Washington, D.C. 20549

FORM 10-K

þ    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2005

OR

o    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) 624-9000

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

Common Stock, par value $.01 per share

and 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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes þ         No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes o         No þ

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 þ         No o

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.    þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. (See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act). (Check one):

Large accelerated filer þ         Accelerated filer o         Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes o         No þ

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 31, 2006 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, 2006: $34,302,471,138 and as of June 30, 2005: $21,049,071,247.

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, 2006, Shares Outstanding: 375,876,300

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:

Information required by Part III will either be included in Burlington Resources Inc. definitive proxy statement filed with the Securities and Exchange Commission or filed as an amendment to this Form 10-K no later than 120 days after the end of the Company’s fiscal year, to the extent required by the Securities Exchange Act of 1934, as amended.

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.

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 lease operating or well operating expenses, 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.

Taxes other than income taxes include severance taxes, ad valorem taxes, franchise and payroll taxes.

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.

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 the 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.

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, the United Kingdom, the Netherlands, North 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., Burlington Resources Canada (Hunter) Ltd. (formerly known as Canadian Hunter Exploration Ltd.) (“Hunter”), and their affiliated companies (collectively, “the Company”).

On December 12, 2005, BR and ConocoPhillips entered into a definitive agreement under which ConocoPhillips will acquire BR. Under the terms of the agreement, BR shareholders will receive $46.50 in cash and 0.7214 shares of ConocoPhillips common stock for each BR share they own. The transaction is subject to approval by BR shareholders of record on February 24, 2006 and other customary terms and conditions. A special meeting of shareholders to vote on the proposed merger is March 30, 2006. Regulatory approvals have been granted and, upon approval by shareholders, the transaction is expected to close by March 31, 2006.

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 the 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 and mineral acreage in this area with over 866,000 net acres under its control. The Company operates over 7,700 well completions in the San Juan Basin and holds interests in an additional 5,000 non-operated well completions.

In 2005, the Company invested $164 million in oil and gas capital, excluding acquisitions, drilled or participated in drilling 374 new wells and performed 134 workovers on existing wells. The Company’s net production from the San Juan Basin averaged approximately 514 MMCF of natural gas per day, 31.3 MBbls of NGLs per day and 1.1 MBbls of crude oil per day during 2005.

The Company continues to pursue development opportunities in the three conventional formations (Mesaverde, Pictured Cliffs and Dakota) in the San Juan Basin. 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 2005, the Company continued its ongoing infill drilling program in this formation. In 2005, the Company drilled or participated in drilling 226 conventional wells on 160-acre and 80-acre spacing. Net production from the tight gas producing formations averaged 327 MMCF of natural gas per day, 30.3 MBbls of NGLs per day and 1.1 MBbls of crude oil per day in 2005.

In the Fruitland Coal, the Company drilled or participated in drilling 148 wells on 320-acre and 160-acre spacing during 2005. In 2005, net production from the Fruitland Coal averaged 187 MMCF of natural gas per day and 1.0 MBbls of NGLs per day from over 2,100 completions.

On the Negro Canyon leasehold purchased in 2004, which is located in the heart of the Company’s Fruitland Coal producing area, the Company drilled eight Fruitland Coal wells and one Dakota well in 2005 and expects to fully develop the remaining leases by the end of 2006. The Company owns a 100 percent working interest and an 87.5 percent net revenue interest in the 1,242 acre tract.

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 127 MMCF of natural gas per day in 2005 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 2005 totaled $48 million for 65 newly drilled wells and workover projects. The Company owns an approximate 48 percent working interest in the Lost Cabin Gas Plant and net revenue interests varying from 22 to 40 percent in the producing reservoirs.

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 2005. Total Williston Basin production averaged 34.0 MBbls of crude oil per day and 11 MMCF of natural gas per day. During 2005, the Company invested $152 million on projects in the Williston Basin.

The Company continued its highly active waterflood development program with 160-acre infill drilling at both the Cedar Hills South and East Lookout Butte Units. A total of 43 production 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, drilling continued in the siltstone of the Bakken Shale formation where 34 wells were drilled in Richland County, Montana and two wells in McKenzie County, North Dakota. The Company currently controls over 98,000 net acres including areas in these two counties.

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 ranging in depth from 11,000 feet to over 21,000 feet. Net production for 2005 from the Anadarko Basin averaged 72 MMCF of natural gas per day and 2.0 MBbls of NGLs per day. During 2005, the Company invested $100 million in the Anadarko Basin. Operated activity focused on the Red Fork and Atoka formations in Roger Mills and Washita counties, Oklahoma, where the Company drilled 107 wells.

Permian Basin

Permian Basin operations, in west Texas, are focused on the Waddell Ranch Field. Total Permian Basin net production in 2005 averaged 12 MMCF of natural gas per day, 3.8 MBbls of crude oil per day and 2.6 MBbls of NGLs per day, with the Waddell Ranch Field contributing 8 MMCF of natural gas per day, 2.7 MBbls of crude oil per day and 2.5 MBbls of NGLs per day. During 2005, the Company invested $7 million in the Permian Basin operations.

Fort Worth Basin

In the Fort Worth Basin of north central Texas, the Company continued to develop its Barnett Shale formation acreage in Denton and Wise counties, Texas. Additional acreage was also acquired during 2005 in mostly Johnson, Hood, Parker, and Palo Pinto counties, Texas. The Company now controls 102,000 net acres in the Fort Worth Basin. During 2005, the Company invested $137 million in this area, excluding acquisitions, and drilled 92 wells. Net production averaged 41 MMCF of natural gas per day, 4.4 MBbls of NGLs per day and 1.0 MBbls of crude oil per day in 2005.

The Onshore Gulf Coast includes operations in a number of drilling trends in east Texas, south Louisiana, the Onshore Gulf of Mexico and the Florida panhandle where the Company invested $344 million and drilled 70 wells. Net production in 2005 averaged 169 MMCF of natural gas per day, 9.0 MBbls of crude oil per day and 1.1 MBbls of NGLs per day.

In south Louisiana, the Company owns 660,000 net acres of fee lands with both surface and mineral rights. The Company spent $156 million of capital in south Louisiana during 2005 and drilled 43 wells. Net production in south Louisiana averaged 89 MMCF of natural gas per day, 6.6 MBbls of crude oil per day and 0.7 MBbls of NGLs per day in 2005.

In the Bossier trend, the Company controlled over 177,000 net acres at year end, and is expanding beyond its successful Savell Field development with other exploration and development activities along the trend. The Company spent $151 million of capital, drilled 18 wells, and had five operated rigs drilling at year end. In 2005, net production averaged 76 MMCF of natural gas per day in the Bossier.

Canada

Western Canadian Sedimentary Basin

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

Canadian operations in 2005 were focused on expanding activity into large-scale, repeatable drilling programs in conventional and lower permeability reservoirs. Oil and gas capital investments in Canada were $1,143 million, excluding acquisitions, and 878 wells were drilled. Production in Canada was 804 MMCF of natural gas per day, 24.2 MBbls of NGLs per day and 6.0 MBbls of crude oil per day during 2005. The Company continued its resource assessment studies to identify future drilling opportunities across the Sedimentary Basin during 2005.

The Deep Basin area, in Alberta and British Columbia, consists of the Elmworth, Wapiti, Noel and Brassey Fields. In 2005, a $408 million oil and gas capital program was focused on exploration and development in the Deep Basin area. As a result, 254 wells were drilled and 241 MMCF of natural gas per day and 13.6 MBbls of NGLs per day were produced from this area.

In the Foothills area, which borders on the west side of the Deep Basin, $76 million of oil and gas capital spending was focused on exploration and development and production was 52 MMCF of natural gas per day. In 2005, 16 wells were drilled.

The O’Chiese area, in central Alberta, yielded production of 150 MMCF of natural gas per day, 5.7 MBbls of NGLs per day and 2.4 MBbls of crude oil per day in 2005. The O’Chiese area was the focus of a $205 million exploration and development program in 2005 that mostly targeted the Lower Cretaceous and Jurassic sands, the principal historical targets. In 2005, 144 wells were drilled.

In the Northern Plains, the Company continued exploration and development activities in the northern Alberta and British Columbia areas. Production in the Northern Plains during 2005 averaged 75 MMCF of natural gas per day and 2.2 MBbls of NGLs per day. A $79 million capital program targeted the Bluesky, Gething and Montney formations and 77 wells were drilled during 2005.

In the Kaybob area, production for the year averaged 122 MMCF of natural gas per day, 1.9 MBbls of NGLs per day and 0.9 MBbls of crude oil per day. The Company invested $249 million and drilled 131 wells in this area during 2005.

The Southern Plains area, which includes the Viking Kinsella property, produced approximately 156 MMCF of natural gas per day, 1.4 MBbls of crude oil per day and 0.8 MBbls of NGLs per day in 2005. In 2005, the Company invested $99 million and drilled 233 wells in the Southern Plains area.

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

Northwest Europe

In the East Irish Sea, the Company has a 100 percent working interest in seven operated gas fields, including Millom and Dalton producing gas fields and the Rivers sour gas fields. Net production from the East Irish Sea averaged 68 MMCF of natural gas per day during 2005. The Company invested $23 million of capital in this area during the year. At the Rivers Fields, the Company continued the remedial work related to the onshore terminal and production is expected to resume during the first quarter of 2006. This facility is capable of reaching a peak sales rate of approximately 100 MMCF of natural gas per day.

During 2005, four wells were drilled in the East Irish Sea. One well in the Dalton Field found sub-commercial quantities of gas and was plugged and abandoned. Three other wells, on the Kelly, Darwen East and Asland North prospects failed to encounter gas in commercial quantities and were also plugged and abandoned.

The Company’s Northwest European shelf investments also consist of non-operated production from its wholly-owned Netherlands affiliate in the Dutch sector of the North Sea. In 2005, the Netherlands affiliate “CLAM” was renamed Burlington Resources Nederland Petroleum B.V. (“BRN”). The BRN assets yielded an average production rate of 57 MMCF of natural gas per day during the year. BRN also owns an interest in an exploration license in Denmark. License 01/04 in the Danish sector comprises 11 blocks or partial blocks. The Company holds a 40 percent interest in the blocks. In 2005, a total of 2,077 kilometers of 2D seismic was acquired by DONG, the operator of the blocks.

North Africa

In North Africa, the Company continued progress in its development programs in both Algeria and Egypt and approved plans for future developments in both locations. The Company’s capital investments in North Africa during 2005 totaled $49 million.

In Algeria, at the Menzel Lejmat North (“MLN”) Field on Block 405a, where the Company operates and has a 65 percent working interest, net production averaged 11.8 MBbls of crude oil per day. During 2005, the Company approved the MLN Expansion Project which is expected to increase field production and reserves through additional pressure maintenance. One development well was drilled in the area in 2005.

The Ourhoud Field, where the Company has a 3.7 percent working interest, produced at an average net rate of 4.8 MBbls of crude oil per day in 2005. Six development wells, two injection wells and one water-source well were drilled during 2005, and the waterflood development of this large crude oil field was continued.

Development of oil reserves in the southern MLSE area of Block 405a progressed with partners agreeing to form the EMK oil field unit where the Company currently has a minority interest in the unit. The partners have initiated engineering studies and drilling activities with the expectation of finalizing the development plan for the field in 2006. Capital spending in 2005 was $4 million and two wells were drilled.

In Egypt, where the Company has a 50 percent non-operated working interest in the Offshore North Sinai concession, development of the Tao Gas Field was approved by the Company during 2005. Detailed engineering studies are under way for the facilities and pipelines, and plans are being developed to commence drilling in 2006.

In the Far East, the Company continued its focus on selected basins in China. The Company entered its second full year of production at the Panyu Field in the South China Sea and continued to pursue the first phase of its development plan for its onshore gas development in the Sichuan Basin. The Company made capital investments of $53 million in China in 2005.

The Panyu development involves two offshore oil fields, Bootes and Ursa, located in Block 15/34 in the Pearl River Mouth Basin. The Company holds a 24.5 percent working interest in this asset. During 2005, the second phase of the development drilling program was initiated. Government sanctioning was also received and work commenced on a $5 million facilities upgrade to handle the additional fluid volumes expected. In addition, the plan of development was submitted to the government for the PY 11-6 discovery which will be produced from the Bootes platform. In 2005, average net production was 15.1 MBbls of crude oil per day.

Onshore, the Company holds a 100 percent working interest in a natural gas project in the Chuanzhong Block in the Sichuan Basin. The project represents an opportunity to apply the Company’s expertise in the development of tight gas sand reservoirs. During 2005, the Company increased its net production from 4 MMCF of natural gas per day to 8 MMCF of natural gas per day. Average annual net production in 2005 was 6 MMCF of natural gas per day.

South America

The Company’s efforts in South America during 2005 were concentrated on expanding near-term production potential and enhancing long-term exploration opportunities. Net production from South America averaged 5.9 MBbls of crude oil per day and 21 MMCF of natural gas per day. The Company invested $38 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. Development of the Yuralpa Field in Block 21 continues where 11 wells were drilled during 2005. Net production from Block 21 averaged 3.3 MBbls of crude oil per day. In Block 7, six wells were successfully drilled during the year. Net production from Block 7 was 2.5 MBbls of crude oil per day. The Company’s capital investments in 2005 totaled $26 million for projects in Ecuador.

In Argentina, the Company holds a 25.7 percent working interest in the Sierra Chata concession in the Neuquen Basin. Three development wells were drilled during 2005. Net production averaged 21 MMCF of natural gas per day in 2005 and capital investments in Argentina totaled $2 million.

In Peru, the Company holds a 45 percent working interest in Block 39 and operates Block 104 in the Marañon Basin with a 100 percent working interest. The Company participated in a discovery on Block 39 with the drilling of the Buena Vista #1 well which tested a gross 2.5 MBbls of crude oil per day from two zones. Additional drilling is expected to determine whether there are sufficient reserves in the area to allow commercial development to proceed. The Company also holds a 23.9 percent working interest in Blocks 57 and 90 located in the Ucayali Basin. The Company’s capital investments in Peru totaled $9 million during 2005.

In Colombia, the Company holds an exploration contract for a 100 percent working interest in the Orquídea area of the Middle Magdalena Basin.

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, 2005, 380 gross wells, representing approximately 281 net wells, were being drilled or awaiting completion with 67 percent and 31 percent of these wells located in Canada and the U.S., respectively.

Working interests in developed and undeveloped acreage follow.

Capital Expenditures

The Company’s capital expenditures follow.

In 2005, worldwide capital expenditures related to oil and gas activities were $2,614 million and included 70 percent associated with development, 18 percent for exploration and 12 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.

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.

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, 2005. 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, 2005. 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 68-72.

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.”

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 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 2005, the Company filed estimates of its oil and gas reserves for the year 2004 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 2,416 and 2,214 employees at December 31, 2005 and 2004, respectively. At December 31, 2005, 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.

RISK FACTORS

Business Uncertainties and Contractual Restrictions While Merger is Pending— Uncertainty about the effect of the merger on employees, suppliers, partners, regulators and customers may have an adverse effect on BR. These uncertainties may impair BR’s ability to attract, retain and motivate key personnel until the merger is consummated, and could cause suppliers, customers and others that deal with BR to defer purchases or other decisions concerning BR, or seek to change existing business relationships with BR. Employee retention may be particularly challenging while the merger is pending, as employees may experience uncertainty about their future roles with ConocoPhillips. In addition, the merger agreement restricts BR from making certain acquisitions and taking other specified actions without ConocoPhillips’ approval. These restrictions could prevent BR from pursuing attractive business opportunities that may arise prior to the completion of the merger.

Failure to Complete Merger Could Negatively Impact Stock Price, Future Business and Financial Results— Although BR has agreed that its board of directors will, subject to fiduciary exceptions, recommend that its stockholders approve and adopt the merger agreement, there is no assurance that the merger agreement and the merger will be approved, and there is no assurance that the other conditions to the completion of the merger will be satisfied. If the merger is not completed, BR will be subject to several risks, including the following:

Changes in Commodity Prices Could Have a Significant Adverse Effect on Financial Results, Impact the Company’s Determination of Proved Reserves and Result in the Company Recognizing an Impairment— Changes in natural gas, NGLs and crude oil prices (including basis differentials) from those assumed in preparing projections and forward-looking statements could cause the Company’s actual financial results to differ materially from projected financial results and could also impact the Company’s determination of proved reserves and the standardized measure of discounted future net cash flows relative to natural gas, NGLs and crude oil reserves. In addition, periods of sharply lower commodity prices could affect the Company’s production levels, could cause it to curtail capital spending projects and delay or defer exploration, exploitation or development projects, could render productive wells non-commercial earlier than in a higher price environment and could result in the Company recognizing for Generally Accepted Accounting Principles purposes an impairment of unamortized capital costs.

Projections relating to the price received by the Company for natural gas and NGLs also rely on assumptions regarding the availability and pricing of transportation to the Company’s key markets. In particular, the Company has contractual arrangements for the transportation of natural gas from the San Juan Basin eastward to Eastern and Midwestern markets or to market hubs in Texas, Oklahoma and Louisiana. The natural gas price received by the Company could be adversely affected by any constraints in pipeline capacity to serve these markets. These and other commodity price risks that could cause actual results to differ from projections and forward-looking statements are further described in Part II, “Qualitative and Quantitative Disclosure About Market Risk-Commodity Risk.”

Risks and Uncertainties Normally Associated with the Exploration for and Development and Production of Natural Gas Could Significantly Impact the Company’s Operations and Financial Results— The Company’s business is subject to all of the risks and uncertainties normally associated with the exploration for and development and production of natural gas, NGLs and crude oil, including uncertainties as to the presence, size and recoverability of hydrocarbons. The exploration for natural gas and crude oil is a high-risk business in which significant numbers of dry holes, completion and production difficulties and high associated costs can be incurred in the process of seeking commercial discoveries and placing them on production.

The process of estimating quantities of proved reserves is inherently uncertain and requires making subjective engineering, geological, geophysical and economic assumptions. In this regard, changes in the economic conditions (including commodity prices) or operating conditions (including, without limitation, exploration, development and production costs and expenses and drilling and production results from exploration and development activity) could cause the Company’s estimated proved reserves or production to differ from those included in any such forward-looking statements or projections. Reserves which require the use of

In addition, 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. Estimating the costs of these obligations requires management to make estimates and judgments regarding timing, existence of a liability as well as what constitutes adequate restoration. Increases in the estimated costs of decommissioning and abandoning a proved property or production facilities above previously forecasted levels could cause the Company’s estimated proved reserves to decrease from those included in forward-looking statements.

Projecting future natural gas, NGLs and crude oil production is imprecise. Producing oil and gas reservoirs eventually have declining production rates. Projections of production rates rely on certain assumptions regarding historical production patterns in the area or formation tests for a particular producing horizon. Actual production rates could differ materially from such projections. Production rates depend on a number of additional factors, including commodity prices, market demand and the political, economic and regulatory climate. In addition, Organization of Petroleum Exporting Countries in which the Company has producing properties, such as Algeria, could subject the Company to periods of curtailed production due to governmental mandated cutbacks when world oil market demand is weak.

Another major factor affecting the Company’s production is its ability to replace depleting reservoirs with new reserves through acquisition, exploration or development programs. Exploration success is extremely difficult to predict with certainty, particularly over the short term where the timing and extent of successful results vary widely. Over the long term, the ability to replace reserves depends not only on the Company’s ability to locate crude oil, NGLs and natural gas reserves, but on the cost of finding and developing such reserves. Moreover, development of any particular exploration or development project may not be justified because of the commodity price environment at the time or because of the Company’s finding and development costs for such project. No assurances can be given as to the level or timing of success that the Company will be able to achieve in acquiring or finding and developing additional reserves.

Projections relating to the Company’s production and financial results rely on certain assumptions about the Company’s continued success in its acquisition and asset rationalization programs and in its cost management efforts.

The Company’s drilling operations are subject to various hazards common to the oil and gas industry, including weather conditions, explosions, fires, and blowouts, which could result in damage to or destruction of oil and gas wells or formations, production facilities and other property and injury to people. They are also subject to the additional hazards of marine operations, such as capsizing, collision and damage or loss from severe weather conditions.

Concentration Risk for Natural Gas Transportation— Because the Company transports a significant amount of its natural gas production through a limited number of pipeline systems, mechanical failure or regulatory action at certain points on these pipeline systems could result in a substantial interruption of the transportation of the Company’s natural gas production for a limited period of time pending the Company securing alternate transportation arrangements.

Assumptions Used in Valuing Goodwill Are Inherently Unpredictable and Uncertain and Revisions to Estimates Could Lead to an Impairment in Future Periods— The Company accounts for goodwill in accordance with Statement of Financial Accounting Standards No. 142, Goodwill and other Intangible Assets, and is required to make an annual impairment assessment in lieu of periodic amortization. The impairment assessment requires the Company to make estimates regarding the fair value of the reporting unit to which goodwill has been assigned. Although the Company bases its fair value estimate on assumptions it believes to be reasonable, those assumptions are inherently unpredictable and uncertain. 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 goodwill in future periods.

Numerous Factors Affecting the Timing and Outcome of Projects Could Have a Significant Adverse Impact on the Company’s Development Plan— A significant portion of the Company’s development plans involve large projects in Canada, Algeria, the East Irish Sea, China, Ecuador, Wyoming, North Dakota and other areas. A variety of factors affect the timing and outcome of such projects including, without limitation, approval by the other parties owning working interests in the project, receipt of necessary permits and approvals by applicable governmental agencies, access to surface locations and facilities, opposition by non-government organizations and local indigenous communities, the availability, costs and performance of the necessary drilling equipment and infrastructure, drilling risks, operating hazards, unexpected cost increases and technical difficulties in constructing, modifying and operating equipment, plants and facilities, manufacturing and delivery schedules for critical equipment and arrangements for the gathering and transportation of the produced hydrocarbons.

The Company’s International Operations Are Subject to Risks Which May Adversely Affect the Company’s Operations— The Company’s operations outside of the U.S. are subject to risks inherent in foreign operations, including, without limitation, the loss of revenue, property and equipment from hazards such as expropriation, nationalization, war, insurrection, acts of terrorism and other political risks, increases in taxes and governmental royalties, renegotiation or abrogation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations, world economic cycles, restrictions or quotas on production and commodity sales, limited market access and other

The Company’s ability to market natural gas, NGLs and crude oil discovered or produced in its foreign operations, and the price the Company could obtain for such production, depends on many factors beyond the Company’s control, including ready markets for natural gas, NGLs and crude oil, the proximity and capacity of pipelines and other transportation facilities, fluctuating demand for crude oil and natural gas, the availability and cost of competing fuels, and the effects of foreign governmental regulation of oil and gas production and sales. Pipeline and processing facilities do not exist in certain areas of exploration and, therefore, any actual sales of the Company’s production could be delayed for extended periods of time until such facilities are constructed.

Competition in the Crude Oil and Natural Gas Industry is Intense; the Company Competes with Companies with Substantially Larger Financial and Other Resources— The Company actively competes for property acquisitions, exploration leases and sales of natural gas, NGLs and crude oil, frequently against companies with substantially larger financial and other resources. In its marketing activities, the Company competes with numerous companies for gas purchasing and processing contracts and for natural gas and NGLs at several stages in the distribution chain. Competitive factors in the Company’s business include price, contract terms, quality of service, pipeline access, transportation discounts and distribution efficiencies.

Foreign, National, State and Local Laws and Regulations Could Negatively Impact the Company’s Operations or Financial Results— The Company’s operations are affected by foreign, national, state and local laws and regulations. Compliance with these regulations is often difficult and costly and non-compliance could subject the Company to material administrative, civil or criminal penalties, or other liabilities. Restrictions on production, price or gathering rate controls, changes in taxes, royalties and other amounts payable to governments or governmental agencies and other changes in or litigation arising under laws and regulations, or interpretations thereof, could have a significant effect on the Company’s operations or financial results. The Company’s operations in some geographic areas may be negatively impacted by legal proceedings, the actions of national, state and local governments, and the actions of non-governmental organizations that delay, restrict or prevent the Company’s access to surface locations for natural gas and crude oil exploration and production activities. The Company’s operations also may be negatively impacted by laws, regulations and legal proceedings pertaining to the valuation and measurement of natural gas, crude oil and NGLs and payment of royalties from such sales. Existing litigation involving the valuation and measurement of natural gas, crude oil and NGLs and payment of royalties from such sales is described in Note 14 of the Notes to Consolidated Financial Statements. Other legal and regulatory risks that could cause actual results to differ from projections and other forward-looking statements are described in Part I, “Other Matters.”

Political and Security Risk Could Have a Significant Adverse Effect on the Company’s Operations or Financial Results— Domestic and international political and security risks, including changes in government, seizure of property, civil unrest, armed hostilities and acts of terrorism, could have a significant effect on the Company’s operations or financial results. Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as the military or other actions taken in response, cause instability in the global financial and energy markets. Terrorism and other geopolitical hostilities could adversely affect production or the market prices in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in crude oil and natural gas prices, or the possibility that the infrastructure on which the Company or operators developing the underlying properties rely could be a direct target or an indirect casualty of an act of terror.

Various Regulations Relating to the Protection of the Environment May Significantly Affect the Company’s Exploration, Development and Production, Including the Cost of Operations, and Could Result in Substantial Liabilities for Noncompliance or Suspension of Operations in Affected Areas— The Company’s operations are subject to various foreign, national, state and local laws and regulations covering the discharge of material into, and protection of, the environment. Such regulations and liability for remedial actions under environmental regulations affect the costs of planning, designing, operating and abandoning facilities. The Company expends considerable resources, both financial and managerial, to comply with environmental regulations and permitting requirements. Although the Company believes that its operations and facilities are in substantial compliance with applicable environmental laws and regulations, risks of substantial costs and liabilities are inherent in crude oil and natural gas operations. Moreover, it is possible that other developments, such as increasingly strict environmental laws, regulations and enforcement, and claims for damage to property or persons resulting from the Company’s current or discontinued operations, could result in substantial costs and liabilities in the future.

While the Company maintains insurance coverage for spills, pollutions and certain other environmental risks, it is not fully insured against all such risks. Because regulatory requirements frequently change and may become more stringent, and environmental costs and liabilities are inherent in the Company’s operations, there can be no assurance that material costs and liabilities will not be incurred in the future or that the Company’s insurance will be sufficient to cover any such costs or liabilities. Such costs may result in increased costs of operations and acquisitions and decrease production.

UNRESOLVED STAFF COMMENTS

None

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 2005.

EXECUTIVE OFFICERS OF THE REGISTRANT

Bobby S. Shackouls, 55— Chairman of the Board, President and Chief Executive Officer, Burlington Resources Inc., July 1997 to present.

Randy L. Limbacher, 47— 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.

Steven J. Shapiro, 53— Office of the Chairman, Burlington Resources Inc., January 2004 to present. Executive Vice President, Finance and Corporate Development, Burlington Resources Inc., April 2005 to present. Executive Vice President and Chief Financial Officer, Burlington Resources Inc., December 2002 to April 2005. Senior Vice President and Chief Financial Officer, Burlington Resources Inc., October 2000 to December 2002.

Mark E. Ellis, 49— Senior Vice President, North American Production, Burlington Resources Inc., September 2004 to present. President, Burlington Resources Canada Ltd., October 2000 to September 2004.

L. David Hanower, 46— Senior Vice President, Law and Administration, Burlington Resources Inc., July 1998 to present.

Joseph P. McCoy, 54— Senior Vice President and Chief Financial Officer, Burlington Resources Inc., April 2005 to present. Vice President and Controller, Burlington Resources Inc., May 2001 to April 2005. Vice President and Controller, Vastar Resources, Inc., May 1994 to March 2001.

John A. Williams, 61— 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.

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, 2005, the number of record holders of Common Stock was 10,522. 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)

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.

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, from its properties primarily located in the onshore U.S. and western Canada, 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 various areas of its 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. In recent years, the Company has put considerable emphasis 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 sustain its production growth goals. 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 on 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. Margin enhancement is another important element of the Company’s business, including focus on 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

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

On December 12, 2005, BR and ConocoPhillips entered into a definitive agreement under which ConocoPhillips will acquire BR. Under the terms of the agreement, BR shareholders will receive $46.50 in cash and 0.7214 shares of ConocoPhillips common stock for each BR share they own. The transaction is subject to approval by BR shareholders of record on February 24, 2006 and other customary terms and conditions. A special meeting of shareholders to vote on the proposed merger is March 30, 2006. Regulatory approvals have been granted and, upon approval by shareholders, the transaction is expected to close by March 31, 2006.

The merger agreement (“Agreement”) provides that until the effective time of the merger, BR will conduct its business in the ordinary course in all material respects, in substantially the same manner as conducted prior to the date of the Agreement, subject to certain conditions and restrictions as set forth in the Agreement. In addition, BR has agreed not to, except with prior written consent of ConocoPhillips, incur or commit to any capital expenditures, other than in the ordinary course of business or as contemplated by the 2006 capital budget. BR has agreed to pay ConocoPhillips a $1 billion termination fee in cash if BR terminates the Agreement prior to the approval by BR’s shareholders of the Agreement, if BR’s board of directors has determined that it has received a superior proposal and BR has complied with its obligation with respect to non-solicitation of other acquisition proposals and conditions.

In the ordinary course of business, 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 its North America business to represent approximately 88 percent of its total production in 2006. 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 approximately 12 percent of the Company’s total production in 2006.

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

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 the 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 2005, the Company’s reserve replacement costs were $1.68 per MCFE including acquisitions or $1.61 per MCFE excluding acquisitions. The increase in costs in 2005 compared to 2004 was primarily due to industry service cost 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, 2005, the Company’s average reserve replacement costs were $1.40 per MCFE including acquisitions and $1.39 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 73 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.

Reserve Replacement

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 and immediately adjacent 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 27 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 80 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.

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 2005, production volumes were 2,863 MMCFE per day, representing a 2 percent increase over 2004. In 2006, the Company expects production volumes to average between 2,940 and 3,100 MMCFE per day.

The Company expects production growth in the U.S. during 2006 to be driven by increased production from Bossier, Cedar Creek, and Barnett Shale drilling programs. Production from the Rivers Fields commenced in October 2004; however, in November 2004, problems were encountered related to the acid plant. Production is expected to resume during the first quarter of 2006. The Company expects production from its international operations to range from a decline of 8 percent to an increase of 7 percent compared to production levels in 2005. In 2006, the Company expects production in Canada to decline from 1 to 4 percent compared to production levels in 2005.

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 in the U.S. are currently available and therefore continues to focus 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 the first quarter of 2006, the Company expects its operating costs to increase 7 to 13 percent and administrative expense to decrease 17 to 33 percent compared to the full year of 2005 on a per unit-of-production basis. The Company expects its operating costs to increase primarily due to industry service cost pressures. The Company expects administrative expense, which includes expenses related to compensation plans that are correlated to the Company stock, to decrease in the first quarter of 2006 compared to the full year of 2005. The Company expects DD&A expense to increase 11 to 19 percent on a unit-of-production basis in the first quarter of 2006 compared to the full year of 2005, 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 the first quarter of 2006 and the full year of 2005, respectively.

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 2005, 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 2005, the Company estimates that a $1.00 per barrel change in crude oil prices would impact annual crude oil revenues approximately $34 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. In accordance with the terms of the Agreement between BR and ConocoPhillips, individual acquisitions by the Company in excess of $50 million are subject to approval by ConocoPhillips.

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, 2005 and December 31, 2004 was 30 percent and 36 percent, respectively. The 17 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 2006 capital expenditures, excluding any potential major acquisition(s). At December 31, 2005, the Company had $3,528 million of cash and cash equivalents on hand, of which $1,948 million was located in Canada, $1,285 million in the U.S. and $295 million in International. On October 27, 2005, the Company repatriated $500 million of eligible foreign earnings to the U.S. 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.

On April 14, 2005, the Company filed as co-registrant with the Permian Basin Royalty Trust (“Royalty Trust”) a registration statement on Form S-3 with the SEC registering the sale from time to time, in one or more offerings, of up to 27,577,741 units of beneficial interest in the Royalty Trust (“Units”) held by the Company. During the second half of 2005, the Company sold

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 sub-limit for the issuance of letters of credit, including up to US$250 million in letters of credit under the Canadian subfacility. On August 17, 2005, the Company amended the Credit Facility to extend the expiration date from July 2009 to August 2010. 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 repay 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, 2005, 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 2005 increased $1,100 million and $1,997 million over 2004 and 2003, 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 32 percent and 49 percent over 2004 and 2003, respectively. Crude oil prices increased 40 percent and 87 percent over 2004 and 2003, respectively, while NGLs prices increased 30 percent and 61 percent over the same period. Crude oil volumes increased 9 percent and 100 percent over 2004 and 2003, respectively. NGLs volumes increased 2 percent and 3 percent over 2004 and 2003, respectively. Natural gas volumes in 2005 were essentially the same as 2004 and 2003. Although the Company believes that 2006 production volumes will exceed 2005 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 2005 is not necessarily indicative of future cash flows from operating activities. See page 22 for a discussion of commodity prices.

The increase in net cash provided by operating activities resulting from higher commodity prices and higher production volumes was partially offset by higher costs and expenses. In 2005, costs and expenses that affect net operating cash provided by operating activities primarily include operating costs, taxes other than income taxes, transportation expenses, and administrative expenses. These costs and expenses increased $289 million and $570 million over 2004 and 2003, 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. Well operating expenses accounted for 24 percent and 30 percent of the increase in costs and expenses over 2004 and 2003, respectively. Taxes other than income taxes include severance taxes, which are directly correlated to crude oil and natural gas revenues. Severance taxes accounted for 25 percent and 24 percent of the increase in costs and expenses over 2004 and 2003, respectively. For revenue, price, volume and costs and expense variances, see tables and explanations on pages 29-34.

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, 2005 was 149 percent and has averaged 139 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 2006.

The Company also has liabilities of $604 million related to asset retirement obligations on its Consolidated Balance Sheet at December 31, 2005. 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, 2005, the Company has a BBB+ long-term debt rating from Standard & Poors and A3 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, 2005, the aggregate unfavorable mark-to-market position under the aforementioned hedging agreements was approximately $72 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 $33 million as of December 31, 2005.

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 announced that the 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 announced that the 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 voted to restore the authorization level to $1 billion. Through October 25, 2005, the Company had the authority to purchase $193 million of its Common Stock under the program authorized in December 2004. On October 26, 2005, the Company announced that the Board voted to restore the authorization level to $1 billion. Through December 31, 2005, the Company had the authority to purchase $857 million of its Common Stock under the current authorization.

During 2005, the Company repurchased approximately 16 million shares of its Common Stock for approximately $902 million and, as of December 31, 2005, had authority to repurchase an additional $857 million of its Common Stock under the current authorization. Share repurchases of $8 million related to 2004 transactions were cash settled during 2005. Since December 2000, the Company has repurchased approximately 77 million shares of its Common Stock for $2.5 billion.

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 $23 million and $2 million, respectively. As of December 31, 2005, Lost Creek had outstanding debt totaling $37 million and Evangeline had outstanding debt totaling $28 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 up 54 percent and 50 percent compared to 2004 and 2003, respectively. Excluding acquisitions, the Company’s capital spending related to internal development and exploration was up 47 and 68 percent compared to 2004 and 2003, respectively. Capital expenditures in 2006, excluding proved property acquisitions, are expected to be approximately $3.1 billion, up 33 percent over 2005, 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 2006 estimated spending is sufficient to add adequate reserves and achieve the target of three to eight percent average annual production growth. Capital expenditures in 2006 are expected to be primarily for internal development and exploration of oil and gas properties. Capital spending in 2006 related to internal development and exploration is expected to be about 29 percent higher than 2005 and is expected to be funded from internally generated cash flows.

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.

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, 2005, 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 $77 million decrease in the net unrealized gain. The derivative instruments in place at December 31, 2005 hedged approximately 10 percent and 11 percent of the Company’s expected natural gas and crude oil production volumes, respectively, through 2006.

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 six percent of the Company’s accounts receivable balance at December 31, 2005. 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 2005, 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

Dividends

On January 25, 2006, the Board declared a Common Stock quarterly cash dividend of $0.10 per share, payable April 10, 2006 to shareholders of record on March 9, 2006. During the third quarter of 2005, the Company increased its quarterly cash dividend from $0.085 to $0.10 per share, representing an 18 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 $141 million and $136 million, respectively, during 2005.

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 2005, 2004, and 2003 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 68-72.

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 the costs of 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 $62 million. See the Supplementary Financial Information in this report 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 as exploration cost 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

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 and additionally 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 DD&A 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 $30 million increase in the Company’s obligation and a $2 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. Under 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 2005, the Company used a professional valuation services firm to assist in preparing its annual valuation of the Canadian reporting unit. At December 31, 2005, 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

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, 2005 Compared With Year Ended December 31, 2004

The Company’s consolidated net income increased to $2,710 million or $7.07 diluted earnings per common share (“per share”) in 2005 primarily due to higher commodity prices and higher production volumes. Net income in 2005 includes a gain of $240 million or $0.39 per share related to the sale of 16,950,000 units of beneficial interest in the Permian Basin Royalty Trust held by the Company. Net income in 2005 and 2004 included charges, net of taxes, of $34 million or $0.09 per share and $59 million or $0.15 per share, respectively, related to the impairment of oil and gas properties. Net income in 2005 and 2004 included income tax benefits of $51 million or $0.13 per share and $23 million or $0.06 per share, respectively, related to the reduction of the Canadian federal income tax rate. Net income in 2004 also included income tax benefits of $45 million or $0.11 per share 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. in 2005 under the one-time provisions of the American Jobs Creation Act of 2004.

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

Price and Volume Variances