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Washington, D.C. 20549

FORM 10-K

[X]    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

For the fiscal year ended December 31, 2003

OR

[ ]    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

Commission file number 1-9971

BURLINGTON RESOURCES INC.

717 Texas, Suite 2100, Houston, Texas 77002

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

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:

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes   X   No      

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    o

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of January 30, 2004 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 30, 2004: $10,829,196,847 and as of June 30, 2003: $10,852,397,432.

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 30, 2004, Shares Outstanding: 197,829,683

DOCUMENTS INCORPORATED BY REFERENCE

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

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

Table of Contents

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

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

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

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

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

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

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

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

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

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

Exploitation is drilling wells in areas proven to be productive.

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

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

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

Formation is a strata 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.

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

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

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

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

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

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

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

Production and processing includes direct and indirect expenses, including divisional office expenses, incurred to manage, operate and maintain the Company’s wells and related equipment and facilities.

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 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 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).

Reserve replacement costs are 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.

Reserve replacement ratio is calculated by dividing the sum of reserve revisions, extensions, discoveries and other additions and acquisitions by the actual production for the corresponding period.

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 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.

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

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

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

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

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

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

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

Zone is a stratigraphic interval containing one or more reservoirs.

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BUSINESS AND PROPERTIES

Burlington Resources Inc. (BR) is a holding company engaged, through its principal subsidiaries, Burlington Resources Oil & Gas Company LP, The Louisiana Land and Exploration Company (LL&E), Burlington Resources Canada Ltd. (formerly known as Poco Petroleums Ltd.), Burlington Resources Canada (Hunter) Ltd. (formerly known as Canadian Hunter Exploration Ltd.) (Hunter), and their affiliated companies (collectively, the Company), in the exploration for and the development, production and marketing of natural gas, crude oil and NGLs. BR ranks 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.

In October 2001, the Company announced its intent to sell certain non-core, non-strategic properties in order to improve the overall quality of its asset portfolio, primarily in the U.S. During 2002, the Company sold approximately 1 TCFE of reserves and the Val Verde Plant. As a result of these property sales, the Company generated proceeds, before post closing adjustments, of approximately $1.2 billion. The Company used a portion of the proceeds generated from property sales to retire debt and for general corporate purposes.

In December 2001, the Company consummated the acquisition of Hunter valued at approximately U.S. $2.1 billion, resulting in goodwill of approximately $793 million. This acquisition was funded with cash on hand and proceeds from the issuance of $1.5 billion of fixed-rate notes and $400 million of commercial paper. The transaction was accounted for under the purchase method.

The Hunter acquisition added a portfolio of producing 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, North America’s third-largest natural gas field, with approximately 1.5 million gross acres and 17 major producing horizons. The acquisition added estimated proved reserves of 1.3 TCFE along with approximately two million net undeveloped acres.

In November 1999, BR consummated the acquisition of Poco Petroleums Ltd. valued at approximately $2.5 billion. The transaction was funded through the issuance of 38,393,135 shares of the Company’s Common Stock and was accounted for under the pooling of interests method.

The Company’s reportable segments are U.S., Canada and Other 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 the Arctic coast of Canada. The Company’s North American operations include a mix of production, development and exploration assets.

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U.S.

San Juan Basin

The San Juan Basin, in northwest New Mexico and southwest Colorado, is one of the Company’s major operating areas in terms of reserves and production. The San Juan Basin encompasses nearly 7,500 square miles, or approximately 4.8 million acres, with the major portion located in New Mexico’s Rio Arriba and San Juan counties. The Company is a significant holder of productive leasehold acreage in this area with over 840,000 net acres under its control. The Company operates almost 7,300 well completions in the San Juan Basin and holds interests in an additional 4,300 non-operated well completions.

In 2003, the Company invested $115 million in oil and gas capital, excluding acquisitions, that included 322 new wells and approximately 585 workovers of existing wells. The Company’s net production from the San Juan Basin averaged approximately 546 MMCF of natural gas per day, 31.3 MBbls of NGLs per day and 1.2 MBbls of crude oil per day during 2003. Production from the San Juan Basin grew significantly during the 1990s, first as a result of Fruitland Coal drilling and then as a result of development of tight gas formations. By the end of the decade, all formations were experiencing some decline. To mitigate Fruitland Coal production decline, the Company has an ongoing program that consists of performing workovers on existing wells, adding compression, and installing artificial lift, where appropriate. The Company also developed 35 BCFE of additional Fruitland Coal reserves by drilling new wells on 320-acre and 160-acre spacing, and added 34 BCFE of proved undeveloped reserves. In 2003, net production from the Fruitland Coal averaged 199 MMCF of natural gas per day from over 1,700 completions.

In 2003, the New Mexico Oil and Gas Conservation Division (NMOCD) granted approval to allow infill drilling on 160-acre spacing in the high-productivity portion of the Fruitland Coal pool. The approval by the NMOCD made available many drilling opportunities that are expected to result in additional production and reserves in San Juan.

Also in 2003, the Company repurchased three production interests in properties related to coalbed methane production. These repurchases added net annualized volumes of 79 MMCF of natural gas per day and 95 BCFE of reserves at a price of approximately $80 million, yielding an average acquisition cost of about $0.84 per MCFE.

The three conventional formations (Mesaverde, Pictured Cliffs and Dakota), located in the San Juan Basin, continue to provide attractive development opportunities for the Company. The Mesaverde formation, which consists of the Lewis Shale, Cliffhouse, Menefee and Point Lookout sands, is the largest producing tight gas formation in the San Juan Basin. In 2003, the Company continued its ongoing infill drilling program in this formation by developing 115 BCFE of reserves. In the Dakota formation, the Company developed 40 BCFE of additional reserves by drilling new wells on 160-acre and 80-acre spacing during 2003 and added 274 BCFE of proved undeveloped reserves. Net production from the tight gas producing formations averaged 347 MMCF of natural gas per day and 31.3 MBbls of NGLs per day.

During the year, the Company continued its cost management efforts in the San Juan Basin. Year-over-year, net operated capital costs for like-kind projects were essentially flat to 2002 as a result of a variety of process improvements. Similarly, lease operating expenses were reduced by $1.5 million from 2002, despite inflationary and operational cost pressures, resulting in unit costs per MCFE being essentially flat to 2002. This was achieved primarily through compression optimization and cost savings for produced water disposal.

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 88 MMCF of natural gas per day in 2003 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 2003 totaled $19 million for approximately 56 newly drilled wells and workover projects in the deep Madison and shallower formations. During the summer of 2003, the Company elected to shut-in natural gas production from the deep Madison wells after localized pipe deformations were found during inspection of the field’s high-pressure gathering system. By year end, the Company had completed repairs on four gathering lines, largely restoring production. Two other gathering lines are producing at reduced rates pending further repairs scheduled for mid-2004. In addition, the final gathering line is also expected to be completed at that time. The Company spent $4 million for repairs to the deep Madison gathering system in 2003. The Big Horn #9-4, the last of the planned deep development wells, began producing in mid-November 2003. The Company owns an approximate 50 percent working interest in the Lost Cabin Gas Plant and a 42 percent net revenue interest in the Madison reservoir.

Williston Basin

The Williston Basin operations, in western North Dakota and eastern Montana, are primarily focused on the Cedar Creek Anticline. Total Williston Basin production averaged 13 MBbls of crude oil per day and 4 MMCF of natural gas per day. During 2003, the Company invested $66 million on horizontal drilling and workover projects, primarily located in the Cedar Hills South and East Lookout Butte waterflood units.

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The Company continued its highly active waterflood development program at the Cedar Hills Unit by drilling 24 wells, extending 33 existing horizontal wells, and increasing water injection volumes. Seven of these newly drilled wells are testing 160-acre infill spacing. This spacing is also being pilot tested in East Lookout Butte and was expanded in 2003 with the addition of 11 wells. These pilots are being monitored to further assess the feasibility of infill drilling on 160-acre spacing to improve the efficiency of the waterflood.

Anadarko Basin

The Anadarko Basin, located principally in western Oklahoma, encompasses over 30,000 square miles and contains some of the deepest producing formations in the world. The Company controls over 250,000 net acres and produces from multiple horizons ranging in depth from 11,000 feet to over 21,000 feet. Net production for 2003 from the Anadarko Basin averaged 78 MMCF of natural gas per day and 0.4 MBbls of NGLs per day. During 2003, the Company invested $27 million in the Anadarko Basin. Operated activity focused on the Red Fork formation in Roger Mills County, Oklahoma where the Company drilled 19 wells.

Permian Basin

Permian Basin operations, in west Texas, are focused on the Waddell Ranch Field. Total Permian Basin production in 2003 averaged 15 MMCF of natural gas per day, 3.5 MBbls of crude oil per day and 1.6 MBbls of NGLs per day, with the Waddell Ranch Field contributing 11 MMCF of natural gas per day, 2.8 MBbls of crude oil per day and 1.6 MBbls of NGLs per day. During 2003, the Company invested $9 million in Permian Basin operations.

Fort Worth Basin

The Fort Worth Basin of north central Texas had a significant increase in activity in 2003 for the Company following the 2002 acquisition of a largely undeveloped Barnett Shale formation acreage position in Denton County, Texas. Net volumes increased from 18 MMCF of natural gas per day, 0.3 MBbls of NGLs per day and 0.3 MBbls of crude oil per day at the beginning of the year to 34 MMCF of natural gas per day, 4.1 MBbls of NGLs per day and 1.1 MBbls of crude oil per day at year end. The Company employed up to nine rigs during the year to drill 163 wells in the Barnett Shale formation including a two-well pilot program to test horizontal well technology. The Company invested $90 million in 2003 with production averaging 28 MMCF of natural gas per day, 2.1 MBbls of NGLs per day and 0.7 MBbls of crude oil per day.

Onshore Gulf Coast

The Onshore Gulf Coast includes a number of drilling trends in south Louisiana, as well as 660,000 acres of fee lands where the Company owns the mineral rights and surface lands. In 2003, the Company invested $75 million in 52 drilling, workover and facilities projects in south Louisiana. Net production for 2003 averaged 94 MMCF of natural gas per day, 6.6 MBbls of crude oil per day and 1.2 MBbls of NGLs per day.

Canada

Western Canadian Sedimentary Basin

In the Western Canadian Sedimentary Basin, the Company’s portfolio of opportunities includes conventional exploration and development in Alberta, British Columbia and Saskatchewan, as well as frontier exploration in the Mackenzie Delta in the Northwest Territories.

Canadian activity in 2003 focused on production growth, reserve additions and cost control on the integrated assets acquired since 1999 by expanding original activity into large-scale repeatable drilling programs in conventional and lower permeability reservoirs. Oil and gas capital investment in Canada was $679 million, including acquisitions, and resulted in the completion of 737 gross wells.

The Deep Basin area, in Alberta and British Columbia, consists of the Elmworth, Wapiti, Noel and Brassey Fields. The Company acquired interests in 84,000 acres of mineral rights through Crown Land sales in Alberta and British Columbia. This included approximately 40,000 acres in the Brassey area to extend drilling activity in the tight gas trend. In 2003, a $256 million oil and gas capital program was focused on exploration and development in the Deep Basin area. As a result, 180 wells were drilled and 233 MMCF of natural gas per day and 15.6 MBbls of NGLs per day were produced from this area, representing a 12 percent increase year over year.

In the Deep Basin, the 2003 program focused on continued exploitation of tight gas reservoirs in the Cadomin and Chinook formations. Regulatory approval to reduce well spacing in the Cadomin from 640-acres to 320-acres was expanded from a 33-section area at the start of the year to 83 sections, with an additional 32 sections pending final regulatory approval. As a result of the down-spacing approvals, the Company drilled 28 infill wells in the Cadomin formation in the Elmworth area and 19 infill wells in the Chinook formation.

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The O’Chiese and Whitecourt areas in central Alberta yielded 2003 production of 226 MMCF of natural gas per day, 8.9 MBbls of NGLs per day and 2.7 MBbls of crude oil per day. The O’Chiese and Whitecourt areas were the focus of a $156 million exploration and development program in 2003 that mostly targeted the Lower Cretaceous and Jurassic sands, the principal historical targets. A total of 168 wells were drilled, including 26 wells in shallow gas formations.

The Company continued exploration and development activities in the greater Ring Border area on the border of northern Alberta and British Columbia. Production in this area during 2003 averaged 111 MMCF of natural gas per day and 1.9 MBbls of NGLs per day. A capital program in this area of $72 million targeted the Bluesky, Gething and Montney formations and 101 wells were drilled. This included 19 wells that extended the Gutah discovery west of the Ring Border Unit. The Kahntah Field, lying northwest of the Ring Border Field, was also brought on-stream to the existing Ring Border plant.

In the Kaybob area, production for the year averaged 69 MMCF of natural gas per day and 0.7 MBbls of NGLs per day. This represents production growth of 54 percent over 2002. During 2003, the Company invested $78 million, drilled 59 wells in the Lower Cretaceous formation and expanded the wholly owned Berland River gas processing plant.

The Viking Kinsella property produced approximately 87 MMCF of natural gas per day in 2003, a 42 percent increase over 2002. An additional 79 wells were drilled on the property in 2003. The infrastructure was expanded with the purchase of a gas processing plant at Scoville Lake and the construction of a new gas processing plant at Vernon Lake.

Mackenzie Delta

In the MacKenzie Delta, a successful exploration well was drilled at the Langley K-30 location resulting in a discovery from the Eocene Taglu formation.

Other International

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

Northwest Europe

Operations in Northwest Europe provided the majority of the Company’s production outside of North America during 2003, from assets in the East Irish Sea and in the Dutch sector of the North Sea.

The East Irish Sea assets consist of eight licenses covering 249,000 acres. The Company has a 100 percent working interest in seven operated gas fields. First production from two sweet gas fields, Millom and Dalton, commenced in 1999. A new sub-sea well was completed during mid-2003, bringing the total number of producing wells in the Millom and Dalton Fields to nine. Net production from the East Irish Sea averaged 96 MMCF of natural gas per day during 2003. The Company invested $218 million of capital in this area, including $108 million of oil and gas capital.

In 2003, the development of the sour gas fields in the East Irish Sea continued with first production planned by mid-2004. During 2003, three production wells were completed from the offshore platform and tested at a combined rate of over 180 MMCF of natural gas per day. The pipeline transporting gas from these offshore facilities was also completed during 2003 and construction work continued on the new onshore terminal that will process the sour gas prior to sale.

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The Company’s remaining Northwest European shelf operations consist of non-operated production from the CLAM venture in the Dutch offshore sector. During the second quarter of 2003, the Company acquired the remaining 50% interest in CLAM for a purchase price of approximately $100 million (including cash acquired at closing of $25 million). The CLAM assets yielded an annual production rate of 43 MMCF of natural gas per day in 2003.

North Africa

In North Africa, the Company continued with its exploration and development programs in both Algeria and Egypt. In Algeria, on Block 405a Menzel Lejmat North, in which the Company has a 65 percent working interest, activity was primarily focused on bringing on line the Company-operated MLN central processing facility for crude oil production. Operated crude oil production into the processing plant commenced in July 2003. Net production to the Company in July 2003 was 4.9 MBbls of crude oil per day and increased to 12.4 MBbls of crude oil per day in December 2003. Net annual production from the MLN property averaged 3.9 MBbls of crude oil per day. In December 2003, production from the MLN satellite fields in Block 405a: MLW; MLNW; KMD and MLC commenced, accounting for the higher year-end production. The Company’s capital investments in this area in 2003 totaled $71 million.

The Ourhoud Field, in which the Company has a 3.7 percent working interest, produced throughout the year. Some operational difficulties with crude oil export pumps prevented the field from producing at its targeted rate until the final few weeks of the year. During 2003, net production was 4.1 MBbls of crude oil per day.

During early 2003, the final required exploration well in Block 405a, MLSE-8, was drilled. This well was a minor natural gas discovery in shallow zones. However, a subsequent test of deeper horizons for producible hydrocarbons failed to flow. The well has been suspended, pending possible future use in a gas development. Subsequent to drilling the MLSE-8 well, a final relinquishment of non-development areas in Block 405a was submitted to Sonatrach, the Algerian national oil company, and awaits finalization.

In the Akfadou PSC, Block 402d, in which the Company has a 75 percent working interest, seismic interpretation was completed and locations were agreed upon for the two commitment exploration wells required under the contract.

In Egypt, where the Company has a 50 percent non-operated working interest in the Offshore North Sinai permit, an appraisal well, Tao-2, was drilled. The well did not find producible hydrocarbons and was abandoned as a dry hole. Plans continue for the Offshore North Sinai gas project and discussions have continued with the Egyptian authorities on timing and the location for the related onshore facilities for that project.

China

In the Far East, the Company continued its focus on selected basins in China. An offshore oil development project started production in 2003, and an onshore gas development program is in its early phase working toward long-term expansion. The Company is also targeting opportunities to add to its existing leasehold position. The Company invested $44 million in China in 2003.

During the year, fabrication on the Panyu offshore oil development project in the Pearl River Mouth Basin of the South China Sea was completed with installation and commissioning of all components. The Panyu development involves two offshore oil fields, Bootes and Ursa, located in Block 15/34, in which the Company holds a 24.5 percent working interest. First production was achieved in October 2003 and production rapidly increased thereafter. In December 2003, the average net production was 11.1 MBbls of crude oil per day, with net production for the year of 1.2 MBbls of crude oil per day.

The Company holds a 100 percent working interest in the onshore Chuanzhong Block in the Sichuan Basin, a natural gas project currently at the end of the appraisal phase. The project represents an opportunity to apply the Company’s expertise in the development of tight gas reservoirs in an area with substantial reserve potential. Three appraisal wells were drilled in 2003 and completion of the appraisal program and initiation of development is expected to occur in 2004. During 2003, net production in this area was 4 MMCF of natural gas per day.

South America

The Company’s efforts in South America during 2003 focused on expanding near-term production potential and enhancing long-term exploration opportunities. Net production from South America averaged 2.8 MBbls of crude oil per day and 24 MMCF of natural gas per day. The Company invested $43 million of capital in South America during the year.

In Ecuador, the Company holds a 30 percent working interest in Block 7 and a 37.5 percent working interest in Block 21. Phase I development of the Yuralpa Field in Block 21 was completed with first production achieved during December 2003. One development well was successfully drilled in Block 7 during 2003. The Oso well was deepened to an untested target, which resulted in a new field discovery in the Hollin formation. Testing of the well was ongoing at

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In Argentina, the Company holds a 25.7 percent working interest in the Sierra Chata concession in the Neuquen Basin. This asset has a net sales capacity of 45 MMCF of natural gas per day from 39 producing wells. During 2003, natural gas sales were curtailed due to low gas prices in Argentina, with the Company’s net production averaging only 24 MMCF of natural gas per day. Deferrals of capital programs and a close focus on operating costs have helped mitigate the economic impact of the poor market conditions over the last two years. Market conditions exhibited signs of improvement at year-end 2003.

Elsewhere in South America, the Company entered into an agreement to acquire a 23.9 percent working interest in Peru’s Block 90, located 100 kilometers north of the Camisea area in the Ucayali Basin. This block was re-configured from the previously held Block 34/35 concessions. Also in Peru, field geologic studies and a 2-D seismic acquisition program were completed in Block 87 in which the Company holds a 70 percent working interest that could be relinquished in 2004. In Colombia, the Company signed an exploration contract with Ecopetrol for a 100 percent interest in the Orquidea area.

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Productive Wells

Working interests in productive wells at December 31, 2003 follow.

Net Wells Drilled

Drilling activity in 2003 was principally in the Western Canadian Sedimentary, San Juan, Onshore Gulf Coast, Ft. Worth, Permian, Anadarko, Wind River and Williston Basins. The following table sets forth the Company’s net productive and dry wells.