BURLINGTON RESOURCES INC - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2002

OR

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

Commission File Number 1-9971

BURLINGTON RESOURCES INC.
(Exact name of registrant as specified in its charter)

Delaware 91-1413284
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)

5051 Westheimer, Suite 1400, Houston, Texas 77056
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code (713) 624-9500

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 the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.

PART I - FINANCIAL INFORMATION

ITEM 1. Financial Statements

BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF INCOME
(UNAUDITED)

See accompanying Notes to Consolidated Financial Statements.

2

BURLINGTON RESOURCES INC.
CONSOLIDATED BALANCE SHEET
(UNAUDITED)

See accompanying Notes to Consolidated Financial Statements.

3

BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(UNAUDITED)

See accompanying Notes to Consolidated Financial Statements.

4

BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. BASIS OF PRESENTATION

The 2001 Annual Report on Form 10-K (Form 10-K) of Burlington Resources
Inc. (the Company) includes certain definitions and a summary of significant
accounting policies and should be read in conjunction with this Quarterly Report
on Form 10-Q (Quarterly Report). The financial statements for the periods
presented herein are unaudited and do not contain all information required by
generally accepted accounting principles to be included in a full set of
financial statements. In the opinion of management, all material adjustments
necessary to present fairly the results of operations have been included. All
such adjustments are of a normal, recurring nature. The results of operations
for any interim period are not necessarily indicative of the results of
operations for the entire year. The consolidated financial statements include
certain reclassifications that were made to conform to current period
presentation.

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 of accounting. The Company
has investments in two entities that it accounts for under the equity method,
Lost Creek Gathering Company (Lost Creek) and CLAM Petroleum B.V. (CLAM). As of
June 30, 2002, Lost Creek and CLAM had outstanding debt totaling $54 million and
$10 million, respectively, that are non-recourse to the Company, and as a
result, the Company has no legal responsibility or obligation for this debt.
Management believes that Lost Creek and CLAM are financially stable and
therefore will be in a position to repay the outstanding debts.

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 201 million and 210 million for the
second quarter of 2002 and 2001, respectively, and 201 million and 212 million
for the first six months of 2002 and 2001, 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 202 million and 211 million for the second quarter
of 2002 and 2001, respectively, and 202 million and 213 million for the first
six months of 2002 and 2001, respectively. For the second quarter of 2002 and
2001 and six months ended June 30, 2002 and June 30, 2001, approximately 4
million, 3 million, 4 million and 3 million shares, respectively, attributable
to the potential exercise of outstanding options were excluded from the
calculation of diluted EPS because the effect was antidilutive. The Company has
no preferred stock or other convertible securities affecting EPS, and therefore,
no adjustments related to preferred stock or other convertible securities were
made to reported net income in the computation of EPS.

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2. COMPREHENSIVE INCOME (LOSS)

The following table presents comprehensive income (loss).

3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The Company enters into gas swap agreements to fix the prices of
anticipated future natural gas production and enters into gas swap agreements
that convert its production back to market sensitive positions when matched
against fixed-price gas sales. In conjunction with these swap agreements, the
Company may enter into natural gas basis swap agreements to fix the sales price
differential between the Company's marketing locations and Henry Hub. The
Company also enters into natural gas option and crude oil agreements (collars)
to establish floor and ceiling prices on anticipated future natural gas and
crude oil production. In order to reduce the cost of the collars, the Company
may sell natural gas and crude oil put options that effectively replace the
floor with a fixed premium over the index price in low price environments. In
order to protect the hedge portfolio in upward price movements, the Company may
purchase natural gas and crude oil call options. There were no net premiums
received when the Company entered into these option agreements.

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As of June 30, 2002, the Company had the following natural gas and
crude oil volumes hedged.

Natural Gas Fixed-price Swaps

Natural Gas Basis Swaps

Natural Gas Options

Crude Oil Options

As of June 30, 2002, 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 $4 million asset offset by a $4
million liability basis adjustment to the carrying value of the fixed-price gas
sales contracts. These agreements extend through 2005.

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The derivative assets and liabilities represent the difference between
hedged prices and market prices (intrinsic value) plus the time value associated
with option hedges, on hedged volumes of the commodities as of June 30, 2002.
Hedging activities increased natural gas and crude oil revenues by $93 million
and $3 million, respectively, during the first six months of 2002. In addition,
during the first six months of 2002, non-cash losses of $26 million were
recorded in revenues associated with ineffectiveness of cash-flow and fair-value
hedges and changes in the fair value of derivative instruments that do not
qualify for hedge accounting. Cash-flow hedges are used by the Company to hedge
exposures to the risk of variability in cash flows. Fair value hedges are used
by the Company to hedge or offset the exposure to changes in the fair value of a
recognized asset or liability or an unrecognized firm commitment.

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 June 30, 2002, the Company had liabilities of
$5 million related to foreign currency exchange rate hedges with contracts
extending through 2005.

Based on commodity prices and foreign exchange rates as of June 30,
2002, the Company expects to reclassify gains of $20 million ($13 million after
tax) to earnings from the balance in accumulated other comprehensive income
during the next twelve months. As of June 30, 2002, the Company had cash-flow
hedge derivative assets of $27 million and derivative liabilities of $24
million. The Company also had liabilities and assets related to fair-value
hedges of $5 million and $7 million, respectively.

4. COMMITMENTS AND CONTINGENCIES

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 during the
period of 1985 to the present. Plaintiffs allege that the royalties paid by
defendants were lower than the royalties required to be paid under federal
regulations and that the forms filed by defendants with the Minerals Management
Service (MMS) reporting these royalty payments were false, thereby violating the
civil False Claims Act. The United States has intervened in certain of the
MDL-1293 cases as to some of the defendants, including the Company. The
plaintiffs and the intervenor have not specified in their pleadings the amount
of damages they seek from the Company.

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

8

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 unlawfully trespassed or were otherwise
unjustly enriched by producing part of the oil from the adjoining Q-1 Block. The
plaintiffs claim that the defendants infringed upon plaintiffs' right to produce
the minerals present in its license area and acted in violation of generally
accepted standards by failing to inform plaintiffs of the overlap of the Logger
Field into the Q-1 Block. Plaintiffs seek damages of $97.5 Million as of January
1, 1997, plus interest. For all relevant periods, the Company owned a 37.5%
working interest in the Logger Field. Following a trial, the District Court in
The Hague rendered a Judgment in favor of the defendants, including the Company,
dismissing all claims. Plaintiffs thereafter appealed. On October 19, 2000, the
Court of Appeal in The Hague issued an interim Judgment in favor of the
plaintiffs and ordered that additional evidence be presented to the court
relating to issues of both liability and damages. The Company and the other
defendants are continuing to present evidence to the Court and vigorously assert
defenses against these claims. The Company has also asserted claims of indemnity
against two of the defendants from whom it had acquired a portion of its working
interest share. If the Company is successful in enforcing the indemnities, its
working interest share of any adverse judgment could be reduced to 15% for some
of the periods covered by plaintiffs' lawsuit. The Company is unable at this
time to reasonably predict the outcome, or, in the event of an unfavorable
outcome, to reasonably estimate the possible loss or range of loss, if any, in
this lawsuit.

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

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5. DEBT

In February 2002, Burlington Resources Finance Company (BRFC) issued
$350 million of 5.7% Notes due March 1, 2007. In June 2002, the Company retired
a $100 million 8 1/4% Note. To retire the 8 1/4% Note, the Company issued a
promissory note for $104 million at a per annum rate equal to the sum of
Eurodollar rates plus 0.70 percent. The promissory note is due September 17,
2002. During the first six months of 2002, the Company also retired $675 million
of net commercial paper and has no commercial paper outstanding at June 30,
2002.

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

The fair value of the Company's long-term debt at June 30, 2002 and
December 31, 2001, excluding commercial paper, was approximately $4,166 million
and $3,727 million, respectively, based on quoted market prices.

6. PROPERTY TRANSACTIONS

On January 3, 2002, the Company consummated a property acquisition from
ATCO Gas and Pipeline Ltd. (ATCO), a Canadian regulated gas utility, for
approximately $344 million.

During the fourth quarter of 2001, the Company announced its intent to
sell certain non-core, non-strategic properties in order to improve the overall
quality of its portfolio, primarily in the U.S. Due to their high cost
structure, high production volume decline rates and limited growth
opportunities, substantially all of the Shelf, and south and east Texas assets
are included in the non-core, non-strategic properties. During the second
quarter of 2002, the Company sold certain non-core, non-strategic properties,
including the Val Verde gathering and processing plant, and generated proceeds,
before post closing adjustments, of approximately $892 million and recognized a
net gain of $73 million. The net gain includes an estimated loss of $114 million
associated with purchase and sale agreements that were signed but the
transactions not closed as of June 30, 2002. The net book value of the
properties held for sale at June 30, 2002 was $234 million. The Company intends
to complete the remaining property sales by year-end 2002 and expects to
generate additional proceeds in excess of $300 million. The Company has and
expects to use the proceeds generated from property sales to repay debt and for
general corporate purposes.

In connection with the divestiture program, the Company also recorded
restructuring liabilities of $10 million in the fourth quarter of 2001. As of
June 30, 2002, $2 million of the restructuring liabilities remained outstanding
as Accounts Payable on the Consolidated Balance Sheet.

10

7. INCOME TAXES

The Company's effective income tax rate decreased to 19 percent at June
30, 2002 from 38 percent at December 31, 2001 primarily due to interest
deductions allowed in both the U.S. and Canada on transactions associated with
debt financing entered into in the second half of 2001 and the first quarter of
2002.

8. SEGMENT AND GEOGRAPHIC INFORMATION

The Company's reportable segments are USA, Canada and Other
International (Intl). The segments are engaged principally in the exploration,
development, production and marketing of crude oil, NGLs and natural gas. The
accounting policies for the segments are the same as those disclosed in Note 1
of Notes to Consolidated Financial Statements included in the Company's Form
10-K. Intersegment sales were $1 million and $53 million during the second
quarter of 2002 and 2001, respectively, and were $15 million and $124 million
during the first six months of 2002 and 2001, respectively.

The following tables present information about reported segment
operations.

9. ACCOUNTING PRONOUNCEMENTS

In April 2002, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 145, Rescission of FASB
Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical
Corrections (SFAS No. 145). SFAS No. 145, which is effective for fiscal years
beginning after May 15, 2002, provides guidance for income statement
classification of gains and losses on extinguishment of debt and accounting for
certain lease modifications that have economic effects that are similar to
sale-leaseback transactions. The Company is currently assessing the impact of
SFAS No. 145 and therefore, cannot reasonably estimate the effects of this
statement on its consolidated financial position, results of operations or cash
flows.

11

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligation. 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-live 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. The Company has embarked upon
engineering studies and is currently accumulating, reviewing and analyzing data
in order to assess the impact of SFAS No. 143. The process is not complete and
therefore, at this time, the Company cannot reasonably estimate the effect of
this statement on its consolidated financial position, results of operations or
cash flows. The Company expects to complete the process during the third quarter
of 2002 and expects to disclose the anticipated effect of this statement on the
Company's consolidated financial position, results of operations and cash flows
in its third quarter 2002 Form 10-Q.

10. GOODWILL

Effective January 1, 2002, the Company adopted SFAS No. 142, Goodwill
and Other Intangible Assets. SFAS No. 142 requires the Company to test goodwill
for impairment rather than amortize. Under the transition provisions of SFAS No.
142, goodwill acquired in a business combination for which the acquisition date
is after June 30, 2001 is not to be amortized and is to be reviewed for
impairment under existing standards until adoption of SFAS 142 on January 1,
2002. The entire goodwill balance of $835 million at June 30, 2002, which is not
deductible for tax purposes, is related to the acquisition of Canadian Hunter
Exploration Ltd. (Hunter) on December 5, 2001. Accordingly, the Company recorded
no goodwill amortization during 2001. With the acquisition of Hunter, the
Company gained Hunter's significant interest in Canada's Deep Basin, North
America's third-largest natural gas field, increased its critical mass and
enhanced its position as a leading North American natural gas producer. The
Company also obtained the exploration expertise of Hunter's workforce, gained
additional cost optimization by eliminating duplicate efforts, increased
purchasing power and gained greater marketing flexibility in optimizing sales
and accessing key market information.

All of the goodwill was assigned to the Company's Canadian reporting
unit for assessing impairment. The initial adoption of SFAS No. 142 required the
Company to perform a two-step fair value based goodwill impairment test. The
first step of the test compares the book values of the Company's reporting units
to their estimated fair values. The second step of the goodwill impairment test
is only required if the net book value of the reporting unit exceeds the fair
value. The second step of the goodwill impairment test compares the implied fair
value of goodwill in accordance with the methodology prescribed by SFAS No. 142
to its book value to determine if an impairment is required. During the second
quarter of 2002, the Company completed the first step of its impairment analysis
related to its goodwill and determined that the Company's fair value of its
Canadian reporting unit exceeded its net book value at January 1, 2002, thereby
eliminating the need for the second step.

The following table reflects the changes in the carrying amount,
including the final purchase accounting adjustment, of goodwill during the year
as it relates to the Canadian reporting unit.

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11. PRO FORMA SUMMARY FINANCIAL INFORMATION

On December 5, 2001, the Company acquired all of the outstanding shares
of Hunter for cash consideration of Canadian $53 per share representing an
aggregate value of approximately U.S. $2.1 billion. The following table presents
the unaudited pro forma results of the Company as though the acquisition of
Hunter had occurred on January 1, 2001. Pro forma results are not necessarily
indicative of actual results.

ITEM 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations

Financial Condition and Liquidity

The Company's total debt to total capital (total capital is defined as
total debt and stockholders' equity) ratio at June 30, 2002 and December 31,
2001 was 51 percent and 55 percent, respectively. The reduction in total debt to
total capital was accomplished by the disposition of assets and the generation
of cash flows from operations. The Company believes that it will generate
sufficient cash from operations to fund the remaining 2002 capital expenditures
in today's natural gas price environment. Effective January 2, 2002, the Company
entered into a $350 million bridge revolving credit facility (Facility) in order
to finance the acquisition of certain assets from ATCO. On January 2, 2002, the
Company issued commercial paper under the Facility to fund the acquisition. In
February 2002, BRFC issued $350 million of 5.7 % Notes due March 1, 2007
(February Notes). The proceeds from the February Notes were used to retire such
commercial paper and the Company terminated the Facility. The February Notes
reduced the Company's amount available under its shelf registration statement on
file with the Securities and Exchange Commission to $397 million. In June 2002,
the Company restored its shelf registration statement to $1,500 million. At June
30, 2002, the Company had $392 million of cash and cash equivalents on hand.

In June 2002, the Company retired a $100 million 8 1/4% Note. To retire
the 8 1/4% Note, the Company issued a promissory note for $104 million at a per
annum rate equal to the sum of Eurodollar rates plus 0.70 percent. The
promissory note is due September 17, 2002. During the first six months of 2002,
the Company also retired $675 million of net commercial paper and has no
commercial paper outstanding at June 30, 2002.

In June 2002, the Company commenced an offer to exchange its
outstanding 5.6% Notes due 2006, 6.5% Notes due 2011 and 7.4% Notes due 2031,
which were issued by BRFC and fully and unconditionally guaranteed by BR, in a
private offering in November 2001 (Private Notes), for a like principal amount
of 5.6% Notes due 2006, 6.5% Notes due 2011 and 7.4% Notes due

13

2031 to be issued by BRFC, fully and unconditionally guaranteed by BR and
registered under the Securities Act of 1933, as amended (Registered Notes). In
July 2002, following the expiration of the exchange offer, the Company issued
the Registered Notes. All of the Private Notes were exchanged for Registered
Notes and the Private Notes were cancelled.

The Company had credit commitments in the form of revolving credit
facilities (revolvers) as of June 30, 2002. The revolvers, which are comprised
of agreements for $600 million, $400 million and approximately Canadian $471
million (U.S. $310 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 and no outstanding commercial paper.
Outstanding commercial paper would reduce the amount of credit available under
the revolvers. The $600 million revolver expires in December 2006 and the $400
million and Canadian $471 million revolvers expire in December 2002 unless
renewed by mutual consent. The Company has the option to convert the outstanding
balances on the $400 million and Canadian $471 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).

Net cash provided by operating activities during the first six months
of 2002 was $776 million compared to $1,489 million in 2001. The decrease was
primarily due to lower income and higher working capital needs. Lower income is
principally the result of lower natural gas and NGL prices partially offset by
higher natural gas and NGL sales volumes.

The Company and its subsidiaries are named defendants in numerous
lawsuits and named parties in numerous governmental and other proceedings
arising in the ordinary course of business. While the outcome of lawsuits and
other proceedings cannot be predicted with certainty, management believes these
matters will not have a material adverse effect on the consolidated financial
position of the Company, although results of operations and cash flows could be
significantly impacted in the reporting periods in which such matters are
resolved.

The Company has certain other commitments and uncertainties related to
its normal operations. However, management believes that these other commitments
or uncertainties will not have a material adverse effect on the consolidated
financial position, results of operations or cash flows of the Company.

Capital Expenditures

Capital expenditures for the first six months of 2002 totaled $982
million compared to $655 million in 2001. The Company invested $484 million on
internal development and exploration of oil and gas properties during the first
six months of 2002 compared to $489 million in 2001. The increase in capital
expenditures in 2002 are primarily due to property acquisitions where the
Company invested $417 million in the first six months of 2002 compared to $92
million in 2001. Property acquisitions include the purchase of certain assets on
January 3, 2002 from ATCO Gas and Pipeline Ltd., a Canadian regulated gas
utility, for approximately $344 million. The Company's base capital
expenditures, which exclude acquisitions, are projected to be approximately $1.3
billion for all of 2002. This amount is expected to be used primarily for the
development and exploration of oil and gas properties and plants and pipeline
expenditures. The Company expects to fund base capital expenditures from
internally generated operating cash flows.

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During the fourth quarter of 2001, the Company announced its intent to
sell certain non-core, non-strategic properties in order to improve the overall
quality of its portfolio, primarily in the U.S. Due to their high cost
structure, high production volume decline rates and limited growth
opportunities, substantially all of the Shelf, and south and east Texas assets
are included in the non-core, non-strategic properties. During the second
quarter of 2002, the Company sold certain non-core, non-strategic properties,
including the Val Verde gathering and processing plant (Val Verde Plant), and
generated proceeds, before post closing adjustments, of approximately $892
million and recognized a net pretax gain of $73 million. The net pretax gain
includes an estimated pretax loss of $114 million associated with purchase and
sale agreements that were signed but the transactions not closed as of June 30,
2002. The net book value of the properties held for sale at June 30, 2002 was
$234 million. The Company intends to complete the remaining property sales by
year-end 2002 and expects to generate additional proceeds in excess of $300
million. The Company has and expects to use the proceeds generated from property
sales to repay debt and for general corporate purposes.

In connection with the divestiture program, in the fourth quarter of
2001, the Company also recorded restructuring liabilities of $10 million. As of
June 30, 2002, $2 million of the restructuring liabilities remained outstanding
as Accounts Payable on the Consolidated Balance Sheet.

Dividends

On July 17, 2002, the Board of Directors declared a quarterly common
stock cash dividend of $0.1375 per share, with record and payment dates of
September 6, 2002 and October 1, 2002, respectively.

Results of Operations - Second Quarter 2002 Compared to Second Quarter 2001

The Company reported net income of $170 million or $0.84 diluted
earnings per common share in second quarter 2002 compared to net income of $231
million or $1.10 diluted earnings per common share in second quarter 2001. Net
income in second quarter 2002 included a net after tax gain of $45 million or
$0.23 per diluted share related to the disposal of assets. Net income in second
quarter 2002 and 2001 also included an after tax loss of $1 million or nil per
diluted share and $14 million or $0.07 per diluted share, respectively,
consisting of ineffectiveness related to cash-flow and fair-value hedges and
changes in the fair value of derivative instruments that do not qualify for
hedge accounting. Cash-flow hedges are used by the Company to hedge exposures to
the risk of variability in cash flows. Fair value hedges are used by the Company
to hedge or offset the exposure to changes in the fair value of a recognized
asset or liability or an unrecognized firm commitment.

Revenues

Revenues decreased $159 million to $769 million in second quarter 2002
compared to $928 million in second quarter 2001. As described below, the $159
million decrease in revenues primarily consists of $250 million related to lower
commodity prices, $24 million due to lower revenues related to ineffectiveness
on hedging activities partially offset by $111 million related to higher
production volumes. Including a $0.14 realized gain per MCF related to hedging
activities, average gas prices decreased $1.23 per MCF in second quarter 2002 to
$3.14 per MCF from $4.37 per MCF in second quarter 2001 which decreased revenues
$214 million. Average NGL prices decreased $6.02 per barrel in second quarter
2002 to $13.86 per barrel from $19.88 per barrel in second quarter 2001,
resulting in reduced revenues of $36 million. Average oil

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prices increased $0.02 per barrel in second quarter 2002 to $24.64 per barrel
from $24.62 per barrel in second quarter 2001. There were no hedging gains or
losses related to oil volumes during second quarter 2002. In second quarter 2002
and 2001, revenues included $10 million and $11 million, respectively, generated
from third parties by the Val Verde Plant that was sold in June 2002. In second
quarter 2002 and 2001, revenues also included a loss of $1 million and a gain of
$23 million, respectively, related to ineffectiveness of cash-flow and
fair-value hedges and changes in the fair value of derivative instruments that
do not qualify for hedge accounting.

Gas sales volumes increased 248 MMCF per day in second quarter 2002 to
1,927 MMCF per day from 1,679 MMCF per day in second quarter 2001 resulting in
increased revenues of $98 million. NGL sales volumes increased 18.5 MBbls per
day in second quarter 2002 to 65.0 MBbls per day from 46.5 MBbls per day in
second quarter 2001, resulting in higher revenues of $34 million from quarter to
quarter. Oil sales volumes decreased 9.5 MBbls per day in second quarter 2002 to
54.8 MBbls per day from 64.3 MBbls per day in second quarter 2001 reducing
revenues $21 million. Gas sales volumes in Canada increased 397 MMCF per day
primarily due to the acquisition of Canadian Hunter Exploration Ltd. (Hunter) in
late 2001 partially offset by natural declines of 77 MMCF per day in Onshore
Gulf Coast and the Gulf of Mexico and natural declines of 80 MMCF per day in San
Juan. NGL sales volumes in Canada also increased 17.2 MBbls per day primarily
due to the acquisition of Hunter. Oil sales volumes decreased 4.7 MBbls per day
primarily due to natural declines in the Gulf of Mexico and Canada and 2.9 MBbls
per day primarily due to asset sales in Mid-Continent and Canada.

Total Costs and Other Income

Total costs and other income were $562 million in second quarter 2002
compared to $548 million in second quarter 2001. The $14 million increase was
primarily due to a $52 million increase in exploration costs, a $39 million
increase in depreciation, depletion and amortization (DD&A), a $24 million
increase in interest expense and a $4 million increase in general and
administrative (G&A) expenses partially offset by a $71 million increase in gain
on disposal of assets, a $17 million decrease in taxes other than income taxes,
an $8 million decrease in production and processing expenses, a $5 million
decrease in transportation expenses and a $4 million increase in other income.

Exploration costs increased primarily due to higher drilling rig
expenses of $36 million, higher amortization of undeveloped lease costs of $19
million and higher geological and geophysical (G&G) and other expenses of $9
million partially offset by lower exploratory dry hole costs of $12 million. The
higher drilling rig expenses, which were approximately $40 million during the
period, were attributable to the subletting of a deepwater drilling rig
currently under lease to the Company. This $40 million charge covers the
anticipated loss for the remaining term of the lease. DD&A increased primarily
due to a higher unit-of-production rate related to changes in production
resulting from the Canadian acquisitions, which had higher rates than the
average unit-of-production rates for the Company. DD&A also increased due to
higher gas production volumes in Canada. Interest expense increased primarily
due to higher debt balances during second quarter 2002 resulting from the Hunter
acquisition in late 2001 and other property acquisitions consummated in early
2002. G&A expenses were higher in 2002 compared to 2001 primarily due to payroll
related costs. Taxes other than income taxes decreased primarily due to lower
oil and gas revenues. Production and processing expenses decreased primarily due
to lower well operating costs related to the Shelf and other divestiture
properties partially offset by higher Canadian expenses resulting from the
acquisition of Hunter in December 2001. Transportation expenses decreased
primarily due to lower contract rates.

16

Income Tax Expense

Income taxes were an expense of $37 million in second quarter 2002
compared to $149 million in second quarter 2001. The decrease in tax expense was
primarily due to lower pretax income. The Company also recorded benefits of $42
million in second quarter 2002 compared to $2 million in second quarter 2001
related to interest deductions allowed in both the U.S. and Canada on
transactions associated with debt financing entered into in the second half of
2001 and the first quarter of 2002. Section 29 Tax Credits were $9 million in
second quarter 2002 compared to $5 million in second quarter 2001.

Results of Operations - First Six Months of 2002 Compared to First Six Months of
2001

The Company reported net income of $218 million or $1.08 diluted
earnings per common share in the first six months of 2002 compared to net income
of $567 million or $2.66 diluted earnings per common share in the first six
months of 2001. Net income in the first six months of 2002 included a net after
tax gain of $45 million or $0.23 per diluted share related to the disposal of
assets. Net income in the first six months of 2002 also included an after tax
loss of $16 million or $0.08 per diluted share compared to an after tax gain of
$21 million or $0.10 per diluted share in the first six months of 2001,
consisting of the cumulative effect of change in accounting principle,
ineffectiveness related to cash-flow and fair-value hedges and changes in the
fair value of derivative instruments that do not qualify for hedge accounting.

Revenues

Revenues decreased $628 million to $1,452 million in the first six
months of 2002 compared to $2,080 million in the first six months of 2001. As
described below, the $628 million decrease in revenues primarily consists of
$834 million related to lower commodity prices, $56 million due to lower
revenues related to ineffectiveness on hedging activities partially offset by
$260 million related to higher production volumes. Including a $0.26 realized
gain per MCF related to hedging activities, average gas prices decreased $2.04
per MCF in the first six months of 2002 to $3.01 per MCF from $5.05 per MCF in
the first six months of 2001 which decreased revenues $728 million. Including a
$0.30 realized gain per barrel related to hedging activities, average oil prices
decreased $2.10 per barrel in the first six months of 2002 to $23.10 per barrel
from $25.20 per barrel in the first six months of 2001 resulting in reduced
revenues of $22 million. Average NGL prices decreased $7.69 per barrel in the
first six months of 2002 to $13.21 per barrel from $20.90 per barrel in the
first six months of 2001, resulting in reduced revenues of $84 million. In the
first six months of 2002 and 2001, revenues included $19 million and $22
million, respectively, generated from third parties by the Val Verde Plant that
was sold in June 2002. In the first six months of 2002 and 2001, revenues also
included a loss of $26 million and a gain of $30 million, respectively, related
to ineffectiveness of cash-flow and fair-value hedges and changes in the fair
value of derivative instruments that do not qualify for hedge accounting.

Gas sales volumes increased 255 MMCF per day in the first six months
of 2002 to 1,972 MMCF per day from 1,717 MMCF per day in the first six months of
2001 resulting in increased revenues of $233 million. NGL sales volumes
increased 16.7 MBbls per day in the first six months of 2002 to 60.7 MBbls per
day from 44.0 MBbls per day in the first six months of 2001, resulting in higher
revenues of $63 million. Oil sales volumes decreased 7.9 MBbls per day in the
first six months of 2002 to 57.3 MBbls per day from 65.2 MBbls per day in the
first six months of 2001 reducing revenues $36 million. Gas sales volumes in
Canada increased 392 MMCF per day primarily due to the acquisition of Hunter in
late 2001 partially offset by natural

17

declines of 81 MMCF per day in Onshore Gulf Coast and the Shelf and natural
declines of 74 MMCF per day in San Juan. NGL sales volumes in Canada also
increased 17.8 MBbls per day primarily due to the acquisition of Hunter. Oil
sales volumes decreased 4.6 MBbls per day primarily due to natural declines in
the Gulf of Mexico and Canada and 2.3 MBbls per day primarily due to asset sales
in Mid-Continent and Canada.

Total Costs and Other Income

Total costs and other income were $1,184 million in the first six
months of 2002 compared to $1,143 million in the first six months of 2001. The
$41 million increase was primarily due to an $89 million increase in DD&A, a $51
million increase in interest expense, a $39 million increase in exploration
costs and a $10 million increase in production and processing expenses partially
offset by a $71 million increase in gain on disposal of assets, a $51 million
decrease in taxes other than income taxes, a $14 million increase in other
income, a $10 million decrease in transportation expenses and a $2 million
decrease in G&A expenses.

DD&A increased primarily due to a higher unit-of-production rate
related to changes in production resulting from the Canadian acquisitions, which
had higher rates than the average unit-of-production rates for the Company. DD&A
also increased due to higher gas production volumes in Canada. Interest expense
increased primarily due to higher debt balances during the first six months of
2002 resulting from the Hunter acquisition in late 2001 and other property
acquisitions consummated in early 2002. Exploration costs increased primarily
due to higher drilling rig costs of $38 million, higher amortization of
undeveloped lease costs of $31 million and higher G&G and other expenses of $13
million partially offset by lower exploratory dry hole costs of $43 million. The
higher drilling rig expenses, which were approximately $40 million during the
period, were attributable to the subletting of a deepwater drilling rig
currently under lease to the Company. This $40 million charge covers the
anticipated loss for the remaining term of the lease. Production and processing
expenses increased primarily due to higher Canadian expenses resulting from the
acquisition of Hunter in December 2001. Taxes other than income taxes decreased
primarily due to lower oil and gas revenues. Other income increased primarily
due to lower miscellaneous expenses incurred in 2002. Transportation expenses
decreased primarily due to lower contract rates and G&A expenses were lower in
2002 compared to 2001 primarily due to higher payroll related costs recorded in
2001.

Income tax Expense

Income taxes were an expense of $50 million in the first six months of
2002 compared to $373 million in the first six months of 2001. The decrease in
tax expense was primarily due to lower pretax income. The Company also recorded
benefits of $55 million in the first six months of 2002 compared to $6 million
in 2001 related to interest deductions allowed in both the U.S. and Canada on
transactions associated with debt financing entered into in the second half of
2001 and the first quarter of 2002. Section 29 Tax Credits were $12 million in
the first six months of 2002 compared to $13 million in the first six months of
2001.

Outlook

For the remainder of 2002, the Company expects production volumes to
decline from second quarter average volumes of 2,646 MMCFE per day. The Company
expects full year production volumes to average between 2,425 and 2,610 MMCFE
per day as a result of property sales and annual plant and pipeline maintenance
extending into the third quarter of 2002. The declines in average daily
production volumes related to property sales and plant and pipeline

18

maintenance are expected to be partially offset by additional production
volumes in Madden Field and the initiation of winter drilling in Canada.
Additionally, in June 2002, the Company sold the Val Verde Plant, which
contributed $19 million in third party revenues during the first six months of
2002. As a result of the sale, in addition to the future revenue loss, the
Company expects its transportation expenses to increase approximately $40
million annually offset partially by lower operating expenses of approximately
$11 million and lower DD&A of approximately $9 million. The current outlook for
natural gas prices is affected by natural gas inventory levels that are
currently high based upon historical levels. This indicator may lead to lower
short-term natural gas prices. However, the Company cannot accurately predict
future natural gas, NGL and crude oil prices, and therefore, it cannot determine
what effect the potential reduced production volumes will have on future
revenues. In addition to production volumes and commodity prices, finding and
developing sufficient amounts of crude oil and natural gas reserves at
economical costs are critical to the Company's long-term success. For 2002, the
Company plans to spend $1.3 billion on development, exploration and plants and
pipeline capital and additional funds on acquisitions. Results of the capital
programs are evaluated annually and cannot be predicted at this time, however
the results will be disclosed as of the end of the year in the Company's 2002
Form 10-K.

Accounting Pronouncements

In April 2002, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Standards No. 145, Rescission of FASB Statements No. 4,
44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections (SFAS
No. 145). SFAS No. 145, which is effective for fiscal years beginning after May
15, 2002, provides guidance for income statement classification of gains and
losses on extinguishment of debt and accounting for certain lease modifications
that have economic effects that are similar to sale-leaseback transactions. The
Company is currently assessing the impact of SFAS No. 145 and therefore, cannot
reasonably estimate the effects of this statement on its consolidated financial
position, results of operations or cash flows.

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset
Retirement Obligations. 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-live 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. The Company has embarked upon
engineering studies and is accumulating, reviewing and analyzing data in order
to assess the impact of SFAS No. 143. The process is not complete and therefore,
at this time, the Company cannot reasonably estimate the effect of this
statement on its consolidated financial position, results of operations or cash
flows. The Company expects to complete the process during the third quarter of
2002 and expects to disclose the anticipated effect of this statement on the
Company's consolidated financial position, results of operations and cash flows
in its third quarter 2002 Form 10-Q.

ITEM 3. Quantitative and Qualitative Disclosures about Commodity Risk

Substantially all of the Company's crude oil 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.

19

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."

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 recorded in income when the hedged commodity is sold. In order
to accommodate the needs of its customers, the Company also uses variable 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 June 30, 2002, the potential decrease in fair value of derivative
instruments assuming a 10 percent adverse movement (an increase in the
underlying commodities prices) would result in a $54 million increase in the
fair value of the net liabilities related to commodity hedging activities.

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.

Based on commodity prices and foreign exchange rates as of June 30,
2002, the Company expects to reclassify gains of $20 million ($13 million after
tax) to earnings from the balance in accumulated other comprehensive loss during
the next twelve months. As of June 30, 2002, the Company had cash-flow hedge
derivative assets of $27 million and derivative liabilities of $24 million. The
Company also had liabilities and assets related to fair-value hedges of $5
million and $7 million, respectively.

Forward-looking Statements

This Quarterly Report contains projections and other forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act of
1934. These projections and statements reflect the Company's current views with
respect to future events and financial performance. No assurances can be given,
however, that these events will occur or that these projections will be achieved
and actual results could differ materially from those projected as a result` of
certain factors. A discussion of these factors is included in the Company's 2001
Form 10-K.

PART II - OTHER INFORMATION

ITEM 1. 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

20

through the use of below-market prices, improper deductions, improper
measurement techniques and transactions with affiliated companies during the
period of 1985 to the present. Plaintiffs allege that the royalties paid by
defendants were lower than the royalties required to be paid under federal
regulations and that the forms filed by defendants with the Minerals Management
Service (MMS) reporting these royalty payments were false, thereby violating the
civil False Claims Act. The United States has intervened in certain of the
MDL-1293 cases as to some of the defendants, including the Company. The
plaintiffs and the intervenor have not specified in their pleadings the amount
of damages they seek from the Company.

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

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 unlawfully trespassed or were otherwise
unjustly enriched by producing part of the oil from the adjoining Q-1 Block. The
plaintiffs claim that the defendants infringed upon plaintiffs' right to produce
the minerals present in its license area and acted in violation of generally
accepted standards by failing to inform plaintiffs of the overlap of the Logger
Field into the Q-1 Block. Plaintiffs seek damages of $97.5 Million as of January
1, 1997, plus interest. For all relevant periods, the Company owned a 37.5%
working interest in the Logger Field. Following a trial, the District Court in
The Hague rendered a Judgment in favor of the defendants, including the Company,
dismissing all claims. Plaintiffs thereafter appealed. On October 19, 2000, the
Court of Appeal in The Hague issued an interim Judgment in favor of the
plaintiffs and ordered that additional evidence be presented to the court
relating to issues of both liability and damages. The Company and the other
defendants are continuing to present evidence to the Court and vigorously assert
defenses against these claims. The Company has also asserted claims of indemnity
against two of the defendants from whom it had acquired a portion of its working
interest share. If the Company is successful in enforcing the indemnities, its
working interest share of any adverse judgment could be reduced to 15% for some
of the periods covered by plaintiffs' lawsuit. The Company is unable at this
time to reasonably predict the outcome, or, in the event of an unfavorable
outcome, to reasonably estimate the possible loss or range of loss, if any, in
this lawsuit.

21

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

ITEM 4. Submission of Matters to a Vote of Security Holders

The annual meeting of stockholders was held on April 17, 2002. The
following were nominated and elected to serve as Directors of
Burlington Resources Inc. for a term of one year or until their
successors shall have been duly elected and qualified:

The Stockholders also approved the Burlington Resources 2002 Stock
Incentive Plan at the annual meeting with 171,119,893 votes for,
9,324,848 votes against and 1,191,981 votes abstaining. There were
no broker non-votes with respect to any matters submitted to a
vote of stockholders.

22

ITEM 6. Exhibits and Reports on Form 8-K

A. Exhibits

The following exhibits are filed as part of this report.

Exhibit Nature of Exhibit

4.1* The Company and its subsidiaries either have filed
with the Securities and Exchange Commission or
upon request will furnish a copy of any instrument
with respect to long-term debt of the Company.

10.1* Amendment No. 1 dated April 25, 2002 to $400
million Short-term Revolving Credit Agreement
(incorporated by reference to Exhibit 10.18 to
Amendment No. 1 to Form S-4 filed June 21, 2002)

10.2* Amendment No. 1 dated April 25, 2002 to $600
million Long-term Revolving Credit Agreement
(incorporated by reference to Exhibit 10.19 to
Amendment No. 1 to Form S-4 filed June 21, 2002)

10.3* Amendment No. 1 dated April 25, 2002 to Canadian
Credit Agreement (incorporated by reference to
Exhibit 10.32 to Amendment No. 1 to Form S-4 filed
June 21, 2002)

10.4* Burlington Resources Inc. 2002 Stock Incentive
Plan (incorporated by reference to Exhibit A to
Schedule 14A filed March 15, 2002)

10.5* Form of agreement on pension related benefits with
certain former Seattle holding company office
employees, including L. David Hanower
(incorporated by reference to Exhibit 10.26 to
Form 10-K, filed March 17, 2000)

* Exhibit incorporated by reference.

B. Reports on Form 8-K

The Company filed no reports on Form 8-K during the second
quarter of 2002.

Items 2, 3 and 5 of Part II are not applicable and have been omitted.

23

SIGNATURES

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

BURLINGTON RESOURCES INC.
----------------------------------
(Registrant)

By /s/ STEVEN J. SHAPIRO
-------------------------------
Steven J. Shapiro
Senior Vice President and
Chief Financial Officer

By /s/ JOSEPH P. McCOY
-------------------------------
Joseph P. McCoy
Vice President, Controller and
Chief Accounting Officer

Date: August 9, 2002

24

Certification Accompanying Periodic Report
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(18 U.S.C. Section 1350)

The undersigned, Bobby S. Shackouls, Chairman of the Board,
President and Chief Executive Officer of Burlington Resources Inc. ("Company"),
and Steven J. Shapiro, Senior Vice President and Chief Financial Officer of the
Company, each hereby certifies that the Quarterly Report of the Company on Form
10-Q for the period ended June 30, 2002 (the "Report") (1) fully complies with
the requirements of Section 13(a) of the Securities Exchange Act of 1934 and (2)
the information contained in the Report fairly presents, in all material
respects, the financial condition and the results of operations of the Company.

/s/ BOBBY S. SHACKOULS
-------------------------------------
Dated: August 9, 2002 Bobby S. Shackouls
Chairman of the Board,
President and
Chief Executive Officer

/s/ STEVEN J. SHAPIRO
-------------------------------------
Dated: August 9, 2002 Steven J. Shapiro
Senior Vice President and
Chief Financial Officer