================================================================================ 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 March 31, 2002 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 March 31, 2002 was 45,723,653. ================================================================================
PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS Murphy Oil Corporation and Consolidated Subsidiaries CONSOLIDATED BALANCE SHEETS (Thousands of dollars) (Unaudited) March 31, December 31, 2002 2001 ----------- ------------ ASSETS Current assets Cash and cash equivalents .................................................. $ 91,129 82,652 Accounts receivable, less allowance for doubtful accounts of $11,324 in 2002 and $11,263 in 2001 ................................... 323,952 262,022 Inventories, at lower of cost or market Crude oil and blend stocks ............................................... 56,295 38,917 Finished products ........................................................ 95,075 85,133 Materials and supplies ................................................... 51,123 49,098 Prepaid expenses ........................................................... 56,089 61,062 Deferred income taxes ...................................................... 20,170 19,777 ----------- ------------ Total current assets ................................................... 693,833 598,661 Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $3,307,539 in 2002 and $3,277,673 in 2001 ................ 2,606,733 2,525,807 Goodwill, net .................................................................. 50,291 50,412 Deferred charges and other assets .............................................. 87,231 84,219 ----------- ------------ Total assets ........................................................... $ 3,438,088 3,259,099 =========== ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Current maturities of long-term debt ....................................... $ 49,003 48,250 Accounts payable and accrued liabilities ................................... 487,544 463,429 Income taxes ............................................................... 44,770 48,378 ----------- ------------ Total current liabilities .............................................. 581,317 560,057 Notes payable .................................................................. 572,279 416,061 Nonrecourse debt of a subsidiary ............................................... 100,578 104,724 Deferred income taxes .......................................................... 300,149 302,868 Accrued dismantlement costs .................................................... 160,504 160,764 Accrued major repair costs ..................................................... 48,252 44,570 Deferred credits and other liabilities ......................................... 170,221 171,892 Stockholders' equity Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued ...................................................... - - Common Stock, par $1.00, authorized 200,000,000 shares, issued 48,775,314 shares ................................................. 48,775 48,775 Capital in excess of par value ............................................. 543,762 527,126 Retained earnings .......................................................... 1,082,045 1,096,567 Accumulated other comprehensive loss ....................................... (88,681) (83,309) Unamortized restricted stock awards ........................................ (1,346) (968) Treasury stock, 3,051,661 shares of Common Stock in 2002, 3,444,234 shares in 2001, at cost ........................................ (79,767) (90,028) ----------- ------------ Total stockholders' equity ............................................. 1,504,788 1,498,163 ----------- ------------ Total liabilities and stockholders' equity ............................. $ 3,438,088 3,259,099 =========== ============ See Notes to Consolidated Financial Statements, page 5. The Exhibit Index is on page 18. 1
Murphy Oil Corporation and Consolidated Subsidiaries CONSOLIDATED STATEMENTS OF INCOME (unaudited) (Thousands of dollars, except per share amounts) Three Months Ended March 31, -------------------------- 2002 2001 ----------- ----------- REVENUES Crude oil and natural gas sales .......................................... $ 194,933 237,199 Petroleum product sales .................................................. 523,730 672,231 Crude oil trading sales .................................................. 63,220 238,460 Other operating revenues ................................................. 47,017 37,805 Interest and other nonoperating revenues ................................. 1,003 3,690 ----------- ----------- Total revenues ................................................... 829,903 1,189,385 ----------- ----------- COSTS AND EXPENSES Crude oil, products and related operating expenses ....................... 686,082 913,211 Exploration expenses, including undeveloped lease amortization ........... 42,021 37,961 Selling and general expenses ............................................. 22,362 21,046 Depreciation, depletion and amortization ................................. 70,689 54,232 Amortization of goodwill ................................................. - 788 Interest expense ......................................................... 9,542 9,744 Interest capitalized ..................................................... (4,817) (3,586) ----------- ----------- Total costs and expenses ......................................... 825,879 1,033,396 ----------- ----------- Income before income taxes ............................................... 4,024 155,989 Income tax expense ....................................................... 1,490 58,153 ----------- ----------- NET INCOME ............................................................... $ 2,534 97,836 =========== =========== NET INCOME PER COMMON SHARE Basic ................................................................ $ .06 2.17 Diluted .............................................................. $ .06 2.16 Average Common shares outstanding Basic ................................................................ 45,508,953 45,056,307 Diluted .............................................................. 45,903,046 45,314,981 See Notes to Consolidated Financial Statements, page 5. 2
Murphy Oil Corporation and Consolidated Subsidiaries CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited) (Thousands of dollars) Three Months Ended March 31, -------------------- 2002 2001 -------- -------- Net income ........................................................................ $ 2,534 97,836 Other comprehensive income (loss), net of tax Cash flow hedges Net derivative gains ........................................................ 2,947 599 Reclassification adjustments ................................................ (3,323) 1,578 -------- -------- Total cash flow hedges .................................................... (376) 2,177 Net loss from foreign currency translation .................................... (4,996) (51,439) -------- --------- Other comprehensive loss before cumulative effect of accounting change .... (5,372) (49,262) Cumulative effect of accounting change (Note B) ............................... - 6,642 -------- -------- Other comprehensive loss .................................................. (5,372) (42,620) -------- -------- COMPREHENSIVE INCOME (LOSS) ....................................................... $ (2,838) 55,216 ======== ======== See Notes to Consolidated Financial Statements, page 5. 3
Murphy Oil Corporation and Consolidated Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (Thousands of dollars) Three Months Ended March 31, ----------------------- 2002 2001 --------- --------- OPERATING ACTIVITIES Net income ......................................................................... $ 2,534 97,836 Adjustments to reconcile net income to net cash provided by operating activities Depreciation, depletion and amortization ....................................... 70,689 54,232 Provisions for major repairs ................................................... 4,579 5,500 Expenditures for major repairs and dismantlement costs ......................... (2,104) (2,449) Dry holes ...................................................................... 23,112 19,005 Amortization of undeveloped leases ............................................. 6,062 5,230 Amortization of goodwill ....................................................... - 788 Deferred and noncurrent income tax charges (benefits) .......................... (264) 16,966 Pretax gains from disposition of assets ........................................ (5,736) (86) Net (increase) decrease in operating working capital other than cash and cash equivalents ......................................................... (66,189) 29,862 Other operating activities - net ............................................... 32 6,568 --------- --------- Net cash provided by operating activities .................................... 32,715 233,452 --------- --------- INVESTING ACTIVITIES Property additions and dry holes ................................................... (204,860) (179,649) Proceeds from the sale of assets ................................................... 27,877 2,266 Other investing activities - net ................................................... (145) (92) --------- --------- Net cash required by investing activities .................................... (177,128) (177,475) --------- --------- FINANCING ACTIVITIES Increase (decrease) in notes payable ............................................... 156,992 (10) Decrease in nonrecourse debt of a subsidiary ....................................... (4,051) (3,070) Proceeds from exercise of stock options and employee stock purchase plans .......... 18,058 1,495 Cash dividends paid ................................................................ (17,057) (16,896) --------- --------- Net cash provided (required) by financing activities ......................... 153,942 (18,481) --------- --------- Effect of exchange rate changes on cash and cash equivalents ....................... (1,052) (4,898) --------- --------- Net increase in cash and cash equivalents .......................................... 8,477 32,598 Cash and cash equivalents at January 1 ............................................. 82,652 132,701 --------- --------- Cash and cash equivalents at March 31 .............................................. $ 91,129 165,299 ========= ========= SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES Cash income taxes paid ............................................................. $ 8,262 28,325 Interest paid, net of amounts capitalized .......................................... (87) (2,024) 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, 2001. 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 March 31, 2002, and the results of operations and cash flows for the three-month periods ended March 31, 2002 and 2001, in conformity with accounting principles generally accepted in the United States. Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company's 2001 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three months ended March 31, 2002 are not necessarily indicative of future results. Note B - New Accounting Principles Effective January 1, 2002, the Company was required to adopt SFAS No. 142, "Goodwill and Other Intangible Assets", which requires that amortization of goodwill be replaced with annual tests for impairment and that intangible assets other than goodwill be amortized over their useful lives. Murphy assesses the recoverability of goodwill by comparing the fair value of net assets for conventional oil and natural gas operations in Canada with the carrying value of these net assets, including goodwill. The fair value of the conventional oil and natural gas reporting unit will be determined using the expected present value of future cash flows. The carrying amount of goodwill at March 31, 2002 was $50.3 million. The change in the carrying amount of goodwill for the period ended March 31, 2002 was due to a change in the exchange rate of Canadian dollars and U.S. dollars. Goodwill is tested for impairment at the end of the Company's fiscal year after the oil and gas reserve information is available. Adjusted net income, excluding goodwill amortization of $.8 million ($.02 basic and $.01 diluted earnings per share), was $98.6 million for the period ended March 31, 2001. Adjusted basic and diluted earnings per share for the period ended March 31, 2001 were $2.19 and $2.18, respectively. At this time, it is not practicable to reasonably estimate the impact of adopting SFAS No. 142 on the Company's financial statements. Also effective January 1, 2002, Murphy was required to adopt SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which 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". There was no current-period effect of adopting SFAS No. 144 on the Company's consolidated financial statements. In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations", which will require the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability must be recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed in service. 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 SFAS No. 143 on January 1, 2003, the Company will recognize transition adjustments for existing asset retirement obligations, long-lived assets and accumulated depreciation, all net of related income tax effects, 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 earnings. At this time, it is not practicable to reasonably estimate the impact of adopting SFAS No. 143 on the Company's financial statements. 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). As a result of the change, 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 Loss (AOCL) in the Consolidated Balance Sheet until the 5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.) Note B - New Accounting Principles (Contd.) 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 immediately recognized in earnings. Adoption of SFAS Nos. 133/138 resulted in a transition adjustment gain to AOCL of $6.6 million, net of $2.8 million in income taxes, in the first quarter of 2001 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 AOCL for the three months ended March 31, 2002 by $.4 million and increased AOCL for the 2001 period $2.2 million, net of $ .1 million and $1.6 million in income taxes, respectively, and increased income by an insignificant amount for the same periods, but did not affect income per diluted share. For the three months ended March 31, 2002 gains of $3.3 million and losses of $1.6 million in the 2001 period, net of $1.8 million and $1.2 million in taxes, respectively, were reclassified from AOCL to earnings. 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, service 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. A lawsuit filed against Murphy by the U.S. Government is discussed under the caption "Legal Proceedings" on page 17 of this Form 10-Q report. The Company does not believe that this 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 March 31, 2002. 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 not limited to: tax increases and retroactive tax claims; import and export controls; price controls; currency controls; 6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.) Note D - Other Contingencies (Contd.) 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. In addition to the lawsuits discussed under the caption "Legal Proceedings" on page 17 of this Form 10-Q report, the Company and its subsidiaries are engaged in a number of other 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 financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. At March 31, 2002, the Company had contingent liabilities of $33.6 million under certain financial guarantees and $33.5 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 months ended March 31, 2002 and 2001. The following table reconciles the weighted-average shares outstanding used for these computations. - ------------------------------------------------------------------ Reconciliation of Shares Outstanding Three Months Ended March 31, - ------------------------------------------------------------------ (Weighted-average shares) 2002 2001 - ------------------------------------------------------------------ Basic method .......................... 45,508,953 45,056,307 Dilutive stock options ................ 394,093 258,674 - ------------------------------------------------------------------ Diluted method 45,903,046 45,314,981 ================================================================== There were no antidilutive options for the periods ended March 31, 2002 or 2001. Note F - Financial Instruments and Risk Management Murphy utilizes derivative instruments on a limited basis to manage certain risks related to interest rates, commodity prices, and foreign currency exchange rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company's senior management. The Company does not hold any derivatives for trading purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges. o Interest Rate Risks - Murphy has variable-rate debt obligations that expose the Company to the effects of changes in interest rates. To limit its exposure to interest rate risk, Murphy has interest rate swap agreements with notional amounts totaling $100,000,000 to hedge fluctuations in cash flows of a similar amount of variable rate debt. The swaps mature in 2002 and 2004. Under the interest rate swaps, the Company pays fixed rates averaging 6.46% over their composite lives and receives variable rates which averaged 1.86% at March 31, 2002. The variable rate received by the Company under each contract is repriced quarterly. 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. The fair value of the effective portions of the interest rate swaps and changes thereto is deferred in Accumulated Other Comprehensive Loss (AOCL) 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. 7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.) Note F - Financial Instruments and Risk Management (Contd.) For the periods ended March 31, 2002 and 2001, the income effect from cash flow hedging ineffectiveness was insignificant. The fair value of the interest rate swaps are estimated using projected Federal funds rates, Canadian overnight funding rates and LIBOR forward curve rates obtained from published indices and counterparties. The estimated fair value approximates the values based on quotes from each of the counterparties. o 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 with a notional volume of 9.2 million British Thermal Units (MMBTU) to hedge fluctuations in cash flows resulting from such risk during 2004 through 2006. Under the natural gas swaps, the Company pays a fixed rate averaging $2.78 per MMBTU and receives a floating rate in each month of settlement based on the average NYMEX price for the final three trading days of the month. 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. The fair value of the effective portions of the natural gas swaps and changes thereto is deferred in AOCL 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. For the periods ended March 31, 2002 and 2001, the income effect from cash flow hedging ineffectiveness was insignificant. o 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 portion of its U.S. and western Canada natural gas production during May through October 2002 by entering into natural gas swap and natural gas collar contracts to hedge cash flow fluctuations resulting from such risk. The natural gas swaps are for a combined notional volume averaging approximately 24,000 MMBTU equivalent per day and require Murphy to pay the average relevant index (NYMEX or AECO "C") price for each month and receive an average price of $3.29 per MMBTU equivalent. The natural gas collars are for a combined notional volume averaging approximately 29,000 MMBTU equivalent per day and based upon the relevant index prices provide Murphy with an average floor price of $2.62 per MMBTU equivalent and an average ceiling price of $4.71 per MMBTU equivalent. 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 in 2000 was limited by natural gas swap agreements that expired in October 2001 that were obtained in the acquisition. These agreements hedged fluctuations in cash flows resulting from such risk. Certain swaps required Murphy to pay a floating price and receive a fixed price and were partially offset by swaps on a lesser volume that require Murphy to pay a fixed price and receive a floating price. The fair value of these swaps was recorded as a net liability upon the acquisition of Beau Canada and was adjusted on January 1, 2001 upon transition to SFAS 133. Net payments by the Company were recorded as a reduction of the associated liability, with any differences recorded as an adjustment of natural gas revenue. 8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.) Note F - Financial Instruments and Risk Management (Contd.) The fair values of the effective portions of the natural gas swaps and collars and changes thereto are deferred in AOCL and are subsequently reclassified into Crude Oil and Natural Gas Sales in the periods in which the hedged natural gas sales affect earnings. For the periods ended March 31, 2002 and 2001, Murphy's earnings were not significantly effected by cash flow hedging ineffectiveness arising from the natural gas swaps and collars in the United States and western Canada. The fair value of the natural gas fuel swaps and the natural gas sales swaps and collars are both based on the average fixed price of the instruments and the published NYMEX or AECO "C" index futures price or natural gas price quotes from counterparties. o 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 by receiving $5.8 million in cash and entered into offsetting contracts for the remaining swap agreements, locking in an additional future net gain of $1.9 million. The fair values of these settlement gains were recorded in AOCL as part of the transition adjustment and are recognized as a reduction of costs of crude oil purchases in the period the forecasted transaction occurs. During the period ended March 31, 2002, pretax gains of $3.6 million were reclassified from AOCL into earnings. The fair value of the offsetting crude oil swap contracts is based on the fixed swap price and the NYMEX crude oil futures price. The Company expects to reclassify approximately $.5 million in after-tax gains from AOCL 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 2006. Note G - Accumulated Other Comprehensive Loss Net gains (losses) in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at March 31, 2002 and December 31, 2001 were as follows. -------------------------------------------------------------------------- March 31, December 31, (Millions of dollars) 2002 2001 -------------------------------------------------------------------------- Foreign currency translation ................ $ (92.8) (87.8) Cash flow hedging, net of income taxes ...... 4.1 4.5 -------------------------------------------------------------------------- Accumulated other comprehensive loss $ (88.7) (83.3) ========================================================================== 9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.) Note H - Business Segments Three Mos. Ended March 31, 2002 Three Mos. Ended March 31, 2001 Total Assets ------------------------------- --------------------------------- at March 31, External Interseg. Income External Interseg. Income (Millions of dollars) 2002 Revenues Revenues (Loss) Revenues Revenues (Loss) - -------------------------------------------------------------------------------------------------------------------------- Exploration and production* United States ........... $ 621.3 23.1 9.9 (2.6) 79.4 17.2 31.1 Canada .................. 1,275.0 120.6 - 17.8 99.7 20.9 28.1 United Kingdom .......... 204.7 45.5 - 13.2 50.3 - 20.1 Ecuador ................. 71.4 5.6 - .8 10.1 - 3.8 Malaysia ................ 30.6 - - (8.0) - - (1.2) Other international ..... 7.0 .6 - (.5) .5 - (1.3) - -------------------------------------------------------------------------------------------------------------------------- Total 2,210.0 195.4 9.9 20.7 240.0 38.1 80.6 - -------------------------------------------------------------------------------------------------------------------------- Refining and marketing United States ........... 832.4 548.4 - (11.5) 706.2 - 15.0 United Kingdom .......... 197.3 85.1 - (2.2) 78.5 - 1.8 Canada .................. .1 - - - 161.0 .1 2.8 - -------------------------------------------------------------------------------------------------------------------------- Total 1,029.8 633.5 - (13.7) 945.7 .1 19.6 - -------------------------------------------------------------------------------------------------------------------------- Total operating segments ............. 3,239.8 828.9 9.9 7.0 1,185.7 38.2 100.2 Corporate and other ......... 198.3 1.0 - (4.5) 3.7 - (2.4) - -------------------------------------------------------------------------------------------------------------------------- Total consolidated $ 3,438.1 829.9 9.9 2.5 1,189.4 38.2 97.8 ========================================================================================================================== * Additional details about results of oil and gas operations are presented in the tables on page 16. Note I - Subsequent Event In May 2002, the Company sold $350 million of 6.375% notes due in 2012. The Company will use approximately $200 million of the $346.3 million in net proceeds to repay outstanding indebtedness under existing credit facilities and use the remaining proceeds for general corporate purposes. 10
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Results of Operations Murphy's net income in the first quarter of 2002 totaled $2.5 million, $.06 a diluted share, compared to net income of $97.8 million, $2.16 a diluted share in the first quarter a year ago. Cash flow from operating activities, excluding changes in noncash working capital items, totaled $98.9 million for the current quarter compared to $203.6 million in the same quarter last year. In the current quarter, the Company's exploration and production operations earned $20.7 million, a decrease of 74% from the $80.6 million earned in the first quarter of 2001. The decline in income was primarily the result of significantly lower North American natural gas and worldwide oil sales prices partially offset by higher oil and gas sales volumes. Murphy's downstream operations generated a loss of $13.7 million in the first quarter of 2002, compared to earnings of $19.6 million in the same period of 2001. Financial results from the Company's U.S. and U.K. downstream operations were hurt by depressed operating margins at each of its refineries, and by decreases in volumes of products sold in the United States. Exploration and Production - -------------------------- Results of exploration and production operations are presented by geographic segment below. Income (Loss) -------------------------- Three Months Ended March 31, -------------------------- (Millions of dollars) 2002 2001 ------------------- ---- ---- Exploration and production United States ............... $(2.6) 31.1 Canada ...................... 17.8 28.1 United Kingdom .............. 13.2 20.1 Ecuador ..................... .8 3.8 Malaysia .................... (8.0) (1.2) Other International ......... (.5) (1.3) ----- ---- Total ................... $20.7 80.6 ===== ==== Exploration and production operations in the United States reported a loss of $2.6 million compared to earnings of $31.1 million in the first quarter of 2001. This decline was primarily due to lower natural gas and oil sales prices and was partially offset by an $11.6 million decline in exploration expenses. Sales of natural gas averaged 101 million cubic feet a day, down from 125 million in the first quarter of 2001 due to lower production in the Gulf of Mexico. U.S. production expenses were up $1.8 million or 15%, primarily because of higher well workover costs. Operations in Canada earned $17.8 million this quarter compared to $28.1 million a year ago as increased production of oil and natural gas were more than offset by significant declines in average oil and natural gas sales prices and increased exploration expenses. Oil and gas liquids sales in Canada averaged 46,569 barrels a day, an increase of 33% over the prior year, primarily because of the timings of liftings at Hibernia and initial production and sales from the Terra Nova field in 2002. Canadian natural gas sales averaged 199 million cubic feet a day in the current quarter, up 88%, with the increase primarily attributable to higher production from the Ladyfern field. Canadian production expenses in the 2002 quarter were virtually unchanged at $33 million, primarily because of lower costs for synthetic oil operations offset by higher offshore production costs caused by timings of liftings. Exploration expenses were $9.6 million higher than in the 2001 quarter primarily because of higher dry holes. U.K. operations earned $13.2 million in the current quarter, down from $20.1 million in the prior year. Sales of oil and gas liquids in the United Kingdom increased 24% primarily due to the timing of liftings. Higher sales volumes were more than offset by lower sales prices for U.K. crude oil. Operations in Ecuador earned $.8 million in the first quarter of 2002 compared to $3.8 million a year ago, while Malaysia and other international operations reported losses of $8.0 million and $.5 million, respectively, compared to losses of $1.2 million and $1.3 million in 2001. The higher loss in Malaysia in the current period was primarily due to increased dry holes. Crude oil production in Ecuador decreased 28% and the average sales price decreased 16% to $14.84 a barrel. Sales volumes in Ecuador were adversely affected by pipeline restrictions. Production expenses in Ecuador were down $1.1 million due to lower sales volumes. 11
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (Contd.) Exploration and Production (Contd.) - -------------------------- On a worldwide basis, the Company's crude oil and condensate prices averaged $19.76 a barrel in the current quarter, a decrease of 13% from the average of $22.65 in the 2001 period. Average crude oil and liquids production was a quarterly record of 74,292 barrels a day, up 8% over last year, but average sales volumes increased 22% to 80,208 barrels a day due to the timing of liftings and new production from Terra Nova. Total natural gas sales volumes were also a Company record and averaged 309 million cubic feet a day in 2002, up 24% from the 2001 period. The tables on page 16 provide additional details of the results of exploration and production operations for the first quarter of each year. Selected operating statistics for the three-month periods ended March 31, 2002 and 2001 follow. Three Months Ended March 31, ---------------------- 2002 2001 -------- -------- Net crude oil, condensate and gas liquids produced - barrels per day ............... 74,292 69,054 United States .................................................................. 6,185 5,503 Canada - light .............................................................. 4,069 4,584 - heavy .............................................................. 9,722 13,000 - offshore ........................................................... 19,759 8,953 - synthetic .......................................................... 11,342 10,352 United Kingdom ................................................................. 19,031 20,825 Ecuador ........................................................................ 4,184 5,837 Net crude oil, condensate and gas liquids sold - barrels per day ................... 80,208 65,754 United States .................................................................. 6,185 5,503 Canada - light .............................................................. 4,069 4,584 - heavy .............................................................. 9,722 13,000 - offshore ........................................................... 21,436 7,155 - synthetic .......................................................... 11,342 10,352 United Kingdom ................................................................. 23,247 18,808 Ecuador ........................................................................ 4,207 6,352 Net natural gas sold - thousands of cubic feet per day ............................. 309,290 248,799 United States .................................................................. 101,294 124,844 Canada ......................................................................... 199,486 106,006 United Kingdom ................................................................. 8,510 17,949 Total net hydrocarbons produced - equivalent barrels per day (1) ................... 125,840 110,521 Total net hydrocarbons sold - equivalent barrels per day (1) ....................... 131,756 107,221 Weighted average sales prices Crude oil and condensate - dollars a barrel (2) United States ................................................................ $ 20.20 27.42 Canada (3) - light ........................................................ 17.86 25.03 - heavy ........................................................ 13.39 9.43 - offshore ..................................................... 21.95 27.05 - synthetic .................................................... 21.23 28.17 United Kingdom ............................................................... 20.73 27.10 Ecuador ...................................................................... 14.84 17.75 Natural gas - dollars a thousand cubic feet United States (2) ............................................................ $ 2.60 7.21 Canada (3) ................................................................... 2.12 5.79 United Kingdom (3) ........................................................... 2.96 2.53 (1) Natural gas converted on an energy equivalent basis of 6:1 (2) Includes intracompany transfers at market prices. (3) U.S. dollar equivalent. 12
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.) Results of Operations (Contd.) Refining and Marketing - ---------------------- Results of refining and marketing operations are presented below by geographic segment. Income (Loss) -------------------------- Three Months Ended March 31, -------------------------- (Millions of dollars) 2002 2001 ------------------- ------ ---- Refining and marketing United States ............... $(11.5) 15.0 United Kingdom .............. (2.2) 1.8 Canada ...................... - 2.8 ------ ---- Total ................... $(13.7) 19.6 ====== ==== Refining and marketing operations in the United States reported a loss of $11.5 million during the first quarter of 2002 compared to earnings of $15 million a year ago. The Company's U.S. refining margins per barrel were significantly lower in the current quarter compared to margins experienced in the first quarter of 2001. U.S. petroleum product sales averaged 157,505 barrels a day in 2002, a 4% decrease from the first quarter of 2001. The first quarter 2002 results included a net gain of $3.5 million from sale of the Company's interest in Butte Pipe Line. Operations in the United Kingdom reflected a loss of $2.2 million in the first quarter of 2002 compared to earnings of $1.8 million a year ago as margins were depressed throughout much of the current quarter. Worldwide refinery crude runs were 142,441 barrels a day in the first quarter of 2002 compared to 172,319 in the 2001 quarter, and petroleum product sales were 191,318 barrels a day, up from 189,097 a year ago. Refinery crude runs in the U.S. declined significantly due to unplanned maintenance caused by power outages at the Meraux and Superior refineries. Earnings from purchasing, transporting and reselling crude oil in Canada were $2.8 million in the first quarter of 2001. The Company sold its Canadian pipeline and trucking operations in May 2001. Selected operating statistics for the three-month periods ended March 31, 2002 and 2001 follow. Three Months Ended March 31, --------------------- 2002 2001 ------- ------- Refinery inputs - barrels a day .................... 154,512 178,694 United States .................................. 117,730 151,654 United Kingdom ................................. 36,782 27,040 Petroleum products sold - barrels a day ............ 191,318 189,097 United States .................................. 157,504 164,556 Gasoline ..................................... 96,903 86,306 Kerosine ..................................... 8,448 12,381 Diesel and home heating oils ................. 35,725 42,700 Residuals .................................... 13,044 17,880 Asphalt, LPG and other ....................... 3,384 5,289 United Kingdom ................................. 33,814 24,541 Gasoline ..................................... 12,848 9,378 Kerosine ..................................... 2,656 2,584 Diesel and home heating oils ................. 13,856 7,403 Residuals .................................... 2,812 2,522 LPG and other ................................ 1,642 2,654 Corporate and other - ------------------- Corporate activities, which include interest income and expense and corporate overhead not allocated to operating functions, reflected a loss of $4.5 million in the current quarter compared to a loss of $2.4 million in the first quarter of 2001. A decrease in interest earned and increased unallocated corporate overhead were partially offset by lower net interest expense. 13
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS (Contd.) Financial Condition Net cash provided by operating activities was $32.7 million for the first three months of 2002 compared to $233.5 million during the same period in 2001. Changes in operating working capital other than cash and cash equivalents required cash of $66.2 million in the first quarter of 2002 and provided cash of $29.9 million in the 2001 period. Other predominant uses of cash in both years were for capital expenditures, which, including amounts expensed, are summarized in the following table, and for dividends, which totaled $17.1 million in 2002 and $16.9 million in 2001. Three Months Ended March 31, ---------------------------- (Millions of dollars) 2002 2001 ------------------- ---- ---- Capital Expenditures Exploration and production ................................... $177.1 163.2 Refining and marketing ....................................... 40.3 28.3 Corporate and other .......................................... .3 1.9 ------ ----- Total capital expenditures ................................ 217.7 193.4 Geological, geophysical and other exploration expenses charged to income ..................................... (12.9) (13.8) ------ ----- Total property additions and dry holes .................... $204.8 179.6 ====== ===== Working capital at March 31, 2002 was $112.5 million, up $73.9 million from December 31, 2001. This level of working capital does not fully reflect the Company's liquidity position, because the lower historical costs assigned to inventories under last-in first-out accounting were $97.2 million below fair value at March 31, 2002. At March 31, 2002, long-term notes payable of $572.3 million were up $156.2 million from December 31, 2001 due to borrowings to fund certain capital expenditures. Long-term nonrecourse debt of a subsidiary was $100.6 million, down $4.1 million from December 31, 2001 due to scheduled repayments. A summary of capital employed at March 31, 2002 and December 31, 2001 follows. (Millions of dollars) March 31, 2002 Dec. 31, 2001 ------------------- ----------------- -------------- Amount % Amount % -------- --- ------- --- Capital Employed Notes payable ................................................ $ 572.3 26 416.1 21 Nonrecourse debt of a subsidiary ............................. 100.6 5 104.7 5 Stockholders' equity ......................................... 1,504.8 69 1,498.2 74 -------- --- ------- --- Total capital employed .................................... $2,177.7 100 2,019.0 100 ======== === ======= === Accounting and Other Matters As described in Note B on page 5 of this Form 10-Q report, Murphy adopted Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets", and SFAS No. 144, "Accounting for the Impairment of Disposal of Long-Lived Assets" effective January 1, 2002. In April 2002, U.K. tax authorities announced that the corporation tax rate would increase from 30% to 40% for profits associated with North Sea oil production. It was also announced that the first-year allowance for North Sea capital expenditures would increase from 25% to 100%. Based on current Company estimates, the net effect of these changes is expected to reduce U.K. income during the last three quarters of 2002 by approximately $4.8 million. 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. 14
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 March 31, 2002 with notional amounts totaling $100 million that were designed to hedge fluctuations in cash flows of a similar amount of variable-rate debt. 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 March 31, 2002, the interest rate to be received by the Company averaged 1.86%. The variable interest rate received by the Company under each swap contract is repriced quarterly. The Company considers these swaps to be a hedge against potentially higher future interest rates. The estimated fair value of these interest rate swaps was recorded as a liability of $3.3 million at March 31, 2002. At March 31, 2002, 43% of the Company's debt had variable interest rates and 6.5% was denominated in Canadian dollars. Based on debt outstanding at March 31, 2002, a 10% increase in variable interest rates would increase the Company's interest expense approximately $.3 million 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 March 31, 2002 for a total notional volume of 9.2 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 $2.78 an MMBTU and to receive the average NYMEX price for the final three trading days of the month. At March 31, 2002, the estimated fair value of these agreements was recorded as an asset of $7.2 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $2.9 million, while a 10% decrease would have reduced the asset by a similar amount. In addition, the Company was a party to natural gas swap agreements and natural gas collar agreements at March 31, 2002 that are intended to hedge the financial exposure of a limited portion of its U.S. and Canadian natural gas production to changes in gas sales prices through October 2002. The swaps are for a combined notional volume that averages 24,000 MMBTU equivalent a day from May 1 through October 2002 and require Murphy to pay the average relevant index price for each month and receive an average equivalent price of $3.29 per MMBTU. The collars are for a combined notional volume of 29,000 MMBTU a day and based upon the relevant index prices provide Murphy with an average floor price of $2.62 per MMBTU equivalent and an average ceiling price of $4.71 per MMBTU equivalent. At March 31, 2002, the estimated fair value of these agreements was recorded as an asset of $.7 million. A 10% increase in the average index price of natural gas would have reduced this asset by $1.3 million, while a 10% decrease would have increased the asset by a similar amount. 15
OIL AND GAS OPERATING RESULTS (unaudited) - ----------------------------------------------------------------------------------------------------------------------------- United Synthetic United King- Ecua- Oil - (Millions of dollars) States Canada dom dor Malaysia Other Canada Total - ----------------------------------------------------------------------------------------------------------------------------- Three Months Ended March 31, 2002 Oil and gas sales, other operating revenues .......... $33.0 98.9 45.5 5.6 - .6 21.7 205.3 Production expenses .................................. 14.0 20.1 11.4 3.3 - - 12.9 61.7 Depreciation, depletion and amortization ............. 9.8 34.8 9.8 1.3 .3 .1 2.1 58.2 Exploration expenses Dry holes ......................................... 5.0 12.4 - - 5.7 - - 23.1 Geological and geophysical ........................ 2.0 7.8 - - .4 - - 10.2 Other ............................................. .4 .6 .2 - 1.6 (.1) - 2.7 - ----------------------------------------------------------------------------------------------------------------------------- 7.4 20.8 .2 - 7.7 (.1) - 36.0 Undeveloped lease amortization .................... 2.5 3.5 - - - - - 6.0 - ----------------------------------------------------------------------------------------------------------------------------- Total exploration expenses ..................... 9.9 24.3 .2 - 7.7 (.1) - 42.0 - ----------------------------------------------------------------------------------------------------------------------------- Selling and general expenses ......................... 3.9 3.3 .8 .2 - 1.2 .1 9.5 Income tax provisions (benefits) ..................... (2.0) 3.0 10.1 - - (.1) 2.2 13.2 - ----------------------------------------------------------------------------------------------------------------------------- Results of operations (excluding corporate overhead and interest) ................... $(2.6) 13.4 13.2 .8 (8.0) (.5) 4.4 20.7 ============================================================================================================================= Three Months Ended March 31, 2001 Oil and gas sales, other operating revenues .......... $96.6 94.4 50.3 10.1 - .5 26.2 278.1 Production expenses .................................. 12.2 18.1 7.2 4.4 - - 15.2 57.1 Depreciation, depletion and amortization ............. 10.3 18.2 9.8 1.8 .1 .1 2.1 42.4 Amortization of goodwill ............................. - .8 - - - - - .8 Exploration expenses Dry holes ......................................... 15.5 3.4 .1 - - - - 19.0 Geological and geophysical ........................ 3.7 7.4 - - .3 .1 - 11.5 Other ............................................. .3 .7 .2 - .8 .3 - 2.3 - ----------------------------------------------------------------------------------------------------------------------------- 19.5 11.5 .3 - 1.1 .4 - 32.8 Undeveloped lease amortization .................... 2.0 3.2 - - - - - 5.2 - ----------------------------------------------------------------------------------------------------------------------------- Total exploration expenses ..................... 21.5 14.7 .3 - 1.1 .4 - 38.0 - ----------------------------------------------------------------------------------------------------------------------------- Selling and general expenses ......................... 3.8 2.1 .6 .1 - 1.4 - 8.0 Income tax provisions (benefits) ..................... 17.7 17.8 12.3 - - (.1) 3.5 51.2 - ----------------------------------------------------------------------------------------------------------------------------- Results of operations (excluding corporate overhead and interest) ................... $31.1 22.7 20.1 3.8 (1.2) (1.3) 5.4 80.6 ============================================================================================================================= 16
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. Subsequent to the court ruling, the Company and the U.S. Government reached a tentative agreement that was filed with the federal court in January 2002. The settlement was approved by the court following a 30-day public comment period that expired March 7, 2002. According to the settlement agreement, the Company paid a civil penalty of $5.5 million in April 2002 and must implement specified environmental projects to resolve Clean Air Act violations. The Company had previously recorded a liability of $5.5 million to cover the penalty. 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 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 and 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. The ultimate resolution of matters referred to in this Item could have a material adverse effect on the Company's results of operations in a future period. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) The Exhibit Index on page 18 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 March 31, 2002. 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) May 6, 2002 (Date) 17
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 as amended, effective May 17, 2001 the quarterly period ended June 30, 2001 3.2 By-Laws of Murphy Oil Corporation as amended effective Exhibit 3.2 of Murphy's Form 10-K report for February 7, 2001 the 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 one in Exhibit 4.1, 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 Form of Indenture and Form of Supplemental Indenture Exhibits 4.1 and 4.2 of Murphy's Form 8-K between Murphy Oil Corporation and SunTrust Bank, report filed April 29, 1999 under the as Trustee Securities Exchange Act of 1934 4.2 Rights Agreement dated as of December 6, 1989 between Exhibit 4.3 of Murphy's Form 10-K report for Murphy Oil Corporation and Harris Trust Company of New the year ended December 31, 1999 York, as Rights Agent 4.3 Amendment No. 1 dated as of April 6, 1998 to Rights Exhibit 3 of Murphy's Form 8-A/A, Amendment Agreement dated as of December 6, 1989 between Murphy Oil No. 1, filed April 14, 1998 under the Corporation and Harris Trust Company of New York, as Securities Exchange Act of 1934 Rights Agent 4.4 Amendment No. 2 dated as of April 15, 1999 to Rights Exhibit 4 of Murphy's Form 8-A/A, Amendment Agreement dated as of December 6, 1989 between Murphy Oil No. 2, filed April 19, 1999 under the Corporation and Harris Trust Company of New York, as Securities Exchange Act of 1934 Rights Agent 10.1 1982 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. 18