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, 2001

OR

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

COMMISSION FILE NUMBER 1-9971

BURLINGTON RESOURCES INC.
5051 WESTHEIMER, SUITE 1400, HOUSTON, TEXAS 77056
TELEPHONE: (713) 624-9500

INCORPORATED IN THE STATE OF DELAWARE EMPLOYER IDENTIFICATION NO. 91-1413284

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
COMMON STOCK, PAR VALUE $.01 PER SHARE
PREFERRED STOCK PURCHASE RIGHTS

THE ABOVE SECURITIES ARE REGISTERED ON THE NEW YORK STOCK EXCHANGE.

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No_____

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

State the aggregate market value of the voting stock held by non-affiliates
of the registrant: Common Stock aggregate market value as of January 31, 2002:
$6,878,464,321

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, 2002, Shares Outstanding: 200,889,729

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

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.

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 natural gas
reserves that is not a development well.

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.

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

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.

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.

Proved developed reserves are the portion of proved reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods.

Proved undeveloped reserves are the portion of proved reserves which can be
expected to be recovered from new wells on undrilled proved acreage, or from
existing wells where a relatively major expenditure is required for completion.

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.

BURLINGTON RESOURCES INC.

TABLE OF CONTENTS

PART I

ITEMS ONE AND TWO

BUSINESS AND PROPERTIES

Burlington Resources Inc. ("BR") is a holding company engaged, through its
principal subsidiaries, Burlington Resources Oil & Gas Company LP (formerly
known as Burlington Resources Oil & Gas Company), The Louisiana Land and
Exploration Company ("LL&E"), 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. On
September 17, 2001, as part of a reorganization of the Company's Canadian
subsidiaries, Burlington Resources Canada Inc., Burlington Resources Canada
Energy Ltd. and another wholly-owned Canadian subsidiary of the Company, were
amalgamated and are now known as Burlington Resources Canada Ltd. The Company is
one of North America's largest producers of natural gas.

On October 8, 2001, BR and Hunter entered into an agreement pursuant to
which BR agreed to make an offer to purchase all of the outstanding shares of
Hunter for cash consideration of C$53 per share representing an aggregate value
of approximately U.S. $2.1 billion resulting in an excess purchase price of
approximately $793 million which has been reflected as goodwill. On December 5,
2001, the transaction was consummated. This acquisition was funded primarily
with 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 attractive producing
properties, long-lived reserves and exploration and exploitation potential. The
assets acquired in the acquisition are primarily located in Canada's Western
Canadian Sedimentary Basin, an area in which the Company operated prior to the
Hunter acquisition. 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 Hunter acquisition added estimated proved reserves of 1.3 TCFE along
with approximately two million net undeveloped acres. The Hunter properties
averaged net production of 364 MMCF of gas per day, 16.7 MBbls of NGLs per day
and .5 MBbls of oil per day during December 2001, the period in which the
Company owned and operated these assets. 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. As a result, in December 2001, the Company recorded a pretax
impairment charge of $184 million ($116 million after tax) primarily related to
these properties resulting in net properties held for sale of $338 million and
related restructuring liabilities of $10 million. The $10 million restructuring
liability is related to severance and other exit costs and is included in
Accounts Payable at December 31, 2001. The held for sale properties are expected
to be sold in 2002. The Company expects to use the proceeds from property sales
to repay debt.

In November 1999, BR consummated the acquisition of Poco Petroleums Ltd.
valued at approximately $2.5 billion. In October 1997, BR completed a merger
with LL&E valued at approximately $3 billion. Both transactions were accounted
for under the pooling of interests method.

To reflect the change in the characteristics of its oil and gas properties,
in 2001, the Company began reporting its production volumes and reserves in
three streams: natural gas, crude oil and NGLs. Under this methodology, gas
production and reserves are reported after extracting liquids and eliminating
non-hydrocarbon gases from the natural gas stream. This change had no financial
impact and no material impact on total equivalent reserves or production
volumes. Amounts for prior years have been reclassified to conform to current
presentation.

Following is a review of the Company's worldwide major operating areas.

1

NORTH AMERICA

The Company's asset base is dominated by North American natural gas
properties. Its extensive North American lease holdings extend from the USA's
Gulf of Mexico to Canada's Mackenzie Delta region in the Northwest Territories
of the Canadian Arctic and Alaska's north slope. Reflecting a diverse yet
balanced portfolio, the Company's North American operations include a mix of
production, exploitation and exploration assets.

In 2001, oil and gas capital expenditures for the Company's USA operations
totaled $583 million, and consisted of $403 million for development projects,
$113 million for exploration and $67 million for proved reserve acquisitions.
The Company's USA production in 2001 represented 67 percent of the Company's
total or 1,121 MMCF of gas per day, 34.6 MBbls of NGLs per day and 44.0 MBbls of
oil per day. At December 31, 2001, USA proved reserves totaled 7.7 TCFE and
represented 66 percent of the Company's total.

In 2001, oil and gas capital expenditures for the Company's Canadian
operations totaled $2,282 million, and consisted of $288 million for development
projects, $94 million for exploration and $1,900 million for proved reserve
acquisitions, primarily the Hunter acquisition. The Company's Canadian
production in 2001 represented 24 percent of the Company's total or 433 MMCF of
gas per day, 12.5 MBbls of NGLs per day and 11.9 MBbls of oil per day. At
December 31, 2001, Canadian proved reserves totaled 2.8 TCFE and represented 23
percent of the Company's total.

USA

San Juan Basin

The San Juan Basin ("San Juan") is the Company's most prolific operating
area in terms of reserves and production. The area's activities are centered in
northwest New Mexico and southwest Colorado. San Juan encompasses nearly 7,500
square miles, or approximately 4.8 million acres, with the major portion located
in the New Mexico counties of Rio Arriba and San Juan. The Company is a
significant holder of productive leasehold acreage in this area with over
840,000 net acres under its control. The Company operates over 6,800 well
completions in San Juan and holds interests in an additional 3,900 non-operated
well completions. The Company also owns and operates the Val Verde gathering and
processing system, consisting of one of San Juan's largest treating plants and
approximately 460 miles of gathering lines with 12 compressor stations.

In 2001, the Company invested $146 million in oil and gas capital that
included investments for over 275 new wells and approximately 630 mechanical
workovers. Over 170 of the new wells and 360 of the workovers were Company
operated. The Company's net production from San Juan averaged approximately 629
MMCF of gas per day, 28.8 MBbls of NGLs per day and 1.4 MBbls of oil per day
during 2001.

A majority of the Company's growth in San Juan during the 1990's came from
production of coalbed methane gas from the Fruitland Coal formation. Beginning
in 1997, as the Fruitland Coal play matured, the Company began placing greater
emphasis on increasing production from conventional gas-producing 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 San Juan. In
2001, the Company continued its aggressive infill drilling program in San Juan's
Mesaverde formation developing an additional 76 BCFE of reserves. In the last
four years, the Company has added over 400 BCFE of reserves in the Mesaverde
formation and developed just over one half of these reserves.

The Company drilled 11 increased density wells in two areas in the Dakota
formation and obtained production and pressure data in 2001. Based on this data,
the Company presented a request for basin wide Dakota well spacing of 80 acres
to the New Mexico Oil Conservation Division on October 18, 2001. San Juan is
planning 15 of the 80-acre Dakota wells for 2002.

Although the Company's production from the Fruitland Coal formation peaked
in 1998, the Company continues to optimize coal gas production through the
application of technology. The Company has an ongoing optimization program that
consists of recavitating existing wells, adding compression and installing
artificial

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lift, where appropriate, to mitigate production decline. In 2001, net production
from the Fruitland Coal averaged 253 MMCF of gas per day from approximately
1,400 wells.

Development of the conventional horizons and minimizing production decline
in the Fruitland Coal continue to be a primary focus for the Company in San
Juan. In 2002, the Company will continue to exploit the San Juan reserve base
with low-risk, high return development projects while setting up future
exploitation opportunities by testing new ideas such as increased density
drilling in the Fruitland Coal and Pictured Cliffs formations.

Wind River Basin

The Madden Field, located in the Wind River Basin ("Wind River"), covers
more than 70,000 acres in Fremont and Natrona Counties, Wyoming. Production in
this basin occurs from multiple horizons ranging in depth from 5,000 feet to
over 25,000 feet. During 2001, the Company delineated the deep Madison reservoir
with the testing of the Big Horn #6-27 wildcat, accelerated infill development
with the drilling of the Big Horn #7-34 and #8-35 wells and continued
construction of the Lost Cabin Gas Plant Train III. All gas produced from the
Madison formation is sour and is currently processed at Lost Cabin Gas Plant
Trains I and II which have a combined inlet capacity of 130 MMCF of gas per day.
Completion of Lost Cabin Gas Plant Train III is expected during the third
quarter of 2002, adding 180 MMCF of gas per day of inlet capacity. Total Lost
Cabin Gas Plant inlet capacity will then be 310 MMCF of gas per day with plant
tail gate capacity of 200 MMCF of gas per day. The Company owns a 49 percent
working interest in the plant and approximately 42 percent of the Madison
reservoir.

In Wind River, the Company invested $30 million on approximately 30
drilling and workover projects in the deep Madison and shallower formations. The
Company also invested $65 million on plant construction in 2001. Net production
for Wind River averaged 74 MMCF of gas per day in 2001.

Williston Basin

The Williston Basin ("Williston") encompasses approximately 225,000 square
miles and has multiple producing horizons. The Company controls over 3.6 million
acres in Williston through both mineral and leasehold interests. Net production
for Williston averaged 7 MMCF of gas per day and 14.0 MBbls of oil per day in
2001. Activities in Williston have been focused on the Cedar Creek Anticline.
Production from the Cedar Creek Anticline was 9.6 MBbls of oil per day during
2001. The Company successfully unitized the Cedar Hills South Unit and initiated
waterflood development during 2001. The Company also initiated a down-spacing
pilot in the East Lookout Butte Unit during 2001. This pilot will test the
feasibility of 160-acre infill wells to improve waterflood efficiency. In 2001,
the Company invested $51 million on drilling and workover projects in Williston.
Certain non-core producing assets in Williston are scheduled for divestiture
during 2002.

Anadarko Basin

The Anadarko Basin ("Anadarko") encompasses over 30,000 square miles and
contains some of the deepest producing formations in the world. The Company
produces from multiple horizons in the basin, ranging in depth from 11,000 feet
to over 21,000 feet. The Company controls over 250,000 net acres principally
located in western Oklahoma. Net production for Anadarko averaged 97 MMCF of gas
per day and 1.4 MBbls of NGLs per day in 2001. In 2001, the Company invested $45
million in Anadarko.

Permian Basin

In 2001, Permian Basin ("Permian") operations were focused primarily on the
Waddell Ranch and Sonora areas. These areas comprise 62 percent of the Company's
net production from this basin. The remainder of Permian operations were
outsourced under property management agreements and are scheduled for
divestiture in 2002. Net production for the entire Permian averaged 54 MMCF of
gas per day, 2.3 MBbls of NGLs per day and 8.0 MBbls of oil per day in 2001. The
Company spent $33 million in Permian during 2001.

3

Onshore Gulf Coast

The Onshore Gulf Coast covers plays in south Louisiana and south and east
Texas, with a net acreage position of more than 870,000 acres including 660,000
acres of mineral fee lands in south Louisiana where the Company owns the mineral
rights and surface lands. Net production from these plays in 2001 averaged 134
MMCF of gas per day, .5 MBbls of NGLs per day and 7 MBbls of oil per day.

The focus for south Louisiana centers on exploiting lower risk
opportunities in and around core assets while exploring select higher risk,
higher reward opportunities. In south Louisiana, the Company spent $59 million
of oil and gas capital to participate in a total of 44 projects in 2001.
Exploitation activities included the drilling of a deeper well on the northwest
flank in Bay St. Elaine. An offset well was drilled resulting in accelerated
development of the shallower pay encountered in the initial well. Additional
drilling successes also occurred at the Pass Wilson and Ramos fields.

Activity in south and east Texas in 2001 focused primarily on the
development of assets in order to maintain production volumes. The Company
invested approximately $6 million of oil and gas capital on four projects. Net
production was 22 MMCF of gas per day at Armstrong Ranch in Jim Hogg County
where the Company has drilled 11 wells over the past three years. The Company
plans to divest substantially all of its south and east Texas assets in 2002 and
focus on opportunities in south Louisiana with its significant land position and
large 3-D seismic database.

Gulf of Mexico Shelf Trend

The Gulf of Mexico Shelf Trend ("Shelf") encompasses plays in the shallow
waters of the Gulf of Mexico at water depths of less than 1,000 feet. Over the
last three years, the Company has de-emphasized activity in the Shelf in favor
of investments in other areas which have longer-life assets with more favorable
cost structures and investment economics. Accordingly, capital investments in
this area have been reduced from annual levels of over $200 million in 1998 to
levels below $50 million in each of the last three years. During 2001, the
Company participated in a total of 42 Shelf projects and produced an average of
109 MMCF of gas per day, .9 MBbls of NGLs per day and 6.7 MBbls of oil per day.
The Company plans to divest substantially all of its Shelf assets in 2002 and
will focus its Gulf Coast activities on onshore south Louisiana.

Deepwater Gulf of Mexico

The Company owns 176,000 net acres in the deepwater provinces of the Gulf
of Mexico ("Deepwater"). The Company's exploration strategy for Deepwater
focuses on exploring opportunities identified on Company owned leases,
supplemented by third party generated prospects. The Company invested $78
million in Deepwater in 2001. Net production during 2001 averaged 12 MMCF of gas
per day and 2.1 MBbls of oil per day from the non-operated Pluto project that
was completed in late 1999. The Company plans to divest Pluto in early 2002.

Alaska

The Company was successful in the May 2001 Alaska State lease sale,
purchasing 184,320 net acres of land for $2 million. These lands are located in
the gas prone foothills south of Prudhoe Bay.

CANADA

Western Canadian Sedimentary Basin

In the Western Canadian Sedimentary Basin, the Company is active in
exploration, exploitation and production of oil and gas. A portfolio of
opportunities is maintained ranging from conventional exploration and
exploitation in Alberta and British Columbia, to frontier exploration in the
Mackenzie Delta.

Exploitation and exploration efforts in 2001 were focused primarily within
the Mesozoic and Mississippian sections of Central Alberta, in and around the
existing producing assets of Whitecourt/Wolf and O'Chiese. The multi-zone
potential of these areas, ranging in depth from 4,100 feet to 10,500 feet, makes

4

them an attractive part of the basin, and core assets to the Company. Eleven
exploration and 124 exploitation successes were realized in these asset areas,
and will create additional drilling locations for 2002. A single well Banff
discovery in the O'Chiese area has a gross potential of 40 BCF of gas with high
deliverability and will attract more drilling in 2002. The development and
exploitation program in the Wolf area resulted in the Wolf plant being loaded to
capacity. Net production from these two assets averaged 225 MMCF of gas per day,
7.5 MBbls of NGLs per day and 2.3 MBbls of oil per day for 2001 with an
investment of $172 million.

Exploitation and exploration activities in eastern Alberta and southeast
Saskatchewan in the shallow gas sands also resulted in 78 successes. Net
production averaged 65 MMCF of gas per day, 2.7 MBbls of NGLs per day and 8.6
MBbls of oil per day with an investment of $60 million for 2001.

Higher impact exploration opportunities have been pursued within the deeper
Devonian section of western and northern Alberta and northeastern British
Columbia. Active areas range from the Gregg Lakes/Berland area to the Hamburg
area in Alberta, and the foothills trend of Bullmoose/Sikunka in northeast
British Columbia. A successful 2001 development re-entry was drilled in the
Gregg Lakes area, targeting the Cooking Lake formation to a total vertical depth
of 18,000 feet. This is the second successful well in this field and one of the
deepest horizontal wells in western Canada at 21,670 feet measured depth. Both
wells are expected to be on production in 2002. Foothills exploration and
development drilling in British Columbia was reduced in 2001 with only two gross
wells being drilled. The Company will be reducing its capital exposure on this
risky play trend in the future by utilizing farm-outs to evaluate the future
potential of its lands. Exploration and development drilling in the Hamburg/Lady
Fern area, for Slave Point reef targets using 3-D seismic data, continues to
confirm the Company's interpretation of the geophysical signature and is
expected to result in a number of additional locations for 2002. Net production
from the area averaged 114 MMCF of gas per day, .9 MBbls of NGLs per day and 1.0
MBbls of oil per day for 2001. The Company invested $114 million here.

Beaufort Basin

The Northwest Territories Mackenzie Delta exploration program continued an
aggressive pace in 2001. The Company and its partners, BP/Canada and Chevron,
completed 181 kilometers ("km") of 2-D and 139 square km of 3-D seismic on our
540,000 gross acre exploration licenses. Plans are in place to shoot 310 square
km of 3-D seismic in 2002 and begin drilling exploration wells in 2003. Because
its costs are currently being carried by its partners, the Company incurred no
expenditures here during 2001.

OTHER INTERNATIONAL

Other International operations are a combination of exploration projects
and large field development operations. Key focus areas of operations are in the
Northwest European Shelf, North Africa, Latin America, the Far East and West
Africa. In 2001, oil and gas capital expenditures for Other International
operations totaled $217 million and consisted of $135 million for development
projects, $52 million for exploration and $30 million related to proved reserve
acquisitions. Other International production in 2001 represented nine percent of
the Company's total or 170 MMCF of gas per day and 7.3 MBbls of oil per day. At
December 31, 2001, Other International proved reserves totaled 1.3 TCFE and
represented 11 percent of the Company's total.

Northwest European Shelf

Other International development and production operations are currently
focused in Northwest Europe, which provides the majority of production outside
of the U.S. and Canada and includes assets in the East Irish Sea and in the
United Kingdom ("U.K.") and Dutch sectors of the North Sea.

The East Irish Sea assets became part of the portfolio in 1997 with the
acquisition of ten licenses covering 267,000 acres. The Company has a 100
percent working interest in seven operated gas fields. First production from the
two sweet gas fields at Dalton and Millom commenced in the third quarter of 1999
and at year-end 2001, the last of six producing wells drilled at Millom was
being completed. Development of the sour gas fields is now underway with first
production planned in 2004. In addition to offshore production facilities and

5

pipelines, a new onshore processing terminal is expected to be built to receive
and process the sour gas prior to final sale. Net production from the East Irish
Sea asset averaged 100 MMCF of gas per day during 2001. The Company invested $81
million in the East Irish Sea in 2001.

The Company's remaining Northwest European Shelf operations consist of
non-operated production from the Brae and T-Block complexes in the U.K. sector
of the North Sea and from the CLAM joint venture in the Dutch sector.

North Africa

The Company's North African operations are concentrated in Algeria and
offshore Egypt. Development operations are now underway in Algeria, with first
production expected in the first half of 2003. The Company invested $62 million
in Algeria in 2001.

In Menzel Lejmat Block 405a, in Algeria's Berkine Basin, the Company is the
operator and holds a 65 percent working interest. A total of 31 wells have been
drilled, including ten wildcat exploration wells. Development of the two MLN
Fields is now underway under a parliamentary decree and the Exploitation Permit,
issued by the Algerian government in late 2000. During 2001, the Company signed
a new Petroleum Sharing Contract ("PSC") with Sonatrach, the Algerian national
oil company, for an additional exploration license, Block 402d, in the Berkine
Basin. During 2002, 3-D seismic operations are expected to commence under this
new PSC. The Company also holds a small interest in the Ourhoud Field in the
northeast portion of the block. Ourhoud is currently under development by
Sonatrach with first production expected in 2003.

Exploitation License Agreements are presently being processed by Sonatrach
for additional satellite fields to the MLN Field. In the future, applications
will be filed for the southern MLSE Fields.

Engineering design preparations were advanced in 2001 for the development
of the non-operated Offshore North Sinai gas fields in Egypt for which a gas
sales agreement exists with the Egyptian General Petroleum Corporation.

Latin America

During 2001, the Company pursued opportunities in the sub-Andean plays in
South America. Across Ecuador and Peru, the Company farmed-in to three new
exploration blocks, shot 200 km of 2-D seismic, drilled one well and concluded
negotiations to acquire interests in one producing and one exploitation
property. Additionally, the Company made substantial progress toward moving one
existing block out of force majeure to enable exploration activities.

The exploration farm-ins include a 23.9 percent interest in Peru Block 35
and a 20 percent interest in Peru Block 34. Blocks 34 and 35 have 2.8 million
and 2.6 million acres, respectively, in the Ucayali Basin, and are located
approximately 100 km north of Camisea. Interest in both blocks was obtained from
Repsol, the operator, and Perez Companc. The Mashansha prospect will be drilled
on Block 35 in 2002. BR also farmed-in to a 50 percent interest in Ecuador Block
23. The Compania General de Combustibles S.A. operated block is adjacent to
Block 24, which is owned 100 percent by BR. Efforts continue to focus on
indigenous issues in these two blocks to enable exploration efforts.

A field geological study and a 200 km, 2-D seismic acquisition program were
completed in Peru Block 87, in an effort to better define multiple prospects.
Processing of the data will be completed in time to drill during the dry season
of 2002, if warranted. The Guineyacu prospect on Peru Block 32 was drilled
mid-year but found sub-economic quantities of oil and the block was subsequently
released to the government.

In Ecuador, the acquisition of a 25 percent interest in Ecuador Block 7 and
a 32.5 percent interest in Ecuador Block 21 from Sipetrol and Clapsa provides
production, development and exploration opportunities. This acquisition closed
on February 8, 2002. Gross production from Block 7 averaged approximately 14.5
MBbls of oil per day in 2001. Exploration and exploitation opportunities also
exist on the block. Development of the Yuralpa Field is underway on Block 21,
with first production anticipated during 2003.

6

BR has a 25.7 percent interest in the Sierra Chata concession in the
Neuquen Basin in Argentina as a result of the Hunter acquisition. The asset has
a gross sales capacity of 178 MMCF of gas per day through 42 producing wells.
Net production from this asset averaged 21 MMCF of gas per day during December
2001. Gas marketing efforts have largely focused on Chilean and Argentine
markets, facilitated through existing infrastructure, which enables substantial
flexibility.

BR holds a 13.7 percent interest in the Casanare concession area in
Colombia, which has maintained production of 1.5 MBbls of oil per day net, due
to a development drilling and workover program. The interest in Casanare is
scheduled for divestiture during 2002.

Far East

In the Far East, the Company continues to focus on selected basins in
China. The Company is targeting exploration and exploitation opportunities to
add to its existing leasehold position.

In 2001, approval was received and work for the Panyu development project
began. The Panyu development involves two offshore oil fields, Bootes and Ursa,
located in Block 15/34. The Company holds a 24.5 percent non-operated interest
in Block 15/34, located in the Pearl River Mouth Basin offshore China. These
fields contain net proved reserves of 14.7 MMBbls of oil. Devon is the operator
and first production is expected in 2003.

The Company obtained the Chuanzhong Block in the Sichuan Basin onshore
China in 2000. This natural gas project is currently in the appraisal phase of
development and the Company holds a 100 percent operated interest. This project
offers an opportunity to apply the Company's expertise in exploitation of tight
gas reservoirs in a concession with substantial reserve potential. The project
is currently in a pilot phase of drilling new wells and stimulating existing
wells. Additional work is contingent on successful negotiation of a long-term
gas marketing agreement. The Company invested $15 million in China in 2001.

West Africa

In West Africa, the Company has been targeting acquisitions of low working
interests in a variety of new and untested deepwater plays that have the promise
of high upside potential. The three blocks in Gabon that the Company holds with
operator, Agip, did not initiate drilling in 2001 due to rig equipment problems.
The license period for these blocks has been extended for a year and drilling is
expected to occur in the second quarter of 2002.

In 2001, the Company added to its exploration acreage portfolio in the
region by entering into an agreement with BP to acquire their entire 20 percent
interest in Block 21, deepwater Angola. The Company's entry into this block is
expected in 2002.

Together with its large acreage position in deepwater Gabon, the Company
has now established a foothold in a number of plays in the area. The Company's
approach is to learn from the exploration activities expected to occur in the
coming year.

7

RESERVES

The following table sets forth estimates by the Company's petroleum
engineers of proved oil, NGL and gas reserves at December 31, 2001. These
reserves have been reduced for royalty interests owned by others. To reflect the
change in the characteristics of its oil and gas properties, in 2001, the
Company began reporting its production volumes and reserves in three streams:
natural gas, crude oil and NGLs. Under this methodology, gas reserves are
reported after extracting liquids and eliminating non-hydrocarbon gases from the
natural gas stream. This change had no material impact on total equivalent
reserves.

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."

PRODUCTIVE WELLS

Working interests in productive wells at December 31, 2001 follow.

8

NET WELLS DRILLED

Drilling activity in 2001 was principally in the Western Canadian
Sedimentary, San Juan, Gulf Coast, Permian, Anadarko, Wind River and Williston
Basins. The following table sets forth the Company's net productive and dry
wells.

As of December 31, 2001, 41 gross wells, representing approximately 31 net
wells, were being drilled.

9

ACREAGE

Working interests in developed and undeveloped acreage at December 31, 2001
follow.

CAPITAL EXPENDITURES

Following are the Company's capital expenditures.

Worldwide capital expenditures for oil and gas activities in 2001 of $3,082
million include 27 percent for development, 8 percent for exploration and 65
percent for proved property acquisitions. Proved property acquisitions are
primarily related to the Hunter acquisition. Included in capital expenditures
for oil and gas activities are exploration costs expensed under the successful
efforts method of accounting.

10

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. In
2001, the Company began reporting its production volumes and reserves in three
streams: natural gas, crude oil and NGLs. Under this methodology, gas production
is reported after extracting liquids and eliminating non-hydrocarbon gases from
the natural gas stream. Amounts for prior years have been reclassified to
conform to current presentation. Following are the Company's production and
prices.

11

PRODUCTION UNIT COSTS

Following are the Company's production unit costs. Production costs consist
of production taxes and well operating costs.

For additional financial information about segments and geographic areas,
see Note 13 of Notes to Consolidated Financial Statements.

OTHER MATTERS

Competition. The Company actively competes for reserve acquisitions,
exploration leases and sales of oil and gas, frequently against companies with
substantially larger financial and other resources. In its marketing activities,
the Company competes with numerous companies for the sale of oil, gas and NGLs.
Competitive factors in the Company's business include price, contract terms,
quality of service, pipeline access, transportation discounts and distribution
efficiencies.

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

The Company operates various gathering systems. The United States
Department of Transportation and certain governmental agencies regulate the
safety and operating aspects of the transportation and storage activities of
these facilities by prescribing standards.

The Federal Energy Regulation Commission ("FERC") has implemented policies
allowing interstate pipeline companies to negotiate their rates with individual
shippers. The Company will monitor the effects of these policies on its
marketing efforts but does not expect that they will have a material adverse
effect on the consolidated financial position, results of operations or cash
flows of the Company. All of the Company's sales of its domestic gas are
currently deregulated, although FERC may elect in the future to regulate certain
sales.

Environmental Regulation. Various federal, state and local laws and
regulations relating to the protection of the environment, including the
discharge of materials into the environment, may affect the Company's domestic
exploration, development and production operations and the costs of those
operations. In addition, certain of the Company's international operations are
subject to environmental regulations adminis-

12

tered by foreign governments, including political subdivisions thereof, or by
international organizations. These domestic and international laws and
regulations, among other things, govern the amounts and types of substances that
may be released into the environment, the issuance of permits to conduct
exploration, drilling and production operations, the discharge and disposition
of generated waste materials, the reclamation and abandonment of wells, sites
and facilities and the remediation of contaminated sites. These laws and
regulations may impose substantial liabilities for noncompliance and for any
contamination resulting from the Company's operations and may require the
suspension or cessation of operations in affected areas. Environmental
requirements have a substantial impact on the oil and gas industry, and on the
costs of doing business.

The Company is committed to the protection of the environment throughout
its operations and believes that it is in substantial compliance with applicable
environmental laws and regulations. The Company believes that environmental
stewardship is an important part of its daily business and will continue to make
expenditures on a regular basis relating to environmental compliance. The
Company also maintains insurance coverage for some environmental risks, although
it is not fully insured against all such risks. The Company does not anticipate
that it will be required under current environmental laws and regulations to
expend amounts that will have a material adverse effect on the consolidated
financial position or results of operations of the Company. However, because
regulatory requirements frequently change and may become more stringent, there
can be no assurance that future laws and regulations will not have a material
adverse effect on the Company's consolidated financial position, results of
operations or cash flows.

Filings of Reserve Estimates With Other Agencies. During 2001, the Company
filed estimates of oil and gas reserves for the year 2000 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 57.

EMPLOYEES

The Company had 2,167 and 1,783 employees at December 31, 2001 and 2000,
respectively. At December 31, 2001, the Company had no union employees.

ITEM THREE

LEGAL PROCEEDINGS

The Company and numerous other oil and gas companies have been named as
defendants in various lawsuits alleging violations of the civil False Claims
Act. These lawsuits have been consolidated by the United States Judicial Panel
on Multidistrict Litigation for pre-trial proceedings in the matter of In re
Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court
for the District of Wyoming ("MDL-1293"). The plaintiffs contend that defendants
underpaid royalties on natural gas and NGLs produced on federal and Indian lands
through the use of below-market prices, improper deductions, improper
measurement techniques and transactions with affiliated companies. Plaintiffs
allege that the royalties paid by defendants were lower than the royalties
required to be paid under federal regulations and that the forms filed by
defendants with the Minerals Management Service ("MMS") of the United States
Department of the Interior reporting these royalty payments were false, thereby
violating the civil False Claims Act. The United States has intervened in
certain of the MDL-1293 cases as to some of the defendants, including the
Company.

Various administrative proceedings are also pending before the MMS of the
United States Department of the Interior with respect to the valuation of
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.

Based on the Company's present understanding of the various governmental
and False Claims Act proceedings described above, the Company believes that it
has substantial defenses to these claims and intends to vigorously assert such
defenses. However, in the event that the Company is found to have violated the
civil False Claims Act, the Company could be subject to monetary damages and a
variety of sanctions, including double damages, substantial monetary fines,
civil penalties and a temporary suspension from entering into

13

future federal mineral leases and other federal contracts for a defined period
of time. While the ultimate outcome and impact on the Company cannot be
predicted with certainty, management believes that the resolution of these
proceedings through settlement or adverse judgment will not have a material
adverse effect on the consolidated financial position of the Company, although
results of operations and cash flow could be significantly impacted in the
reporting periods in which such matters are resolved.

The Company has also been named as a defendant in the lawsuit styled UNOCAL
Netherlands B.V., et al v. Continental Netherlands Oil Company B.V., et al, No.
98-854, in the Court of Appeal in The Hague in the Netherlands. Plaintiffs, who
are working interest owners in the Q1 Block in the North Sea, have alleged that
the Company and other former working interest owners in the adjacent Logger
Field in the L16a Block unlawfully trespassed or were otherwise unjustly
enriched by producing part of the oil from the adjoining Q1 Block. The
plaintiffs claim that the defendants infringed upon plaintiffs' right to produce
the minerals present in its license area and acted in violation of generally
accepted standards by failing to inform plaintiffs of the overlap of the Logger
Field into the Q-1 Block. For all relevant periods, the Company owned a 37.5%
working interest in the Logger Field. Following a trial, the District Court in
The Hague rendered a Judgment in favor of the defendants, including the Company,
dismissing all claims. Plaintiffs thereafter appealed. On October 19, 2000, the
Court of Appeal in The Hague issued an interim Judgment in favor of the
plaintiffs and ordered that additional evidence be presented to the court
relating to issues of both liability and damages. The Company and the other
defendants are continuing to vigorously assert defenses against these claims and
have presented additional evidence to the Court of Appeal. The Company has also
asserted claims of indemnity against two of the defendants from whom it had
acquired a portion of its working interest share. The Company is unable at this
time to reasonably predict the outcome, or, in the event of an unfavorable
outcome, to reasonably estimate the possible loss or range of loss, if any, in
this lawsuit.

In addition to the foregoing, the Company and its subsidiaries are named
defendants in numerous other lawsuits and named parties in governmental and
other proceedings arising in the ordinary course of business. While the outcome
of these other lawsuits and proceedings cannot be predicted with certainty,
management believes these other matters will not have a material adverse effect
on the consolidated financial position, results of operations or cash flows of
the Company.

ITEM FOUR

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None

PART II

ITEM FIVE

MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

The Company's common stock, par value $.01 per share ("Common Stock") is
traded on the New York Stock Exchange under the symbol "BR." At December 31,
2001, the number of holders of Common Stock was 17,531. Information on Common
Stock prices and quarterly dividends is shown on page 60.

14

ITEM SIX

SELECTED FINANCIAL DATA

The selected financial data for the Company set forth below for the five
years ended December 31, 2001 should be read in conjunction with the
consolidated financial statements.

ITEMS SEVEN AND SEVEN A

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

FINANCIAL CONDITION AND LIQUIDITY

The Company's long-term debt to total capital (total capital is defined as
long-term debt and stockholders' equity) ratio at December 31, 2001 and December
31, 2000 was 55 percent and 38 percent, respectively. In February 2001, the
Company, through its wholly-owned subsidiary, Burlington Resources Finance
Company ("BRFC"), issued $400 million of 6.68% Notes due February 15, 2011.

On July 18, 2001, the Company's Board of Directors authorized the Company
to redeem or repurchase up to $1 billion principal amount of debt securities of
the Company. In August 2001, the Company acquired notes with an aggregate
principal amount of $710 million and a weighted average interest rate of 7.28%
and issued $178 million of 6.4% Notes and $575 million of 7.2% Notes due August
15, 2011 and 2031, respectively. The transaction was accounted for as an
exchange of debt instruments and reduced the Company's amount available under
its shelf registration statement on file with the Securities and Exchange
Commission ("SEC") from $1,500 million to $747 million. On October 8, 2001, the
Company's Board of Directors authorized the Company to restore its shelf
registration statement to $1,500 million. The Company expects to file such
registration statement in the first half of 2002.

In November 2001, the Company issued $500 million of 5.6% Notes due
December 1, 2006, $500 million of 6.5% Notes due December 1, 2011 and $500
million of 7.4% Notes due December 1, 2031. These notes were issued through a
private placement and the proceeds were used, along with cash on hand and the
issuance of $400 million of commercial paper, to fund the Hunter acquisition.

During 2001, the Company issued $348 million of net commercial paper.
Commercial paper outstanding at December 31, 2001 was $675 million with a
weighted average interest rate of approximately 3%. On October 1, 2001, the
Company retired $150 million of 8 1/2% Notes. The Company also repaid $61
million of other debt during the year. On December 13, 2001, the Company's Board
of Directors authorized the Company to redeem or repurchase an additional $700
million principal amount of debt securities.

15

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, 2001. The revolvers which are
comprised of agreements for $600 million, $400 million and $300 million are
available to cover debt due within one year. Therefore, commercial paper, credit
facility notes and fixed-rate debt due within one year are classified as
long-term debt. Currently, there are no amounts outstanding under the revolvers,
however, the Company's outstanding commercial paper reduces the amount of credit
available under the revolvers. The $600 million revolver expires in December
2006 and the $400 million and $300 million revolvers expire in December 2002
unless renewed by mutual consent. At expiration of the agreements, the Company
has the option to convert the outstanding balances on the $400 million and $300
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).

Effective January 2, 2002, the Company entered into a $350 million bridge
revolving credit facility in order to finance the acquisition of certain assets
from ATCO Gas and Pipelines Ltd. Any advances under the facility are required to
be used to finance this acquisition or to repay commercial paper issued in order
to finance this acquisition. On January 2, 2002, the Company issued $346 million
of commercial paper to fund the acquisition. The facility expires in July 2002.
On December 13, 2001, the Company's Board of Directors authorized the Company to
issue debt securities, either through a private placement or public offering, in
order to refinance any outstanding amounts under the facility or commercial
paper issued in connection with the acquisition.

Net cash provided by operating activities in 2001 was $2,106 million
compared to $1,598 million and $1,102 million in 2000 and 1999, respectively.
The increase in 2001 was primarily due to higher operating income, excluding
non-cash items, and lower working capital needs. Operating income was higher
principally as a result of higher natural gas prices. The increase in 2000
compared to 1999 was primarily due to higher operating income resulting from
higher commodity prices partially offset by working capital and other changes.

The Company has various commitments primarily related to leases for office
space, other property and equipment and demand charges on firm transportation
agreements. The Company expects to fund these commitments with cash generated
from operations. The following table summarizes the Company's contractual
obligations at December 31, 2001.

16

- ---------------

(1) See discussion of long-term debt commercial paper above and Note 6 of Notes
to Consolidated Financial Statements.

Certain of the Company's contracts require the posting of collateral upon
request in the event that the Company's long-term debt is rated below investment
grade or ceases to be rated. Those contracts primarily consist of hedging
agreements, 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,
2001, a rating change would have had no impact on the Company related to the
hedging agreements, since the mark-to-market position under each of the
respective agreements 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 $9
million as of December 31, 2001.

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 10.32 to this
Form 10-K.

The Company has investments in two 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") and CLAM Petroleum B.V. ("CLAM") are $8
million and $24 million, respectively. Lost Creek and CLAM have debt obligations
in the amount of $53 million and $20 million, respectively, that are
non-recourse to the Company. Management believes that even if the Company's
share of the debt obligations of these entities were deemed obligations of the
Company, the amounts would not have a material impact on the Company's
liquidity.

In December 2000, the Company's Board of Directors authorized the
repurchase of up to $1 billion of the Company's Common Stock. During 2001, the
Company repurchased 16.1 million shares of its Common Stock for approximately
$684 million. Through December 31, 2001, 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.

CAPITAL EXPENDITURES AND RESOURCES

Capital expenditures for 2001 totaled $3,454 million compared to $1,012
million and $989 million in 2000 and 1999, respectively. The Company invested
$1,085 million on internal development and exploration of oil and gas properties
during 2001 compared to $858 million and $792 million in 2000 and 1999,
respectively. The Company invested $1,997 million for property acquisitions in
2001 compared to $49 million and $135 million in 2000 and 1999, respectively.
The Company also invested $346 million on plants and pipelines in 2001 compared
to $76 million and $18 million in 2000 and 1999, respectively. Property
acquisitions and plants and pipelines in 2001 primarily include assets from the
Hunter acquisition. See Note 2 of Notes to Consolidated Financial Statements for
additional information. Capital expenditures for 2002, excluding proved property
acquisitions, are projected to be approximately $1.3 billion. Capital
expenditures are expected to be primarily

17

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.

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. As a result, in December 2001, the Company recorded a pretax
impairment charge of $184 million ($116 million after tax) primarily related to
these properties resulting in net properties held for sale of $338 million and
related restructuring liabilities of $10 million. The $10 million restructuring
liability is related to severance and other exit costs and is included in
Accounts Payable on the Consolidated Balance Sheet at December 31, 2001. The
held for sale properties are expected to be sold in 2002. The Company expects to
use the proceeds from property sales to repay debt.

MARKETING

North America (USA 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.

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.

There is also a difference between the NYMEX futures contract price for a
particular month and the actual cash price received for that month in a U.S.
producing basin or at a U.S. market hub, which is referred to as the "basis
differential."

On January 1, 2001, the Company adopted 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 in the balance sheet and measure those instruments
at fair value. The requisite accounting for changes in the fair value of a
derivative depends on the intended use of the derivative and the resulting
designation.

In accordance with the transition provisions of SFAS No. 133, the Company
recorded a net-of-tax cumulative-effect-type adjustment of $366 million loss in
accumulated other comprehensive income to recognize at fair value all
derivatives that are designated as cash flow hedging instruments. The Company

18

recorded cash flow hedge derivatives liabilities of $582 million ($361 million
after tax) and $3 million after tax was recorded in current earnings as a
cumulative effect of the change in accounting principle. The Company
reclassified, as reductions to earnings during 2001, $322 million ($200 million
after tax) from the transition adjustment that was recorded in accumulated other
comprehensive income.

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, 2001, the potential decrease in fair value of
derivative instruments assuming a 10 percent adverse movement (an increase in
the underlying commodities prices) would result in a $72 million decrease in the
net unrealized gain. The derivative instruments in place at December 31, 2001
hedged approximately 22 percent of the Company's projected production volumes
through 2002.

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, monitoring procedures and, if
necessary, through establishment of valuation reserves related to counterparty
credit risk. In the normal course of business, collateral is not required for
financial instruments with credit risk. Historically, the Company has suffered
minimal losses from credit risk.

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 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 units-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. See
the Supplementary Financial Information for reserve data.

19

CARRYING VALUE OF LONG-LIVE 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 oil, NGLs and gas reserves, future oil,
NGLs and gas prices and costs to extract these reserves. Downward revisions in
estimated reserve quantities, increases in future cost estimates or depressed
oil, NGLs and gas prices could cause the Company to reduce the carrying amounts
of its properties. As described in Note 12 of Notes to Consolidated Financial
Statements, the Company recorded a pretax impairment charge of $184 million and
$225 million for the years ended December 31, 2001, and 1999, respectively.

NATURAL GAS MEASUREMENT

The Company records estimated amounts for natural gas revenues and natural
gas purchase costs based on volumetric calculations under its natural gas sales
and purchase contracts. Variances or imbalances resulting from such calculations
are inherent in natural gas sales, production, operations, measurement and
administration. Management does not believe that differences between actual and
estimated natural gas revenues or purchase costs attributable to the unresolved
variances or imbalances are material.

FOREIGN CURRENCY RISK

The Company's reported cash flows related to Canadian operations is 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 subsidiaries have no financial
obligations that are denominated in U.S. dollars.

DIVIDENDS

On January 9, 2002, the Board of Directors declared a common stock
quarterly cash dividend of $.1375 per share, payable April 1, 2002 to
shareholders of record on March 8, 2002. 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 $113 million during 2001.

RESULTS OF OPERATIONS

Year Ended December 31, 2001 Compared With Year Ended December 31, 2000

The Company reported net income of $561 million or $2.70 diluted earnings
per common share in 2001 compared to net income of $675 million or $3.12 diluted
earnings per common share in 2000. Net income in 2001 included a non-cash after
tax charge of $116 million or $.56 per diluted share primarily related to the
impairment of oil and gas properties held for sale. The Company evaluates the
impairment of its oil and gas properties on a field-by-field basis whenever
events or changes in circumstances indicate an asset's carrying amount may not
be recoverable. In December 2001, primarily as a result of the Company's
decision to exit the Gulf of Mexico Shelf and divest of certain other
properties, the Company recognized a pretax charge of $184 million ($116 million
after tax) related to those properties. The Company also recognized a $6 million
after tax restructuring charge or $.03 per share related to severance and other
exit costs. Net income in 2001 also included an after tax gain of $12 million or
$.06 per diluted share consisting of ineffectiveness of cash-flow and fair-value
hedges and gains on derivative instruments which do not qualify for hedge
accounting under Statement of Financial Accounting Standards ("SFAS") No. 133,
Accounting for Derivative Instruments and Hedging Activities, as amended. The
Company adopted SFAS No. 133 effective January 1, 2001. For more discussion of
SFAS No. 133, see Note 1 of Notes to Consolidated Financial Statements. The
results of operations for 2001 include one month of activities related to the
Canadian Hunter Exploration Ltd. ("Hunter") acquisition.

To reflect the change in the characteristics of its oil and gas properties,
in 2001, the Company began reporting its production volumes and reserves in
three streams: natural gas, crude oil and NGLs. Under this

20

methodology, gas production is reported after extracting liquids and eliminating
non-hydrocarbon gases from the natural gas stream. This change had no financial
impact and no material impact on total equivalent production volumes. Amounts
for prior years have been reclassified to conform to current presentation.

Revenues increased $179 million to $3,326 million in 2001 compared to
$3,147 million in 2000. Revenues in 2001 increased $267 million compared to 2000
as a result of higher gas prices partially offset by lower oil and NGL prices.
Including a $.48 realized loss per MCF related to hedging activities, average
gas prices increased $.57 per MCF in 2001 to $3.94 per MCF from $3.37 per MCF in
2000 which increased revenues $362 million. The increase in revenues related to
higher gas prices was partially offset by a reduction in revenues due to lower
average oil and NGL prices. Including a $1.10 realized loss per barrel related
to hedging activities, average oil prices decreased $1.99 per barrel in 2001 to
$23.45 per barrel from $25.44 per barrel in 2000 resulting in reduced revenues
of $47 million. Average NGL prices decreased $2.79 per barrel in 2001 to $14.35
per barrel from $17.14 per barrel in 2000 resulting in reduced revenues of $48
million.

A decline in oil sales volumes resulted in a decrease in revenues of $107
million in 2001 compared to 2000. Oil sales volumes decreased 10.5 MBbls per day
in 2001 to 63.2 MBbls per day from 73.7 MBbls per day in 2000 reducing revenues
$100 million. Gas sales volumes were the same as the prior year at 1,724 MMCF
per day, however, due to one less day in 2001 compared to 2000, gas revenues
were down $6 million. NGL sales volumes decreased slightly to 47.1 MBbls per day
in 2001 from 47.2 MBbls per day in 2000, resulting in a reduction in revenues of
$1 million. Oil sales volumes decreased primarily due to natural production
declines and reduced capital spending in the Gulf Coast and Mid-Continent areas
and property sales in 2000. Although total gas sales volumes were the same as
the prior year, sales volumes were higher in Canada and East Irish Sea. Gas
sales volumes were higher in Canada due to a successful drilling program and the
Hunter acquisition and East Irish Sea was higher due to an additional interest
acquired in the area. These increases were offset primarily due to lower sales
volumes in the San Juan, Gulf of Mexico and south Louisiana areas. Gas sales
volumes were lower in these areas due to lower capital spending in the Gulf of
Mexico and natural declines in the other areas. Revenues in 2001 also included a
$19 million gain related to ineffectiveness of cash-flow and fair-value hedges
and gains on derivative instruments which do not qualify for hedge accounting.

Costs and Expenses were $2,241 million in 2001 compared to $1,956 million
in 2000. Costs and Expenses for 2001 included a $184 million charge primarily
related to the impairment of oil and gas properties held for sale and a
restructuring charge of $10 million for severance and other exit costs.
Excluding the $194 million charges in 2001, costs and expenses increased $91
million. The increase was primarily due to a $35 million increase in production
and processing expenses, a $26 million increase in depreciation, depletion and
amortization ("DD&A"), a $21 million increase in exploration costs, a $9 million
increase in transportation expense and an $8 million increase in taxes other
than income taxes. Production and processing expenses increased primarily due to
higher workover expense, higher service, electrical and lease fuel costs. DD&A
increased due to a higher unit-of-production rates related to changes in
production mix and higher finding costs. Exploration costs increased primarily
due to higher drilling rig expenses of $29 million and higher exploratory dry
hole costs of $28 million partially offset by lower geological and geophysical
("G&G") expenses of $23 million and lower lease impairment charges of $16
million. Transportation expense increased primarily due to higher tariffs and
taxes other than income taxes increased primarily due to higher oil and gas
revenues.

Interest Expense was $190 million in 2001 compared to $197 million in 2000.
The decrease was primarily due to higher capitalized interest during 2001.

Other Expense (Income) -- Net was income of $12 million in 2001 compared to
expense of $27 million in 2000. This increase was primarily due to higher
interest income in 2001 as a result of excess cash on hand during the year,
higher gains on sale of non-oil and gas assets and lower interest expense
related to tax matters.

Income tax expense was $349 million in 2001 compared to $292 million in
2000. The increase in tax expense was primarily due to lower tax benefits
related to Section 29 credits and tax-accrual adjustments partially offset by
lower tax on 2001 pretax income. The Section 29 tax credits were $24 million in
2001 compared to $52 million in 2000. Favorable tax-accrual adjustments were $21
million in 2001 compared to $56 million in 2000 primarily related to prior
period activity.
21

Year Ended December 31, 2000 Compared With Year Ended December 31, 1999

The Company reported net income of $675 million or $3.12 diluted earnings
per common share in 2000 compared to a net loss of $10 million or $.05 diluted
loss per common share in 1999. The 1999 results included a non-cash after tax
charge of $140 million or $.65 per share related to the impairment of oil and
gas properties. In the fourth quarter of 1999, the Company determined that there
would be performance related downward reserve adjustments associated with
certain properties located on the Gulf of Mexico Shelf and in the Permian Basin.
As a result, the Company recognized a pretax impairment charge of $225 million
($140 million after tax) related to those properties. The Company also
recognized a $26 million after tax charge or $.12 per share related to severance
and transaction costs associated with the acquisition of Poco Petroleums Ltd.
("Acquisition").

Revenues increased $834 million to $3,147 million in 2000 compared to
$2,313 million in 1999. Revenues in 2000 increased $950 million compared to 2000
as a result of higher commodity prices. Including a $.45 realized loss per MCF
related to hedging activities, average gas prices increased $.96 per MCF in 2000
to $3.37 per MCF from $2.41 per MCF in 1999, which increased revenues $611
million. Including a $2.62 realized loss per barrel related to hedging
activities, average oil prices increased $8.51 per barrel in 2000 to $25.44 per
barrel from $16.93 per barrel in 1999, which increased revenues $230 million.
Average NGL prices increased $6.35 per barrel in 2000 to $17.14 per barrel from
$10.79 per barrel in 1999, increasing revenues $109 million.

A decline in oil and gas sales volumes partially offset by an increase in
NGL sales volumes resulted in a decrease in revenues of $105 million in 2000
compared to 1999. Oil sales volumes decreased 10.5 MBbls per day in 2000 to 73.7
MBbls per day from 84.2 MBbls per day in 1999, reducing revenues $63 million.
Gas sales volumes decreased 59 MMCF in 2000 to 1,724 per MMCF per day from 1,783
per MMCF per day compared to the prior year, reducing revenues $48 million. The
decrease in revenues as a result of lower oil and gas sales volumes were
partially offset by an increase in NGL sales volumes of 1.4 MBbls per day in
2000 to 47.2 MBbls per day from 45.8 MBbls per day in 1999, resulting in
increased revenues of $6 million. Oil sales volumes decreased primarily due to
natural production declines in the Gulf Coast area.

Costs and Expenses were $1,956 million in 2000 compared to $2,113 million
in 1999. Costs and expenses in 1999 included a $225 million charge related to
the impairment of oil and gas properties and also a charge of $37 million
related to severance and transaction costs associated with the Acquisition.
Excluding the $262 million of charges in 1999, costs and expenses in 2000
increased $105 million compared to 1999. The increase was primarily due to a $73
million increase in DD&A, a $27 million increase in taxes other than income
taxes and an $11 million increase in exploration costs partially offset by an $8
million decrease in transportation expenses. DD&A increased primarily due to a
higher unit rate resulting from a change in production mix. Taxes other than
income taxes increased primarily due to higher oil and gas revenues. Exploration
costs increased primarily due to higher lease impairment expense of $19 million
and higher exploratory dry hole costs of $7 million, partially offset by lower
G&G expense of $15 million. Transportation expenses decreased due to lower
Canadian production.

Interest Expense was $197 million in 2000 compared to $211 million in 1999.
The decrease was primarily due to lower outstanding fixed-rate debt partially
offset by higher commercial paper borrowings during 2000.

Other Expense (Income) -- Net was an expense of $27 million in 2000
compared to expense of $2 million in 1999. This increase is primarily due to
foreign currency transaction losses and other miscellaneous expenses partially
offset by interest income related to the settlement of a windfall profits tax
matter.

Income taxes were an expense of $292 million in 2000 compared to a benefit
of $3 million in 1999. The increase in tax expense was primarily due to higher
pretax income resulting in higher income taxes of $342 million, higher state
taxes of $21 million and higher foreign taxes in excess of the U.S. statutory
rate of $35 million partially offset by tax benefits resulting from Section 29
tax credits and tax-accrual adjustments. The Section 29 tax credits were $52
million in 2000 compared to $2 million in 1999. Tax-accrual adjustments were
also $52 million in 2000 primarily related to prior period activity.

22

Acquisitions

On October 8, 2001, BR and Hunter entered into an agreement pursuant to
which BR agreed to make an offer to purchase all of the outstanding shares of
Hunter for cash consideration of C$53 per share representing an aggregate value
of approximately U.S. $2.1 billion resulting in an excess purchase price of
approximately $793 million which has been reflected as goodwill. On December 5,
2001, the transaction was consummated. This acquisition was funded with cash on
hand and proceeds from the issuances of $1.5 billion of fixed-rate notes and
$400 million of commercial paper. The transaction was accounted for under the
purchase method in accordance with SFAS No. 141. See Note 2 of Notes to
Consolidated Financial Statements for more information related to this
transaction.

During the first quarter of 2001, the Company purchased from DIFCO Limited
an additional 10 percent interest in 7 fields in the East Irish Sea for $25
million. The Company is the operator of the properties and now owns 100 percent
of the assets.

In January 2001, the Company's Canadian subsidiary, Burlington Resources
Canada Energy Ltd., now known as Burlington Resources Canada Ltd. ("BRCL"),
acquired approximately 37 billion cubic feet of gas equivalent ("BCFE") of
proved reserves from Petrobank Energy and Resources Ltd. for $57 million.

In December 2001, the Alberta Energy and Utility Board approved the
application by ATCO Gas Pipelines Ltd., a regulated gas utility, to sell
properties in the Viking-Kinsella area of Alberta, Canada to BRCL for
approximately $346 million. The properties have net proved reserves of
approximately 251 BCFE. The transaction was consummated on January 3, 2002.

Legal Proceedings

The Company and numerous other oil and gas companies have been named as
defendants in various lawsuits alleging violations of the civil False Claims
Act. These lawsuits have been consolidated by the United States Judicial Panel
on Multidistrict Litigation for pre-trial proceedings in the matter of In re
Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court
for the District of Wyoming ("MDL-1293"). The plaintiffs contend that defendants
underpaid royalties on natural gas and NGLs produced on federal and Indian lands
through the use of below-market prices, improper deductions, improper
measurement techniques and transactions with affiliated companies. Plaintiffs
allege that the royalties paid by defendants were lower than the royalties
required to be paid under federal regulations and that the forms filed by
defendants with the Minerals Management Service ("MMS") reporting these royalty
payments were false, thereby violating the civil False Claims Act. The United
States has intervened in certain of the MDL-1293 cases as to some of the
defendants, including the Company.

Various administrative proceedings are also pending before the MMS of the
United States Department of the Interior with respect to the valuation of
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.

Based on the Company's present understanding of the various governmental
and False Claims Act proceedings described above, the Company believes that it
has substantial defenses to these claims and intends to vigorously assert such
defenses. However, in the event that the Company is found to have violated the
civil False Claims Act, the Company could be subject to monetary damages and a
variety of sanctions, including double damages, substantial monetary fines,
civil penalties and a temporary suspension from entering into future federal
mineral leases and other federal contracts for a defined period of time. While
the ultimate outcome and impact on the Company cannot be predicted with
certainty, management believes that the resolution of these proceedings through
settlement or adverse judgment will not have a material adverse effect on the
consolidated financial position of the Company, although results of operations
and cash flow could be significantly impacted in the reporting periods in which
such matters are resolved.

The Company has also been named as a defendant in the lawsuit styled UNOCAL
Netherlands B.V., et al. v. Continental Netherlands Oil Company B.V., et al, No.
98-854, in the Court of Appeal in The Hague in the Netherlands. Plaintiffs, who
are working interest owners in the Q-1 Block in the North Sea, have alleged that
23

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. For all relevant periods, the Company owned a 37.5%
working interest in the Logger Field. Following a trial, the District Court in
The Hague rendered a Judgment in favor of the defendants, including the Company,
dismissing all claims. Plaintiffs thereafter appealed. On October 19, 2000, the
Court of Appeal in The Hague issued an interim Judgment in favor of the
plaintiffs and ordered that additional evidence be presented to the court
relating to issues of both liability and damages. The Company and the other
defendants are continuing to vigorously assert defenses against these claims.
The Company has also asserted claims of indemnity against two of the defendants
from whom it had acquired a portion of its working interest share. The Company
is unable at this time to reasonably predict the outcome, or, in the event of an
unfavorable outcome, to reasonably estimate the possible loss or range of loss,
if any, in this lawsuit.

In addition to the foregoing, the Company and its subsidiaries are named
defendants in numerous other lawsuits and named parties in numerous governmental
and other proceedings arising in the ordinary course of business. While the
outcome of these other lawsuits and proceedings cannot be predicted with
certainty, management believes these other matters will not have a material
adverse effect on the consolidated financial position, results of operations or
cash flows of the Company.

OTHER MATTERS

Recent Accounting Pronouncements

The following SFAS's were issued in June 2001: SFAS No. 141, Business
Combinations, SFAS No. 142, Goodwill and Other Intangible Assets, and SFAS No.
143, Accounting for Asset Retirement Obligations. In August 2001, SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets was also issued.
SFAS No. 141, requires the use of the purchase method of accounting for all
business combinations, applies to all business combinations initiated after June
30, 2001 and to all business combinations accounted for by the purchase method
that are completed after June 30, 2001. SFAS No. 142 requires that goodwill as
well as other intangible assets with indefinite lives not be amortized but be
tested annually for impairment and is effective for fiscal years beginning after
December 15, 2001. SFAS No. 141 and No. 142 apply to the Company's accounting
for the acquisition of Hunter. The Company is in the process of evaluating the
impairment methodology for goodwill.

SFAS No. 143 requires entities to record the fair value of a liability for
an asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
Subsequently, the asset retirement cost should be allocated to expense using a
systematic and rational method. SFAS No. 143 is effective for fiscal years
beginning after June 15, 2002. SFAS No. 144 addresses financial accounting and
reporting for the impairment of long-lived assets and long-lived assets to be
disposed of. It supersedes, with exceptions, SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of and
is effective for fiscal years beginning after December 15, 2001. The Company is
currently assessing the impact of SFAS No. 143 and No. 144 and therefore, at
this time cannot reasonably estimate the effect of these statements on its
consolidated financial position, results of operations or cash flows.

FORWARD-LOOKING STATEMENTS

The Company, in discussions of its future plans, expectations, objectives
and anticipated performance in periodic reports filed by the Company with the
Securities and Exchange Commission (or documents incorporated by reference
therein) may include projections or other forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933 or Section 21E of the
Securities Exchange Act of 1934, as amended. Such projections and
forward-looking statements are based on assumptions which the Company believes
are reasonable, but are by their nature inherently uncertain. In all cases,
there can be no assurance

24

that such assumptions will prove correct or that projected events will occur,
and actual results could differ materially from those projected. Some of the
important factors that could cause actual results to differ from any such
projections or other forward-looking statements follow.

Changes in crude oil, NGL and natural gas prices (including basis
differentials) from those assumed in preparing projections and forward-looking
statements could cause the Company's actual financial results to differ
materially from projected financial results and can also impact the Company's
determination of proved reserves and the standardized measure of discounted
future net cash flows relative to crude oil, NGL and natural gas reserves. In
addition, periods of sharply lower commodity prices could affect the Company's
production levels and/or cause it to curtail capital spending projects and delay
or defer exploration, exploitation or development projects.

Projections relating to the price received by the Company for natural gas
and NGLs also rely on assumptions regarding the availability and pricing of
transportation to the Company's key markets. In particular, the Company has
contractual arrangements for the transportation of natural gas from the San Juan
Basin eastward to Eastern and Midwestern markets or to market hubs in Texas,
Oklahoma and Louisiana. The natural gas price received by the Company could be
adversely affected by any constraints in pipeline capacity to serve these
markets.

Exploration and Production Risks. The Company's business is subject to all
of the risks and uncertainties normally associated with the exploration for and
development and production of crude oil, NGLs and natural gas.

Reserves which require the use of improved recovery techniques for
production are included in proved reserves if supported by a successful pilot
project or the operation of an installed program. The process of estimating
quantities of proved reserves is inherently uncertain and involves subjective
engineering and economic determinations. In this regard, changes in the economic
conditions (including commodity prices) or operating conditions (including,
without limitation, exploration, development and production costs and expenses
and drilling results from exploration and development activity) could cause the
Company's estimated proved reserves or production to differ from those included
in any such forward-looking statements or projections.

Projecting future crude oil, NGL and natural gas production is imprecise.
Producing oil and gas reservoirs eventually have declining production rates.
Projections of production rates rely on certain assumptions regarding historical
production patterns in the area or formation tests for a particular producing
horizon. Actual production rates could differ materially from such projections.
Production rates depend on a number of additional factors, including commodity
prices, market demand and the political, economic and regulatory climate.

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

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

The Company's drilling operations are subject to various hazards common to
the oil and gas industry, including explosions, fires, and blowouts, which could
result in damage to or destruction of oil and gas wells or formations,
production facilities and other property and injury to people. They are also
subject to the

25

additional hazards of marine operations, such as capsizing, collision and damage
or loss from severe weather conditions.

Development Risk. A significant portion of the Company's development plans
involve large projects in Algeria, the East Irish Sea, China, Wyoming, North
Dakota, the Gulf of Mexico and other areas. A variety of factors affect the
timing and outcome of such projects including, without limitation, approval by
the other parties owning working interests in the project, receipt of necessary
permits and approvals by applicable governmental agencies, the availability of
the necessary drilling equipment, delivery schedules for critical equipment and
arrangements for the gathering and transportation of the produced hydrocarbons.

Foreign Operations Risk. The Company's operations outside of the U.S. are
subject to risks inherent in foreign operations, including, without limitation,
the loss of revenue, property and equipment from hazards such as expropriation,
nationalization, war, insurrection and other political risks, increases in taxes
and governmental royalties, renegotiation of contracts with governmental
entities, changes in laws and policies governing operations of foreign-based
companies, currency restrictions and exchange rate fluctuations and other
uncertainties arising out of foreign government sovereignty over the Company's
international operations. Laws and policies of the U.S. affecting foreign trade
and taxation may also adversely affect the Company's international operations.

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

Competition. The Company actively competes for property acquisitions,
exploration leases and sales of crude oil, NGL's and natural gas, frequently
against companies with substantially larger financial and other resources. In
its marketing activities, the Company competes with numerous companies for gas
purchasing and processing contracts and for natural gas and NGLs at several
steps in the distribution chain. Competitive factors in the Company's business
include price, contract terms, quality of service, pipeline access,
transportation discounts and distribution efficiencies.

Political and Regulatory Risk. The Company's operations are affected by
foreign, national, state and local laws and regulations such as restrictions on
production, changes in taxes, royalties and other amounts payable to governments
or governmental agencies, price or gathering rate controls and environmental
protection regulations. Changes in such laws and regulations, or interpretations
thereof, could have a significant effect on the Company's operations or
financial results.

Potential Environmental Liabilities. The Company's operations are subject
to various foreign, national, state and local laws and regulations covering the
discharge of material into, and protection of, the environment. Such regulations
affect the costs of planning, designing, operating and abandoning facilities.
The Company expends considerable resources, both financial and managerial, to
comply with environmental regulations and permitting requirements. Although the
Company believes that its operations and facilities are in substantial
compliance with applicable environmental laws and regulations, risks of
substantial costs and liabilities are inherent in crude oil and natural gas
operations. Moreover, it is possible that other developments, such as
increasingly strict environmental laws, regulations and enforcement, and claims
for damage to property or persons resulting from the Company's current or
discontinued operations, could result in substantial costs and liabilities in
the future.

26

ITEM EIGHT

FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL INFORMATION

BURLINGTON RESOURCES INC.

CONSOLIDATED STATEMENT OF INCOME (LOSS)

See accompanying Notes to Consolidated Financial Statements.

27

BURLINGTON RESOURCES INC.

CONSOLIDATED BALANCE SHEET

See accompanying Notes to Consolidated Financial Statements.

28

BURLINGTON RESOURCES INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

See accompanying Notes to Consolidated Financial Statements.

29

BURLINGTON RESOURCES INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

See accompanying Notes to Consolidated Financial Statements.

30

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ACCOUNTING POLICIES

Principles of Consolidation and Reporting

The consolidated financial statements include the accounts of Burlington
Resources Inc. ("BR") and its majority-owned subsidiaries (the "Company"). All
significant intercompany transactions have been eliminated in consolidation.
Investments in entities in which the Company has a significant ownership
interest, generally 20 to 50 percent, or otherwise does not exercise control,
are accounted for using the equity method. Under the equity method, the
investments are stated at cost plus the Company's equity in undistributed
earnings and losses. The consolidated financial statements for previous periods
include certain reclassifications that were made to conform to current
presentation. Such reclassifications have no impact on previously reported net
income or stockholders' equity.

Cash and Cash Equivalents

All short-term investments purchased with a maturity of three months or
less are considered cash equivalents. Cash equivalents are stated at cost, which
approximates market value.

Inventories

Inventories of materials, supplies and products are valued at the lower of
average cost or market.

Properties

Oil and gas properties are accounted for using the successful efforts
method. Under this method, all development costs and acquisition costs of proved
properties are capitalized and amortized on a units-of-production basis over the
remaining life of proved developed reserves and proved reserves, respectively.
Costs of drilling exploratory wells are initially capitalized, but charged to
expense if and when a well is determined to be unsuccessful. Costs of unproved
properties are capitalized and amortized on a composite basis, based on past
success experience and average property lives. The Company evaluates the
impairment of its oil and gas properties on a field-by-field basis whenever
events or changes in circumstances indicate an asset's carrying amount may not
be recoverable. Unamortized capital costs are reduced to fair value if the sum
of the expected undiscounted future cash flows is less than the asset's net book
value. Cash flows are determined based upon proved reserves using prices and
costs consistent with those used for internal decision making.

Costs of retired, sold or abandoned properties that constitute a part of an
amortization base are charged or credited, net of proceeds, to accumulated
depreciation, depletion and amortization. Gains or losses from the disposal of
other properties are recognized currently. Expenditures for maintenance, repairs
and minor renewals necessary to maintain properties in operating condition are
expensed as incurred. Major replacements and renewals are capitalized. Estimated
dismantlement and abandonment costs for oil and gas properties are capitalized
at their estimated net present value and amortized net of salvage value. The
Company's abandonment liability, included in Other Liabilities and Deferred
Credits in the Consolidated Balance Sheet, was $201 million and $147 million at
December 31, 2001 and 2000, respectively.

Other properties include gas plants, pipelines, buildings, data processing
and telecommunications equipment, office furniture and equipment and other fixed
assets. These items are recorded at cost and are depreciated on the
straight-line method based on expected lives of the individual assets or group
of assets.

Revenue Recognition

Gas revenues are recorded on the entitlement method. Under the entitlement
method, revenue is recorded when title passes based on the Company's net
interest. Gas imbalances occur when the Company sells more or less than its
entitled ownership percentage of total gas production. Any amount received in
excess

31

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of the Company's share is treated as a liability. If the Company receives less
than it is entitled, the underproduction is recorded as a receivable. At
December 31, 2001 and 2000, the Company had gas imbalance receivables of $39
million and $19 million, respectively.

Functional Currency

The assets, liabilities and operations of BR's Canadian subsidiaries are
measured using the Canadian dollar as the functional currency. These assets and
liabilities are translated into United States ("U.S.") dollars at end-of-period
exchanges rates and are recorded in other comprehensive income. Revenue and
expenses are translated into U.S. dollars at the average exchange rates in
effect during the period. The assets, liabilities and results of operations of
foreign entities other than BR's Canadian subsidiaries are measured using the
U.S. dollar as the functional currency. For subsidiaries where the U.S. dollar
is the functional currency, all foreign currency denominated assets and
liabilities are remeasured into U.S. dollars at end-of-period exchange rates.
Inventories, prepaid expenses and properties are exceptions to this policy and
are remeasured at historical rates. Foreign currency revenues and expenses are
remeasured at average exchange rates in effect during the year. Exceptions to
this policy include all expenses related to balance sheet amounts that are
remeasured at historical exchange rates. Exchange gains and losses arising from
remeasured foreign currency denominated monetary assets and liabilities are
included in Other Expense (Income) -- Net in the Consolidated Statement of
Income (Loss). Included in net income for the years ended December 31, 2001,
2000 and 1999 are losses of $7 million, $4 million and a gain of $9 million,
respectively.

Derivative Instruments and Hedging Activities

The Company enters into derivative contracts, primarily options and swaps,
to hedge future crude oil and natural gas production in order to mitigate the
risk of market price fluctuations. The Company also enters into derivative
contracts to mitigate the risk of foreign currency exchange rate fluctuations.
On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging
Activities, as amended. Effective with the adoption of SFAS No. 133, all
derivatives are recognized on the balance sheet and measured at fair value. If
the derivative does not qualify as a hedge or is not designated as a hedge, the
gain or loss on the derivative is recognized currently in earnings. If the
derivative qualifies for hedge accounting, the gain or loss on the derivative is
either recognized in income along with an offsetting adjustment to the basis of
the item being hedged for fair value hedges or deferred in other comprehensive
income to the extent the hedge is effective for cash flow hedges. To qualify for
hedge accounting, the derivative must qualify as either a fair-value, cash-flow
or foreign-currency hedge.

The hedging relationship between the hedging instruments and hedged items
must be highly effective in achieving the offset of changes in fair values or
cash flows attributable to the hedged risk both at the inception of the hedge
and on an ongoing basis. The Company measures hedge effectiveness on a quarterly
basis. Hedge accounting is discontinued prospectively when a hedging instrument
becomes ineffective. The Company assesses hedge effectiveness based on total
changes in the fair value of options used in cash flow hedges rather than
changes of intrinsic value only. As a result, changes in the entire fair value
of option contracts are deferred in accumulated other comprehensive income until
the hedged transaction affects earnings to the extent such contracts are
effective. Gains and losses deferred in accumulated other comprehensive income
related to cash flow hedge derivatives that become ineffective remain unchanged
until the related production is delivered. Adjustment to the carrying amounts of
hedged production is discontinued in instances where the related fair-value
hedging instrument becomes ineffective. The balance in the fair-value hedge
adjustment account is recorded in income when the related production is
delivered. If the Company determines that it is probable that a hedged
forecasted transaction will not occur, deferred gains or losses on the hedging
instrument are recognized in earnings immediately.

32

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Gains and losses on hedging instruments and adjustments of the carrying
amounts of hedged production are included in crude oil and natural gas revenues
and are included in realized prices in the period that the related production is
delivered. Gains and losses on hedging instruments which represent hedge
ineffectiveness and gains and losses on derivative instruments which do not
qualify for hedge accounting are included in other revenues in the period in
which they occur. The resulting cash flows are reported as cash flows from
operating activities.

Credit and Market Risks

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

Income Taxes

Income taxes are provided based on earnings reported for tax return
purposes in addition to a provision for deferred income taxes. Deferred income
taxes are provided to reflect the tax consequences in future years of
differences between the financial statement and tax basis of assets and
liabilities. Tax credits are accounted for under the flow-through method, which
reduces the provision for income taxes in the year the tax credits are earned. A
valuation allowance is established to reduce deferred tax assets if it is more
likely than not that the related tax benefits will not be realized.

Stock-based Compensation

The Company uses the intrinsic value based method of accounting for
stock-based compensation, as prescribed by Accounting Principles Board Opinion
No. 25 and related interpretations. Under this method, the Company records no
compensation expense for stock options granted when the exercise price for
options granted is equal to the fair market value of the Company's stock on the
date of the grant.

Environmental Costs

Environmental expenditures are expensed or capitalized, as appropriate,
depending on their future economic benefit. Expenditures that relate to an
existing condition caused by past operations, and that do not have future
economic benefit, are expensed. Liabilities related to future costs are recorded
on an undiscounted basis when environmental assessments and/or remediation
activities are probable and the costs can be reasonably estimated.

Reclassifications

The Company's 2001 taxes other than income taxes include severance, ad
valorem, payroll and miscellaneous taxes. To conform to current presentation,
the Company reclassified $11 million of payroll and miscellaneous taxes from
production and processing expenses and administrative expenses to taxes other
than income taxes for each of the years ended December 31, 2000 and 1999. The
Company also reclassified $15 million and $12 million of certain other
non-corporate expenses from administrative expenses to production and processing
expenses for years ended December 31, 2000 and 1999, respectively. These
reclassifications had no effect on operating income.

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BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Earnings Per Common Share

Basic earnings per common share ("EPS") is computed by dividing income
available to common stockholders by the weighted-average number of common shares
outstanding for the period. The weighted average number of common shares
outstanding for computing basic EPS was 207 million, 216 million and 216 million
for the years ended December 31, 2001, 2000 and 1999, respectively. Diluted EPS
reflects the potential dilution that could occur if securities or other
contracts to issue common stock were exercised or converted into common stock.
The weighted average number of common shares outstanding for computing diluted
EPS, including dilutive stock options, was 208 million, 216 million and 217
million for the years ended December 31, 2001, 2000 and 1999, respectively. For
the years ended December 31, 2001, 2000 and 1999, approximately 4 million shares
attributable to the exercise of outstanding options were excluded from the
calculation of diluted EPS because the effect was antidilutive. No adjustments
were made to reported net income in the computation of EPS.

Use of Estimates

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. The most significant estimates pertain to proved oil, NGL and
gas reserve volumes and the future development, dismantlement and abandonment
costs as well as estimates relating to certain gas, NGL and oil revenues and
expenses. Actual results could differ from those estimates.

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BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

2. BUSINESS COMBINATIONS AND OTHER PROPERTY ACQUISITIONS

Acquisition of Canadian Hunter Exploration Ltd. ("Hunter")

On December 5, 2001, BR acquired all of the outstanding shares of Hunter
for cash consideration of C$53 per share representing an aggregate value of
approximately U.S. $2.1 billion resulting in an excess purchase price of
approximately $793 million which has been reflected as goodwill. Through the
acquisition, BR gains Hunter's significant interest in Canada's Deep Basin,
North America's third-largest natural gas field, increasing its critical mass
and enhancing its position as a leading North American natural gas producer. BR
also obtains the exploration expertise of Hunter's workforce, gains additional
cost optimization by eliminating duplicate efforts and increasing purchasing
power and gains greater marketing flexibility in optimizing sales and accessing
key market information. This acquisition was funded with cash on hand and
proceeds from the issuances of $1.5 billion of fixed-rate notes and $400 million
of commercial paper. The transaction was accounted for under the purchase method
in accordance with SFAS No. 141. The results of operations of Hunter were
included in the Company's financial statements effective December 5, 2001. The
Company is in the process of evaluating the impairment methodology for goodwill.
The purchase price was calculated as follows.

The following is the allocation of the purchase price to specific assets
and liabilities based on estimates of fair values and costs. All of the goodwill
was assigned to the Company's Canadian reporting unit.

The purchase price allocation is preliminary in nature and is subject to
changes as additional information becomes available. Management does not expect
the final purchase price allocation to differ materially. Other purchase price
costs relate primarily to professional fees of approximately $16 million and
other direct transaction costs of approximately $1 million.

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BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table presents the unaudited pro forma results of the Company
as though the acquisition had occurred on January 1, 2000. Pro forma results are
not necessarily indicative of actual results.

Other Acquisitions

During the first quarter of 2001, the Company purchased from DIFCO Limited
an additional 10 percent interest in 7 fields in the East Irish Sea for $25
million. The Company is the operator of the properties and now owns 100 percent
of the assets.

In January 2001, the Company's Canadian subsidiary, Burlington Resources
Canada Energy Ltd., now known as Burlington Resources Canada Ltd. ("BRCL"),
acquired approximately 37 billion cubic feet of gas equivalent ("BCFE") of
proved reserves from Petrobank Energy and Resources Ltd. for $57 million.

On August 16, 1999, the Company entered into a definitive agreement to
acquire Poco Petroleums Ltd. ("Poco") (the "Acquisition"). The Acquisition was
consummated on November 18, 1999 and accounted for under the pooling of
interests method. Under the terms of the Acquisition, Poco shareholders received
.25 BR common equivalent shares ("exchangeable shares"), totaling 38,393,135
shares, for each Poco share held. The exchangeable shares were Canadian
securities, which began trading on the Toronto Stock Exchange on November 23,
1999 under the symbol BRX. These shares had the same voting rights, dividend
entitlements and other attributes as shares of BR Common Stock and were
exchangeable, at each shareholder's option, for BR Common Stock on a one for one
basis. See Note 8 of Notes to Consolidated Financial Statements for disposition
of remaining exchangeable shares.

During the fourth quarter of 1999, the Company recorded a pretax charge of
$37 million ($26 million after tax) for direct costs associated with the
Acquisition. These costs consist of $10 million for severance related to certain
executives and $27 million for direct transaction costs. At December 31, 2000,
all costs had been paid.

3. OIL AND GAS AND OTHER PROPERTIES

Oil and gas properties consisted of the following.

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BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Other properties consisted of the following.

4. INCOME TAXES

The jurisdictional components of income (loss) before income taxes follow.

The provision for income taxes follows.

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

37

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Deferred income tax liabilities (assets) follow.

The net deferred income tax liabilities, as of December 31, 2001 and 2000,
include deferred state income tax liabilities of approximately $49 million and
$35 million, respectively. The net deferred income tax liabilities also include
foreign tax liabilities of approximately $1,102 million and $124 million as of
December 31, 2001 and 2000, respectively. No deferred U.S. income tax liability
has been recognized on the undistributed earnings of controlled foreign
corporations that have been retained for reinvestment. A valuation allowance is
provided for uncertainties surrounding the realization of various tax credit
carryforwards.

The Alternative Minimum Tax ("AMT") credit carryforward, related primarily
to nonconventional fuel tax credits, is available to offset future federal
income tax liabilities. The AMT credit carryforward has no expiration date. The
benefit of these tax credits is recognized in net income for accounting purposes
and is reflected in the current tax provision to the extent the Company is able
to utilize the credits for tax return purposes. The net operating loss
carryforward primarily relates to foreign jurisdictions and will expire between
2003 and 2006 if not used.

5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The Company enters into fixed-price gas swap agreements to fix the prices
of anticipated future natural gas production and enters into variable-price gas
swap agreements that convert fixed price physical sales contracts back to market
sensitive prices. The Company enters into natural gas basis swap agreements to
fix the sales price differential between the Company's marketing locations and
NYMEX Henry Hub. The Company enters into natural gas option agreements to
establish floor and ceiling prices on anticipated future natural gas production.
The Company also enters into natural gas option agreements to establish floor
and ceiling prices on anticipated future natural gas production while allowing
the Company to participate in upward price movements above a specified
non-participation range. Generally, the Company does not receive net premiums on
its option hedging strategies.

The Company enters into crude oil swap agreements to fix the price of
anticipated future crude oil production and purchases call options agreements
that allow the Company to participate in market price increases that exceed
hedge prices established when the Company enters into a swap. The Company also
enters into crude oil option agreements to establish floor and ceiling prices on
anticipated future crude oil production while allowing the Company to
participate in upward price movements above a specified non-participation range.
Generally, the Company does not receive net premiums on its option hedging
strategies.

38

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As of December 31, 2001, the Company had the following natural gas volumes
hedged.

Natural Gas Fixed-Price Swaps

Natural Gas Basis Swaps

Natural Gas Options

As of December 31, 2001, the fair value of the swap agreements the Company
had entered into in order to convert the Company's fixed-price gas sales
contracts to market sensitive positions was a $1 million liability offset by a
$1 million asset basis adjustment to the carrying value of the fixed-price gas
sales contracts.

As of December 31, 2001, the Company had the following crude oil volumes
hedged. The total notional amount of the crude oil call options is matched with
a corresponding notional amount of fixed-price swaps.

Crude Oil Swaps

39

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Crude Oil Options

The derivative assets and liabilities represent the difference between
hedged values and market values on hedged volumes of the commodities as of
December 31, 2001. Hedging activities reduced natural gas and crude oil revenues
by $297 million and $25 million, respectively, during 2001. In addition, during
2001, gains of $19 million were recorded in revenues associated with
ineffectiveness of cash-flow and fair-value hedges and gains on derivative
instruments which do not qualify for hedge accounting.

In addition to hedges of commodity prices, the Company also has foreign
currency swaps to hedge its exposure to exchange rate fluctuations related to
its Canadian subsidiaries. As of December 31, 2001, the Company had $8 million
of liabilities related to foreign currency exchange rate hedges.

In accordance with the transition provisions of SFAS No. 133, on January 1,
2001, the Company recorded a net-of-tax cumulative-effect-type loss adjustment
of $366 million in accumulated other comprehensive income to recognize at fair
value all derivatives that are designated as cash-flow hedging instruments. The
Company recorded cash-flow hedge derivatives liabilities of $582 million ($361
million after tax), fair value hedge derivative assets of $16 million ($10
million after tax), related liability adjustments to book value of fair-value
hedged items of $16 million ($10 million after tax) and a $3 million after tax
non-cash gain was recorded in current earnings as a cumulative effect of
accounting change.

Changes in other comprehensive income for the year ended December 31,
2001 follow.

Based on commodity prices and foreign exchange rates as of December 31,
2001, the Company expects to reclassify gains of $86 million ($54 million after
tax) to earnings from the balance in accumulated other comprehensive income
during the next twelve months. As of December 31, 2001, the Company had
cash-flow hedge derivative assets of $109 million and liabilities of $10
million. The Company had liabilities and assets related to fair-value hedges of
$4 million and $4 million, respectively. The Company also had assets totaling
$10 million related to commodity derivative instruments that do not qualify for
hedge accounting.

40

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

6. LONG-TERM DEBT

Long-term debt follows.

Excluding commercial paper, the Company has debt maturities of $100 million
due in 2002, $63 million due in 2003, $0 million due in 2004 and 2005, and
$3,544 million due in 2006 and thereafter. The Company's commercial paper
borrowings at December 31, 2001 and 2000 had weighted average interest rates of
approximately 3 percent and 6 percent, respectively. The fair value of debt
outstanding as of December 31, 2001 and 2000 approximates the carrying amount.

Burlington Resources Capital Trust I, Burlington Resources Capital Trust II
(collectively, the "Trusts"), BR and Burlington Resources Finance Company
("BRFC") have a shelf registration on file with the Securities and Exchange
Commission ("SEC"). 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.

In February 2001, BRFC issued $400 million of 6.68% Notes due February 15,
2011. In August 2001, BRFC acquired notes with an aggregate principal amount of
$710 million and a weighted average interest rate

41

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of 7.28% and issued $178 million of 6.4% Notes and $575 million of 7.2% Notes
due August 15, 2011 and 2031, respectively. The transaction was accounted for as
an exchange of debt instruments and reduced the Company's amount available under
its shelf registration statement on file with the SEC from $1,500 million to
$747 million.

The Company had credit commitments in the form of revolving credit
facilities ("revolvers") as of December 31, 2001. These revolvers are available
to cover debt due within one year, therefore, commercial paper, credit facility
notes and fixed-rate debt due within one year are classified as long-term debt.
Currently, there are no amounts outstanding under the revolvers, however, the
Company's outstanding commercial paper reduces the amount of credit available
under the revolvers. The revolvers are comprised of agreements for $600 million,
$400 million and $300 million. The $600 million revolver expires in December
2006 and the $400 million and $300 million revolvers expire in December 2002
unless renewed by mutual consent. At expiration of the agreements, the Company
has the option to convert the outstanding balances on the $400 million and $300
million revolvers to one year and five-year plus one day term notes,
respectively.

At the Company's option, interest on borrowings under the $600 million and
$400 million revolvers is based on the prime rate or Eurodollar rates. The other
revolver bears interest at rates based on prime or Eurodollar rates also at the
Company's option, however, the lenders have the option to provide bankers'
acceptances in lieu of Eurodollar rate loans. Under the covenants of the
revolvers, Company debt cannot exceed 60 percent of capitalization (as defined
in the agreements).

Outstanding borrowings of $127 million and $114 million as of December 31,
2001 and 2000, respectively, on Company-owned life insurance policies were
reported as a reduction to the cash surrender value and are included as a
component of Other Assets in the Company's consolidated balance sheet.

7. TRANSPORTATION ARRANGEMENTS WITH EL PASO NATURAL GAS COMPANY

In 2001, 2000 and 1999, approximately 29 percent, 32 percent and 30
percent, respectively, of the Company's gas production was transported to direct
sale customers through El Paso Natural Gas Company's ("EPNG") pipeline systems.
These transportation arrangements are pursuant to EPNG's approved Federal Energy
Regulatory Commission tariffs applicable to all shippers. The Company expects to
continue to transport a substantial portion of its future gas production through
EPNG's pipeline system. See Note 10 of Notes to Consolidated Financial
Statements for demand charges paid to EPNG which provide the Company with firm
and interruptible transportation capacity rights on interstate and intrastate
pipeline systems.

42

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

8. CAPITAL STOCK

Common Stock Activity

In December 2000, the Company's Board of Directors authorized the
repurchase of up to $1 billion of the Company's Common Stock. During 2001, the
Company repurchased 16.1 million shares of its Common Stock for approximately
$684 million. Through December 31, 2001, the Company has repurchased
approximately 16.3 million shares or $693 million of its Common Stock under this
$1 billion authorization.

Stock Compensation Plans

The Company's 1993 Stock Incentive Plan (the "1993 Plan") succeeds its 1988
Stock Option Plan which expired by its terms in May 1993 but remains in effect
for options granted prior to May 1993. The 1993 Plan provides for the grant of
stock options, restricted stock, stock purchase rights and stock appreciation
rights or limited stock appreciation rights.

Under the 1993 Plan, options may be granted to officers and key employees
at fair market value on the date of grant, are exercisable in whole or part by
the optionee after completion of at least one year of continuous employment from
the grant date and have a term of ten years. At December 31, 2001, 4,169,973
shares were available for grant under the 1993 Plan.

In 1997, the Company adopted the 1997 Employee Stock Incentive Plan (the
"1997 Plan") from which stock options and restricted stock ("Awards") may be
granted to employees who are not eligible to participate in the 1993 Plan. The
options are granted at fair market value on the grant date, become exercisable
in whole or part by the optionee after completion of at least one year of
continuous employment and have a term of ten years. The 1997 Plan limits Awards,
in aggregate, to a maximum of 1.5 million shares annually, of which up to
150,000 shares annually may be restricted stock.

The Company issued 256,700, 211,350 and 110,250 shares of restricted stock
in 2001, 2000 and 1999, respectively, from the 1993 and 1997 Plans. The
restrictions on this stock generally lapse on the third anniversary of the date
of grant. The weighted average grant-date fair value of restricted stock granted
in the years ended December 31, 2001, 2000, and 1999 was approximately $50.30,
$34.62 and $36.47, respectively.

43

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Related compensation expense of $7 million, $4 million and $2 million was
recognized for the years ended December 31, 2001, 2000 and 1999, respectively.

The Company's 2000 Stock Option Plan for Non-Employee Directors provides
for the annual grant of a nonqualified option for 2,000 shares of Common Stock
immediately following the Annual Meeting of Stockholders to Directors who are
not salaried officers of the Company. In addition, an option for 5,000 shares is
granted upon a Director's initial election or appointment to the Board of
Directors. The exercise price per share with respect to each option is the fair
market value, as defined in the plan, of the Common Stock on the date the option
is granted. The total number of shares of the Company's Common Stock for which
options may be granted under the plan is 250,000.

The Company's stock option activity follows.

The following table summarizes information related to stock options
outstanding and exercisable at December 31, 2001.

Exercisable stock options and weighted average exercise prices at December
31, 2000 and 1999 follow.

44

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The weighted average fair values of options granted during the years 2001,
2000 and 1999 were $11.33, $10.33 and $11.13, respectively. The fair values of
employee stock options were calculated using a variation of the Black-Scholes
stock option valuation model with the following weighted average assumptions for
grants in 2001, 2000 and 1999: stock price volatility of 35 percent, 35 percent
and 27 percent, respectively; risk free rate of return ranging from 4 percent to
5 percent; dividend yield of 1.32 percent, 1.46 percent and .88 percent,
respectively; and an expected term of 3 years. If the fair value based method of
accounting, as prescribed by SFAS No. 123, Accounting for Stock-Based
Compensation, had been applied, the Company's pro forma net income (loss) and
pro forma EPS are shown below. The fair value of stock options included in the
pro forma amounts is not necessarily indicative of future effects on net income
(loss) and EPS.

Preferred Stock and Preferred Stock Purchase Rights

The Company is authorized to issue 75,000,000 shares of preferred stock,
par value $.01 per share. As of December 31, 2001, one share of preferred stock
was issued and designated as Special Voting Stock in connection with the Poco
acquisition. On December 9, 1998, the Company's Board of Directors designated
3,250,000 of the authorized preferred shares as Series A Junior Participating
Preferred Stock. Upon issuance, each one-hundredth of a share of Series A Junior
Participating Preferred Stock will have dividend and voting rights approximately
equal to those of one share of Common Stock of the Company. In addition, on
December 9, 1998, the Board of Directors declared a dividend distribution of one
Right for each outstanding share of Common Stock of the Company to shareholders
of record on December 16, 1998. The Rights become exercisable if, without the
Company's prior consent, a person or group acquires securities having 15 percent
or more of the voting power of all of the Company's voting securities (an
"Acquiring Person") or ten days following the announcement of a tender offer
which would result in such ownership. Each Right, when exercisable, entitles the
registered holder to purchase from the Company one-hundredth of a share of
Series A Junior Participating Preferred Stock at a price of $200 per one
hundredth of a share, subject to adjustment. If, after the Rights become
exercisable, the Company were to be involved in a merger or other business
combination in which its Common Stock was exchanged or changed or 50 percent or
more of the Company's assets or earning power were sold, each Right would permit
the holder to purchase, for the exercise price, stock of the acquiring company
having a value of twice the exercise price. In addition, except for certain
permitted offers, if any person or group becomes an Acquiring Person, each Right
would permit the purchase, for the exercise price, of Common Stock of the
Company having a value of twice the exercise price. Rights owned by an Acquiring
Person are void. The Rights may be redeemed by the Company under certain
circumstances until their expiration date for $.01 per Right.

On November 8, 1999 (effective November 18, 1999), the Company's Board of
Directors designated one of the authorized preferred shares as Special Voting
Stock. The Special Voting Stock is entitled to a number of votes equal to the
number of outstanding Exchangeable Shares of Burlington Resources Canada Inc.
(other than Exchangeable Shares held by the Company), on all matters presented
to the stockholders of the Company. Upon the liquidation, dissolution or winding
up of the Company, the holder of the Special Voting Stock shall be entitled,
prior and in preference to any distribution to the holders of Common Stock and
after

45

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the distribution to the holders of any class or series of Preferred Stock
ranking senior to the Special Voting Stock of all amounts to which such holders
are entitled, to receive the sum of $.01. Except as aforesaid, no dividends or
distributions shall be payable to the holder of the Special Voting Stock. The
Special Voting Stock is not convertible into any other class or series of the
capital stock or to cash, property or other rights, and may not be redeemed. If
the Special Voting Stock shall be purchased or otherwise acquired by the
Company, it shall be deemed retired and shall be cancelled and may not
thereafter be reissued or otherwise disposed of by the Company. As long as any
Exchangeable Shares of Burlington Resources Canada Inc. are outstanding, the
number of shares comprising the Special Voting Stock shall not be increased or
decreased and no other term of the Special Voting Stock shall be amended, except
upon the unanimous approval of all shares of Common Stock. On November 18, 1999,
the one share of Special Voting Stock was issued to CIBC Mellon Trust Company,
as trustee pursuant to the Voting and Exchange Trust Agreement among the
Company, Burlington Resources Canada Inc. and CIBC Mellon Trust Company, for the
benefit of the holders of the Exchangeable Shares of Burlington Resources Canada
Inc. On September 14, 2001, all of the remaining outstanding exchangeable shares
issued by the Company's subsidiary, Burlington Resources Canada Inc., in
connection with the November 1999 acquisition of Poco Petroleums Ltd., were
exchanged for BR Common Stock. The exchangeable shares had been trading on the
Toronto Stock Exchange in Canada under the symbol "BRX". On September 17, 2001,
as part of a reorganization of the Company's Canadian subsidiaries, Burlington
Resources Canada Inc., Burlington Resources Canada Energy Ltd. (formerly Poco
Petroleums Ltd.) and another wholly-owned Canadian subsidiary of the Company
were amalgamated and are now known as Burlington Resources Canada Ltd.

9. RETIREMENT BENEFITS

The Company's U.S. pension plans are non-contributory defined benefit plans
covering all U.S. employees. The benefits are based on years of credited service
and final average compensation. Contributions to the tax qualified plans are
limited to amounts that are currently deductible for tax purposes. Contributions
are intended to provide not only for benefits attributed to service-to-date but
also for those expected to be earned in the future. Hunter also provides a
pension plan and postretirement benefits to a closed group of employees and
retirees.

The Company provides postretirement medical, dental and life insurance
benefits for a closed group of retirees and their dependents. The Company also
provides limited retiree life insurance benefits to employees who retire under
the pension plan. The postretirement benefit plans are unfunded, therefore, the
Company funds claims on a cash basis.

The Company has a discretionary defined contribution plan ("401K" plan).
Under the 401K plan, an employee may elect to contribute from 1 to 13 percent of
his/her eligible compensation subject to an Internal Revenue Service limit of
$10,500 per year. The Company matches, with cash, from 6 to 8 percent of the
employee's eligible contributions. The Company contributed $8 million to the
401K plan for each of the years ended December 31, 2001, 2000 and 1999 to match
eligible contributions by employees.

46

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following tables set forth the amounts recognized in the Consolidated
Balance Sheet and Statement of Income.

47

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

A 10 percent annual rate of increase in the per capita cost of pre-age 65
covered health care benefits was assumed for 2002. The rate is assumed to
decrease gradually to 5 percent for 2007 and remain at that level thereafter. A
12 percent annual rate of increase in the per capita cost of post-age 65 covered
health care benefits was assumed to decrease gradually to 5 percent for 2009 and
remain at that level thereafter. Assumed health care cost trends have a
significant effect on the amounts reported for the postretirement medical and
dental care plans. A one-percentage point change in assumed health care cost
trend rates would have the following effects.

10. COMMITMENTS AND CONTINGENT LIABILITIES

Demand Charges

The Company has entered into contracts which provide firm transportation
capacity rights on interstate and intrastate pipeline systems. The remaining
terms on these contracts range from 1 to 23 years and require the Company to pay
transportation demand charges regardless of the amount of pipeline capacity
utilized by the Company. The Company paid $128 million, $123 million and $122
million of demand charges of which $24 million, $27 million and $36 million were
paid to EPNG for the years ended December 31, 2001, 2000 and 1999, respectively.
All transportation costs including demand charges are included in transportation
expense in the income statement.

Future transportation demand charge commitments at December 31, 2001
follow.

Lease Obligations

The Company has operating leases for office space and other property and
equipment. The Company incurred lease rental expense of $23 million, $24 million
and $24 million for the years ended December 31, 2001, 2000 and 1999,
respectively.

48

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Future minimum annual rental commitments at December 31, 2001 follow.

Drilling Rig Commitments

During 1998, the Company entered into agreements to lease two deep water
drilling rigs through 2004 with remaining commitments of $188 million. This
commitment will be utilized by drilling exploration wells, partner participation
or subletting to extent possible.

Legal Proceedings

The Company and numerous other oil and gas companies have been named as
defendants in various lawsuits alleging violations of the civil False Claims
Act. These lawsuits have been consolidated by the United States Judicial Panel
on Multidistrict Litigation for pre-trial proceedings in the matter of In re
Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court
for the District of Wyoming ("MDL-1293"). The plaintiffs contend that defendants
underpaid royalties on natural gas and NGLs produced on federal and Indian lands
through the use of below-market prices, improper deductions, improper
measurement techniques and transactions with affiliated companies. Plaintiffs
allege that the royalties paid by defendants were lower than the royalties
required to be paid under federal regulations and that the forms filed by
defendants with the Minerals Management Service ("MMS") reporting these royalty
payments were false, thereby violating the civil False Claims Act. The United
States has intervened in certain of the MDL-1293 cases as to some of the
defendants, including the Company.

Various administrative proceedings are also pending before the MMS of the
United States Department of the Interior with respect to the valuation of
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.

Based on the Company's present understanding of the various governmental
and False Claims Act proceedings described above, the Company believes that it
has substantial defenses to these claims and intends to vigorously assert such
defenses. However, in the event that the Company is found to have violated the
civil False Claims Act, the Company could be subject to monetary damages and a
variety of sanctions, including double damages, substantial monetary fines,
civil penalties and a temporary suspension from entering into future federal
mineral leases and other federal contracts for a defined period of time. While
the ultimate outcome and impact on the Company cannot be predicted with
certainty, management believes that the resolution of these proceedings through
settlement or adverse judgment will not have a material adverse effect on the
consolidated financial position of the Company, although results of operations
and cash flow could be significantly impacted in the reporting periods in which
such matters are resolved.

The Company has also been named as a defendant in the lawsuit styled UNOCAL
Netherlands B.V., et al. v. Continental Netherlands Oil Company B.V., et al, No.
98-854, in the Court of Appeal in The Hague in the Netherlands. Plaintiffs, who
are working interest owners in the 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

49

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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. For all
relevant periods, the Company owned a 37.5% working interest in the Logger
Field. Following a trial, the District Court in The Hague rendered a Judgment in
favor of the defendants, including the Company, dismissing all claims.
Plaintiffs thereafter appealed. On October 19, 2000, the Court of Appeal in The
Hague issued an interim Judgment in favor of the plaintiffs and ordered that
additional evidence be presented to the court relating to issues of both
liability and damages. The Company and the other defendants are continuing to
vigorously assert defenses against these claims. The Company has also asserted
claims of indemnity against two of the defendants from whom it had acquired a
portion of its working interest share. The Company is unable at this time to
reasonably predict the outcome, or, in the event of an unfavorable outcome, to
reasonably estimate the possible loss or range of loss, if any, in this lawsuit.

In addition to the foregoing, the Company and its subsidiaries are named
defendants in numerous other lawsuits and named parties in numerous governmental
and other proceedings arising in the ordinary course of business. While the
outcome of these other lawsuits and proceedings cannot be predicted with
certainty, management believes these other matters will not have a material
adverse effect on the consolidated financial position, results of operations or
cash flows of the Company.

11. SUPPLEMENTAL CASH FLOW INFORMATION

The following is additional information concerning supplemental disclosures
of cash payments.

The Company purchased all of the outstanding shares of Hunter for $2,087
million, net of cash acquired. In conjunction with the acquisition, liabilities
were assumed as follows.

Fair value of assets acquired............................... $3,297
Cash paid for the capital stock, net of cash acquired....... 2,087
------
Liabilities assumed....................................... $1,210
======

At December 31, 2001, 2000 and 1999, the Accounts Payable balance on the
Consolidated Balance Sheet included payables for capital expenditures of $298
million, $232 million and $161 million, respectively.

12. IMPAIRMENT OF OIL AND GAS PROPERTIES

In December 2001, primarily as a result of the Company's decision to exit
the Gulf of Mexico Shelf and divest of certain other properties, the Company
recognized a pretax impairment charge of $184 million primarily related to the
impairment of oil and gas properties held for sale. The net book value of these
properties at December 31, 2001 totaled approximately $338 million.

In the fourth quarter of 1999, the Company determined there would be
performance related downward reserve adjustments associated with certain
properties located on the Gulf of Mexico shelf and in the Permian Basin. As a
result, the Company recognized a pretax impairment charge of $225 million
related to those properties.

50

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

13. SEGMENT AND GEOGRAPHIC INFORMATION

The Company's reportable segments are USA, Canada and Other International.
These segments are engaged principally in the exploration, development,
production and marketing of oil, gas and NGLs. The accounting policies for the
segments are the same as those described in Note 1 of Notes to Consolidated
Financial Statements. Intersegment sales were $157 million and $85 million in
2001 and 2000, respectively. There were no intersegment sales in 1999.

The following tables present information about reported segment operations.

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

51

BURLINGTON RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

14. OTHER MATTERS

Recent Accounting Pronouncements

The following SFAS's were issued in June 2001: SFAS No. 141, Business
Combinations, SFAS No. 142, Goodwill and Other Intangible Assets, and SFAS No.
143, Accounting for Asset Retirement Obligations. In August 2001, SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets was also issued.
SFAS No. 141, requires the use of the purchase method of accounting for all
business combinations, applies to all business combinations initiated after June
30, 2001 and to all business combinations accounted for by the purchase method
that are completed after June 30, 2001. SFAS No. 142 requires that goodwill as
well as other intangible assets with indefinite lives not be amortized but be
tested annually for impairment and is effective for fiscal years beginning after
December 15, 2001. SFAS No. 141 and No. 142 apply to the Company's accounting
for the Hunter acquisition. The Company is in the process of evaluating the
impairment methodology for goodwill.

SFAS No. 143 requires entities to record the fair value of a liability for
an asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
Subsequently, the asset retirement cost should be allocated to expense using a
systematic and rational method. SFAS No. 143 is effective for fiscal years
beginning after June 15, 2002. SFAS No. 144 addresses financial accounting and
reporting for the impairment of long-lived assets to be disposed of. It
supersedes, with exceptions, SFAS No. 121, Accounting for the Impairment of
Long-Lived Assets to Be Disposed Of and is effective for fiscal years beginning
after December 15, 2001. The Company is currently assessing the impact of SFAS
No. 143 and No. 144 and therefore, at this time cannot reasonably estimate the
effect of these statements on its consolidated financial position, results of
operations or cash flows.

15. SUBSEQUENT EVENTS

On January 3, 2002, the Company consummated a property acquisition from
ATCO Gas and Pipelines Ltd., a Canadian regulated gas utility, for approximately
$346 million.

52

REPORT OF MANAGEMENT

The management of BR is responsible for the preparation and integrity of
all information contained in this Annual Report. The accompanying financial
statements have been prepared in conformity with accounting principles generally
accepted in the United States of America. The financial statements include
amounts that are management's best estimates and judgments.

BR maintains a system of internal control and a program of internal
auditing that provides management with reasonable assurance that BR's assets are
protected and that published financial statements are reliable and free of
material misstatement. Management is responsible for the effectiveness of
internal controls. This is accomplished through established codes of conduct,
accounting and other control systems, policies and procedures, employee
selection and training, appropriate delegation of authority and segregation of
responsibilities.

The Audit Committee of the Board of Directors, composed solely of directors
who are not officers or employees, meets regularly with the independent
accountants, financial management, counsel and internal audit. To ensure
complete independence, the independent accountants and internal audit have full
and free access to the Audit Committee to discuss the results of their audits,
the adequacy of internal controls and the quality of financial reporting.

Our independent accountants provide an objective independent review by
their audit of the Company's financial statements. Their audit is conducted in
accordance with auditing standards generally accepted in the United States of
America and includes a review of internal accounting controls to the extent
deemed necessary for the purposes of their audit.

/s/ STEVEN J. SHAPIRO /s/ JOSEPH P. MCCOY
- -------------------------------------------- --------------------------------------------
Steven J. Shapiro Joseph P. McCoy
Senior Vice President and Vice President, Controller and
Chief Financial Officer Chief Accounting Officer

53

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholders of Burlington Resources Inc.

In our opinion, based on our audits and the report of other auditors, the
accompanying consolidated balance sheet and the related consolidated statements
of income, cash flows and stockholders' equity, present fairly, in all material
respects, the financial position of Burlington Resources Inc. and its
subsidiaries at December 31, 2001 and 2000, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2001 in conformity with accounting principles generally accepted in the
United States of America. These financial statements are the responsibility of
the Company's management; our responsibility is to express an opinion on these
financial statements based on our audits. The consolidated financial statements
give retroactive effect to the merger of Poco Petroleums Ltd. on November 18,
1999 in a transaction accounted for as a pooling of interests, as described in
Note 2 to the consolidated financial statements. We did not audit the financial
statements of Poco Petroleums Ltd., which statements reflect total revenues of
$407 million for the year ended December 31, 1999. Those statements were audited
by other auditors whose report thereon has been furnished to us, and our opinion
expressed herein, insofar as it relates to the amounts included for Poco
Petroleums Ltd., is based solely on the report of the other auditors. We
conducted our audits of these statements in accordance with auditing standards
generally accepted in the United States of America, which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits and the report of other auditors provide a reasonable
basis for our opinion.

As discussed in Note 4 to the consolidated financial statements, the
Company changed its method of accounting for its derivative instruments and
hedging activities in connection with its adoption of Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities", as amended.

/s/ PRICEWATERHOUSECOOPERS LLP

February 13, 2002
Houston, Texas

54

BURLINGTON RESOURCES INC.

SUPPLEMENTARY FINANCIAL INFORMATION

SUPPLEMENTAL OIL AND GAS DISCLOSURES -- UNAUDITED

The supplemental data presented herein reflects information for all of the
Company's oil and gas producing activities.

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

- ---------------

(1) The amounts exclude deferred taxes of $902 million related to the Hunter
acquisition.

55

BURLINGTON RESOURCES INC.

SUPPLEMENTARY FINANCIAL INFORMATION

Results of operations for oil, NGL and gas producing activities, which
exclude pipeline and processing activities, corporate general and administrative
expenses, fixed-rate depreciation expense, and payroll and miscellaneous taxes,
were as follow. Prior years have been restated to conform to current year
presentation. Intersegment sales were $157 million and $85 million in 2001 and
2000, respectively. There were no intersegment sales in 1999.

56

BURLINGTON RESOURCES INC.

SUPPLEMENTARY FINANCIAL INFORMATION

The following table reflects estimated quantities of proved oil, NGL and
gas reserves. These reserves have been estimated by the Company's petroleum
engineers. The Company considers such estimates to be reasonable, however, due
to inherent uncertainties, estimates of underground reserves are imprecise and
subject to change over time as additional information becomes available. To
reflect the change in the characteristics of its oil and gas properties, in
2001, the Company began reporting its production volumes and reserves in three
streams: natural gas, crude oil and NGLs. Under this methodology, gas production
and reserves are reported after extracting liquids and eliminating
non-hydrocarbon gases from the natural gas stream. This change had no material
impact on total equivalent reserves or production volumes. Amounts for prior
years have been reclassified to conform to current presentation.

58

BURLINGTON RESOURCES, INC.

SUPPLEMENTARY FINANCIAL INFORMATION

A summary of the standardized measure of discounted future net cash flows
relating to proved oil, NGL and gas reserves is shown below. Future net cash
flows are computed using year end commodity prices, costs and statutory tax
rates (adjusted for tax credits and other items) that relate to the Company's
existing proved oil, NGL and gas reserves.

59

BURLINGTON RESOURCES INC.

SUPPLEMENTARY FINANCIAL INFORMATION

A summary of the changes in the standardized measure of discounted future
net cash flows applicable to proved oil, NGL and gas reserves follows.

QUARTERLY FINANCIAL DATA -- UNAUDITED

- ---------------

(a) During the fourth quarter of 2001, the Company recognized a non-cash,
pretax charge of $184 million primarily related to the impairment of oil
and gas properties held for sale.

ITEM NINE

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE

None

60

PART III

ITEMS TEN AND ELEVEN

DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT AND EXECUTIVE COMPENSATION

Executive officers of the Registrant

Bobby S. Shackouls, 51 -- Chairman of the Board, President and Chief
Executive Officer, Burlington Resources Inc., July 1997 to present. President
and Chief Executive Officer, Burlington Resources Inc., December 1995 to July
1997; President and Chief Executive Officer, Burlington Resources Oil & Gas
Company, October 1994 to June 1998.

Randy L. Limbacher, 43 -- Senior Vice President, Production, Burlington
Resources Inc., April 2001 to present. President and Chief Executive Officer,
BROG GP Inc., general partner of Burlington Resources Oil & Gas Company LP,
December 2000 to present. President and Chief Executive Officer, Burlington
Resources Oil & Gas Company, July 1998 to December 2000. Vice President, Gulf
Coast Division, Burlington Resources Oil & Gas Company, February 1997 to June
1998; Vice President, Farmington Region, Burlington Resources Oil & Gas Company,
June 1993 to January 1997.

L. David Hanower, 42 -- Senior Vice President, Law and Administration,
Burlington Resources Inc., July 1998 to present. Senior Vice President, Law,
Burlington Resources Inc., April 1996 to June 1998, Vice President, Law,
Burlington Resources Inc., April 1991 to April 1996; Senior Vice President, Law,
Burlington Resources Oil & Gas Company, July 1993 to June 1998.

Steven J. Shapiro, 49 -- Senior Vice President and Chief Financial Officer,
Burlington Resources Inc., October 2000 to present. Senior Vice President, Chief
Financial Officer and Director, Vastar Resources, Inc., 1993 to September 2000.

John A. Williams, 57 -- Senior Vice President, Exploration, Burlington
Resources Inc., April 2001 to present. Senior Vice President, Exploration, BROG
GP Inc., general partner of Burlington Resources Oil & Gas Company LP, December
2000 to present. Senior Vice President, Exploration, Burlington Resources Oil &
Gas Company, July 1998 to December 2000. Senior Vice President, Exploration,
Burlington Resources Inc., October 1997 to June 1998; Senior Vice President,
Exploration and Production, The Louisiana Land and Exploration Company,
September 1995 to October 1997.

A definitive proxy statement for the 2002 Annual Meeting of Stockholders
(the "Proxy Statement") of the Company will be filed no later than 120 days
after the end of the fiscal year with the Securities and Exchange Commission.
The information set forth therein under "Election of Directors" and "Executive
Compensation" is incorporated herein by reference.

ITEM TWELVE

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information required is set forth under the caption "Stock Ownership of
Management and Certain Other Holders" in the Proxy Statement and is incorporated
herein by reference.

ITEM THIRTEEN

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Any information required is set forth under the caption "Election of
Directors" in the Proxy Statement and is incorporated herein by reference.

61

PART IV

ITEM FOURTEEN

EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

REPORTS ON FORM 8-K

The Company filed a Form 8-K dated December 4, 2001, which included as an
exhibit a Press Release also dated December 4, 2001 announcing the acceptance of
its C$53 per share cash tender offer to acquire all the common shares of
Canadian Hunter Exploration Ltd. by Canadian Hunter's shareholders. The
financial statements and pro forma financial information for Canadian Hunter
required to be filed pursuant to Item 7 of such Form 8-K are filed as exhibits
99.3, 99.4 and 99.5 in this Form 10-K.

The Company filed a Form 8-K dated October 9, 2001, which included as an
exhibit a Press Release also dated October 9, 2001 announcing the Company and
Canadian Hunter Exploration Ltd. have entered into an agreement pursuant to
which the Company will make an offer to holders of the outstanding shares of
Canadian Hunter to acquire all such shares for cash consideration of C$53 per
share, representing an aggregate value of approximately U.S. $2.1 billion in
cash.

62

SIGNATURES REQUIRED FOR FORM 10-K

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Burlington Resources Inc. has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized.

BURLINGTON RESOURCES INC.

By /s/ BOBBY S. SHACKOULS
------------------------------------
Bobby S. Shackouls
Chairman of the Board, President and
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of Burlington
Resources Inc. and in the capacities and on the dates indicated.

By /s/ BOBBY S. SHACKOULS Chairman of the Board, February 13, 2002
----------------------------------------------------- President and Chief
Bobby S. Shackouls Executive Officer

/s/ STEVEN J. SHAPIRO Senior Vice President and February 13, 2002
- -------------------------------------------------------- Chief Financial Officer
Steven J. Shapiro

/s/ JOSEPH P. MCCOY Vice President, February 13, 2002
- -------------------------------------------------------- Controller and Chief
Joseph P. McCoy Accounting Officer

/s/ REUBEN V. ANDERSON Director February 13, 2002
- --------------------------------------------------------
Reuben V. Anderson

/s/ LAIRD I. GRANT Director February 13, 2002
- --------------------------------------------------------
Laird I. Grant

/s/ JOHN T. LAMACCHIA Director February 13, 2002
- --------------------------------------------------------
John T. Lamacchia

/s/ JAMES F. MCDONALD Director February 13, 2002
- --------------------------------------------------------
James F. McDonald

/s/ KENNETH W. ORCE Director February 13, 2002
- --------------------------------------------------------
Kenneth W. Orce

/s/ DONALD M. ROBERTS Director February 13, 2002
- --------------------------------------------------------
Donald M. Roberts

/s/ JOHN F. SCHWARZ Director February 13, 2002
- --------------------------------------------------------
John F. Schwarz

/s/ WALTER SCOTT, JR. Director February 13, 2002
- --------------------------------------------------------
Walter Scott, Jr.

/s/ WILLIAM E. WADE Director February 13, 2002
- --------------------------------------------------------
William E. Wade

BURLINGTON RESOURCES INC.

AMENDED EXHIBIT INDEX

The following exhibits are filed as part of this report.

A-1

A-2

*Exhibit incorporated herein by reference as indicated.

+Exhibit constitutes a management contract or compensatory plan or arrangement
required to be filed as an exhibit to this report pursuant to Item 14(c) of
Form 10-K.

A-3