10-Q 1 h01199e10vq.txt BURLINGTON RESOURCES INC.- SEPTEMBER 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 September 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 September 30, 2002 201,332,800 PART I - FINANCIAL INFORMATION ITEM 1. Financial Statements BURLINGTON RESOURCES INC. CONSOLIDATED STATEMENT OF INCOME (UNAUDITED)
THIRD QUARTER NINE MONTHS ---------------------------- ---------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ----------- (In Millions, Except per Share Amounts) Revenues......................................................... $ 630 $ 666 $ 2,082 $ 2,746 ----------- ----------- ----------- ----------- Costs and Other Income Taxes Other than Income Taxes.................................. 29 26 92 140 Transportation Expense......................................... 79 75 216 222 Production and Processing...................................... 117 126 365 364 Depreciation, Depletion and Amortization....................... 192 183 625 527 Exploration Costs.............................................. 53 79 214 201 Administrative................................................. 36 34 113 113 Interest Expense............................................... 65 41 207 132 (Gain)/Loss on Disposal of Assets.............................. 6 1 (67) (1) Other Expense (Income) - Net................................... (14) (5) (18) 5 ----------- ----------- ----------- ----------- Total Costs and Other Income..................................... 563 560 1,747 1,703 Income Before Income Taxes....................................... 67 106 335 1,043 Income Tax Expense (Benefit)..................................... (12) 33 38 406 ----------- ----------- ----------- ----------- Net Income Before Cumulative Effect of Change in Accounting Principle..................................................... 79 73 297 637 Cumulative Effect of Change in Accounting Principle - Net........ - - - 3 ----------- ----------- ----------- ----------- Net Income....................................................... $ 79 $ 73 $ 297 $ 640 =========== =========== =========== =========== Earnings per Common Share Basic Before Cumulative Effect of Change in Accounting Principle..... $ 0.39 $ 0.36 $ 1.47 $ 3.05 Cumulative Effect of Change in Accounting Principle - Net...... - - - 0.01 ----------- ----------- ----------- ----------- Net Income..................................................... $ 0.39 $ 0.36 $ 1.47 $ 3.06 =========== =========== =========== =========== Diluted Before Cumulative Effect of Change in Accounting Principle..... $ 0.39 $ 0.36 $ 1.47 $ 3.04 Cumulative Effect of Change in Accounting Principle - Net...... - - - 0.01 ----------- ----------- ----------- ----------- Net Income..................................................... $ 0.39 $ 0.36 $ 1.47 $ 3.05 =========== =========== =========== ===========
See accompanying Notes to Consolidated Financial Statements. 2 BURLINGTON RESOURCES INC. CONSOLIDATED BALANCE SHEET (UNAUDITED)
September 30, December 31, 2002 2001 ------------------ ------------------- (In Millions, Except Share Data) ASSETS Current Assets Cash and Cash Equivalents..................................... $ 344 $ 116 Accounts Receivable........................................... 347 398 Commodity Hedging Contracts and Other Derivatives............. 7 118 Inventories................................................... 56 50 Other Current Assets.......................................... 43 33 ------------------ ------------------- 797 715 ------------------ ------------------- Oil & Gas Properties (Successful Efforts Method)................. 15,176 16,038 Other Properties................................................. 1,147 1,416 ------------------ ------------------- 16,323 17,454 Accumulated Depreciation, Depletion and Amortization........... 7,730 8,623 ------------------ ------------------- Properties - Net............................................. .8,593 8,831 ------------------ ------------------- Goodwill......................................................... 800 782 ------------------ ------------------- Other Assets..................................................... 222 254 ------------------ ------------------- Total Assets............................................... $ 10,412 $ 10,582 ================== =================== LIABILITIES Current Liabilities Accounts Payable............................................... $ 647 $ 599 Taxes Payable.................................................. . 122 6 Accrued Interest............................................... 64 61 Dividends Payable.............................................. 27 28 Other Current Liabilities...................................... 23 17 ------------------ ------------------- 883 711 ------------------ ------------------- Long-term Debt................................................... 3,914 4,337 ------------------ ------------------- Deferred Income Taxes............................................ 1,331 1,403 ------------------ ------------------- Commodity Hedging Contracts and Other Derivatives................ 33 15 ------------------ ------------------- Other Liabilities and Deferred Credits........................... 548 591 ------------------ ------------------- 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.................................................. 3,941 3,944 Retained Earnings................................................ 1,546 1,332 Deferred Compensation - Restricted Stock......................... (11) (9) Accumulated Other Comprehensive Loss............................. (158) (106) Cost of Treasury Stock (39,855,888 and 40,395,695 Shares for 2002 and 2001, respectively)................................................... (1,617) (1,638) ------------------ ------------------- Stockholders' Equity............................................. 3,703 3,525 ------------------ ------------------- Total Liabilities and Stockholders' Equity................. $ 10,412 $ 10,582 ================== ===================
See accompanying Notes to Consolidated Financial Statements. 3 BURLINGTON RESOURCES INC. CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)
NINE MONTHS ---------------------------------- 2002 2001 -------------- -------------- (In Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income.................................................................. $ 297 $ 640 Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities Depreciation, Depletion and Amortization.................................. 625 527 Deferred Income Taxes..................................................... (67) 316 Exploration Costs......................................................... 214 201 Gains on Sale of Assets................................................... (67) (1) Changes in Derivative Fair Values......................................... 32 (47) Working Capital Changes Accounts Receivable....................................................... 51 396 Inventories............................................................... (6) (1) Other Current Assets...................................................... (9) (5) Accounts Payable.......................................................... 19 (158) Taxes Payable............................................................. 117 3 Accrued Interest.......................................................... 8 5 Other Current Liabilities................................................. (9) (9) Changes in Other Assets and Liabilities..................................... (32) (40) -------------- -------------- Net Cash Provided By Operating Activities............................... 1,173 1,827 -------------- -------------- CASH FLOWS FROM INVESTING ACTIVITIES Additions to Properties..................................................... (1,496) (964) Proceeds from Sales and Other............................................... 1,055 10 -------------- -------------- Net Cash Used In Investing Activities................................... (441) (954) -------------- -------------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Borrowings.................................................... 454 400 Reduction in Borrowings..................................................... (879) (309) Dividends Paid.............................................................. (84) (88) Common Stock Purchases...................................................... - (684) Common Stock Issuances...................................................... 9 42 Other....................................................................... 3 (7) -------------- -------------- Net Cash Used In Financing Activities................................... . (497) (646) -------------- -------------- Effect of Exchange Rate Changes on Cash and Cash Equivalents.................. (7) - INCREASE IN CASH AND CASH EQUIVALENTS......................................... 228 227 CASH AND CASH EQUIVALENTS Beginning of Year........................................................... 116 132 -------------- -------------- End of Period............................................................... $ 344 $ 359 ============== ==============
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 three entities that it accounts for under the equity method, Lost Creek Gathering Company (Lost Creek), CLAM Petroleum B.V. (CLAM) and Evangeline Gas Pipeline Company (Evangeline). As of September 30, 2002, CLAM had no outstanding debt, Lost Creek had outstanding debt totaling $53 million and Evangeline had outstanding debt totaling $43 million. Lost Creek and Evangeline's debts are non-recourse to the Company, and as a result, the Company has no legal responsibility or obligation for these debts. Management believes that Lost Creek and Evangeline are financially stable and therefore will be in a position to repay their 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 204 million for the third quarter of 2002 and 2001, respectively, and 201 million and 209 million for the first nine 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 205 million for the third quarter of 2002 and 2001, respectively, and 202 million and 210 million for the first nine months of 2002 and 2001, respectively. For the third quarter of 2002 and 2001 and nine months ended September 30, 2002 and September 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).
NINE MONTHS NINE MONTHS ---------------------------------------- (In Millions) 2002 2001 ------------- ---------------------------------------- Accumulated other comprehensive loss - Beginning of Period............... $ (106) $ (70) Net income............................................................... $ 297 $ 640 ----- ----- 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........... 24 96 Reclassification adjustments for settled contracts.................. (72) 244 Changes in fair value of outstanding hedging positions.............. (24) 101 ----- ----- Hedging activities............................................. (72) 75 Foreign currency translation Foreign currency translation adjustments............................ 20 (49) ----- ----- Total other comprehensive income (loss).................................. (52) (52) 26 26 ----- ----- ----- ----- Comprehensive income..................................................... $ 245 $ 666 ===== ===== Accumulated other comprehensive loss - End of Period..................... $(158) $ (44) ===== =====
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 various marketing locations of the Company. The Company also enters into natural gas and crude oil option 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 September 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 4,854,652 $3.20 $ (4) 2003 15,570,630 3.12 (14) 2004 15,613,289 3.22 (10) 2005 10,513,930 3.17 (6) 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 4,854,652 $(0.64) $2 2003 15,570,630 (0.28) 3 2004 15,613,289 (0.27) 2 2005 10,513,930 (0.28) 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 32,930,000 $2.74 $ 2 2002 Puts Sold 32,155,000 2.12 - 2002 Calls Sold 32,930,000 4.01 (4) 2003 Puts Purchased 142,350,000 3.02 28 2003 Puts Sold 142,350,000 2.17 (4) 2003 Calls Sold 142,350,000 $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 $24.00 $ - 2002 Puts Sold 920,000 19.00 - 2002 Calls Sold 920,000 30.43 (1) 2003 Puts Purchased 450,000 25.00 1 2003 Puts Sold 450,000 20.00 - 2003 Calls Sold 450,000 $30.36 $(1)
As of September 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 $6 million asset offset by a $6 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 September 30, 2002. Hedging activities increased natural gas and crude oil revenues by $113 million and $3 million, respectively, during the first nine months of 2002. In addition, during the first nine months of 2002, non-cash losses of $21 million and $11 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, respectively. 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. Examples of such derivatives instruments include fixed price swaps, fixed price swaps combined with basis swaps, purchased put options, costless collars (purchased put options and written call options) and producer three-ways (purchased put spreads and written call options). These derivative instruments either fix the price the Company receives for its production or in the case of option contracts, set a minimum price or a price within a fixed range. 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. For example, the Company periodically enters into contracts whereby it commits to deliver to a customer a specified quantity of crude oil or natural gas at a fixed price over a specified period of time. In order to hedge against changes in the fair value of these commitments, the Company enters into swap agreements with financial counterparties that allow the Company to receive market prices for the committed specified quantities included in the physical contract. In addition to commodity price hedges, a Canadian subsidiary of the Company makes limited use of foreign currency swaps as cash flow hedges of anticipated sales denominated in U.S. dollars with contracts extending through 2004. As of September 30, 2002, the fair value related to these hedges was a liability of $3 million. The Company also has foreign currency swaps that, prior to September 1, 2002, were collectively designated as a hedge of Canadian Hunter Exploration Ltd.'s (Hunter) net investment in a U.S. dollar denominated foreign subsidiary with contracts that mature in 2005. During September 2002, the foreign entity that was the subject of the hedge was transferred to a U.S. subsidiary of the Company and the swaps were de-designated as a hedge. At September 30, 2002, the fair value of the swaps was a liability of $8 million. Based on commodity prices and foreign exchange rates as of September 30, 2002, the Company expects to reclassify gains of $10 million ($6 million after tax) to earnings from the balance in accumulated other comprehensive income during the next twelve months. As of September 30, 2002, the Company had cash-flow hedge derivative assets of $4 million and derivative liabilities of $33 million. The Company also had liabilities and assets related to fair-value hedges of $6 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 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 8 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. 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. In the event of adverse changes in circumstances, potential liability may exceed the amounts accrued. While the ultimate outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the consolidated financial position 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 9 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. Accordingly, there has been no reserve established for this matter. The Company received notice in 1997 from the United States Environmental Protection Agency (EPA) that it was one of many Potentially Responsible Parties (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act, as amended, with respect to the Commencement Bay Nearshore/Tideflats National Priorities List Site. The site, located in the Puget Sound near Tacoma, Washington, consists of 10-12 square miles of shallow water, shoreline and adjacent land, most of which is developed and industrialized. The EPA determined that marine sediments had become contaminated from many years of diverse industrial activities. The Company and Burlington Northern Inc. previously owned land adjacent to the Thea Foss Waterway, which the EPA considered as a potential source of the contamination. On September 23, 2002, the Company completed the settlement of all claims through the payment of $587,621 from a reserve that was previously 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. 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. 5. DEBT In February 2002, Burlington Resources Finance Company (BRFC) issued $350 million of 5.7% Notes due March 1, 2007, which were fully and unconditionally guaranteed by BR. 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 for $104 million was retired on September 16, 2002. During the first nine months of 2002, the Company also retired $675 million of net commercial paper and has no commercial paper outstanding at September 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. 10 The fair value of the Company's long-term debt at September 30, 2002 and December 31, 2001, excluding commercial paper, was approximately $4,443 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. In August 2002, the Company purchased certain oil and gas properties located in Wise and Denton Counties, Texas for approximately $140 million. In October 2002, the Company also provided notice in accordance with prior agreements that it intends to exercise its option to purchase additional oil and gas reserves in the western U.S. during 2003 for approximately $100 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 Gulf of Mexico Shelf Trend and south and east Texas assets are included in the non-core, non-strategic properties. During the second and third quarters 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 $1,063 million and recognized a net pretax gain of $67 million. The net pretax gain includes an estimated pretax loss of $65 million associated with a purchase and sale agreement that was signed but the transaction not closed as of September 30, 2002. In October 2002, the Company signed a purchase and sale agreement to sell certain non-core, non-strategic properties in the Mid-Continent area. The net book value of the properties held for sale at September 30, 2002, including those identified in October 2002, was $165 million. The producing properties sold and currently held for sale generated $167 million and $321 million of revenues and incurred $126 million and $243 million of direct operating expenses during the first nine months of 2002 and 2001, respectively. The Company intends to complete the remaining property sales by year-end 2002. There is minimal income statement effect expected during the fourth quarter of 2002 related to the remaining sales. The Company has and expects to use a portion of the proceeds generated from property sales to retire commercial paper, to repay the promissory note for $104 million and for general corporate purposes, including future funding of a portion of the Company's capital program. In connection with the divestiture program, the Company also recorded restructuring liabilities of $10 million in the fourth quarter of 2001. As of September 30, 2002, approximately $409 thousand of the restructuring liabilities remained outstanding as Accounts Payable on the Consolidated Balance Sheet. 7. INCOME TAXES The Company's effective income tax rate decreased to 11 percent at September 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 and the reversal of a tax valuation reserve of $27 million in September 2002 related to the sale of assets in the U.K. sector of the North Sea. 11 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 for and the 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 $2 million and $19 million during the third quarter of 2002 and 2001, respectively, and were $17 million and $143 million during the first nine months of 2002 and 2001, respectively. The following tables present information about reported segment operations.
Third Quarter ---------------------------------------------------------------------------------------------- 2002 2001 ------------------------------------------ ----------------------------------------------- USA Canada Intl Corp. Total USA Canada Intl Corp. Total ---- ------- ---- ----- ----- ---- ------- ---- ----- ------ (In Millions) (In Millions) Revenues................ $360 $240 $ 30 $ - $630 $457 $167 $ 42 $ - $666 Consolidated income before income taxes... 119 49 (10) (91) 67 141 43 (2) (76) 106 Capital expenditures.... $244 $ 84 $115 $ 5 $448 $191 $ 87 $ 41 $ 6 $325
Nine Months ---------------------------------------------------------------------------------------------- 2002 2001 ------------------------------------------ ----------------------------------------------- USA Canada Intl Corp. Total USA Canada Intl Corp. Total ---- ------- ---- ----- ----- ---- ------- ---- ----- ------ (In Millions) (In Millions) Revenues................ $1,177 $789 $116 $ - $2,082 $1,832 $775 $139 $ - $2,746 Consolidated income before income taxes... 597 142 (89) (315) 335 861 424 21 (263) 1,043 Capital expenditures.... $ 370 $709 $321 $ 30 $1,430 $ 470 $352 $146 $ 12 $ 980
9. ACCOUNTING PRONOUNCEMENTS In June 2002, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities (SFAS No. 146). SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred and establishes that fair value is the objective for initial measurement of the liability. The provisions of SFAS No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002. The Company expects to adopt SFAS No. 146 on January 1, 2003, but at this time does not anticipate that this statement will have any effect on its consolidated financial position or results of operations. In April 2002, the 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 12 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 expects to adopt SFAS No. 145 on January 1, 2003, but at this time does not anticipate that this statement will have any effect on its consolidated financial position or results of operations. In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143). 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. Based on current estimates, the Company expects to record a net-of-tax cumulative effect of change in accounting principle loss, in the first quarter of 2003, of approximately $50 million to $65 million in accordance with the provisions of SFAS No. 143. There will be no impact on the Company's cash flows as a result of adopting SFAS No. 143. 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 $800 million at September 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, 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. 13 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............................ 4 Purchase accounting adjustments related to foreign income taxes and other...... 14 ---- Balance-September 30, 2002..................................................... $800 ====
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.
Third Quarter Nine Months 2001 2001 ------------- ----------- (In Millions, Except per Share Amounts) Revenues .................................... $ 774 $3,271 Net income .................................. 90 788 Basic earnings per share .................... 0.44 3.77 Diluted earnings per share .................. $0.44 $ 3.75
ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Outlook During the fourth quarter of 2002, the Company expects average production volumes to range between 2,260 and 2,488 MMCFE per day. The Company expects full year production volumes to average between 2,484 and 2,579 MMCFE. Although the Company experienced production declines as a result of property sales, natural declines and annual plant and pipeline maintenance that extended into the third quarter of 2002, the Company expects 2002 full year production volumes to exceed full year 2001 volumes primarily due to acquisitions in Canada in late 2001 and early 2002, additional production volumes in Madden Field and the acceleration of winter drilling activity in Canada during the fourth quarter of 2002. The Lost Cabin Gas Plant expansion in Madden Field was completed during the third quarter of 2002. As a result, in 2003 upon the completion of a well which is currently being drilled, the Company's future deep Madison gas sales in the area is expected to increase to a maximum of 85 MMCF of gas per day from the current level of approximately 35 MMCF of gas per day. 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, economic 14 climate, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, the Company cannot accurately predict future natural gas, NGL and crude oil prices, and therefore, it cannot determine what effect increases or decreases in 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 all of 2002, the Company plans to spend $1.3 billion on development, exploration and plants and pipeline capital and an additional $600 million on acquisitions. The Company expects its reserve replacement costs from internal sources, which exclude acquisitions, to range between $1.10 and $1.25 per MCFE for 2002. The Company also expects to replace its production from internal sources during 2002. On June 30, 2002, the Company sold the Val Verde gathering and processing plant (Val Verde Plant), which contributed $19 million in third party revenues in 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 Company has certain oil and gas wells that qualify for Section 29 Tax Credits. In 2002, the Company generated $17 million of Section 29 Tax Credits. Production from qualified wells will cease to generate Section 29 Tax Credits at the end of 2002. Financial Condition and Liquidity The Company's long-term debt to total capital (total capital is defined as total debt and stockholders' equity) ratio at September 30, 2002 and December 31, 2001 was 51 percent and 55 percent, respectively. The reduction in long-term debt to total capital was accomplished by the use of proceeds from 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 commodity 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), which were fully and unconditionally guaranteed by BR. 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 May 2002, the Company restored its shelf registration statement to $1,500 million. At September 30, 2002, the Company had $344 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 for $104 million was retired on September 16, 2002. During the first nine months of 2002, the Company also retired $675 million of net commercial paper and has no commercial paper outstanding at September 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), 15 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 Company had credit commitments in the form of revolving credit facilities (revolvers) as of September 30, 2002. The revolvers, which are comprised of agreements for $600 million, $400 million and approximately Canadian $471 million (U.S. $297 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 any remaining 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 nine months of 2002 was $1,173 million compared to $1,827 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, crude oil and NGL prices and lower crude oil sales volumes partially offset by higher natural gas and NGL sales volumes. 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 nine months of 2002 totaled $1,430 million compared to $985 million in 2001. The Company invested $669 million on internal development and exploration of oil and gas properties during the first nine months of 2002 compared to $735 million in 2001. The increase in capital expenditures in 2002 are primarily due to property acquisitions where the Company invested $596 million in the first nine months of 2002 compared to $143 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. Property acquisitions also include approximately $140 million for the purchase of certain oil and gas properties located in Wise and Denton Counties, Texas in August 2002. 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. 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 16 growth opportunities, substantially all of the Gulf of Mexico Shelf Trend (Shelf) and south and east Texas assets are included in the non-core, non-strategic properties. During the second and third quarters of 2002, the Company sold certain non-core, non-strategic properties, including the Val Verde Plant, and generated proceeds, before post closing adjustments, of approximately $1,063 million and recognized a net pretax gain of $67 million. The net pretax gain includes an estimated pretax loss of $65 million associated with a purchase and sale agreement that was signed but the transaction not closed as of September 30, 2002. In October 2002, the Company signed a purchase and sale agreement to sell certain non-core, non-strategic properties in the Mid-Continent area. The net book value of the properties held for sale at September 30, 2002, including those identified in October 2002, was $165 million. The producing properties sold and currently held for sale generated $167 million and $321 million of revenues and incurred $126 million and $243 million of direct operating expenses during the first nine months of 2002 and 2001, respectively. The Company intends to complete the remaining property sales by year-end 2002. There is minimal income statement effect expected during the fourth quarter of 2002 related to the remaining sales. The Company has and expects to use a portion of the proceeds generated from property sales to retire commercial paper, to repay the promissory note for $104 million and for general corporate purposes, including future funding of a portion of the Company's capital program. In connection with the divestiture program, the Company also recorded restructuring liabilities of $10 million in the fourth quarter of 2001. As of September 30, 2002, approximately $409 thousand of the restructuring liabilities remained outstanding as Accounts Payable on the Consolidated Balance Sheet. Dividends On October 16, 2002, the Board of Directors declared a quarterly common stock cash dividend of $0.1375 per share, with record and payment dates of December 6, 2002 and January 2, 2003, respectively. Results of Operations - Third Quarter 2002 Compared to Third Quarter 2001 The Company reported net income of $79 million or $0.39 diluted earnings per common share in third quarter 2002 compared to net income of $73 million or $0.36 diluted earnings per common share in third quarter 2001. Net income in third quarter 2002 included a net after tax loss of $4 million or $0.02 per diluted share related to the disposal of assets and the reversal of a tax valuation reserve of $27 million or $0.13 per diluted share in September 2002 related to the sale of assets in the U.K. sector of the North Sea. Net income in third quarter 2002 also included an after tax loss of $3 million and $1 million compared to an after tax gain of $3 million and $4 million in third quarter 2001, 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, respectively. 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. Examples of such derivatives instruments include fixed price swaps, fixed price swaps combined with basis swaps, purchased put options, costless collars (purchased put options and written call options) and producer three-ways (purchased put spreads and written call options). These derivative instruments either fix the price the Company receives for its production or in the case of option contracts, set a minimum price or a price within a fixed range. 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. For example, the Company periodically enters into contracts whereby it commits to deliver to a customer a 17 specified quantity of crude oil or natural gas at a fixed price over a specified period of time. In order to hedge against changes in the fair value of these commitments, the Company enters into swap agreements with financial counterparties that allow the Company to receive market prices for the committed specified quantities included in the physical contract. Revenues Revenues decreased $36 million to $630 million in third quarter 2002 compared to $666 million in third quarter 2001. The $36 million decrease in revenues primarily consists of $34 million related to lower commodity prices, $9 million and $8 million due to lower revenues related to ineffectiveness on cash-flow and fair-value hedges and changes in the fair value of derivative instruments that do not qualify for hedge accounting, respectively, and $10 million due to the sale of the Val Verde Plant in the second quarter of 2002 partially offset by $26 million related to higher production volumes. Details of commodity prices and sales volumes variances are described below. Price variances Average gas prices, including an $0.11 realized gain per MCF related to hedging activities, decreased $0.24 per MCF in third quarter 2002 to $2.65 per MCF from $2.89 per MCF in third quarter 2001 which decreased revenues $41 million during third quarter 2002. Also imbedded in the average gas prices during third quarter 2002 was the impact of weaker than normal location basis differentials primarily at the AECO hub and the Rocky Mountain region of the U.S. Average NGL prices decreased $0.24 per barrel in third quarter 2002 to $15.22 per barrel from $15.46 per barrel in third quarter 2001, resulting in reduced revenues of $1 million during third quarter 2002. Average oil prices increased $2.09 per barrel in third quarter 2002 to $25.90 per barrel from $23.81 per barrel in third quarter 2001 resulting in increased revenues of $8 million during third quarter 2002. There were no hedging gains or losses related to oil volumes during third quarter 2002. Volume variances Average gas sales volumes increased 167 MMCF per day in third quarter 2002 to 1,839 MMCF per day from 1,672 MMCF per day in third quarter 2001 resulting in increased revenues of $44 million during third quarter 2002. Average NGL sales volumes increased 12.8 MBbls per day in third quarter 2002 to 59.6 MBbls per day from 46.8 MBbls per day in third quarter 2001, resulting in higher revenues of $18 million from quarter to quarter. Average oil sales volumes decreased 16.5 MBbls per day in third quarter 2002 to 44.7 MBbls per day from 61.2 MBbls per day in third quarter 2001 reducing revenues $36 million during third quarter 2002. Average gas sales volumes in Canada and Other International increased 393 MMCF per day primarily due to the acquisition of Canadian Hunter Exploration Ltd. (Hunter) in late 2001 partially offset by asset sales and natural declines of 234 MMCF per day in Mid-Continent, Gulf Coast, Canada, San Juan and Other International areas. Average NGL sales volumes in Canada increased 13.7 MBbls per day primarily due to the acquisition of Hunter. Average oil sales volumes decreased 17.4 MBbls per day primarily due to asset sales and natural declines in the Gulf of Mexico, Mid-Continent, Canada and Other International areas. Total Costs and Other Income Total costs and other income were $563 million in third quarter 2002 compared to $560 million in third quarter 2001. The $3 million increase was primarily due to a $24 million increase 18 in interest expense, a $9 million increase in depreciation, depletion and amortization (DD&A), a $5 million higher loss on disposal of assets, a $4 million increase in transportation expenses, a $3 million increase in taxes other than income taxes and a $2 million increase in general and administrative (G&A) expenses partially offset by a $26 million decrease in exploration costs, a $9 million decrease in production and processing expenses and a $9 million increase in other income. Interest expense increased primarily due to higher debt balances during third quarter 2002 resulting from the Hunter acquisition in late 2001 and other property acquisitions consummated in early 2002. 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. Transportation expenses increased primarily due to higher contract rates primarily resulting from the sale of the Val Verde Plant. Taxes other than income taxes increased primarily due to higher miscellaneous taxes partially offset by lower production taxes resulting from lower oil and gas revenues. Exploration costs decreased primarily due to lower drilling rig expenses of $21 million, lower exploratory dry hole costs of $17 million and lower geological and geophysical (G&G) and other expenses of $1 million partially offset by higher amortization of undeveloped lease costs of $13 million. 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. Other income increased primarily due to higher foreign currency transactions and higher interest income. Income Tax Expense Income taxes were a benefit of $12 million in third quarter 2002 compared to an expense of $33 million in third quarter 2001. The Company recorded tax benefits of $18 million in third quarter 2002 compared to $7 million in third 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 $5 million in third quarter 2002 compared to $4 million in third quarter 2001. Third quarter 2002 also included the reversal of a tax valuation reserve of $27 million in September 2002 related to the sale of assets in the U.K. sector of the North Sea. Results of Operations - First Nine Months of 2002 Compared to First Nine Months of 2001 The Company reported net income of $297 million or $1.47 diluted earnings per common share in the first nine months of 2002 compared to net income of $640 million or $3.05 diluted earnings per common share in the first nine months of 2001. Net income in the first nine months of 2002 included a net after tax gain of $42 million or $0.20 per diluted share related to the disposal of assets and the reversal of a valuation reserve of $27 million or $0.13 per diluted share in September 2002 related to the sale of assets in the U.K. sector of the North Sea. Net income in the first nine months of 2002 also included an after tax loss of $13 million and $7 million compared to an after tax gain of $12 million and $13 million in the first nine months of 2001, 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, respectively. Net income in the first nine months of 2001 also included an after tax gain of $3 million or $0.01 per diluted share related to the cumulative effect of change in accounting principle resulting from the adoption of SFAS No. 133. 19 Revenues Revenues decreased $664 million to $2,082 million in the first nine months of 2002 compared to $2,746 million in the first nine months of 2001. The $664 million decrease in revenues primarily consists of $866 million related to lower commodity prices, $40 million and $33 million due to lower revenues related to ineffectiveness on cash-flow and fair-value hedges and changes in the fair value of derivative instruments that do not qualify for hedge accounting, respectively, and $10 million due to the sale of the Val Verde Plant in the second quarter of 2002 partially offset by $285 million related to higher production volumes. Details of commodity prices and sales volumes variances are described below. Price variances Average gas prices, including a $0.21 realized gain per MCF related to hedging activities, decreased $1.47 per MCF in the first nine months of 2002 to $2.89 per MCF from $4.36 per MCF in the first nine months of 2001 which decreased revenues $771 million during the first nine months of 2002. Also imbedded in the average gas prices during the first nine months of 2002 was the impact of location basis differentials that varied widely compared to the same period in 2001 primarily in the western U.S. and western Canada. Average NGL prices decreased $5.10 per barrel in the first nine months of 2002 to $13.88 per barrel from $18.98 per barrel in the first nine months of 2001, resulting in reduced revenues of $84 million during the first nine months of 2002. Average oil prices, including a $0.22 realized gain per barrel related to hedging activities, decreased $0.77 per barrel in the first nine months of 2002 to $23.90 per barrel from $24.67 per barrel in the first nine months of 2001 resulting in reduced revenues of $11 million during the first nine months of 2002. Volume variances Average gas sales volumes increased 235 MMCF per day in the first nine months of 2002 to 1,927 MMCF per day from 1,692 MMCF per day in the first nine months of 2001 resulting in increased revenues of $279 million during the first nine months of 2002. Average NGL sales volumes increased 15.4 MBbls per day in the first nine months of 2002 to 60.3 MBbls per day from 44.9 MBbls per day in the first nine months of 2001, resulting in higher revenues of $80 million during the first nine months of 2002. Average oil sales volumes decreased 11.0 MBbls per day in the first nine months of 2002 to 53.1 MBbls per day from 64.1 MBbls per day in the first nine months of 2001 reducing revenues $74 million during the first nine months of 2002. Average gas sales volumes in Canada and Other International areas increased 414 MMCF per day primarily due to the acquisition of Hunter in late 2001 partially offset by natural declines and asset sales of 179 MMCF per day in Onshore Gulf Coast, Shelf, San Juan and Mid-Continent. Average NGL sales volumes in Canada also increased 16.6 MBbls per day primarily due to the acquisition of Hunter. Average oil sales volumes decreased 9.7 MBbls per day primarily due to natural declines and asset sales in the Gulf of Mexico, Canada and Mid-Continent. 20 Total Costs and Other Income Total costs and other income were $1,747 million in the first nine months of 2002 compared to $1,703 million in the first nine months of 2001. The $44 million increase was primarily due to a $98 million increase in DD&A, a $75 million increase in interest expense, a $13 million increase in exploration costs and a $1 million increase in production and processing expenses partially offset by a $66 million increase in gain on disposal of assets, a $48 million decrease in taxes other than income taxes, a $23 million increase in other income and a $6 million decrease in transportation 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 nine 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 amortization of undeveloped lease costs of $44 million, higher drilling rig costs of $17 million, and higher G&G and other expenses of $12 million partially offset by lower exploratory dry hole costs of $60 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. 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. Income tax Expense Income taxes were an expense of $38 million in the first nine months of 2002 compared to $406 million in the first nine months of 2001. The decrease in tax expense was primarily due to lower pretax income. The Company also recorded benefits of $73 million in the first nine months of 2002 compared to $13 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 $17 million during the first nine months of 2002 and 2001. The first nine months also included the reversal of a tax valuation reserve of $27 million in September 2002 related to the sale of assets in the U.K. sector of the North Sea. Accounting Pronouncements In June 2002, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 146, Accounting for Costs Associated with Exit or Disposal Activities (SFAS No. 146). SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred and establishes that fair value is the objective for initial measurement of the liability. The provisions of SFAS No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002. The Company expects to adopt SFAS No. 146 on January 1, 2003, but at this time does not anticipate that this statement will have any effect on its consolidated financial position or results of operations. 21 In April 2002, the 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 expects to adopt SFAS No. 145 on January 1, 2003, but at this time does not anticipate that this statement will have any effect on its consolidated financial position or results of operations. In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143). 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. Based on current estimates, the Company expects to record a net-of-tax cumulative effect of change in accounting principle loss, in the first quarter of 2003, of approximately $50 million to $65 million in accordance with the provisions of SFAS No. 143. There will be no impact on the Company's cash flows as a result of adopting SFAS No. 143. 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). Location and quality differentials, worldwide political developments and the actions of the Organization of Petroleum Exporting Countries also affect crude oil prices. The difference between the NYMEX futures contract price for a particular month and the actual cash price received for that month in a North American producing basin or at a North American market hub 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 some 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 September 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 $69 million increase in the fair value of the net liabilities related to commodity hedging activities. 22 For purposes of calculating the hypothetical change in fair value, the relevant variables include the type of commodity, the commodity futures prices, the volatility of commodity prices and the basis and quality differentials. The hypothetical change in fair value is calculated by multiplying the difference between the hypothetical price (adjusted for any basis or quality differentials) and the contractual price by the contractual volumes. Based on commodity prices and foreign exchange rates as of September 30, 2002, the Company expects to reclassify gains of $10 million ($6 million after tax) to earnings from the balance in accumulated other comprehensive income during the next twelve months. As of September 30, 2002, the Company had cash-flow hedge derivative assets of $4 million and derivative liabilities of $33 million. The Company also had liabilities and assets related to fair-value hedges of $6 million and $7 million, respectively. ITEM 4. Controls and Procedures Within 90 days prior to the date of this report, 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-14(c) and 15d-14(c) to the Securities Exchange Act of 1934, as amended). Based on this evaluation, the Company's Chief Executive Officer and Chief Financial Officer believe that the disclosure controls and procedures are effective 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 were no significant changes in the Company's internal controls or other factors that could significantly affect internal controls subsequent to the date of the most recently completed evaluation. 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 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 23 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. 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. In the event of adverse changes in circumstances, potential liability may exceed the amounts accrued. While the ultimate outcome and impact on the Company cannot be predicted with certainty, management believes that the resolution of these proceedings through settlement or adverse judgment will not have a material adverse effect on the consolidated financial position 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 24 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. Accordingly, there has been no reserve established for this matter. The Company received notice in 1997 from the United States Environmental Protection Agency (EPA) that it was one of many Potentially Responsible Parties (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act, as amended, with respect to the Commencement Bay Nearshore/Tideflats National Priorities List Site. The site, located in the Puget Sound near Tacoma, Washington, consists of 10-12 square miles of shallow water, shoreline and adjacent land, most of which is developed and industrialized. The EPA determined that marine sediments had become contaminated from many years of diverse industrial activities. The Company and Burlington Northern Inc. previously owned land adjacent to the Thea Foss Waterway, which the EPA considered as a potential source of the contamination. On September 23, 2002, the Company completed the settlement of all claims through the payment of $587,621 from a reserve that was previously 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. 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 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* Letter Agreement regarding Steven J. Shapiro dated October 18, 2000 related to supplemental pension benefits in connection with employment (incorporated by reference to Exhibit 10.29 to Form 10-K, filed February 2001) * Exhibit incorporated by reference. 25 B. Reports on Form 8-K On August 12, 2002, the Company filed Form 8-K in connection with the Company's Chief Executive Officer and Chief Financial Officer each filing with the Securities and Exchange Commission (the "SEC") a statement under oath regarding facts and circumstances relating to the Securities Exchange Act filings of the Company, as required by the SEC's Order Requiring the Filing of Sworn Statements Pursuant to Section 21(a)(1) of the Securities Exchange Act of 1934 (File No. 4-460, June 27, 2002). Items 2, 3, 4 and 5 of Part II are not applicable and have been omitted. 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: November 13, 2002 26 CERTIFICATIONS I, Bobby S. Shackouls, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Burlington Resources Inc.; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 13, 2002 /s/ BOBBY S. SHACKOULS ------------------------------------------- Bobby S. Shackouls Chairman of the Board, President and Chief Executive Officer 27 CERTIFICATIONS I, Steven J. Shapiro, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Burlington Resources Inc.; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 13, 2002 /s/ STEVEN J. SHAPIRO ----------------------------------- Steven J. Shapiro Senior Vice President and Chief Financial Officer 28 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"), hereby certifies that the Quarterly Report of the Company on Form 10-Q for the period ended September 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: November 13, 2002 Bobby S. Shackouls Chairman of the Board, President and Chief Executive Officer Certification Accompanying Periodic Report Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350) The undersigned, Steven J. Shapiro, Senior Vice President and Chief Financial Officer of the Company, hereby certifies that the Quarterly Report of the Company on Form 10-Q for the period ended September 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/ STEVEN J. SHAPIRO --------------------------------- Dated: November 13, 2002 Steven J. Shapiro Senior Vice President and Chief Financial Officer