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, 2004

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.

717 Texas, Suite 2100, Houston, Texas 77002

Telephone: (713) 624-9500

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.    o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes   X   No      

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of January 30, 2005 and as of the last business day of the registrant’s most recently completed second fiscal quarter. Common Stock aggregate market value held by non-affiliates as of January 31, 2005: $16,915,639,395 and as of June 30, 2004: $14,035,722,348.

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, 2005, Shares Outstanding: 386,997,012

DOCUMENTS INCORPORATED BY REFERENCE

List hereunder the following documents if incorporated by reference and the Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated:

Burlington Resources Inc. definitive proxy statement, to be filed not later than 120 days after the end of the fiscal year covered by this report, is incorporated by reference into Part III.

Below are definitions of key certain technical industry terms used in this Form 10-K.

Appraisal well is a well drilled in the vicinity of a discovery or wildcat well in order to evaluate the extent and importance of the discovery.

Basin is a synclinal structure in the subsurface that is composed of sedimentary rock and regarded as a good prospect for exploration.

Call options are contracts giving the holder (purchaser) the right, but not the obligation, to buy (call) a specified item at a fixed price (exercise or strike price) during a specified period. The purchaser pays a nonrefundable fee (the premium) to the seller (writer).

Cash-flow hedges are derivative instruments used to mitigate the risk of variability in cash flows from crude oil and natural gas sales due to changes in market prices. Examples of such derivative instruments include fixed-price swaps, fixed-price swaps combined with basis swaps, purchased put options, costless collars (purchased put options and written call options) and producer three-ways (purchased put spreads and written call options). These derivative instruments either fix the price a party receives for its production or, in the case of option contracts, set a minimum price or a price within a fixed range.

Compression is the process of squeezing a given volume of gas into a smaller space.

Completion refers to the work performed and the installation of permanent equipment for the production of natural gas and crude oil from a recently drilled well.

Developed acreage is acreage that is allocated or assignable to producing wells or wells capable of production.

Development well is a well drilled within the proved area of an oil or natural gas field to the depth of a stratigraphic horizon known to be productive.

Dry hole is an exploratory or development well that does not produce oil or gas in commercial quantities.

Exploitation is drilling wells in areas proven to be productive.

Exploratory well is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well, a service well or a stratigraphic test well.

Fair-value hedges are derivative instruments used to hedge or offset the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment. For example, a contract is entered into whereby a commitment is made to deliver to a customer a specified quantity of crude oil or natural gas at a fixed price over a specified period of time. In order to hedge against changes in the fair value of these commitments, a party enters into swap agreements with financial counterparties that allow the party to receive market prices for the committed specified quantities included in the physical contract.

Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

Formation is a stratum of rock that is recognizable from adjacent strata consisting mainly of a certain type of rock or combination of rock types with thickness that may range from less than two feet to hundreds of feet.

Gross acres or gross wells are the total acres or wells in which a working interest is owned.

Horizon is a zone of a particular formation or that part of a formation of sufficient porosity and permeability to form a petroleum reservoir.

Independent oil and gas company is a company that is primarily engaged in the exploration and production sector of the oil and gas business.

Infill drilling refers to drilling wells between established producing wells on a lease; a drilling program to reduce the spacing between wells in order to increase production and/or recovery of in-place hydrocarbons from the lease.

Lease operating or well operating expenses are expenses incurred to operate the wells and equipment on a producing lease.

Net acreage and net oil and gas wells are obtained by multiplying gross acreage and gross oil and gas wells by the Company’s working interest percentage in the properties.

Oil and NGLs are converted into cubic feet of gas equivalent based on 6 MCF of gas to one barrel of oil or NGLs.

Operating costs include direct and indirect expenses, including divisional office expenses, incurred to manage, operate and maintain the Company’s wells and related equipment and facilities.

Permeability is a measure of ease with which fluids can move through a reservoir.

Porosity is the ratio of the volume of empty space to the volume of solid rock in a formation, indicating how much fluid a rock can hold.

Production costs are costs incurred to operate and maintain the Company’s wells and related equipment and facilities. These costs include well operating costs, severance taxes and ad valorem taxes.

Productive well is a well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed reserves are the portion of proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. For complete definitions of proved developed natural gas, NGLs and crude oil reserves, refer to the Securities and Exchange Commission’s Regulation S-X, Rule 4-10(a)(2), (3) and (4).

Proved reserves represent estimated quantities of natural gas, NGLs and crude oil 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. For complete definitions of proved natural gas, NGLs and crude oil reserves, refer to the Securities and Exchange Commission’s Regulation S-X, Rule 4-10(a)(2), (3) and (4).

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. For complete definitions of proved undeveloped natural gas, NGLs and crude oil reserves, refer to the Securities and Exchange Commission’s Regulation S-X, Rule 4-10(a)(2), (3) and (4).

Put options are contracts giving the holder (purchaser) the right, but not the obligation, to sell (put) a specified item at a fixed price (exercise or strike price) during a specified period. The purchaser pays a nonrefundable fee (the premium) to the seller (writer).

Reservoir is a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock and water barriers and/or is individual and separate from other reservoirs.

Seismic is an exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formation. (2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional pictures.)

Sour gas is natural gas containing chemical impurities, notably hydrogen sulfide, other sulfur compounds and/or carbon dioxide.

Spacing is the number of wells which conservation laws allow to be drilled on a given area of land.

Step-out drilling is drilling a well adjacent to a proven well but moving in the direction of an unproven area.

Swaps are contracts between two parties to exchange streams of variable and fixed prices on specified notional amounts. One party to the swap pays a fixed price while the other pays a variable price.

Sweet gas is natural gas free of significant amounts of hydrogen sulfide or carbon dioxide when produced.

Tight gas is natural gas produced from a formation with low permeability that will not give up its gas readily at high flow rates.

Transportation expense primarily includes costs to process, including payments made in-kind, and costs to transport crude oil, NGLs and natural gas to a major facility, market hub, sales point or plant.

Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas.

Working interest is the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover is operations on a producing well to restore or increase production.

Writer refers to the seller of an option. The writer earns the premium on the option but bears the risk of fulfilling the obligations of the option.

Zone is a stratigraphic interval containing one or more reservoirs.

PART I

ITEMS ONE AND TWO

BUSINESS AND PROPERTIES

Burlington Resources Inc. (“BR”) is among the world’s largest independent oil and gas companies and holds one of the industry’s leading positions in North American natural gas reserves and production. BR conducts exploration, production and development operations in the U.S., Canada, United Kingdom, Africa, China and South America. BR is a holding company and its principal subsidiaries include Burlington Resources Oil & Gas Company LP, The Louisiana Land and Exploration Company (“LL&E”), Burlington Resources Canada Ltd. (formerly known as Poco Petroleums Ltd.), Burlington Resources Canada (Hunter) Ltd. (formerly known as Canadian Hunter Exploration Ltd.) (“Hunter”), and their affiliated companies (collectively, “the Company”).

During 2002, after announcing in late 2001 its intent to sell certain non-core, non-strategic properties, the Company sold approximately 1 TCFE of reserves and a processing facility. As a result of these property sales, the Company generated proceeds, before post-closing adjustments, of approximately $1.2 billion. The Company used a portion of the proceeds generated from property sales to retire debt and for general corporate purposes.

In December 2001, the Company consummated the acquisition of Hunter valued at approximately U.S. $2.1 billion, resulting in goodwill of approximately $793 million. The Hunter acquisition added a portfolio of properties, primarily located in the Western Canadian Sedimentary Basin, an area in which the Company already operated. The most significant of the assets is the Deep Basin, one of North America’s largest natural gas fields.

The Company’s reportable segments are U.S., Canada and International. For financial information related to the Company’s reportable segments, see Note 17 of Notes to Consolidated Financial Statements. The Company’s worldwide major operating areas are discussed below.

North America

The Company’s asset base is dominated by North American natural gas properties. Its extensive North American lease holdings extend from the U.S. Gulf Coast to Northeast British Columbia and Northern Alberta in Canada. The Company’s North American operations include a mix of production, development and exploration assets.

U.S.

San Juan Basin

The San Juan Basin, in northwest New Mexico and southwest Colorado, is one of the Company’s major operating areas in terms of reserves and production. The San Juan Basin encompasses nearly 7,500 square miles, or approximately 4.8 million acres, with the major portion located in New Mexico’s Rio Arriba and San Juan counties. The Company is a significant holder of productive leasehold acreage in this area with over 840,000 net acres under its control. The Company operates almost 7,500 well completions in the San Juan Basin and holds interests in an additional 4,700 non-operated well completions.

In 2004, the Company invested $154 million in oil and gas capital, excluding acquisitions, drilled or participated in drilling 361 new wells and performed 172 workovers on existing wells. The Company’s net production from the San Juan Basin averaged approximately 550 MMCF of natural gas per day, 31.3 MBbls of NGLs per day and 1.1 MBbls of crude oil per day during 2004. Production from the San Juan Basin grew significantly during the 1990s, first as a result of Fruitland Coal drilling and then as a result of development of tight gas formations. By the end of the decade, all formations were experiencing some decline; however, the Company has been able to maintain flat production for the last three years. To mitigate Fruitland Coal production decline, the Company has an ongoing program that consists of performing workovers on existing wells, adding compression, and installing artificial lift, where appropriate. The Company drilled or participated in drilling 200 wells on 320-acre and 160-acre spacing during 2004. In 2004, net production from the Fruitland Coal averaged 206 MMCF of natural gas per day from over 1,900 completions.

Also in 2004, the Company completed a $28 million purchase of 1,242 undrilled acres in Negro Canyon, which is located in the heart of the Company’s Fruitland Coal producing area. The purchase encompasses a 100 percent working interest and 87.5 percent net revenue interest in the tract. Production has already been established and the Company expects to fully develop these leases by the end of 2006.

The three conventional formations (Mesaverde, Pictured Cliffs and Dakota) in the San Juan Basin continue to provide attractive development opportunities for the Company. The Mesaverde formation, which consists of the Lewis Shale, Cliffhouse, Menefee and Point Lookout sands, is the largest producing tight gas formation in the San Juan Basin. In 2004, the Company continued its ongoing infill-drilling program in this formation. In 2004, the Company drilled or participated in drilling 161 conventional wells on 160-acre and 80-acre spacing. Net production from the tight gas producing formations averaged 344 MMCF of natural gas per day, 31.3 MBbls of NGLs per day and 1.1 MBbls of crude oil per day in 2004.

Wind River Basin

The Madden Field, located in the Wind River Basin, covers more than 70,000 acres in Wyoming’s Fremont and Natrona counties. Net production averaged 119 MMCF of natural gas per day in 2004 from multiple horizons ranging in depth from 5,000 feet to over 25,000 feet, where the deep Madison formation occurs. Investments in the Wind River Basin during 2004 totaled $24 million for 57 newly drilled wells and workover projects. The Company owns an approximate 48 percent working interest in the Lost Cabin Gas Plant and a 43 percent net revenue interest in the Madison reservoir.

Williston Basin

The Williston Basin operations, located in western North Dakota and eastern Montana, were focused on activities on the Cedar Creek Anticline and in the Bakken Shale formation during 2004. Total Williston Basin production averaged 21.2 MBbls of crude oil per day and 8 MMCF of natural gas per day. During 2004, the Company invested $113 million on projects in the Williston Basin.

The Company continued its highly active waterflood development program at both the Cedar Hills South and East Lookout Butte Units, where the focus has moved to 160-acre infill drilling. A total of 39 production and 8 injection wells were drilled in the two units, along with the continued expansion of the injection and gathering infrastructure. In addition to the development drilling program on the Cedar Creek Anticline, a new development area was initiated in Richland County, Montana, where the Company drilled 8 horizontal wells in the siltstone of the Bakken Shale formation and acquired additional acreage. The Company currently controls over 60,000 acres including areas in Richland County, Montana, and McKenzie County, North Dakota.

Anadarko Basin

The Anadarko Basin, located principally in western Oklahoma, encompasses over 30,000 square miles and contains some of the deepest producing formations in the world. The Company controls over 250,000 net acres and produces from multiple horizons ranging in depth from 11,000 feet to over 21,000 feet. Net production for 2004 from the Anadarko Basin averaged 70 MMCF of natural gas per day and 1.9 MBbls of NGLs per day. During 2004, the Company invested $31 million in the Anadarko Basin. Operated activity focused on the Red Fork formation in Roger Mills County, Oklahoma, where the Company drilled 14 wells.

Permian Basin

Permian Basin operations, in west Texas, are focused on the Waddell Ranch Field. Total Permian Basin production in 2004 averaged 14 MMCF of natural gas per day, 4.0 MBbls of crude oil per day and 2.0 MBbls of NGLs per day, with the Waddell Ranch Field contributing 10 MMCF of natural gas per day, 2.7 MBbls of crude oil per day and 2.0 MBbls of NGLs per day. During 2004, the Company invested $10 million in Permian Basin operations.

Fort Worth Basin

In the Fort Worth Basin of north central Texas, the Company is focused on the continued development of the Barnett Shale formation acreage position in Denton and Wise Counties, Texas. The Company employed up to five rigs during the year to drill or participate in 93 wells in the Barnett Shale formation, including an 11 well horizontal drilling program. The Company invested $83 million in 2004 with production averaging 33 MMCF of natural gas per day, 4.2 MBbls of NGLs per day and 1.0 MBbls of crude oil per day.

Onshore Gulf Coast Area

The Onshore Gulf Coast Area includes operations in a number of drilling trends in east Texas, south Louisiana, the Onshore Gulf of Mexico and the Florida panhandle. In south Louisiana, the Company owns 660,000 acres of fee lands with both surface and mineral rights. In early 2004, the Company acquired $70 million of properties in south Louisiana from ChevronTexaco. The Company spent $29 million of capital on these properties in 2004, and production increased to over 20 MMCF of natural gas per day. In the East Texas Bossier trend, the Company commenced drilling seven wells in 2004, and natural gas sales averaged 7 MMCF per day. Overall, the Company invested $138 million on 128 drilling, workover and facilities projects in the Gulf Coast Area. Net production for 2004 averaged 108 MMCF of natural gas per day, 9.2 MBbls of crude oil per day and 1.5 MBbls of NGLs per day.

Canada

Western Canadian Sedimentary Basin

In the Western Canadian Sedimentary Basin, the Company’s portfolio of opportunities includes conventional exploration and development in Alberta, British Columbia and Saskatchewan.

Canadian activity in 2004 was focused on expanding activity into large-scale repeatable drilling programs in conventional and lower permeability reservoirs. Oil and gas capital investment in Canada was $798 million, excluding acquisitions, and 591 wells were drilled. Production in Canada was 819 MMCF of natural gas per day, 23.6 MBbls of NGLs per day and 5.5 MBbls of crude oil per day during 2004.

The Deep Basin area, in Alberta and British Columbia, consists of the Elmworth, Wapiti, Noel and Brassey Fields. In 2004, a $262 million oil and gas capital program was focused on exploration and development in the Deep Basin area. As a result, 106 wells were drilled and 231 MMCF of natural gas per day and 12.3 MBbls of NGLs per day were produced from this area.

In 2004, the Company completed resource assessment studies that identified future drilling opportunities across 4 horizons in the Deep Basin. The most prolific of these formations include the Cadomin, Falher-A, Falher-B and Cadotte. The Company also conducted down-spacing studies across the Cadomin, Chinook and Belly River horizons. These studies were supplemented by favorable regulatory approval to reduce well spacing from 640-acre to 320-acre over 55 sections of the Deep Basin.

In the Foothills area, which borders on the west side of the Deep Basin, oil and gas capital spending focused on exploration and development was $31 million and production was 53 MMCF of natural gas per day. Five wells were drilled in 2004.

The O’Chiese area in central Alberta yielded production of 161 MMCF of natural gas per day, 6.2 MBbls of NGLs per day and 2.0 MBbls of crude oil per day in 2004. The O’Chiese area was the focus of a $144 million exploration and development program in 2004 that mostly targeted the Lower Cretaceous and Jurassic sands, the principal historical targets. In 2004, 111 wells were drilled.

In the Northern Plains, the Company continued exploration and development activities in the northern Alberta and British Columbia areas. Production in this area during 2004 averaged 83 MMCF of natural gas per day and 2.0 MBbls of NGLs per day. A capital program in this area of $83 million targeted the Bluesky, Gething and Montney formations and 58 wells were drilled during 2004.

In the Kaybob area, production for the year averaged 112 MMCF of natural gas per day, 1.8 MBbls of NGLs per day and 0.8 MBbls of crude oil per day. The Company invested $170 million and 82 wells were drilled during 2004.

The Southern Plains area, which includes the Viking Kinsella property, produced approximately 166 MMCF of natural gas per day, 1.4 MBbls of crude oil per day and 1.2 MBbls of NGLs per day in 2004. In 2004, the Company invested $81 million and 214 wells were drilled in the Southern Plains area.

In 2004, the Company divested its acreage position in the Mackenzie Delta area to focus efforts on Western Canadian Sedimentary Basin opportunities.

International

The Company’s International operations include a combination of exploration opportunities, large field development projects, and production operations. Key focus areas are Northwest Europe, North Africa, China, and South America.

Northwest Europe

The East Irish Sea assets consist of eight licenses covering 163,000 acres. The Company has a 100 percent working interest in seven operated gas fields. First production from two sweet gas fields, Millom and Dalton, commenced in 1999. Net production from the East Irish Sea averaged 87 MMCF of natural gas per day during 2004. The Company invested $53 million of capital in this area during the year.

The development of the sour gas fields in the East Irish Sea continued with first production from Calder in October 2004, representing the first development in the Rivers Fields. Operational issues identified during the startup phase of the Rivers Fields onshore gas processing terminal resulted in the shut down of production from mid-November through the remainder of the year. Production at the Rivers Fields is expected to resume by the second quarter of 2005 and is expected to peak at a sales rate of approximately 100 MMCF of natural gas per day during the year.

The Company’s remaining Northwest European shelf operations consist of non-operated production from the Company’s wholly-owned Netherlands affiliate (“CLAM”) in the Dutch sector of the North Sea. The CLAM assets yielded an annual production rate of 72 MMCF of natural gas per day in 2004.

North Africa

In North Africa, the Company continued with its exploration and development programs in both Algeria and Egypt. The Company benefited from a full year’s production from Algeria Block 405a. Plans for future developments were advanced in both Algeria and Egypt, and the Company completed its exploration program on Algeria Block 402d. The Company’s capital investments in North Africa during 2004 totaled $33 million.

In Algeria, at the Menzel Lejmat North (MLN) Field on Block 405a, where the Company has a 65 percent working interest, activity was primarily focused on stabilizing production from the Company-operated MLN central processing facility. Annual average net oil production was 11.0 MBbls of crude oil per day. One natural gas injection well was successfully drilled and completed during 2004 for reservoir pressure maintenance purposes. In the MLSE area, on the southern portion of the block, development plans for crude oil and natural gas discoveries are being discussed with Sonatrach, the Algerian national oil company.

The Ourhoud Field, in which the Company has a 3.7 percent working interest, produced at an average net rate of 5.5 MBbls of crude oil per day. Five development wells, four injection wells and one water-source well were drilled during 2004, and the waterflood development of this large crude oil field was continued. The Company relinquished its 75 percent working interest in Block 402d in December of 2004.

In Egypt, where the Company has a 50 percent non-operated working interest in the Offshore North Sinai permit, development of the Company’s gas discoveries progressed. An agreement was reached with the Egyptian authorities on a revision to the existing gas sales contract to revise the start date of the project and to bring the pricing structure in line with other Egyptian contracts of this nature. Also, engineering design studies were begun to determine the facilities required to develop the Tao Field and potential satellites. These studies should be completed in 2005.

China

In the Far East, the Company continued its focus on selected basins in China. In 2004, an offshore oil development project achieved the first full year of production and the first phase of a development plan for an onshore gas development received sanctioning and is working toward long-term expansion. The Company invested $42 million in China in 2004.

During the year, the initial development drilling program was completed for the Panyu offshore oil project in the Pearl River Mouth Basin of the South China Sea. The Panyu development involves two offshore oil fields, Bootes and Ursa, located in Block 15/34, in which the Company holds a 24.5 percent working interest. First production was achieved in October 2003, and in 2004 the initial development drilling program was successfully completed. In 2004, the average net production was 19.0 MBbls of crude oil per day.

The Company holds a 100 percent working interest in a natural gas project in the onshore Chuanzhong Block in the Sichuan Basin. In 2004, the Company received government sanctioning of the first phase of development. The project represents an opportunity to apply the Company’s expertise in the development of tight gas reservoirs in an area with substantial reserve potential. During 2004, net production in this area was 5 MMCF of natural gas per day.

South America

The Company’s efforts in South America during 2004 focused on expanding near-term production potential and enhancing long-term exploration opportunities. Net production from South America averaged 6.8 MBbls of crude oil per day and 23 MMCF of natural gas per day. The Company invested $18 million of capital in South America during the year.

In Ecuador, the Company holds a 30 percent working interest in Block 7 and a 37.5 percent working interest in Block 21. Phase II development of the Yuralpa Field in Block 21 is underway following startup in December 2003. Production in this area averaged 4.0 MBbls of crude oil per day during 2004. In Block 7, four wells were successfully drilled during 2004. Net production in Block 7 for the year was 2.6 MBbls of crude oil per day. In Ecuador, the Company’s capital investments in 2004 totaled $12 million.

In Argentina, the Company holds a 25.7 percent working interest in the Sierra Chata concession in the Neuquen Basin. The Company’s net production averaged 23 MMCF of natural gas per day in 2004.

In Peru, the Company entered into an agreement to acquire a 23.9 percent working interest in Block 57, located in the Ucayali Basin. The Company also holds a 23.9 percent working interest in Block 90. In the Marañon Basin, the Company entered into an agreement to farm-in a 45 percent working interest in Block 39 and signed a preliminary agreement to explore and operate Block 104 with a 100 percent working interest. During early 2004, the Company relinquished its interests in Block 87.

In Colombia, the Company holds an exploration contract for a 100 percent working interest in the Orquídea area of the Middle Magdalena Basin. A 3-D seismic acquisition program was completed in November 2004.

Productive Wells

Working interests in productive wells follow.

Net Wells Drilled

The following table sets forth the Company’s net productive and dry wells.

As of December 31, 2004, 331 gross wells, representing approximately 227 net wells, were being drilled or awaiting completion with 71 percent and 29 percent of these wells located in Canada and the U.S., respectively.

Acreage

Working interests in developed and undeveloped acreage follow.

Capital Expenditures

The Company’s capital expenditures follow.

In 2004, worldwide capital expenditures related to oil and gas activities were $1,644 million and included 78 percent associated with development, 17 percent for exploration and 5 percent for proved property acquisitions. Exploration costs expensed under the successful efforts method of accounting are included in capital expenditures for oil and gas activities.

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 daily production and average sales prices follow.

Production Unit Costs

The Company’s production unit costs follow. Production costs include production taxes and well operating costs.

Reserves

The following table sets forth estimates by the Company’s petroleum engineers of proved natural gas, NGLs and crude oil reserves at December 31, 2004. These reserves have been prepared in accordance with the Securities and Exchange Commission’s Regulations. These reserves have been reduced for royalty interests owned by others.

Miller and Lents, Ltd. and Sproule Associates Limited, independent oil and gas consultants, have reviewed the estimates of proved reserves of natural gas, crude oil and NGLs that the Company attributed to its net interests in oil and gas properties as of December 31, 2004. Miller and Lents, Ltd. reviewed the reserve estimates for the Company’s U.S. and International interests and Sproule Associates Limited reviewed the Company’s interests in Canada. Based on their review of more than 80 percent of the Company’s reserve estimates, it is their judgment that the estimates are reasonable in the aggregate. For more information, see independent oil and gas consultants letters on pages 69-73.

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.”

Other Matters

Competition— The Company actively competes for reserve acquisitions, exploration leases and sales of natural gas and crude oil, frequently against companies with substantially larger financial and other resources. In its marketing activities,

the Company competes with numerous companies for the sale of natural gas, NGLs and crude oil. 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. However, based on current standards concerning transportation and storage activities and any proposed or contemplated standards, the Company believes that the impact of such standards is not material to the Company’s operations, capital expenditures or financial position. Compliance with such standards has been incorporated by the Company in its operations over many years and no material capital expenditures are allocated to such compliance.

All of the Company’s sales of its domestic natural gas are currently deregulated, although governmental agencies may elect in the future to regulate certain sales.

Environmental Regulation— Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect the Company’s domestic exploration, development and production operations and the costs of those operations. In addition, 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 and waste management, the reclamation and abandonment of wells, sites and facilities, financial assurance under the Oil Pollution Act of 1990 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.

The environmental laws and regulations applicable to the Company and its operations include, among others, the following United States federal laws and regulations:

In addition, many states and foreign countries where the Company operates have similar environmental laws and regulations covering the same types of matters. In Canada, environmental compliance is governed by various statutes, regulations and codes promulgated at different levels of government including the federal Fisheries Act and Canadian Environmental Protection Act; and provincially, the Environmental Protection and Enhancement Act, the Oil and Gas Conservation Act and the Pipeline Act in the province of Alberta; and the Waste Management Act, the Environmental Assessment Act and the Environment Management Act in the province of British Columbia. The Kyoto Protocol to the United Nations Framework Convention on Climate Change (“Kyoto Protocol”) became effective February 16, 2005, and requires Annex I countries, including Canada and the United Kingdom, to reduce their emissions of carbon dioxide and other greenhouse gases. As a result of the ratification of the Kyoto Protocol and the adoption of legislation or other regulatory initiatives designed to implement its objectives by the national and regional governments, reductions in greenhouse gases from crude oil and natural gas producers may be required which could result in, among other things,

increased operating and capital expenditures for those producers. Until such legislation or other regulatory initiatives are finalized, the impact of the Kyoto Protocol and any such legislation adopted as a result of its ratification remains uncertain.

The Company routinely obtains permits for its facilities and operations in accordance with these applicable laws and regulations on an ongoing basis. There are no known issues that have a significant adverse effect on the permitting process or permit compliance status of any of the Company’s facilities or operations.

The ultimate financial impact of these environmental laws and regulations is neither clearly known nor easily determined as new standards are enacted and new interpretations of existing standards are rendered. Environmental laws and regulations are expected to have an increasing impact on the Company’s operations in the United States and in most countries in which it operates. In addition, any non-compliance with such laws could subject the Company to material administrative, civil or criminal penalties, or other liabilities. Potential permitting costs are variable and directly associated with the type of facility and its geographic location. Costs, for example, may be incurred for air emission permits, spill contingency requirements, and discharge or injection permits. These costs are considered a normal, recurring cost of the Company’s ongoing operations and not an extraordinary cost of compliance with government regulations.

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 maintains insurance coverage for spills, pollution and certain other environmental risks, although it is not fully insured against all such risks. The insurance coverage maintained by the Company provides for the reimbursement to the Company of costs incurred for the containment and clean-up of materials that may be suddenly and accidentally released in the course of the Company’s operations, but such insurance does not fully insure pollution and similar environmental 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, since environmental costs and liabilities are inherent in the Company’s operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.

Filings of Reserve Estimates With Other Agencies— During 2004, the Company filed estimates of its oil and gas reserves for the year 2003 with the Department of Energy. These estimates differ by 5 percent or less from the reserve data presented. For information concerning proved natural gas, NGLs and crude oil reserves, see “Supplementary Financial Information— Supplemental Oil and Gas Disclosures.”

Employees

The Company had 2,214 and 2,111 employees at December 31, 2004 and 2003, respectively. At December 31, 2004, the Company had no union employees.

Web Site Access to Reports

The Company’s Web site address is www.br-inc.com. The Company makes available, free of charge on or through its Web site, its annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, and all amendments to these reports as soon as reasonably practicable after such material is electronically filed with, or furnished to, the United States Securities and Exchange Commission. Such reports, which include the Company’s annual and quarterly financial statements, are also filed in Canada on the System for Electronic Document Analysis and Retrieval (SEDAR) and are also available to the Company’s stockholders, including those residing in Ontario, Canada, from the Company upon request at no charge.

ITEM THREE

LEGAL PROCEEDINGS

See Note 14 of Notes to Consolidated Financial Statements.

ITEM FOUR

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of Burlington Resources Inc.’s security holders during the fourth quarter of 2004.

EXECUTIVE OFFICERS OF THE REGISTRANT

Bobby S. Shackouls, 54— Chairman of the Board, President and Chief Executive Officer, Burlington Resources Inc., July 1997 to present.

Randy L. Limbacher, 46— Office of the Chairman, Burlington Resources Inc., January 2004 to present. Executive Vice President and Chief Operating Officer, Burlington Resources Inc., December 2002 to present. Senior Vice President, Production, Burlington Resources Inc., April 2001 to December 2002. President and Chief Executive Officer, BROG GP Inc., general partner of Burlington Resources Oil & Gas Company LP, December 2000 to July 2001. President and Chief Executive Officer, Burlington Resources Oil & Gas Company, July 1998 to December 2000.

Steven J. Shapiro, 52— Office of the Chairman, Burlington Resources Inc., January 2004 to present. Executive Vice President and Chief Financial Officer, Burlington Resources Inc., December 2002 to present. Senior Vice President and Chief Financial Officer, Burlington Resources Inc., October 2000 to December 2002. Senior Vice President, Chief Financial Officer and Director, Vastar Resources, Inc., 1993 to September 2000.

Mark E. Ellis, 48— Senior Vice President, North American Production, Burlington Resources Inc., September 2004 to present. President, Burlington Resources Canada Ltd., October 2000 to September 2004. Vice President, San Juan Division, Burlington Resources Oil & Gas Company, January 1997 to October 2000.

L. David Hanower, 45— Senior Vice President, Law and Administration, Burlington Resources Inc., July 1998 to present.

John A. Williams, 60— Senior Vice President, Exploration, Burlington Resources Inc., April 2001 to present. Senior Vice President, Exploration, BROG GP Inc., general partner of Burlington Resources Oil & Gas Company LP, December 2000 to present. Senior Vice President, Exploration, Burlington Resources Oil & Gas Company, July 1998 to December 2000.

PART II

ITEM FIVE

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The Company’s common stock, par value $.01 per share (“Common Stock”), is traded on the New York Stock Exchange under the symbol “BR.” Effective at the close of business on January 31, 2005, the Company discontinued the listing of its Common Stock on the Toronto Stock Exchange. At December 31, 2004, the number of record holders of Common Stock was 11,801. Information on Common Stock prices and quarterly dividends is shown on page 79 under the subheading “Quarterly Financial Data— Unaudited.” See also “Equity Compensation Plan Information” under Part III, Item 12 of this report.

Issuer Purchases of Equity Securities(1)

ITEM SIX

SELECTED FINANCIAL DATA

The selected financial data for the Company set forth below should be read in conjunction with the consolidated financial statements and accompanying notes thereto.

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

Overview

The Company is one of the largest independent exploration and production companies in North America. The Company explores for, develops and produces natural gas, NGLs and crude oil, primarily from its properties located in the Rocky Mountain natural gas fairway of North America, complemented by international operations. The Company’s North American activities are concentrated in areas with known hydrocarbon resources, which are conducive to large, multi-well, repeatable drilling programs and the Company’s technical skills. Internationally, the Company is focused on achieving operational efficiencies, while advancing potential growth opportunities in existing positions.

Basin Excellence^SM is the Company’s concept of concentrating its operations and expertise in core areas where it believes it holds significant competitive advantages. These areas are typically in high potential geologic basins with large natural gas and crude oil resources that support multiple-year development programs. These are also areas where the Company holds significant land or mineral interest positions, has teams with years of relevant geologic, geophysical, engineering and operational experience, has access to production, processing and gathering infrastructure and has long-term relationships with partners, suppliers and land and mineral interest owners. The Company believes that it has attained or will ultimately attain this stature in several areas throughout the world that currently represent the majority of its core assets. These assets traditionally yield high returns on investment, and, therefore, the Company has concentrated its activities in these areas and exited other areas that did not meet these standards.

The Company has adopted a disciplined capital allocation process, with the objective of achieving annual volumetric growth (in the range of three to eight percent as a long-term annual average) coupled with strong financial returns.

In managing its business, the Company must deal with numerous risks and uncertainties. These risks and uncertainties can be broadly categorized as: “subsurface,” which includes the presence, size and recoverability of hydrocarbons; “regulatory,” which includes access and permitting necessary to conduct its operations; “operational,” which includes logistical, timing and infrastructure issues, especially internationally, which are often beyond the Company’s control; and “commercial,” which includes commodity price volatility, local price differentials in its various areas of operations and attention to operating margins and the availability of markets for its production, especially natural gas. Each of these factors is challenging and highly variable.

To address subsurface risks, the Company utilizes many of the latest technological tools available to assess and mitigate these risks. These tools include, but are not limited to, modern geophysical data and interpretation software, petrophysical information, physical core data, production histories, paleontology data and satellite imagery. In spite of these technologies, the multitude of unknown variables that exist below the surface of the earth make it difficult to consistently and accurately predict drilling results. The Company has put considerable emphasis in recent years on creating an asset portfolio that improves the reliability of those predictions; however, these types of operations tend to exploit or develop smaller quantities of hydrocarbon reserves and, as a result, the Company must develop more of these opportunities in order to maintain production. Similarly, the Company has reduced its focus on areas where there is far less analytical data available and drilling outcomes are less predictable, such as wildcat exploration operations in sparsely explored areas. The Company is constantly assessing its drilling opportunities to achieve balance in its drilling program for risk and financial returns. In order to make this possible, the Company attempts to maintain a large inventory of drillable projects from which its technical and management teams can select a drilling program in any given period.

On regulatory and operational matters, the Company actively manages its exploration and production activities. The Company values sound stewardship and strong relationships with all stakeholders in conducting its business. The Company attempts to stay abreast of emerging issues to effectively anticipate and manage potential impacts to the Company’s operations.

Managing the commercial risks is an ongoing priority at the Company. Considerable analysis of historical price trends, supply statistics, demand projections and infrastructure constraints form the basis of the Company’s outlook for the commodity prices it may receive for its future production. Because much of this data is dynamic, the Company’s view and the market’s view of future commodity pricing can change rapidly. Based on the Company’s ongoing assessment of the underlying data and the markets, the Company will from time to time use various financial tools to hedge the price it will receive for a particular commodity in the future. The primary purpose of these activities is to enhance financial returns on the significant investments that the Company makes annually to replenish its productive base and grow its reserves while leaving as much commodity price upside as possible for the Company’s stockholders. Margin enhancement is another important element of the Company’s business, including attention to operating costs, administrative expenses and marketing activities, such as securing transportation to alternative market hubs to protect

against weak producing-area prices. The Company may also enter into transportation agreements that allow the Company to sell a portion of its production in alternative markets when local prices are weak.

All of the risks and uncertainties described above create opportunities in the exploration and production business to the extent they drive the relative valuations of three distinct asset classes in the business. The first asset class is the commodities themselves—natural gas, NGLs and crude oil. The prices for this asset class are generally established by the purchasers of these commodities, but closely track the prices that are set through the public trading of futures contracts for those same commodities. The second asset class consists of the physical oil and gas properties that may contain proved, probable and possible reserves, as well as exploratory potential. The value of physical assets is usually established in a private market created by a willing seller and a willing buyer of a given property or group of properties. The third asset class consists of the equities of the publicly traded exploration and production companies that are valued in the public market place daily. Because these three asset classes are not always valued consistently with one another, opportunities may exist from time to time to take advantage of these various valuation differences. These valuation differences are key to the Company’s capital allocation philosophy.

There are three types of investment alternatives that constantly compete for available capital at the Company. These include drilling opportunities, acquisition opportunities and financial alternatives such as share repurchases, dividends and debt repayment. Depending on circumstances and the relative valuations of the asset classes described above, the Company allocates capital among its investment alternatives through an allocation approach that is rate-of-return based. Its goal is to ensure that capital is being invested in the highest return opportunities available at any given time.

Much of what has been described above is conducted and handled routinely. The ability of the Company’s management and staff to take into account all relevant factors, which fluctuate constantly, will be a key determinant in the Company’s future performance.

Outlook

The Company’s business model strives to achieve both production growth and sector-leading financial returns when compared to other independent oil and gas exploration and production companies. This model requires the continuous development of natural gas and crude oil reserves to fuel growth, while maintaining a rigorous focus on cost structure and capital efficiency.

Key to achieving the Company’s financial goals is its disciplined capital investment approach. The Company deploys the net operating cash flows it generates among its core capital programs, as well as for acquisitions and other financial uses, such as share repurchases and dividend payments. Although commodity prices are volatile, the Company generally does not favor increasing or decreasing its capital program in response to commodity prices. Instead, the Company seeks to exercise a disciplined approach in order to keep its cost structure as low as possible.

The Company expects to continue focusing on exploring for and producing North American natural gas as its primary business. The Company expects North America to represent 85 percent of its total production in 2005. While the Company’s management recognizes that the North American natural gas business has many characteristics of a mature, slow-growth business, it believes that finding or acquiring and producing North American natural gas will continue to be a profitable, high-return business for the Company due to certain unique advantages that position it to be successful. First, the Company has long-lived asset positions in gas resource-prone basins and focuses heavily on maintaining a competitive cost structure. Secondly, the Company executes a consistent capital program by employing a capital allocation approach that favors discipline and balance.

The Company’s International business segment is less mature, but has undergone a significant growth phase after several years of developing major projects. The International segment is expected to represent 15 percent of the Company’s total production in 2005 and remain at about that level for the foreseeable future.

Reserve Replacement

Finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to the Company’s long-term success. Given the inherent decline of hydrocarbon reserves resulting from the production of those reserves, it is important for an exploration and production company to demonstrate a long-term trend of more than offsetting produced volumes with new reserves that will provide for future production. Management uses the reserve replacement ratio, as defined below, as an indicator of the Company’s ability to replenish annual production volumes and grow its reserves, thereby providing some information on the sources of future production. The reserve replacement ratio is calculated by dividing the sum of reserve additions from all sources (revisions, extensions, discoveries, and other additions and acquisitions) by the actual production for the corresponding period. The values for these reserve additions are derived directly from the proved reserves table on pages 76-77 in the Supplementary Financial Information section of this report. Accordingly, the Company does not use unproved reserve quantities or proved reserve additions that include both proved reserve additions attributable to consolidated entities and investments accounted for using the equity method in calculating its reserve replacement ratio. It should be noted that

the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries, project sanctioning and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not imbed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

It is also important for an exploration and production company to demonstrate a long-term trend of adding reserves at a reasonable cost. Given that the cost of adding reserves is ultimately included in depreciation, depletion and amortization (“DD&A”) expense, management believes that an ability to add reserves in its core asset areas at a lower cost than its competition should contribute to a sustainable competitive advantage. The Company, in fact, has a goal to achieve 10 to 15 percent lower replacement costs than its competition in North America. Management therefore uses a per unit reserve replacement costs metric, as defined below, as an indicator of the Company’s ability to replenish annual production volumes and grow reserves on a cost-effective basis. Analysts and investors use the measure widely and often cite the measure on a single year basis. In 2004, the Company’s reserve replacement costs were $1.27 per MCFE including acquisitions or $1.27 per MCFE excluding acquisitions. The increase in costs was primarily due to industry service inflation. The Company typically cites reserve replacement costs in the context of a multi-year trend, in recognition of its limitations as a single year measure, but also to demonstrate consistency and stability, which are essential to the Company’s business model. For the three-year period ended December 31, 2004, the Company’s average reserve replacement costs were $1.17 per MCFE including acquisitions and $1.19 per MCFE excluding acquisitions. As used herein, reserve replacement costs represent total oil and gas capital costs, including acquisitions, incurred in order to add reserves. Reserve replacement costs per unit are calculated by dividing total oil and gas capital costs, including acquisitions, by the sum of reserve revisions, extensions, discoveries and other additions and acquisitions. The costs used to calculate reserve replacement costs include the costs of development, exploration and property acquisition activities as presented in the Supplemental Oil and Gas Disclosures table on page 74 of this report.

Set forth below are the Company’s reserve replacement ratio and reserve replacement costs per unit, along with the Company’s capital expenditures.

Capital Expenditures

The Company’s focus on Basin Excellence^sm in established, long-lived core assets results in the majority of its reserve additions coming from development drilling, including extensions from both infill and step-out drilling. Resource assessment studies in targeted areas also result in the addition of proved undeveloped reserves at infill locations in existing producing fields. Reserves added include both proved developed and proved undeveloped components for all periods presented. Over the past two years, the ratio of proved undeveloped reserves to total proved reserves has been about 26 percent. Proved developed reserves will generally begin producing within the year they are added. Proved undeveloped reserves generally require a major future expenditure and it is anticipated that approximately 75 percent of these reserves will begin producing within five years from the date in which the reserves are recorded. Due to the Company’s extensive inventory of potential capital projects, reserve additions are expected to continue in the future, particularly in the Company’s core operating areas, although there are no assurances as to the timing and magnitude of these additions.

In 2005, the Company expects to spend approximately $2 billion of capital, excluding acquisitions. This level of spending represents a 21 percent increase over 2004 capital. The Company currently believes that this level of spending is needed in each of the next few years to achieve its objective of three to eight percent average annual production growth. Approximately 88 percent of the Company’s 2005 capital program is allocated to its North American programs in Canada and the U.S. This capital level in North America represents an increase of approximately 12 percent from prior years. In North America, the Company is allocating a higher percentage of its capital investment to Canada primarily due to an expected increase in drilling activities, higher service costs and a stronger Canadian dollar in 2005.

Below is a discussion of the Company’s production levels and expected production growth.

Production

The Company has a goal to achieve between three and eight percent average annual production growth. In 2004, production volumes were 2,817 MMCFE per day, representing a 10 percent increase over 2003. In 2005, the Company expects production volumes to average between 2,800 and 3,001 MMCFE per day. Production growth is expected to be driven by steady production growth in the U.S. and increased production from international operations.

In 2005, the Company expects production growth in the U.S. as a result of increased production from Cedar Creek, Bossier, south Louisiana and Bakken drilling programs. Internationally, the Company expects increased production at the sour gas fields in the East Irish Sea resulting from the expected resumption of production from the Rivers Fields. Production from the Rivers Fields commenced in October 2004; however, in November 2004, problems were encountered related to the acid plant. Repairs to the plant are progressing and production is expected to resume by the second quarter of 2005. The Company expects production in Canada to decline one to seven percent from production levels in 2004.

While these activities are subject to the risks and delays inherent to this business as discussed above, the Company believes that these sources of production growth are currently available and is now focused on identifying sources of production growth for the future.

Financial Returns

In addition to the Company’s production growth goal, it is committed to generating sector-leading returns on capital employed when compared to other independent oil and gas exploration and production companies. While commodity prices play a significant role in the Company’s financial returns, the Company focuses on controllable elements such as certain operating costs. In 2005, the Company expects to keep its operating and administrative costs about the same as 2004 on a per unit-of-production basis. However, it expects DD&A expense to increase about 14 to 23 percent in 2005 compared to 2004, primarily as a result of higher rates related to Canadian and International properties and unfavorable exchange rate impacts. Other costs could also increase as a result of unfavorable exchange rate impacts. Although subject to the upward cost pressures generally experienced by the industry, the Company believes it can differentiate its performance from that of its peers as a result of several initiatives underway to maintain its diligence on costs, specifically in the areas of purchasing, continuous process improvement, and knowledge transfer. The Company will continue to focus on capital efficiency and cost control.

Below are estimated and actual costs and expenses for 2005 and 2004, respectively.

Transportation expense is expected to be higher in 2005 as a result of resuming production at Rivers Fields in the International operation. This operation is expected to add approximately nine percent to the amount expended for transportation in 2004. Transportation expense for the Company’s remaining operations is expected to increase slightly over 2004. Exploration costs are primarily dependent upon the size of the Company’s drilling program and the success it has in finding commercial hydrocarbons. The Company cannot forecast its expected exploration success rate but it expects exploration costs to exceed the costs incurred in 2004 primarily due to higher anticipated exploration capital spending.

Income Tax Expense

The ratio of current income tax expense to total income tax expense is expected to increase from historical ratios in the Canadian, International and U.S. jurisdictions as a result of the reversal of book tax differences, initiation of production in foreign locations and the exhaustion of Alternative Minimum Tax credit carryforwards.

Commodity Prices

Commodity prices are impacted by many factors that are outside of the Company’s control. Historically, commodity prices have been volatile and the Company expects them to remain that way in the future. Commodity prices are affected by numerous factors, including but not limited to, supply, market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, the Company cannot accurately predict future natural gas, NGLs and crude oil prices, and therefore, it cannot determine what impact increases or decreases in production volumes will have on future revenues or net operating cash flows. However, based on average daily natural gas production in 2004, the Company estimates that a $0.10 per MCF change in natural gas prices would impact annual natural gas revenues approximately $70 million. Also, based on average daily crude oil production in 2004, the Company estimates that a $1.00 per barrel change in crude oil prices would impact annual crude oil revenues approximately $31 million.

Potential Acquisitions

While it is difficult to predict future plans with respect to acquisitions, the Company actively seeks acquisition opportunities that build upon the Company’s existing core asset basins and conform to its Basin Excellence^sm concept. Although the Company does not plan major acquisitions, they play a large role in this industry’s consolidation and must be considered. Generally, acquisitions for the Company fall into one of two categories: bolt-on transactions and other acquisitions. Bolt-on transactions are usually relatively small and involve acquiring properties and assets in areas where the Company already controls a core position. Other acquisitions tend to be transactions that involve the Company acquiring a core position in an area where it either has no position or a relatively small position. In either case, the purpose of acquiring assets is to assist the Company in adding to its existing inventory of future growth opportunities. Depending on the commodity price environment at any given time, the property acquisition market can be extremely competitive. Because of its focus on sector-leading financial returns, the Company takes a disciplined approach to property acquisitions, making it difficult to predict the number and frequency of future transactions.

Financial Condition and Liquidity

The Company’s total debt to total capital (total capital is defined as total debt and stockholders’ equity) ratio at December 31, 2004 and December 31, 2003 was 36 percent and 41 percent, respectively. The 12 percent improvement in this ratio was attributable to the Company’s strong net income and the strength of the Canadian currency partially offset by the repurchase of Common Stock. Based on the current price environment, the Company believes that it will generate sufficient cash from operating activities to fund its 2005 capital expenditures, excluding any potential major acquisition(s). At December 31, 2004, the Company had $2,179 million of cash and cash equivalents on hand, of which $1,200 million was located in Canada, $696 million in the U.S. and $283 million in

International. The Company plans to repatriate $500 million of eligible foreign earnings to the U.S. in 2005 under the one-time provisions of the American Jobs Creation Act of 2004.

Burlington Resources Capital Trust I, Burlington Resources Capital Trust II (collectively, “the Trusts”), BR and Burlington Resources Finance Company (“BRFC”) have a shelf registration statement of $1,500 million on file with the Securities and Exchange Commission (“SEC”). Pursuant to the registration statement, BR may issue debt securities, shares of common stock or preferred stock. In addition, BRFC may issue debt securities and the Trusts may issue trust preferred securities. Net proceeds, terms and pricing of offerings of securities issued under the shelf registration statement will be determined at the time of the offerings. BRFC and the Trusts are wholly owned finance subsidiaries of BR and have no independent assets or operations other than transferring funds to BR’s subsidiaries. Any debt issued by BRFC is fully and unconditionally guaranteed by BR. Any trust preferred securities issued by the Trusts are also fully and unconditionally guaranteed by BR. In 2001, the Company’s Board of Directors authorized the Company to redeem, exchange or repurchase up to an aggregate of $990 million principal amount of debt securities.

The Company has a $1.5 billion revolving credit facility (“Credit Facility”) that includes (i) a US$500 million Canadian subfacility and (ii) a US$750 million sublimit for the issuance of letters of credit, including up to US$250 million in letters of credit under the Canadian subfacility. The Credit Facility expires in July 2009 unless extended. Under the covenants of the Credit Facility, Company debt cannot exceed 60 percent of capitalization (as defined in the agreements). The Credit Facility is available to cover debt due within one year, therefore commercial paper, credit facility notes and fixed-rate debt due within one year are generally classified as long-term debt. At December 31, 2004, there were no amounts outstanding under the Credit Facility and no outstanding commercial paper.

The Company’s access to funds from its Credit Facility is not restricted under any “material adverse condition” clauses. These clauses typically remove the obligation of the lenders to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations or properties considered as a whole, the borrower’s ability to make timely debt payments, or the enforceability of material items of the credit agreement. While the Company’s Credit Facility includes a covenant that requires the Company to report litigation or a proceeding that the Company has determined is likely to have a material adverse effect on the consolidated financial condition of the Company, the obligation of the lenders to fund the Credit Facility is not conditioned on the absence of such litigation or proceeding.

Net cash provided by operating activities in 2004 increased $897 million and $1,887 million over 2003 and 2002, respectively, primarily due to higher commodity prices and higher production volumes partially offset by higher costs and expenses, excluding non-cash expenses. Key drivers of net operating cash flows are commodity prices, production volumes and costs and expenses. Average natural gas prices increased 14 percent and 72 percent over 2003 and 2002, respectively. Crude oil prices increased 33 percent and 50 percent over 2003 and 2002, respectively, while NGLs prices increased 24 percent and 76 percent over the same period. Production volumes increased 10 percent over both 2003 and 2002. Although the Company believes that 2005 production volumes will exceed 2004 levels, it is unable to predict future commodity prices, and as a result cannot provide any assurance about future levels of net cash provided by operating activities. Net cash provided by operating activities in 2004 is not necessarily indicative of future cash flows from operating activities. See page 19 for a discussion of commodity prices.

The increase in net cash provided by operating activities resulting from higher commodity prices and higher production volumes were partially offset by higher costs and expenses. In 2004, costs and expenses that affect net operating cash provided by operating activities primarily include operating costs, taxes other than income taxes, transportation expense, and administrative expenses. These costs and expenses increased $281 million and $410 million over 2003 and 2002, respectively. Operating costs and taxes other than income taxes represented the largest increase in these costs. Operating costs include well operating expenses, which are expenses incurred to operate the Company’s wells and equipment on producing leases. The increase related to well operating expenses accounted for 36 percent and 25 percent of the increase in costs and expenses over 2003 and 2002, respectively. Taxes other than income taxes include severance taxes, which are directly correlated to crude oil and natural gas revenues. The increase related to severance taxes accounted for 22 percent and 29 percent of the increase in costs and expenses over 2003 and 2002, respectively. For revenue, price, volume and costs and expense variances, see tables and explanations on pages 27-29.

Generally, producing natural gas and crude oil reservoirs have declining production rates. Production rates are impacted by numerous factors, including but not limited to, geological, geophysical and engineering matters, production curtailments and restrictions, weather, market demands and the Company’s ability to replace depleting reserves. The Company’s inability to adequately replace reserves could result in a decline in production volumes, one of the key drivers of generating net operating cash flows. The Company’s reserve replacement ratio for the year ended December 31, 2004 was 125 percent and has averaged 142 percent over the last three years. Results for any year are a function of the success of the Company’s drilling program and acquisitions. While program results are difficult to predict, the Company’s current drilling inventory provides the Company opportunities to replace its production in 2005.

The Company has various contractual obligations primarily related to leases for office space, other property and equipment and demand charges on firm transportation agreements for its production of natural gas and crude oil. The Company expects to fund these contractual obligations with cash generated from operations. The following table summarizes the Company’s contractual obligations at December 31, 2004.

The Company also has liabilities of $468 million related to asset retirement obligations on its Consolidated Balance Sheet at December 31, 2004. Due to the nature of these obligations, the Company cannot determine precisely when the payments will be made to settle these obligations. See Note 10 of Notes to Consolidated Financial Statements.

Certain of the Company’s contracts require the posting of collateral upon request in the event that the Company’s long-term debt is rated below investment grade or ceases to be rated. Those contracts primarily consist of hedging agreements and two long-term natural gas transportation agreements. A few of the hedging agreements also require posting of collateral if the market value of the transactions thereunder exceed a specified dollar threshold that varies with the Company’s credit rating. As of December 31, 2004, the Company has a BBB+ long-term debt rating from Standard & Poors and Baa1 Moody’s Investors Service (“Moody’s”) rating. Investment grade is designated as all ratings above BB+ for Standard & Poors and Ba1 for Moody’s.

While the mark-to-market positions under the hedging agreements will fluctuate with commodity prices, as a producer, the Company’s liquidity exposure due to its outstanding derivative instruments tends to increase when commodity prices increase. Consequently, the Company is most likely to have its largest unfavorable mark-to-market position in a high commodity price environment when it is least likely that a credit support requirement due to an adverse rating action would occur. At December 31, 2004, the aggregate unfavorable mark-to-market position under the aforementioned hedging agreements was approximately $11 million. In the case of the Canadian transportation agreements, the collateral required would be an amount equal to 12 months of estimated demand charges. That amount totaled approximately $34 million as of December 31, 2004.

In the normal course of business, the Company has performance obligations which are supported by surety bonds or letters of credit. These obligations are primarily for site restoration and dismantlement, royalty payment appeals and excise tax exemption certifications where governmental organizations require such support.

Changes in credit rating also impact the cost of borrowing under the Company’s Credit Facility, but have no impact on availability of credit under the agreements.

In December 2000, the Company’s Board of Directors (“Board”) authorized the repurchase of up to $1 billion of the Company’s Common Stock. Through April 30, 2003, the Company had repurchased $816 million of its Common Stock under the program authorized in December 2000. In April 2003, the Company’s Board voted to restore the authorization level to $1 billion effective May 1, 2003. Through December 7, 2004, the Company had repurchased $712 million of its Common Stock under the program authorized in April 2003. In December 2004, the Company’s Board again voted to restore the authorization level to $1 billion.

During 2004, the Company repurchased approximately 14 million shares of its Common Stock for approximately $522 million and, as of December 31, 2004, had authority to repurchase an additional $952 million of its Common Stock under the current authorization. As of December 31, 2004, $8 million of the share repurchases were not cash settled; however, $4 million related to 2003 repurchases were settled during the current year. Since December 2000, the

Company has repurchased approximately 61.8 million shares of its Common Stock for $1.6 billion. Share amounts have been adjusted to reflect the 2-for-1 stock split (“split”) of the Company’s Common Stock effective June 1, 2004.

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.

Off-Balance Sheet Arrangements

The Company has off-balance sheet arrangements that it believes have not and are not reasonably likely to have a material current or future effect on the Company’s results of operations, financial condition, liquidity, capital expenditures or capital resources. These off-balance sheet arrangements consist of equity investments in two entities that the Company accounts for under the equity method. The book values of the Company’s interests in Lost Creek Gathering Company, L.L.C. (“Lost Creek”) and Evangeline Gas Pipeline Company (“Evangeline”) are $19 million and $2 million, respectively. As of December 31, 2004, Lost Creek had outstanding debt totaling $42 million and Evangeline had outstanding debt totaling $33 million. Lost Creek and Evangeline’s debts are non-recourse to the Company, and as a result, the Company has no legal responsibility or obligation for these debts. Management believes that Lost Creek and Evangeline are financially stable and therefore will be in a position to repay their outstanding debts.

Capital Expenditures and Resources

Capital expenditures were as follow.

The Company’s consolidated capital expenditures were down 2 percent and 5 percent compared to 2003 and 2002, respectively. Excluding acquisitions, the Company’s capital spending related to internal development and exploration was up 15 and 56 percent compared to 2003 and 2002, respectively. Capital expenditures in 2005, excluding proved property acquisitions, are expected to be approximately $2 billion, up 21 percent over 2004, primarily due to anticipated higher project counts in major operating areas, increased service costs, and higher foreign currency exchange rates, particularly in Canada. The Company believes that 2005 estimated spending is sufficient to add adequate reserves and achieve the target of three to eight percent average annual production growth. Capital expenditures in 2005 are expected to be primarily for internal development and exploration of oil and gas properties. Capital spending in 2005 related to internal development and exploration is expected to be about 22 percent higher than 2004 and is expected to be funded from internally generated cash flows.

During 2002, the Company sold a processing facility and other non-core, non-strategic properties that consisted of high cost structure, high production volume decline rates and limited growth opportunities. As a result of these property sales, the Company generated proceeds, before post closing adjustments, of approximately $1.2 billion and recognized a net pretax gain of $68 million. The producing properties that were sold contributed approximately 230 MMCFE per day during 2002. The Company used a portion of the proceeds generated from property sales to retire debt and for general corporate purposes.

Marketing

North America (U.S. and Canada)

The Company’s marketing strategy is to maximize the value of its production by developing marketing flexibility from the wellhead to its ultimate sale. The Company’s natural gas production is gathered, processed, exchanged and transported utilizing various firm and interruptible contracts and routes to access higher value market hubs. The Company’s customers include local distribution companies, electric utilities, industrial users and marketers. The Company maintains the capacity to ensure its production can be marketed either at the wellhead or downstream at market sensitive prices.

All of the Company’s crude oil production is sold to third parties at the wellhead or transported to market hubs where it is sold or exchanged. NGLs are typically sold at field plants or transported to market hubs and sold to third parties. Downgrades or the inability of the Company’s customers to maintain their credit rating or credit worthiness could result in an increase in the allowance for unrecoverable receivables from natural gas, NGLs or crude oil revenues or it could result in a change in the Company’s assumption process of evaluating collectibility based on situations regarding specific customers and applicable economic conditions.

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 various sales points based on spot or contract prices.

Qualitative and Quantitative Disclosure About Market Risk

Commodity Risk

Substantially all of the Company’s natural gas, NGLs and crude oil production is sold on the spot market or under short-term contracts at market sensitive prices. Spot market prices for domestic natural gas and crude oil 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 North America producing basin or at a North America market hub, which is referred to as “basis differentials.” Basis differentials can vary widely depending on various factors, including but not limited to, local supply and demand.

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 recognizes all derivatives as either assets or liabilities on the balance sheet and measures 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.

The Company uses a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of natural gas and crude oil may have on the fair value of the Company’s derivative instruments. For example, at December 31, 2004, 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 $50 million decrease in the net unrealized gain. The derivative instruments in place at December 31, 2004 hedged approximately 15 percent of the Company’s expected natural gas production volumes through 2005.

For purposes of calculating the hypothetical change in fair value, the relevant variables include the type of commodity, the commodity futures prices, the volatility of commodity prices and the basis and quality differentials. The hypothetical change in fair value is calculated by multiplying the difference between the hypothetical price (adjusted for any basis or quality differentials) and the contractual price by the contractual volumes. As more fully described in Note 1 of Notes to Consolidated Financial Statements, the Company periodically assesses the effectiveness of its derivative instruments in achieving offsetting cash flows attributable to the risks being hedged. Changes in basis differentials or notional amounts of the hedged transactions could cause the derivative instruments to fail the effectiveness test and result in mark-to-market accounting for the affected derivative transactions which would be reflected in the Company’s current period earnings.

Credit and Market Risks

The Company manages and controls market and counterparty credit risk through a system of established internal controls and procedures which are reviewed on a periodic basis. The Company attempts to minimize credit risk exposure to counterparties through formal credit policies and monitoring procedures as well as the use of netting arrangements and requiring letters of credit or parent guarantees, when necessary. Accounts receivable are stated at historical value which approximates fair market value on the Company’s Consolidated Balance Sheet and no single customer of the Company constitutes more than 11 percent of the Company’s accounts receivable balance at December 31, 2004. In the normal course of business, collateral is not required for financial instruments with credit risk. The fair value of the Company’s fixed-rate debt is subject to change based on changes in interest rates. From time to time, the Company enters into financial derivatives to manage this exposure. Based on financial derivative transactions in place as of year-end 2004, a 10 percent adverse move in interest rates (an increase in the underlying interest rates) would result in less than a $1 million increase in interest expense. Additionally, the Company has cash investments that it manages based on internal investment guidelines that emphasize liquidity and preservation of capital, and such cash investments are stated at historical cost which approximates fair market value on the Company’s Consolidated Balance Sheet.

Foreign Currency Risk

The Company has exposure to currency risk in certain of its foreign subsidiaries where the functional currency is the U.S. dollar and where some of the transactions are denominated in the local currency. The Company monitors and manages its exposure to foreign currency risk in these subsidiaries primarily by balancing local currency monetary assets and liabilities. The Company does not actively manage foreign currency risk in its other foreign subsidiaries where the U.S. dollar is not the functional currency, primarily Canada, since the majority of transactions are denominated in the local currency. A substantial amount of the Company’s cash is located in Canada, in Canadian dollars, which provides a natural hedge against foreign currency risk. As of December 31, 2004, the Company had no foreign currency financial derivatives.

Dividends

On January 26, 2005, the Board declared a Common Stock quarterly cash dividend of $0.085 per share, payable April 8, 2005 to shareholders of record on March 9, 2005. During the third quarter of 2004, the Company increased its quarterly cash dividend from $0.075 to $0.085 per share, representing a 13 percent increase. Dividend levels are determined by the Board based on profitability, capital expenditures, financing and other factors. The Company declared and paid cash dividends on Common Stock totaling approximately $125 million and $122 million, respectively, during 2004.

On January 21, 2004, the Company’s Board approved a 2-for-1 split of the Company’s Common Stock in the form of a share distribution, subject to shareholder approval of an amendment to the Company’s Certificate of Incorporation to increase the number of authorized shares from 325 million to 650 million. On April 21, 2004, the Company’s shareholders approved the amendment. As a result, the split was paid in the form of a share distribution on June 1, 2004 to shareholders of record on May 5, 2004.

Application of Critical Accounting Policies

Oil and Gas Reserves

The Company’s estimate of proved reserves reflects quantities of natural gas, NGLs and crude oil which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic conditions. The process of estimating quantities of natural gas, NGLs and crude oil reserves requires judgment in the evaluation of all available geological, geophysical, engineering and economic data, including production data, reservoir pressure data and data collected as a result of development or exploration drilling. Economic and operating conditions, such as product prices, the availability of additional development capital, operating costs, development costs, production tax rates, the installation of additional infrastructure, regulatory approval and actions of domestic or foreign governments influence the estimation of reserves. Any significant variance in these assumptions could materially affect the estimated quantity and value of the Company’s reserves.

The Company has policies and procedures through which the required engineering, geological, and economic data is gathered and proved reserves are estimated. Experienced and qualified Company engineers prepare the reserve estimates. These estimates are subjected to a series of internal reviews to ensure that they are technically and legally justified and therefore reasonable, prepared using generally accepted principles and practices, and comply with SEC Regulations. A corporate staff of engineers conducts oversight and audit of the reserve estimates. Furthermore, the reserve maintenance process requires review and approval of every change to the proved reserve ledger, the most significant requiring approval by the Company’s Chief Engineer.

The Company also engages independent oil and gas engineering consulting firms to review its proved reserves base. The firms determine both the specific properties reviewed and the aggregate magnitude they require for review. Typically, at least 80 percent of the estimated proved reserves receive external review. The Company’s reserve estimates during 2002, 2003, and 2004 were subjected to this external review by the independent oil and gas consultants, who in their judgment determined the estimates to be reasonable in the aggregate. At the conclusion of their external review, the audit firms issue a written opinion and present their findings to the members of the Board of Directors’ Audit Committee. For more information, see the independent oil and gas consultant’s letters on pages 69-73.

Despite the inherent imprecision in these engineering estimates, the Company’s reserves are used throughout its financial statements. As described in Note 1 of Notes to Consolidated Financial Statements, the Company uses the unit-of-production method to amortize its oil and gas properties. Changes in reserve quantities as described above will cause corresponding changes in depletion expense in periods subsequent to the quantity revision or, in some cases, an impairment charge in the period of the revision. Although revisions to reserve estimates in previous years have averaged less than one percent, a five percent negative or adverse revision to the Company’s consolidated proved reserves would result in an increase in annual DD&A expense of approximately $66 million. See the Supplementary Financial Information for reserve data.

Successful Efforts Method of Accounting

The Company accounts for its oil and gas properties using the successful efforts method of accounting. Acquisition and development costs are capitalized and amortized using the unit-of-production method based on total proved and proved developed reserves, respectively, estimated by the Company’s reserve engineers. Changes in reserve quantities as described above will cause corresponding changes in depletion expense in periods subsequent to the quantity revision. Unsuccessful exploration or dry hole wells are expensed in the period in which the wells are determined to be dry and could have a significant effect on results of operations.

Carrying Value of Long-lived Assets

As more fully described in Note 1 of Notes to Consolidated Financial Statements, the Company performs an impairment analysis on its proved properties whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable and annually for the Company’s unproved reserves. Cash flows used in the impairment analysis are determined based upon management’s estimates of proved natural gas, NGLs and crude oil reserves, future natural gas, NGLs and crude oil prices and costs to extract these reserves. Downward revisions in estimated reserve quantities, increases in future cost estimates or depressed natural gas, NGLs and crude oil prices could cause the Company to reduce the carrying amounts of its properties. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Because natural gas, NGLs and crude oil prices are volatile, these estimates are inherently imprecise. A five percent negative or adverse revision to the Company’s proved reserves combined with a 10 percent decline in the natural gas price used to identify fields that are potentially impaired would have resulted in a pretax impairment charge of approximately $105 million ($70 million after tax) for the year ended December 31, 2004. See Note 16 of Notes to Consolidated Financial Statements for impairment of oil and gas properties.

The Company’s lease acquisition costs are not subject to the impairment analysis described above, however, a portion of the costs associated with such properties is subject to amortization on a composite basis based on past experience and average property lives. On an annual basis, the Company monitors the estimated success rate used to determine the amount of lease acquisition costs that are not subject to amortization and makes an adjustment, if needed. Typically, these adjustments do not have a significant impact on future amortization. As these properties are developed and reserves are proven, the remaining capitalized costs are subject to depletion. If the development of these properties is deemed unsuccessful, the capitalized costs related to the unsuccessful activity are expensed in the period the determination is made. The rate at which the unproved properties are written off depends on the timing and success of the Company’s future exploration program.

Asset Retirement Obligations (“ARO”)

The Company has significant obligations to plug and abandon natural gas and crude oil wells and related equipment as well as to dismantle and abandon plants at the end of oil and gas production operations. The Company records the fair value of a liability for ARO in the period in which it is incurred and a corresponding increase in the carrying amount of the related asset. Subsequently, the asset retirement costs included in the carrying amount of the related asset are allocated to expense using a systematic and rational method. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as additional depreciation, depletion and amortization expense in the Consolidated Statement of Income.

Estimating the future ARO requires management to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. The Company uses the present value of estimated cash flows related to its ARO to determine the fair value. The present value calculation includes numerous assumptions and

judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. Abandonment cost estimates are determined by the Company’s reserve engineers based on actual costs incurred to abandon similar wells, and their knowledge of the respective wells. The Company has been unable to determine the accuracy of these estimates due to the limited amount of abandonment activity since the adoption of SFAS No. 143. The Company uses an inflation factor determined by analyzing an industry specific price index that it updates annually. Timing of settlement is based on reserve estimates and is subject to the same inherent imprecision described above for oil and gas reserves. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset. A five percent increase in the Company consolidated ARO would result in a $23 million increase in the Company’s obligation and a $1.5 million increase in annual accretion expense.

Goodwill

As required, the Company performs an annual impairment assessment in lieu of periodic amortization of goodwill. The impairment assessment requires management to make estimates regarding the fair value of the reporting unit to which goodwill has been assigned. The Company determined the fair value of its Canadian reporting unit using a combination of the income approach and the market approach. Under the income approach, the Company estimated the fair value of the reporting unit based on the present value of expected future cash flows. Under the market approach, the Company estimated the fair value based on market multiples of reserves and production for comparable companies.

The income approach is dependent on a number of factors including estimates of forecasted revenue and costs, proved reserves, as well as the success of future exploration for and development of unproved reserves, appropriate discount rates and other variables. Downward revisions of estimated reserve quantities, increases in future cost estimates, divestiture of a significant component of the reporting unit, continued weakening of the U.S. dollar or depressed natural gas, NGLs and crude oil prices could lead to an impairment of all or a portion of goodwill in future periods. In the market approach, the Company makes certain judgments about the selection of comparable companies, comparable recent company and asset transactions and transaction premiums. Although the Company based its fair value estimate on assumptions it believes to be reasonable, those assumptions are inherently unpredictable and uncertain. In 2004, the Company used a professional valuation services firm to assist in preparing its annual valuation of goodwill. At December 31, 2004, the fair value of the Canadian reporting unit exceeded its carrying amount and the use of other reasonable assumptions would not have changed the outcome of the impairment test.

Revenue Recognition

Natural gas, NGLs and crude oil revenues are recorded using the entitlement method. Under the entitlement method, revenue is recorded when title passes based on the Company’s net interest. The Company records its entitled share of revenues based on entitled volumes and contracted sales prices. The sales prices for natural gas, NGLs and crude oil are adjusted for transportation costs and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third-party documents. Historically, these adjustments have been insignificant. Since there is a ready market for natural gas, crude oil and NGLs, the Company sells the majority of its products soon after production at various locations at which time title and risk of loss pass to the buyer.

Legal, Environmental and Other Contingencies

A provision for legal, environmental and other contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is an estimation process that includes the subjective judgment of management. In many cases, management’s judgment is based on the advice and opinions of legal counsel and other advisers, the interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law, the experience of the Company and other companies in dealing with similar matters, and the decision of management on how it intends to respond to a particular contingency (for example, a decision to contest a matter vigorously or a decision to seek a negotiated settlement). The Company’s management closely monitors known and potential legal, environmental and other contingencies and periodically determines when the Company should record losses for these items based on information available to the Company.

Results of Operations

Year Ended December 31, 2004 Compared With Year Ended December 31, 2003

The Company’s consolidated net income increased $326 million or $0.86 diluted earnings per common share (“per share”) in 2004 primarily due to higher commodity prices and higher production volumes. Net income in 2004 and 2003 included charges, net of taxes, of $59 million or $0.15 per share and $38 million or $0.09 per share, respectively,

related to the impairment of oil and gas properties primarily in Canada. Net income in 2004 and 2003 included income tax benefits of $23 million or $0.06 per share and $203 million or $0.51 per share, respectively, related to the reduction of the Canadian federal income tax rate. Net income in 2004 and 2003 also included income tax benefits of $45 million or $0.11 per share and $11 million or $0.02 per share, respectively, related to the reduction of the Alberta provincial corporate income tax rate. In 2004, the Company recorded a U.S. income tax expense of $26 million or $0.07 per share related to the planned repatriation of $500 million of eligible foreign earnings to the U.S. under the one-time provisions of the American Jobs Creation Act of 2004. Net income in 2003 also included a net-of-tax cumulative effect of change in accounting principle charge of $59 million or $0.15 per share related to the adoption of SFAS No. 143, Asset Retirement Obligations. See Note 10 of Notes to Consolidated Financial Statements for more information. Per share amounts for 2003 have been retroactively adjusted to reflect the 2-for-1 split of the Company’s Common Stock effective June 1, 2004.

Below is a discussion of prices, volumes and revenue variances.

Price and Volume Variances

Revenue Variances

Revenues

The Company’s consolidated revenues increased $1,307 million in 2004. Higher revenues were primarily due to higher commodity prices and higher production volumes, resulting in increased revenues of $863 million and $427 million, respectively. Revenue variances related to commodity prices and sales volumes are described below.

    Price Variances

Commodity prices are one of the key drivers of earnings generation and net operating cash flow for the Company. Higher commodity prices contributed $863 million to the increase in revenues in 2004. Average natural gas prices, including a $0.01 realized loss per MCF related to hedging activities, increased $0.66 per MCF during 2004, resulting in increased revenues of $462 million. Average crude oil prices, including a $0.99 realized loss per barrel related to hedging activities, increased $9.03 per barrel in 2004, resulting in increased revenues of $282 million. Average NGLs

prices increased $4.98 per barrel in 2004, resulting in higher revenues of $119 million. As discussed on page 19, commodity prices are affected by many factors that are outside of the Company’s control. Therefore, commodity prices received by the Company during 2004 are not necessarily indicative of prices it may receive in the future. Depressed commodity prices over a significant period of time would result in reduced cash from operating activities potentially causing the Company to expend less on its capital program. Lower spending on the capital program could result in a reduction of the amount of production volumes the Company is able to produce. The Company cannot accurately predict future commodity prices, and cannot be certain whether these events will occur.

    Volume Variances

Sales volumes are another key driver that impact the Company’s earnings and net operating cash flow. Higher sales volumes in 2004 resulted in increased revenues of $427 million. Average crude oil sales volumes increased 38.7 MBbls per day in 2004, resulting in increased revenues of $387 million. The increase in crude oil sales volumes was primarily due to higher production from International’s new project start-ups in late 2003 from fields in offshore China, Algeria and Ecuador, which contributed increased production of 17.9 MBbls per day, 8.6 MBbls per day and 3.9 MBbls per day, respectively, in 2004. Production from the U.S. Cedar Creek Anticline increased 6.6 MBbls per day and the Bakken Shale increased 1.5 MBbls per day in 2004.

Average natural gas sales volumes increased 15 MMCF per day in 2004, resulting in increased revenues of $35 million. Average natural gas sales volumes increased primarily due to higher production from the Madden Field, CLAM in the Dutch sector of the North Sea, and south Louisiana, which contributed increased production of 31 MMCF per day, 29 MMCF per day and 6 MMCF per day, respectively, in 2004. These increases were partially offset by lower production volumes in Canada of 48 MMCF per day. Production volumes in Canada were down primarily due to higher service costs and the Canadian dollar strengthening against the U.S. dollar that led to fewer net wells drilled in 2004 versus 2003, unfavorable weather conditions that impacted program execution during 2004 and lower than expected new well productivity in certain areas. Average NGLs sales volumes increased 0.5 MBbls per day in 2004, resulting in higher revenues of $5 million over 2003.

The Company has a goal to achieve between three and eight percent average annual production growth; therefore, future production volumes are expected to increase over the current period. See discussion under “Outlook” on page 18 for guidance on production volumes. As mentioned above, depressed prices over an extended period of time or other unforeseen events could occur that would result in the Company being unable to sustain a capital program that allows it to meet its production growth goals. However, the Company cannot predict whether such events will occur.

Below is a discussion of total costs and other income—net.

Total Costs and Other Income— Net

Total costs and other income—net increased $573 million in 2004. This increase in total costs and other income—net was primarily due to the items discussed below. The increase in the exchange rate in Canada during 2004 impacted certain costs and expenses for the Company. Changes in the value of the Canadian dollar versus the U.S. dollar could impact costs and expenses in future years. However, at this time, the Company cannot predict what impact the

Canadian exchange rate will have on costs and expenses in the future. See discussion under “Outlook” on page 18 for guidance on costs and expenses in 2005.

DD&A expense increased $210 million primarily due to higher production and higher unit-of-production rates on International properties and higher unit-of-production rates on Canadian properties. Operating costs increased $112 million compared to 2003. This increase is primarily due to higher well operating expenses, which include direct expenses incurred to operate the Company’s wells and equipment on producing leases. Well operating expenses were higher primarily due to increased repair and maintenance expenses, higher workover activity and changes in exchange rates.

Taxes other than income taxes increased $73 million primarily due to higher production taxes resulting from higher crude oil and natural gas revenues. Taxes other than income taxes include severance taxes which are directly correlated to natural gas and crude oil revenues. Administrative expense increased $51 million primarily due to higher stock-based compensation expense, excluding stock options, related to a higher stock price for the Company and higher legal expenses. Transportation expense increased $45 million primarily due to operations related to new start-up projects in late 2003 in International operations and higher rates in Canada. Interest expense increased $22 million primarily due to no capitalized interest incurred on capital projects in 2004.

The Company performs an impairment analysis annually for unproved reserves or whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. Cash flows used in the impairment analysis are determined based upon management’s estimates of natural gas, NGLs and crude oil reserves, future natural gas, NGLs and crude oil prices and costs to extract these reserves. In 2004 and 2003, the Company recorded non-cash charges of $90 million and $63 million, respectively, related to the impairment of oil and gas properties. The impairments in 2004 and 2003 were related to undeveloped properties in Canada and performance-related downward reserve adjustments, also primarily in Canada, respectively.

Exploration costs increased $6 million due to higher geological and geophysical (“G&G”) and other expenses of $20 million partially offset by lower amortization of undeveloped lease costs of $10 million and lower exploratory dry hole costs of $4 million. Exploration expense fluctuates from period to period primarily due to the amount the Company expends on its exploration capital program and its success rate; however, the success rate is difficult to predict. Of the exploratory wells drilled by the Company in 2004, 2003 and 2002, the Company experienced a success rate in the range of approximately 50 to 66 percent during that period of time. These success rates are not necessarily indicative of future rates. The Company capitalizes costs incurred to drill exploratory wells pending determination of whether the wells have found an adequate amount of economically recoverable reserves to be classified as proved. When a determination cannot be made at the time drilling is completed, the costs are deferred until a determination can be made. At December 31, 2004, $23 million of deferred exploration costs were included in oil and gas properties on the Company’s Consolidated Balance Sheet. Some or all of these costs could be included in exploration expense in future periods. In 2004 and 2003, $14 million and $7 million, respectively, were reclassified from oil and gas properties to exploration expense.

Income Tax Expense

Income tax expense increased $467 million in 2004, primarily due to an increase in pretax income of $734 million. In 2004, the Company recorded $26 million of U.S. income tax expense related to its plan to repatriate $500 million of eligible foreign earnings under the one-time provisions of the American Job Creation Act of 2004. In addition, income taxes on foreign earnings in excess of the U.S. tax rate resulted in an increase in tax expense of $19 million in 2004. The reduction of the Canadian federal income tax rate resulted in an income tax benefit of $45 million in 2004 compared to a benefit of $203 million in 2003. The reduction of the Alberta provincial corporate income tax rate resulted in an income tax benefit of $23 million in 2004 compared to a benefit of $11 million in 2003. The Company also recorded a net tax benefit of $10 million in 2004 related to the settlement of the 1999-2000 audits of its Section 29 Tax Credits, and recorded a net tax benefit of $27 million in 2003 related to the settlements of the 1996-1998 audits of its Section 29 Tax Credits. As a result of the increase in exchange rates, the Company recorded higher tax benefits of $7 million related to interest deductions allowed in both the U.S. and Canada on transactions associated with cross-border financing. The deduction for interest on the cross-border financing is allowable in both the U.S. and Canada because the issuer of the debt is a wholly-owned finance subsidiary of the Company and the activities of the finance subsidiary are taxable in both the U.S. and Canada. Substantially all of the increase in the tax benefit of the cross-border financing deduction from 2003 to 2004 was due to the strengthening of the Canadian dollar. This benefit is not expected to fluctuate in the future for reasons other than changes in exchange rate and debt levels.

Year Ended December 31, 2003 Compared With Year Ended December 31, 2002

The Company’s consolidated net income increased $747 million or $1.87 per share in 2003 primarily due to higher commodity prices. Net income in 2003 included tax benefits of $203 million or $0.51 per share and $11 million or $0.02 per share related to the reduction of the Canadian federal income tax and the Alberta provincial corporate income tax rates, respectively. Net income in 2002 included a tax benefit of $26 million or $0.06 per share related to the reduction of the Alberta provincial corporate income tax rate in Canada and the reversal of a tax valuation reserve of

$27 million or $0.07 per share related to the sale of assets in the United Kingdom (“U.K.”) sector of the North Sea. Per share amounts for 2003 and 2002 have been retroactively adjusted to reflect the 2-for-1 split of the Company’s Common Stock effective June 1, 2004.

Below is a discussion of prices, volumes and revenue variances.

Price and Volume Variances

Revenue Variances

Revenues

The Company’s consolidated revenues increased $1,343 million in 2003. Higher revenues were primarily due to higher commodity prices, resulting in increased revenues of $1,322 million. Revenues also increased $26 million due to higher processing and other revenues. Processing and other revenues increased $20 million and $19 million, respectively, due to ineffectiveness of cash-flow and fair-value hedges and changes in fair value instruments that do not qualify for hedge accounting. The amounts were partially offset by a decrease of $18 million related to lower sales volumes and $19 million related to the sale of a processing facility in June 2002. The revenue variances related to commodity prices and sales volumes are described below.

    Price Variances

Commodity prices are one of the key drivers of earnings and net operating cash flow generation. Higher commodity prices contributed $1,322 million to the increase in revenues in 2003. Average natural gas prices, including a $0.09 realized loss per MCF related to hedging activities, increased $1.63 per MCF in 2003 resulting in increased revenues of $1,129 million. Average NGLs prices increased $5.94 per barrel in 2003, resulting in higher revenues of $140 million. Average crude oil prices, including a $0.09 realized loss per barrel related to hedging activities, increased $3.11 per barrel in 2003, resulting in increased revenues of $53 million. See page 19 for a discussion of commodity prices.

    Volume Variances

Sales volumes are another key driver that impact the Company’s earnings and net operating cash flow generation. Lower sales volumes in 2003 resulted in a decline in revenues of $18 million. Average crude oil sales volumes

decreased 2.6 MBbls per day in 2003, reducing revenues $23 million. Average crude oil sales volumes decreased 13.8 MBbls per day primarily due to asset sales in 2002 in the Gulf of Mexico, Canada, the U.K. sector of the North Sea and the Williston Basin. This decrease in crude oil sales volumes was partially offset by an increase of 10.8 MBbls per day resulting from higher production at Ourhoud Field and the Company-operated MLN Field in Algeria, south Louisiana and Cedar Creek. Average natural gas sales volumes decreased 17 MMCF per day in 2003, resulting in decreased revenues of $20 million. Average natural gas sales volumes decreased 108 MMCF per day primarily due to asset sales in 2002 in the Gulf of Mexico, the U.K. sector of the North Sea and Sonora. This decrease in natural gas sales volumes was partially offset by an increase of 93 MMCF per day primarily as a result of the drilling programs in Canada and the Fort Worth Basin. Average NGLs sales volumes increased 4.7 MBbls per day in 2003, resulting in higher revenues of $25 million year over year. Average NGLs sales volumes increased 4.8 MBbls per day in the San Juan Basin and the Fort Worth Basin.

Below is a discussion of total costs and other income— net.

Total Costs and Other Income— Net