10-Q 1 h07978e10vq.txt BURLINGTON RESOURCES INC.- JUNE 30, 2003 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 2003 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 1-9971 BURLINGTON RESOURCES INC. (Exact name of registrant as specified in its charter) Delaware 91-1413284 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 5051 Westheimer, Suite 1400, Houston, Texas 77056 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (713) 624-9500 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --------------- -------------- Indicate 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.

Class Outstanding ----- ----------- Common Stock, par value $.01 per share, as of June 30, 2003 200,710,143

PART I - FINANCIAL INFORMATION ITEM 1. Financial Statements BURLINGTON RESOURCES INC. CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)

SECOND QUARTER SIX MONTHS ----------------- --------------------- 2003 2002 2003 2002 ------ ----- ------- ------- (In Millions, Except per Share Amounts) Revenues ........................................................... $1,059 $ 783 $ 2,187 $ 1,486 ------ ----- ------- ------- Costs and Other Income - Net Taxes Other than Income Taxes .................................... 46 30 94 63 Transportation Expense ........................................... 102 82 201 168 Production and Processing ........................................ 112 112 214 248 Depreciation, Depletion and Amortization ......................... 227 215 430 436 Exploration Costs ................................................ 52 104 120 161 Impairment of Oil and Gas Properties ............................. 30 -- 30 -- Administrative ................................................... 39 39 81 77 Interest Expense ................................................. 63 70 127 142 (Gain)/Loss on Disposal of Assets ................................ 1 (73) -- (73) Other Expense (Income) - Net ..................................... 11 (3) 15 (4) ------ ----- ------- ------- Total Costs and Other Income - Net ................................. 683 576 1,312 1,218 ------ ----- ------- ------- Income Before Income Taxes and Cumulative Effect of Change in Accounting Principle .......................................... 376 207 875 268 Income Tax Expense ................................................. 98 37 269 50 ------ ----- ------- ------- Income Before Cumulative Effect of Change in Accounting Principle... 278 170 606 218 Cumulative Effect of Change in Accounting Principle - Net .......... -- -- (59) -- ------ ----- ------- ------- Net Income ......................................................... $ 278 $ 170 $ 547 $ 218 ====== ===== ======= ======= Earnings per Common Share Basic Before Cumulative Effect of Change in Accounting Principle ....... $ 1.39 $0.84 $ 3.03 $ 1.08 Cumulative Effect of Change in Accounting Principle - Net ........ -- -- (0.30) -- ------ ----- ------- ------- Net Income ....................................................... $ 1.39 $0.84 $ 2.73 $ 1.08 ====== ===== ======= ======= Diluted Before Cumulative Effect of Change in Accounting Principle ....... $ 1.38 $0.84 $ 3.00 $ 1.08 Cumulative Effect of Change in Accounting Principle - Net ........ -- -- (0.30) -- ------ ----- ------- ------- Net Income ....................................................... $ 1.38 $0.84 $ 2.70 $ 1.08 ====== ===== ======= =======

See accompanying Notes to Consolidated Financial Statements. 2 BURLINGTON RESOURCES INC. CONSOLIDATED BALANCE SHEET (UNAUDITED)

June 30, December 31, 2003 2002 -------- -------- (In Millions, Except Share Data) ASSETS Current Assets Cash and Cash Equivalents ....................................... $ 615 $ 443 Accounts Receivable ............................................. 617 515 Inventories ..................................................... 54 48 Other Current Assets ............................................ 41 55 -------- -------- 1,327 1,061 -------- -------- Oil & Gas Properties (Successful Efforts Method) .................. 15,103 12,716 Other Properties .................................................. 1,289 1,140 -------- -------- 16,392 13,856 Accumulated Depreciation, Depletion and Amortization .............. 6,453 5,353 -------- -------- Properties - Net ................................................ 9,939 8,503 -------- -------- Goodwill .......................................................... 936 803 -------- -------- Other Assets ...................................................... 219 278 -------- -------- Total Assets .................................................... $ 12,421 $ 10,645 ======== ======== LIABILITIES Current Liabilities Accounts Payable ................................................ $ 840 $ 809 Taxes Payable ................................................... 60 44 Accrued Interest ................................................ 61 61 Commodity Hedging Contracts and Other Derivatives ............... 72 38 Other Current Liabilities ....................................... 31 7 Current Maturities of Long-term Debt ............................ 74 63 -------- -------- 1,138 1,022 -------- -------- Long-term Debt .................................................... 3,867 3,853 -------- -------- Deferred Income Taxes ............................................. 1,873 1,436 -------- -------- Commodity Hedging Contracts and Other Derivatives ................. 27 33 -------- -------- Other Liabilities and Deferred Credits ............................ 686 469 -------- -------- Commitments and Contingencies 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 ................................................... 3,913 3,941 Retained Earnings ................................................. 2,167 1,675 Deferred Compensation - Restricted Stock .......................... (16) (9) Accumulated Other Comprehensive Income (Loss) ..................... 410 (164) Cost of Treasury Stock (40,478,545 and 39,749,431 Shares for 2003 and 2002, respectively) (1,646) (1,613) -------- -------- Stockholders' Equity .............................................. 4,830 3,832 -------- -------- Total Liabilities and Stockholders' Equity ...................... $ 12,421 $ 10,645 ======== ========

See accompanying Notes to Consolidated Financial Statements. 3 BURLINGTON RESOURCES INC. CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

SIX MONTHS --------------------- 2003 2002 ------- ------- (In Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income .................................................. $ 547 $ 218 Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities Depreciation, Depletion and Amortization .................. 430 436 Deferred Income Taxes ..................................... 155 (28) Exploration Costs ......................................... 120 161 (Gain)/Loss on Disposal of Assets ......................... -- (73) Impairment of Oil and Gas Properties ...................... 30 -- Cumulative Effect of Change in Accounting Principle - Net.. 59 -- Changes in Derivative Fair Values ......................... (6) 26 Working Capital Changes Accounts Receivable ....................................... (54) (10) Inventories ............................................... (2) (8) Other Current Assets ...................................... 16 (16) Accounts Payable .......................................... 18 (7) Taxes Payable ............................................. 18 99 Accrued Interest .......................................... -- 4 Other Current Liabilities ................................. (5) (7) Changes in Other Assets and Liabilities ..................... (4) (19) ------- ------- Net Cash Provided By Operating Activities ................. 1,322 776 ------- ------- CASH FLOWS FROM INVESTING ACTIVITIES Additions to Properties ..................................... (1,080) (1,034) Proceeds from Sales and Other ............................... (10) 875 ------- ------- Net Cash Used In Investing Activities ..................... (1,090) (159) ------- ------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Long-term Debt ................................ -- 454 Reduction in Long-term Debt ................................. -- (775) Dividends Paid .............................................. (28) (56) Common Stock Purchases ...................................... (173) -- Common Stock Issuances ...................................... 101 9 Other ....................................................... -- 14 ------- ------- Net Cash Used In Financing Activities ..................... (100) (354) ------- ------- Effect of Exchange Rate Changes on Cash and Cash Equivalents... 40 13 ------- ------- INCREASE IN CASH AND CASH EQUIVALENTS ......................... 172 276 CASH AND CASH EQUIVALENTS Beginning of Year ........................................... 443 116 ------- ------- End of Period ............................................... $ 615 $ 392 ======= =======

See accompanying Notes to Consolidated Financial Statements. 4 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. BASIS OF PRESENTATION 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 200 million and 201 million for the second quarter of 2003 and 2002, respectively, and 200 million and 201 million for the first six months of 2003 and 2002, respectively. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. The weighted average number of common shares outstanding for computing diluted EPS, including dilutive stock options, was 202 million and 202 million for the second quarter of 2003 and 2002, respectively, and 203 million and 202 million for the first six months of 2003 and 2002, respectively. For the second quarter of 2003 and 2002 and six months ended June 30, 2003 and 2002, approximately 2 million, 4 million, 3 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. Recent Development 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 July 1, 2001 and January 1, 2002, respectively. It is our understanding that the Securities and Exchange Commission (SEC) has questioned other SEC registrants as to whether they properly adopted the provisions of SFAS No. 141 and SFAS No. 142, with respect to how the costs of acquiring contractual mineral interests in oil and gas properties should be classified on the balance sheet. It is also our understanding that the Financial Accounting Standards Board (FASB), the SEC and others are engaged in deliberations on the issue of whether SFAS No. 141 and SFAS No. 142 require that interests held under oil, gas and mineral leases or other contractual arrangements be classified as intangible assets or as oil and gas properties. If such interests were deemed intangible assets, mineral interests for undeveloped and developed leaseholds would be classified separately from oil and gas properties on the balance sheet but would be aggregated with oil and gas properties in the Notes to Consolidated Financial Statements in accordance with SFAS No. 69, Disclosures about Oil and Gas Producing Activities. 5 Historically, the Company has included all oil and gas leasehold interests as part of oil and gas properties. Because this issue is being deliberated and is unresolved, the Company continues to include mineral interests as oil and gas properties on its balance sheet. At June 30, 2003, the Company had undeveloped and developed leaseholds of approximately $1.4 billion and $2.4 billion that would have been classified on the balance sheet as intangible undeveloped leaseholds and intangible developed leaseholds, respectively, if the interpretation currently being deliberated had been applied. The reclassification would have no impact on the Company's results of operations. 2. STOCK-BASED COMPENSATION 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.

Second Quarter Six Months -------------------- -------------------- 2003 2002 2003 2002 ------- ------- ------- ------- (In Millions, Except per Share Amounts) Net income - as reported ..................................... $ 278 $ 170 $ 547 $ 218 Pro forma stock based employee compensation cost, after tax... 3 2 6 5 ------- ------- ------- ------- Net income - pro forma ....................................... $ 275 $ 168 $ 541 $ 213 ======= ======= ======= ======= Basic EPS - as reported ...................................... $ 1.39 $ 0.84 $ 2.73 $ 1.08 Basic EPS - pro forma ........................................ 1.38 0.83 2.70 1.06 Diluted EPS - as reported .................................... 1.38 0.84 2.70 1.08 Diluted EPS - pro forma ...................................... $ 1.37 $ 0.83 $ 2.67 $ 1.06

6 3. COMPREHENSIVE INCOME (LOSS) The following table presents comprehensive income (loss).

SIX MONTHS ------------------------------------------------- (In Millions) 2003 2002 ---------------------- -------------------- Accumulated other comprehensive loss - Beginning of Period....... $ (164) $ (106) Net income....................................................... $ 547 $ 218 ------- ------ Other comprehensive income (loss) - net of tax................. Hedging activities Current period changes in fair value of settled contracts...... (25) 19 Reclassification adjustments for settled contracts............. 32 (60) Changes in fair value of outstanding hedging positions......... (26) (11) ------- ------ Hedging activities......................................... (19) (52) Foreign currency translation Foreign currency translation adjustments....................... 593 176 ------- ------ Total other comprehensive income................................. 574 574 124 124 ------- ------- ------ ------- Comprehensive income............................................. $ 1,121 $ 342 ======= ====== Accumulated other comprehensive income - End of Period........... $ 410 $ 18 ======= =======

4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES The Company uses derivative instruments to manage risks associated with natural gas, crude oil and electricity price volatility as well as 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 crude oil and natural gas 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. 7 As of June 30, 2003, the Company had the following derivative instruments outstanding with average underlying prices that represent hedged prices at various market locations.

Notional Amount ----------------------------------- Electricity US$ Average Fair Value Settlement Derivative Hedge Gas (Megawatt- (In Underlying Asset Period Instrument Strategy (MMBTU) Hours) Millions) Prices (Liability) ----------------------------------------------------------------------------------------------------------------------- 2003 Swap Cash Flow Hedge 9,227,847 $ 2.95 $ (14) Purchased Put Cash Flow Hedge 112,829,084 3.34 4 Written Call Cash Flow Hedge 112,829,084 5.23 (43) Written Put Cash Flow Hedge 110,069,084 2.49 -- Swap Foreign Currency Hedge $9 1.42 -- Swap Fair Value Hedge 1,290,700 3.04 3 N/A Fair Value Hedge (Obligation) 1,290,700 3.09 (3) Purchased Call Cash Flow Hedge 88,320 47.23 1 Written Put Cash Flow Hedge 88,320 30.99 -- 2004 Swap Cash Flow Hedge 15,610,390 3.12 (21) Purchased Put Cash Flow Hedge 11,351,257 4.25 3 Written Put Cash Flow Hedge 11,351,257 3.15 (1) Written Call Cash Flow Hedge 11,351,257 7.09 (3) Swap Foreign Currency Hedge $8 1.43 -- Swap Fair Value Hedge 2,256,800 2.92 4 N/A Fair Value Hedge (Obligation) 2,256,800 2.95 (4) 2005 Swap Cash Flow Hedge 10,511,522 3.11 (12) 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) ----------- $ (88) ===========

Based on commodity prices and foreign exchange rates as of June 30, 2003, the Company expects to reclassify losses of $64 million ($40 million after tax) to earnings from the balance in accumulated other comprehensive income during the next twelve months. At June 30, 2003, the Company had derivative assets of $11 million and derivative liabilities of $99 million. Of the derivative assets of $11 million, $6 million are included in Other Current Assets and $5 million are included in Other Assets on the Consolidated Balance Sheet. The derivative assets and liabilities represent the difference between hedged prices and market prices on hedged volumes of the commodities as of June 30, 2003. Hedging activities related to cash settlements decreased revenues $11 million in the second quarter of 2003 and increased revenues $24 million in the second quarter of 2002. Hedging activities decreased revenues $52 million in the first six months of 2003 and increased revenues $96 million in the first six months of 2002. In addition, non-cash losses of $2 million and $1 million were recorded 8 in revenues associated with ineffectiveness of cash-flow and fair-value hedges during the second quarter of 2003 and 2002, respectively. Non-cash losses of $3 million and $16 million were recorded in revenues associated with ineffectiveness of cash-flow and fair-value hedges during the first six months of 2003 and 2002, respectively. Also, a non-cash gain of $3 million and a non-cash loss of $25 thousand were recorded in revenues associated with changes in the fair value of derivative instruments that do not qualify for hedge accounting during the second quarter of 2003 and 2002, respectively. A non-cash gain of $9 million and a non-cash loss of $10 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 six months of 2003 and 2002, 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. 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. 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, 9 although cash flow could be significantly impacted in the reporting periods in which such matters are resolved. The Company has also been named as a defendant in the lawsuit styled UNOCAL Netherlands B.V., et al v. Continental Netherlands Oil Company B.V., et al, No. 98-854, 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 is unable at this time to reasonably predict the outcome, or, in the event of an unfavorable outcome, to reasonably estimate the possible loss or range of loss, if any, in this lawsuit. Accordingly, there has been no reserve established for this matter. In addition to the foregoing, the Company and its subsidiaries are named defendants in numerous other lawsuits and named parties in numerous governmental and other proceedings arising in the ordinary course of business, including: claims for personal injury and property damage, claims challenging oil and gas royalty and severance tax payments, claims related to joint interest billings under oil and gas operating agreements, claims alleging mismeasurement of volumes and wrongful analysis of heating content of natural gas and other claims in the nature of contract, regulatory or employment disputes. Two of the governmental proceedings arise under the provincial laws of Alberta and British Columbia, Canada, and relate to safety and environmental matters, respectively. None of the other governmental proceedings involve foreign governments. While the ultimate outcome of these other lawsuits and proceedings cannot be predicted with certainty, management believes that the resolution of these other matters will not have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company. The Company has established reserves for 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 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. 10 6. LONG-TERM DEBT The fair value of the Company's long-term debt at June 30, 2003 and December 31, 2002 was approximately $4,741 million and $4,443 million, respectively, based on quoted market prices. 7. SEGMENT AND GEOGRAPHIC INFORMATION 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 second quarter and first six months of 2003. Intersegment sales were $1 million and $15 million during the second quarter and first six months of 2002, respectively. The following tables present information about the Company's reportable segments.

Second Quarter ----------------------------------------------------------------------- 2003 2002 ---------------------------------- ---------------------------------- U.S. Canada Intl Total U.S. Canada Intl Total ------ ------ ------ ------ ------ ------ ------ ------ (In Millions) Revenues ................................................. $ 525 $ 491 $ 43 $1,059 $ 429 $ 313 $ 41 $ 783 Income (loss) before income taxes and cumulative effect of change in accounting principle ............... 287 213 (4) 496 341 59 (83) 317 Capital expenditures ..................................... $ 122 $ 120 $ 232 $ 474 $ 53 $ 101 $ 88 $ 242

Six Months ---------------------------------------------------------------------- 2003 2002 --------------------------------- ---------------------------------- U.S. Canada Intl Total U.S. Canada Intl Total ------ ------ ------ ------ ------ ------ ------ ------ (In Millions) Revenues .................................................. $1,080 $1,017 $ 90 $2,187 $ 826 $ 565 $ 95 $1,486 Income (loss) before income taxes and cumulative effect of change in accounting principle ................ 596 509 6 1,111 478 93 (79) 492 Capital expenditures ...................................... $ 335 $ 404 $ 329 $1,068 $ 126 $ 625 $ 206 $ 957

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.

Second Quarter Six Months ------------------- ------------------- 2003 2002 2003 2002 ------ ------ ------ ------ (In Millions) Income before income taxes and cumulative effect of change in accounting principle ........... $ 496 $ 317 $1,111 $ 492 Corporate expense .................................... 46 43 94 86 Interest expense ..................................... 63 70 127 142 Other expense (income) - net ......................... 11 (3) 15 (4) ------ ------ ------ ------ Consolidated income before income taxes and cumulative effect of change in accounting principle ........... $ 376 $ 207 $ 875 $ 268 ====== ====== ====== ======

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

Second Quarter Six Months ------------------- ------------------- 2003 2002 2003 2002 ------ ------ ------ ------ (In Millions) Capital expenditures for reportable segments................ $ 474 $ 242 $1,068 $ 957 Administrative capital expenditures ........................ 2 4 5 25 ------ ------ ------ ------ Consolidated capital expenditures .......................... $ 476 $ 246 $1,073 $ 982 ====== ====== ====== ======

8. ASSET RETIREMENT OBLIGATIONS 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 $360 million at June 30, 2003. For the period ended June 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.

Second Quarter Six Months --------------------------- --------------------------- As Reported Pro Forma As Reported Pro Forma ----------- ---------- ----------- ---------- (In Millions, Except per Share Amounts) Net income ................................... $ 170 $ 169 $ 218 $ 215 Earnings per share: Basic ...................................... 0.84 0.84 1.08 1.07 Diluted .................................... $ 0.84 $ 0.83 $ 1.08 $ 1.06

9. ACQUISITION 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, prior to the acquisition in May 2003, owned 50 percent of CLAM which had been accounted for under the equity method of accounting. Effective on the date of acquisition, the Company began consolidating CLAM's financial results. 12 10. 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 six months of 2003 as it relates to the Canadian reporting unit.

(In Millions) Balance - December 31, 2002 ................................... $803 Changes in foreign exchange rates during the period ........... 133 ---- Balance - June 30, 2003 ....................................... $936 ====

11. INCOME TAXES The Company's effective income tax rate increased to 31 percent for the period ended June 30, 2003 from 20 percent for the year ended December 31, 2002 primarily due to higher pretax income. The period ended June 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. 12. RECENT ACCOUNTING PRONOUNCEMENTS 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. 13 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Outlook The Company expects third quarter 2003 production volumes to average between 2,410 and 2,610 MMCFE per day. The key to third quarter 2003 performance will be the impact on production volumes associated with annual plant maintenance, the base capital program and the restoration of production from the Deep Madison Formation at Madden Field (Madden) in Wyoming. In late June 2003, the production at Madden was curtailed due to deformations in the gas gathering lines. Currently, repairs to the gathering lines are underway. 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. Accomplishing the production goals depend upon the performance of the base assets, results of the capital program, restoration of production at Madden and delivery of production from major projects in Algeria, China and the East Irish Sea. 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 six months of 2003, the Company spent $211 million on acquisitions. Financial Condition and Liquidity The Company's total debt to total capital (total capital is defined as total debt and stockholders' equity) ratio at June 30, 2003 and December 31, 2002 was 45 percent and 51 percent, respectively. Based on the current price environment, management believes that the Company will generate sufficient cash from operations to fund its 2003 capital expenditures, excluding any major acquisition(s), dividend payments and Common Stock repurchases. At June 30, 2003, the Company had $615 million of cash and cash equivalents on hand. The Company had credit commitments in the form of revolving credit facilities (Revolvers) as of June 30, 2003. The Revolvers are comprised of agreements for $600 million, $400 million and Canadian $468 million (U.S. $345 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 June 30, 2003, there were no amounts outstanding under the Revolvers and no outstanding commercial paper. 14 Net cash provided by operating activities during the first six months of 2003 was $1,322 million compared to $776 million in 2002. The increase was primarily due to higher net income partially offset by higher working capital needs. Higher net income is principally the result of higher commodity prices partially offset by lower natural gas and crude oil sales volumes. 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 six months of 2003, the Company repurchased approximately 3.7 million shares of its Common Stock for approximately $176 million and, as of June 30, 2003, has authority to repurchase an additional $947 million of its Common Stock under the current authorization. As of June 30, 2003, $3 million of the share repurchases were not cash settled during the period. Since December 2000, the Company has repurchased approximately 20 million shares or $870 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 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. Capital Expenditures Capital expenditures for the first six months of 2003 totaled $1,073 million compared to $982 million in 2002. The Company invested $742 million on internal development and exploration of oil and gas properties during the first six months of 2003 compared to $484 million in 2002. The Company invested $211 million for property acquisitions in the first six months of 2003 compared to $417 million in 2002. Property acquisitions during the first six 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 six months of 2002 included the purchase of certain assets from ATCO Gas and Pipelines Ltd., a Canadian regulated gas utility, for approximately $344 million. Dividends On July 23, 2003, the Board of Directors declared a quarterly common stock cash dividend of $0.15 per share which represents a 9 percent increase over the previous quarterly dividend of $0.1375 per share. The record and payment dates for the quarterly dividend are September 10, 2003 and October 10, 2003, respectively. 15 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 July 1, 2001 and January 1, 2002, respectively. It is our understanding that the Securities and Exchange Commission (SEC) has questioned other SEC registrants as to whether they properly adopted the provisions of SFAS No. 141 and SFAS No. 142, with respect to how the costs of acquiring contractual mineral interests in oil and gas properties should be classified on the balance sheet. It is also our understanding that the Financial Accounting Standards Board (FASB), the SEC and others are engaged in deliberations on the issue of whether SFAS No. 141 and SFAS No. 142 require that interests held under oil, gas and mineral leases or other contractual arrangements be classified as intangible assets or as oil and gas properties. If such interests were deemed intangible assets, mineral interests for undeveloped and developed leaseholds would be classified separately from oil and gas properties on the balance sheet but would be aggregated with oil and gas properties in the Notes to Consolidated Financial Statements in accordance with SFAS No. 69, Disclosures about Oil and Gas Producing Activities. Historically, the Company has included all oil and gas leasehold interests as part of the oil and gas properties. Because this issue is unresolved, the Company continues to include mineral interests as oil and gas properties on its balance sheet. At June 30, 2003, the Company had undeveloped and developed leaseholds of approximately $1.4 billion and $2.4 billion that would have been classified on the balance sheet as intangible undeveloped leaseholds and intangible developed leaseholds, respectively, if the interpretation currently being deliberated had been applied. The reclassification would have no impact on the Company's results of operations. Results of Operations - Second Quarter 2003 Compared to Second Quarter 2002 The Company reported net income of $278 million or $1.38 diluted earnings per common share in the second quarter of 2003 compared to net income of $170 million or $0.84 diluted earnings per common share in 2002. Net income in the second quarter of 2003 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 second quarter of 2002 included a net after tax gain of $45 million or $0.23 per diluted share related to the disposal of assets. Revenues Revenues increased $276 million to $1,059 million in the second quarter of 2003 compared to $783 million in the second quarter of 2002. As described below, the $276 million increase in revenues primarily consists of $335 million related to higher commodity prices, partially offset by $48 million related to lower sales volumes and $10 million due to the sale of the Val Verde Plant in the second quarter of 2002. Details of commodity prices AND sales volumes variances are described below. Price Variances Average gas prices, including a $0.07 realized loss per MCF related to hedging activities, increased $1.74 per MCF in the second quarter of 2003 to $4.96 per MCF from $3.22 per MCF, including a $0.14 realized gain per MCF related to hedging activities in the second quarter of 2002. Higher average natural gas prices resulted in increased revenues of $297 million during the second quarter of 2003. Average NGLs prices increased $4.67 per barrel in the second quarter of 16 2003 to $18.53 per barrel from $13.86 per barrel in the second quarter of 2002, resulting in higher revenues of $27 million during the second quarter of 2003. Average oil prices, which included no gains or losses related to hedging activities, increased $2.89 per barrel in the second quarter of 2003 to $27.53 per barrel from $24.64 per barrel in the second quarter of 2002. Higher average oil prices resulted in increased revenues of $11 million during the second quarter of 2003. Volume Variances Average gas sales volumes decreased 48 MMCF per day in the second quarter of 2003 to 1,879 MMCF per day from 1,927 MMCF per day in the second quarter of 2002, resulting in decreased revenues of $14 million during the second quarter of 2003. Average oil sales volumes decreased 14.1 MBbls per day in the second quarter of 2003 to 40.7 MBbls per day from 54.8 MBbls per day in the second quarter of 2002, reducing revenues $32 million during the second quarter of 2003. Average NGLs sales volumes decreased 1.9 MBbls per day in the second quarter of 2003 to 63.1 MBbls per day from 65.0 MBbls per day in the second quarter of 2002, resulting in lower revenues of $2 million from quarter to quarter. Average gas sales volumes, primarily in the Gulf of Mexico, the Permian Basin and the U.K. Sector of the North Sea, decreased 170 MMCF per day due to asset sales in 2002 partially offset by an increase of 122 MMCF per day primarily as a result of the winter drilling program in Canada, the drilling program in the Ft. Worth Basin and the plant expansion at Madden in Wyoming. Average oil sales volumes decreased 20.0 MBbls per day due to asset sales in 2002 primarily in the Gulf of Mexico, the U.K. Sector of the North Sea, Canada and the Williston Basin partially offset by an increase of 4.0 MBbls per day resulting from higher production at the Ourhoud Field in Algeria. Total Costs and Other Income - Net Total costs and other income - net were $683 million in the second quarter of 2003 compared to $576 million in the second quarter of 2002. The $107 million increase in total costs and other income - net was primarily due to a $74 million decrease in gain on disposal of assets, a $30 million increase in the impairment of oil and gas properties, a $20 million increase in transportation expenses, a $16 million increase in taxes other than income taxes, a $14 million increase in other expense-net, a $12 million increase in depreciation, depletion and amortization (DD&A), partially offset by a $52 million decrease in exploration costs and a $7 million decrease in interest expense. Gain on disposal of assets decreased primarily due to the divestiture program initiated by the Company in the second quarter of 2002 and completed in late 2002. The impairment of oil and gas properties increased due to performance related downward reserve adjustments associated with certain properties primarily in Canada. Transportation expenses increased primarily due to higher contract rates primarily resulting from the sale of the Val Verde Plant in 2002. Taxes other than income taxes increased primarily due to higher production taxes resulting from higher oil and gas revenues. Other expense-net increased primarily due to foreign currency transactions, lower interest income and higher environmental costs. 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 gas and oil production volumes. Exploration costs decreased primarily due to lower drilling rig expenses of $41 million, lower amortization of undeveloped lease costs of $6 million and lower geological and geophysical and other expenses of $5 million. Interest expense decreased primarily due to lower debt balances and higher capitalized interest during the second quarter of 2003. 17 Income Tax Expense Income taxes were an expense of $98 million in the second quarter of 2003 compared to an expense of $37 million in the second quarter of 2002. The increase in tax expense was primarily due to higher pretax income. The Company recorded tax benefits of $11 million in the second quarter of 2003 compared to $42 million in the second quarter of 2002 related to interest deductions allowed in both the U.S. and Canada on transactions associated with cross-border financing. The Company also recorded a net tax benefit of $31 million in second quarter 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 second quarter of 2003, the Company resolved all disputes under tax sharing agreements with certain former affiliates. As a result, during the second quarter of 2003, the Company recorded a $3 million decrease in income tax expense. Results of Operations - First Six Months of 2003 Compared to First Six Months of 2002 The Company reported net income of $547 million or $2.70 diluted earnings per common share in the first six months of 2003 compared to net income of $218 million or $1.08 diluted earnings per common share in the first six months of 2002. Net income in the first six months of 2002 included a net-of-tax cumulative effect of change in accounting principle charge of $59 million or $0.30 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 six 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 six months of 2002 included a net after tax gain of $45 million or $0.23 per diluted share related to the disposal of assets. Revenues Revenues increased $701 million to $2,187 million in the first six months of 2003 compared to $1,486 million in the first six months of 2002. As described below, the $701 million increase in revenues primarily consists of $810 million related to higher commodity prices, $19 million due to higher revenues related to changes in fair value instruments that do not qualify for hedge accounting, $13 million due to higher revenues related to ineffectiveness on hedging activities and $6 million related to higher NGLs sales volumes, partially offset by $127 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. Price Variances Average gas prices, including a $0.15 realized loss per MCF related to hedging activities, increased $2.03 per MCF in the first six months of 2003 to $5.13 per MCF from $3.10 per MCF, including a $0.26 realized gain per MCF related to hedging activities in the first six months of 2002. Higher average natural gas prices resulted in increased revenues of $689 million during the first six months of 2003. Average NGLs prices increased $7.09 per barrel in the first six months of 2003 to $20.30 per barrel from $13.21 per barrel in the first six months of 2002, resulting in higher revenues of $81 million during first six months of 2003. Average oil prices, including a $0.21 realized loss per barrel related hedging activities, increased $5.51 per barrel in first six months of 2003 to $28.61 per barrel from $23.10 per barrel. Higher average oil prices resulted in increased revenues of $40 million during the first six months of 2003. 18 Volume Variances Average gas sales volumes decreased 97 MMCF per day in the first six months of 2003 to 1,875 MMCF per day from 1,972 MMCF per day in the first six months of 2002, resulting in decreased revenues of $55 million during the first six months of 2003. Average oil sales volumes decreased 17.3 MBbls per day in the first six months of 2003 to 40.0 MBbls per day from 57.3 MBbls per day in the first six months of 2002, reducing revenues $72 million during the first six months of 2003. Average NGLs sales volumes increased 2.7 MBbls per day in the first six months of 2003 to 63.4 MBbls per day from 60.7 MBbls per day in the first six months of 2002, resulting in higher revenues of $6 million from period to period. Average gas sales volumes, primarily in the Gulf of Mexico, the U.K. Sector of the North Sea and the Permian Basin, decreased 183 MMCF per day due to asset sales in 2002 partially offset by an increase of 111 MMCF per day primarily as a result of the winter drilling program in Canada and plant expansion at Madden in Wyoming. Average oil sales volumes decreased 22.6 MBbls per day due to asset sales in 2002 primarily in the Gulf of Mexico, Canada, the U.K. Sector of the North Sea and the Williston Basin partially offset by an increase of 3.9 MBbls per day resulting from higher production at the Ourhoud Field in Algeria. Total Costs and Other Income - Net Total costs and other income - net were $1,312 million in the first six months of 2003 compared to $1,218 million in first six months of 2002. The $94 million increase in total costs and other income - net was primarily due to a $73 million decrease in gain on disposal of assets, a $30 million increase in the impairment of oil and gas properties, a $33 million increase in transportation expenses, a $31 million increase in taxes other than income taxes, a $19 million increase in other expense-net, partially offset by a $41 million decrease in exploration costs, a $34 million decrease in production and processing expenses, a $15 million decrease in interest expense and a $6 million decrease in DD&A. 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. The impairment of oil and gas properties increased due to performance related downward reserve adjustments associated with certain properties primarily in Canada. Transportation expenses increased primarily due to higher contract rates primarily resulting from the sale of the Val Verde Plant in 2002. Taxes other than income taxes increased primarily due to higher production taxes resulting from higher oil and gas revenues. Other expense-net increased primarily due to foreign currency transactions, lower interest income and higher environmental costs. Exploration costs decreased primarily due to lower drilling rig expenses of $38 million, lower amortization of undeveloped lease costs of $10 million and lower geological and geophysical and other expenses of $9 million partially offset by higher exploratory dry hole costs of $16 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 six months of 2003. DD&A decreased primarily due to the divestiture of higher cost properties in 2002 and lower gas and oil production volumes partially offset by higher unit-of-production rates on the Canadian properties which have higher rates than average unit-of-production rates for the Company. 19 Income Tax Expense Income taxes were an expense of $269 million in the first six months of 2003 compared to $50 million in the first six months of 2002. The increase in tax expense was primarily due to higher pretax income. The Company also recorded benefits of $37 million in the first six months of 2003 compared to $55 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 six 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 six months of 2003, the Company resolved all disputes under tax sharing agreements with certain former affiliates. As a result, during the first six months of 2003, the Company recorded a $3 million decrease in income tax expense. Recent Accounting Pronouncements 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 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. 20 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 June 30, 2003, an assumed 10 percent adverse movement in commodity prices (an increase in the underlying commodities prices) would result in a $136 million increase in the fair value of the net liabilities related to commodity hedging activities. For purposes of calculating the hypothetical change in fair value, the relevant variables include the type of commodity, the commodity futures prices, the volatility of commodity prices and the basis and quality differentials. The hypothetical change in fair value is calculated by multiplying the difference between the hypothetical price (adjusted for any basis or quality differentials) and the contractual price by the contractual volumes. Based on commodity prices and foreign exchange rates as of June 30, 2003, the Company expects to reclassify losses of $64 million ($40 million after tax) to earnings from the balance in accumulated other comprehensive loss during the next twelve months. At June 30, 2003, the Company had derivative assets of $11 million and derivative liabilities of $99 million. Of the derivative assets of $11 million, $6 million are included in Other Current Assets and $5 million are included in Other Assets 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. 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. 21 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 2002 Form 10-K. PART II - OTHER INFORMATION ITEM 1. Legal Proceedings See Note 5 of Notes to Consolidated Financial Statements. ITEM 4. Submission of Matters to a Vote of Security Holders The annual meeting of stockholders was held on April 23, 2003. The following were nominated and elected to serve as Directors of Burlington Resources Inc. for a term of one year or until their successors shall have been duly elected and qualified:

Nominee For Withheld --------------- ----------- ----------- R. V. Anderson 178,748,109 2,445,238 L. I. Grant 179,262,282 1,931,065 R. J. Harding 178,877,789 2,315,558 J. T. LaMacchia 178,852,879 2,340,468 J. F. McDonald 179,386,731 1,806,616 K. W. Orce 148,295,919 32,897,428 D. M. Roberts 179,254,219 1,939,128 J. F. Schwarz 179,435,034 1,758,313 W. Scott, Jr 178,645,702 2,547,645 B. S. Shackouls 178,655,934 2,537,413 W. E. Wade, Jr 179,462,378 1,730,969

22 ITEM 6. Exhibits and Reports on Form 8-K A. Exhibits The following exhibits are filed as part of this report.

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

* Exhibit incorporated by reference. B. Reports on Form 8-K On April 24, 2003, the Company furnished Form 8-K, pursuant to Item 12, Results of Operations, under Item 9, Regulation FD Disclosure (in accordance with the interim filing guidance for these items), a press release announcing its earnings results for the first quarter of fiscal year 2003. Items 2, 3 and 5 of Part II are not applicable and have been omitted. 23 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: August 7, 2003 24 Exhibit Index

Exhibit No. Description ----------- ----------- 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