UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

For the quarterly period ended March 31, 2004

OR

Commission File Number 1-9971

BURLINGTON RESOURCES INC.

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 þ            No o

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

Yes þ            No o

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

Table of Contents

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF INCOME
(UNAUDITED)

See accompanying Notes to Consolidated Financial Statements.

2

BURLINGTON RESOURCES INC.
CONSOLIDATED BALANCE SHEET
(UNAUDITED)

See accompanying Notes to Consolidated Financial Statements.

3

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

See accompanying Notes to Consolidated Financial Statements.

4

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

1. BASIS OF PRESENTATION

     The 2003 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 197 million and 201 million for the first quarter of 2004 and 2003, 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 198 million and 202 million for the first quarter of 2004 and 2003, respectively. For the periods ended March 31, 2004 and 2003, approximately 1 million and 3 million shares, respectively, attributable to the potential exercise of outstanding options were excluded from the calculation of diluted EPS because the effect was antidilutive. The Company has no convertible securities affecting EPS, therefore, no adjustments related to convertible securities were made to reported net income in the computation of EPS.

Other

     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 intangible assets separately from goodwill. SFAS No. 142 established 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. One interpretation being considered relative to these standards is that oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract reserves for both undeveloped and developed leaseholds should be classified separately from oil and gas properties, and included as intangible assets on the Company’s consolidated balance sheets. Historically, the Company, like many other oil and gas companies, has 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

5

6

3. COMPREHENSIVE INCOME (LOSS)

4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

     The Company uses derivative instruments to manage risks associated with natural gas and crude oil price volatility as well as interest rate and foreign currency exchange rate fluctuations. Derivative instruments that meet the hedge criteria in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, are designated as 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 natural gas and crude oil sales due to changes in market prices. Fair-value hedges are used by the Company to hedge or offset the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment. In addition to hedges of commodity prices, the Company also uses foreign-currency swaps to hedge its exposure to exchange rate fluctuations related to its Canadian subsidiaries. Derivative instruments that do not meet the hedge criteria in SFAS No. 133 are not designated as hedges.

7

     As of March 31, 2004, the Company had the following derivative instruments outstanding with average underlying prices that represent hedged prices of commodities at various market locations.

     As of March 31, 2004, the Company had the following derivative instruments outstanding related to interest rate and foreign currency swaps.

     Based on commodity prices and foreign exchange rates as of March 31, 2004, the Company expects to reclassify losses of $49 million ($30 million after tax) to earnings from the balance in accumulated other comprehensive loss during the next twelve months. At March 31, 2004, the Company had derivative assets of $8 million and derivative liabilities of $70 million. Of the derivative assets of $8 million, $6 million and $2 million are included in Other Current Assets and Other Assets, respectively, on the Consolidated Balance Sheet. Of the derivative liabilities of $70 million, $14 million are included in Other Liabilities and Deferred Credits on the Consolidated Balance Sheet.

8

     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 March 31, 2004. Hedging activities related to cash settlements on commodities decreased revenues $1 million and $41 million in the first quarter of 2004 and 2003, respectively. In addition, non-cash gains of $438 thousand and non-cash losses of $1 million were recorded in revenues associated with ineffectiveness of cash-flow and fair-value hedges during the first quarter of 2004 and 2003, respectively. Also, non-cash losses of $39 thousand and non-cash gains of $6 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 quarter of 2004 and 2003, respectively.

5. COMMITMENTS AND CONTINGENCIES

     The Company and numerous other oil and gas companies have been named as defendants in various lawsuits alleging violations of the civil False Claims Act. These lawsuits 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. On December 5, 2003, the United States Judicial Panel on Multidistrict Litigation entered an order transferring the cases alleging claims of below-market prices, improper deductions, and transactions with affiliated companies for further pre-trial proceedings and trial in Wright v. AGIP, 5:03CV264, United States District Court for the Eastern District of Texas, Texarkana Division. The cases alleging improper measurement techniques remain pending in MDL-1293.

     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.

9

     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. After receiving additional evidence from the parties, the Court of Appeals subsequently issued a ruling in favor of defendants. In an interim judgment issued on December 18, 2003, the Court of Appeals found that defendants should not have assumed that they were extracting oil from the Q-1 Block, that Unocal was not entitled to compensation for any production occurring prior to 1992 and that damages, if any, would be limited to the proceeds Unocal would have received for oil extracted from the Q-1 Block, less the costs Unocal would have incurred to produce the oil from an existing well in the L16a Block. The Court of Appeals ordered that further evidence be presented to a court appointed expert to determine whether any damages had been suffered by Unocal. 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. However, through pre-trial discovery, plaintiffs have provided defendants with alternative theories of recovery claiming monetary damages of up to $263.6 million in principal, plus interest, punitive damages and

10

attorney’s fees. The Company believes it has substantial defenses to these claims and is vigorously asserting such defenses. The Company and El Paso Natural Gas Company have asserted contractual claims for indemnity against each other. The court has certified the plaintiff classes of royalty and overriding royalty interest owners, and the parties are proceeding with pre-trial discovery. 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. None of the 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 an 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 legal 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.

6. LONG-TERM DEBT

     The fair value of the Company’s long-term debt at March 31, 2004 and December 31, 2003 was approximately $4,500 million and $4,483 million, respectively, based on quoted market prices.

11

7. SEGMENT AND GEOGRAPHIC INFORMATION

     The Company’s reportable segments are U.S., Canada and Other International. The Company is engaged principally in the exploration for and the development, production and marketing of natural gas, crude oil, and NGLs. 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 2003 Form 10-K.

     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.

12

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

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

8. ASSET RETIREMENT OBLIGATIONS

     On January 1, 2003, the Company adopted SFAS No. 143, Asset Retirement Obligations. 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). The asset retirement obligations of $443 million are included on the Consolidated Balance Sheet in Other Liabilities and Deferred Credits. Accretion expense is included in Depreciation, Depletion and Amortization expense on the Company’s Consolidated Statement of Income.

     The following table reflects the changes of the asset retirement obligations during the first quarter of 2004.

13

9. GOODWILL

     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 quarter of 2004 as it relates to the Canadian reporting unit.

10. INCOME TAXES

     The Company’s effective income tax rate increased to 35 percent for the period ended March 31, 2004 from 20 percent for the year ended December 31, 2003. The year ended December 31, 2003 included a tax benefit of $203 million or 13 percent related to the reduction in the Canadian federal income tax rate.

11. RETIREMENT BENEFITS

     The Company’s U.S. pension plans are non-contributory defined benefit plans covering all eligible U.S. employees. The benefits are based on years of credited service and final average compensation. Effective January 1, 2003, the Company amended its U.S. pension plan to provide cash balance benefits to new employees. U.S. employees hired before January 1, 2003, were given the choice to remain in the prior plan or accrue future benefits under the cash balance formula. Contributions to the tax qualified plans are limited to amounts that are currently deductible for tax purposes. Contributions are intended to provide not only for benefits attributed to service-to-date but also for those expected to be earned in the future. Burlington Resources Canada (Hunter) Ltd. also provides a pension plan and postretirement benefits to a closed group of employees and retirees.

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

14

     During the first quarter of 2004, the Company contributed $4 million to its U.S. pension plans. The Company expects to contribute a total of $11 million to its U.S. pension plans during 2004. The assumptions used in the valuation of the Company’s retirement plans and the target investment allocations have not changed since December 31, 2003.

12. STOCK SPLIT

     On January 21, 2004, the Company’s Board of Directors announced a 2-for-1 split on the Company’s Common Stock in the form of a share distribution, subject to shareholder approval of an amendment to the Company’s Certificate of Incorporation to increase the number of authorized shares of the Company’s Common Stock from 325 million to 650 million. On April 21, 2004, shareholders approved the amendment. As a result, the stock split is payable on June 1, 2004 to shareholders of record on May 5, 2004. The pro forma effect on the March 31, 2004 balance sheet is to reduce Paid-in Capital by $2 million and increase Common Stock by $2 million. Common shares outstanding, giving retroactive effect to the stock split at March 31, 2004 and December 31, 2003 are 397 million and 395 million, respectively. Pro forma earnings per share, giving retrospective effect to the stock split are as follows.

15

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

Outlook

     The Company strives to achieve both production growth and sector-leading financial returns when compared to certain other independent oil and gas exploration and production companies. Achieving this requires continuous development of natural gas and crude oil reserves to fuel growth, while maintaining focus on cost structure and capital efficiency. The Company has a goal to achieve between 3 and 8 percent average annual production growth and expects to generate cumulative production growth of 20 percent over the three-year period beginning in 2004. The Company expects to achieve production volume growth at the top of the 3 to 8 percent range in 2004. This production growth is expected to be driven by steady production growth in North America and accelerating production growth from several international projects. The Company expects second quarter production volumes to average between 2,606 and 2,804 MMCFE per day and expects full year 2004 production volumes to average between 2,695 and 2,903 MMCFE per day. The Company also expects costs and expenses, on a unit basis in 2004, to be essentially in the range of year 2003’s costs and expenses, except for Depreciation, Depletion and Amortization (DD&A). DD&A expense is expected to be higher primarily due to higher production volumes and higher rates resulting from international start-up projects and the weakening of the U.S. dollar.

     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 that way in the future. Commodity prices are affected by supply, 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, it cannot determine what impact increases or decreases in production volumes will have on future revenues or net operating cash flows. However, based on the estimated range of average daily natural gas production in 2004, the Company estimates that a $0.10 per MCF change in natural gas prices would have an impact on full year 2004 revenues of approximately $68 to $73 million. Also, based on the estimated range of average daily crude oil production in 2004, the Company estimates that a $1.00 per barrel change in crude oil prices would have an impact on full year 2004 revenues of approximately $27 to $30 million.

     Finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to the Company’s long-term success. Currently, the Company expects to spend approximately $1.5 billion of capital for oil and gas activities, excluding acquisitions, in 2004 but may increase its spending if it can do so efficiently. The current level of spending is roughly the same as recent years. However, the Company expects to spend approximately $5 billion of capital from 2004 through 2006 in order to achieve its goal of generating cumulative production growth of 20 percent over this three-year period.

Financial Condition and Liquidity

     The Company’s total debt to total capital (total capital is defined as total debt and stockholders’ equity) ratio at March 31, 2004 and December 31, 2003 was 40 percent and 41 percent, respectively. Based on the current price environment, management believes that the

16

Company will generate sufficient cash from operations to fund its 2004 capital expenditures, excluding any major acquisition(s). At March 31, 2004, the Company had $1,027 million of cash and cash equivalents on hand.

     The Company had credit commitments in the form of revolving credit facilities (“revolvers”) as of March 31, 2004. The revolvers are comprised of agreements for $600 million, $400 million and Canadian $390 million (U.S. $298 million). The $600 million revolver expires in December 2006 and the $400 million and Canadian $390 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 $390 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 March 31, 2004, there were no amounts outstanding under the revolvers and no outstanding commercial paper. In 2001, the Company’s Board of Directors (“Board”) authorized the Company to redeem, exchange or repurchase up to an aggregate of $990 million principal amount of debt securities.

     Net cash provided by operating activities during the first quarter of 2004 increased $153 million over the same period in 2003 primarily due to higher net income resulting from higher production volumes. Key drivers of net operating cash flows are commodity prices, production volumes and costs. Although realized commodity prices were relatively flat, production volumes on a gas equivalent basis increased 14 percent, resulting in increased revenues of $175 million over 2003.

     In December 2000, the Company’s Board 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 voted to restore the authorization level to $1 billion effective May 1, 2003. During the first quarter of 2004, the Company repurchased approximately 1.6 million shares of its Common Stock for approximately $90 million and, as of March 31, 2004, has authority to repurchase an additional $672 million of its Common Stock under the current authorization. Since December 2000, the Company has repurchased approximately 25 million shares of its Common Stock for approximately $1.1 billion.

     The Company and its subsidiaries are named defendants in numerous lawsuits and named parties in numerous governmental and other proceedings arising in the ordinary course of business. While the outcome of these 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.

17

Capital Expenditures

     The Company’s consolidated capital expenditures were down 5 percent compared to the first quarter of 2003. The Company utilizes a disciplined approach to capital spending. Excluding acquisitions, the Company’s capital spending related to internal development and exploration is up 4 percent compared to the first quarter of 2003. However, at the current capital spending levels, the Company believes that spending is sufficient to add adequate reserves and achieve the target of 3 to 8 percent average annual production growth. Capital expenditures in 2004, excluding proved property acquisitions, are expected to be approximately $1.5 billion, essentially the same as 2003. Capital expenditures in 2004 are expected to be primarily for internal development and exploration of oil and gas properties which are expected to be 3 percent higher than 2003. Capital expenditures are expected to be funded from internally generated cash flows.

Dividends

     On April 21, 2004, the Company’s Board declared a quarterly common stock cash dividend of $0.15 per share on a current-share basis, or $0.075 per share on a post-split basis, with record and payment dates of June 10, 2004 and July 9, 2004, respectively.

     On January 21, 2004, the Company’s Board announced a 2-for-1 split on the Company’s Common Stock in the form of a share distribution, subject to shareholder approval of an amendment to the Company’s Certificate of Incorporation to increase the number of authorized shares of the Company’s Common Stock from 325 million to 650 million. On April 21, 2004, shareholders approved the amendment. As a result, the stock split is payable on June 1, 2004 to shareholders of record on May 5, 2004.

Application of Critical Accounting Policies

     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 intangible assets separately from goodwill. SFAS No. 142 established 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. One interpretation being considered relative to these standards is that oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract reserves for both

18

undeveloped and developed leaseholds should be classified separately from oil and gas properties, and included as intangible assets on the Company’s consolidated balance sheets. Historically, the Company, like many other oil and gas companies, has 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 matter was referred to the Emerging Issues Task Force (“EITF”) in late 2003. At the March 2004 meeting, the EITF reached a consensus that mineral rights for mining companies should be accounted for as tangible assets. However, this issue as it pertains to oil and gas companies is still under consideration by the EITF. The Company will continue to monitor this issue and 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.

     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 March 31, 2004, the Company had undeveloped and developed leaseholds of approximately $1.2 billion and $2.3 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.

Results of Operations – First Quarter 2004 Compared to First Quarter 2003

     The Company reported net income of $354 million or $1.78 diluted earnings per common share in first quarter 2004 compared to net income of $269 million or $1.33 diluted earnings per common share in 2003. Net income in 2003 included a net-of-tax cumulative effect of change in accounting principle charge of $59 million or $0.29 diluted earnings per common share related to the adoption of SFAS No. 143, Asset Retirement Obligations. See Note 8 of Notes to Consolidated Financial Statements for more information.

19

     Below is a discussion of prices, volumes and revenue variances.

Price and Volume Variances

Revenue Variances

Revenues

     The Company’s consolidated revenues increased $180 million in the first quarter of 2004. Higher revenues were primarily due to higher sales volumes, resulting in increased revenues of $175 million, which represent 97 percent of the total increase in revenues. Revenue variances related to commodity prices and sales volumes are described below.

Price Variances

     Commodity prices are one of the key drivers of earnings and net operating cash flow generation. However, during the first quarter of 2004, realized commodity prices were essentially flat compared to the same quarter last year. Higher commodity prices contributed $3 million to the increase in revenues in the first quarter of 2004. Average natural gas prices, including a $0.01 realized gain per MCF related to hedging activities, increased $0.02 per MCF during the quarter resulting in increased revenues of $4 million. Average crude oil prices, including a $0.32 realized loss per barrel related to hedging activities, decreased $0.17 per barrel in the first quarter, resulting in reduced revenues of $1 million.

20

Volume Variances

     Sales volumes are another key driver that impact the Company’s earnings and net operating cash flow. Higher sales volumes in the first quarter of 2004 resulted in increased revenues of $175 million. Average crude oil sales volumes increased 43.1 MBbls per day in the first quarter of 2004, resulting in increased revenues of $118 million. The increase in crude oil sales volumes was primarily due to higher production from the Cedar Creek Anticline and new project start-ups after first quarter 2003 in offshore China, Algeria, and Ecuador. Average natural gas sales volumes increased 81 MMCF per day in the first quarter of 2004, resulting in increased revenues of $49 million. Average natural gas sales volumes increased primarily due to higher production from the purchase of an additional interest in CLAM in the Dutch offshore sector, and the East Irish Sea. Average NGLs sales volumes increased 3.2 MBbls per day in the first quarter of 2004, resulting in higher revenues of $8 million quarter over quarter. Average NGLs sales volumes increased primarily due to increased production in the Fort Worth Basin.

Below is a discussion of total costs and other income — net.

Total Costs and Other Income — Net

     Total costs and other income—net increased $132 million in the first quarter of 2004. The increase in total costs and other income—net was primarily due to items discussed below. The increase in exchange rates during the first quarter of 2004 impacted certain costs and expenses by $31 million compared to the same period last year. Changes in foreign currencies versus the U.S. dollar could impact costs and expenses in future periods. However, at this time, the Company cannot predict what impact the exchange rates will have on costs and expenses in the future.

     DD&A expense increased $74 million primarily due to higher production and higher unit-of-production rates on the Canadian and Other International properties which have higher rates than the average unit-of-production rates for the Company.

21

     Operating costs increased $29 million primarily due to higher well operating costs related to operations in Other International and Canada. Transportation expense increased $11 million also primarily due to operations in Other International and Canada. Taxes other than income taxes increased $11 million primarily due to higher production taxes resulting from higher crude oil and natural gas revenues. Interest expense increased $7 million primarily due to lower capitalized interest being incurred on capital projects during the first quarter of 2004.

     The increases in costs and expenses discussed above were partially offset by lower exploration costs. Exploration costs decreased $8 million primarily due to lower exploratory dry hole costs of $15 million partially offset by higher geological and geophysical and other expenses of $7 million.

Income Tax Expense

     Income tax expense increased $22 million in the first quarter of 2004. The increase in income tax expense was primarily due to higher pretax income of $48 million. The Company recorded lower tax benefits of $7 million in the first quarter of 2004 related to interest deductions allowed in both the U.S. and Canada on transactions associated with cross-border financing.

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 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 March 31, 2004, an assumed 10 percent adverse movement in commodity prices (an increase in the underlying commodities prices) would result in a $45 million increase in the fair value of the net liabilities related to commodity hedging activities.

22

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

     Based on commodity prices and foreign exchange rates as of March 31, 2004, the Company expects to reclassify losses of $49 million ($30 million after tax) to earnings from the balance in accumulated other comprehensive loss during the next twelve months. At March 31, 2004, the Company had derivative assets of $8 million and derivative liabilities of $70 million. Of the derivative assets of $8 million, $6 million and $2 million are included in Other Current Assets and Other Assets, respectively, on the Consolidated Balance Sheet. Of the derivative liabilities of $70 million, $14 million are included in Other Liabilities and Deferred Credits on the Consolidated Balance Sheet.

ITEM 4. Controls and Procedures

     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 control over financial reporting 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.

23

     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.

Forward-looking Statements

     This Quarterly Report contains projections and other forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These projections and statements reflect the Company’s current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved and actual results could differ materially from those projected as a result of certain factors. A discussion of these factors is included in the Company’s 2003 Annual Report on Form 10-K.

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

     See Note 5 of Notes to Consolidated Financial Statements.

ITEM 2. Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

Issuer Purchases of Equity Securities (1)

(1)

In December 2000, the Company announced that its Board of Directors (“Board”) 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 announced that its Board voted to restore the authorization level to $1 billion effective May 1, 2003.

24

ITEM 6. Exhibits and Reports on Form 8-K

          A. Exhibits

          The following exhibits are filed as part of this report.

*

Exhibit incorporated by reference.

          B. Reports on Form 8-K

     On January 22, 2004, the Company filed on Form 8-K, pursuant to Item 5, press releases relating to the election of additional members to the Board, the creation of the Office of the Chairman and the announcement of the 2-for-1 stock split and furnished on Form 8-K, pursuant to Item 12, Results of Operations and Financial Condition, and Item 9, Regulation FD Disclosure, a press release announcing its earnings results for the fourth quarter and full fiscal year 2003.

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

25

SIGNATURES

     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

Date: May 7, 2004

26

INDEX TO EXHIBITS

* Exhibit incorporated by reference.