BURLINGTON RESOURCES INC - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-9971

BURLINGTON RESOURCES INC.

Incorporated in the State of Delaware Employer Identification No. 91-1413284

5051 Westheimer, Suite 1400, Houston, Texas 77056
Telephone: (713) 624-9500
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, par value $.01 per share

Preferred Stock Purchase Rights

The above securities are registered on the New York Stock Exchange.

Securities registered pursuant to Section 12(g) of the Act:
None

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

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

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 31, 2003 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, 2003: $8,885,621,814 and as of June 28,
2002: $7,649,418,316

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, 2003, Shares Outstanding: 201,488,023

DOCUMENTS INCORPORATED BY REFERENCE

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

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

Below are certain definitions of key 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.

Artificial lift is the mechanical process of producing well fluids to the
surface using a rod, tubing or bottom-hole centrifugal pump.

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.

Consumer collar is an option strategy that combines a written put option and a
purchased call option. The writer of a consumer collar writes a put option
(ceiling) and buys a call option (floor).

Developed acreage is the number of acres that are allocated or assignable to
producing wells or wells capable of production.

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

Exploitation is drilling wells in areas proven to be productive.

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

Exploratory well is a well drilled to find and produce oil or 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.

Farm-in or farm-out is an agreement whereby the owner of a working interest in
an oil and gas lease assigns the working interest or a portion thereof to
another party who desires to drill on the leased acreage. Generally, the
assignee is required to drill one or more wells in order to earn its interest in
the acreage. The assignor usually retains a royalty or reversionary interest in
the lease. The interest received by an assignee is a "farm-in," while the
interest transferred by the assignor is a "farm-out."

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

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.

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.

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

Proved reserves represent estimated quantities of oil and gas which geological
and engineering data demonstrate, with reasonable certainty, can be recovered in
future years from known reservoirs under existing economic and operating
conditions. Reservoirs are considered proved if shown to be economically
producible by either actual production or conclusive formation tests. For
complete definitions of proved oil and gas reserves, refer to the Securities and
Exchange Commission's Regulation S-X, Rule 4-10(a)(2), (3) and (4).

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 oil and gas reserves,
refer to the Securities and Exchange Commission's Regulation S-X, Rule
4-10(a)(2), (3) and (4).

Producer collar is an option strategy that combines a written call option and a
purchased put option. The writer of a producer collar writes a call option
(ceiling) and buys a put option (floor). When the premium received on the call
option equals the premium paid for the put option, the collar is known as a
zero-cost collar.

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 oil and gas 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).

Recompletion is an operation whereby a completion in one zone is abandoned in
order to attempt a completion in a different zone within the existing wellbore.

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, carbon dioxide or other sulfur compounds.

Spacing is the regulation of the number of wells which can 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.

CONTENTS

PART I
Items One and Two
Business and Properties 1
Employees 12
Web Site Access to Reports 12
Item Three
Legal Proceedings 12
Item Four
Submission of Matters to a Vote of
Security Holders 13
Executive Officers of the Registrant 13
PART II
Item Five
Market for Registrant's Common Equity and
Related Stockholder Matters 14
Item Six
Selected Financial Data 14
Items Seven and Seven A
Management's Discussion and Analysis of
Financial Condition and Results of
Operations and Quantitative and
Qualitative Disclosures About Market
Risk 14
Safe Harbor Cautionary Disclosure on
Forward-Looking Statements 25
Item Eight
Financial Statements and Supplementary
Financial Information 28
Item Nine
Changes in and Disagreements with
Accountants on Accounting and Financial
Disclosure 62
PART III
Items Ten and Eleven
Directors and Executive Officers of the
Registrant and Executive Compensation 62
Item Twelve
Security Ownership of Certain Beneficial
Owners and Management and Related
Shareholder Matters 62
Item Thirteen
Certain Relationships and Related
Transactions 62
Item Fourteen
Controls and Procedures 63
PART IV
Item Fifteen
Exhibits, Financial Statement Schedules
and Reports on Form 8-K 63

PART I

ITEMS ONE AND TWO

BUSINESS AND PROPERTIES

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

On December 5, 2001, the Company consummated a transaction with Hunter valued at
approximately U.S. $2.1 billion, resulting in an excess purchase price of
approximately $793 million which was reflected as goodwill. 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.
See Note 2 of Notes to Consolidated Financial Statements for more information
related to this transaction.

In October 2001, the Company announced its intent to sell certain non-core,
non-strategic properties in order to improve the overall quality of its
portfolio and at December 31, 2001, these properties were classified as held for
sale. These properties along with others, which together held approximately 1
TCFE of reserves and yielded 228 MMCFE per day of production, were sold in 2002.
Based on the purchase and sale agreements, the divestiture program sales price
totaled $1.3 billion. Due to differences between purchase and sale agreement
dates and closing dates, the Company generated proceeds, before post closing
adjustments, of approximately $1.2 billion. The Company used a portion of these
proceeds generated from property sales to retire commercial paper, to repay a
$104 million promissory note and for general corporate purposes, including
funding a portion of the Company's capital program. The Company also expects to
use the remaining proceeds for general corporate purposes, including funding a
portion of the Company's future capital program.

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 14
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.

In 2002, oil and gas capital expenditures for the Company's U.S. operations
totaled $463 million and consisted of $246 million for development projects, $39
million for exploration and $178 million for proved reserve acquisitions. U.S.
production in 2002 represented 53 percent of the Company's total production and
included 949 MMCF of natural gas per day, 35.4 MBbls of crude oil per day and
32.7 MBbls of NGLs per day. At December 31, 2002, proved reserves in the U.S.
totaled 7.3 TCFE and represented 64 percent of the Company's total proved
reserves.

In 2002, oil and gas capital expenditures for the Company's Canadian operations
totaled $839 million and consisted of $348 million for development projects,
$139 million for exploration and $352 million for proved reserve acquisitions,
primarily a property acquisition from ATCO Gas and Pipeline Ltd. (ATCO). The
Company's Canadian production in 2002 represented 39 percent of the Company's
total production and included 802 MMCF of natural gas per day, 27.4 MBbls of
NGLs per day and 7.8 MBbls of crude oil per day. At December 31, 2002, Canadian
proved reserves totaled 2.7 TCFE and represented 24 percent of the Company's
total proved reserves.

In 2002, the Company identified 15 to 20 areas for pilot testing and potential
future development, which the Company describes as unconventional resource
projects. Unconventional resource projects are defined as tight gas,
basin-centered gas, coalbed methane, fractured shale and biogenic gas projects.
The Company spent approximately $30 million evaluating these projects during
2002 and advanced the Barnett Shale program, in the Ft. Worth Basin, to the
development stage. The Company is continuing to evaluate the remaining projects.

1

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 848,000 net acres under its control. The Company operates
over 6,900 well completions in the San Juan Basin and holds interests in an
additional 4,000 non-operated well completions. During the second quarter of
2002, the Company sold the Val Verde gathering and processing facilities and all
associated equipment including 360 miles of gathering lines and 14 compressor
stations.

In 2002, the Company invested $125 million in oil and gas capital that included
over 240 new wells and approximately 290 workovers of existing wells. The
Company's net production from the San Juan Basin averaged approximately 569 MMCF
of natural gas per day, 28.2 MBbls of NGLs per day and 1.3 MBbls of crude oil
per day during 2002. A majority of the growth in the San Juan Basin during the
1990s came from production of coalbed methane gas from the Fruitland Coal
formation. 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
continued to develop additional Fruitland Coal reserves by drilling new wells on
320-acre spacing, and added 62 BCFE of proved undeveloped reserves. In 2002, net
production from the Fruitland Coal averaged 217 MMCF of natural gas per day from
over 1,500 wells.

In 2002, the New Mexico Oil and Gas Conservation Division (NMOCD) granted
approval to allow infill drilling to 160-acre spacing in the lower-productivity
portion of the Fruitland Coal pool. The Company conducted a successful pilot
test of the concept during 2001.

Beginning in 1997, with the Fruitland Coal play reaching maturity, the Company
began placing greater emphasis on increasing production from conventional
gas-producing formations, such as the Mesaverde, the Pictured Cliffs and the
Dakota. The Mesaverde formation, which consists of the Lewis Shale, Cliffhouse,
Menefee and Point Lookout sands, is the largest producing conventional formation
in the San Juan Basin. In 2002, the Company continued its ongoing infill
drilling program in this formation. This brought total proved undeveloped
reserves added in the Mesaverde formation over the last five years to more than
450 BCFE and the Company has subsequently developed just over half of these
reserves. In 2002, net production from the conventional gas-producing formations
averaged 323 MMCF of natural gas per day and 28.2 MBbls of NGLs per day.

In the first quarter of 2002, the Company also received approval from the NMOCD
to infill drill the Dakota formation. As a result of the increased spacing order
and a complete reservoir assessment, during 2002 the Company added 255 BCFE of
proved undeveloped reserves in the formation. In addition, the Company drilled
11 80-acre Dakota wells in 2002 and has interests in over 5,000 additional
undrilled 80-acre Dakota locations.

In the Pictured Cliffs formation, during 2002 the Company, in partnership with
two other operators, received approval from the NMOCD to complete 30 pilot wells
on 80-acre spacing, in lieu of the 160-acre spacing currently permitted. This
pilot will evaluate whether more wells are needed to extract the Pictured Cliffs
formation's remaining gas. Basin wide, the Pictured Cliffs formation has yielded
3.6 TCF gross of natural gas from 6,200 wells. The Company operates about one-
third of these wells and owns interests in many others. This pilot testing is
expected to allow a more thorough evaluation of this potentially significant
reservoir.

During 2002, the Company continued its cost management efforts in the San Juan
Basin. Year-over-year, net operated capital costs were reduced approximately $5
million from comparable projects in 2001 as a result of a variety of process
improvements. Similarly, lease operating expenses were essentially the same as
in 2001, despite inflationary and operational cost pressures. This was achieved
primarily through compression optimization and salt water disposal cost savings.

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 79 MMCF of
natural gas per day in 2002 and came 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 2002 totaled $19 million for
approximately 20 newly drilled wells and workover projects in the deep Madison
and shallower formations and $21 million on plant construction. During 2002, the
Company completed and commissioned the Lost Cabin Gas Plant Train III, which
increased total plant inlet capacity to 310 MMCF of sour gas per day and plant
tail gate capacity to 200 MMCF of natural gas per day. The Company also
initiated production from two new deep Madison wells, the Big Horn #7-34 and Big
Horn #8-35, and began drilling the final deep Madison well, the Big Horn #9-4,
which is expected to begin production in late 2003. The Company owns an
approximate 50 percent working interest in the plant and a 42 percent revenue
interest in the Madison reservoir.

2

Williston Basin

The Williston Basin operations, in western North Dakota and eastern Montana, are
now focused on the Cedar Creek Anticline area, following the divestiture in late
2002 of non-core producing assets located in the northern portion of the basin
and characterized by their high cost structure. Total Williston Basin production
averaged 14.0 MBbls of oil per day and 7 MMCF of natural gas per day. The Cedar
Creek Anticline produced the largest portion of the total, with 11.1 MBbls of
crude oil per day and 4 MMCF of natural gas per day. During 2002, the Company
invested $32 million on drilling and workover projects in the Williston Basin.
The Company continued its highly active waterflood development program in the
Cedar Hills South Unit by drilling 23 new wells and increasing water injection
volumes. The Company also completed implementation of an 8-well infill-drilling
pilot in the East Lookout Butte Unit. This pilot will be monitored during 2003
to further assess the feasibility of drilling infill wells 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
from the Anadarko Basin averaged 91 MMCF of natural gas per day and 1.4 MBbls of
NGLs per day in 2002. During 2002, the Company invested $5 million in the
Anadarko Basin.

Permian Basin

Permian Basin operations, in west Texas and southeast New Mexico, are now
focused on the Waddell Ranch Field. Total Permian Basin production in 2002
averaged 30 MMCF of natural gas per day, 1.6 MBbls of NGLs per day and 5.1 MBbls
of crude oil per day, with the Waddell Ranch Field contributing 12 MMCF of
natural gas per day, 1.3 MBbls of NGLs per day and 3.1 MBbls of crude oil per
day. During 2002, the Company invested $4 million in Permian Basin operations.
In mid-2002, the Company divested non-core Permian Basin operations, including
the Sonora Field, all characterized by their high cost structure and limited
growth opportunities.

Fort Worth Basin

The Fort Worth Basin, in north central Texas, is a new area of operations for
the Company. Production during 2002 averaged 6 MMCF of natural gas per day and
0.2 MBbls of NGLs per day. The Company invested $29 million in oil and gas
expenditures during the year in the Fort Worth Basin. After initially entering
the basin by successfully testing an unconventional resource project, the
Barnett Shale, on leasehold located in Wise County, Texas, the Company acquired
a larger position located primarily in Denton County, Texas, for $141 million,
and ultimately drilled a total of 40 wells during 2002.

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. Net production from south Louisiana in 2002 averaged 79 MMCF
of natural gas per day, 5.3 MBbls of crude oil per day and 0.4 MBbls of NGLs per
day. The Company invested $41 million of oil and gas capital and participated in
a total of 52 Onshore Gulf Coast projects in 2002. During the year, the Company
also divested substantially all of its south and east Texas assets in order to
focus its activities on onshore south Louisiana, specifically on development and
exploration projects in and around core assets. The divested properties were
characterized by their high cost structure and limited growth opportunities.

Gulf of Mexico Shelf

The Company previously held producing interests in the Gulf of Mexico Shelf, but
over the past few years has de-emphasized its Gulf of Mexico Shelf activities
due to the area's high cost structure and high production decline rates. The
Company divested substantially all of its assets in the Gulf of Mexico Shelf
during 2002.

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 of the
Mackenzie Delta in the Northwest Territories.

A key focus of Canadian activity during 2002 was on integrating and growing the
assets acquired through the acquisitions of Hunter in December 2001 and the ATCO
properties, in the Viking-Kinsella area, in January 2002. These assets

3

represent opportunities to expand existing programs into large scale, repeatable
drilling programs in conventional and lower permeability zones.

Oil and gas capital investment in Canada during 2002 was $839 million, including
acquisitions, and resulted in the completion of 579 wells and the recompletion
of 167 wells. During the year, the Company sold certain non-core, high-cost oil
and gas properties which contributed to improving the cost structure of the
Canadian assets. Throughout the year, continued emphasis on cost control and the
lower lease operating expenses of the former Hunter and ATCO assets resulted in
a reduction in average lease operating expenses in 2002.

The Deep Basin area, in Alberta and British Columbia, consists of the Elmworth,
Wapiti, Noel and Brassey Fields and largely represents properties acquired from
Hunter. As a result of a successful drilling program in 2002, 198 MMCF of gas
per day and 15.5 MBbls of NGLs per day were produced from the Deep Basin. In
2002, a $120 million oil and gas capital program was focused on exploration and
development in the Deep Basin area. A total of 116 wells were drilled in the
basin in 2002.

As part of the Deep Basin 2002 program, a tight gas development project largely
targeting the Cadomin and Chinook formations was implemented. A recompletion
program was focused on testing tight gas concepts in existing multi-zone
wellbores. Additionally, regulatory approval was obtained to reduce the normal
well spacing requirements from 640 acres to 320 acres in the Cadomin interval in
a 33-section area.

The O'Chiese and Whitecourt areas in central Alberta, yielded 2002 production of
226 MMCF of natural gas per day, 8.0 MBbls of NGLs per day and 2.5 MBbls of
crude oil per day. The O'Chiese and Whitecourt areas were the focus of a $156
million exploration and development program in 2002 that mostly targeted the
Lower Cretaceous and Jurassic sands, the principal historical targets in these
areas. At O'Chiese in 2002, the Company completed a regional study of a shallow
gas exploration program and drilled 21 wells in this area. The Company has an
800 section land position within this area.

In the Wolf area, 26 wells were drilled, adding 28 MMCF of natural gas per day.
In addition, a five-well program to reduce spacing from 640 acres to 320 acres
was implemented and resulted in an additional net production of 11 MMCF of
natural gas per day. As a result of the successful drilling program, an
expansion of the wholly-owned Wolf Plant and gathering system is expected to
increase production from 32 MMCF of natural gas per day to 44 MMCF of natural
gas per day and is targeted for early 2003. At Alder, 28 wholly-owned successful
wells were drilled into the Rock Creek and Lower Cretaceous Ostracod sands with
net initial production of 51 MMCF of natural gas per day and 1.9 MBbls of crude
oil per day.

The Company added assets in the Ring Border area on the border of northern
Alberta and British Columbia as a result of the Hunter acquisition. Production
during 2002 averaged 66 MMCF of natural gas per day and 1.3 MBbls of NGLs per
day and the focus of activity was on the development and expansion of this asset
base. The capital program in this area was $27 million in 2002 which targeted
the Bluesky and Gething formations and resulted in 53 successful wells.

Production from the outlying area along the border, between Alberta and British
Columbia, averaged 58 MMCF of natural gas per day, 1.0 MBbls of NGLs per day and
0.7 MBbls of crude oil per day. The Company invested $42 million of oil and gas
capital in this area to drill 34 wells. An exploration and development program
focused on drilling for Slave Point reefs resulted in seven successful wells,
the most notable being a discovery north of the prolific Ladyfern Field. This
discovery well and a development well are anticipated to come onstream in early
2003.

In the Kaybob area, production for the year averaged 45 MMCF of natural gas per
day and 0.4 MBbls of NGLs per day and the Company invested $54 million in the
area during 2002. An expansion of the wholly-owned Berland River gas plant
commissioned in December 2002 resulted in an increase in production from 8 MMCF
of natural gas per day to 23 MMCF of natural gas per day. During 2002, 32 wells
were drilled in the Cretaceous and Lower Gething formations.

During 2002, the Company added interests in the Viking-Kinsella area through the
ATCO property acquisition. These assets yielded average production of 61 MMCF of
natural gas per day during the year. Capital investments during 2002 totaled $34
million and included development drilling in the Viking and Mannville
formations. New compressors were installed and a gas processing plant was
started up in September 2002, a month ahead of schedule. During the year, the
Company acquired 3-D seismic over a 125,000 acre area and drilled eight wells.

Beaufort Basin

In the McKenzie Delta, a 3-D seismic program funded by partners was shot on the
Company's exploration acreage. The partners also agreed to drill a well on the
North Langley prospect in the first quarter of 2003. The Company incurred no
expenditures in this area during 2002.

4

OTHER INTERNATIONAL

The Company's Other International operations include a combination of
exploration projects, large field development projects and production
operations. Other International production in 2002 represented 8 percent of the
Company's total production and included 165 MMCF of natural gas per day and 5.9
MBbls of crude oil per day. At December 31, 2002, Other International proved
reserves totaled 1.4 TCFE and represented 12 percent of the Company's total
proved reserves. In 2002, oil and gas capital investments for Other
International operations totaled $299 million and consisted of $185 million for
development projects, $40 million for exploration and $74 million for proved
reserve acquisitions. Key focus areas are Northwest Europe, North Africa, the
Far East and South America.

Northwest Europe

Operations in Northwest Europe provided the majority of the Company's production
outside of North America during 2002, largely from assets in the East Irish Sea
and in the Dutch sector of the North Sea.

The East Irish Sea assets consist of 10 licenses covering 267,000 acres. The
Company has a 100 percent working interest in seven operated gas fields. First
production from two sweet gas fields, Dalton and Millom, commenced in the third
quarter of 1999. Early in 2002, the last of six producing wells drilled at
Millom was completed. Net production from the East Irish Sea averaged 97 MMCF of
natural gas per day during 2002 and the Company invested $128 million in
capital.

In 2002, the development of the sour gas fields in the East Irish Sea continued
with first production planned in early 2004. During 2002, an offshore production
facility was installed, with a pipeline and new onshore processing terminal
currently under construction to receive and process the sour gas prior to sale.

During 2002, the Company divested its interests in the Brae and T-Block
complexes in the United Kingdom sector of the North Sea due to their limited
growth opportunities. The Company's remaining Northwest European Shelf
operations consist of non-operated production from the CLAM joint venture in the
Dutch offshore sector with net production of 25 MMCF of natural gas per day in
2002.

North Africa

In North Africa, the appraisal and development of oil and gas fields in Algeria
have resulted in 37 wells being drilled, including 13 exploration wells. The
Company invested $138 million in Algeria in 2002. Significant achievements
occurred in the Company-operated Menzel Lejmat Block 405a in the Algerian
Berkine Basin, where work advanced on the first phase development project in
which the Company currently has a 65 percent working interest. First oil
production from this project is expected mid-year 2003 from the MLN and
associated fields on the northern part of the block, at a net rate that is
expected to reach about 13.0 MBbls of crude oil per day. Exploitation Licence
Applications were also submitted during 2002 to Sonatrach, the Algerian national
oil company, for ratification and Ministry approval for the next phase of
development of oil fields in the southern part of the block from the MLSE area.
Work continues on the potential commercialization of the significant gas
discoveries that have been made on the block.

Meanwhile, first production was achieved during 2002 in the Ourhoud Field, a
portion of which extends onto Block 405a. Crude oil began flowing into newly
constructed facilities in November 2002 with the first exports of crude oil for
sale occurring in January 2003. The Company has a 3.7 percent working interest
in the Ourhoud Field.

In addition, the Company has a 75 percent working interest in Akfadou Block
402d, also in the Berkine Basin. During 2002, the Company acquired over 500
square kilometers (km) of 3-D seismic data on this block. The data has been
processed and interpreted and work is underway to finalize a location for the
first commitment exploration well.

In Egypt, the Company has a 50 percent working interest in the Offshore North
Sinai contract area. The partners contemplate drilling an additional appraisal
well. The subsequent project definition and contract award for front-end
engineering and design for the planned gas project is expected to follow in late
2003 or early 2004.

Far East

In the Far East, the Company continued to focus on selected basins in China,
with an offshore oil development program scheduled for start-up in 2003, and an
onshore gas development program working toward long-term commercialization. The
Company is also targeting opportunities to add to its existing leasehold
position. The Company invested $49 million in China in 2002.

During the year, work on the Panyu offshore oil development project in the Pearl
River Mouth Basin of the South China Sea continued with fabrication of all
components well underway. 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. These fields contain net proved reserves of 14.7
MMBbls of crude oil and first production is expected in the second half of 2003.

5

Onshore, the Company holds a 100 percent working interest in the Chuanzhong
Block in the Sichuan Basin, a natural gas project currently in 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. Significant milestones achieved in 2002 included the signing of a
long-term gas marketing agreement and the submittal of a plan of development for
the Bajiaochang Field. Completion of the appraisal program and initiation of
development is expected to occur in 2003.

South America

The Company's efforts in South America during 2002 focused on expanding
near-term production potential, enhancing long-term exploration opportunities
and reducing the number of countries in which the Company operates. During the
year, the Company divested its 13.7 percent working interest in the Casanare
concession area in Colombia. Production from South America averaged 3.0 MBbls of
crude oil per day and 18 MMCF of natural gas per day and the Company invested
$90 million of capital in South America during the year.

In Ecuador, capital investments totaled $79 million in 2002. An acquisition in
Blocks 7 and 21 resulted in a 30 percent working interest in Block 7 and a 37.5
percent working interest in Block 21. Development drilling commenced in the
Yuralpa Field in Block 21, with initial production planned for year-end 2003,
provided pipeline construction is completed. Seismic operations also began in
Block 7, as did permitting for development drilling during 2003. Block 7 average
net production for the year was 2.7 MBbls of crude oil per day.

The Company also reached agreement to farm-out half of its share of Ecuador
Blocks 23 and 24 to Perenco Ltd. This will ultimately result in the Company
holding a 25 percent working interest in Block 23 and a 50 percent working
interest in Block 24.

In Peru, the Company holds a 23.9 percent working interest in Block 35 and a 20
percent interest in Block 34, both located in the Ucayali Basin, 100 km north of
Camisea. Elsewhere in Peru, a field geological study and a 293-km 2-D seismic
acquisition program were completed in Block 87 in an effort to develop multiple
prospects from previously identified leads.

In Argentina, the Company holds a 25.7 percent working interest in the Sierra
Chata concession in the Neuquen Basin. This asset has a gross sales capacity of
200 MMCF of natural gas per day from 39 producing wells. During 2002, gas sales
were curtailed due to low gas prices in Argentina, with production thus
averaging only 18 MMCF of natural gas per day net. Deferrals of capital programs
and a close focus on operating costs have helped mitigate the economic impact of
an approximate 70 percent devaluation of the Argentine peso.

West Africa

The Company participated in unsuccessful exploratory drilling offshore Angola
and Gabon during 2002. In Angola, the Company participated as a 25 percent
working interest holder in a well on the Kangandala prospect in Block 21. This
$3 million net dry hole was the second commitment well on the block. The Company
also holds a 25 percent working interest in each of the Mpolo, Chauillu and
Meboun blocks in Gabon. One well was drilled in each block in 2002 but all
proved uneconomical.

6

PRODUCTIVE WELLS

Working interests in productive wells at December 31, 2002 follow.

NET WELLS DRILLED

Drilling activity in 2002 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.

As of December 31, 2002, 67 gross wells, representing approximately 48 net
wells, were being drilled.

7

ACREAGE

Working interests in developed and undeveloped acreage at December 31, 2002
follow.

CAPITAL EXPENDITURES

Following are the Company's capital expenditures.

In 2002, worldwide capital expenditures of $1,601 million for oil and gas
activities include 49 percent for development, 13 percent for exploration and 38
percent for proved property acquisitions. Proved property acquisitions are
primarily related to the property acquisition from ATCO and the acquisition of
properties located in Wise and Denton Counties, Texas. Included in capital
expenditures for oil and gas activities are exploration costs expensed under the
successful efforts method of accounting.

8

OIL AND GAS PRODUCTION AND PRICES

The Company's average daily production represents its net ownership and includes
royalty interests and net profit interests owned by the Company. Following are
the Company's average daily production and average sales prices.

9

PRODUCTION UNIT COSTS

The Company's production unit costs follow. Production costs consist of
production taxes and well operating costs.

RESERVES

The following table sets forth estimates by the Company's petroleum engineers of
proved oil, NGLs and gas reserves at December 31, 2002. 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, oil
and NGLs that BR attributed to its net interests in oil and gas properties as of
December 31, 2002. Miller and Lents, Ltd. reviewed the reserve estimates for the
Company's U.S. and international interests (excluding Canada and Argentina) and
Sproule Associates Limited reviewed the Company's interests in Canada and
Argentina. 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 further information on reserves, including information on future net cash
flows and the standardized measure of discounted future net cash flows, see
"Supplementary Financial Information--Supplemental Oil and Gas Disclosures."

OTHER MATTERS

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

10

Company competes with numerous companies for the sale of oil, gas and NGLs.
Competitive factors in the Company's business include price, contract terms,
quality of service, pipeline access, transportation discounts and distribution
efficiencies.

Regulation of Oil and Gas Production, Sales and Transportation--The oil and gas
industry is subject to regulation by numerous national, state and local
governmental agencies and departments throughout the world. Compliance with
these regulations is often difficult and costly and noncompliance could result
in substantial penalties and risks. Most jurisdictions in which the Company
operates also have statutes, rules, regulations or guidelines governing the
conservation of natural resources, including the unitization or pooling of oil
and gas properties and the establishment of maximum rates of production from oil
and gas wells. Some jurisdictions also require the filing of drilling and
operating permits, bonds and reports. The failure to comply with these statutes,
rules and regulations could result in the imposition of fines and penalties and
the suspension or cessation of operations in affected areas.

The Company operates various gathering systems. The United States Department of
Transportation and certain governmental agencies regulate the safety and
operating aspects of the transportation and storage activities of these
facilities by prescribing standards. 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 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, the reclamation and
abandonment of wells, sites and facilities and the remediation of contaminated
sites. These laws and regulations may impose substantial liabilities for
noncompliance and for any contamination resulting from the Company's operations
and may require the suspension or cessation of operations in affected areas.

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

- - Clean Air Act, and its amendments, which governs air emissions;

- - Clean Water Act, which governs discharges to waters of the United States;

- - Comprehensive Environmental Response, Compensation and Liability Act, which
imposes liability where hazardous releases have occurred or are threatened to
occur;

- - Resource Conservation and Recovery Act, which governs the management of solid
waste;

- - Oil Pollution Act of 1990, which imposes liabilities resulting from discharges
of oil into navigable waters of the United States;

- - Emergency Planning and Community Right-to-Know Act, which requires reporting
of toxic chemical inventories;

- - Safe Drinking Water Act, which governs the underground injection and disposal
of wastewater; and

- - U.S. Department of Interior regulations, which impose liability for pollution
cleanup and damages.

In addition, many states and foreign countries where the Company operates have
similar environmental laws and regulations covering the same types of matters.
The Company routinely obtains permits for its facilities and operations in
accordance with these applicable laws and regulations on an ongoing basis. There
are no known issues that have a significant adverse effect on the permitting
process or permit compliance status of any of the Company's facilities or
operations.

The ultimate financial impact of these environmental laws and regulations is
neither clearly known nor easily determined as new standards continue to evolve.
Environmental laws and regulations are expected to have an increasing impact on
the Company's operations in the United States and in most countries in which it
operates. Potential permitting costs are variable and directly associated with
the type of facility and its geographic location. Costs, for example, may be
incurred for air emission permits, spill contingency requirements, and discharge
or injection permits. These costs are considered a normal, recurring cost of the
Company's ongoing operations and not an extraordinary cost of compliance with
government regulations.

The Company is committed to the protection of the environment throughout its
operations and believes that it is in substantial compliance with applicable
environmental laws and regulations. The Company believes that environmental

11

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. The Company does not anticipate that it will be required under
current environmental laws and regulations to expend amounts that will have a
material adverse effect on the consolidated financial position or results of
operations of the Company. However, because regulatory requirements frequently
change and may become more stringent and as with other companies engaged in
similar businesses, 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.

Filings of Reserve Estimates With Other Agencies--During 2002, the Company filed
estimates of its oil and gas reserves for the year 2001 with the Department of
Energy. These estimates differ by 5 percent or less from the reserve data
presented. For information concerning proved oil, NGLs and gas reserves, see
page 58.

EMPLOYEES

The Company had 2,003 and 2,167 employees at December 31, 2002 and 2001,
respectively. At December 31, 2002, 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. In addition, the Company has
adopted a Code of Business Conduct and Ethics that applies to directors,
officers and employees, including the principal executive officer, principal
financial officer and principal accounting officer or controller and has posted
such code on its Web site.

ITEM THREE

LEGAL PROCEEDINGS

The Company and numerous other oil and gas companies have been named as
defendants in various lawsuits alleging violations of the civil False Claims
Act. These lawsuits were consolidated during 1999 and 2000 for pre-trial
proceedings by the United States Judicial Panel on Multidistrict Litigation in
the matter of In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United
States District Court for the District of Wyoming (MDL-1293). The plaintiffs
contend that defendants underpaid royalties on natural gas and NGLs produced on
federal and Indian lands through the use of below-market prices, improper
deductions, improper measurement techniques and transactions with affiliated
companies during the period of 1985 to the present. Plaintiffs allege that the
royalties paid by defendants were lower than the royalties required to be paid
under federal regulations and that the forms filed by defendants with the
Minerals Management Service (MMS) reporting these royalty payments were false,
thereby violating the civil False Claims Act. The United States has intervened
in certain of the MDL-1293 cases as to some of the defendants, including the
Company. The plaintiffs and the intervenor have not specified in their pleadings
the amount of damages they seek from the Company.

Various administrative proceedings are also pending before the MMS of the United
States Department of the Interior with respect to the valuation of natural gas
produced by the Company on federal and Indian lands. In general, these
proceedings stem from regular MMS audits of the Company's royalty payments over
various periods of time and involve the interpretation of the relevant federal
regulations. Most of these proceedings involve production volumes and royalty
disputes that are the subject of Natural Gas Royalties Qui Tam Litigation.

Based on the Company's present understanding of the various governmental and
civil False Claims Act proceedings described above, the Company believes that it
has substantial defenses to these claims and intends to vigorously assert such
defenses. The Company is also exploring the possibility of a settlement of these
claims. Although there has been no formal demand for damages, the Company
currently estimates, based on its communications with the intervenor, that the
amount of underpaid royalties on onshore production claimed by the intervenor in
these proceedings is approximately $68 million. In the event that the Company is
found to have violated the civil False Claims Act, the Company could also be
subject to double damages, civil monetary penalties and other sanctions,
including a temporary suspension from bidding on and entering into future
federal mineral leases and other federal contracts for a defined period of time.
The Company has established a reserve that management believes to be adequate to
provide for this potential liability based upon its evaluation of this matter.
While the ultimate outcome and impact on the Company cannot be predicted with
certainty, management believes that the resolution of these proceedings through
settlement or adverse judgment will not have a

12

material adverse effect on the consolidated financial position or results of
operations of the Company, although cash flow could be significantly impacted in
the reporting periods in which such matters are resolved.

The Company has also been named as a defendant in the lawsuit styled UNOCAL
Netherlands B.V., et al v. Continental Netherlands Oil Company B.V., et al, No.
98-854, filed in 1995 in the District Court in The Hague and currently pending
in the Court of Appeal in The Hague, the Netherlands. Plaintiffs, who are
working interest owners in the Q-1 Block in the North Sea, have alleged that the
Company and other former working interest owners in the adjacent Logger Field in
the L16a Block unlawfully trespassed or were otherwise unjustly enriched by
producing part of the oil from the adjoining Q-1 Block. The plaintiffs claim
that the defendants infringed upon plaintiffs' right to produce the minerals
present in its license area and acted in violation of generally accepted
standards by failing to inform plaintiffs of the overlap of the Logger Field
into the Q-1 Block. Plaintiffs seek damages of $97.5 million as of January 1,
1997, plus interest. For all relevant periods, the Company owned a 37.5 percent
working interest in the Logger Field. Following a trial, the District Court in
The Hague rendered a Judgment in favor of the defendants, including the Company,
dismissing all claims. Plaintiffs thereafter appealed. On October 19, 2000, the
Court of Appeal in The Hague issued an interim Judgment in favor of the
plaintiffs and ordered that additional evidence be presented to the court
relating to issues of both liability and damages. The Company and the other
defendants are continuing to present evidence to the Court and vigorously assert
defenses against these claims. The Company has also asserted claims of indemnity
against two of the defendants from whom it had acquired a portion of its working
interest share. If the Company is successful in enforcing the indemnities, its
working interest share of any adverse judgment could be reduced to 15 percent
for some of the periods covered by plaintiffs' lawsuit. The Company is unable at
this time to reasonably predict the outcome, or, in the event of an unfavorable
outcome, to reasonably estimate the possible loss or range of loss, if any, in
this lawsuit. Accordingly, there has been no reserve established for this
matter.

In addition to the foregoing, the Company and its subsidiaries are named
defendants in numerous other lawsuits and named parties in numerous governmental
and other proceedings arising in the ordinary course of business, including:
claims for personal injury and property damage, claims challenging oil and gas
royalty and severance tax payments, claims related to joint interest billings
under oil and gas operating agreements, claims alleging mismeasurement of
volumes and wrongful analysis of heating content of natural gas and other claims
in the nature of contract, regulatory or employment disputes. None of the
governmental proceedings involve foreign governments. While the ultimate outcome
of these other lawsuits and proceedings cannot be predicted with certainty,
management believes that the resolution of these other matters will not have a
material adverse effect on the consolidated financial position, results of
operations or cash flows of the Company.

The Company has established reserves for legal proceedings which are included in
Other Liabilities and Deferred Credits on the Consolidated Balance Sheet. The
establishment of a reserve involves a complex estimation process that includes
the advice of legal counsel and subjective judgment of management. While
management believes these reserves to be adequate, it is reasonably possible
that the Company could incur additional loss of up to approximately $25 million
to $30 million in excess of the amounts currently accrued. Future changes in the
facts and circumstances could result in actual liability exceeding the estimated
ranges of loss and the amounts accrued.

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 2002.

EXECUTIVE OFFICERS OF THE REGISTRANT

Bobby S. Shackouls, 52--Chairman of the Board, President and Chief Executive
Officer, Burlington Resources Inc., July 1997 to present. President and Chief
Executive Officer, Burlington Resources Oil & Gas Company, October 1994 to June
1998.

Randy L. Limbacher, 44--Executive Vice President and Chief Operating Officer,
Burlington Resources Inc., December 2002 to present. Senior Vice President,
Production, Burlington Resources Inc., April 2001 to December 2002. President
and Chief Executive Officer, BROG GP Inc., general partner of Burlington
Resources Oil & Gas Company LP, December 2000 to July 2001. President and Chief
Executive Officer, Burlington Resources Oil & Gas Company, July 1998 to December
2000. Vice President, Gulf Coast Division, Burlington Resources Oil & Gas
Company, February 1997 to June 1998.

Steven J. Shapiro, 50--Executive Vice President and Chief Financial Officer,
Burlington Resources Inc., December 2002 to present. Senior Vice President and
Chief Financial Officer, Burlington Resources Inc., October 2000 to December
2002. Senior Vice President, Chief Financial Officer and Director, Vastar
Resources, Inc., 1993 to September 2000.

L. David Hanower, 43--Senior Vice President, Law and Administration, Burlington
Resources Inc., July 1998 to present. Senior Vice President, Law, Burlington
Resources Inc., April 1996 to June 1998.

John A. Williams, 58--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

13

to present. Senior Vice President, Exploration, Burlington Resources Oil & Gas
Company, July 1998 to December 2000. Senior Vice President, Exploration,
Burlington Resources Inc., October 1997 to June 1998.

PART II

ITEM FIVE

MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

The Company's common stock, par value $.01 per share (Common Stock) is traded on
the New York Stock Exchange under the symbol "BR" and on the Toronto Stock
Exchange under the symbol "B." At December 31, 2002, the number of holders of
Common Stock was 16,273. Information on Common Stock prices and quarterly
dividends is shown on page 60 under the subheading "Quarterly Financial
Data -- Unaudited." See also "Equity Compensation Plan Information" under Part
III, Item 12 of this report.

ITEM SIX

SELECTED FINANCIAL DATA

The selected financial data for the Company set forth below for the five years
ended December 31, 2002 should be read in conjunction with the consolidated
financial statements and accompanying notes thereto.

ITEMS SEVEN AND SEVEN A

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

BR is one of the largest independent exploration and production companies in
North America. The Company explores for, develops and produces natural gas, NGLs
and crude oil, primarily from its properties located in the Rocky Mountain
natural gas fairway of North America, complemented by several key international
projects. 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 the start-up and delivery of several
key projects.

The Company has adopted a very disciplined capital allocation process, with the
objective of achieving modest 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, BR 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 is often beyond the Company's control, and
"commercial", which includes commodity price volatility, local price
differentials in its various areas of operations and attention to operating
margins. Each of these factors is complex, challenging and highly variable.

To address subsurface risks, BR utilizes most 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

14

and accurately predict drilling results. The Company has put considerable
emphasis in recent years on creating an asset portfolio that improves the
reliability of those predictions; however, these types of operations tend to
exploit or develop smaller quantities of hydrocarbon reserves and, as a result,
the Company must develop more of these opportunities in order to maintain
production. Similarly, the Company has reduced its focus on areas where there is
far less analytical data available and drilling outcomes are less predictable,
such as wildcat exploration operations in sparsely explored areas. BR 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. BR values sound stewardship and strong
relationships with all stakeholders in conducting its business. The Company
attempts to stay abreast of emerging issues to effectively anticipate and manage
potential impacts to the Company's operations.

At BR, managing the commercial risks is an ongoing priority. 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 very 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, BR will from time to time use various
financial tools to hedge the price it will receive for a particular commodity in
the future. The primary purpose of these activities is to provide for adequate
financial returns on the significant investments that the Company makes annually
to replenish its productive base and grow its reserves while leaving as much
commodity price upside as possible for the Company's stockholders. Margin
enhancement is another important element in BR's business, including attention
to cash operating and administrative costs 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 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
commodity itself -- 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 are
usually established in a private market created by a willing seller and a
willing buyer of a given property or group of properties. The third asset class
consists of the equities of the publicly traded exploration and production
companies which are valued in the public market place daily. Because these three
asset classes are not always valued consistently with each other, opportunities
may exist from time to time to take advantage of these various valuation
differences. These valuation differences are key to BR's capital allocation
philosophy.

At BR, there are three types of investment alternatives that constantly compete
for available capital. These include drilling opportunities, acquisition
opportunities and financial opportunities such as share repurchases and debt
repayment. Depending on circumstances and the relative valuations of the asset
classes described above, BR allocates capital among its investment alternatives
which is 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 BR's management and staff to take into account all relevant factors,
which fluctuate constantly, will be a key determinant in the Company's future
performance.

OUTLOOK

The Company expects full year production volumes in 2003 to average between
2,573 and 2,708 MMCFE per day. In 2003, the Company is expected to experience
some gas equivalent production decreases as a result of property sales in 2002
and natural declines. However, the Company expects to offset these production
declines with new projects such as the Lost Cabin Gas Plant expansion in Madden
Field in Wyoming, which was completed during the third quarter of 2002, the
Ourhoud Field in Algeria and other projects that are anticipated to start-up
during 2003 such as crude oil development projects in the MLN Field in Algeria
and the Bootes and Ursa offshore Fields in China.

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 volatile. Commodity prices are affected by changes in
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 effect increases or
decreases in production volumes will have on future revenues.

15

In addition to production volumes and commodity prices, finding and developing
sufficient amounts of crude oil and natural gas reserves at economical costs are
critical to the Company's long-term success. In 2002, the Company spent
approximately $1.2 billion on development, exploration and plants and pipeline
capital and an additional $604 million on acquisitions. In 2002, the Company's
reserve replacement costs were $1.03 per MCFE excluding acquisitions or $1.06
per MCFE including acquisitions. The Company replaced 161 percent of its
worldwide production from all sources and 103 percent of its worldwide
production excluding acquisitions during 2002.

On June 30, 2002, the Company sold the Val Verde gathering and processing plant
(Val Verde Plant), which contributed $19 million in third party revenues in
2002. As a result of the sale, in addition to the future revenue loss, the
Company expects its transportation expenses to increase approximately $40
million annually offset partially by lower operating expenses of approximately
$11 million and lower DD&A of approximately $9 million. The Company has certain
wells that qualify for Section 29 Tax Credits. In 2002, the Company generated
$16 million of Section 29 Tax Credits. Production from qualified wells ceased to
generate Section 29 Tax Credits at the end of 2002.

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, 2002 and December 31, 2001
was 51 percent and 55 percent, respectively. The reduction in total debt to
total capital was accomplished by the use of proceeds from the disposal of
assets and the generation of cash flows from operations. Based on the current
price environment, the Company believes that it will generate sufficient cash
from operations to fund the 2003 capital expenditures, excluding potential
acquisitions. At December 31, 2002, the Company had $443 million of cash and
cash equivalents on hand.

In February 2002, Burlington Resources Finance Company (BRFC) issued $350
million of 5.7% Notes due March 1, 2007 (February Notes), which were fully and
unconditionally guaranteed by BR. The proceeds from the February Notes were used
to retire commercial paper that was issued to finance the acquisition of certain
assets from ATCO Gas and Pipeline Ltd. (ATCO). The February Notes reduced the
Company's amount available under its shelf registration statement on file with
the Securities and Exchange Commission (SEC) to $397 million. In May 2002, the
Company restored its shelf registration statement to $1,500 million.

In June 2002, the Company retired a $100 million 8 1/4% Note. To retire the
8 1/4% Note, the Company issued a $104 million promissory note at a per annum
rate equal to the sum of Eurodollar rates plus 0.70 percent. The $104 million
promissory note was retired on September 16, 2002. During 2002, the Company also
retired $675 million of net commercial paper and had no commercial paper
outstanding at December 31, 2002.

In June 2002, the Company commenced an offer to exchange outstanding 5.6% Notes
due 2006, 6.5% Notes due 2011 and 7.4% Notes due 2031, which were issued by BRFC
and fully and unconditionally guaranteed by BR, in a private offering in
November 2001 (Private Notes), for a like principal amount of 5.6% Notes due
2006, 6.5% Notes due 2011 and 7.4% Notes due 2031 to be issued by BRFC, fully
and unconditionally guaranteed by BR and registered under the Securities Act of
1933, as amended (Registered Notes). In July 2002, following the expiration of
the exchange offer, the Company issued the Registered Notes. All of the Private
Notes were exchanged for Registered Notes and the Private Notes were cancelled.

Burlington Resources Capital Trust I, Burlington Resources Capital Trust II
(collectively, the Trusts), BR and BRFC have a shelf registration statement on
file with the SEC as mentioned above. Pursuant to such registration statement,
BR may issue debt securities, shares of common stock or preferred stock. In
addition, BRFC may issue debt securities and the Trusts may issue trust
preferred securities. Net proceeds, terms and pricing of offerings of securities
issued under the shelf registration statement will be determined at the time of
the offerings.

BRFC and the Trusts are wholly owned finance subsidiaries of BR and have no
independent assets or operations other than transferring funds to BR's
subsidiaries. Any debt issued by BRFC is fully and unconditionally guaranteed by
BR. Any trust preferred securities issued by the Trusts are also fully and
unconditionally guaranteed by BR.

The Company had credit commitments in the form of revolving credit facilities
(Revolvers) as of December 31, 2002. The Revolvers are comprised of agreements
for $600 million, $400 million and Canadian $468 million (U.S. $296 million).
The $600 million Revolver expires in December 2006 and the $400 million and
Canadian $468 million Revolvers expire in December 2003 unless renewed by mutual
consent. The Company has the option to convert any remaining balances on the
$400 million and Canadian $468 million Revolvers to one-year and five-year plus
one day term notes, respectively. Under the covenants of the Revolvers, Company
debt cannot exceed 60 percent of capitalization (as defined in the agreements).
The Revolvers are available to cover debt due within one year, therefore,
commercial paper, credit facility notes and fixed-rate debt due within one year
are generally classified as long-term debt. At December 31, 2002, there are no
amounts outstanding under the Revolvers and no outstanding commercial paper.

Net cash provided by operating activities in 2002 was $1,549 million compared to
$2,106 million and $1,598 million in 2001 and 2000, respectively. The decrease
in 2002 compared to 2001 was primarily due to lower net income, excluding
non-cash items. Net income was lower principally as a result of lower natural
gas and NGLs prices and lower oil sales

16

volumes partially offset by higher natural gas and NGLs sales volumes. The
increase in 2001 compared to 2000 was primarily due to higher net income,
excluding non-cash items, resulting primarily from higher natural gas prices and
lower working capital needs.

The Company has various commitments primarily related to leases for office
space, other property and equipment and demand charges on firm transportation
agreements for its production of natural gas. The Company expects to fund these
commitments with cash generated from operations. The following table summarizes
the Company's contractual obligations at December 31, 2002.

(1) See discussion of long-term debt above and Note 7 of Notes to Consolidated
Financial Statements.
(2) See Note 11 of Notes to Consolidated Financial Statements for discussion of
these commitments.

Certain of the Company's contracts require the posting of collateral upon
request in the event that the Company's long-term debt is rated below investment
grade or ceases to be rated. Those contracts primarily consist of hedging
agreements, two Canadian transportation agreements and a natural gas purchase
agreement. A few of the hedging agreements also require posting of collateral if
the market value of the transactions thereunder exceed a specified dollar
threshold that varies with the Company's credit rating.

While the mark-to-market positions under the hedging agreements and the natural
gas purchase agreement will fluctuate with commodity prices, as a producer, the
Company's liquidity exposure due to its outstanding derivative instruments tends
to increase when commodity prices increase. Consequently, the Company is most
likely to have its largest unfavorable mark-to-market position in a high
commodity price environment when it is least likely that a credit support
requirement due to an adverse rating action would occur. At December 31, 2002,
the aggregate unfavorable mark-to-market position under the aforementioned
hedging agreements was approximately $13 million. A rating change would have had
no impact on the Company related to the natural gas purchase agreement since the
mark-to-market position under such agreement was favorable to the Company. In
the case of the Canadian transportation agreements, the collateral required
would be an amount equal to 12 months of estimated demand charges. That amount
totaled approximately $27 million as of December 31, 2002.

In the normal course of business, the Company has performance obligations which
are supported by surety bonds or letters of credit. These obligations are
primarily site restoration and dismantlement, royalty payments and exploration
programs where governmental organizations require such support.

Changes in credit rating also impact the cost of borrowing under the Company's
Revolvers, but have no impact on availability of credit under the agreements.
The Revolvers are filed as exhibits 10.18, 10.19 and 10.31 to this Form 10-K.

The Company has investments in three entities that it accounts for under the
equity method. The book values of the Company's interests in Lost Creek
Gathering Company, L.L.C. (Lost Creek), Evangeline Gas Pipeline Company
(Evangeline) and CLAM Petroleum B.V. (CLAM) are $13 million, $2 million and $31
million, respectively. As of December 31, 2002, CLAM had no outstanding debt,
Lost Creek had outstanding debt totalling $52 million and Evangeline had
outstanding debt totalling $43 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. At December 31, 2002, the Company also owns a
1.5 percent interest in a foreign entity that is accounted for at cost. The
Company is the guarantor of approximately $14 million of the entity's total
outstanding debt.

In December 2000, the Company's Board of Directors authorized the repurchase of
up to $1 billion of the Company's Common Stock. During 2002, the Company
repurchased none of its Common Stock. Through December 31, 2002, the Company has
repurchased approximately 16.3 million shares or $693 million of its Common
Stock under this $1 billion authorization.

The Company has certain other commitments and uncertainties related to its
normal operations. Management believes that there are no other commitments or
uncertainties that will have a material adverse effect on the consolidated
financial position, results of operations or cash flows of the Company.

17

CAPITAL EXPENDITURES AND RESOURCES

Capital expenditures in 2002 totaled $1,837 million compared to $3,454 million
and $1,012 million in 2001 and 2000, respectively. The Company invested $997
million on internal development and exploration of oil and gas properties during
2002 compared to $1,085 million and $858 million in 2001 and 2000, respectively.
The Company invested $604 million on property acquisitions in 2002 compared to
$1,997 million and $49 million in 2001 and 2000, respectively. Property
acquisitions in 2002 included the purchase of certain assets, located in the
Viking-Kinsella area, in January 2002 from ATCO, a Canadian regulated gas
utility, for approximately $344 million and $141 million for the purchase of
certain oil and gas properties located in Wise and Denton Counties, Texas in
August 2002. The Company also invested $193 million on plants and pipelines in
2002 compared to $346 million and $76 million in 2001 and 2000, respectively.
Property acquisitions and plants and pipelines in 2001 primarily included assets
from the Canadian Hunter Exploration Ltd. (Hunter) acquisition. See Note 2 of
Notes to Consolidated Financial Statements for additional information regarding
the Hunter acquisition. Capital expenditures in 2003, excluding proved property
acquisitions, are expected to be approximately $1.4 billion. Capital
expenditures in 2003 are expected to be primarily for internal development and
exploration of oil and gas properties and plant and pipeline expenditures.
Capital expenditures are expected to be funded from internal cash flows.

During the fourth quarter of 2001, the Company announced its intent to sell
certain non-core, non-strategic properties in order to improve the overall
quality of its portfolio, primarily in the U.S. Due to their high cost
structure, high production volume decline rates and limited growth
opportunities, substantially all of the Gulf of Mexico Shelf and south and east
Texas assets were included in the non-core, non-strategic properties. During
2002, the Company completed the sale of certain non-core, non-strategic
properties, including the Val Verde Plant. Based on the purchase and sale
agreements, the divestiture program sales price totaled $1.3 billion. Due to
differences between purchase and sale agreement dates and closing dates, the
Company generated proceeds, before post closing adjustments, of approximately
$1.2 billion and recognized a net pretax gain of $68 million. The producing
properties that were sold during the year generated $202 million, $401 million
and $416 million of revenues and incurred $140 million, $478 million and $336
million of direct operating expenses during the years 2002, 2001 and 2000,
respectively. The Company used a portion of the proceeds generated from property
sales to retire commercial paper, to repay the $104 million promissory note and
for general corporate purposes, including funding a portion of the Company's
capital program. The Company also expects to use the remaining proceeds for
general corporate purposes, including funding a portion of the Company's future
capital program.

In connection with the divestiture program, the Company also recorded a
restructuring liability of $10 million in the fourth quarter of 2001. As of
December 31, 2002, all of the restructuring liability had been paid.

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.

OTHER INTERNATIONAL

The Company's Other International production is marketed to third parties either
directly by the Company or by the operators of the properties. Production is
sold at the platforms or local sales points based on spot or contract prices.

QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK

Commodity Risk

Substantially all of the Company's crude oil, NGLs and natural gas production is
sold on the spot market or under short-term contracts at market sensitive
prices. Spot market prices for domestic crude oil and natural gas are subject to
volatile trading patterns in the commodity futures market, including among
others, the New York Mercantile Exchange (NYMEX). Quality differentials,
worldwide political developments and the actions of the Organization of
Petroleum Exporting Countries also affect crude oil prices.

18

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 the "basis differential." Basis differentials can vary widely depending on
various factors, including but not limited to, local supply and demand.

On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging
Activities, as amended. SFAS No. 133 establishes accounting and reporting
standards for derivative instruments and for hedging activities. It requires
enterprises to recognize all derivatives as either assets or liabilities on the
balance sheet and measure those instruments at fair value. The requisite
accounting for changes in the fair value of a derivative depends on the intended
use of the derivative and the resulting designation.

The Company utilizes over-the-counter price and basis swaps as well as options
to hedge its production in order to decrease its price risk exposure. The gains
and losses realized as a result of these price and basis derivative transactions
are substantially offset when the hedged commodity is delivered. In order to
accommodate the needs of its customers, the Company also uses price swaps to
convert natural gas sold under fixed-price contracts to market sensitive prices.

The Company uses a sensitivity analysis technique to evaluate the hypothetical
effect that changes in the market value of crude oil and natural gas may have on
the fair value of the Company's derivative instruments. For example, at December
31, 2002, 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 $97 million decrease in the net unrealized
gain. The derivative instruments in place at December 31, 2002 hedged
approximately 30 percent of the Company's expected natural gas production
volumes through 2003.

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

Credit and Market Risks

The Company manages and controls market and counterparty credit risk through
established formal internal control procedures which are reviewed on an ongoing
basis. The Company attempts to minimize credit risk exposure to counterparties
through formal credit policies and monitoring procedures. In the normal course
of business, collateral is not required for financial instruments with credit
risk.

Foreign Currency Risk

The Company's reported cash flows related to its Canadian operating subsidiaries
are based on cash flows measured in Canadian dollars and converted to the U.S.
dollar equivalent based on the average of the Canadian and U.S. dollar exchange
rates for the period reported. The Company's Canadian operating subsidiaries
have no financial obligations that are denominated in U.S. dollars.

DIVIDENDS

On January 22, 2003, the Board of Directors declared a common stock quarterly
cash dividend of $0.1375 per share, payable April 1, 2003 to shareholders of
record on March 7, 2003. Dividend levels are determined by the Board of
Directors based on profitability, capital expenditures, financing and other
factors. The Company declared cash dividends on Common Stock totaling
approximately $111 million and paid dividends totaling approximately $139
million during 2002. During the year, the Company paid five quarterly dividends,
including fourth quarter 2002, which normally would have been paid in January
2003.

APPLICATION OF CRITICAL ACCOUNTING POLICIES

Oil and Gas Reserves

The process of estimating quantities of natural gas, NGLs and crude oil reserves
is very complex, requiring significant decisions in the evaluation of all
available geological, geophysical, engineering and economic data. The data for a
given field may also change substantially over time as a result of numerous
factors including, but not limited to, additional development activity, evolving
production history and continual reassessment of the viability of production
under varying economic conditions. As a result, material revisions to existing
reserve estimates may occur from time to time. Although

19

every reasonable effort is made to ensure that reserve estimates reported
represent the most accurate assessments possible, the subjective decisions and
variances in available data for various fields make these estimates generally
less precise than other estimates included in the financial statement
disclosures. As described in Note 1 of Notes to Consolidated Financial
Statements, the Company uses the unit-of-production method to amortize its oil
and gas properties. Changes in reserve quantities as described above will cause
corresponding changes in depletion expense in periods subsequent to the quantity
revision or, in some cases, an impairment charge in the period of the revision.
See the Supplementary Financial Information for reserve data.

Successful Efforts Method of Accounting

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

Carrying Value of Long-Lived Assets

As more fully described in Note 1 of Notes to Consolidated Financial Statements,
the Company performs an impairment analysis whenever events or changes in
circumstances indicate an asset's carrying amount may not be recoverable. Cash
flows used in the impairment analysis are determined based upon management's
estimates of proved crude oil, NGLs and natural gas reserves, future crude oil,
NGLs and natural gas prices and costs to extract these reserves. Downward
revisions in estimated reserve quantities, increases in future cost estimates or
depressed crude oil, NGLs and natural gas prices could cause the Company to
reduce the carrying amounts of its properties. See Note 13 of Notes to
Consolidated Financial Statements for impairment of oil and gas properties.

Costs attributable to the Company's unproved properties 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. As these properties are developed
and reserves are proven, the remaining capitalized costs are subject to
depreciation and depletion. If the development of these properties is deemed
unsuccessful, the capitalized costs related to the unsuccessful activity is
expensed in the year 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.

Goodwill

As described in Note 3 of Notes to Consolidated Financial Statements, the
Company accounts for goodwill in accordance with SFAS No. 142, Goodwill and
Other Intangible Assets. SFAS No. 142 requires an annual impairment assessment
in lieu of periodic amortization. The impairment assessment requires management
to make estimates regarding the fair value of the reporting unit to which
goodwill has been assigned. These estimates are based on future net cash flows
and are based upon management's estimates of proved reserves as well as the
success of future exploration for and development of unproved reserves. Downward
revisions of estimated reserve quantities, increases in future cost estimates or
depressed crude oil, NGLs and natural gas prices could lead to an impairment of
all or a portion of goodwill in future periods.

Revenue Recognition

Natural gas, NGLs and crude oil revenues are recorded on 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 estimated production volumes. Subsequently, these estimated volumes are
adjusted to reflect actual volumes that are supported by third party pipeline
statements or cash receipts. Since there is a ready market for crude oil,
natural gas and NGLs, the Company sells the majority of its products soon after
production at various locations at which time title and risk of loss pass to the
buyer.

Legal, Environmental and Other Contingencies

A provision for legal, environmental and other contingencies is charged to
expense when the loss is probable and the cost can be reasonably estimated.
Determining when expenses should be recorded for these contingencies and the
appropriate amounts for accrual is a complex estimation process that includes
the subjective judgment of management. In many cases, management's judgment is
based on interpretation of laws and regulations, which can be interpreted
differently by regulators and/or courts of law. 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.

20

RESULTS OF OPERATIONS

Year Ended December 31, 2002 Compared With Year Ended December 31, 2001

The Company reported net income of $454 million or $2.25 diluted earnings per
common share in 2002 compared to net income of $561 million or $2.70 diluted
earnings per common share in 20