================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark one) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2001 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to _______________ Commission File Number 1-8590 MURPHY OIL CORPORATION (Exact name of registrant as specified in its charter) Delaware 71-0361522 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 200 Peach Street P. O. Box 7000, El Dorado, Arkansas 71731-7000 (Address of principal executive offices) (Zip Code) (870) 862-6411 (Registrant's telephone number, including area code) 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. X Yes No ---- ---- Number of shares of Common Stock, $1.00 par value, outstanding at September 30, 2001, was 45,309,458. ================================================================================
PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Thousands of dollars) (Unaudited) September 30, December 31, 2001 2000 ------------- ------------ ASSETS Current Assets Cash and cash equivalents $ 161,254 132,701 Accounts receivable, less allowance for doubtful accounts of $9,852 in 2001 and $10,208 in 2000 342,183 469,616 Inventories Crude oil and blend stocks 65,671 47,875 Finished products 88,556 68,464 Materials and supplies 47,645 48,416 Prepaid expenses 52,013 23,949 Deferred income taxes 20,735 25,916 ------------ ------------ Total current assets 778,057 816,937 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $3,236,389 in 2001 and $3,144,369 in 2000 2,412,164 2,184,719 Goodwill, net 43,632 48,396 Deferred charges and other assets 84,414 84,301 ------------ ------------ Total assets $3,318,267 3,134,353 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Current maturities of long-term debt $ 47,868 37,242 Accounts payable and accrued liabilities 554,557 639,642 Income taxes 72,128 68,343 ------------ ------------ Total current liabilities 674,553 745,227 Notes payable 374,383 398,375 Nonrecourse debt of a subsidiary 107,725 126,384 Deferred income taxes 279,903 229,968 Reserve for dismantlement costs 160,657 160,049 Reserve for major repairs 41,361 34,302 Deferred credits and other liabilities 185,194 180,488 Stockholders' equity Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued - - Common stock, par $1.00, authorized 200,000,000 shares at September 30, 2001 and 80,000,000 shares at December 31, 2000, issued 48,775,314 shares 48,775 48,775 Capital in excess of par value 526,012 514,474 Retained earnings 1,084,793 833,490 Accumulated other comprehensive loss (73,342) (38,266) Unamortized restricted stock awards (1,154) (1,410) Treasury stock, 3,465,856 shares of Common Stock at September 30, 2001, 3,729,769 shares at December 31, 2000, at cost (90,593) (97,503) ------------ ------------ Total stockholders' equity 1,494,491 1,259,560 ------------ ------------ Total liabilities and stockholders' equity $3,318,267 3,134,353 ============ ============ See Notes to Consolidated Financial Statements, page 5. The Exhibit Index is on page 17. 1
Murphy Oil Corporation and Consolidated Subsidiaries CONSOLIDATED STATEMENTS OF INCOME (unaudited) (Thousands of dollars, except per share amounts) Three Months Ended Nine Months Ended September 30, September 30, ----------------------- ----------------------- 2001 2000* 2001 2000* ---------- ---------- ---------- ---------- REVENUES Crude oil and natural gas sales $ 197,460 196,254 667,611 508,826 Petroleum product sales 767,296 725,592 2,217,598 1,979,104 Crude oil trading sales 134,939 286,086 531,265 794,574 Other operating revenues 36,682 24,332 202,632 61,464 Interest and other nonoperating revenues 2,959 15,045 9,994 20,611 ---------- ---------- ---------- ---------- Total revenues 1,139,336 1,247,309 3,629,100 3,364,579 ---------- ---------- ---------- ---------- COSTS AND EXPENSES Crude oil, products and related operating expenses 935,122 994,578 2,770,746 2,700,570 Exploration expenses, including undeveloped lease amortization 45,541 20,899 125,091 89,617 Selling and general expenses 25,698 22,962 71,727 61,603 Depreciation, depletion and amortization 58,090 51,389 170,578 154,522 Amortization of goodwill 782 - 2,355 - Impairment of long-lived assets - 20,997 - 20,997 Interest expense 9,516 6,821 28,962 20,393 Interest capitalized (5,065) (3,325) (12,984) (10,064) ---------- ---------- ---------- ---------- Total costs and expenses 1,069,684 1,114,321 3,156,475 3,037,638 ---------- ---------- ---------- ---------- Income before income taxes and cumulative effect of accounting change 69,652 132,988 472,625 326,941 Income tax expense 27,923 42,878 170,492 114,643 ---------- ---------- ---------- ---------- Income before cumulative effect of accounting change 41,729 90,110 302,133 212,298 Cumulative effect of accounting change, net of tax (Note B) - - - (8,733) ---------- ---------- ---------- ---------- NET INCOME $ 41,729 90,110 302,133 203,565 ========== ========== ========== ========== INCOME PER COMMON SHARE - BASIC Before cumulative effect of accounting change $ .92 2.00 6.69 4.71 Cumulative effect of accounting change - - - (.19) ---------- ---------- ---------- ---------- NET INCOME - BASIC $ .92 2.00 6.69 4.52 ========== ========== ========== ========== INCOME PER COMMON SHARE - DILUTED Before cumulative effect of accounting change $ .91 1.99 6.63 4.69 Cumulative effect of accounting change - - - (.19) ---------- ---------- ---------- ---------- NET INCOME - DILUTED $ .91 1.99 6.63 4.50 ========== ========== ========== ========== Average Common shares outstanding - basic 45,306,674 45,043,061 45,190,224 45,025,280 Average Common shares outstanding - diluted 45,683,102 45,305,598 45,550,230 45,237,243 *Restated to conform to 2001 presentation. See Notes to Consolidated Financial Statements, page 5. 2
Murphy Oil Corporation and Consolidated Subsidiaries CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited) (Thousands of dollars) Three Months Ended Nine Months Ended September 30, September 30, ------------------ ----------------- 2001 2000* 2001 2000* -------- ------- ------- ------- Net income $ 41,729 90,110 302,133 203,565 Other comprehensive income (loss), net of tax Cash flow hedges Net derivative losses (2,057) - (4) - Reclassification adjustments (2,001) - (655) - -------- ------- ------- ------- Total cash flow hedges (4,058) - (659) - Net loss from foreign currency translation (19,188) (15,671) (41,056) (43,888) -------- ------- ------- ------- Other comprehensive income (loss) before cumulative effect of accounting change (23,246) (15,671) (41,715) (43,888) Cumulative effect of accounting change (Note B) - - 6,642 - -------- ------- ------- ------- Other comprehensive loss (23,246) (15,671) (35,073) (43,888) -------- ------- ------- ------- COMPREHENSIVE INCOME $ 18,483 74,439 267,060 159,677 ======== ======= ======= ======= *Restated to conform to 2001 presentation. See Notes to Consolidated Financial Statements, page 5. 3
Murphy Oil Corporation and Consolidated Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (Thousands of dollars) Nine Months Ended September 30, ----------------------- 2001 2000* -------- -------- OPERATING ACTIVITIES Income before cumulative effect of accounting change $ 302,133 212,298 Adjustments to reconcile above income to net cash provided by operating activities Depreciation, depletion and amortization 170,578 154,522 Impairment of long-lived assets - 20,997 Provisions for major repairs 16,870 17,141 Expenditures for major repairs (14,113) (9,185) Dry holes 65,638 49,347 Amortization of undeveloped leases 17,268 9,792 Amortization of goodwill 2,355 - Deferred and noncurrent income tax charges 61,815 30,280 Pretax gains from disposition of assets (95,604) (2,881) Cumulative effect of accounting change on working capital - (11,170) Net (increase) decrease in operating working capital other than cash and cash equivalents (13,867) 55,970 Other operating activities - net 13,863 12,900 -------- -------- Net cash provided by operating activities 526,936 540,011 -------- -------- INVESTING ACTIVITIES Property additions and dry holes (587,702) (373,365) Proceeds from sale of property, plant and equipment 159,882 14,550 Other investing activities - net (290) (5) -------- -------- Net cash required by investing activities (428,110) (358,820) -------- -------- FINANCING ACTIVITIES Decrease in notes payable (17,319) (47) Decrease in nonrecourse debt of a subsidiary (14,706) (6,382) Cash dividend paid (50,830) (48,399) Proceeds from exercise of stock options and sale of stock under employee stock purchase plan 14,919 674 Other financing activities - net (2,000) - -------- -------- Net cash required by financing activities (69,936) (54,154) -------- -------- Effect of exchange rate changes on cash and cash equivalents (337) (5,908) -------- -------- Net increase in cash and cash equivalents 28,553 121,129 Cash and cash equivalents at January 1 132,701 34,132 -------- -------- Cash and cash equivalents at September 30 $ 161,254 155,261 ======== ======== SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES Cash income taxes paid $ 102,092 27,466 Interest paid, net of amounts capitalized 7,236 5,201 *Restated to conform to 2001 presentation. See Notes to Consolidated Financial Statements, page 5. 4
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 1 through 4 of this Form 10-Q report. Note A - Interim Financial Statements The consolidated financial statements of the Company presented herein have not been audited by independent auditors, except for the Consolidated Balance Sheet at December 31, 2000. In the opinion of Murphy's management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company's financial position at September 30, 2001, and the results of its operations and cash flows for the three-month and nine-month periods ended September 30, 2001 and 2000, in conformity with accounting principles generally accepted in the United States of America. Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company's 2000 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the nine months ended September 30, 2001 are not necessarily indicative of future results. Note B - New Accounting Principles Effective January 1, 2001, Murphy adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by Statement of Financial Accounting Standards No. 138 (SFAS Nos. 133/138). Under SFAS Nos. 133/138, Murphy records the fair values of its derivative instruments as either assets or liabilities. All such instruments have been designated as hedges of forecasted cash flow exposures. Changes in the fair value of a qualifying cash flow hedging derivative are deferred and recorded as a component of Accumulated Other Comprehensive Income (AOCI) in the Consolidated Balance Sheet until the forecasted transaction occurs, at which time the derivative's fair value will be recognized in earnings. Ineffective portions of a hedging derivative's change in fair value are recognized currently in earnings. Adoption of SFAS Nos. 133/138 resulted in a transition adjustment gain to AOCI of $6.6 million, net of $2.8 million in income taxes for the cumulative effect on prior years; there was no cumulative effect on earnings. Excluding the transition adjustment, the effect of this accounting change decreased AOCI for the nine months ended September 30, 2001 by $.7 million, net of $.4 million in income taxes, and decreased net income for the same period by $.3 million, net of $.2 million in taxes, but did not affect income per diluted share. For the nine months ended September 30, 2001, losses of $.6 million, net of $.1 million in taxes, associated with the transition adjustment were reclassified from AOCI to earnings. In 2000, Murphy adopted the revenue recognition guidance in the Securities and Exchange Commission's Staff Accounting Bulletin 101. As a result of the change, Murphy records revenues related to its crude oil as the oil is sold, and carries its unsold crude oil production in inventory at cost or market, whichever is lower, rather than at market value as in the past. Consequently, Murphy restated its 2000 operating results and recorded a transition adjustment charge of $8.7 million, net of income tax benefits of $3.9 million, for the cumulative effect on prior years. Excluding the transition adjustment, this accounting change decreased income for the nine months ended September 30, 2000 by $4.9 million. In 2000, the Company also applied the provisions of Emerging Issues Task Force (EITF) Issue 99-19, "Reporting Revenue Gross as a Principal Versus Net as an Agent," and Issue 00-10, "Accounting for Shipping and Handling Fees." Prior to applying EITF 99-19, the Company reported the results of crude oil trading and certain other downstream activities on a net margin basis in either Other Operating Revenues or Crude Oil, Products and Related Operating Expenses in its Statements of Income and in its refining, marketing and transportation segment disclosures. Under EITF 99-19, the Company began reporting these activities as gross revenues and cost of sales. Before applying EITF 00-10, the Company reduced Crude Oil and Natural Gas Sales for certain gathering and pipeline charges incurred prior to the point of sale. Such costs have now been recorded as cost of sales rather than as a reduction of revenues. Due to applying these two accounting principles, the Company's previously reported revenues and cost of sales for all 2000 periods have been reclassified to reflect the new presentation. 5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.) Note C - Environmental Contingencies The Company's operations are subject to numerous laws and regulations intended to protect the environment and/or impose remedial obligations. The Company is also involved in personal injury and property damage claims, allegedly caused by exposure to or by the release or disposal of materials manufactured or used in the Company's operations. The Company operates or has previously operated certain sites and facilities, including refineries, oil and gas fields, gasoline stations, and terminals, for which known or potential obligations for environmental remediation exist. Under the Company's accounting policies, an environmental liability is recorded when an obligation is probable and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Recorded liabilities are reviewed quarterly. Actual cash expenditures often occur one or more years after a liability is recognized. The Company's reserve for remedial obligations, which is included in "Deferred Credits and Other Liabilities" in the Consolidated Balance Sheets, contains certain amounts that are based on anticipated regulatory approval for proposed remediation of former refinery waste sites. If regulatory authorities require more costly alternatives than the proposed processes, future expenditures could exceed the amount reserved by up to an estimated $3 million. The Company has received notices from the U.S. Environmental Protection Agency (EPA) that it is currently considered a Potentially Responsible Party (PRP) at three Superfund sites and has also been assigned responsibility by defendants at another Superfund site. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. Based on currently available information, the Company has reason to believe that it is a "de minimus" party as to ultimate responsibility at the four sites. The Company does not expect that its related remedial costs will be material to its financial condition or its results of operations, and it has not provided a reserve for remedial costs on Superfund sites. Additional information may become known in the future that would alter this assessment, including any requirement to bear a pro rata share of costs attributable to nonparticipating PRPs or indications of additional responsibility by the Company. Lawsuits filed against Murphy by the U.S. Government and the State of Wisconsin are discussed under the caption "Legal Proceedings" on page 16 of this Form 10-Q report. The Company does not believe that these or other known environmental matters will have a material adverse effect on its financial condition. There is the possibility that expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. Such expenditures could materially affect the results of operations in a future period. Certain environmental expenditures are likely to be recovered by the Company from other sources, primarily environmental funds maintained by certain states. Since no assurance can be given that future recoveries from other sources will occur, the Company has not recognized a benefit for likely recoveries at September 30, 2001. Note D - Other Contingencies The Company's operations and earnings have been and may be affected by various other forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax increases and retroactive tax claims; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety; governmental support for other forms of energy; and laws and regulations affecting the Company's relationships with employees, suppliers, customers, stockholders and others. Because governmental actions are often motivated by political considerations, may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company. 6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.) Note D - Other Contingencies (Contd.) The Company and its subsidiaries are engaged in a number of legal proceedings, all of which the Company considers routine and incidental to its business and none of which is considered material. In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide letters of credit that may be drawn upon if the Company fails to perform under those contracts. At September 30, 2001 the Company had contingent liabilities of $38 million under certain financial guarantees and $41.4 million on outstanding letters of credit. Note E - Earnings per Share Net income was used as the numerator in computing both basic and diluted income per Common share for the three-month and nine-month periods ended September 30, 2001 and 2000. The following table reconciles the weighted-average shares outstanding used for these computations. - -------------------------------------------------------------------------------------------------- Reconciliation of Shares Outstanding Three Months Ended Nine Months Ended September 30, September 30, - -------------------------------------------------------------------------------------------------- (Weighted-average shares) 2001 2000 2001 2000 - -------------------------------------------------------------------------------------------------- Basic method........................ 45,306,674 45,043,061 45,190,224 45,025,280 Dilutive stock options.............. 376,428 262,537 360,006 211,963 - -------------------------------------------------------------------------------------------------- Diluted method 45,683,102 45,305,598 45,550,230 45,237,243 ================================================================================================== The computations of earnings per share in the Consolidated Statements of Income did not consider outstanding options of 73,500 shares for the three-month period of 2000, and 147,000 shares for the nine-month period of 2000, because the effects of these options would have improved the Company's earnings per share. Average exercise prices per share of the options not used were $65.49 and $62.97, respectively. There were no antidilutive options for the three-month and nine-month periods of 2001. Note F - Risk Management and Derivative Instruments . Interest Rate Risks - Murphy has variable-rate debt obligations consisting of commercial paper issued under nonrecourse guaranteed credit facilities to finance certain expenditures for the Hibernia oil field. These obligations expose the Company to the effects of changes in interest rates. To limit its exposure to interest rate risk on a significant portion of the variable-rate debt, Murphy has interest rate swap agreements to hedge fluctuations in cash flows resulting from such risk. Under the interest rate swaps, the Company pays fixed rates and receives variable rates. The Company has a risk management control system to monitor interest rate cash flow risk attributable to the Company's outstanding and forecasted debt obligations as well as the offsetting interest rate swaps. The control system involves using analytical techniques, including cash flow sensitivity analysis, to estimate the impact of interest rate changes on future cash flows. For the nine months ended September 30, 2001, the income effect from cash flow hedging ineffectiveness was insignificant. The fair value of the effective portions of the interest rate swaps and changes thereto is deferred in Accumulated Other Comprehensive Income (AOCI) and is subsequently reclassified into Interest Expense as a rate adjustment in the periods in which the hedged interest payments on the variable-rate debt affect earnings. . Natural Gas Fuel Price Risks - The Company purchases natural gas as fuel at its Meraux, Louisiana refinery. The cost of natural gas is subject to commodity price risk. Murphy has reduced the effect of changes in the price of natural gas used for fuel at Meraux by entering into natural gas swap contracts to hedge fluctuations in cash flows resulting from such risk. Under the natural gas swaps, the Company pays a fixed rate and receives a floating rate in each month of settlement. Murphy has a risk management control system to monitor natural gas price risk attributable both to forecasted natural gas fuel requirements and to Murphy's natural gas swaps. The control system involves using analytical techniques, including various correlations of natural gas purchase prices to futures prices, to estimate the impact of changes in natural gas fuel prices on Murphy's cash flows. 7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.) Note F - Risk Management and Derivative Instruments (Contd.) For the nine months ended September 30, 2001, the income effect from cash flow hedging ineffectiveness was insignificant. The fair value of the effective portions of the natural gas swaps and changes thereto is deferred in AOCI and is subsequently reclassified into Crude Oil, Products and Related Operating Expenses in the periods in which the hedged natural gas fuel purchases affect earnings. . Natural Gas Sales Price Risks - The sales price of natural gas produced by the Company is subject to commodity price risk. Murphy has minimized the effect of changes in the selling price of a limited portion of its U.S. natural gas production through February 2002 by entering into natural gas swap contracts and natural gas options to hedge cash flow fluctuations resulting from such risk. Murphy has a risk management control system to monitor natural gas price risk attributable both to forecasted natural gas sales prices and to Murphy's hedging instruments. The control system involves using analytical techniques, including various correlations of natural gas sales prices to futures prices, to estimate the impact of changes in natural gas prices on Murphy's cash flows from the sale of natural gas. The natural gas price risk pertaining to a portion of gas sales from properties Murphy acquired from Beau Canada Exploration Ltd. in 2000 is limited by natural gas swap agreements expiring in October 2001 that were obtained in the acquisition. These agreements hedge fluctuations in cash flows resulting from such risk. Certain swaps require Murphy to pay a floating price and receive a fixed price and are partially offset by swaps on a lesser volume that require Murphy to pay a fixed price and receive a floating price. For the nine months ended September 30, 2001, Murphy's earnings were not significantly impacted from cash flow hedging ineffectiveness arising from the natural gas swaps and options in the United States and western Canada. The fair values of the effective portions of the natural gas swaps and options and changes thereto are deferred in AOCI and are subsequently reclassified into Crude Oil and Natural Gas Sales in the periods in which the hedged natural gas sales affect earnings. . Crude Oil Purchase Price Risks - Each month, the Company purchases crude oil as the primary feedstock for its U.S. refineries. Prior to April 2000, the Company was a party to crude oil swap agreements that limited the exposure of its U.S. refineries to the risks of fluctuations in cash flows resulting from changes in the prices of crude oil purchased in 2001 and 2002. Under each swap, Murphy would have paid a fixed crude oil price and would have received a floating price during the agreement's contractual maturity period. In April 2000, the Company settled certain of the swaps for cash and entered into offsetting contracts for the remaining swap agreements, locking in a future net cash settlement gain. The fair values of these settlement gains and changes thereto are deferred in AOCI and are subsequently reclassified as a reduction of Crude Oil, Products and Related Operating Expenses in the periods in which the hedged crude oil purchases affect earnings. The Company expects to reclassify approximately $3.8 million in after-tax gains from AOCI into earnings during the next 12 months as the forecasted transactions actually occur. All forecasted transactions currently being hedged are expected to occur by December 2005. 8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.) Note G - Accumulated Other Comprehensive Loss Net gains (losses) in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at September 30, 2001 and December 31, 2000 were as follows. - -------------------------------------------------------------------- (Millions of dollars) September 30, December 31, 2001 2000 - -------------------------------------------------------------------- Foreign currency translation.......... $(79.3) (38.3) Cash flow hedging..................... 6.0 - - -------------------------------------------------------------------- Accumulated other comprehensive loss $(73.3) (38.3) ==================================================================== Note H - Business Segments Three Months Ended Three Months Ended September 30, 2001 September 30, 2000/1/ Total Assets ----------------------------- ---------------------------- at Sept. 30, External Interseg. Income External Interseg. Income (Millions of dollars) 2001 Revenues Revenues (Loss) Revenues Revenues (Loss) - ---------------------------------------------------------------------------------------------------------------- Exploration and production/2/ United States........................ $ 534.3 31.2 12.9 4.6 56.2 18.7 8.7 Canada............................... 1,221.8 101.6 - 21.0 73.9 31.5 35.1 United Kingdom....................... 225.6 55.8 - 20.7 52.7 - 19.8 Ecuador.............................. 69.4 7.1 - 3.0 12.5 - 7.4 Other................................ 23.7 .3 - (16.8) .6 - (2.6) - ---------------------------------------------------------------------------------------------------------------- Total 2,074.8 196.0 12.9 32.5 195.9 50.2 68.4 - ---------------------------------------------------------------------------------------------------------------- Refining, marketing and transportation United States........................ 786.3 827.5 - 9.0 775.1 - 4.1 United Kingdom....................... 199.0 112.4 - 5.0 113.2 - 7.3 Canada............................... - .4 - .2 148.1 .2 1.5 - ---------------------------------------------------------------------------------------------------------------- Total 985.3 940.3 - 14.2 1,036.4 .2 12.9 - ---------------------------------------------------------------------------------------------------------------- Total operating segments........... 3,060.1 1,136.3 12.9 46.7 1,232.3 50.4 81.3 Corporate and other................... 258.2 3.0 - (5.0) 15.0 - 8.8 - ---------------------------------------------------------------------------------------------------------------- Total consolidated $3,318.3 1,139.3 12.9 41.7 1,247.3 50.4 90.1 ================================================================================================================ Nine Months Ended Nine Months Ended September 30, 2001 September 30, 2000/1/ ---------------------------- ---------------------------- External Interseg. Income External Interseg. Income (Millions of dollars) Revenues Revenues (Loss) Revenues Revenues (Loss) - ---------------------------------------------------------------------------------------------------------------- Exploration and production/2/ United States.............................. $ 163.8 43.8 60.3 140.2 54.8 22.5 Canada..................................... 320.6 30.0 72.9 188.5 84.7 85.5 United Kingdom............................. 157.3 - 62.2 140.4 11.6 58.8 Ecuador.................................... 27.4 - 11.1 38.1 - 22.1 Other...................................... 1.2 - (32.8) 1.9 - (13.4) - ---------------------------------------------------------------------------------------------------------------- Total 670.3 73.8 173.7 509.1 151.1 175.5 - ---------------------------------------------------------------------------------------------------------------- Refining, marketing and transportation United States.............................. 2,372.4 - 58.3 2,060.8 .8 17.0 United Kingdom............................. 274.6 - 8.8 349.7 - 17.9 Canada..................................... 301.8 .2 71.4 424.4 .5 5.3 - ---------------------------------------------------------------------------------------------------------------- Total 2,948.8 .2 138.5 2,834.9 1.3 40.2 - ---------------------------------------------------------------------------------------------------------------- Total operating segments................. 3,619.1 74.0 312.2 3,344.0 152.4 215.7 Corporate and other......................... 10.0 - (10.1) 20.6 - (3.4) - ---------------------------------------------------------------------------------------------------------------- Total.................................... 3,629.1 74.0 302.1 3,364.6 152.4 212.3 Cumulative effect of accounting change.................................... - - - - - (8.7) - ---------------------------------------------------------------------------------------------------------------- Total consolidated $3,629.1 74.0 302.1 3,364.6 152.4 203.6 ================================================================================================================ /1/Restated to conform to 2001 presentation. /2/Additional details about results of operations are presented in the tables on page 15. 9
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Results of Operations Three Months Ended September 30, 2001 Compared to Three Months Ended September 30, 2000 Net income in the third quarter of 2001 totaled $41.7 million, $.91 a diluted share, compared to income of $90.1 million, $1.99 a diluted share, in the third quarter a year ago. Two essentially offsetting special items in the third quarter of 2001 had no effect on diluted earnings per share. Third quarter 2000 net income included two special items with a net after-tax benefit of $1.9 million, $.04 a diluted share. Special items in the 2000 quarter included settlement of prior years' U.S. income tax matters, which provided $15.5 million of income to corporate functions, and an after-tax charge of $13.6 million for impairment of two U.S. natural gas properties. The reduction in the Company's third quarter 2001 earnings was attributable to weaker exploration and production results. A combination of lower oil and natural gas sales prices and higher exploration expenses, a large portion of which was in foreign jurisdictions with no recorded tax benefits, caused the decline in upstream results. U.S. refining and marketing income was stronger in the current quarter compared to the 2000 quarter. Murphy's exploration and production operations earned $26.7 million before special items in the third quarter of 2001 compared to $82 million in the same quarter of 2000. Exploration and production operations in the United States earned $4.6 million compared to $22.3 million in the third quarter of 2000. Operations in Canada earned $15.2 million compared to $35.1 million a year ago, and U.K. operations earned $20.7 million compared to $19.8 million. Operations in Ecuador earned $3 million in the third quarter of 2001 compared to $7.4 million a year ago. Other international operations reported a loss of $16.8 million compared to a $2.6 million loss a year earlier. The Company's worldwide crude oil and condensate sales prices averaged $23.37 a barrel in the current quarter compared to $27.06 a year ago. Crude oil and condensate sales prices averaged $26.08 a barrel in the United States, down 18%, and $25.45 in the United Kingdom, down 9%. In Canada, sales prices averaged $23.55 a barrel for light oil, down 20% from last year; $16.50 for heavy oil, down 23%; $24.18 for production from the offshore Hibernia field, down 9%; and $26.43 for synthetic oil, down 15%. The average crude oil sales price in Ecuador was $18.75 a barrel, down 22%. Total crude oil and gas liquids production averaged 64,779 barrels a day compared to 61,852 in the third quarter of 2000. Production increased 3,967 barrels a day or 13% in Canada as light oil was up 1,632 barrels a day, synthetic oil was up 1,022, heavy oil was up 791, and Hibernia was up 522. Oil production also increased 877 barrels a day or 5% in the United Kingdom. In other areas, production decreased 1,076 barrels a day or 17% in Ecuador and declined 841 barrels a day or 13% in the United States. In the current quarter, natural gas sales prices averaged $3.35 a thousand cubic feet (MCF) in the United States, down 25% from the third quarter of 2000; $2.38 in Canada, down 31%; and $2.00 in the United Kingdom, up 69%. Total natural gas sales averaged a record 295 million cubic feet a day in the current quarter compared to 211 million a year ago. Sales of natural gas in the United States averaged 111 million cubic feet a day, down from 141 million in the third quarter of 2000 as a result of a decrease in production from mature fields in the Gulf of Mexico. Canadian natural gas sales were a record 176 million cubic feet a day in the current quarter, an increase of 108 million cubic feet a day due to production from new fields in Western Canada, and U.K. sales were 8 million cubic feet a day, up 6 million from the previous year. Exploration expenses totaled $45.5 million in the third quarter 2001 compared to $20.9 million in 2000. Exploration expenses in the current quarter reflect increased dry hole expense versus the prior year and $14.2 million to acquire 3-D seismic covering the Company's significant deepwater prospects in Malaysia. The tables on page 15 provide additional details of the results of exploration and production operations for the third quarter of each year. Earnings from Murphy's downstream operations before special items for the three months ended September 30, 2001 were $19.6 million, up from $12.9 million in 2000. Refining, marketing and transportation operations in the United States reported earnings of $14.4 million compared to $4.1 million a year ago. Operations in the United Kingdom earned $5 million compared to $7.3 million in the third quarter of 2000. The Company earned $1.5 million in the third quarter of 2000 from purchasing, transporting and reselling crude oil in Canada, while the third quarter of 2001 included earnings of $.2 million from disposal of residual inventory following the sale of this business in the second quarter of 2001. Refinery crude runs worldwide for the quarter were 167,297 barrels a day compared to 164,350 in the third quarter of 2000. Worldwide refined product sales were a record at 215,091 barrels a day compared to 184,237 a year ago. Corporate functions, which include interest income and expense and corporate overhead not allocated to operating functions, reflected losses before special items of $4.6 million in the current quarter compared to $6.7 million in the third quarter of 2000. 10
MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (Contd.) Nine Months Ended September 30, 2001 Compared to Nine Months Ended September 30, 2000 For the first nine months of 2001, income excluding special items totaled $234.5 million, $5.15 a diluted share, compared to $208.9 million, $4.62 a diluted share, a year ago. Net income for the current nine-month period was $302.1 million, $6.63 a diluted share, and included an after-tax benefit of $67.6 million, $1.48 a diluted share, from the gain on sale of the Company's pipeline assets in Canada. Net income for the 2000 period was $203.6 million, $4.50 a diluted share. Special items in 2000 included the aforementioned settlement of prior years' U.S. income tax matters, which provided $15.5 million of income to corporate functions, and the after-tax charge of $13.6 million for impairment of two U.S. natural gas properties. Additionally, 2000 included an after-tax gain of $1.5 million, $.03 a diluted share, from the sale of corporate assets. Earnings from exploration and production operations before a special item for the nine months ended September 30, 2001 were $167.9 million, down from $189.1 million in 2000. Canadian operations earned $67.1 million in 2001, down from $85.5 million in 2000, and earnings in Ecuador declined from $22 million in the 2000 period to $11.1 million in 2001. Other international operations recorded losses of $32.8 million in the first nine months of 2001 and $13.4 million in the 2000 period. United States operations earned $60.3 million for 2001 compared to $36.1 million in the prior period, and the United Kingdom earned $62.2 million compared to $58.8 million in 2000. The Company's worldwide crude oil and condensate sales prices averaged $23.04 a barrel in the 2001 period compared to $26.09 a year ago. Crude oil and condensate sales prices averaged $26.93 a barrel in the United States, down 10%, and $26.09 in the United Kingdom, down 4%. In Canada, sales prices averaged $24.34 a barrel for light oil, down 10%; $12.13 for heavy oil, down 40%; $26.14 for Hibernia production, down 3%; and $27.41 for synthetic oil, down 6%. The average crude oil sales price in Ecuador was $18.33 a barrel, down 18%. Crude oil and gas liquids production for the nine months of 2001 averaged 66,232 barrels a day compared to 65,065 barrels a day during the same period of 2000. Production of crude oil and gas liquids averaged 11,942 barrels a day for Canadian heavy oil, up 18%; 4,335 for Canadian light oil, up 52%; and 9,583 for Canadian synthetic oil, up 11%. In other areas, crude oil and gas liquids production averaged 5,714 in the United States, down 17%; 5,534 in Ecuador, down 16%; 20,154 in the United Kingdom, down 3%; and 8,970 at Hibernia, down 2%. Natural gas sales prices for the first nine months of 2001 averaged $5.23 per MCF in the United States, up 49%; $3.73 in Canada, up 33%; and $2.33 in the United Kingdom, up 38%. Total natural gas sales averaged 276 million cubic feet a day in 2001 compared to 223 million in 2000. Sales of natural gas in the United States averaged 118 million cubic feet a day, down 20%. Average natural gas sales volumes were 145 million cubic feet a day in Canada, up 126%, and 13 million in the United Kingdom, up 19%. Exploration expenses totaled $125.1 million for the nine months ended September 30, 2001, up from $89.6 million a year ago. The increase in exploration expenses in the first nine months of 2001 primarily occurred in Canada and Malaysia, partially offset by lower expenses in the United States. The tables on page 15 provide additional details of the results of exploration and production operations for the first nine months of each year. Earnings from the Company's downstream operations before special items for the nine months ended September 30, 2001 were $76.3 million, up from $40.2 million in 2000. Refining, marketing and transportation operations in the United States reported earnings of $63.7 million in the first nine months of 2001 compared to $17 million for the same period last year; the improvement resulted from higher product margins and higher product sales volumes. Operations in the United Kingdom were affected by lower product margins and lower sales volumes and earned $8.8 million in 2001 compared to $17.9 million in the prior year. The Company sold its Canadian pipeline assets in the second quarter of 2001 for an after-tax gain of $67.6 million. Excluding the gain, earnings from purchasing, transporting and reselling crude oil in Canada were $3.8 million in the current year compared to $5.3 million a year ago. Refinery crude runs worldwide were 168,269 barrels a day compared to 166,487 a year ago. Petroleum product sales were 198,879 barrels a day, up from 177,326 in 2000, with the increase primarily related to higher U.S. product sales volumes at stations built on Wal-Mart parking lots. Excluding special items, financial results from corporate functions reflected losses of $9.7 million in the first nine months of 2001 and $20.4 million a year ago. 11
MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.) Financial Condition Net cash provided by operating activities was $526.9 million for the first nine months of 2001 compared to $540 million for the same period in 2000. Changes in operating working capital other than cash and cash equivalents used cash of $13.9 million in the first nine months of 2001, while providing cash of $56 million in the 2000 period. Cash from operating activities was reduced by expenditures for refinery turnarounds and abandonment of oil and gas properties totaling $14.1 million in the current year and $9.2 million in 2000. Other predominant uses of cash in each year were for capital expenditures, which including amounts expensed, are summarized in the following table, and for dividends, which totaled $50.8 million in 2001 and $48.4 million in 2000. --------------------------------------------------------------------- Nine Months Ended September 30, --------------------------------------------------------------------- (Millions of dollars) 2001 2000 --------------------------------------------------------------------- Capital Expenditures Exploration and production......................... $514.5 282.7 Refining, marketing and transportation............. 110.3 111.7 Corporate and other................................ 5.2 9.4 --------------------------------------------------------------------- Total capital expenditures..................... 630.0 403.8 Geological, geophysical and other exploration expenses charged to income......................... (42.3) (30.4) --------------------------------------------------------------------- Total property additions and dry hole costs $587.7 373.4 ===================================================================== Working capital at September 30, 2001 was $103.5 million, up $31.8 million from December 31, 2000. This level of working capital does not fully reflect the Company's liquidity position, because the lower historical costs assigned to inventories under LIFO accounting were $103.9 million below current costs at September 30, 2001. At September 30, 2001, long-term notes payable of $374.4 million were down $24 million from December 31, 2000 due to repayments and reclassification to current maturities. Long-term nonrecourse debt of a subsidiary was $107.7 million, down $18.7 million from December 31, 2000 primarily due to repayments. A summary of capital employed at September 30, 2001 and December 31, 2000 follows. - ----------------------------------------------------------------------------- Capital Employed September 30, 2001 December 31, 2000 - ----------------------------------------------------------------------------- (Millions of dollars) Amount % Amount % - ----------------------------------------------------------------------------- Notes payable........................ $ 374.4 19 398.4 22 Nonrecourse debt of a subsidiary..... 107.7 5 126.4 7 Stockholders' equity................. 1,494.5 76 1,259.6 71 - ----------------------------------------------------------------------------- $1,976.6 100 1,784.4 100 ============================================================================= 12
MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.) Accounting Matters As described in Note B on page 5 of this Form 10-Q report, Murphy adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended by Statement of Financial Accounting Standards No. 138, effective January 1, 2001. In addition, the Company adopted a change in accounting for unsold crude oil production effective January 1, 2000, restating operating results for all of 2000, and also has retroactively applied two consensuses of the Financial Accounting Standard Board's Emerging Issues Task Force to the Consolidated Statement of Income for all of 2000. In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, "Business Combinations", and SFAS No. 142, "Goodwill and Other Intangible Assets". SFAS No. 141 requires that all future business combinations be accounted for using the purchase method of accounting and that certain acquired intangible assets in a business combination be recognized and reported as assets apart from goodwill. SFAS No. 142 requires that amortization of goodwill be replaced with periodic tests of the goodwill's impairment at least annually in accordance with the provisions of this statement and that intangible assets other than goodwill be amortized over their useful lives. The Company will adopt SFAS No. 141 immediately and SFAS No. 142 on January 1, 2002. As of the date of adoption, the Company expects to have unamortized goodwill of approximately $43 million, which will be subject to the transition provisions of SFAS No. 142. Amortization expense related to goodwill was $2.4 million for the nine months ended September 30, 2001. In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations". SFAS No. 143 requires the Company to record the fair value of a liability for an asset retirement obligation in the period in which the obligation meets the definition of a liability. When the liability is initially recorded, the Company will increase the carrying amount of the related long- lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon adoption of the Statement, the Company will recognize transition amounts for existing asset retirement obligations, long-lived assets and accumulated depreciation as the cumulative effect of a change in accounting principle. After adoption, any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability will be recognized as a gain or loss in the Company's results of operations. The Company is required to adopt the provisions of SFAS No. 143 effective January 1, 2003. In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 supercedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," and the accounting and reporting provisions of APB Opinion No. 30, "Reporting the Results of Operations--Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual, and Infrequently Occurring Events and Transactions," for the disposal of a segment of a business as defined in APB Opinion No. 30. The Company is required to adopt the provisions of SFAS No. 144 effective January 1, 2002. The provisions of SFAS No. 144 generally are to be applied prospectively. It is not practicable to reasonably estimate the impact of adopting these accounting standards on the Company's financial statements at the date of this report, including whether any transitional goodwill impairment losses will be required to be recognized as the cumulative effect of a change in accounting principle. Forward-Looking Statements This Form 10-Q report contains statements of the Company's expectations, intentions, plans and beliefs that are forward-looking and are dependent on certain events, risks and uncertainties that may be outside of the Company's control. These forward-looking statements are made in reliance upon the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results and developments could differ materially from those expressed or implied by such statements due to a number of factors including those described in the context of such forward-looking statements as well as those contained in the Company's January 15, 1997 Form 8-K report on file with the U.S. Securities and Exchange Commission. 13
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note F to this Form 10-Q report, Murphy makes limited use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions. The Company was a party to interest rate swaps at September 30, 2001 with notional amounts totaling $100 million that were designed to convert a similar amount of variable-rate debt to fixed rates. These swaps mature in 2002 and 2004. The swaps require the Company to pay an average interest rate of 6.46% over their composite lives, and at September 30, 2001, the interest rate to be received by the Company averaged 3.58%. The variable interest rate received by the Company under each swap contract is repriced quarterly. The Company considers these swaps to be a hedge of its exposure to fluctuations in interest rates. The estimated fair value of these interest rate swaps was recorded as a liability of $4.9 million at September 30, 2001. At September 30, 2001, 19% of the Company's debt had variable interest rates and 10% was denominated in Canadian dollars. Based on debt outstanding at September 30, 2001, a 10% increase in variable interest rates would have an insignificant impact on the Company's interest expense for the next 12 months after including the favorable effect resulting from lower net settlement payments under the aforementioned interest rate swaps. A 10% increase in the exchange rate of the Canadian dollar versus the U.S. dollar would increase interest expense for the next 12 months by $.1 million for debt denominated in Canadian dollars. Murphy was a party to natural gas price swap agreements at September 30, 2001 for a total notional volume of 7.7 million MMBTU that are intended to hedge a portion of the financial exposure of its Meraux, Louisiana refinery to fluctuations in the future price of natural gas purchased for fuel. In each month of settlement, the swaps require Murphy to pay an average natural gas price of $2.68 an MMBTU and to receive the average NYMEX price for the final three trading days of the month. At September 30, 2001, the estimated fair value of these agreements was recorded as an asset of $4.2 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $2.2 million, while a 10% decrease would have reduced the asset by a similar amount. At September 30, 2001, Murphy was also a party to certain natural gas swap agreements for a total notional volume of 20,000 gigajoules (GJ) a day through October 2001 that are intended to hedge a portion of the financial exposure of its Canadian natural gas production to changes in gas sales prices. In each month, the swaps require Murphy to pay the AECO "C" index price and to receive an average of C$2.47 per GJ. The Company also has a natural gas swap agreement for the purchase of 10,000 GJ per day through October 2001 that requires Murphy to pay C$5.64 per GJ and to receive based on the AECO "C" index. At September 30, 2001, the estimated net fair value of these agreements was recorded as a liability of $1 million. A 10% increase in the average price of the AECO "C" index would have increased this liability by $.1 million, while a 10% decrease would have reduced the liability by a similar amount. In addition, the Company was a party to natural gas swap agreements and natural gas options at September 30, 2001 that are intended to hedge the financial exposure of a limited portion of its U.S. natural gas production to changes in gas sales prices through February 2002. The swaps are for a notional volume ranging from 5,000 to 10,000 MMBTU a day and require Murphy to pay the average NYMEX price for the final trading day of each month and receive a price ranging from $2.91 to $5.50 an MMBTU. The options are for a notional volume of 5,000 MMBTU a day and provides that in each month, Murphy will receive any difference between $4.50 an MMBTU and a lower average NYMEX price for the last three trading days of the first nearby month futures contract for the relevant delivery month. At September 30, 2001, the estimated fair value of these agreements was recorded as an asset of $1.6 million. A 10% increase in the average NYMEX price of natural gas would have reduced this asset by $.2 million, while a 10% decrease would have increased the asset by a similar amount. 14
OIL AND GAS OPERATING RESULTS/1/ (unaudited) - ---------------------------------------------------------------------------------------------------------------- Synthetic United United Oil - (Millions of dollars) States Canada Kingdom Ecuador Other Canada Total - ---------------------------------------------------------------------------------------------------------------- Three Months Ended September 30, 2001 Oil and gas sales, other operating revenues...... $ 44.1 79.4 55.8 7.1 .3 22.2 208.9 Production expenses.............................. 11.2 17.4 10.0 2.7 - 11.3 52.6 Depreciation, depletion and amortization......... 9.8 23.6 9.5 1.3 .2 2.0 46.4 Goodwill amortization............................ - .8 - - - - .8 Exploration expenses Dry holes....................................... 8.0 11.3 - - (.3) - 19.0 Geological and geophysical...................... 1.7 .7 - - 13.7 - 16.1 Other........................................... 1.0 .4 .3 - 2.3 - 4.0 - ---------------------------------------------------------------------------------------------------------------- 10.7 12.4 .3 - 15.7 - 39.1 Undeveloped lease amortization.................. 2.9 3.5 - - - - 6.4 - ---------------------------------------------------------------------------------------------------------------- Total exploration expenses 13.6 15.9 .3 - 15.7 - 45.5 - ---------------------------------------------------------------------------------------------------------------- Selling and general expenses..................... 3.1 3.3 .5 .1 1.4 .1 8.5 Income tax provisions (benefits)................. 1.8 8.6 14.8 - (.2) 3.4 28.4 - ---------------------------------------------------------------------------------------------------------------- Results of operations (excluding corporate overhead and interest) $ 4.6 9.8 20.7 3.0 (16.8) 5.4 26.7 ================================================================================================================ Three Months Ended September 30, 2000/2/ Oil and gas sales, other operating revenues...... $ 74.9 82.0 52.7 12.5 .6 23.4 246.1 Production expenses.............................. 10.6 14.6 8.0 3.6 - 10.1 46.9 Depreciation, depletion and amortization......... 12.3 15.8 8.4 1.4 .2 1.9 40.0 Exploration expenses Dry holes....................................... 10.2 .6 - - - - 10.8 Geological and geophysical...................... .9 2.5 - - .8 - 4.2 Other........................................... .9 .1 .4 - .9 - 2.3 - ---------------------------------------------------------------------------------------------------------------- 12.0 3.2 .4 - 1.7 - 17.3 Undeveloped lease amortization.................. 2.0 1.6 - - - - 3.6 - ---------------------------------------------------------------------------------------------------------------- Total exploration expenses 14.0 4.8 .4 - 1.7 - 20.9 - ---------------------------------------------------------------------------------------------------------------- Selling and general expenses..................... 3.5 1.4 .7 .1 1.3 - 7.0 Income tax provisions............................ 12.2 17.0 15.4 - - 4.7 49.3 - ---------------------------------------------------------------------------------------------------------------- Results of operations (excluding corporate overhead and interest) $ 22.3 28.4 19.8 7.4 (2.6) 6.7 82.0 ================================================================================================================ Nine Months Ended September 30, 2001 Oil and gas sales, other operating revenues...... $ 207.6 278.9 157.3 27.4 1.2 71.7 744.1 Production expenses.............................. 36.0 53.7 24.8 11.1 - 39.8 165.4 Depreciation, depletion and amortization......... 30.5 65.5 28.2 4.9 .5 6.2 135.8 Goodwill amortization............................ - 2.4 - - - - 2.4 Exploration expenses Dry holes....................................... 23.7 34.5 .1 - 7.3 - 65.6 Geological and geophysical...................... 5.4 9.7 .1 - 17.2 - 32.4 Other........................................... 2.4 1.7 .8 - 5.0 - 9.9 - ---------------------------------------------------------------------------------------------------------------- 31.5 45.9 1.0 - 29.5 - 107.9 Undeveloped lease amortization.................. 7.0 10.2 - - - - 17.2 - ---------------------------------------------------------------------------------------------------------------- Total exploration expenses 38.5 56.1 1.0 - 29.5 - 125.1 - ---------------------------------------------------------------------------------------------------------------- Selling and general expenses..................... 9.8 8.4 1.7 .3 4.4 .1 24.7 Income tax provisions (benefits)................. 32.5 41.4 39.4 - (.4) 9.9 122.8 - ---------------------------------------------------------------------------------------------------------------- Results of operations (excluding corporate overhead and interest) $ 60.3 51.4 62.2 11.1 (32.8) 15.7 167.9 ================================================================================================================ Nine Months Ended September 30, 2000/2/ Oil and gas sales, other operating revenues...... $ 195.0 204.2 152.0 38.1 1.9 69.0 660.2 Production expenses.............................. 31.1 38.6 21.8 10.8 - 29.2 131.5 Depreciation, depletion and amortization......... 39.5 43.1 29.2 5.0 .3 5.7 122.8 Exploration expenses Dry holes....................................... 45.2 3.9 - - .3 - 49.4 Geological and geophysical...................... 6.1 8.9 .2 - 8.5 - 23.7 Other........................................... 2.0 .5 1.1 - 3.1 - 6.7 - ---------------------------------------------------------------------------------------------------------------- 53.3 13.3 1.3 - 11.9 - 79.8 Undeveloped lease amortization.................. 5.6 4.2 - - - - 9.8 - ---------------------------------------------------------------------------------------------------------------- Total exploration expenses 58.9 17.5 1.3 - 11.9 - 89.6 - ---------------------------------------------------------------------------------------------------------------- Selling and general expenses..................... 9.9 3.6 2.3 .2 2.9 .1 19.0 Income tax provisions............................ 19.5 36.9 38.6 - .2 13.0 108.2 - ---------------------------------------------------------------------------------------------------------------- Results of operations (excluding corporate overhead and interest) $ 36.1 64.5 58.8 22.1 (13.4) 21.0 189.1 ================================================================================================================ /1/ Excludes special items. /2/ Restated to conform to 2001 presentation. 15
PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS In June 2000, the U.S. Government filed a lawsuit against Murphy Oil USA, Inc., the Company's wholly-owned subsidiary, in federal court in Madison, Wisconsin, alleging violations of environmental laws at the Company's Superior, Wisconsin refinery. The lawsuit was divided into liability and damage phases, and on August 1, 2001, the court ruled against the Company in the liability phase of the trial. The damage phase of the trial has been continued while the parties attempt to conclude a settlement. The Company expects that the resolution of the lawsuit will likely include monetary fines and future capital and environmental improvements at the Superior refinery. While settlement discussions are confidential and not finalized, the Company has established a reserve of $5.5 million towards resolution of the lawsuit. Although no assurance can be given, the Company does not believe that the ultimate resolution of this matter will have a material adverse effect on its financial condition. In December 2000, two of the Company's Canadian subsidiaries as plaintiffs filed an action in the Court of Queen's Bench of Alberta seeking a constructive trust over oil and gas leasehold rights to Crown lands in British Columbia. The suit alleges that the defendants acquired the lands after first inappropriately obtaining confidential and proprietary data belonging to the Company and its joint venturer. In January 2001, one of the defendants, representing an undivided 75% interest in the lands in question, settled its portion of the litigation by conveying its interest to the Company and its joint venturer at cost. In February 2001, the remaining defendants, representing the remaining undivided 25% of the lands in question, filed a counterclaim against the Company's two Canadian subsidiaries and one officer individually seeking compensatory damages of C$6.14 billion. The Company believes that the counterclaim is without merit and that the amount of damages sought is frivolous. While the litigation is in its preliminary stages and no assurance can be given about the outcome, the Company does not believe that the ultimate resolution of this suit will have a material adverse effect on its financial condition. Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business and none of which is expected to have a material adverse effect on the Company's financial condition. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) The Exhibit Index on page 17 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference. (b) No reports on Form 8-K were filed for the quarter ended September 30, 2001. SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. MURPHY OIL CORPORATION (Registrant) By /s/ JOHN W. ECKART ----------------------------------- John W. Eckart, Controller (Chief Accounting Officer and Duly Authorized Officer) November 9, 2001 (Date) 16
EXHIBIT INDEX Exhibit No. Incorporated by Reference to - ------- ------------------------------------------------- 3.1 Certificate of Incorporation of Murphy Oil Corporation Exhibit 3.1 of Murphy's Form 10-Q report for the as amended, effective May 17, 2001 quarterly period ended June 30, 2001 3.2 By-Laws of Murphy Oil Corporation as amended, Exhibit 3.2 of Murphy's Form 10-K report for the effective February 7, 2001 year ended December 31, 2000 4 Instruments Defining the Rights of Security Holders. Murphy is party to several long-term debt instruments in addition to the ones in Exhibits 4.1 and 4.2, none of which authorizes securities exceeding 10% of the total consolidated assets of Murphy and its subsidiaries. Pursuant to Regulation S-K, item 601(b), paragraph 4(iii)(A), Murphy agrees to furnish a copy of each such instrument to the Securities and Exchange Commission upon request. 4.1 Credit Agreement among Murphy Oil Corporation and Exhibit 4.1 of Murphy's Form 10-K report for the certain subsidiaries and the Chase Manhattan Bank et year ended December 31, 1997 al as of November 13, 1997 4.2 Form of Indenture and Form of Supplemental Indenture Exhibits 4.1 and 4.2 of Murphy's Form 8-K report between Murphy Oil Corporation and SunTrust Bank, filed April 29, 1999 under the Securities Nashville, N.A., as Trustee Exchange Act of 1934 4.3 Rights Agreement dated as of December 6, 1989 between Exhibit 4.3 of Murphy's Form 10-K report for the Murphy Oil Corporation and Harris Trust Company of New year ended December 31, 1999 York, as Rights Agent 4.4 Amendment No. 1 dated as of April 6, 1998 to Rights Exhibit 3 of Murphy's Form 8-A/A, Amendment No. Agreement dated as of December 6, 1989 between Murphy 1, filed April 14, 1998 under the Securities Oil Corporation and Harris Trust Company of New York, Exchange Act of 1934 as Rights Agent 4.5 Amendment No. 2 dated as of April 15, 1999 to Rights Exhibit 4 of Murphy's Form 8-A/A, Amendment No. Agreement dated as of December 6, 1989 between Murphy 2, filed April 19, 1999 under the Securities Oil Corporation and Harris Trust Company of New York, Exchange Act of 1934 as Rights Agent 10.1 1992 Stock Incentive Plan as amended May 14, 1997 Exhibit 10.2 of Murphy's Form 10-Q report for the quarterly period ended June 30, 1997 10.2 Employee Stock Purchase Plan as amended May 10, 2000 Exhibit 99.01 of Murphy's Form S-8 registration statement filed August 4, 2000 under the Securities Act of 1933 Exhibits other than those listed above have been omitted since they are either not required or not applicable. 17