BURLINGTON RESOURCES INC - 10-Q Quarterly Report

Back to GetFilings.com

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 September 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.

Class Outstanding
----- -----------

Common Stock, par value $.01 per share,
as of September 30, 2002 201,332,800

PART I - FINANCIAL INFORMATION

ITEM 1. Financial Statements

BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF INCOME
(UNAUDITED)

THIRD QUARTER NINE MONTHS
---------------------------- ----------------------------
2002 2001 2002 2001
----------- ----------- ----------- -----------
(In Millions, Except per Share Amounts)

Revenues......................................................... $ 630 $ 666 $ 2,082 $ 2,746
----------- ----------- ----------- -----------

Costs and Other Income
Taxes Other than Income Taxes.................................. 29 26 92 140
Transportation Expense......................................... 79 75 216 222
Production and Processing...................................... 117 126 365 364
Depreciation, Depletion and Amortization....................... 192 183 625 527
Exploration Costs.............................................. 53 79 214 201
Administrative................................................. 36 34 113 113
Interest Expense............................................... 65 41 207 132
(Gain)/Loss on Disposal of Assets.............................. 6 1 (67) (1)
Other Expense (Income) - Net................................... (14) (5) (18) 5
----------- ----------- ----------- -----------
Total Costs and Other Income..................................... 563 560 1,747 1,703

Income Before Income Taxes....................................... 67 106 335 1,043
Income Tax Expense (Benefit)..................................... (12) 33 38 406
----------- ----------- ----------- -----------
Net Income Before Cumulative Effect of Change in Accounting
Principle..................................................... 79 73 297 637
Cumulative Effect of Change in Accounting Principle - Net........ - - - 3
----------- ----------- ----------- -----------

Net Income....................................................... $ 79 $ 73 $ 297 $ 640
=========== =========== =========== ===========

Earnings per Common Share

Basic
Before Cumulative Effect of Change in Accounting Principle..... $ 0.39 $ 0.36 $ 1.47 $ 3.05
Cumulative Effect of Change in Accounting Principle - Net...... - - - 0.01
----------- ----------- ----------- -----------
Net Income..................................................... $ 0.39 $ 0.36 $ 1.47 $ 3.06
=========== =========== =========== ===========

Diluted
Before Cumulative Effect of Change in Accounting Principle..... $ 0.39 $ 0.36 $ 1.47 $ 3.04
Cumulative Effect of Change in Accounting Principle - Net...... - - - 0.01
----------- ----------- ----------- -----------
Net Income..................................................... $ 0.39 $ 0.36 $ 1.47 $ 3.05
=========== =========== =========== ===========

See accompanying Notes to Consolidated Financial Statements.

2

BURLINGTON RESOURCES INC.
CONSOLIDATED BALANCE SHEET
(UNAUDITED)

September 30, December 31,
2002 2001
------------------ -------------------
(In Millions, Except Share Data)
ASSETS

Current Assets
Cash and Cash Equivalents..................................... $ 344 $ 116
Accounts Receivable........................................... 347 398
Commodity Hedging Contracts and Other Derivatives............. 7 118
Inventories................................................... 56 50
Other Current Assets.......................................... 43 33
------------------ -------------------
797 715
------------------ -------------------

Oil & Gas Properties (Successful Efforts Method)................. 15,176 16,038
Other Properties................................................. 1,147 1,416
------------------ -------------------
16,323 17,454
Accumulated Depreciation, Depletion and Amortization........... 7,730 8,623
------------------ -------------------
Properties - Net............................................. .8,593 8,831
------------------ -------------------
Goodwill......................................................... 800 782
------------------ -------------------
Other Assets..................................................... 222 254
------------------ -------------------
Total Assets............................................... $ 10,412 $ 10,582
================== ===================

LIABILITIES
Current Liabilities
Accounts Payable............................................... $ 647 $ 599
Taxes Payable.................................................. . 122 6
Accrued Interest............................................... 64 61
Dividends Payable.............................................. 27 28
Other Current Liabilities...................................... 23 17
------------------ -------------------
883 711
------------------ -------------------
Long-term Debt................................................... 3,914 4,337
------------------ -------------------
Deferred Income Taxes............................................ 1,331 1,403
------------------ -------------------
Commodity Hedging Contracts and Other Derivatives................ 33 15
------------------ -------------------
Other Liabilities and Deferred Credits........................... 548 591
------------------ -------------------

Commitments and Contingent Liabilities

STOCKHOLDERS' EQUITY
Preferred Stock, Par Value $.01 per Share
(Authorized 75,000,000 Shares; One Share Issued)............... - -
Common Stock, Par Value $.01 per Share
(Authorized 325,000,000 Shares; Issued 241,188,688 Shares)..... 2 2
Paid-in Capital.................................................. 3,941 3,944
Retained Earnings................................................ 1,546 1,332
Deferred Compensation - Restricted Stock......................... (11) (9)
Accumulated Other Comprehensive Loss............................. (158) (106)
Cost of Treasury Stock
(39,855,888 and 40,395,695 Shares for 2002 and 2001,
respectively)................................................... (1,617) (1,638)
------------------ -------------------
Stockholders' Equity............................................. 3,703 3,525
------------------ -------------------
Total Liabilities and Stockholders' Equity................. $ 10,412 $ 10,582
================== ===================

See accompanying Notes to Consolidated Financial Statements.

3

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

NINE MONTHS
----------------------------------
2002 2001
-------------- --------------
(In Millions)

CASH FLOWS FROM OPERATING ACTIVITIES
Net Income.................................................................. $ 297 $ 640
Adjustments to Reconcile Net Income to Net Cash
Provided By Operating Activities
Depreciation, Depletion and Amortization.................................. 625 527
Deferred Income Taxes..................................................... (67) 316
Exploration Costs......................................................... 214 201
Gains on Sale of Assets................................................... (67) (1)
Changes in Derivative Fair Values......................................... 32 (47)
Working Capital Changes
Accounts Receivable....................................................... 51 396
Inventories............................................................... (6) (1)
Other Current Assets...................................................... (9) (5)
Accounts Payable.......................................................... 19 (158)
Taxes Payable............................................................. 117 3
Accrued Interest.......................................................... 8 5
Other Current Liabilities................................................. (9) (9)
Changes in Other Assets and Liabilities..................................... (32) (40)
-------------- --------------
Net Cash Provided By Operating Activities............................... 1,173 1,827
-------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Properties..................................................... (1,496) (964)
Proceeds from Sales and Other............................................... 1,055 10
-------------- --------------
Net Cash Used In Investing Activities................................... (441) (954)
-------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Borrowings.................................................... 454 400
Reduction in Borrowings..................................................... (879) (309)
Dividends Paid.............................................................. (84) (88)
Common Stock Purchases...................................................... - (684)
Common Stock Issuances...................................................... 9 42
Other....................................................................... 3 (7)
-------------- --------------
Net Cash Used In Financing Activities................................... . (497) (646)
-------------- --------------
Effect of Exchange Rate Changes on Cash and Cash Equivalents.................. (7) -

INCREASE IN CASH AND CASH EQUIVALENTS......................................... 228 227

CASH AND CASH EQUIVALENTS
Beginning of Year........................................................... 116 132
-------------- --------------
End of Period............................................................... $ 344 $ 359
============== ==============

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 three entities that it accounts for under the equity method,
Lost Creek Gathering Company (Lost Creek), CLAM Petroleum B.V. (CLAM) and
Evangeline Gas Pipeline Company (Evangeline). As of September 30, 2002, CLAM had
no outstanding debt, Lost Creek had outstanding debt totaling $53 million and
Evangeline had outstanding debt totaling $43 million. Lost Creek and
Evangeline's debts are non-recourse to the Company, and as a result, the Company
has no legal responsibility or obligation for these debts. Management believes
that Lost Creek and Evangeline are financially stable and therefore will be in a
position to repay their outstanding debts.

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 204 million for the
third quarter of 2002 and 2001, respectively, and 201 million and 209 million
for the first nine 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 205 million for the third quarter of
2002 and 2001, respectively, and 202 million and 210 million for the first nine
months of 2002 and 2001, respectively. For the third quarter of 2002 and 2001
and nine months ended September 30, 2002 and September 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.

5

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 various marketing locations of the Company. The Company
also enters into natural gas and crude oil option 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.

6

As of September 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 September 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 $6 million asset offset by a $6
million liability basis adjustment to the carrying value of the fixed-price gas
sales contracts. These agreements extend through 2005.

7

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 September 30,
2002. Hedging activities increased natural gas and crude oil revenues by $113
million and $3 million, respectively, during the first nine months of 2002. In
addition, during the first nine months of 2002, non-cash losses of $21 million
and $11 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, respectively. Derivative
instruments designated as cash-flow hedges are used by the Company to mitigate
the risk of variability in cash flows from crude oil and natural gas sales due
to changes in market prices. Examples of such derivatives instruments include
fixed price swaps, fixed price swaps combined with basis swaps, purchased put
options, costless collars (purchased put options and written call options) and
producer three-ways (purchased put spreads and written call options). These
derivative instruments either fix the price the Company receives for its
production or in the case of option contracts, set a minimum price or a price
within a fixed range. 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. For example, the Company
periodically enters into contracts whereby it commits to deliver to a customer a
specified quantity of crude oil or natural gas at a fixed price over a specified
period of time. In order to hedge against changes in the fair value of these
commitments, the Company enters into swap agreements with financial
counterparties that allow the Company to receive market prices for the
committed specified quantities included in the physical contract.

In addition to commodity price hedges, a Canadian subsidiary of the
Company makes limited use of foreign currency swaps as cash flow hedges of
anticipated sales denominated in U.S. dollars with contracts extending through
2004. As of September 30, 2002, the fair value related to these hedges was a
liability of $3 million. The Company also has foreign currency swaps that, prior
to September 1, 2002, were collectively designated as a hedge of Canadian Hunter
Exploration Ltd.'s (Hunter) net investment in a U.S. dollar denominated foreign
subsidiary with contracts that mature in 2005. During September 2002, the
foreign entity that was the subject of the hedge was transferred to a U.S.
subsidiary of the Company and the swaps were de-designated as a hedge. At
September 30, 2002, the fair value of the swaps was a liability of $8 million.

Based on commodity prices and foreign exchange rates as of September
30, 2002, the Company expects to reclassify gains of $10 million ($6 million
after tax) to earnings from the balance in accumulated other comprehensive
income during the next twelve months. As of September 30, 2002, the Company had
cash-flow hedge derivative assets of $4 million and derivative liabilities of
$33 million. The Company also had liabilities and assets related to fair-value
hedges of $6 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 for pre-trial proceedings by the
United States Judicial Panel on Multidistrict Litigation in the matter of In re
Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court
for the District of Wyoming (MDL-1293). The plaintiffs contend that defendants
underpaid royalties on natural gas and NGLs produced on federal and Indian lands
through the use of below-market prices, improper deductions, improper
measurement techniques and transactions with affiliated companies during the
period of 1985 to the present. Plaintiffs allege that the royalties paid by
defendants were lower than the royalties required to be paid under

8

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. The Company is also exploring the possibility
of a settlement of these claims. Although there has been no formal demand for
damages, the Company currently estimates, based on its communications with the
intervenor, that the amount of underpaid royalties on onshore production claimed
by the intervenor in these proceedings is approximately $68 million. In the
event that the Company is found to have violated the civil False Claims Act, the
Company could also be subject to double damages, civil monetary penalties and
other sanctions, including a temporary suspension from bidding on and entering
into future federal mineral leases and other federal contracts for a defined
period of time. The Company has established a reserve that management believes
to be adequate to provide for this potential liability based upon its evaluation
of this matter. In the event of adverse changes in circumstances, potential
liability may exceed the amounts accrued. 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

9

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. Accordingly, there
has been no reserve established for this matter.

The Company received notice in 1997 from the United States
Environmental Protection Agency (EPA) that it was one of many Potentially
Responsible Parties (PRP) under the Comprehensive Environmental Response,
Compensation and Liability Act, as amended, with respect to the Commencement Bay
Nearshore/Tideflats National Priorities List Site. The site, located in the
Puget Sound near Tacoma, Washington, consists of 10-12 square miles of shallow
water, shoreline and adjacent land, most of which is developed and
industrialized. The EPA determined that marine sediments had become contaminated
from many years of diverse industrial activities. The Company and Burlington
Northern Inc. previously owned land adjacent to the Thea Foss Waterway, which
the EPA considered as a potential source of the contamination. On September 23,
2002, the Company completed the settlement of all claims through the payment of
$587,621 from a reserve that was previously established for this matter.

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

5. DEBT

In February 2002, Burlington Resources Finance Company (BRFC) issued
$350 million of 5.7% Notes due March 1, 2007, which were fully and
unconditionally guaranteed by BR. 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 for $104 million was retired on September
16, 2002. During the first nine months of 2002, the Company also retired $675
million of net commercial paper and has no commercial paper outstanding at
September 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.

10

The fair value of the Company's long-term debt at September 30, 2002
and December 31, 2001, excluding commercial paper, was approximately $4,443
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. In August 2002, the Company purchased certain oil
and gas properties located in Wise and Denton Counties, Texas for approximately
$140 million. In October 2002, the Company also provided notice in accordance
with prior agreements that it intends to exercise its option to purchase
additional oil and gas reserves in the western U.S. during 2003 for
approximately $100 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 Gulf of Mexico Shelf Trend and south and
east Texas assets are included in the non-core, non-strategic properties. During
the second and third quarters 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
$1,063 million and recognized a net pretax gain of $67 million. The net pretax
gain includes an estimated pretax loss of $65 million associated with a purchase
and sale agreement that was signed but the transaction not closed as of
September 30, 2002. In October 2002, the Company signed a purchase and sale
agreement to sell certain non-core, non-strategic properties in the
Mid-Continent area. The net book value of the properties held for sale at
September 30, 2002, including those identified in October 2002, was $165
million. The producing properties sold and currently held for sale generated
$167 million and $321 million of revenues and incurred $126 million and $243
million of direct operating expenses during the first nine months of 2002 and
2001, respectively. The Company intends to complete the remaining property sales
by year-end 2002. There is minimal income statement effect expected during the
fourth quarter of 2002 related to the remaining sales. The Company has and
expects to use a portion of the proceeds generated from property sales to retire
commercial paper, to repay the promissory note for $104 million and for general
corporate purposes, including future funding of a portion of the Company's
capital program.

In connection with the divestiture program, the Company also recorded
restructuring liabilities of $10 million in the fourth quarter of 2001. As of
September 30, 2002, approximately $409 thousand of the restructuring liabilities
remained outstanding as Accounts Payable on the Consolidated Balance Sheet.

7. INCOME TAXES

The Company's effective income tax rate decreased to 11 percent at
September 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 and the reversal of a tax valuation reserve of $27 million
in September 2002 related to the sale of assets in the U.K. sector of the North
Sea.

11

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
for and the 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 $2 million and $19 million during the third
quarter of 2002 and 2001, respectively, and were $17 million and $143 million
during the first nine months of 2002 and 2001, respectively.

The following tables present information about reported segment
operations.

9. ACCOUNTING PRONOUNCEMENTS

In June 2002, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 146, Accounting for Costs
Associated with Exit or Disposal Activities (SFAS No. 146). SFAS No. 146
addresses financial accounting and reporting for costs associated with exit or
disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS
No. 146 requires that a liability for a cost associated with an exit or disposal
activity be recognized when the liability is incurred and establishes that fair
value is the objective for initial measurement of the liability. The provisions
of SFAS No. 146 are effective for exit or disposal activities that are initiated
after December 31, 2002. The Company expects to adopt SFAS No. 146 on January 1,
2003, but at this time does not anticipate that this statement will have any
effect on its consolidated financial position or results of operations.

In April 2002, the 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

12

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 expects to adopt SFAS No. 145 on
January 1, 2003, but at this time does not anticipate that this statement will
have any effect on its consolidated financial position or results of operations.

In June 2001, the FASB issued Statement of Financial Accounting
Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143).
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. Based on current estimates, the Company expects
to record a net-of-tax cumulative effect of change in accounting principle loss,
in the first quarter of 2003, of approximately $50 million to $65 million in
accordance with the provisions of SFAS No. 143. There will be no impact on the
Company's cash flows as a result of adopting SFAS No. 143.

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 $800 million at September 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, 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.

13

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.

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

Outlook

During the fourth quarter of 2002, the Company expects average
production volumes to range between 2,260 and 2,488 MMCFE per day. The Company
expects full year production volumes to average between 2,484 and 2,579 MMCFE.
Although the Company experienced production declines as a result of property
sales, natural declines and annual plant and pipeline maintenance that extended
into the third quarter of 2002, the Company expects 2002 full year production
volumes to exceed full year 2001 volumes primarily due to acquisitions in Canada
in late 2001 and early 2002, additional production volumes in Madden Field and
the acceleration of winter drilling activity in Canada during the fourth quarter
of 2002. The Lost Cabin Gas Plant expansion in Madden Field was completed during
the third quarter of 2002. As a result, in 2003 upon the completion of a well
which is currently being drilled, the Company's future deep Madison gas sales in
the area is expected to increase to a maximum of 85 MMCF of gas per day from the
current level of approximately 35 MMCF of gas per day.

Commodity prices are impacted by many factors that are outside of the
Company's control. Historically, commodity prices have been volatile and the
Company expects them to remain volatile. Commodity prices are affected by
changes in market demands, economic

14

climate, weather, pipeline capacity constraints, inventory storage levels, basis
differentials and other factors. As a result, the Company cannot accurately
predict future natural gas, NGL and crude oil prices, and therefore, it cannot
determine what effect increases or decreases in 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 all of
2002, the Company plans to spend $1.3 billion on development, exploration and
plants and pipeline capital and an additional $600 million on acquisitions. The
Company expects its reserve replacement costs from internal sources, which
exclude acquisitions, to range between $1.10 and $1.25 per MCFE for 2002. The
Company also expects to replace its production from internal sources during
2002.

On June 30, 2002, the Company sold the Val Verde gathering and
processing plant (Val Verde Plant), which contributed $19 million in third party
revenues in 2002. As a result of the sale, in addition to the future revenue
loss, the Company expects its transportation expenses to increase approximately
$40 million annually offset partially by lower operating expenses of
approximately $11 million and lower DD&A of approximately $9 million. The
Company has certain oil and gas wells that qualify for Section 29 Tax Credits.
In 2002, the Company generated $17 million of Section 29 Tax Credits. Production
from qualified wells will cease to generate Section 29 Tax Credits at the end of
2002.

Financial Condition and Liquidity

The Company's long-term debt to total capital (total capital is defined
as total debt and stockholders' equity) ratio at September 30, 2002 and December
31, 2001 was 51 percent and 55 percent, respectively. The reduction in long-term
debt to total capital was accomplished by the use of proceeds from 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 commodity 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), which were fully
and unconditionally guaranteed by BR. 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 May 2002, the Company restored its shelf registration statement
to $1,500 million. At September 30, 2002, the Company had $344 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 for $104 million was retired on September 16, 2002. During the
first nine months of 2002, the Company also retired $675 million of net
commercial paper and has no commercial paper outstanding at September 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),

15

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 Company had credit commitments in the form of revolving credit
facilities (revolvers) as of September 30, 2002. The revolvers, which are
comprised of agreements for $600 million, $400 million and approximately
Canadian $471 million (U.S. $297 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 any
remaining 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 nine months
of 2002 was $1,173 million compared to $1,827 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, crude oil and NGL prices and lower
crude oil sales volumes partially offset by higher natural gas and NGL sales
volumes.

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 nine months of 2002 totaled $1,430
million compared to $985 million in 2001. The Company invested $669 million on
internal development and exploration of oil and gas properties during the first
nine months of 2002 compared to $735 million in 2001. The increase in capital
expenditures in 2002 are primarily due to property acquisitions where the
Company invested $596 million in the first nine months of 2002 compared to $143
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. Property acquisitions also include
approximately $140 million for the purchase of certain oil and gas properties
located in Wise and Denton Counties, Texas in August 2002. 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.

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

16

growth opportunities, substantially all of the Gulf of Mexico Shelf Trend
(Shelf) and south and east Texas assets are included in the non-core,
non-strategic properties. During the second and third quarters of 2002, the
Company sold certain non-core, non-strategic properties, including the Val Verde
Plant, and generated proceeds, before post closing adjustments, of approximately
$1,063 million and recognized a net pretax gain of $67 million. The net pretax
gain includes an estimated pretax loss of $65 million associated with a purchase
and sale agreement that was signed but the transaction not closed as of
September 30, 2002. In October 2002, the Company signed a purchase and sale
agreement to sell certain non-core, non-strategic properties in the
Mid-Continent area. The net book value of the properties held for sale at
September 30, 2002, including those identified in October 2002, was $165
million. The producing properties sold and currently held for sale generated
$167 million and $321 million of revenues and incurred $126 million and $243
million of direct operating expenses during the first nine months of 2002 and
2001, respectively. The Company intends to complete the remaining property sales
by year-end 2002. There is minimal income statement effect expected during the
fourth quarter of 2002 related to the remaining sales. The Company has and
expects to use a portion of the proceeds generated from property sales to retire
commercial paper, to repay the promissory note for $104 million and for general
corporate purposes, including future funding of a portion of the Company's
capital program.

In connection with the divestiture program, the Company also recorded
restructuring liabilities of $10 million in the fourth quarter of 2001. As of
September 30, 2002, approximately $409 thousand of the restructuring liabilities
remained outstanding as Accounts Payable on the Consolidated Balance Sheet.

Dividends

On October 16, 2002, the Board of Directors declared a quarterly common
stock cash dividend of $0.1375 per share, with record and payment dates of
December 6, 2002 and January 2, 2003, respectively.

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

The Company reported net income of $79 million or $0.39 diluted
earnings per common share in third quarter 2002 compared to net income of $73
million or $0.36 diluted earnings per common share in third quarter 2001. Net
income in third quarter 2002 included a net after tax loss of $4 million or
$0.02 per diluted share related to the disposal of assets and the reversal of a
tax valuation reserve of $27 million or $0.13 per diluted share in September
2002 related to the sale of assets in the U.K. sector of the North Sea. Net
income in third quarter 2002 also included an after tax loss of $3 million and
$1 million compared to an after tax gain of $3 million and $4 million in third
quarter 2001, 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, respectively. Derivative instruments designated as
cash-flow hedges are used by the Company to mitigate the risk of variability in
cash flows from crude oil and natural gas sales due to changes in market prices.
Examples of such derivatives instruments include fixed price swaps, fixed price
swaps combined with basis swaps, purchased put options, costless collars
(purchased put options and written call options) and producer three-ways
(purchased put spreads and written call options). These derivative instruments
either fix the price the Company receives for its production or in the case of
option contracts, set a minimum price or a price within a fixed range. 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. For example, the Company periodically enters into contracts whereby
it commits to deliver to a customer a

17

specified quantity of crude oil or natural gas at a fixed price over a specified
period of time. In order to hedge against changes in the fair value of these
commitments, the Company enters into swap agreements with financial
counterparties that allow the Company to receive market prices for the committed
specified quantities included in the physical contract.

Revenues

Revenues decreased $36 million to $630 million in third quarter 2002
compared to $666 million in third quarter 2001. The $36 million decrease in
revenues primarily consists of $34 million related to lower commodity prices, $9
million and $8 million due to lower revenues related to ineffectiveness on
cash-flow and fair-value hedges and changes in the fair value of derivative
instruments that do not qualify for hedge accounting, respectively, and $10
million due to the sale of the Val Verde Plant in the second quarter of 2002
partially offset by $26 million related to higher production volumes. Details of
commodity prices and sales volumes variances are described below.

Price variances

Average gas prices, including an $0.11 realized gain per MCF related
to hedging activities, decreased $0.24 per MCF in third quarter 2002 to $2.65
per MCF from $2.89 per MCF in third quarter 2001 which decreased revenues $41
million during third quarter 2002. Also imbedded in the average gas prices
during third quarter 2002 was the impact of weaker than normal location basis
differentials primarily at the AECO hub and the Rocky Mountain region of the
U.S. Average NGL prices decreased $0.24 per barrel in third quarter 2002 to
$15.22 per barrel from $15.46 per barrel in third quarter 2001, resulting in
reduced revenues of $1 million during third quarter 2002. Average oil prices
increased $2.09 per barrel in third quarter 2002 to $25.90 per barrel from
$23.81 per barrel in third quarter 2001 resulting in increased revenues of $8
million during third quarter 2002. There were no hedging gains or losses related
to oil volumes during third quarter 2002.

Volume variances

Average gas sales volumes increased 167 MMCF per day in third quarter
2002 to 1,839 MMCF per day from 1,672 MMCF per day in third quarter 2001
resulting in increased revenues of $44 million during third quarter 2002.
Average NGL sales volumes increased 12.8 MBbls per day in third quarter 2002 to
59.6 MBbls per day from 46.8 MBbls per day in third quarter 2001, resulting in
higher revenues of $18 million from quarter to quarter. Average oil sales
volumes decreased 16.5 MBbls per day in third quarter 2002 to 44.7 MBbls per day
from 61.2 MBbls per day in third quarter 2001 reducing revenues $36 million
during third quarter 2002. Average gas sales volumes in Canada and Other
International increased 393 MMCF per day primarily due to the acquisition of
Canadian Hunter Exploration Ltd. (Hunter) in late 2001 partially offset by asset
sales and natural declines of 234 MMCF per day in Mid-Continent, Gulf Coast,
Canada, San Juan and Other International areas. Average NGL sales volumes in
Canada increased 13.7 MBbls per day primarily due to the acquisition of Hunter.
Average oil sales volumes decreased 17.4 MBbls per day primarily due to asset
sales and natural declines in the Gulf of Mexico, Mid-Continent, Canada and
Other International areas.

Total Costs and Other Income

Total costs and other income were $563 million in third quarter 2002
compared to $560 million in third quarter 2001. The $3 million increase was
primarily due to a $24 million increase

18

in interest expense, a $9 million increase in depreciation, depletion and
amortization (DD&A), a $5 million higher loss on disposal of assets, a $4
million increase in transportation expenses, a $3 million increase in taxes
other than income taxes and a $2 million increase in general and administrative
(G&A) expenses partially offset by a $26 million decrease in exploration costs,
a $9 million decrease in production and processing expenses and a $9 million
increase in other income.

Interest expense increased primarily due to higher debt balances during
third quarter 2002 resulting from the Hunter acquisition in late 2001 and other
property acquisitions consummated in early 2002. 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. Transportation expenses increased primarily due to
higher contract rates primarily resulting from the sale of the Val Verde Plant.
Taxes other than income taxes increased primarily due to higher miscellaneous
taxes partially offset by lower production taxes resulting from lower oil and
gas revenues. Exploration costs decreased primarily due to lower drilling rig
expenses of $21 million, lower exploratory dry hole costs of $17 million and
lower geological and geophysical (G&G) and other expenses of $1 million
partially offset by higher amortization of undeveloped lease costs of $13
million. 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. Other income increased primarily due to higher foreign
currency transactions and higher interest income.

Income Tax Expense

Income taxes were a benefit of $12 million in third quarter 2002
compared to an expense of $33 million in third quarter 2001. The Company
recorded tax benefits of $18 million in third quarter 2002 compared to $7
million in third 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 $5 million in third quarter 2002 compared to $4 million in third quarter
2001. Third quarter 2002 also included the reversal of a tax valuation reserve
of $27 million in September 2002 related to the sale of assets in the U.K.
sector of the North Sea.

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

The Company reported net income of $297 million or $1.47 diluted
earnings per common share in the first nine months of 2002 compared to net
income of $640 million or $3.05 diluted earnings per common share in the first
nine months of 2001. Net income in the first nine months of 2002 included a net
after tax gain of $42 million or $0.20 per diluted share related to the disposal
of assets and the reversal of a valuation reserve of $27 million or $0.13 per
diluted share in September 2002 related to the sale of assets in the U.K. sector
of the North Sea. Net income in the first nine months of 2002 also included an
after tax loss of $13 million and $7 million compared to an after tax gain of
$12 million and $13 million in the first nine months of 2001, 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,
respectively. Net income in the first nine months of 2001 also included an after
tax gain of $3 million or $0.01 per diluted share related to the cumulative
effect of change in accounting principle resulting from the adoption of SFAS No.
133.

19

Revenues

Revenues decreased $664 million to $2,082 million in the first nine
months of 2002 compared to $2,746 million in the first nine months of 2001. The
$664 million decrease in revenues primarily consists of $866 million related to
lower commodity prices, $40 million and $33 million due to lower revenues
related to ineffectiveness on cash-flow and fair-value hedges and changes in the
fair value of derivative instruments that do not qualify for hedge accounting,
respectively, and $10 million due to the sale of the Val Verde Plant in the
second quarter of 2002 partially offset by $285 million related to higher
production volumes. Details of commodity prices and sales volumes variances are
described below.

Price variances

Average gas prices, including a $0.21 realized gain per MCF related to
hedging activities, decreased $1.47 per MCF in the first nine months of 2002 to
$2.89 per MCF from $4.36 per MCF in the first nine months of 2001 which
decreased revenues $771 million during the first nine months of 2002. Also
imbedded in the average gas prices during the first nine months of 2002 was the
impact of location basis differentials that varied widely compared to the same
period in 2001 primarily in the western U.S. and western Canada. Average NGL
prices decreased $5.10 per barrel in the first nine months of 2002 to $13.88 per
barrel from $18.98 per barrel in the first nine months of 2001, resulting in
reduced revenues of $84 million during the first nine months of 2002. Average
oil prices, including a $0.22 realized gain per barrel related to hedging
activities, decreased $0.77 per barrel in the first nine months of 2002 to
$23.90 per barrel from $24.67 per barrel in the first nine months of 2001
resulting in reduced revenues of $11 million during the first nine months of
2002.

Volume variances

Average gas sales volumes increased 235 MMCF per day in the first
nine months of 2002 to 1,927 MMCF per day from 1,692 MMCF per day in the first
nine months of 2001 resulting in increased revenues of $279 million during the
first nine months of 2002. Average NGL sales volumes increased 15.4 MBbls per
day in the first nine months of 2002 to 60.3 MBbls per day from 44.9 MBbls per
day in the first nine months of 2001, resulting in higher revenues of $80
million during the first nine months of 2002. Average oil sales volumes
decreased 11.0 MBbls per day in the first nine months of 2002 to 53.1 MBbls per
day from 64.1 MBbls per day in the first nine months of 2001 reducing revenues
$74 million during the first nine months of 2002. Average gas sales volumes in
Canada and Other International areas increased 414 MMCF per day primarily due to
the acquisition of Hunter in late 2001 partially offset by natural declines and
asset sales of 179 MMCF per day in Onshore Gulf Coast, Shelf, San Juan and
Mid-Continent. Average NGL sales volumes in Canada also increased 16.6 MBbls per
day primarily due to the acquisition of Hunter. Average oil sales volumes
decreased 9.7 MBbls per day primarily due to natural declines and asset sales in
the Gulf of Mexico, Canada and Mid-Continent.

20

Total Costs and Other Income

Total costs and other income were $1,747 million in the first nine
months of 2002 compared to $1,703 million in the first nine months of 2001. The
$44 million increase was primarily due to a $98 million increase in DD&A, a $75
million increase in interest expense, a $13 million increase in exploration
costs and a $1 million increase in production and processing expenses partially
offset by a $66 million increase in gain on disposal of assets, a $48 million
decrease in taxes other than income taxes, a $23 million increase in other
income and a $6 million decrease in transportation 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 nine 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 amortization of undeveloped lease costs of $44 million, higher
drilling rig costs of $17 million, and higher G&G and other expenses of $12
million partially offset by lower exploratory dry hole costs of $60 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. 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.

Income tax Expense

Income taxes were an expense of $38 million in the first nine months of
2002 compared to $406 million in the first nine months of 2001. The decrease in
tax expense was primarily due to lower pretax income. The Company also recorded
benefits of $73 million in the first nine months of 2002 compared to $13 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 $17 million
during the first nine months of 2002 and 2001. The first nine months also
included the reversal of a tax valuation reserve of $27 million in September
2002 related to the sale of assets in the U.K. sector of the North Sea.

Accounting Pronouncements

In June 2002, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 146, Accounting for Costs
Associated with Exit or Disposal Activities (SFAS No. 146). SFAS No. 146
addresses financial accounting and reporting for costs associated with exit or
disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS
No. 146 requires that a liability for a cost associated with an exit or disposal
activity be recognized when the liability is incurred and establishes that fair
value is the objective for initial measurement of the liability. The provisions
of SFAS No. 146 are effective for exit or disposal activities that are initiated
after December 31, 2002. The Company expects to adopt SFAS No. 146 on January 1,
2003, but at this time does not anticipate that this statement will have any
effect on its consolidated financial position or results of operations.

21

In April 2002, the 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
expects to adopt SFAS No. 145 on January 1, 2003, but at this time does not
anticipate that this statement will have any effect on its consolidated
financial position or results of operations.

In June 2001, the FASB issued Statement of Financial Accounting
Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143).
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. Based on current estimates, the Company expects
to record a net-of-tax cumulative effect of change in accounting principle loss,
in the first quarter of 2003, of approximately $50 million to $65 million in
accordance with the provisions of SFAS No. 143. There will be no impact on the
Company's cash flows as a result of adopting SFAS No. 143.

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). Location and quality
differentials, worldwide political developments and the actions of the
Organization of Petroleum Exporting Countries also affect crude oil prices.

The difference between the NYMEX futures contract price for a
particular month and the actual cash price received for that month in a North
American producing basin or at a North American market hub 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 some 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 September 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 $69 million increase in the
fair value of the net liabilities related to commodity hedging activities.

22

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 September
30, 2002, the Company expects to reclassify gains of $10 million ($6 million
after tax) to earnings from the balance in accumulated other comprehensive
income during the next twelve months. As of September 30, 2002, the Company had
cash-flow hedge derivative assets of $4 million and derivative liabilities of
$33 million. The Company also had liabilities and assets related to fair-value
hedges of $6 million and $7 million, respectively.

ITEM 4. Controls and Procedures

Within 90 days prior to the date of this report, under the supervision
and with the participation of certain members of the Company's management,
including the Chief Executive Officer and Chief Financial Officer, the Company
completed an evaluation of the effectiveness of the design and operation of its
disclosure controls and procedures (as defined in Rules 13a-14(c) and 15d-14(c)
to the Securities Exchange Act of 1934, as amended). Based on this evaluation,
the Company's Chief Executive Officer and Chief Financial Officer believe that
the disclosure controls and procedures are effective with respect to timely
communicating to them and other members of management responsible for preparing
periodic reports all material information required to be disclosed in this
report as it relates to the Company and its consolidated subsidiaries.

There were no significant changes in the Company's internal controls or
other factors that could significantly affect internal controls subsequent to
the date of the most recently completed evaluation.

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 for pre-trial proceedings by the
United States Judicial Panel on Multidistrict Litigation in the matter of In re
Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court
for the District of Wyoming (MDL-1293). The plaintiffs contend that defendants
underpaid royalties on natural gas and NGLs produced on federal and Indian lands
through the use of below-market prices, improper deductions, improper
measurement techniques

23

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. The Company is also exploring the possibility
of a settlement of these claims. Although there has been no formal demand for
damages, the Company currently estimates, based on its communications with the
intervenor, that the amount of underpaid royalties on onshore production claimed
by the intervenor in these proceedings is approximately $68 million. In the
event that the Company is found to have violated the civil False Claims Act, the
Company could also be subject to double damages, civil monetary penalties and
other sanctions, including a temporary suspension from bidding on and entering
into future federal mineral leases and other federal contracts for a defined
period of time. The Company has established a reserve that management believes
to be adequate to provide for this potential liability based upon its evaluation
of this matter. In the event of adverse changes in circumstances, potential
liability may exceed the amounts accrued. 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

24

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. Accordingly, there has been no reserve established for this
matter.

The Company received notice in 1997 from the United States
Environmental Protection Agency (EPA) that it was one of many Potentially
Responsible Parties (PRP) under the Comprehensive Environmental Response,
Compensation and Liability Act, as amended, with respect to the Commencement Bay
Nearshore/Tideflats National Priorities List Site. The site, located in the
Puget Sound near Tacoma, Washington, consists of 10-12 square miles of shallow
water, shoreline and adjacent land, most of which is developed and
industrialized. The EPA determined that marine sediments had become contaminated
from many years of diverse industrial activities. The Company and Burlington
Northern Inc. previously owned land adjacent to the Thea Foss Waterway, which
the EPA considered as a potential source of the contamination. On September 23,
2002, the Company completed the settlement of all claims through the payment of
$587,621 from a reserve that was previously established for this matter.

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

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* Letter Agreement regarding Steven J. Shapiro
dated October 18, 2000 related to supplemental
pension benefits in connection with employment
(incorporated by reference to Exhibit 10.29 to
Form 10-K, filed February 2001)

* Exhibit incorporated by reference.

25

B. Reports on Form 8-K

On August 12, 2002, the Company filed Form 8-K in connection with the
Company's Chief Executive Officer and Chief Financial Officer each filing with
the Securities and Exchange Commission (the "SEC") a statement under oath
regarding facts and circumstances relating to the Securities Exchange Act
filings of the Company, as required by the SEC's Order Requiring the Filing of
Sworn Statements Pursuant to Section 21(a)(1) of the Securities Exchange Act of
1934 (File No. 4-460, June 27, 2002).

Items 2, 3, 4 and 5 of Part II are not applicable and have been
omitted.

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: November 13, 2002

26

CERTIFICATIONS

I, Bobby S. Shackouls, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Burlington Resources
Inc.;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

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

27

CERTIFICATIONS

I, Steven J. Shapiro, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Burlington Resources
Inc.;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the effectiveness of
the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our
most recent evaluation, to the registrant's auditors and the audit committee of
registrant's board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls
which could adversely affect the registrant's ability to record, process,
summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

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

28

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"), hereby
certifies that the Quarterly Report of the Company on Form 10-Q for the period
ended September 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: November 13, 2002 Bobby S. Shackouls
Chairman of the Board, President
and Chief Executive Officer

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

The undersigned, Steven J. Shapiro, Senior Vice President and Chief
Financial Officer of the Company, hereby certifies that the Quarterly Report of
the Company on Form 10-Q for the period ended September 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/ STEVEN J. SHAPIRO
---------------------------------
Dated: November 13, 2002 Steven J. Shapiro
Senior Vice President and Chief
Financial Officer