10-Q 1 qtr301.txt 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, 2001 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 1-9971 BURLINGTON RESOURCES INC. (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, 2001 200,767,321 PART I - FINANCIAL INFORMATION ITEM 1. Financial Statements BURLINGTON RESOURCES INC. CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)

THIRD QUARTER NINE MONTHS --------------------- --------------------- 2001 2000 2001 2000 ------- ------- ------- ------- (In Millions, Except per Share Amounts) Revenues........................................................................ $ 655 $ 760 $ 2,715 $ 2,148 -------- ------- -------- -------- Costs and Expenses Production Taxes................................................................ 23 31 130 102 Transportation Expense.......................................................... 64 65 191 180 Production and Processing....................................................... 127 110 368 349 Depreciation, Depletion and Amortization........................................ 183 171 527 522 Exploration Costs............................................................... 79 28 201 174 Administrative.................................................................. 36 37 119 115 -------- ------- -------- -------- Total Costs and Expenses........................................................ 512 442 1,536 1,442 -------- ------- -------- -------- Operating Income................................................................ 143 318 1,179 706 Interest Expense................................................................ 41 48 132 151 Other Expense (Income) - Net.................................................... (4) (3) 4 7 -------- ------- -------- -------- Income Before Income Taxes...................................................... 106 273 1,043 548 Income Tax Expense.............................................................. 33 73 406 177 -------- ------- -------- -------- Net Income Before Cumulative Effect of Change in Accounting Principle........... 73 200 637 371 Cumulative Effect of Change in Accounting Principle - Net....................... - - 3 - -------- ------- -------- -------- Net Income...................................................................... $ 73 $ 200 $ 640 $ 371 ======== ======= ======== ======== Earnings per Common Share Basic Before Cumulative Effect of Change in Accounting Principle................. $ .36 $ .93 $ 3.05 $ 1.72 Cumulative Effect of Change in Accounting Principle - Net.................. - - .01 - -------- ------- -------- -------- Net Income.............................................................. $ .36 $ .93 $ 3.06 $ 1.72 ======== ======= ======== ======== Diluted Before Cumulative Effect of Change in Accounting Principle................. $ .36 $ .93 $ 3.04 $ 1.71 Cumulative Effect of Change in Accounting Principle - Net.................. - - .01 - -------- ------- -------- -------- Net Income................................................................. $ .36 $ .93 $ 3.05 $ 1.71 ======== ======= ======== ======== See accompanying Notes to Consolidated Financial Statements.

2 BURLINGTON RESOURCES INC. CONSOLIDATED BALANCE SHEET (UNAUDITED)

September 30, December 31, 2001 2000 ----------------- ----------------- (In Millions, Except Share Data) ASSETS Current Assets Cash and Cash Equivalents..................................................... $ 359 $ 132 Accounts Receivable........................................................... 413 809 Commodity Hedging Contracts and Other Derivatives............................. 181 - Inventories................................................................... 46 45 Other Current Assets.......................................................... 29 25 ----------------- ----------------- 1,028 1,011 ----------------- ----------------- Oil & Gas Properties (Successful Efforts Method)................................ 13,684 13,118 Other Properties................................................................ 1,108 1,019 ----------------- ----------------- 14,792 14,137 Accumulated Depreciation, Depletion and Amortization............................ 8,272 7,830 ----------------- ----------------- Properties - Net............................................................ 6,520 6,307 ----------------- ----------------- Commodity Hedging Contracts and Other Derivatives............................... 9 - ----------------- ----------------- Other Assets.................................................................... 182 188 ----------------- ----------------- Total Assets................................................................ $ 7,739 $ 7,506 ================= ================= LIABILITIES Current Liabilities Accounts Payable.............................................................. $ 485 $ 619 Commodity Hedging Contracts and Other Derivatives............................. 12 - Taxes Payable................................................................. 54 55 Accrued Interest.............................................................. 38 33 Dividends Payable............................................................. 28 30 Other Current Liabilities..................................................... 14 21 ----------------- ----------------- 631 758 ----------------- ----------------- Long-term Debt.................................................................. 2,383 2,301 ----------------- ----------------- Deferred Income Taxes........................................................... 621 266 ----------------- ----------------- Commodity Hedging Contracts and Other Derivatives............................... 6 - ----------------- ----------------- Other Liabilities and Deferred Credits.......................................... 407 431 ----------------- ----------------- 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................................................................. 3,944 3,944 Retained Earnings............................................................... 1,438 884 Deferred Compensation - Restricted Stock........................................ (12) (5) Accumulated Other Comprehensive Loss............................................ (44) (70) Cost of Treasury Stock (40,421,597 and 25,619,893 Shares for 2001 and 2000, respectively)............. (1,637) (1,005) ----------------- ----------------- Stockholders' Equity............................................................ 3,691 3,750 ----------------- ----------------- Total Liabilities and Stockholders' Equity................................ $ 7,739 $ 7,506 ================= ================= See accompanying Notes to Consolidated Financial Statements.

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

NINE MONTHS ------------------------- 2001 2000 ----------- ----------- (In Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income............................................................ $ 640 $ 371 Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities Depreciation, Depletion and Amortization.............................. 527 522 Deferred Income Taxes................................................. 316 116 Exploration Costs..................................................... 201 174 Changes in Derivative Fair Values..................................... (47) - Working Capital Changes Accounts Receivable................................................... 396 (84) Inventories........................................................... (1) 1 Other Current Assets.................................................. (5) (4) Accounts Payable...................................................... (158) 25 Taxes Payable......................................................... 3 (23) Accrued Interest...................................................... 5 1 Other Current Liabilities............................................. (9) 3 Other.................................................................. (41) 3 ----------- ----------- Net Cash Provided By Operating Activities.......................... 1,827 1,105 ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES Additions to Properties................................................ (964) (679) Other.................................................................. 10 37 ----------- ----------- Net Cash Used In Investing Activities............................... (954) (642) ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Borrowings............................................... 400 72 Reduction in Borrowings................................................ (309) (528) Dividends Paid......................................................... (88) (59) Common Stock Purchases................................................. (684) (75) Common Stock Issuances................................................. 42 44 Other.................................................................. (7) 10 ----------- ----------- Net Cash Used In Financing Activities............................... (646) (536) ----------- ----------- INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........................ 227 (73) CASH AND CASH EQUIVALENTS Beginning of Year...................................................... 132 89 ---------- ----------- End of Period............. ............................................ $ 359 $ 16 =========== =========== See accompanying Notes to Consolidated Financial Statements.

4 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. BASIS OF PRESENTATION The 2000 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. 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 204 million and 216 million for the third quarter of 2001 and 2000, respectively, and 209 million and 216 million for the first nine months of 2001 and 2000, 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 205 million and 217 million for the third quarter of 2001 and 2000, respectively, and 210 million and 217 million for the first nine months of 2001 and 2000, respectively. No adjustments were made to reported net income in the computation of EPS. 2. PROPOSED ACQUISITION On October 9, 2001, the Company and Canadian Hunter Exploration Ltd. ("Canadian Hunter") announced that they have entered into an agreement pursuant to which the Company will make an offer to holders of the outstanding shares of Canadian Hunter to acquire all such shares for cash consideration of Canadian $53 per share representing an aggregate value of approximately U.S. $2.1 billion in cash. Under the terms of the agreement, the offer is conditional upon at least two-thirds of Canadian Hunter's shares being tendered, regulatory approval and other closing conditions. The transaction is expected to be funded with proceeds from the issuance of certain debt securities. The transaction will be accounted for under the purchase method in accordance with Statement of Financial Accounting Standards ("SFAS") No. 141 and is expected to close by year-end 2001. The Company also announced that it intends to divest of certain existing oil and gas properties that do not fit its preferred asset profile. 5 3. COMPREHENSIVE INCOME The following table presents comprehensive income for the first nine months of 2001.

NINE MONTHS 2001 -------------------------- (In Millions) Accumulated other comprehensive loss - December 31, 2000........................ $ (70) Net income......................................................................$ 640 ----------- Other comprehensive income - net of tax Hedging activities Cumulative effect of change in accounting principle - January 1, 2001. (366) Reclassification adjustments for settled contracts.................... 244 Current period changes in fair value of settled contracts............. 96 Changes in fair value of outstanding hedging positions................ 101 ----------- Hedging activities.............................................. 75 Foreign currency translation Foreign currency translation adjustments.............................. (49) ----------- Total other comprehensive income................................................ 26 26 ----------- ----------- Comprehensive income............................................................$ 666 =========== Accumulated other comprehensive loss - September 30, 2001....................... $ (44) ===========

In the first nine months of 2000, comprehensive income was $352 million consisting of $371 million of net income and $19 million of losses from foreign currency translation adjustments. 4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES The Company enters into derivative contracts, primarily options and swaps, to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. The Company also enters into derivative contracts to mitigate the risk of foreign currency exchange rate fluctuations. On January 1, 2001, the Company adopted SFAS No. 133, as amended, Accounting for Derivative Instruments and Hedging Activities. Effective with the adoption of SFAS No. 133, all derivatives are recognized on the balance sheet and measured at fair value. If the derivative does not qualify as a hedge or is not 6 designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is either recognized in income along with an offsetting adjustment to the basis of the item being hedged or deferred in other comprehensive income to the extent the hedge is effective. To qualify for hedge accounting, the derivative must qualify as either a fair-value, cash-flow or foreign-currency hedge. The hedging relationship between the hedging instruments and hedged items must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk both at the inception of the hedge and on an ongoing basis. The Company measures hedge effectiveness on a quarterly basis. Hedge accounting is discontinued prospectively when a hedging instrument becomes ineffective. The Company assesses hedge effectiveness based on total changes in the fair value of options used in cash flow hedges rather than changes of intrinsic value only. As a result, changes in fair value of option contracts are deferred in accumulated other comprehensive income until the hedged transaction affect earnings to the extent such contracts are effective. Gains and losses deferred in accumulated other comprehensive income related to cash flow hedge derivatives that become ineffective remain unchanged until the related production is delivered. Adjustment to the carrying amounts of hedged production is discontinued in instances where the related fair-value hedging instrument becomes ineffective. The balance in the fair-value hedge adjustment account is recorded in income when the related production is delivered. If the Company determines that it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument are recognized in earnings immediately. Gains and losses on hedging instruments and adjustments of the carrying amounts of hedged production are included in crude oil and natural gas revenues and are included in realized prices in the period that the related production is delivered. Gains and losses on hedging instruments which represent hedge ineffectiveness and gains and losses on derivative instruments which do not qualify for hedge accounting are included in other revenues in the period in which they occur. The 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. The Company enters into natural gas basis swap agreements to fix the sales price differential between the Company's marketing locations and NYMEX Henry Hub. The Company enters into natural gas option agreements to establish floor and ceiling prices on anticipated future natural gas production. The Company also enters into natural gas option agreements to establish floor and ceiling prices on anticipated future natural gas production while allowing the Company to participate in upward price movements above a specified non-participation range. Generally, the Company does not receive net premiums on its option hedging strategies. The Company also enters into crude oil swap agreements to fix the price of anticipated future crude oil production and purchases call options agreements that allow the Company to participate in market price increases that exceed hedge prices established when the Company enters into a swap. The Company also enters into crude oil option agreements to establish floor and ceiling prices on anticipated future crude oil production while allowing the Company to participate in upward price movements above a specified non-participation range. Generally, the Company does not receive net premiums on its option hedging strategies. 7 As of September 30, 2001, the Company had the following natural gas volumes hedged. Natural Gas Fixed-Price Swaps

Average Fair Value Production Volumes Strike Asset Period (MMBTU) Price (In Millions) --------------- ------------------ ---------------- -------------------- 2001 7,009,940 $2.66 $3 2002 11,861,175 3.02 1 2003 to 2007 23,742,340 $3.39 $2 Natural Gas Basis Swaps Average Fair Value Production Volumes Basis Asset Period (MMBTU) Differential (In Millions) --------------- ------------------ ---------------- -------------------- 2001 2,409,940 $1.24 $3 2002 9,331,175 .17 4 2003 to 2007 23,742,340 $ (.19) $3

Natural Gas Options

Average Fair Value Production Volumes Strike Asset Period Option Type (MMBTU) Price (In Millions) --------------- ------------------- ------------------- --------------- --------------------- 2001 Puts purchased 41,085,000 $ 3.88 $74 2001 Calls sold 41,085,000 7.74 - 2001 Calls purchased 25,760,000 10.60 - 2002 Puts purchased 65,050,000 3.76 82 2002 Calls sold 65,050,000 7.44 - 2002 Calls purchased 30,250,000 $10.80 $ -

As of September 30, 2001, the fair value of the swap agreements the Company had entered into in order to convert the Company's fixed-price gas sales contracts to market sensitive positions was a $3 million liability offset by a $4 million asset basis adjustment to the carrying value of the fixed-price gas sales contracts. These arrangements are recorded as a revision to gas price in periods the production is delivered. All firm commitments qualified as fair-value hedges during the first nine months of 2001. As of September 30, 2001, the Company had the following crude oil volumes hedged. Crude Oil Swaps

Average Fair Value Production Volumes Strike Liability Period (Barrels) Price (In Millions) --------------- ----------------- ---------------- -------------------- 2001 4,140,000 $19.98 $(15) 2002 180,000 $21.91 $ -

8 Crude Oil Options

Average Fair Value Production Option Volumes Strike Asset (Liability) Period Type (Barrels) Price (In Millions) -------------- ------------------- ------------------ ----------------- ------------------------ 2001 Puts Purchased 920,000 $25.00 $ 3 2001 Puts Sold 920,000 20.00 (1) 2001 Calls Sold 920,000 32.17 - 2001 Calls Purchased 2,760,000 19.69 12 2002 Puts Purchased 1,810,000 25.00 6 2002 Puts Sold 1,810,000 20.00 (2) 2002 Calls Sold 1,810,000 32.17 (1) 2002 Calls Purchased 542,000 $33.32 $ 1

Approximately 67 percent of the crude oil volumes for 2001 swaps and all of the crude oil volumes for 2002 swaps were matched with call options. The derivative assets and liabilities represent the difference between hedged prices and market prices on hedged volumes of the commodities as of September 30, 2001. Hedging activities reduced natural gas and crude oil revenues by $364 million and $30 million, respectively, during the first nine months of 2001. In addition, during the first nine months, gains of $41 million were recorded in revenues associated with ineffectiveness of cash-flow and fair-value hedges and gains on derivative instruments which do not qualify for hedge accounting. There were no discontinued cash-flow hedges during the first nine months of 2001. In addition to hedges of commodity prices, the Company also has foreign currency swaps to hedge its exposure to exchange rate fluctuations at one of its Canadian subsidiaries. As of September 30, 2001, the Company had $4 million of liabilities related to foreign currency exchange rate hedges. In accordance with the transition provisions of SFAS No. 133, on January 1, 2001, the Company recorded a net-of-tax cumulative-effect-type loss adjustment of $366 million in accumulated other comprehensive income to recognize at fair value all derivatives that are designated as cash-flow hedging instruments. The Company recorded cash-flow hedge derivatives liabilities of $582 million ($361 million after tax), fair value hedge derivative assets of $16 million ($10 million after tax), related liability adjustments to book value of fair-value hedged items of $16 million ($10 million after tax) and a $3 million after tax non-cash gain was recorded in current earnings as a cumulative effect of accounting change. During the first nine months of 2001, losses of $394 million ($244 million after tax) were transferred from accumulated other comprehensive income to earnings related to settlements of oil and gas price hedging contracts, credit adjustments of $154 million ($96 million after tax) were made to accumulated other comprehensive income to reflect current period changes in fair value of settled contracts, and the fair value of outstanding hedging position liabilities decreased $164 million ($101 million after tax) resulting in an ending balance of a $122 million credit ($75 million after tax) related to hedging activities in accumulated other comprehensive income at September 30, 2001. Based on commodity prices and foreign exchange rates as of September 30, 2001, the Company expects to reclassify gains of $119 million ($74 million after tax) to earnings from the balance in accumulated other comprehensive income during the next twelve months. As of September 30, 2001, the Company had cash-flow hedge derivative assets of $161 million and liabilities of $10 million. The Company had liabilities and assets related to fair-value hedges of $7 million and $8 million, respectively. The Company also had commodity-related derivative instruments that do not qualify for hedge accounting with related assets of $21 million and liabilities of $1 million. 9 5. COMMITMENTS AND CONTINGENT LIABILITIES The Company and numerous other oil and gas companies have been named as defendants in various lawsuits alleging violations of the civil False Claims Act. These lawsuits have been consolidated by the United States Judicial Panel on Multidistrict Litigation for pre-trial proceedings in the matter of In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court for the District of Wyoming ("MDL-1293"). The plaintiffs contend that defendants underpaid royalties on natural gas and NGLs produced on federal and Indian lands through the use of below-market prices, improper deductions, improper measurement techniques and transactions with affiliated companies. Plaintiffs allege that the royalties paid by defendants were lower than the royalties required to be paid under federal regulations and that the forms filed by defendants with the Minerals Management Service ("MMS") reporting these royalty payments were false, thereby violating the civil False Claims Act. The United States has intervened in certain of the MDL-1293 cases as to some of the defendants, including the Company. Various administrative proceedings are also pending before the MMS of the United States Department of the Interior with respect to the valuation of oil and gas produced by the Company on federal and Indian lands. In general, these proceedings stem from regular MMS audits of the Company's royalty payments over various periods of time and involve the interpretation of the relevant federal regulations. Based on the Company's present understanding of the various governmental and False Claims Act proceedings described above, the Company believes that it has substantial defenses to these claims and intends to vigorously assert such defenses. However, in the event that the Company is found to have violated the civil False Claims Act, the Company could be subject to monetary damages and a variety of sanctions, including double damages, substantial monetary fines, civil penalties and a temporary suspension from entering into future federal mineral leases and other federal contracts for a defined period of time. While the ultimate outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the consolidated financial position of the Company, although results of operations and cash flow could be significantly impacted in the reporting periods in which such matters are resolved. The Company has also been named as a defendant in the lawsuit styled UNOCAL Netherlands B.V., et al v. Continental Netherlands Oil Company B.V., et al, No. 98-854, in the Court of Appeal in The Hague in the Netherlands. Plaintiffs, who are working interest owners in the Q1 Block in the North Sea, have alleged that the Company and other former working interest owners in the adjacent Logger Field in the L16a Block unlawfully trespassed or were otherwise unjustly enriched by producing part of the oil from the adjoining Q1 Block. The plaintiffs claim that the defendants infringed upon plaintiffs' right to produce the minerals present in its license area and acted in violation of generally accepted standards by failing to inform plaintiffs of the overlap of the Logger Field into the Q-1 Block. For all relevant periods, the Company owned a 37.5% working interest in the Logger Field. Following a trial, the District Court in The Hague rendered a Judgment in favor of the defendants, including the Company, dismissing all claims. Plaintiffs thereafter appealed. On October 19, 2000, the Court of Appeal in The Hague issued an interim Judgment in favor of the plaintiffs and ordered that additional evidence be presented to the court relating to issues of both liability and damages. The Company and the other defendants are continuing to vigorously assert defenses against these claims. 10 The Company has also asserted claims of indemnity against two of the defendants from whom it had acquired a portion of its working interest share. The Company is unable at this time to reasonably predict the outcome, or, in the event of an unfavorable outcome, to reasonably estimate the possible loss or range of loss, if any, in this lawsuit. In addition to the foregoing, the Company and its subsidiaries are named defendants in numerous other lawsuits and named parties in numerous governmental and other proceedings arising in the ordinary course of business. While the outcome of these other lawsuits and proceedings cannot be predicted with certainty, management believes these other matters will not have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company. 6. LONG-TERM DEBT On February 12, 2001, the Company issued $400 million of fixed-rate debt with an interest rate of 6.68 percent due February 2011. In August 2001, the Company exchanged $112 million of 7.65% notes, $82 million of 6.875% notes, $358 million of 7.375% notes, $33 million of 7.12% notes, $50 million of 6.91% notes and $75 million of 7% notes for $575 million of 7.2% notes due 2031 and $178 million of 6.4% notes due 2011. The transaction was accounted for as an exchange of debt instruments. This exchange of debt instruments reduced the Company's amount available under its shelf registration statement on file with the Securities and Exchange Commission to $747 million. During the first nine months of 2001, the Company also retired $288 million of commercial paper and repaid $23 million of other fixed-rate debt. On October 1, 2001, the Company retired $150 million of 8 1/2% notes in accordance with their original terms. 7. PROPERTY ACQUISITIONS During the first quarter of 2001, the Company purchased from DIFCO Limited an additional 10 percent interest in 7 fields in the East Irish Sea for $25 million. The Company is the operator of the properties and now owns 100 percent of the assets. In January 2001, the Company's Canadian subsidiary, Burlington Resources Canada Energy Ltd., now known as Burlington Resources Canada Ltd. ("BRCL"), acquired approximately 46 billion cubic feet of gas equivalent ("BCFE") of proved reserves from Petrobank Energy and Resources Ltd. for $57 million. In January 2001, the Company also announced that BRCL entered into an agreement with ATCO Gas, a regulated gas utility, to acquire properties in the Viking-Kinsella area of Alberta, Canada for approximately $328 million. The properties have net proved reserves of approximately 251 BCFE. In May, the Alberta Energy and Utilities Board ( the "AEUB") denied an application by ATCO Gas to sell the properties. In September 2001, the Company increased the base purchase price to Canadian $550 million (approximately U.S. $347 million based on the exchange rate at September 28, 2001). ATCO Gas asked the AEUB to reconsider its initial decision denying the sale in view of the revised purchase price and other factors. The AEUB will hear ATCO's review and variance application on November 14, 2001 and its decision will follow that date. 8. SEGMENT AND GEOGRAPHIC INFORMATION The Company's reportable segments are North America and International. Both segments are engaged principally in the exploration, development, production and marketing of oil and gas. The North America segment is responsible for the Company's operations in the USA and Canada and the International segment is responsible for all operations outside that geographical region. 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. There are no significant intersegment sales or transfers. 11 The following tables present information about reported segment operations.

Third Quarter --------------------------------------------------------------------------------------------------- 2001 2000 ---------------------------------------------- ----------------------------------------------------- North America North America ----------------- ------------------ USA Canada International Total USA Canada International Total ------ -------- ---------------- ------- ------- ---------- --------------- -------- (In Millions) (In Millions) Revenues $446 $167 $42 $655 $540 $191 $29 $760 Operating income (loss) $142 $ 44 $(2) $184 $279 $ 81 $ - $360

Nine Months ------------------------------------------------------------------------------------------------------ 2001 2000 ---------------------------------------------- ----------------------------------------------------- North America North America ----------------- --------------------- USA Canada International Total USA Canada International Total ------- -------- -------------- ------ -------- ---------- --------------- ------- (In Millions) (In Millions) Revenues $1,801 $775 $139 $2,715 $1,541 $483 $124 $2,148 Operating income $ 864 $428 $ 21 $1,313 $ 642 $159 $ 34 $ 835

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

Third Quarter Nine Months -------------------------- ------------------------- 2001 2000 2001 2000 ---------- ------------- ----------- ----------- (In Millions) (In Millions) Total operating income of reportable segments $184 $360 $1,313 $835 Corporate expenses 41 42 134 129 Interest expense 41 48 132 151 Other expense (income) - net (4) (3) 4 7 ---------- ------------- ----------- ----------- Consolidated income before income taxes $106 $273 $1,043 $548 ========== ============= =========== ===========

9. RECENT ACCOUNTING PRONOUNCEMENTS The following SFAS's were issued in June 2001: SFAS No. 141, Business Combinations, SFAS No. 142, Goodwill and Other Intangible Assets, and SFAS No. 143, Accounting for Asset Retirement Obligations. In August 2001, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets was also issued. SFAS No. 141, requires the purchase method of accounting for all business combinations, applies to all business combinations initiated after June 30, 2001 and to all business combinations accounted for by the purchase method that are completed after June 30, 2001. SFAS No. 142 requires that goodwill as well as other intangible assets with indefinite lives not be amortized but be tested annually for impairment and is effective for fiscal years beginning after December 15, 2001. SFAS No. 141 and No. 142 apply to the Company's accounting for the proposed acquisition of Canadian Hunter. 12 SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. SFAS No. 144 addresses financial accounting and reporting for the impairment of long-lived assets and for long-lived assets to be disposed of. It supersedes, with exceptions, SFAS No.121, Accounting for the Impairment of Long-Live Assets and for Long-Lived Assets to Be Disposed Of and is effective for fiscal years beginning after December 15, 2001. The Company is currently assessing the impact of SFAS No. 143 and No. 144 and therefore, at this time cannot reasonably estimate the effect of these statements on its financial condition, results of operations and cash flows. ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Financial Condition and Liquidity The Company's long-term debt to total capital ratio at September 30, 2001 and December 31, 2000 was 39 percent and 38 percent, respectively. On February 12, 2001, the Company issued $400 million of fixed-rate debt with an interest rate of 6.68 percent due February 2011. In August 2001, the Company exchanged $112 million of 7.65% notes, $82 million of 6.875% notes, $358 million of 7.375% notes, $33 million of 7.12% notes, $50 million of 6.91% notes and $75 million of 7% notes for $575 million of 7.2% notes due 2031 and $178 million of 6.4% notes due 2011. The transaction was accounted for as an exchange of debt instruments. This exchange of debt instruments reduced the Company's amount available under its shelf registration statement on file with the Securities and Exchange Commission to $747 million. During the first nine months of 2001, the Company also retired $288 million of commercial paper and repaid $23 million of other fixed-rate debt. On October 1, 2001, the Company retired $150 million of 8 1/2% notes in accordance with their original terms. On July 18, 2001, the Company's board of directors authorized the Company to redeem or repurchase up to $1 billion principal amount of debt securities of the Company. The Company had unused credit commitments in the form of revolving credit facilities ("revolvers") as of September 30, 2001. These revolvers are available to cover debt due within one year, therefore, commercial paper, credit facility notes and fixed-rate debt due within one year are classified as long-term debt. The revolvers are comprised of agreements for $600 million, $400 million and $316 million. The $600 million revolver expires in February 2003 and the $400 million and $316 million revolvers expire in March 2002 unless renewed by mutual consent. The Company has the option to convert the outstanding balances on the $400 million and $316 million revolvers to one year term notes at expiration of the agreements. In December 2000, the Company's Board of Directors authorized the repurchase of up to $1 billion of the Company's Common Stock. During the first nine months of 2001, the Company repurchased 16 million shares of its Common Stock for approximately $684 million. Net cash provided by operating activities during the first nine months of 2001 was $1,827 million compared to $1,105 million in 2000. The increase was primarily due to higher operating income and lower working capital needs. Operating income was higher principally as a result of higher commodity prices. The Company and its subsidiaries are named defendants in numerous lawsuits and named parties in numerous governmental and other proceedings arising in the 13 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. Management believes that there are no other commitments or uncertainties that will have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company. Capital Expenditures Capital expenditures for the first nine months of 2001 totaled $985 million compared to $675 million in 2000. The Company invested $735 million on internal development and exploration of oil and gas properties during the first nine months of 2001 compared to $617 million in 2000. The Company invested $143 million for property acquisitions in the first nine months of 2001 compared to $11 million in 2000. The Company also invested $85 million in plants and pipelines during the first nine months of 2001 compared to $29 million in 2000. During the first quarter of 2001, the Company purchased from DIFCO Limited an additional 10 percent interest in 7 fields in the East Irish Sea for $25 million. The Company is the operator of the properties and now owns 100 percent of the assets. In January 2001, the Company's Canadian subsidiary, Burlington Resources Canada Energy Ltd., now known as Burlington Resources Canada Ltd. ("BRCL"), acquired approximately 46 billion cubic feet of gas equivalent ("BCFE") of proved reserves from Petrobank Energy and Resources Ltd. for $57 million. In January 2001, the Company also announced that BRCL entered into an agreement with ATCO Gas, a regulated gas utility, to acquire properties in the Viking-Kinsella area of Alberta, Canada for approximately $328 million. The properties have net proved reserves of approximately 251 BCFE. In May, the Alberta Energy and Utilities Board ( the "AEUB") denied an application by ATCO Gas to sell the properties. In September 2001, the Company increased the base purchase price to Canadian $550 million (approximately U.S. $347 million based on the exchange rate at September 28, 2001). ATCO Gas asked the AEUB to reconsider its initial decision denying the sale in view of the revised purchase price and other factors. The AEUB will hear ATCO's review and variance application on November 14, 2001 and its decision will follow that date. Dividends On October 17, 2001, the Board of Directors declared a quarterly common stock cash dividend of $.1375 per share, payable January 3, 2002. Results of Operations - Third Quarter 2001 Compared to Third Quarter 2000 The Company reported net income of $73 million or $.36 diluted earnings per common share in third quarter 2001 compared to net income of $200 million or $.93 diluted earnings per common share in 2000. Net income in the third quarter of 2001 included an after tax gain of $7 million or $.03 per diluted share consisting of ineffectiveness of cash-flow and fair-value hedges and gains on derivative instruments which do not qualify for hedge accounting under Statement of Financial Accounting Standards No. 133, as amended, Accounting for Derivative Instruments and Hedging Activities ("SFAS No. 133"). For more discussion of SFAS No. 133, see ITEM 3. 14 Revenues were $655 million in third quarter 2001 compared to $760 million in 2000. Average gas prices, including a $.23 gain per MCF related to hedging activities, decreased 18 percent to $2.75 per MCF in third quarter 2001 resulting in decreased revenues of $109 million. Average oil prices, including a $1.43 loss per barrel related to hedging activities decreased 12 percent to $23.92 per barrel in third quarter 2001 resulting in decreased revenues of $19 million. Oil sales volumes decreased 10 percent in third quarter 2001 to 66.2 MBbls per day and gas sales volumes increased 4 percent to 1,929 MMCF per day which decreased revenues $18 million and increased revenues $25 million, respectively. Oil sales volumes decreased primarily due to natural production declines and reduced capital spending in the Gulf Coast and Mid-Continent areas and property sales in 2000. Gas sales volumes increased primarily due to tie-ins in the Canada and East Irish Sea areas. Revenues also included an $11 million gain related to ineffectiveness of cash-flow and fair-value hedges and gains on derivative instruments which do not qualify for hedge accounting. Costs and Expenses were $512 million in third quarter 2001 compared to $442 million in 2000. The increase was primarily due to a $51 million increase in exploration costs, a $17 million increase in production and processing expenses and a $12 million increase in depreciation, depletion and amortization ("DD&A") partially offset by an $8 million decrease in production taxes. Exploration costs increased primarily due to higher exploratory dry hole costs of $36 million and higher impairment charges of $15 million. Production and processing expenses increased primarily due to higher workover expense and higher service, electrical and lease fuel costs. DD&A increased due to a higher unit of production rate related to changes in production mix and higher production volumes. Production taxes decreased primarily due to lower oil and gas revenues. Interest Expense was $41 million in third quarter 2001 compared to $48 million in 2000. The decrease was primarily due to lower outstanding commercial paper borrowings during 2001. Income taxes were an expense of $33 million in third quarter 2001 as compared to $73 million in 2000. The decrease in tax expense was primarily due to lower pretax income. Also, third quarter 2000 included a beneficial tax adjustment of $34 million related to cumulative Section 29 credits. Results of Operations - First Nine Months of 2001 Compared to First Nine Months of 2000 The Company reported net income of $640 million or $3.05 diluted earnings per common share in the first nine months of 2001 compared to net income of $371 million or $1.71 diluted earnings per common share in 2000. Net income in the first nine months of 2001 included an after tax gain of $3 million or $.01 per diluted share consisting of the cumulative effect of change in accounting principle related to SFAS No. 133. Net income in the first nine months of 2001 also included an after tax gain of $25 million or $.12 per diluted share consisting of ineffectiveness of cash-flow and fair-value hedges and gains on derivative transactions which do not qualify for hedge accounting under SFAS No. 133. For more discussion of SFAS No. 133, see ITEM 3. Revenues were $2,715 million in the first nine months of 2001 compared to $2,148 million in 2000. Average gas prices, including a $.68 loss per MCF related to hedging activities, increased 41 percent to $4.07 per MCF in the first nine months of 2001 resulting in increased revenues of $632 million. Average oil prices, including a $1.59 loss per barrel related to hedging activities, were $25.10 per barrel which was essentially the same as the first nine months of 2000. Oil sales volumes decreased 16 percent in the first nine 15 months of 2001 to 68.5 MBbls per day and gas sales volumes decreased 1 percent to 1,961 MMCF per day which decreased revenues $88 million and $18 million, respectively. Oil sales volumes decreased primarily due to natural production declines and reduced capital spending in the Gulf Coast and Mid-Continent areas and property sales in 2000. Revenues in 2001 also included a $41 million gain related to ineffectiveness of cash-flow and fair-value hedges and gains on derivative instruments which do not qualify for hedge accounting. Costs and Expenses were $1,536 million in the first nine months of 2001 compared to $1,442 million in 2000. The increase was primarily due to a $28 million increase in production taxes, a $27 million increase in exploration costs, a $19 million increase in production and processing expenses, an $11 million increase in transportation expenses, a $5 million increase in DD&A and a $4 million increase in administrative expenses. Production taxes increased primarily due to higher gas revenues. Exploration costs increased primarily due to higher exploratory dry hole costs of $36 million and higher impairment charges of $16 million partially offset by lower geological and geophysical expense of $25 million. Production and processing expenses increased primarily due to higher workover expense and higher service, electrical and lease fuel costs. Transportation expenses increased due to new agreements, higher tariffs and higher fuel charges. DD&A increased due to a higher unit of production rate related to changes in production mix partially offset by lower production volumes. Administrative expenses increased primarily due to non-recurring payroll related costs. Interest Expense was $132 million in the first nine months of 2001 compared to $151 million in 2000. The decrease was primarily due to lower outstanding commercial paper borrowings during 2001. Other Expense (Income) -- Net was an expense of $4 million in the first nine months of 2001 compared to $7 million in 2000. This change was primarily due to higher interest income in 2001. Income taxes were an expense of $406 million in the first nine months of 2001 as compared to $177 million in 2000. The increase in tax expense was primarily due to higher pretax income. Also, nine months of 2000 included a beneficial tax adjustment of $34 million related to cumulative Section 29 credits. Other Matters Subsequent Events On October 9, 2001, the Company and Canadian Hunter Exploration Ltd. ("Canadian Hunter") announced that they have entered into an agreement pursuant to which the Company will make an offer to holders of the outstanding shares of Canadian Hunter to acquire all such shares for cash consideration of Canadian $53 per share representing an aggregate value of approximately U.S. $2.1 billion in cash. Under the terms of the agreement, the offer is conditional upon at least two-thirds of Canadian Hunter's shares being tendered, regulatory approval and other closing conditions. The transaction is expected to be funded with proceeds from the issuance of certain debt securities. The transaction will be accounted for under the purchase method in accordance with Statement of Financial Accounting Standards ("SFAS") No. 141 and is expected to close by year-end 2001. The Company also announced that it intends to divest of certain existing oil and gas properties that do not fit its preferred asset profile. 16 Recent Accounting Pronouncements The following SFAS's were issued in June 2001: SFAS No. 141, Business Combinations, SFAS No. 142, Goodwill and Other Intangible Assets, and SFAS No. 143, Accounting for Asset Retirement Obligations. In August 2001, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets was also issued. SFAS No. 141, requires the purchase method of accounting for all business combinations, applies to all business combinations initiated after June 30, 2001 and to all business combinations accounted for by the purchase method that are completed after June 30, 2001. SFAS No. 142 requires that goodwill as well as other intangible assets with indefinite lives not be amortized but be tested annually for impairment and is effective for fiscal years beginning after December 15, 2001. SFAS No. 141 and No. 142 apply to the Company's accounting for the proposed acquisition of Canadian Hunter. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. SFAS No. 144 addresses financial accounting and reporting for the impairment of long-lived assets and for long-lived assets to be disposed of. It supersedes, with exceptions, SFAS No.121, Accounting for the Impairment of Long-Live Assets and for Long-Lived Assets to Be Disposed Of and is effective for fiscal years beginning after December 15, 2001. The Company is currently assessing the impact of SFAS No. 143 and No. 144 and therefore, at this time cannot reasonably estimate the effect of these statements on its financial condition, results of operations and cash flows. BR Exchangeable Shares On September 14, 2001, all of the remaining outstanding exchangeable shares issued by the Company's subsidiary, Burlington Resources Canada Inc., in connection with the November 1999 acquisition of Poco Petroleums Ltd., were exchanged for BR common shares. The exchangeable shares had been trading on the Toronto Stock Exchange in Canada under the symbol "BRX". On September 17, 2001, as part of a reorganization of the Company's Canadian subsidiaries, Burlington Resources Canada Inc., Burlington Resources Canada Energy Ltd.(formerly Poco Petroleums Ltd.) and another wholly-owned Canadian subsidiary of the Company were amalgamated and are now known as Burlington Resources Canada Ltd. 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. There is also a difference between the NYMEX Henry Hub 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 fixed-price and basis swaps as well as options to hedge its production in order to decrease its price risk exposure. The gains and losses realized as a result of these price and basis derivative transactions are substantially offset when the hedged commodity is delivered. In order to accommodate the needs of its customers, the Company also uses price swaps to convert natural gas sold under fixed-price contracts to market sensitive prices. 17 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. At September 30, 2001, the potential decrease in fair value of derivative instruments assuming a 10 percent adverse movement (an increase in the underlying commodities prices) would result in a $37 million decrease in the fair value of the net assets 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. On January 1, 2001, the Company adopted SFAS No. 133. This pronouncement establishes accounting and reporting standards for derivative instruments and for hedging activities. It requires enterprises to recognize all derivatives as either assets or liabilities in the balance sheet and measure those instruments at fair value. The requisite accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. In accordance with the transition provisions of SFAS No. 133, the Company recorded a net-of-tax cumulative-effect-type loss adjustment of $366 million in accumulated other comprehensive income to recognize at fair value all derivatives that are designated as cash-flow hedging instruments. The Company recorded cash-flow hedge derivatives liabilities of $582 million ($361 million after tax), fair-value hedge derivative assets of $16 million ($10 million after tax), related liability adjustments to book value of fair-value hedged items of $16 million ($10 million after tax) and a $3 million after tax non-cash gain was recorded in current earnings as a cumulative effect of accounting change. During the first nine months of 2001, losses of $394 million ($244 million after tax) were transferred from accumulated other comprehensive income to earnings related to settlements of oil and gas price hedging contracts, credit adjustments of $154 million ($96 million after tax) were made to accumulated other comprehensive income to reflect current period changes in fair value of settled contracts, and the fair value of outstanding hedging position liabilities decreased $164 million ($101 million after tax) resulting in an ending balance of a $122 million credit ($75 million after tax) related to hedging activities in accumulated other comprehensive income at September 30, 2001. Based on commodity prices and foreign exchange rates as of September 30, 2001, the Company expects to reclassify gains of $119 million ($74 million after tax) to earnings from the balance in accumulated other comprehensive income during the next twelve months. As of September 30, 2001, the Company had cash-flow hedge derivative assets of $161 million and liabilities of $10 million. The Company had liabilities and assets related to fair-value hedges of $7 million and $8 million, respectively. The Company also had commodity-related derivative instruments that do not qualify for hedge accounting with related assets of $21 million and liabilities of $1 million. 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 18 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 2000 Form 10-K. 19 PART II - OTHER INFORMATION ITEM 1. Legal Proceedings See Note 5 of Notes to Consolidated Financial Statements. 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. * Exhibit incorporated by reference. B. Reports on Form 8-K On August 22, 2001, the Company filed Form 8-K in connection with its August 2001 issuance of $575 million and $178 million of 7.2% and 6.4% notes, respectively. Items 2, 3, 4 and 5 of Part II are not applicable and have been omitted. 20 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: October 23, 2001 21