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, ----------------------------- 2000 1999 2000 1999 ---- ---- ------ ------ (IN MILLIONS) Change in benefit obligation Benefit obligation at beginning of year................... $161 $182 $ 24 $ 32 Service cost.............................................. 9 10 -- -- Interest cost............................................. 11 12 3 2 Amendments................................................ -- -- -- (4) Actuarial loss (gain)..................................... 1 (15) 8 (3) Benefits paid............................................. (22) (28) (3) (3) ---- ---- ---- ---- Benefit obligation at end of year......................... 160 161 32 24 ---- ---- ---- ---- Change in plan assets Fair value of plan assets at beginning of year............ 171 172 -- -- Actual return on plan assets.............................. 2 22 -- -- Employer contribution..................................... 5 5 3 3 Benefits paid............................................. (22) (28) (3) (3) ---- ---- ---- ---- Fair value of plan assets at end of year.................. 156 171 -- -- ---- ---- ---- ---- Funded status............................................... (4) 10 (32) (24) Unrecognized net actuarial gain (loss)...................... 2 (11) 7 (1) Unrecognized net transition obligation...................... 1 1 -- -- Unrecognized prior service cost............................. 1 1 (7) (3) ---- ---- ---- ---- Net prepaid (accrued) benefit cost.......................... $ -- $ 1 $(32) $(28) ==== ==== ==== ====

PENSION BENEFITS POSTRETIREMENT BENEFITS -------------------- ------------------------ YEAR ENDED DECEMBER 31, ------------------------------------------------ 2000 1999 1998 2000 1999 1998 ---- ---- ---- ----- ----- ------ (IN MILLIONS) Benefit cost for the plans includes the following components Service cost.................................. $ 9 $ 10 $ 9 $-- $-- $-- Interest cost................................. 11 12 12 3 2 2 Expected return on plan assets................ (13) (14) (13) -- -- -- Recognized net actuarial loss (gain).......... -- 1 2 -- -- (1) ---- ---- ---- --- --- -- Net benefit cost...................... $ 7 $ 9 $ 10 $ 3 $ 2 $1 ==== ==== ==== === === ==

PENSION BENEFITS POSTRETIREMENT BENEFITS ----------------------- ----------------------- YEAR ENDED DECEMBER 31, -------------------------------------------------- 2000 1999 1998 2000 1999 1998 ----- ----- ----- ----- ----- ----- Weighted average assumptions Discount rate......................... 7.50% 7.75% 6.75% 7.50% 7.75% 6.75% Expected return on plan assets........ 9.00% 9.00% 9.00% -- -- -- Rate of compensation increase......... 5.00% 5.00% 5.00% -- -- --

36 40 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) During 1998, the Company recognized a settlement expense of approximately $800 thousand related to the employee reduction associated with the Merger in the fourth quarter of 1997. An 8 percent annual rate of increase in the per capita cost of covered health care benefits was assumed for 2001. The rate is assumed to decrease gradually to 5 percent for 2006 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................... $ 201 $ (174) Effect on postretirement benefit obligation................. $2,902 $(2,510)

9. 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 $123 million, $122 million and $109 million of demand charges of which $27 million, $36 million and $44 million were paid to EPNG for the years ended December 31, 2000, 1999 and 1998, respectively. All transportation costs including demand charges are included in transportation expense in the income statement pursuant to Emerging Issues Task Force Issue No. 00-10. Future transportation demand charge commitments at December 31, 2000 follow.

YEAR ENDED DECEMBER 31, ----------------------- (IN MILLIONS) 2001........................................................ $124 2002........................................................ 119 2003........................................................ 115 2004........................................................ 110 2005........................................................ 99 Thereafter.................................................. 347 ---- Total............................................. $914 ====

Lease Obligations The Company has operating leases for office space and other property and equipment. The Company incurred lease rental expense of $24 million, $24 million and $19 million for the years ended December 31, 2000, 1999 and 1998, respectively. 37 41 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Future minimum annual rental commitments at December 31, 2000 follow.

YEAR ENDED DECEMBER 31, ----------------------- (IN MILLIONS) 2001........................................................ $ 22 2002........................................................ 20 2003........................................................ 18 2004........................................................ 18 2005........................................................ 19 Thereafter.................................................. 61 ---- Total............................................. $158 ====

Drilling Rig Commitments During 1998, the Company entered into agreements to lease or participate in the use of various drilling rigs. The commitments with respect to these agreements range from $116 million to $245 million depending on partner participation. These agreements extend through the year 2004. Debt Guarantee BR guarantees its 65 percent pro rata share of the debt of a non-consolidated affiliate. As of December 31, 2000, the affiliate's total debt was $66 million. 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 oil and 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. 38 42 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company and numerous other oil and gas companies have also been named as defendants in a lawsuit styled as United States of America ex rel. J. Benjamin Johnson, Jr., et al. v. Shell Oil Company, et al. in the United States District Court for the Eastern District of Texas alleging violations of the civil False Claims Act with respect to the valuation of oil. This suit alleges that the Company underpaid royalties for crude oil produced on federal and Indian lands. The Company has entered into an agreement to pay $8.5 million, plus attorneys fees, in settlement of all claims against it. The District Court has entered an order approving the settlement and dismissing the case against the Company. 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. 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. 10. SUPPLEMENTAL CASH FLOW INFORMATION The following is additional information concerning supplemental disclosures of cash payments.

YEAR ENDED DECEMBER 31, ----------------------- 2000 1999 1998 ----- ----- ----- (IN MILLIONS) Interest paid............................................... $195 $206 $192 Income taxes paid -- net.................................... $ 88 $ 13 $ 26

The following is additional information concerning supplemental disclosure of non-cash investing and financing activities.

YEAR ENDED DECEMBER 31, ----------------------- 2000 1999 1998 ----- ----- ----- (IN MILLIONS) Issuance of Common Stock in exchange for oil and gas properties................................................ $ -- $ -- $74 Capitalized lease obligations............................... $ -- $ -- $53

39 43 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) At December 31, 2000 and 1999, the Accounts Payable balance on the Consolidated Balance Sheet included payables for capital expenditures of $232 million and $161 million, respectively. 11. IMPAIRMENT OF OIL AND GAS PROPERTIES 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. 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 ($140 million after tax) related to those properties. In the fourth quarter of 1998, the market experienced a weakness in commodity prices. The Company subjected all properties to impairment testing and subsequently recognized a pretax impairment charge related to certain Canadian properties of $706 million ($390 million after tax). 12. SEGMENT AND GEOGRAPHIC INFORMATION The Company's reportable segments are North America and International. Both segments are engaged principally in the exploration, development, production and marketing of oil and gas. The North America segment is responsible for the Company's operations in the USA and Canada and the International segment is responsible for all operations outside that geographical region. The accounting policies for the segments are the same as those described in Note 1 of Notes to Consolidated Financial Statements. There are no significant intersegment sales or transfers. The following tables present information about reported segment operations.

YEAR ENDED DECEMBER 31, 2000 -------------------------------------- NORTH AMERICA INTERNATIONAL TOTAL ------------- ------------- ------ (IN MILLIONS) Revenues................................................... $2,976 $171 $3,147 Depreciation, depletion and amortization................... 627 58 685 Operating income........................................... 1,339 36 1,375 Additions to properties.................................... $ 804 $179 $ 983

YEAR ENDED DECEMBER 31, 1999 -------------------------------------- NORTH AMERICA INTERNATIONAL TOTAL ------------- ------------- ------ (IN MILLIONS) Revenues................................................... $2,182 $131 $2,313 Depreciation, depletion and amortization................... 560 57 617 Impairment of oil and gas properties....................... 225 -- 225 Operating income (loss).................................... 438 (21) 417 Additions to properties.................................... $ 797 $148 $ 945

40 44 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

YEAR ENDED DECEMBER 31, 1998 -------------------------------------- NORTH AMERICA INTERNATIONAL TOTAL ------------- ------------- ------ (IN MILLIONS) Revenues................................................... $2,076 $149 $2,225 Depreciation, depletion and amortization................... 601 67 668 Impairment of oil and gas properties....................... 706 -- 706 Operating loss............................................. (236) (38) (274) Additions to properties.................................... $1,653 $136 $1,789

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

YEAR ENDED DECEMBER 31, ------------------------ 2000 1999 1998 ------- ----- ------ (IN MILLIONS) Total operating income (loss) for reportable segments....... $1,375 $417 $(274) Merger costs................................................ -- 37 -- Corporate expenses.......................................... 184 180 165 Interest expense............................................ 197 211 193 Other expense (income)-- net................................ 27 2 (8) ------ ---- ----- Consolidated income (loss) before income taxes.............. $ 967 $(13) $(624) ====== ==== =====

The following is a reconciliation of segment additions to properties to consolidated amounts.

YEAR ENDED DECEMBER 31, ------------------------ 2000 1999 1998 ------ ------ ------ (IN MILLIONS) Total additions to properties for reportable segments....... $ 983 $ 945 $1,789 Administrative expenditures................................. 29 44 50 ------ ------ ------ Consolidated additions to properties........................ $1,012 $ 989 $1,839 ====== ====== ======

The following table presents revenues by geographic location.

YEAR ENDED DECEMBER 31, ------------------------ 2000 1999 1998 ------ ------ ------ (IN MILLIONS) USA......................................................... $2,224 $1,694 $1,635 Canada...................................................... 752 488 441 Other International......................................... 171 131 149 ------ ------ ------ Consolidated revenues....................................... $3,147 $2,313 $2,225 ====== ====== ======

13. ADOPTION OF SFAS NO. 133 On January 1, 2001, the Company adopted SFAS No. 133, as amended, Accounting for Derivative Instruments and Hedging Activities. 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. 41 45 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 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 expects to reclassify as reductions to earnings during the next twelve months $571 million ($354 million after tax) from the transition adjustment that was recorded in accumulated other comprehensive income. The Company does not expect to be in violation of any debt covenants or other contracts as a result of implementing SFAS No. 133. 14. SUBSEQUENT EVENTS On January 17, 2001, BR announced that its Canadian subsidiary, Burlington Resources Canada Energy Ltd., closed its transaction with Petrobank Energy and Resources Ltd. and entered into an agreement with ATCO Gas to acquire properties in the Western Canadian Sedimentary Basin for a total of approximately $385 million. The properties have net proved reserves of approximately 297 BCFE. Consummation of the transaction with ATCO Gas is dependent on government and regulatory approval. On February 15, 2001, BR entered into an agreement with DIFCO Limited to exercise a preferential right to purchase an additional 10% interest in 7 fields in the East Irish Sea. The purchase price will be $25 million and the deal will close by the end of the first quarter of 2001. BR is the operator of the fields and already owns 90% of the assets. 42 46 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 generally accepted accounting principles. 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 certified public accountants, financial management, counsel and internal audit. To ensure complete independence, the certified public 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 certified public accountants provide an objective independent review by their audit of the Company's financial statements. Their audit is conducted in accordance with generally accepted auditing standards and includes a review of internal accounting controls to the extent deemed necessary for the purposes of their audit. /s/ STEVEN J. SHAPIRO /s/ PHILIP W. COOK -------------------------------------------- -------------------------------------------- Steven J. Shapiro Philip W. Cook Senior Vice President and Vice President, Controller and Chief Financial Officer Chief Accounting Officer 43 47 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, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 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 assets of $1.3 billion as of December 31, 1999 and total revenues of $407 million and, $372 million for the years ended December 31, 1999 and 1998, respectively. 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 the opinion expressed above. /s/ PRICEWATERHOUSECOOPERS LLP February 12, 2001 Houston, Texas 44 48 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. Capitalized costs for oil and gas producing activities follow.

DECEMBER 31, ------------------ 2000 1999 ------- ------- (IN MILLIONS) Proved properties........................................... $12,837 $12,516 Unproved properties......................................... 281 318 ------- ------- 13,118 12,834 Accumulated depreciation, depletion and amortization........ 7,345 6,765 ------- ------- Net capitalized costs............................. $ 5,773 $ 6,069 ======= =======

Costs incurred for oil and gas property acquisition, exploration and development activities follow.

YEAR ENDED DECEMBER 31, 2000 -------------------------------------------- NORTH AMERICA -------------- 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 -------------- 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 ==== ==== ==== ====

YEAR ENDED DECEMBER 31, 1998 -------------------------------------------- NORTH AMERICA -------------- USA CANADA INTERNATIONAL WORLDWIDE ---- ------ ------------- --------- (IN MILLIONS) Property acquisition Unproved.......................................... $ 92 $ 16 $ 6 $ 114 Proved............................................ 23 410 4 437 Exploration......................................... 315 95 96 506 Development......................................... 491 150 30 671 ---- ---- ---- ------ Total costs incurred...................... $921 $671 $136 $1,728 ==== ==== ==== ======

45 49 BURLINGTON RESOURCES INC. SUPPLEMENTARY FINANCIAL INFORMATION Results of operations for oil and gas producing activities follow.

YEAR ENDED DECEMBER 31, 2000 ------------------------------------------- NORTH AMERICA --------------- USA CANADA INTERNATIONAL WORLDWIDE ------ ------ ------------- --------- (IN MILLIONS) Revenues............................................. $2,171 $ 748 $171 $3,090 ------ ------ ---- ------ Production costs..................................... 373 122 20 515 Exploration costs.................................... 103 92 42 237 Operating expenses................................... 414 108 23 545 Depreciation, depletion and amortization............. 487 118 54 659 ------ ------ ---- ------ 1,377 440 139 1,956 ------ ------ ---- ------ Operating income..................................... 794 308 32 1,134 Income tax provision................................. 190 148 21 359 ------ ------ ---- ------ Results of operations for oil and gas producing activities......................................... $ 604 $ 160 $ 11 $ 775 ====== ====== ==== ======

YEAR ENDED DECEMBER 31, 1999 ------------------------------------------- NORTH AMERICA --------------- USA CANADA INTERNATIONAL WORLDWIDE ------ ------ ------------- --------- (IN MILLIONS) Revenues............................................. $1,646 $ 481 $124 $2,251 ------ ------ ---- ------ Production costs..................................... 347 102 33 482 Exploration costs.................................... 140 40 46 226 Operating expenses................................... 369 104 27 500 Depreciation, depletion and amortization............. 435 107 54 596 Impairment of oil and gas properties................. 225 -- -- 225 ------ ------ ---- ------ 1,516 353 160 2,029 ------ ------ ---- ------ Operating income (loss).............................. 130 128 (36) 222 Income tax provision (benefit)....................... 38 61 (11) 88 ------ ------ ---- ------ Results of operations for oil and gas producing activities......................................... $ 92 $ 67 $(25) $ 134 ====== ====== ==== ======

YEAR ENDED DECEMBER 31, 1998 ------------------------------------------- NORTH AMERICA --------------- USA CANADA INTERNATIONAL WORLDWIDE ------ ------ ------------- --------- (IN MILLIONS) Revenues............................................. $1,595 $ 432 $149 $2,176 ------ ------ ---- ------ Production costs..................................... 343 90 43 476 Exploration costs.................................... 247 31 59 337 Operating expenses................................... 342 82 32 456 Depreciation, depletion and amortization............. 429 157 64 650 Impairment of oil and gas properties................. -- 706 -- 706 ------ ------ ---- ------ 1,361 1,066 198 2,625 ------ ------ ---- ------ Operating income (loss).............................. 234 (634) (49) (449) Income tax provision (benefit)....................... 55 (259) (11) (215) ------ ------ ---- ------ Results of operations for oil and gas producing activities......................................... $ 179 $ (375) $(38) $ (234) ====== ====== ==== ======

46 50 BURLINGTON RESOURCES INC. SUPPLEMENTARY FINANCIAL INFORMATION The following table reflects estimated quantities of proved oil 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.

OIL (MMBBLS) GAS (BCF) ------------------------------------------ ------------------------------------------ NORTH AMERICA NORTH AMERICA -------------- -------------- USA CANADA INTERNATIONAL WORLDWIDE USA CANADA INTERNATIONAL WORLDWIDE ----- ------ ------------- --------- ----- ------ ------------- --------- PROVED DEVELOPED AND UNDEVELOPED RESERVES December 31, 1997.......... 232.4 68.3 21.3 322.0 5,884 1,128 534 7,546 Revisions of previous estimates................ (8.4) (.4) 1.6 (7.2) (94) (66) (6) (166) Extensions, discoveries and other additions.......... 26.7 11.6 29.7 68.0 636 235 35 906 Production................. (24.2) (7.9) (6.0) (38.1) (577) (157) (24) (758) Purchases of reserves in place.................... .1 3.7 -- 3.8 81 338 8 427 Sales of reserves in place.................... -- (2.9) -- (2.9) (72) (57) (25) (154) ----- ---- ---- ----- ----- ----- --- ----- December 31, 1998............ 226.6 72.4 46.6 345.6 5,858 1,421 522 7,801 Revisions of previous estimates................ (9.0) (1.9) .3 (10.6) (52) (20) (2) (74) Extensions, discoveries and other additions.......... 19.0 4.7 2.0 25.7 554 164 384 1,102 Production................. (20.9) (7.1) (4.8) (32.8) (543) (156) (32) (731) Purchases of reserves in place.................... .5 1.0 -- 1.5 138 53 -- 191 Sales of reserves in place.................... -- -- -- -- -- (9) -- (9) ----- ---- ---- ----- ----- ----- --- ----- December 31, 1999............ 216.2 69.1 44.1 329.4 5,955 1,453 872 8,280 Revisions of previous estimates................ .3 6.4 .9 7.6 (66) (95) (10) (171) Extensions, discoveries and other additions.......... 7.5 3.8 15.3 26.6 625 231 8 864 Production................. (18.9) (6.2) (3.5) (28.6) (527) (145) (45) (717) Purchases of reserves in place.................... .6 .1 14.7 15.4 5 22 -- 27 Sales of reserves in place.................... (1.5) -- (1.5) (3.0) (12) (4) (30) (46) ----- ---- ---- ----- ----- ----- --- ----- December 31, 2000............ 204.2 73.2 70.0 347.4 5,980 1,462 795 8,237 ===== ==== ==== ===== ===== ===== === ===== PROVED DEVELOPED RESERVES December 31, 1997.......... 203.9 62.8 15.6 282.3 4,641 1,053 233 5,927 December 31, 1998.......... 199.2 61.2 14.5 274.9 4,564 1,134 258 5,956 December 31, 1999.......... 168.3 57.5 13.5 239.3 4,715 1,180 314 6,209 December 31, 2000.......... 169.7 54.8 10.4 234.9 4,779 1,180 274 6,233

47 51 BURLINGTON RESOURCES, INC. SUPPLEMENTARY FINANCIAL INFORMATION A summary of the standardized measure of discounted future net cash flows relating to proved oil 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 and gas reserves.

DECEMBER 31, 2000 --------------------------------------------- NORTH AMERICA ----------------- 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 ======= ======= ====== =======

DECEMBER 31, 1999 -------------------------------------------- NORTH AMERICA ---------------- 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 ======= ====== ====== =======

48 52 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 and gas reserves follows.

2000 1999 1998 ------- ------- ------- (IN MILLIONS) January 1................................................... $ 6,293 $ 5,144 $ 5,789 ------- ------- ------- Revisions of previous estimates Changes in prices and costs............................... 18,756 1,844 (1,017) Changes in quantities..................................... (157) (83) (135) Changes in rate of production............................. (157) (92) (274) Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs..... 2,613 723 547 Purchases of reserves in place.............................. 191 168 183 Sales of reserves in place.................................. (46) (6) (102) Accretion of discount....................................... 825 628 737 Sales of oil and gas, net of production costs............... (2,575) (1,769) (1,700) Net change in income taxes.................................. (8,023) (815) 435 Other....................................................... 1,084 551 681 ------- ------- ------- Net change.................................................. 12,511 1,149 (645) ------- ------- ------- December 31................................................. $18,804 $ 6,293 $ 5,144 ======= ======= =======

QUARTERLY FINANCIAL DATA -- UNAUDITED

2000 1999 ------------------------------------- ------------------------------------- 4TH 3RD 2ND 1ST 4TH 3RD 2ND 1ST ------- ------- ------- ------- ------- ------- ------- ------- (IN MILLIONS, EXCEPT PER SHARE AMOUNTS) Revenues(a)................ $999 $760 $680 $708 $690 $610 $516 $497 Operating Income (Loss)(b)(c)............. 485 318 201 187 (81) 147 83 51 Net Income (Loss)(b)(c).... 304 200 94 77 (86) 56 22 (2) Basic Earnings (Loss) per Common Share.. 1.41 .93 .43 .36 (.40) .26 .10 (.01) Diluted Earnings (Loss) per Common Share............. 1.41 .93 .43 .35 (.40) .26 .10 (.01) Cash Dividends Declared per Common Share............. .14 .13 .14 .14 .12 .11 .12 .11 Common Stock Price Range High..................... 52 7/8 40 3/4 46 1/4 39 1/2 39 1/4 46 3/4 47 5/8 42 5/16 Low...................... $ 34 5/16 $ 29 1/4 $ 34 1/2 $ 25 3/4 $ 29 1/2 $ 35 5/8 $ 38 3/8 $ 29 1/2

--------------- (a) Pursuant to implementation of EITF No. 00-10, the Company has reclassified its transportation expenses from oil and gas revenues to costs and expenses for all periods presented. (b) During the fourth quarter of 1999, as a result of the Acquisition, the Company recorded a pretax charge of $37 million for severance and transaction costs ($26 million after tax). (c) During the fourth quarter of 1999, as a result of a downward adjustment associated with the performance of certain properties, the Company recognized a non-cash, pretax charge of $225 million ($140 million after tax). 49 53 ITEM NINE CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None PART III ITEMS TEN AND ELEVEN DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT AND EXECUTIVE COMPENSATION Executive officers of the Registrant Bobby S. Shackouls, 50 -- 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, 42 -- 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, 41 -- 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, 48 -- 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, 56 -- 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 2001 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. 50 54 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.......................... 22 Consolidated Balance Sheet................................ 23 Consolidated Statement of Cash Flows...................... 24 Consolidated Statement of Stockholders' Equity............ 25 Notes to Consolidated Financial Statements................ 26 Report of Independent Accountants......................... 44 Supplemental Oil and Gas Disclosures -- Unaudited......... 45 Quarterly Financial Data -- Unaudited..................... 49 AMENDED EXHIBIT INDEX....................................... A-1

REPORTS ON FORM 8-K The Company filed no reports on Form 8-K during the last quarter of the fiscal year ended December 31, 2000. 51 55 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, January 17, 2001 ----------------------------------------------------- President and Chief Executive Bobby S. Shackouls Officer /s/ STEVEN J. SHAPIRO Senior Vice President and January 17, 2001 -------------------------------------------------------- Chief Financial Officer Steven J. Shapiro /s/ PHILIP W. COOK Vice President, January 17, 2001 -------------------------------------------------------- Controller and Chief Philip W. Cook Accounting Officer /s/ S. PARKER GILBERT Director January 17, 2001 -------------------------------------------------------- S. Parker Gilbert /s/ LAIRD I. GRANT Director January 17, 2001 -------------------------------------------------------- Laird I. Grant /s/ JOHN T. LAMACCHIA Director January 17, 2001 -------------------------------------------------------- John T. Lamacchia /s/ JAMES F. MCDONALD Director January 17, 2001 -------------------------------------------------------- James F. McDonald /s/ KENNETH W. ORCE Director January 17, 2001 -------------------------------------------------------- Kenneth W. Orce /s/ DONALD M. ROBERTS Director January 17, 2001 -------------------------------------------------------- Donald M. Roberts /s/ JOHN F. SCHWARZ Director January 17, 2001 -------------------------------------------------------- John F. Schwarz /s/ WALTER SCOTT, JR. Director January 17, 2001 -------------------------------------------------------- Walter Scott, Jr. 56 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 the 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 the 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 the 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 among 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).................. * +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....................... +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......................... +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).............................................. * +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).............................................. *

A-1 57

EXHIBIT PAGE NUMBER DESCRIPTION NUMBER ------- ----------- ------ +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....................................... Amendment to Burlington Resources 1993 Stock Incentive Plan dated December 2000 (filed as Exhibit 10.2 hereto).......... +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 (filed as Exhibit 10.2 hereto)..................................................... +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 February 23, 1999 between Burlington Resources Inc. and Chase Bank of Texas, N.A., as agent (Exhibit 10.22 to Form 10-K filed February 1999).............................................. * First Amendment and Restatement Agreement dated as of January 17, 2000 in respect of the Short-Term Revolving Credit Agreement (Exhibit 10.1 to Form 8-K, filed February 2001)....................................................... * Second Amendment and Restatement Agreement dated as of March 31, 2000 in respect of the Short-Term Revolving Credit Agreement (Exhibit 10.2 to Form 8-K filed February 2001).... * Amendment dated as of November 30, 2000 in respect of the Short-Term Revolving Credit Agreement....................... 10.19 $600 million Long-term Revolving Credit Agreement, dated as of February 25, 1998, between Burlington Resources Inc. and Morgan Guaranty Trust Company of New York as agent (Exhibit 10.23 to Form 10-K filed February 1999)..................... * Amendment and Restatement Agreement dated as of February 23, 1999 in respect of the Long-Term Revolving Credit Agreement (Exhibit 10.23 to Form 10-K filed February 1999)............ * Second Amendment and Restatement dated as of March 31, 2000 in respect of the Long-Term Credit Agreement (Exhibit 10.3 to Form 8-K filed February 2001)............................ * Amendment dated as of November 30, 2000 in respect of the Long-Term Revolving Credit Agreement........................ +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.................................................... +10.30 Burlington Resources Inc. 2001 Performance Share Unit Plan........................................................

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EXHIBIT PAGE NUMBER DESCRIPTION NUMBER ------- ----------- ------ 21.1 Subsidiaries of the Registrant.............................. 23.1 Consent of Independent Accountants -- PricewaterhouseCoopers....................... 23.2 Consent of Independent Accountants -- KPMG.................. 99.1 Audit Opinion of KPMG.......................................

--------------- *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