10-Q 1 h98813e10vq.txt BURLINGTON RESOURCES INC. - DATED 6/30/2002 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, 2002 OR ( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 1-9971 BURLINGTON RESOURCES INC. (Exact name of registrant as specified in its charter) Delaware 91-1413284 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 5051 Westheimer, Suite 1400, Houston, Texas 77056 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (713) 624-9500 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
Class Outstanding ----- ----------- Common Stock, par value $.01 per share, as of June 30, 2002 201,300,482
PART I - FINANCIAL INFORMATION ITEM 1. Financial Statements BURLINGTON RESOURCES INC. CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
SECOND QUARTER SIX MONTHS ---------------------- ---------------------- 2002 2001 2002 2001 --------- --------- --------- --------- (In Millions, Except per Share Amounts) Revenues .............................................................. $ 769 $ 928 $ 1,452 $ 2,080 --------- --------- --------- --------- Costs and Other Income Taxes Other than Income Taxes ...................................... 30 47 63 114 Transportation Expense ............................................. 70 75 137 147 Production and Processing .......................................... 112 120 248 238 Depreciation, Depletion and Amortization ........................... 213 174 433 344 Exploration Costs .................................................. 104 52 161 122 Administrative ..................................................... 39 35 77 79 Interest Expense ................................................... 70 46 142 91 (Gain)/Loss on Disposal of Assets .................................. (73) (2) (73) (2) Other Expense (Income) - Net ....................................... (3) 1 (4) 10 --------- --------- --------- --------- Total Costs and Other Income .......................................... 562 548 1,184 1,143 Income Before Income Taxes ............................................ 207 380 268 937 Income Tax Expense .................................................... 37 149 50 373 --------- --------- --------- --------- Net Income Before Cumulative Effect of Change in Accounting Principle . 170 231 218 564 Cumulative Effect of Change in Accounting Principle - Net ............. -- -- -- 3 --------- --------- --------- --------- Net Income ............................................................ $ 170 $ 231 $ 218 $ 567 ========= ========= ========= ========= Earnings per Common Share Basic Before Cumulative Effect of Change in Accounting Principle ....... $ 0.84 $ 1.10 $ 1.08 $ 2.66 Cumulative Effect of Change in Accounting Principle - Net ........ -- -- -- 0.01 --------- --------- --------- --------- Net Income ....................................................... $ 0.84 $ 1.10 $ 1.08 $ 2.67 ========= ========= ========= ========= Diluted Before Cumulative Effect of Change in Accounting Principle ....... $ 0.84 $ 1.10 $ 1.08 $ 2.65 Cumulative Effect of Change in Accounting Principle - Net ........ -- -- -- 0.01 --------- --------- --------- --------- Net Income ....................................................... $ 0.84 $ 1.10 $ 1.08 $ 2.66 ========= ========= ========= =========
See accompanying Notes to Consolidated Financial Statements. 2 BURLINGTON RESOURCES INC. CONSOLIDATED BALANCE SHEET (UNAUDITED)
June 30, December 31, 2002 2001 ------------- ------------- (In Millions, Except Share Data) ASSETS Current Assets Cash and Cash Equivalents .......................................... $ 392 $ 116 Accounts Receivable ................................................ 408 398 Commodity Hedging Contracts and Other Derivatives .................. 28 118 Inventories ........................................................ 57 50 Other Current Assets ............................................... 51 33 ------------- ------------- 936 715 ------------- ------------- Oil & Gas Properties (Successful Efforts Method) ..................... 15,949 16,038 Other Properties ..................................................... 1,199 1,416 ------------- ------------- 17,148 17,454 Accumulated Depreciation, Depletion and Amortization ............... 8,377 8,623 ------------- ------------- Properties - Net ................................................. 8,771 8,831 ------------- ------------- Goodwill ............................................................. 835 782 ------------- ------------- Other Assets ......................................................... 236 254 ------------- ------------- Total Assets ................................................... $ 10,778 $ 10,582 ============= ============= LIABILITIES Current Liabilities Accounts Payable ................................................... $ 652 $ 599 Taxes Payable ...................................................... 104 6 Accrued Interest ................................................... 61 61 Dividends Payable .................................................. 27 28 Note Payable ....................................................... 104 -- Other Current Liabilities .......................................... 36 17 ------------- ------------- 984 711 ------------- ------------- Long-term Debt ....................................................... 3,920 4,337 ------------- ------------- Deferred Income Taxes ................................................ 1,429 1,403 ------------- ------------- Commodity Hedging Contracts and Other Derivatives .................... 29 15 ------------- ------------- Other Liabilities and Deferred Credits ............................... 592 591 ------------- ------------- Commitments and Contingent Liabilities STOCKHOLDERS' EQUITY Preferred Stock, Par Value $.01 per Share (Authorized 75,000,000 Shares; One Share Issued) .................. -- -- Common Stock, Par Value $.01 per Share (Authorized 325,000,000 Shares; Issued 241,188,688 Shares) ........ 2 2 Paid-in Capital ...................................................... 3,942 3,944 Retained Earnings .................................................... 1,494 1,332 Deferred Compensation - Restricted Stock ............................. (13) (9) Accumulated Other Comprehensive Income (Loss) ........................ 18 (106) Cost of Treasury Stock (39,888,206 and 40,395,695 Shares for 2002 and 2001, respectively) .. (1,619) (1,638) ------------- ------------- Stockholders' Equity ................................................. 3,824 3,525 ------------- ------------- Total Liabilities and Stockholders' Equity ..................... $ 10,778 $ 10,582 ============= =============
See accompanying Notes to Consolidated Financial Statements. 3 BURLINGTON RESOURCES INC. CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)
SIX MONTHS ------------------------ 2002 2001 ---------- ---------- (In Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income .................................................... $ 218 $ 567 Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities Depreciation, Depletion and Amortization .................... 433 344 Deferred Income Taxes ....................................... (28) 239 Exploration Costs ........................................... 161 122 (Gain)/Loss on Disposal of Assets ........................... (73) (2) Changes in Derivative Fair Values ........................... 26 (36) Working Capital Changes Accounts Receivable ......................................... (10) 217 Inventories ................................................. (8) (3) Other Current Assets ........................................ (16) 4 Accounts Payable ............................................ (7) (33) Taxes Payable ............................................... 99 89 Accrued Interest ............................................ 4 10 Other Current Liabilities ................................... (7) (6) Changes in Other Assets and Liabilities ....................... (16) (23) ---------- ---------- Net Cash Provided By Operating Activities ................. 776 1,489 ---------- ---------- CASH FLOWS FROM INVESTING ACTIVITIES Additions to Properties ....................................... (1,034) (657) Proceeds from Sales and Other ................................. 875 9 ---------- ---------- Net Cash Used In Investing Activities ..................... (159) (648) ---------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Borrowings ...................................... 454 400 Reduction in Borrowings ....................................... (775) (341) Dividends Paid ................................................ (56) (59) Common Stock Purchases ........................................ -- (418) Common Stock Issuances ........................................ 9 37 Other ......................................................... 14 (6) ---------- ---------- Net Cash Used In Financing Activities ..................... (354) (387) ---------- ---------- Effect of Exchange Rate Changes on Cash and Cash Equivalents .... 13 -- ---------- ---------- INCREASE IN CASH AND CASH EQUIVALENTS ........................... 276 454 CASH AND CASH EQUIVALENTS Beginning of Year ............................................. 116 132 ---------- ---------- End of Period ................................................. $ 392 $ 586 ========== ==========
See accompanying Notes to Consolidated Financial Statements. 4 BURLINGTON RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 1. BASIS OF PRESENTATION The 2001 Annual Report on Form 10-K (Form 10-K) of Burlington Resources Inc. (the Company) includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q (Quarterly Report). The financial statements for the periods presented herein are unaudited and do not contain all information required by generally accepted accounting principles to be included in a full set of financial statements. In the opinion of management, all material adjustments necessary to present fairly the results of operations have been included. All such adjustments are of a normal, recurring nature. The results of operations for any interim period are not necessarily indicative of the results of operations for the entire year. The consolidated financial statements include certain reclassifications that were made to conform to current period presentation. Investments in entities in which the Company has a significant ownership interest, generally 20 to 50 percent, or otherwise does not exercise control, are accounted for using the equity method of accounting. The Company has investments in two entities that it accounts for under the equity method, Lost Creek Gathering Company (Lost Creek) and CLAM Petroleum B.V. (CLAM). As of June 30, 2002, Lost Creek and CLAM had outstanding debt totaling $54 million and $10 million, respectively, that are non-recourse to the Company, and as a result, the Company has no legal responsibility or obligation for this debt. Management believes that Lost Creek and CLAM are financially stable and therefore will be in a position to repay the outstanding debts. Basic earnings per common share (EPS) is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding for the period. The weighted average number of common shares outstanding for computing basic EPS was 201 million and 210 million for the second quarter of 2002 and 2001, respectively, and 201 million and 212 million for the first six months of 2002 and 2001, respectively. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. The weighted average number of common shares outstanding for computing diluted EPS, including dilutive stock options, was 202 million and 211 million for the second quarter of 2002 and 2001, respectively, and 202 million and 213 million for the first six months of 2002 and 2001, respectively. For the second quarter of 2002 and 2001 and six months ended June 30, 2002 and June 30, 2001, approximately 4 million, 3 million, 4 million and 3 million shares, respectively, attributable to the potential exercise of outstanding options were excluded from the calculation of diluted EPS because the effect was antidilutive. The Company has no preferred stock or other convertible securities affecting EPS, and therefore, no adjustments related to preferred stock or other convertible securities were made to reported net income in the computation of EPS. 5 2. COMPREHENSIVE INCOME (LOSS) The following table presents comprehensive income (loss).
SIX MONTHS SIX MONTHS --------------------------------------- (In Millions) 2002 2001 ------------------ ----------------- Accumulated other comprehensive income (loss) - Beginning of Period . $ (106) $ (70) Net income .......................................................... $ 218 $ 567 ------- ------- Other comprehensive income (loss) - net of tax Hedging activities Cumulative effect of change in accounting principle - January 1, 2001 .......................................... -- (366) Current period changes in fair value of settled contracts ...... 19 56 Reclassification adjustments for settled contracts ............. (60) 264 Changes in fair value of outstanding hedging positions ......... (11) 75 ------- ------- Hedging activities ........................................ (52) 29 Foreign currency translation Foreign currency translation adjustments ....................... 176 (6) ------- ------- Total other comprehensive income .................................... 124 124 23 23 ------- ------- ------- ------- Comprehensive income ................................................ $ 342 $ 590 ======= ======= Accumulated other comprehensive income (loss) - End of Period ....... $ 18 $ (47) ======= =======
3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES The Company enters into gas swap agreements to fix the prices of anticipated future natural gas production and enters into gas swap agreements that convert its production back to market sensitive positions when matched against fixed-price gas sales. In conjunction with these swap agreements, the Company may enter into natural gas basis swap agreements to fix the sales price differential between the Company's marketing locations and Henry Hub. The Company also enters into natural gas option and crude oil agreements (collars) to establish floor and ceiling prices on anticipated future natural gas and crude oil production. In order to reduce the cost of the collars, the Company may sell natural gas and crude oil put options that effectively replace the floor with a fixed premium over the index price in low price environments. In order to protect the hedge portfolio in upward price movements, the Company may purchase natural gas and crude oil call options. There were no net premiums received when the Company entered into these option agreements. 6 As of June 30, 2002, the Company had the following natural gas and crude oil volumes hedged. Natural Gas Fixed-price Swaps
Average Fair Value Production Volumes Fixed Liability Period (MMBTU) Price (In Millions) --------------- ------------------ ---------------- -------------------- 2002 8,079,304 $3.26 $ (1) 2003 15,570,630 3.17 (10) 2004 15,613,289 3.28 (10) 2005 10,513,930 3.25 (7) 2006 to 2007 1,672,500 $3.21 $ (1)
Natural Gas Basis Swaps
Average Fair Value Production Volumes Basis Asset Period (MMBTU) Differential (In Millions) --------------- ------------------ ---------------- -------------------- 2002 8,079,304 $(0.31) $ 3 2003 15,570,630 (0.28) 2 2004 15,613,289 (0.28) 1 2005 10,513,930 (0.29) 1 2006 to 2007 1,672,500 $(0.15) $ --
Natural Gas Options
Average Fair Value Production Volumes Strike Asset/(Liability) Period Option Type (MMBTU) Price (In Millions) --------------- ------------------- ------------------- --------------- --------------------- 2002 Puts Purchased 97,790,000 $2.79 $ 30 2002 Puts Sold 90,115,000 2.14 (6) 2002 Calls Sold 97,790,000 4.10 (4) 2003 Puts Purchased 124,100,000 2.98 34 2003 Puts Sold 124,100,000 2.15 (6) 2003 Calls Sold 124,100,000 $4.83 $(22)
Crude Oil Options
Average Fair Value Production Volumes Strike Asset/(Liability) Period Option Type (Barrels) Price (In Millions) --------------- ------------------- ------------------- --------------- ---------------------- 2002 Puts Purchased 920,000 $23.00 $ 1 2002 Puts Sold 920,000 18.00 -- 2002 Calls Sold 920,000 $30.50 $ (1)
As of June 30, 2002, the fair value of the swap agreements the Company had entered into in order to convert the Company's fixed-price gas sales contracts to market sensitive positions was a $4 million asset offset by a $4 million liability basis adjustment to the carrying value of the fixed-price gas sales contracts. These agreements extend through 2005. 7 The derivative assets and liabilities represent the difference between hedged prices and market prices (intrinsic value) plus the time value associated with option hedges, on hedged volumes of the commodities as of June 30, 2002. Hedging activities increased natural gas and crude oil revenues by $93 million and $3 million, respectively, during the first six months of 2002. In addition, during the first six months of 2002, non-cash losses of $26 million were recorded in revenues associated with ineffectiveness of cash-flow and fair-value hedges and changes in the fair value of derivative instruments that do not qualify for hedge accounting. Cash-flow hedges are used by the Company to hedge exposures to the risk of variability in cash flows. 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 has foreign currency swaps to hedge its exposure to exchange rate fluctuations related to its Canadian subsidiaries. As of June 30, 2002, the Company had liabilities of $5 million related to foreign currency exchange rate hedges with contracts extending through 2005. Based on commodity prices and foreign exchange rates as of June 30, 2002, the Company expects to reclassify gains of $20 million ($13 million after tax) to earnings from the balance in accumulated other comprehensive income during the next twelve months. As of June 30, 2002, the Company had cash-flow hedge derivative assets of $27 million and derivative liabilities of $24 million. The Company also had liabilities and assets related to fair-value hedges of $5 million and $7 million, respectively. 4. COMMITMENTS AND CONTINGENCIES The Company and numerous other oil and gas companies have been named as defendants in various lawsuits alleging violations of the civil False Claims Act. These lawsuits have been consolidated by the United States Judicial Panel on Multidistrict Litigation for pre-trial proceedings in the matter of In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court for the District of Wyoming (MDL-1293). The plaintiffs contend that defendants underpaid royalties on natural gas and NGLs produced on federal and Indian lands through the use of below-market prices, improper deductions, improper measurement techniques and transactions with affiliated companies during the period of 1985 to the present. Plaintiffs allege that the royalties paid by defendants were lower than the royalties required to be paid under federal regulations and that the forms filed by defendants with the Minerals Management Service (MMS) reporting these royalty payments were false, thereby violating the civil False Claims Act. The United States has intervened in certain of the MDL-1293 cases as to some of the defendants, including the Company. The plaintiffs and the intervenor have not specified in their pleadings the amount of damages they seek from the Company. Various administrative proceedings are also pending before the MMS of the United States Department of the Interior with respect to the valuation of natural gas produced by the Company on federal and Indian lands. In general, these proceedings stem from regular MMS audits of the Company's royalty payments over various periods of time and involve the interpretation of the relevant federal regulations. Most of these proceedings have been stayed by agreement with the MMS pending the resolution of the Natural Gas Royalties Qui Tam Litigation. 8 Based on the Company's present understanding of the various governmental and False Claims Act proceedings described above, the Company believes that it has substantial defenses to these claims and intends to vigorously assert such defenses. However, in the event that the Company is found to have violated the civil False Claims Act, the Company could be subject to monetary damages and a variety of sanctions, including double damages, substantial monetary fines, civil penalties and a temporary suspension from entering into future federal mineral leases and other federal contracts for a defined period of time. While the ultimate outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the consolidated financial position of the Company, although results of operations and cash flow could be significantly impacted in the reporting periods in which such matters are resolved. The Company has also been named as a defendant in the lawsuit styled UNOCAL Netherlands B.V., et al v. Continental Netherlands Oil Company B.V., et al, No. 98-854, in the Court of Appeal in The Hague in the Netherlands. Plaintiffs, who are working interest owners in the Q-1 Block in the North Sea, have alleged that the Company and other former working interest owners in the adjacent Logger Field in the L16a Block unlawfully trespassed or were otherwise unjustly enriched by producing part of the oil from the adjoining Q-1 Block. The plaintiffs claim that the defendants infringed upon plaintiffs' right to produce the minerals present in its license area and acted in violation of generally accepted standards by failing to inform plaintiffs of the overlap of the Logger Field into the Q-1 Block. Plaintiffs seek damages of $97.5 Million as of January 1, 1997, plus interest. For all relevant periods, the Company owned a 37.5% working interest in the Logger Field. Following a trial, the District Court in The Hague rendered a Judgment in favor of the defendants, including the Company, dismissing all claims. Plaintiffs thereafter appealed. On October 19, 2000, the Court of Appeal in The Hague issued an interim Judgment in favor of the plaintiffs and ordered that additional evidence be presented to the court relating to issues of both liability and damages. The Company and the other defendants are continuing to present evidence to the Court and vigorously assert defenses against these claims. The Company has also asserted claims of indemnity against two of the defendants from whom it had acquired a portion of its working interest share. If the Company is successful in enforcing the indemnities, its working interest share of any adverse judgment could be reduced to 15% for some of the periods covered by plaintiffs' lawsuit. The Company is unable at this time to reasonably predict the outcome, or, in the event of an unfavorable outcome, to reasonably estimate the possible loss or range of loss, if any, in this lawsuit. In addition to the foregoing, the Company and its subsidiaries are named defendants in numerous other lawsuits and named parties in numerous governmental and other proceedings arising in the ordinary course of business, including: claims for personal injury and property damage, claims challenging oil and gas royalty and severance tax payments, claims related to joint interest billings under oil and gas operating agreements, claims alleging mismeasurement of volumes and wrongful analysis of heating content of natural gas and other claims in the nature of contract, regulatory or employment disputes. None of the governmental proceedings involve foreign governments. While the ultimate outcome of these other lawsuits and proceedings cannot be predicted with certainty, management believes that the resolution of these other matters will not have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company. 9 5. DEBT In February 2002, Burlington Resources Finance Company (BRFC) issued $350 million of 5.7% Notes due March 1, 2007. In June 2002, the Company retired a $100 million 8 1/4% Note. To retire the 8 1/4% Note, the Company issued a promissory note for $104 million at a per annum rate equal to the sum of Eurodollar rates plus 0.70 percent. The promissory note is due September 17, 2002. During the first six months of 2002, the Company also retired $675 million of net commercial paper and has no commercial paper outstanding at June 30, 2002. In June 2002, the Company commenced an offer to exchange its outstanding 5.6% Notes due 2006, 6.5% Notes due 2011 and 7.4% Notes due 2031, which were issued by BRFC and fully and unconditionally guaranteed by BR, in a private offering in November 2001 (Private Notes), for a like principal amount of 5.6% Notes due 2006, 6.5% Notes due 2011 and 7.4% Notes due 2031 to be issued by BRFC, fully and unconditionally guaranteed by BR and registered under the Securities Act of 1933, as amended (Registered Notes). In July 2002, following the expiration of the exchange offer, the Company issued the Registered Notes. All of the Private Notes were exchanged for Registered Notes and the Private Notes were cancelled. The fair value of the Company's long-term debt at June 30, 2002 and December 31, 2001, excluding commercial paper, was approximately $4,166 million and $3,727 million, respectively, based on quoted market prices. 6. PROPERTY TRANSACTIONS On January 3, 2002, the Company consummated a property acquisition from ATCO Gas and Pipeline Ltd. (ATCO), a Canadian regulated gas utility, for approximately $344 million. During the fourth quarter of 2001, the Company announced its intent to sell certain non-core, non-strategic properties in order to improve the overall quality of its portfolio, primarily in the U.S. Due to their high cost structure, high production volume decline rates and limited growth opportunities, substantially all of the Shelf, and south and east Texas assets are included in the non-core, non-strategic properties. During the second quarter of 2002, the Company sold certain non-core, non-strategic properties, including the Val Verde gathering and processing plant, and generated proceeds, before post closing adjustments, of approximately $892 million and recognized a net gain of $73 million. The net gain includes an estimated loss of $114 million associated with purchase and sale agreements that were signed but the transactions not closed as of June 30, 2002. The net book value of the properties held for sale at June 30, 2002 was $234 million. The Company intends to complete the remaining property sales by year-end 2002 and expects to generate additional proceeds in excess of $300 million. The Company has and expects to use the proceeds generated from property sales to repay debt and for general corporate purposes. In connection with the divestiture program, the Company also recorded restructuring liabilities of $10 million in the fourth quarter of 2001. As of June 30, 2002, $2 million of the restructuring liabilities remained outstanding as Accounts Payable on the Consolidated Balance Sheet. 10 7. INCOME TAXES The Company's effective income tax rate decreased to 19 percent at June 30, 2002 from 38 percent at December 31, 2001 primarily due to interest deductions allowed in both the U.S. and Canada on transactions associated with debt financing entered into in the second half of 2001 and the first quarter of 2002. 8. SEGMENT AND GEOGRAPHIC INFORMATION The Company's reportable segments are USA, Canada and Other International (Intl). The segments are engaged principally in the exploration, development, production and marketing of crude oil, NGLs and natural gas. The accounting policies for the segments are the same as those disclosed in Note 1 of Notes to Consolidated Financial Statements included in the Company's Form 10-K. Intersegment sales were $1 million and $53 million during the second quarter of 2002 and 2001, respectively, and were $15 million and $124 million during the first six months of 2002 and 2001, respectively. The following tables present information about reported segment operations.
Second Quarter ------------------------------------------------------------------------------------------------------ 2002 2001 -------------------------------------------------- -------------------------------------------------- USA Canada Intl Corp. Total USA Canada Intl Corp. Total -------- -------- -------- -------- -------- -------- -------- -------- -------- -------- (In Millions) (In Millions) Revenues ................. $ 425 $ 306 $ 38 $ -- $ 769 $ 623 $ 263 $ 42 $ -- $ 928 Consolidated income before income taxes .... 341 59 (83) (110) 207 323 143 (1) (85) 380 Additions to properties .. $ 53 $ 101 $ 88 $ 4 $ 246 $ 128 $ 67 $ 41 $ 6 $ 242
Six Months ------------------------------------------------------------------------------------------------------ 2002 2001 -------------------------------------------------- -------------------------------------------------- USA Canada Intl Corp. Total USA Canada Intl Corp. Total -------- -------- -------- -------- -------- -------- -------- -------- -------- -------- (In Millions) (In Millions) Revenues ................. $ 817 $ 549 $ 86 $ -- $ 1,452 $ 1,375 $ 608 $ 97 $ -- $ 2,080 Consolidated income before income taxes .... 478 93 (79) (224) 268 720 381 23 (187) 937 Additions to properties .. $ 126 $ 625 $ 206 $ 25 $ 982 $ 279 $ 265 $ 105 $ 6 $ 655
9. ACCOUNTING PRONOUNCEMENTS In April 2002, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 145, Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections (SFAS No. 145). SFAS No. 145, which is effective for fiscal years beginning after May 15, 2002, provides guidance for income statement classification of gains and losses on extinguishment of debt and accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. The Company is currently assessing the impact of SFAS No. 145 and therefore, cannot reasonably estimate the effects of this statement on its consolidated financial position, results of operations or cash flows. 11 In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligation. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-live asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company has embarked upon engineering studies and is currently accumulating, reviewing and analyzing data in order to assess the impact of SFAS No. 143. The process is not complete and therefore, at this time, the Company cannot reasonably estimate the effect of this statement on its consolidated financial position, results of operations or cash flows. The Company expects to complete the process during the third quarter of 2002 and expects to disclose the anticipated effect of this statement on the Company's consolidated financial position, results of operations and cash flows in its third quarter 2002 Form 10-Q. 10. GOODWILL Effective January 1, 2002, the Company adopted SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 142 requires the Company to test goodwill for impairment rather than amortize. Under the transition provisions of SFAS No. 142, goodwill acquired in a business combination for which the acquisition date is after June 30, 2001 is not to be amortized and is to be reviewed for impairment under existing standards until adoption of SFAS 142 on January 1, 2002. The entire goodwill balance of $835 million at June 30, 2002, which is not deductible for tax purposes, is related to the acquisition of Canadian Hunter Exploration Ltd. (Hunter) on December 5, 2001. Accordingly, the Company recorded no goodwill amortization during 2001. With the acquisition of Hunter, the Company gained Hunter's significant interest in Canada's Deep Basin, North America's third-largest natural gas field, increased its critical mass and enhanced its position as a leading North American natural gas producer. The Company also obtained the exploration expertise of Hunter's workforce, gained additional cost optimization by eliminating duplicate efforts, increased purchasing power and gained greater marketing flexibility in optimizing sales and accessing key market information. All of the goodwill was assigned to the Company's Canadian reporting unit for assessing impairment. The initial adoption of SFAS No. 142 required the Company to perform a two-step fair value based goodwill impairment test. The first step of the test compares the book values of the Company's reporting units to their estimated fair values. The second step of the goodwill impairment test is only required if the net book value of the reporting unit exceeds the fair value. The second step of the goodwill impairment test compares the implied fair value of goodwill in accordance with the methodology prescribed by SFAS No. 142 to its book value to determine if an impairment is required. During the second quarter of 2002, the Company completed the first step of its impairment analysis related to its goodwill and determined that the Company's fair value of its Canadian reporting unit exceeded its net book value at January 1, 2002, thereby eliminating the need for the second step. The following table reflects the changes in the carrying amount, including the final purchase accounting adjustment, of goodwill during the year as it relates to the Canadian reporting unit.
(In Millions) Balance-January 1, 2002....................................................... $782 Changes in foreign exchange rates during the period........................... 39 Purchase accounting adjustments related to foreign income taxes............... 14 ---- Balance-June 30, 2002......................................................... $835 ====
12 11. PRO FORMA SUMMARY FINANCIAL INFORMATION On December 5, 2001, the Company acquired all of the outstanding shares of Hunter for cash consideration of Canadian $53 per share representing an aggregate value of approximately U.S. $2.1 billion. The following table presents the unaudited pro forma results of the Company as though the acquisition of Hunter had occurred on January 1, 2001. Pro forma results are not necessarily indicative of actual results.
Second Quarter Six Months 2001 2001 ------------- ------------- (In Millions, Except per Share Amounts) Revenues .................................................. $ 1,104 $ 2,497 Net income ................................................ 284 698 Basic earnings per share .................................. 1.36 3.29 Diluted earnings per share ................................ $ 1.35 $ 3.28
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 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, 2002 and December 31, 2001 was 51 percent and 55 percent, respectively. The reduction in total debt to total capital was accomplished by the disposition of assets and the generation of cash flows from operations. The Company believes that it will generate sufficient cash from operations to fund the remaining 2002 capital expenditures in today's natural gas price environment. Effective January 2, 2002, the Company entered into a $350 million bridge revolving credit facility (Facility) in order to finance the acquisition of certain assets from ATCO. On January 2, 2002, the Company issued commercial paper under the Facility to fund the acquisition. In February 2002, BRFC issued $350 million of 5.7 % Notes due March 1, 2007 (February Notes). The proceeds from the February Notes were used to retire such commercial paper and the Company terminated the Facility. The February Notes reduced the Company's amount available under its shelf registration statement on file with the Securities and Exchange Commission to $397 million. In June 2002, the Company restored its shelf registration statement to $1,500 million. At June 30, 2002, the Company had $392 million of cash and cash equivalents on hand. In June 2002, the Company retired a $100 million 8 1/4% Note. To retire the 8 1/4% Note, the Company issued a promissory note for $104 million at a per annum rate equal to the sum of Eurodollar rates plus 0.70 percent. The promissory note is due September 17, 2002. During the first six months of 2002, the Company also retired $675 million of net commercial paper and has no commercial paper outstanding at June 30, 2002. In June 2002, the Company commenced an offer to exchange its outstanding 5.6% Notes due 2006, 6.5% Notes due 2011 and 7.4% Notes due 2031, which were issued by BRFC and fully and unconditionally guaranteed by BR, in a private offering in November 2001 (Private Notes), for a like principal amount of 5.6% Notes due 2006, 6.5% Notes due 2011 and 7.4% Notes due 13 2031 to be issued by BRFC, fully and unconditionally guaranteed by BR and registered under the Securities Act of 1933, as amended (Registered Notes). In July 2002, following the expiration of the exchange offer, the Company issued the Registered Notes. All of the Private Notes were exchanged for Registered Notes and the Private Notes were cancelled. The Company had credit commitments in the form of revolving credit facilities (revolvers) as of June 30, 2002. The revolvers, which are comprised of agreements for $600 million, $400 million and approximately Canadian $471 million (U.S. $310 million), are available to cover debt due within one year. Therefore, commercial paper, credit facility notes and fixed-rate debt due within one year are classified as long-term debt. Currently, there are no amounts outstanding under the revolvers and no outstanding commercial paper. Outstanding commercial paper would reduce the amount of credit available under the revolvers. The $600 million revolver expires in December 2006 and the $400 million and Canadian $471 million revolvers expire in December 2002 unless renewed by mutual consent. The Company has the option to convert the outstanding balances on the $400 million and Canadian $471 million revolvers to one-year and five-year plus one day term notes, respectively. Under the covenants of the revolvers, Company debt cannot exceed 60 percent of capitalization (as defined in the agreements). Net cash provided by operating activities during the first six months of 2002 was $776 million compared to $1,489 million in 2001. The decrease was primarily due to lower income and higher working capital needs. Lower income is principally the result of lower natural gas and NGL prices partially offset by higher natural gas and NGL sales volumes. 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 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. However, management believes that these other commitments or uncertainties will not have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company. Capital Expenditures Capital expenditures for the first six months of 2002 totaled $982 million compared to $655 million in 2001. The Company invested $484 million on internal development and exploration of oil and gas properties during the first six months of 2002 compared to $489 million in 2001. The increase in capital expenditures in 2002 are primarily due to property acquisitions where the Company invested $417 million in the first six months of 2002 compared to $92 million in 2001. Property acquisitions include the purchase of certain assets on January 3, 2002 from ATCO Gas and Pipeline Ltd., a Canadian regulated gas utility, for approximately $344 million. The Company's base capital expenditures, which exclude acquisitions, are projected to be approximately $1.3 billion for all of 2002. This amount is expected to be used primarily for the development and exploration of oil and gas properties and plants and pipeline expenditures. The Company expects to fund base capital expenditures from internally generated operating cash flows. 14 During the fourth quarter of 2001, the Company announced its intent to sell certain non-core, non-strategic properties in order to improve the overall quality of its portfolio, primarily in the U.S. Due to their high cost structure, high production volume decline rates and limited growth opportunities, substantially all of the Shelf, and south and east Texas assets are included in the non-core, non-strategic properties. During the second quarter of 2002, the Company sold certain non-core, non-strategic properties, including the Val Verde gathering and processing plant (Val Verde Plant), and generated proceeds, before post closing adjustments, of approximately $892 million and recognized a net pretax gain of $73 million. The net pretax gain includes an estimated pretax loss of $114 million associated with purchase and sale agreements that were signed but the transactions not closed as of June 30, 2002. The net book value of the properties held for sale at June 30, 2002 was $234 million. The Company intends to complete the remaining property sales by year-end 2002 and expects to generate additional proceeds in excess of $300 million. The Company has and expects to use the proceeds generated from property sales to repay debt and for general corporate purposes. In connection with the divestiture program, in the fourth quarter of 2001, the Company also recorded restructuring liabilities of $10 million. As of June 30, 2002, $2 million of the restructuring liabilities remained outstanding as Accounts Payable on the Consolidated Balance Sheet. Dividends On July 17, 2002, the Board of Directors declared a quarterly common stock cash dividend of $0.1375 per share, with record and payment dates of September 6, 2002 and October 1, 2002, respectively. Results of Operations - Second Quarter 2002 Compared to Second Quarter 2001 The Company reported net income of $170 million or $0.84 diluted earnings per common share in second quarter 2002 compared to net income of $231 million or $1.10 diluted earnings per common share in second quarter 2001. Net income in second quarter 2002 included a net after tax gain of $45 million or $0.23 per diluted share related to the disposal of assets. Net income in second quarter 2002 and 2001 also included an after tax loss of $1 million or nil per diluted share and $14 million or $0.07 per diluted share, respectively, consisting of ineffectiveness related to cash-flow and fair-value hedges and changes in the fair value of derivative instruments that do not qualify for hedge accounting. Cash-flow hedges are used by the Company to hedge exposures to the risk of variability in cash flows. 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. Revenues Revenues decreased $159 million to $769 million in second quarter 2002 compared to $928 million in second quarter 2001. As described below, the $159 million decrease in revenues primarily consists of $250 million related to lower commodity prices, $24 million due to lower revenues related to ineffectiveness on hedging activities partially offset by $111 million related to higher production volumes. Including a $0.14 realized gain per MCF related to hedging activities, average gas prices decreased $1.23 per MCF in second quarter 2002 to $3.14 per MCF from $4.37 per MCF in second quarter 2001 which decreased revenues $214 million. Average NGL prices decreased $6.02 per barrel in second quarter 2002 to $13.86 per barrel from $19.88 per barrel in second quarter 2001, resulting in reduced revenues of $36 million. Average oil 15 prices increased $0.02 per barrel in second quarter 2002 to $24.64 per barrel from $24.62 per barrel in second quarter 2001. There were no hedging gains or losses related to oil volumes during second quarter 2002. In second quarter 2002 and 2001, revenues included $10 million and $11 million, respectively, generated from third parties by the Val Verde Plant that was sold in June 2002. In second quarter 2002 and 2001, revenues also included a loss of $1 million and a gain of $23 million, respectively, related to ineffectiveness of cash-flow and fair-value hedges and changes in the fair value of derivative instruments that do not qualify for hedge accounting. Gas sales volumes increased 248 MMCF per day in second quarter 2002 to 1,927 MMCF per day from 1,679 MMCF per day in second quarter 2001 resulting in increased revenues of $98 million. NGL sales volumes increased 18.5 MBbls per day in second quarter 2002 to 65.0 MBbls per day from 46.5 MBbls per day in second quarter 2001, resulting in higher revenues of $34 million from quarter to quarter. Oil sales volumes decreased 9.5 MBbls per day in second quarter 2002 to 54.8 MBbls per day from 64.3 MBbls per day in second quarter 2001 reducing revenues $21 million. Gas sales volumes in Canada increased 397 MMCF per day primarily due to the acquisition of Canadian Hunter Exploration Ltd. (Hunter) in late 2001 partially offset by natural declines of 77 MMCF per day in Onshore Gulf Coast and the Gulf of Mexico and natural declines of 80 MMCF per day in San Juan. NGL sales volumes in Canada also increased 17.2 MBbls per day primarily due to the acquisition of Hunter. Oil sales volumes decreased 4.7 MBbls per day primarily due to natural declines in the Gulf of Mexico and Canada and 2.9 MBbls per day primarily due to asset sales in Mid-Continent and Canada. Total Costs and Other Income Total costs and other income were $562 million in second quarter 2002 compared to $548 million in second quarter 2001. The $14 million increase was primarily due to a $52 million increase in exploration costs, a $39 million increase in depreciation, depletion and amortization (DD&A), a $24 million increase in interest expense and a $4 million increase in general and administrative (G&A) expenses partially offset by a $71 million increase in gain on disposal of assets, a $17 million decrease in taxes other than income taxes, an $8 million decrease in production and processing expenses, a $5 million decrease in transportation expenses and a $4 million increase in other income. Exploration costs increased primarily due to higher drilling rig expenses of $36 million, higher amortization of undeveloped lease costs of $19 million and higher geological and geophysical (G&G) and other expenses of $9 million partially offset by lower exploratory dry hole costs of $12 million. The higher drilling rig expenses, which were approximately $40 million during the period, were attributable to the subletting of a deepwater drilling rig currently under lease to the Company. This $40 million charge covers the anticipated loss for the remaining term of the lease. DD&A increased primarily due to a higher unit-of-production rate related to changes in production resulting from the Canadian acquisitions, which had higher rates than the average unit-of-production rates for the Company. DD&A also increased due to higher gas production volumes in Canada. Interest expense increased primarily due to higher debt balances during second quarter 2002 resulting from the Hunter acquisition in late 2001 and other property acquisitions consummated in early 2002. G&A expenses were higher in 2002 compared to 2001 primarily due to payroll related costs. Taxes other than income taxes decreased primarily due to lower oil and gas revenues. Production and processing expenses decreased primarily due to lower well operating costs related to the Shelf and other divestiture properties partially offset by higher Canadian expenses resulting from the acquisition of Hunter in December 2001. Transportation expenses decreased primarily due to lower contract rates. 16 Income Tax Expense Income taxes were an expense of $37 million in second quarter 2002 compared to $149 million in second quarter 2001. The decrease in tax expense was primarily due to lower pretax income. The Company also recorded benefits of $42 million in second quarter 2002 compared to $2 million in second quarter 2001 related to interest deductions allowed in both the U.S. and Canada on transactions associated with debt financing entered into in the second half of 2001 and the first quarter of 2002. Section 29 Tax Credits were $9 million in second quarter 2002 compared to $5 million in second quarter 2001. Results of Operations - First Six Months of 2002 Compared to First Six Months of 2001 The Company reported net income of $218 million or $1.08 diluted earnings per common share in the first six months of 2002 compared to net income of $567 million or $2.66 diluted earnings per common share in the first six months of 2001. 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. Net income in the first six months of 2002 also included an after tax loss of $16 million or $0.08 per diluted share compared to an after tax gain of $21 million or $0.10 per diluted share in the first six months of 2001, consisting of the cumulative effect of change in accounting principle, ineffectiveness related to cash-flow and fair-value hedges and changes in the fair value of derivative instruments that do not qualify for hedge accounting. Revenues Revenues decreased $628 million to $1,452 million in the first six months of 2002 compared to $2,080 million in the first six months of 2001. As described below, the $628 million decrease in revenues primarily consists of $834 million related to lower commodity prices, $56 million due to lower revenues related to ineffectiveness on hedging activities partially offset by $260 million related to higher production volumes. Including a $0.26 realized gain per MCF related to hedging activities, average gas prices decreased $2.04 per MCF in the first six months of 2002 to $3.01 per MCF from $5.05 per MCF in the first six months of 2001 which decreased revenues $728 million. Including a $0.30 realized gain per barrel related to hedging activities, average oil prices decreased $2.10 per barrel in the first six months of 2002 to $23.10 per barrel from $25.20 per barrel in the first six months of 2001 resulting in reduced revenues of $22 million. Average NGL prices decreased $7.69 per barrel in the first six months of 2002 to $13.21 per barrel from $20.90 per barrel in the first six months of 2001, resulting in reduced revenues of $84 million. In the first six months of 2002 and 2001, revenues included $19 million and $22 million, respectively, generated from third parties by the Val Verde Plant that was sold in June 2002. In the first six months of 2002 and 2001, revenues also included a loss of $26 million and a gain of $30 million, respectively, related to ineffectiveness of cash-flow and fair-value hedges and changes in the fair value of derivative instruments that do not qualify for hedge accounting. Gas sales volumes increased 255 MMCF per day in the first six months of 2002 to 1,972 MMCF per day from 1,717 MMCF per day in the first six months of 2001 resulting in increased revenues of $233 million. NGL sales volumes increased 16.7 MBbls per day in the first six months of 2002 to 60.7 MBbls per day from 44.0 MBbls per day in the first six months of 2001, resulting in higher revenues of $63 million. Oil sales volumes decreased 7.9 MBbls per day in the first six months of 2002 to 57.3 MBbls per day from 65.2 MBbls per day in the first six months of 2001 reducing revenues $36 million. Gas sales volumes in Canada increased 392 MMCF per day primarily due to the acquisition of Hunter in late 2001 partially offset by natural 17 declines of 81 MMCF per day in Onshore Gulf Coast and the Shelf and natural declines of 74 MMCF per day in San Juan. NGL sales volumes in Canada also increased 17.8 MBbls per day primarily due to the acquisition of Hunter. Oil sales volumes decreased 4.6 MBbls per day primarily due to natural declines in the Gulf of Mexico and Canada and 2.3 MBbls per day primarily due to asset sales in Mid-Continent and Canada. Total Costs and Other Income Total costs and other income were $1,184 million in the first six months of 2002 compared to $1,143 million in the first six months of 2001. The $41 million increase was primarily due to an $89 million increase in DD&A, a $51 million increase in interest expense, a $39 million increase in exploration costs and a $10 million increase in production and processing expenses partially offset by a $71 million increase in gain on disposal of assets, a $51 million decrease in taxes other than income taxes, a $14 million increase in other income, a $10 million decrease in transportation expenses and a $2 million decrease in G&A expenses. DD&A increased primarily due to a higher unit-of-production rate related to changes in production resulting from the Canadian acquisitions, which had higher rates than the average unit-of-production rates for the Company. DD&A also increased due to higher gas production volumes in Canada. Interest expense increased primarily due to higher debt balances during the first six months of 2002 resulting from the Hunter acquisition in late 2001 and other property acquisitions consummated in early 2002. Exploration costs increased primarily due to higher drilling rig costs of $38 million, higher amortization of undeveloped lease costs of $31 million and higher G&G and other expenses of $13 million partially offset by lower exploratory dry hole costs of $43 million. The higher drilling rig expenses, which were approximately $40 million during the period, were attributable to the subletting of a deepwater drilling rig currently under lease to the Company. This $40 million charge covers the anticipated loss for the remaining term of the lease. Production and processing expenses increased primarily due to higher Canadian expenses resulting from the acquisition of Hunter in December 2001. Taxes other than income taxes decreased primarily due to lower oil and gas revenues. Other income increased primarily due to lower miscellaneous expenses incurred in 2002. Transportation expenses decreased primarily due to lower contract rates and G&A expenses were lower in 2002 compared to 2001 primarily due to higher payroll related costs recorded in 2001. Income tax Expense Income taxes were an expense of $50 million in the first six months of 2002 compared to $373 million in the first six months of 2001. The decrease in tax expense was primarily due to lower pretax income. The Company also recorded benefits of $55 million in the first six months of 2002 compared to $6 million in 2001 related to interest deductions allowed in both the U.S. and Canada on transactions associated with debt financing entered into in the second half of 2001 and the first quarter of 2002. Section 29 Tax Credits were $12 million in the first six months of 2002 compared to $13 million in the first six months of 2001. Outlook For the remainder of 2002, the Company expects production volumes to decline from second quarter average volumes of 2,646 MMCFE per day. The Company expects full year production volumes to average between 2,425 and 2,610 MMCFE per day as a result of property sales and annual plant and pipeline maintenance extending into the third quarter of 2002. The declines in average daily production volumes related to property sales and plant and pipeline 18 maintenance are expected to be partially offset by additional production volumes in Madden Field and the initiation of winter drilling in Canada. Additionally, in June 2002, the Company sold the Val Verde Plant, which contributed $19 million in third party revenues during the first six months of 2002. As a result of the sale, in addition to the future revenue loss, the Company expects its transportation expenses to increase approximately $40 million annually offset partially by lower operating expenses of approximately $11 million and lower DD&A of approximately $9 million. The current outlook for natural gas prices is affected by natural gas inventory levels that are currently high based upon historical levels. This indicator may lead to lower short-term natural gas prices. However, the Company cannot accurately predict future natural gas, NGL and crude oil prices, and therefore, it cannot determine what effect the potential reduced production volumes will have on future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of crude oil and natural gas reserves at economical costs are critical to the Company's long-term success. For 2002, the Company plans to spend $1.3 billion on development, exploration and plants and pipeline capital and additional funds on acquisitions. Results of the capital programs are evaluated annually and cannot be predicted at this time, however the results will be disclosed as of the end of the year in the Company's 2002 Form 10-K. Accounting Pronouncements In April 2002, the Financial Accounting Standards Board (FASB) issued Statement of Financial Standards No. 145, Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections (SFAS No. 145). SFAS No. 145, which is effective for fiscal years beginning after May 15, 2002, provides guidance for income statement classification of gains and losses on extinguishment of debt and accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. The Company is currently assessing the impact of SFAS No. 145 and therefore, cannot reasonably estimate the effects of this statement on its consolidated financial position, results of operations or cash flows. In June 2001, the FASB issued SFAS No. 143, Accounting for 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-live asset. Subsequently, the asset retirement cost should be allocated to expense using a systematic and rational method. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company has embarked upon engineering studies and is accumulating, reviewing and analyzing data in order to assess the impact of SFAS No. 143. The process is not complete and therefore, at this time, the Company cannot reasonably estimate the effect of this statement on its consolidated financial position, results of operations or cash flows. The Company expects to complete the process during the third quarter of 2002 and expects to disclose the anticipated effect of this statement on the Company's consolidated financial position, results of operations and cash flows in its third quarter 2002 Form 10-Q. 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. 19 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 U.S. producing basin or at a U.S. market hub, which is referred to as the "basis differential." The Company utilizes over-the-counter price and basis swaps as well as options to hedge its production in order to decrease its price risk exposure. The gains and losses realized as a result of these price and basis derivative transactions are recorded in income when the hedged commodity is sold. In order to accommodate the needs of its customers, the Company also uses variable price swaps to convert natural gas sold under fixed-price contracts to market sensitive prices. The Company uses a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of crude oil and natural gas may have on the fair value of the Company's derivative instruments. For example, at June 30, 2002, the potential decrease in fair value of derivative instruments assuming a 10 percent adverse movement (an increase in the underlying commodities prices) would result in a $54 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, 2002, the Company expects to reclassify gains of $20 million ($13 million after tax) to earnings from the balance in accumulated other comprehensive loss during the next twelve months. As of June 30, 2002, the Company had cash-flow hedge derivative assets of $27 million and derivative liabilities of $24 million. The Company also had liabilities and assets related to fair-value hedges of $5 million and $7 million, respectively. Forward-looking Statements This Quarterly Report contains projections and other forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. These projections and statements reflect the Company's current views with respect to future events and financial performance. No assurances can be given, however, that these events will occur or that these projections will be achieved and actual results could differ materially from those projected as a result` of certain factors. A discussion of these factors is included in the Company's 2001 Form 10-K. PART II - OTHER INFORMATION ITEM 1. Legal Proceedings The Company and numerous other oil and gas companies have been named as defendants in various lawsuits alleging violations of the civil False Claims Act. These lawsuits have been consolidated by the United States Judicial Panel on Multidistrict Litigation for pre-trial proceedings in the matter of In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court for the District of Wyoming (MDL-1293). The plaintiffs contend that defendants underpaid royalties on natural gas and NGLs produced on federal and Indian lands 20 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 have been stayed by agreement with the MMS pending the resolution of the Natural Gas Royalties Qui Tam Litigation. Based on the Company's present understanding of the various governmental and False Claims Act proceedings described above, the Company believes that it has substantial defenses to these claims and intends to vigorously assert such defenses. However, in the event that the Company is found to have violated the civil False Claims Act, the Company could be subject to monetary damages and a variety of sanctions, including double damages, substantial monetary fines, civil penalties and a temporary suspension from entering into future federal mineral leases and other federal contracts for a defined period of time. While the ultimate outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the consolidated financial position of the Company, although results of operations and cash flow could be significantly impacted in the reporting periods in which such matters are resolved. The Company has also been named as a defendant in the lawsuit styled UNOCAL Netherlands B.V., et al v. Continental Netherlands Oil Company B.V., et al, No. 98-854, in the Court of Appeal in The Hague in the Netherlands. Plaintiffs, who are working interest owners in the Q-1 Block in the North Sea, have alleged that the Company and other former working interest owners in the adjacent Logger Field in the L16a Block unlawfully trespassed or were otherwise unjustly enriched by producing part of the oil from the adjoining Q-1 Block. The plaintiffs claim that the defendants infringed upon plaintiffs' right to produce the minerals present in its license area and acted in violation of generally accepted standards by failing to inform plaintiffs of the overlap of the Logger Field into the Q-1 Block. Plaintiffs seek damages of $97.5 Million as of January 1, 1997, plus interest. For all relevant periods, the Company owned a 37.5% working interest in the Logger Field. Following a trial, the District Court in The Hague rendered a Judgment in favor of the defendants, including the Company, dismissing all claims. Plaintiffs thereafter appealed. On October 19, 2000, the Court of Appeal in The Hague issued an interim Judgment in favor of the plaintiffs and ordered that additional evidence be presented to the court relating to issues of both liability and damages. The Company and the other defendants are continuing to present evidence to the Court and vigorously assert defenses against these claims. The Company has also asserted claims of indemnity against two of the defendants from whom it had acquired a portion of its working interest share. If the Company is successful in enforcing the indemnities, its working interest share of any adverse judgment could be reduced to 15% for some of the periods covered by plaintiffs' lawsuit. The Company is unable at this time to reasonably predict the outcome, or, in the event of an unfavorable outcome, to reasonably estimate the possible loss or range of loss, if any, in this lawsuit. 21 In addition to the foregoing, the Company and its subsidiaries are named defendants in numerous other lawsuits and named parties in numerous governmental and other proceedings arising in the ordinary course of business, including: claims for personal injury and property damage, claims challenging oil and gas royalty and severance tax payments, claims related to joint interest billings under oil and gas operating agreements, claims alleging mismeasurement of volumes and wrongful analysis of heating content of natural gas and other claims in the nature of contract, regulatory or employment disputes. None of the governmental proceedings involve foreign governments. While the ultimate outcome of these other lawsuits and proceedings cannot be predicted with certainty, management believes that the resolution of these other matters will not have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company. ITEM 4. Submission of Matters to a Vote of Security Holders The annual meeting of stockholders was held on April 17, 2002. 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 178,924,314 2,712,408 L. I. Grant 178,928,061 2,708,661 R. J. Harding 178,897,072 2,739,650 J. T. LaMacchia 178,900,156 2,736,566 J. F. McDonald 178,928,396 2,708,326 K. W. Orce 178,912,321 2,724,401 D. M. Roberts 178,918,646 2,718,076 J. F. Schwarz 178,913,676 2,723,046 W. Scott, Jr. 178,886,792 2,749,930 B. S. Shackouls 178,836,794 2,799,928 W. E. Wade, Jr. 178,879,051 2,757,671
The Stockholders also approved the Burlington Resources 2002 Stock Incentive Plan at the annual meeting with 171,119,893 votes for, 9,324,848 votes against and 1,191,981 votes abstaining. There were no broker non-votes with respect to any matters submitted to a vote of stockholders. 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. 10.1* Amendment No. 1 dated April 25, 2002 to $400 million Short-term Revolving Credit Agreement (incorporated by reference to Exhibit 10.18 to Amendment No. 1 to Form S-4 filed June 21, 2002) 10.2* Amendment No. 1 dated April 25, 2002 to $600 million Long-term Revolving Credit Agreement (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to Form S-4 filed June 21, 2002) 10.3* Amendment No. 1 dated April 25, 2002 to Canadian Credit Agreement (incorporated by reference to Exhibit 10.32 to Amendment No. 1 to Form S-4 filed June 21, 2002) 10.4* Burlington Resources Inc. 2002 Stock Incentive Plan (incorporated by reference to Exhibit A to Schedule 14A filed March 15, 2002) 10.5* Form of agreement on pension related benefits with certain former Seattle holding company office employees, including L. David Hanower (incorporated by reference to Exhibit 10.26 to Form 10-K, filed March 17, 2000) * Exhibit incorporated by reference. B. Reports on Form 8-K The Company filed no reports on Form 8-K during the second quarter of 2002. Items 2, 3 and 5 of Part II are not applicable and have been omitted. 23 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. BURLINGTON RESOURCES INC. ---------------------------------- (Registrant) By /s/ STEVEN J. SHAPIRO ------------------------------- Steven J. Shapiro Senior Vice President and Chief Financial Officer By /s/ JOSEPH P. McCOY ------------------------------- Joseph P. McCoy Vice President, Controller and Chief Accounting Officer Date: August 9, 2002 24 Certification Accompanying Periodic Report Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350) The undersigned, Bobby S. Shackouls, Chairman of the Board, President and Chief Executive Officer of Burlington Resources Inc. ("Company"), and Steven J. Shapiro, Senior Vice President and Chief Financial Officer of the Company, each hereby certifies that the Quarterly Report of the Company on Form 10-Q for the period ended June 30, 2002 (the "Report") (1) fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934 and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and the results of operations of the Company. /s/ BOBBY S. SHACKOULS ------------------------------------- Dated: August 9, 2002 Bobby S. Shackouls Chairman of the Board, President and Chief Executive Officer /s/ STEVEN J. SHAPIRO ------------------------------------- Dated: August 9, 2002 Steven J. Shapiro Senior Vice President and Chief Financial Officer