Form 10-Q

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). 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.

The 2002 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 199 million and 201 million for the third quarter of 2003 and 2002, respectively, and 200 million and 201 million for the first nine months of 2003 and 2002, respectively. Diluted EPS reflects the potential dilution that could occur if contracts to issue common stock related to stock options were exercised. The weighted average number of common shares outstanding for computing diluted EPS, including dilutive stock options, was 201 million and 202 million for the third quarter of 2003 and 2002, respectively, and 201 million and 202 million for the first nine months of 2003 and 2002, respectively. For the third quarter of 2003 and 2002 and nine months ended September 30, 2003 and 2002, approximately 2 million, 4 million, 2 million and 4 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 dividends affecting EPS, therefore, no adjustments related to preferred dividends were made to reported net income in the computation of EPS.

Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations, and SFAS No. 142, Goodwill and Intangible Assets, were issued in June 2001 and became effective for the Company July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS No. 141 requires companies to disaggregate and report certain intangibles assets separately from goodwill. SFAS No. 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. The Financial Accounting Standards Board, the Securities and Exchange Commission and others continue to discuss the appropriate application of SFAS No. 141 and No. 142 as it relates to oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract reserves. Depending on the outcome of such discussions, oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract reserves for both undeveloped and developed leaseholds may be classified separately from oil and gas properties, and included as intangible assets on the Company’s consolidated balance sheets. In

addition, the disclosures required by SFAS No. 141 and No. 142 related to intangibles would be included in the notes to the consolidated financial statements. Historically, the Company, like many other oil and gas companies, have included oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract reserves as part of the oil and gas properties, even after SFAS No. 141 and No. 142 became effective.

This interpretation of SFAS No. 141 and No. 142 would only affect the Company’s consolidated balance sheet classification of oil and gas leaseholds. The Company’s results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract reserves would continue to be amortized in accordance with accounting rules for oil and gas companies provided in SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies.

At September 30, 2003, the Company had undeveloped and developed leaseholds of approximately $1.3 billion and $2.4 billion that would have been classified on the consolidated balance sheet as intangible undeveloped leaseholds and intangible developed leaseholds, respectively, if it had applied the interpretation currently being discussed. The Company will continue to classify its oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as oil and gas properties until further guidance is provided.

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

The following table illustrates the effect on net income and EPS if the Company had applied the fair value recognition provisions of SFAS No. 123, Accounting for Stock-Based Compensation, as amended by SFAS No. 148, to stock-based employee compensation. The fair value of stock options included in the pro forma amounts is not necessarily indicative of future effects on net income and EPS.

The Company uses derivative instruments to manage risks associated with commodity prices, foreign currency exchange rates and interest rates. Derivative instruments that meet the hedge criteria in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, are designated as either cash-flow hedges, fair-value hedges or foreign-currency hedges. 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 as well as foreign currency denominated sales. 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.

As of September 30, 2003, the Company had the following derivative instruments outstanding with average underlying prices that represent hedged prices of commodities at various market locations.

In July 2003, the Company entered into interest rate swap agreements with an aggregate notional amount of $50 million related to principal amounts of $50 million, 5.6% notes due December 1, 2006. The objective of these transactions is to protect the designated debt against changes in fair value due to changes in the benchmark interest rate, which was designated as six-month LIBOR. Under the interest rate swap agreements, the Company receives a fixed rate equal to 5.6 percent per annum and pays the benchmark interest rate plus 3.36 percent. Interest expense on the debt is adjusted to reflect payments made or received under the hedge agreements.

As of September 30, 2003, the Company had the following derivative instruments outstanding related to interest rate and foreign currency swaps.

Based on commodity prices and interest rates as of September 30, 2003, the Company expects to reclassify losses of $19 million ($12 million after tax) to earnings from the balance in accumulated other comprehensive income during the next twelve months. At September 30, 2003, the Company had derivative assets of $10 million and derivative liabilities of $45 million. Of the derivative assets of $10 million, $7 million are included in Other Current Assets and $3 million are included in Other Assets on the Consolidated Balance Sheet. Of the derivative liabilities of $45 million, $24 million are included in Other Current Liabilities.

The derivative assets and liabilities related to commodities represent the difference between hedged prices and market prices on hedged volumes of the commodities as of September 30, 2003. Hedging activities related to cash settlements on commodities decreased revenues $6 million in the third quarter of 2003 and increased revenues $19 million in the third quarter of 2002. Hedging activities related to cash settlements on commodities decreased revenues $58 million in the first nine months of 2003 and increased revenues $116 million in the first nine months of 2002. In addition, non-cash gains of $1 million and non-cash losses of $5 million were recorded in revenues associated with ineffectiveness of cash-flow and fair-value hedges during the third quarter of 2003 and 2002, respectively. Non-cash losses of $1 million and $21 million were recorded in revenues associated with ineffectiveness of cash-flow and fair-value hedges during the first nine months of 2003 and 2002, respectively. Also, non-cash gains of $23 thousand and non-cash losses of $1 million were recorded in revenues associated with changes in the fair value of derivative instruments that do not qualify for hedge accounting during the third quarter of 2003 and 2002, respectively. Non-cash gains of $9 million and non-cash losses of $11 million were recorded in revenues associated with changes in the fair value of derivative instruments that do not qualify for hedge accounting during the first nine months of 2003 and 2002, respectively.

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

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

Based on the Company’s present understanding of the various governmental and civil False Claims Act proceedings described above, the Company believes that it has substantial defenses to these claims and intends to vigorously assert such defenses. The Company is also exploring the possibility of a settlement of these claims. Although there has been no formal demand for damages, the Company currently estimates, based on its communications with the intervenor, that the amount of underpaid royalties on onshore production claimed by the intervenor in these proceedings is approximately $68 million. In the event that the Company is found to have violated the civil False Claims Act, the Company could also be subject to double damages, civil monetary penalties and other sanctions, including a temporary suspension from bidding on and entering into future federal mineral leases and other federal contracts for a defined period of time. The Company has established a reserve that management believes to be adequate to provide for this potential liability based upon its evaluation of this matter.

The Company has also been named as a defendant in the lawsuit styled UNOCAL Netherlands B.V., et al v. Continental Netherlands Oil Company B.V., et al, No. 98-854, filed in 1995 in the District Court in The Hague and currently pending in the Court of Appeal in The Hague, the Netherlands. Plaintiffs, who are working interest owners in the Q-1 Block in the North Sea, have alleged that the Company and other former working interest owners in the adjacent Logger Field in the L16a Block unlawfully trespassed or were otherwise unjustly enriched by producing part of the oil from the adjoining Q-1 Block. The plaintiffs claim that the defendants infringed upon plaintiffs’ right to produce the minerals present in its license area and acted in violation of generally accepted standards by failing to inform plaintiffs of the overlap of the Logger Field into the Q-1 Block. Plaintiffs seek damages of $97.5 million as of January 1, 1997, plus interest. For all relevant periods, the Company owned a 37.5 percent working interest in the Logger Field. Following a trial, the District Court in The Hague rendered a Judgment in

favor of the defendants, including the Company, dismissing all claims. Plaintiffs thereafter appealed. On October 19, 2000, the Court of Appeal in The Hague issued an interim Judgment in favor of the plaintiffs and ordered that additional evidence be presented to the court relating to issues of both liability and damages. The Company and the other defendants are continuing to present evidence to the Court and vigorously assert defenses against these claims. The Company has also asserted claims of indemnity against two of the defendants from whom it had acquired a portion of its working interest share. If the Company is successful in enforcing the indemnities, its working interest share of any adverse judgment could be reduced to 15 percent for some of the periods covered by plaintiffs’ lawsuit. The Company currently does not believe that an unfavorable outcome is probable nor, in the event of an unfavorable outcome, is the Company reasonably able to estimate the possible loss, if any, or range of loss in this lawsuit. Accordingly, there has been no reserve established for this matter.

The Company and its former affiliate, El Paso Natural Gas Company, have also been named as defendants in two class action lawsuits styled Bank of America, et al. v. El Paso Natural Gas Company, et al., Case No. CJ-97-68, and Deane W. Moore, et al. v. Burlington Northern, Inc., et. al., Case No. CJ-97-132, each filed in 1997 in the District Court of Washita County, State of Oklahoma and subsequently consolidated by the court. Plaintiffs contend that defendants underpaid royalties from 1983 to the present on natural gas produced from specified wells in Oklahoma through the use of below-market prices, improper deductions and transactions with affiliated companies and in other instances failed to pay or delayed in the payment of royalties on certain gas sold from these wells. The Plaintiffs seek an accounting and damages for alleged royalty underpayments, plus interest from the time such amounts were allegedly due. Plaintiffs additionally seek the recovery of punitive damages. The plaintiffs have not specified in their pleadings the amount of damages they seek from the Company. The Company believes it has substantial defenses to these claims and is vigorously asserting such defenses. The Company has also asserted contractual claims for indemnity against El Paso Natural Gas Company. The court has certified the plaintiff classes of royalty and overriding royalty interest owners, and the parties are proceeding with pre-trial discovery. A scheduling order for pre-trial proceedings was issued by the court in September 2003. It is anticipated that this matter will be scheduled for trial during 2004. The Company currently does not believe that an unfavorable outcome is probable nor, in the event of an unfavorable outcome, is the Company reasonably able to estimate the possible loss, if any, or range of loss in these lawsuits. Accordingly, there has been no reserve established for this matter.

In addition to the foregoing, the Company and its subsidiaries are named defendants in numerous other lawsuits and named parties in numerous governmental and other proceedings arising in the ordinary course of business, including: claims for personal injury and property damage, claims challenging oil and gas royalty, ad valorem 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. One of the governmental proceedings arises under the provincial laws of Alberta, Canada, and relates to a safety matter at a natural gas processing facility. None of the other governmental proceedings involve foreign governments.

The Company has established reserves for certain legal proceedings which are included in Other Liabilities and Deferred Credits on the Consolidated Balance Sheet. The establishment of a reserve involves a complex estimation process that includes the advice of legal counsel and subjective judgment of management. While management believes these reserves to be adequate, it

is reasonably possible that the Company could incur additional loss with respect to those matters in which reserves have been established of up to approximately $25 million to $30 million in excess of the amounts currently accrued. Future changes in the facts and circumstances could result in actual liability exceeding the estimated ranges of loss and the amounts accrued.

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 or results of operations of the Company, although cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

The fair value of the Company’s long-term debt at September 30, 2003 and December 31, 2002 was approximately $4,534 million and $4,443 million, respectively, based on quoted market prices.

The Company’s reportable segments are U.S., Canada and Other International (Intl). The segments are engaged principally in the exploration for and the development, production and marketing of oil and 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 2002 Form 10-K. There were no intersegment sales during the third quarter and first nine months of 2003. Intersegment sales were $2 million and $17 million during the third quarter and first nine months of 2002, respectively.

The following tables present information about the Company’s reportable segments.

The following is a reconciliation of income before income taxes and cumulative effect of change in accounting principle for reportable segments to consolidated income before income taxes and cumulative effect of change in accounting principle.

The following is a reconciliation of capital expenditures for reportable segments to consolidated capital expenditures.

On January 1, 2003, the Company adopted SFAS No. 143, Asset Retirement Obligations. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. During the first quarter of 2003, the Company recorded a net-of-tax cumulative effect of change in accounting principle charge of $59 million ($95 million before tax), increased long-term liabilities $191 million, net properties $96 million and deferred tax assets $36 million in accordance with the provisions of SFAS No. 143. There was no impact on the Company’s cash flows as a result of adopting SFAS No. 143. The pro forma asset retirement obligation would have been $376 million at January 1, 2002 and $298 million at December 31, 2002 had the Company adopted SFAS No. 143 on January 1, 2002. The asset retirement obligation, which is included on the Consolidated Balance Sheet in Other Liabilities and Deferred Credits, was $369 million at September 30, 2003. Accretion expense during the first nine months of 2003 was $16 million, and is included in Depreciation, Depletion and Amortization expense on the Company’s Consolidated Statement of Income.

For the period ended September 30, 2002, the pro forma effect on net income and earnings per share, had SFAS No. 143 been adopted by the Company on January 1, 2002, would have been as follows.

In May 2003, the Company purchased an additional 50 percent interest in CLAM Petroleum B.V. (CLAM) for approximately $100 million, including cash acquired of $25 million, resulting in a total purchase price for the common equity of approximately $75 million. The Company owned 50 percent of CLAM prior to the acquisition and had accounted for its interest under the equity method of accounting. Effective on the date of acquisition, the Company began consolidating CLAM’s financial results.

All of the Company’s goodwill is assigned to the Canadian reporting unit which consists of all of the Company’s Canadian subsidiaries. The following table reflects the changes in the carrying amount of goodwill during the first nine months of 2003 as it relates to the Canadian reporting unit.

The Company’s effective income tax rate increased to 31 percent for the period ended September 30, 2003 from 20 percent for the year ended December 31, 2002. The period ended September 30, 2003 includes amounts related to the closing of the 1996–1998 IRS tax audit cycle, the reversal of tax reserves no longer required due to the audit closure, normal tax return true-up and adjustments of tax credits. The tax rate for the year ended December 31, 2002 included the reversal of a foreign tax valuation reserve related to the sale of assets in the U.K. sector of the North Sea.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (SFAS No. 150). SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. It is to be implemented by reporting the cumulative effect of a change in an accounting principle for financial instruments created before the issuance date of SFAS No. 150 and still existing at the beginning of the interim period of adoption. Restatement is not permitted. The Company does not expect the requirements of SFAS No. 150 to have a material impact on its consolidated financial position or results of operations.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement No. 133 on Derivative Instruments and Hedging Activities (SFAS No. 149). SFAS No. 149 improves financial reporting by requiring that contracts with comparable characteristics be accounted for similarly. In particular, SFAS No. 149 clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, clarifies when a derivative contains a financing component, amends the definition of an “underlying” to conform it to language used in FIN No. 45 and amends certain other existing pronouncements. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. In addition, with some exceptions, all provisions of SFAS No. 149 should be applied prospectively. The Company does not expect the requirements of SFAS No. 149 to have a material impact on its consolidated financial position or results of operations.

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

The Company expects fourth quarter 2003 production volumes to average between 2,590 and 2,845 MMCFE per day. Due to significant progress recently made on several major projects in Algeria, China, the East Irish Sea, and the Deep Madison Formation at Madden Field (Madden), the Company expects fourth quarter 2003 production to increase between 5 and 15 percent compared to the same period in 2002. In late June 2003, the production at Madden was curtailed due to deformations in the gas gathering lines. Repairs to the gathering lines are currently proceeding as planned and by yearend, production at Madden is expected to be about the level it was prior to the curtailment. The Company expects full year 2003 production volumes to average between 2,500 and 2,640 MMCFE per day and expects full year 2004 production volumes to average between 2,650 and 2,850 MMCFE per day. The Company targets the delivery of 3-8 percent production volume growth and expects to achieve the high end of this range in 2004.

Commodity prices are impacted by many factors that are outside of the Company’s control. Historically, commodity prices have been volatile and the Company expects them to remain volatile. Commodity prices are affected by changes in market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and

other factors. As a result, the Company cannot accurately predict future natural gas, NGLs and crude oil prices, and therefore, cannot accurately predict 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. In 2003, excluding acquisitions, the Company expects to spend approximately $1.5 billion on development, exploration and plants and pipeline capital. During the first nine months of 2003, the Company spent $229 million on acquisitions. The Company expects its reserve replacement costs to range between $1.15 and $1.35 per MCFE for 2003. The Company also expects to replace 100 percent of its production from internal sources during 2003.

The Company’s total debt to total capital (total capital is defined as total debt and stockholders’ equity) ratio at September 30, 2003 and December 31, 2002 was 44 percent and 51 percent, respectively. Based on the current price environment, management believes that the Company will generate sufficient cash flows from operations to fund its 2003 capital expenditures (excluding any major acquisition(s)), dividend payments and Common Stock repurchases. At September 30, 2003, the Company had $720 million of cash and cash equivalents on hand.

The Company had credit commitments in the form of revolving credit facilities (Revolvers) as of September 30, 2003. The Revolvers are comprised of agreements for $600 million, $400 million and Canadian $468 million (U.S. $346 million). The $600 million Revolver expires in December 2006 and the $400 million and Canadian $468 million Revolvers expire in December 2004 unless renewed by mutual consent. The Company has the option to convert the outstanding balances on the $400 million and Canadian $468 million Revolvers to one-year and five-year plus one day term notes, respectively. Under the covenants of the Revolvers, Company debt cannot exceed 60 percent of capitalization (as defined in the agreements). The Revolvers are available to cover debt due within one year, therefore, commercial paper, credit facility notes and fixed-rate debt due within one year are generally classified as long-term debt. At September 30, 2003, there were no amounts outstanding under the Revolvers and no outstanding commercial paper.

Net cash provided by operating activities during the first nine months of 2003 was $1,987 million compared to $1,173 million in 2002. The increase was primarily due to higher net income, principally as a result of higher commodity prices.

In December 2000, the Company’s Board of Directors authorized the repurchase of up to $1 billion of the Company’s Common Stock. Through April 30, 2003, the Company had repurchased $816 million of its Common Stock under the program authorized in December 2000. In April 2003, the Company’s Board of Directors voted to restore the authorization level to $1 billion effective May 1, 2003. During the first nine months of 2003, the Company repurchased approximately 5.8 million shares of its Common Stock for approximately $277 million and, as of September 30, 2003, has authority to repurchase an additional $845 million of its Common Stock under the current authorization. As of September 30, 2003, $5 million of the share repurchases were not cash settled during the period. Since December 2000, the Company has repurchased approximately 22 million shares or $971 million of its Common Stock. In 2001, the Company’s Board of Directors authorized the Company to redeem, exchange or repurchase up to an aggregate of $990 million principal amount of debt securities.

The Company and its subsidiaries are named defendants in numerous lawsuits and named parties in numerous governmental and other proceedings arising in the ordinary course of business. While the 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 or results of operations of the Company, although cash flow could be significantly impacted in the reporting periods in which such matters are resolved.

The Company has 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 for the first nine months of 2003 totaled $1,472 million compared to $1,430 million in 2002. The Company invested $1,080 million on internal development and exploration of oil and gas properties during the first nine months of 2003 compared to $669 million in 2002. The Company invested $229 million for property acquisitions in the first nine months of 2003 compared to $596 million in 2002. Property acquisitions during the first nine months of 2003 included the acquisition of an additional 50 percent interest in CLAM Petroleum B.V. for approximately $100 million. For more information on this acquisition, see Note 9 of Notes to Consolidated Financial Statements. Property acquisitions during the first nine months of 2002 included $344 million and $140 million, respectively, for the purchase of certain assets from ATCO Gas and Pipelines Ltd., a Canadian regulated gas utility and the purchase of certain oil and gas properties located in Wise and Denton Counties, Texas.

On October 21, 2003, the Board of Directors declared a quarterly common stock cash dividend of $0.15 per share. The record and payment dates for the quarterly dividend are December 10, 2003 and January 9, 2004, respectively. On July 23, 2003, the Company increased its quarterly cash dividend from $0.1375 per share to $0.15 per share, representing a 9 percent increase.

properties, and included as intangible assets on the Company’s consolidated balance sheets. In addition, the disclosures required by SFAS No. 141 and No. 142 related to intangibles would be included in the notes to the consolidated financial statements. Historically, the Company, like many other oil and gas companies, have included oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract reserves as part of the oil and gas properties, even after SFAS No. 141 and No. 142 became effective.

The Company reported net income of $267 million or $1.33 diluted earnings per common share in the third quarter of 2003 compared to net income of $79 million or $0.39 diluted earnings per common share in 2002. Net income in the third quarter of 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 related to the sale of assets in the U.K. sector of the North Sea.

Revenues increased $407 million to $1,059 million in the third quarter of 2003 compared to $652 million in the third quarter of 2002. As described below, the $407 million increase in revenues primarily consists of $368 million related to higher commodity prices and $24 million related to higher sales volumes. Details of commodity prices and sales volumes variances are described below.

Average gas prices, including a $0.04 realized loss per MCF related to hedging activities, increased $1.91 per MCF in the third quarter of 2003 to $4.68 per MCF from $2.77 per MCF, including an $0.11 realized gain per MCF related to hedging activities in the third quarter of 2002. Higher average natural gas prices resulted in increased revenues of $333 million during the third quarter of 2003. Average NGLs prices increased $5.20 per barrel in the third quarter of 2003 to $20.42 per barrel from $15.22 per barrel in the third quarter of 2002, resulting in higher revenues of $30 million during the third quarter of 2003. Average oil prices, which included no gains or losses related to hedging activities, increased $1.26 per barrel in the third quarter of 2003

to $27.16 per barrel from $25.90 per barrel in the third quarter of 2002. Higher average oil prices resulted in increased revenues of $5 million during the third quarter of 2003.

Average gas sales volumes increased 50 MMCF per day in the third quarter of 2003 to 1,889 MMCF per day from 1,839 MMCF per day in the third quarter of 2002, resulting in increased revenues of $13 million during the third quarter of 2003. Average NGLs sales volumes increased 3.4 MBbls per day in the third quarter of 2003 to 63.0 MBbls per day from 59.6 MBbls per day in the third quarter of 2002, resulting in higher revenues of $5 million from quarter to quarter. Average oil sales volumes increased 2.6 MBbls per day in the third quarter of 2003 to 47.3 MBbls per day from 44.7 MBbls per day in the third quarter of 2002, increasing revenues $6 million during the third quarter of 2003. Average gas sales volumes increased 146 MMCF per day primarily as a result of the drilling programs in Canada, south Louisiana and the Fort Worth Basin. This increase was partially offset by a decrease of 100 MMCF per day primarily due to asset sales in 2002 in the Gulf of Mexico and the U.K. sector of the North Sea and declines in Madden due to the production curtailment related to repairs on the gas gathering lines. Average NGLs sales volumes increased 2.8 MBbls per day in Canada and the San Juan Basin. Average oil sales volumes increased 12.6 MBbls per day primarily due to higher production at Ourhoud Field and the Company-operated MLN Field in Algeria, Cedar Creek and south Louisiana partially offset by a decrease of 10.4 MBbls per day primarily due to asset sales in 2002 in the Gulf of Mexico, Williston Basin and the U.K. sector of the North Sea.

Total costs and other income – net were $663 million in the third quarter of 2003 compared to $585 million in the third quarter of 2002. The $78 million increase in total costs and other income – net was primarily due to a $44 million increase in depreciation, depletion and amortization (DD&A), an $18 million increase in taxes other than income taxes and a $12 million decrease in other income – net.

DD&A increased primarily due to higher natural gas and crude oil production volumes and higher unit-of-production rates on the Canadian properties which have higher rates than average unit-of-production rates for the Company, partially offset by the divestiture of higher cost properties in 2002. Taxes other than income taxes increased primarily due to higher production taxes resulting from higher oil and gas revenues. Other income – net decreased primarily due to lower interest income.

Income taxes were an expense of $129 million in the third quarter of 2003 compared to a benefit of $12 million in the third quarter of 2002. The increase in tax expense was primarily due to higher pretax income. The Company recorded tax benefits of $26 million in the third quarter of 2003 compared to $18 million in the third quarter of 2002 related to interest deductions allowed in both the U.S. and Canada on transactions associated with cross-border financing.

Results of Operations – First Nine Months of 2003 Compared to First Nine Months of 2002

The Company reported net income of $814 million or $4.05 diluted earnings per common share in the first nine months of 2003 compared to net income of $297 million or $1.47 diluted

earnings per common share in the first nine months of 2002. Net income in the first nine months of 2003 included a net-of-tax cumulative effect of change in accounting principle charge of $59 million or $0.29 per diluted earnings per common share related to the adoption of Statement of Financial Accounting Standards No. 143, Asset Retirement Obligations. See Note 8 of Notes to Consolidated Financial Statements for more information. Net income in the first nine months of 2003 also included a net after tax charge of $18 million or $0.09 per diluted share related to the impairment of oil and gas properties. 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 tax valuation reserve of $27 million or $0.13 per diluted share related to the sale of assets in the U.K. sector of the North Sea.

Revenues increased $1,108 million to $3,246 million in the first nine months of 2003 compared to $2,138 million in the first nine months of 2002. As described below, the $1,108 million increase in revenues primarily consists of $1,176 million related to higher commodity prices, $20 million due to higher revenues related to ineffectiveness on hedging activities, $20 million due to higher revenues related to changes in fair value instruments that do not qualify for hedge accounting and $11 million related to higher NGLs sales volumes, partially offset by $107 million related to lower natural gas and oil sales volumes and $19 million related to the sale of the Val Verde Plant in June 2002.

Average gas prices, including an $0.11 realized loss per MCF related to hedging activities, increased $1.98 per MCF in the first nine months of 2003 to $4.98 per MCF from $3.00 per MCF, including a $0.21 realized gain per MCF related to hedging activities in the first nine months of 2002. Higher average natural gas prices resulted in increased revenues of $1,017 million during the first nine months of 2003. Average NGLs prices increased $6.46 per barrel in the first nine months of 2003 to $20.34 per barrel from $13.88 per barrel in the first nine months of 2002, resulting in higher revenues of $111 million during first nine months of 2003. Average oil prices, including a $0.13 realized loss per barrel related hedging activities, increased $4.16 per barrel in first nine months of 2003 to $28.06 per barrel from $23.90 per barrel. Higher average oil prices resulted in increased revenues of $48 million during the first nine months of 2003.

Average oil sales volumes decreased 10.6 MBbls per day in the first nine months of 2003 to 42.5 MBbls per day from 53.1 MBbls per day in the first nine months of 2002, reducing revenues $69 million during the first nine months of 2003. Average gas sales volumes decreased 47 MMCF per day in the first nine months of 2003 to 1,880 MMCF per day from 1,927 MMCF per day in the first nine months of 2002, resulting in decreased revenues of $38 million during the first nine months of 2003. Average NGLs sales volumes increased 3.0 MBbls per day in the first nine months of 2003 to 63.3 MBbls per day from 60.3 MBbls per day in the first nine months of 2002, resulting in higher revenues of $11 million from period to period. Average oil sales volumes decreased 16.9 MBbls per day primarily due to asset sales in 2002 in the Gulf of Mexico, Canada, the U.K. sector of the North Sea and the Williston Basin partially offset by an increase of 5.7 MBbls per day resulting from higher production at Ourhoud Field and the Company-operated MLN Field in Algeria. Average gas sales volumes decreased 140 MMCF per day primarily due to asset sales in 2002 in the Gulf of Mexico, the U.K. sector of the North Sea,

Sonora, south Texas and the Permian Basin partially offset by an increase of 98 MMCF per day primarily as a result of the drilling programs in Canada and the Fort Worth Basin. Average NGLs sales volumes increased 2.9 MBbls per day in the San Juan Basin.

Total costs and other income – net were $1,975 million in the first nine months of 2003 compared to $1,803 million in first nine months of 2002. The $172 million increase in total costs and other income – net was primarily due to a $69 million decrease in gain on disposal of assets, a $49 million increase in taxes other than income taxes, a $38 million increase in DD&A, a $35 million increase in transportation expenses, a $31 million increase in other expense-net, a $30 million increase in the impairment of oil and gas properties, a $6 million increase in administrative expenses, partially offset by a $39 million decrease in exploration costs, a $33 million decrease in production and processing expenses and a $14 million decrease in interest expense.

Gain on disposal of assets decreased primarily due to the divestiture program that was initiated by the Company in the second quarter of 2002 and completed in late 2002. Taxes other than income taxes increased primarily due to higher production taxes resulting from higher oil and gas revenues. DD&A increased primarily due to higher unit-of-production rates on the Canadian properties which have higher rates than average unit-of-production rates for the Company partially offset by the divestiture of higher cost properties in 2002 and lower oil and gas production volumes. Transportation expenses increased primarily due to higher contract rates primarily resulting from the sale of the Val Verde Plant in 2002. Other expense-net increased primarily due to lower interest income and higher expenses related to foreign currency transactions. The impairment of oil and gas properties increased due to performance related downward reserve adjustments associated with certain properties primarily in Canada. Exploration costs decreased primarily due to lower drilling rig expenses of $33 million attributable to a loss incurred by the Company in 2002 related to the remaining terms of a sublease of a deepwater drilling rig, lower amortization of undeveloped lease costs of $13 million, lower geological and geophysical and other expenses of $12 million partially offset by higher exploratory dry hole costs of $19 million. Production and processing expenses decreased primarily due to lower well operating costs related to the Shelf and other asset sales in 2002. Interest expense decreased primarily due to lower debt balances and higher capitalized interest during the first nine months of 2003.

Income taxes were an expense of $398 million in the first nine months of 2003 compared to $38 million in the first nine months of 2002. The increase in tax expense was primarily due to higher pretax income. The Company also recorded benefits of $63 million in the first nine months of 2003 compared to $73 million in 2002 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. The Company also recorded a net tax benefit of $31 million in the first nine months of 2003 related to the closing of the 1996–1998 IRS tax audit cycle, the reversal of tax reserves no longer required due to the audit closure, normal tax return true-up and adjustments of tax credits. Additionally, in the first nine months of 2003, the Company resolved all disputes under tax sharing agreements with certain former affiliates. As a result, during the first nine months of 2003, the Company recorded a $3 million decrease in income tax expense.

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 futures contract price for a particular month and the actual cash price received for that month in a North America producing basin or at a North America market hub, which is referred to as the “basis differential.” Basis differentials can vary widely depending on various factors, including but not limited to, local supply and demand.

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

The Company uses a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of crude oil and natural gas may have on the fair value of the Company’s derivative instruments. For example, at September 30, 2003, an assumed 10 percent

adverse movement in commodity prices (an increase in the underlying commodities prices) would result in a $25 million increase in the fair value of the net liabilities related to commodity hedging activities.

For purposes of calculating the hypothetical change in fair value, the relevant variables include the type of commodity, the commodity futures prices, the volatility of commodity prices and the basis and quality differentials. The hypothetical change in fair value is calculated by multiplying the difference between the hypothetical price (adjusted for any basis or quality differentials) and the contractual price by the contractual volumes.

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-15(e) and 15d-15(e) to the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on this evaluation, the Company’s Chief Executive Officer and Chief Financial Officer believe that the disclosure controls and procedures were effective as of the end of the period covered by this report 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.

The Company’s management does not expect that its disclosure controls and procedures or its internal controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some person or by collusion of two or more people. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Accordingly, the Company’s disclosure controls and procedures are designed to provide reasonable, not absolute, assurance that the objectives of our disclosure control system are met and, as set forth above, the Company’s management has concluded, based on their evaluation as of the end of the

period, that our disclosure controls and procedures were sufficiently effective to provide reasonable assurance that the objectives of our disclosure control system were met.

On July 1, 2003, the Company’s Canadian segment implemented a new accounting system that contains general ledger, payables and receivables, fixed assets, joint venture and other related accounting functions. Certain new accounting processes and procedures were implemented at that time to support the new software. This system change is the result of the Company’s process to evaluate and upgrade or replace its systems and related processes to support the Company’s evolving operational needs. This system enhancement will allow the Company to fully integrate the significant acquisitions in Canada and provide a scalable accounting platform for continued growth in that segment. During the quarter ended September 30, 2003, the new system and supporting processes were used by the Canadian segment to record and report its financial results which are included in the Company’s consolidated totals. Following evaluation, management believes that the new system has been successfully implemented. Except for the new Canadian accounting system, there was no change in the Company’s internal control over financial reporting during the Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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 2002 Form 10-K.

On July 24, 2003, the Company furnished on Form 8-K, pursuant to Item 12, Results of Operations, and Item 9, Regulation FD Disclosure, a press release announcing its earnings results for the second quarter of fiscal year 2003.

Pursuant to the requirements 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
		Executive Vice President and
		Chief Financial Officer


By		/S/ JOSEPH P. McCOY

		Joseph P. McCoy
		Vice President, Controller and
		Chief Accounting Officer

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

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

	THIRD QUARTER						NINE MONTHS
	2003			2002			2003			2002
	(In Millions, Except per Share Amounts)
Revenues	$	1,059		$	652		$	3,246		$	2,138

Costs and Other Income - Net
Taxes Other than Income Taxes		47			29			141			92
Transportation Expense		100			98			301			266
Production and Processing		118			117			332			365
Depreciation, Depletion and Amortization		239			195			669			631
Exploration Costs		55			53			175			214
Impairment of Oil and Gas Properties		—			—			30			—
Administrative		38			36			119			113
Interest Expense		66			65			193			207
(Gain)/Loss on Disposal of Assets		2			6			2			(67	)
Other Expense (Income) - Net		(2	)		(14	)		13			(18	)

Total Costs and Other Income - Net		663			585			1,975			1,803

Income Before Income Taxes and Cumulative Effect of Change in Accounting Principle		396			67			1,271			335
Income Tax Expense (Benefit)		129			(12	)		398			38

Income Before Cumulative Effect of Change in Accounting Principle		267			79			873			297
Cumulative Effect of Change in Accounting Principle - Net		—			—			(59	)		—

Net Income	$	267		$	79		$	814		$	297

Earnings per Common Share

Basic
Before Cumulative Effect of Change in Accounting Principle	$	1.34		$	0.39		$	4.37		$	1.47
Cumulative Effect of Change in Accounting Principle - Net		—			—			(0.29	)		—

Net Income	$	1.34		$	0.39		$	4.08		$	1.47

Diluted
Before Cumulative Effect of Change in Accounting Principle	$	1.33		$	0.39		$	4.34		$	1.47
Cumulative Effect of Change in Accounting Principle - Net		—			—			(0.29	)		—

Net Income	$	1.33		$	0.39		$	4.05		$	1.47

	September 30, 2003			December 31, 2002
	(In Millions, Except Share Data)
ASSETS
Current Assets
Cash and Cash Equivalents	$	720		$	443
Accounts Receivable		540			515
Inventories		59			48
Other Current Assets		68			55

		1,387			1,061

Oil & Gas Properties (Successful Efforts Method)		15,467			12,716
Other Properties		1,330			1,140

		16,797			13,856
Accumulated Depreciation, Depletion and Amortization		6,728			5,353

Properties - Net		10,069			8,503

Goodwill		940			803

Other Assets		181			278

Total Assets	$	12,577		$	10,645

LIABILITIES
Current Liabilities
Accounts Payable	$	719		$	809
Taxes Payable		63			44
Accrued Interest		65			61
Other Current Liabilities		62			45
Current Maturities of Long-term Debt		74			63

		983			1,022

Long-term Debt		3,868			3,853

Deferred Income Taxes		2,000			1,436

Commodity Hedging Contracts and Other Derivatives		21			33

Other Liabilities and Deferred Credits		690			469

Commitments and Contingencies (Note 5)

STOCKHOLDERS’ EQUITY
Preferred Stock, Par Value $.01 Per Share (Authorized 75,000,000 Shares)		—			—
Common Stock, Par Value $.01 Per Share (Authorized 325,000,000 Shares; Issued 241,188,688 Shares)		2			2
Paid-in Capital		3,943			3,941
Retained Earnings		2,404			1,675
Deferred Compensation - Restricted Stock		(13	)		(9	)
Accumulated Other Comprehensive Income (Loss)		456			(164	)
Cost of Treasury Stock (42,550,394 and 39,749,431 Shares for 2003 and 2002, respectively)		(1,777	)		(1,613	)

Stockholders’ Equity		5,015			3,832

Total Liabilities and Stockholders’ Equity	$	12,577		$	10,645

	NINE MONTHS
	2003			2002
	(In Millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	814		$	297
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities
Depreciation, Depletion and Amortization		669			631
Deferred Income Taxes		257			(67	)
Exploration Costs		175			214
(Gain)/Loss on Disposal of Assets		2			(67	)
Impairment of Oil and Gas Properties		30			—
Cumulative Effect of Change in Accounting Principle - Net		59			—
Changes in Derivative Fair Values		(9	)		32
Working Capital Changes
Accounts Receivable		34			51
Inventories		(6	)		(6	)
Other Current Assets		(11	)		(9	)
Accounts Payable		(59	)		19
Taxes Payable		21			117
Accrued Interest		4			8
Other Current Liabilities		(4	)		(9	)
Changes in Other Assets and Liabilities		11			(38	)

Net Cash Provided By Operating Activities		1,987			1,173

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Properties		(1,528	)		(1,496	)
Proceeds from Sales and Other		(1	)		1,055

Net Cash Used In Investing Activities		(1,529	)		(441	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-term Debt		—			454
Reduction in Long-term Debt		—			(879	)
Dividends Paid		(55	)		(84	)
Common Stock Purchases		(272	)		—
Common Stock Issuances		103			9
Other		(3	)		3

Net Cash Used In Financing Activities		(227	)		(497	)

Effect of Exchange Rate Changes on Cash and Cash Equivalents		46			(7	)

INCREASE IN CASH AND CASH EQUIVALENTS		277			228

CASH AND CASH EQUIVALENTS
Beginning of Year		443			116

End of Period	$	720		$	344

	Third Quarter				Nine Months
	2003		2002		2003		2002
	(In Millions, Except per Share Amounts)
Net income - as reported	$	267	$	79	$	814	$	297
Pro forma stock based employee compensation cost, after tax		3		3		9		8

Net income - pro forma	$	264	$	76	$	805	$	289

Basic EPS - as reported	$	1.34	$	0.39	$	4.08	$	1.47
Basic EPS - pro forma		1.33		0.38		4.03		1.44
Diluted EPS - as reported		1.33		0.39		4.05		1.47
Diluted EPS - pro forma	$	1.32	$	0.38	$	4.01	$	1.43

Settlement Period	Derivative Instrument	Hedge Strategy	Notional Amount			Average Underlying Prices		Fair Value Asset (Liability) (In Millions)
Settlement Period	Derivative Instrument	Hedge Strategy	Gas (MMBTU)	Oil (Barrels)	Electricity (MWh)	Average Underlying Prices
2003	Swap	Cash Flow Hedge	3,923,923			$	2.97	$	(5	)
	Purchased Put	Cash Flow Hedge	56,249,084				3.37		2
	Purchased Put	Not Designated	38,419,084				2.53		—
	Written Call	Cash Flow Hedge	56,249,084				5.32		(7	)
	Written Call	Not Designated	920,000				5.00		—
	Written Put	Not Designated	55,789,084				2.50		—
	Purchased Put	Cash Flow Hedge		460,000			25.00		—
	Written Call	Cash Flow Hedge		460,000			36.00		—
	Swap	Fair Value Hedge	631,600				3.13		1
	N/A	Fair Value Hedge (Obligation)	631,600				3.13		(1	)
	Purchased Call	Cash Flow Hedge			44,160		47.29		—
	Written Put	Cash Flow Hedge			44,160		31.03		—

2004	Swap	Cash Flow Hedge	15,610,390				3.13		(17	)
	Purchased Put	Cash Flow Hedge	14,033,770				4.20		5
	Purchased Put	Not Designated	11,351,257				3.15		1
	Written Call	Cash Flow Hedge	14,033,770				6.87		(2	)
	Written Put	Not Designated	11,351,257				3.15		(1	)
	Purchased Put	Cash Flow Hedge		455,000			25.00		1
	Purchased Put	Not Designated		455,000			20.00		—
	Written Call	Cash Flow Hedge		455,000			33.59		—
	Written Put	Not Designated		455,000			20.00		—
	Swap	Fair Value Hedge	2,336,800				2.99		3
	N/A	Fair Value Hedge (Obligation)	2,336,800				3.03		(3	)

2005	Swap	Cash Flow Hedge	10,511,522				3.12		(10	)
	Swap	Fair Value Hedge	1,579,200				2.82		2
	N/A	Fair Value Hedge (Obligation)	1,579,200				2.83		(2	)

2006 to 2007	Swap	Cash Flow Hedge	1,672,500			$	3.06		(2	)

								$	(35	)

	Third Quarter				Nine Months
	As Reported		Pro Forma		As Reported		Pro Forma
	(In Millions, Except per Share Amounts)
Net income	$	79	$	78	$	297	$	292

Earnings per share:
Basic		0.39		0.39		1.47		1.45
Diluted	$	0.39	$	0.39	$	1.47	$	1.45

	(In Millions)
Balance - December 31, 2002	$	803
Changes in foreign exchange rates during the period		137

Balance - September 30, 2003	$	940

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.

31.1		Rule 13a-14(a)/15d-14(a) Certification executed by Bobby S. Shackouls, Chairman of the Board, President and Chief Executive Officer of the Company

31.2		Rule 13a-14(a)/15d-14(a) Certification executed by Steven J. Shapiro, Executive Vice President and Chief Financial Officer of the Company

32.1		Section 1350 Certification

32.2		Section 1350 Certification

	Third Quarter
	2003								2002
	U.S.		Canada		Intl		Total		U.S.		Canada		Intl			Total
	(In Millions)
Revenues	$	524	$	471	$	64	$	1,059	$	368	$	249	$	35		$	652
Income (loss) before income taxes and cumulative effect of change in accounting principle		269		225		9	$	503		119		49		(10	)		158
Capital expenditures	$	114	$	191	$	89	$	394	$	244	$	84	$	115		$	443

	Nine Months
	2003								2002
	U.S.		Canada		Intl		Total		U.S.		Canada		Intl			Total
	(In Millions)
Revenues	$	1,604	$	1,488	$	154	$	3,246	$	1,194	$	814	$	130		$	2,138
Income (loss) before income taxes and cumulative effect of change in accounting principle		865		734		15		1,614		597		142		(89	)		650
Capital expenditures	$	449	$	595	$	418	$	1,462	$	370	$	709	$	321		$	1,400