Murphy Oil (MUR) 10-Q 2002 Q3 Quarterly report

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, 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 incorporation or organization)	(I.R.S. Employer 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, 2002, was45,820,451.

PART I – FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)

	September 30, 2002			December 31, 2001
	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	126,376		82,652
Accounts receivable, less allowance for doubtful accounts of $9,081 in 2002 and $11,263 in 2001		351,677		262,022
Inventories
Crude oil and blend stocks		107,804		38,917
Finished products		103,257		85,133
Materials and supplies		63,060		49,098
Prepaid expenses		74,296		61,062
Deferred income taxes		19,169		19,777
Total current assets		845,639		598,661
Property, plant and equipment, at cost less accumulated depreciation and amortization of $3,498,331 in 2002 and $3,277,673 in 2001		2,793,685		2,525,807
Goodwill, net		50,564		50,412
Deferred charges and other assets		91,106		84,219
Total assets	$	3,780,994		3,259,099
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	56,160		48,250
Accounts payable and accrued liabilities		548,957		463,429
Income taxes		47,915		48,378
Total current liabilities		653,032		560,057
Notes payable		797,603		416,061
Nonrecourse debt of a subsidiary		77,406		104,724
Deferred income taxes		315,880		302,868
Accrued dismantlement costs		171,102		160,764
Accrued major repair costs		51,341		44,570
Deferred credits and other liabilities		164,809		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		547,592		527,126
Retained earnings		1,097,875		1,096,567
Accumulated other comprehensive loss		(66,967	)	(83,309	)
Unamortized restricted stock awards		(216	)	(968	)
Treasury stock, 2,954,863 shares of Common Stock in 2002, 3,444,234 shares in 2001, at cost		(77,238	)	(90,028	)
Total stockholders’ equity		1,549,821		1,498,163
Total liabilities and stockholders’ equity	$	3,780,994		3,259,099

See Notes to Consolidated Financial Statements, page 5.

The Exhibit Index is on page 23.

1

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars, except per share amounts)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2002			2001		2002		2001
REVENUES
Crude oil and natural gas sales	$	170,487		173,059		590,664		633,811
Petroleum product sales		793,775		767,296		2,052,185		2,217,598
Crude oil trading sales		83,996		134,939		238,105		531,265
Other operating revenues		76,717		36,682		172,010		202,632
Interest and other nonoperating revenues		2,431		2,959		4,433		9,994
Total revenues		1,127,406		1,114,935		3,057,397		3,595,300
COSTS AND EXPENSES
Crude oil, products and related operating expenses		958,088		910,721		2,523,935		2,736,946
Exploration expenses, including undeveloped lease amortization		17,619		45,541		121,407		125,091
Selling and general expenses		23,166		25,698		68,657		71,727
Depreciation, depletion and amortization		67,796		58,090		223,167		170,578
Impairment of properties		9,154		—		9,154		—
Amortization of goodwill		—		782		—		2,355
Interest expense		13,961		9,516		36,790		28,962
Interest capitalized		(7,172	)	(5,065	)	(16,596	)	(12,984	)
Total costs and expenses		1,082,612		1,045,283		2,966,514		3,122,675
Income before income taxes		44,794		69,652		90,883		472,625
Income tax expense		7,386		27,923		37,012		170,492
NET INCOME	$	37,408		41,729		53,871		302,133
NET INCOME PER COMMON SHARE
Basic	$	.82		.92		1.18		6.69
Diluted		.81		.91		1.17		6.63
Average Common shares outstanding
Basic		45,819,355		45,306,674		45,690,981		45,190,224
Diluted		46,073,736		45,683,102		46,044,342		45,550,230

2

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2002			2001		2002		2001
Net income	$	37,408		41,729		53,871		302,133
Other comprehensive income (loss), net of tax
Cash flow hedges
Net derivative gains (losses)		(1,899	)	(2,057	)	5,723		(4	)
Reclassification adjustments		(3,881	)	(2,001	)	(6,259	)	(655	)
Total cash flow hedges		(5,780	)	(4,058	)	(536	)	(659	)
Net gain (loss) from foreign currency translation		(35,538	)	(19,188	)	16,878		(41,056	)
Other comprehensive income (loss) before cumulative effect of accounting change		(41,318	)	(23,246	)	16,342		(41,715	)
Cumulative effect of accounting change (Note B)		—		—		—		6,642
Other comprehensive income (loss)		(41,318	)	(23,246	)	16,342		(35,073	)
COMPREHENSIVE INCOME/(LOSS)	$	(3,910	)	18,483		70,213		267,060

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,
	2002			2001
OPERATING ACTIVITIES
Net income	$	53,871		302,133
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		223,167		170,578
Impairment of properties		9,154		—
Provisions for major repairs		14,820		16,870
Expenditures for major repairs and dismantlement costs		(11,821	)	(14,113	)
Dry holes		78,373		65,638
Amortization of undeveloped leases		18,369		17,268
Amortization of goodwill		—		2,355
Deferred and noncurrent income tax charges		2,914		61,815
Pretax gains from disposition of assets		(9,200	)	(95,604	)
Net increase in operating working capital other than cash and cash equivalents		(118,191	)	(13,867	)
Other operating activities – net		6,233		13,863
Net cash provided by operating activities		267,689		526,936
INVESTING ACTIVITIES
Property additions and dry holes		(615,075	)	(587,702	)
Proceeds from sale of assets		55,383		159,882
Other investing activities – net		(77	)	(290	)
Net cash required by investing activities		(559,769	)	(428,110	)
FINANCING ACTIVITIES
Increase (decrease) in notes payable		382,967		(17,319	)
Decrease in nonrecourse debt of a subsidiary		(21,565	)	(14,706	)
Cash dividend paid		(52,563	)	(50,830	)
Proceeds from exercise of stock options and employee stock purchase plan		23,488		14,919
Other financing activities – net		(2,688	)	(2,000	)
Net cash provided (required) by financing activities		329,639		(69,936	)
Effect of exchange rate changes on cash and cash equivalents		6,165		(337	)
Net increase in cash and cash equivalents		43,724		28,553
Cash and cash equivalents at January 1		82,652		132,701
Cash and cash equivalents at September 30	$	126,376		161,254
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid	$	7,453		102,092
Interest paid, net of amounts capitalized		5,622		7,236

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, and the results of its operations and cash flows for such periods, in conformity with accounting principles generally accepted in the United States of America.

The Company’s revenues and crude oil, products and related operating expenses for the three-month and nine-months ended September 30, 2001 have been reduced by approximately 2% compared to the amounts reflected in the Company’s Form 10-Q filings for those periods to eliminate intracompany sales of crude oil inadvertently included in revenues and crude oil, products and related operating expenses. This correction had no effect on the Company’s net income for any periods.

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 nine months ended September 30, 2002 are not necessarily indicative of future results.

Note B – New Accounting Principles

Effective January 1, 2002, the Company was required to adopt Statement of Financial Accounting Standards (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 is determined using the expected present value of future cash flows. The carrying amount of goodwill at September 30, 2002 was $50.6 million. The change in the carrying amount of goodwill for the period ended September 30, 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. Based on its assessment of the fair value of its Canadian conventional oil and natural gas operations, the Company believes the recorded value of goodwill is not impaired. Adjusted net income for the nine-month period ended September 30, 2001, excluding goodwill amortization of $2.4 million ($.05 basic and diluted earnings per share), was $304.5 million. Adjusted basic and diluted earnings per share for the nine-month period ended September 30, 2001 were $6.74 and $6.68, respectively.

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 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 consolidated financial statements.

Effective January 1, 2001, Murphy adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 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 forecasted transaction occurs, at which time the derivative’s fair value will be

5

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B – New Accounting Principles (Contd.)

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, 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 nine months ended September 30, 2002 by $.5 million, net of $.3 million in income taxes, and increased income by an insignificant amount for the same period. During the first nine months of 2001, the accounting change decreased AOCL by $.7 million, net of $.4 million in income taxes, and decreased net income by $.3 million, net of $.2 million in taxes. For the nine months ended September 30, 2002, gains of $6.3 million, net of $4.2 million in taxes, were reclassified from AOCL to income. In the first nine months of 2001, gains of $.6 million, net of $.1 million in taxes, were reclassified from AOCL to income.

In June 2002, the Emerging Issues Task Force (“EITF”) of the Financial Accounting Standards Board reached a consensus on certain issues contained in Topic 02-3, Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. The Company does not believe that this consensus, as currently interpreted by the EITF, applies to its operations of marketing crude oil. However, if the EITF expands its definition of energy trading activities to include the Company’s marketing activities, the Company may be required to present crude oil trading sales in its statement of income on a net margin basis. Any such change would decrease the Company’s reported crude oil trading sales and crude oil, products and related operating expenses by an equal amount, but would have no effect on operating income or cash flow.

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 a former waste site at a Company refinery. 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 ade 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.

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.

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Environmental Contingencies (Contd.)

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, 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 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.

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 financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. At September 30, 2002 the Company had contingent liabilities of $33.5 million under certain financial guarantees and $27.5 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-month and nine-month periods ended September 30, 2002 and 2001. The following table reconciles the weighted-average shares outstanding used for these computations.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2002	2001	2002	2001
	(Weighted-average shares)
Reconciliation of Shares Outstanding
Basic method	45,819,355	45,306,674	45,690,981	45,190,224
Dilutive stock options	254,381	376,428	353,361	360,006
Dilutive method	46,073,736	45,683,102	46,044,342	45,550,230

All stock options outstanding during each of the periods presented were dilutive.

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.

• Interest Rate Risks – Murphy has variable-rate debt obligations that expose the Company to the effects of changes in interest rates. To partially reduce its exposure to interest rate risk, Murphy has interest rate swap agreements with notional amounts totaling $50 million at September 30, 2002 to hedge fluctuations in cash flows of a similar amount of variable rate debt. Interest rate swaps with notional amounts totaling $50 million matured during the second quarter of 2002. The remaining swaps mature in 2004. Under the interest rate swaps, the Company pays fixed rates averaging 6.17% over their composite lives and receives variable rates which averaged 1.83% at September 30, 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

7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Financial Instruments and Risk Management (Contd.)

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 in the periods in which the hedged interest payments on the variable-rate debt affect earnings. For the periods ended September 30, 2002 and 2001, the income effect from cash flow hedging ineffectiveness of interest rates 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.

• Natural Gas Fuel Price Risks – The Company purchases natural gas as fuel at its Meraux, Louisiana refinery, and as such, is subject to commodity price risk related to the purchase price of this gas. Murphy has hedged the cash flow risk associated with the cost of a portion of the natural gas it will purchase in 2004 through 2006 by entering into natural gas swap contracts with a total notional volume of 9.2 million British Thermal Units (MMBTU). 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 September 30, 2002 and 2001, the income effect from cash flow hedging ineffectiveness was insignificant.

• Natural Gas Sales Price Risks – The sales price of natural gas produced by the Company is subject to commodity price risk. Murphy has hedged the cash flow risk associated with the sales price for a portion of the natural gas it will produce in the United States and Canada in October 2002 by entering into financial contracts known as natural gas swaps and collars. The swaps cover a combined notional volume averaging 47,000 MMBTU equivalents per day and require Murphy to pay the average relevant index (NYMEX or AECO “C”) price for October and receive an average price of $3.38 per MMBTU equivalent. The natural gas collars are for a combined notional volume averaging 48,000 MMBTU equivalents per day and based upon the relevant index prices, provide Murphy with an average floor price of $2.73 per MMBTU and an average ceiling price of $4.88 per MMBTU. 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 required 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.

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 period ended September 30, 2002 and 2001, Murphy’s earnings were not significantly affected by cash flow hedging ineffectiveness. During the third quarter of 2002, the Company received approximately $5.9 million for settlement of natural gas swap and collar agreements in 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.

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Financial Instruments and Risk Management (Contd.)

• 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 purchases 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 and entered into offsetting contracts for the remaining swap agreements, locking in a total net gain of $7.7 million. The fair values of these settlement gains were recorded in AOCL as part of the transition adjustment at January 1, 2001 and are recognized as a reduction of costs of crude oil purchases in the period the forecasted transaction occurs. During the nine-month period ended September 30, 2002, pretax gains of $5.2 million were reclassified from AOCL into earnings. Pretax gains of $1.6 million were reclassified into earnings in the third quarter of 2002. There were no gains reported in the nine-month period ended September 30, 2001. 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 $1 million in after-tax losses from AOCL into earnings during the next 12 months as the forecasted transactions covered by hedging instruments 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 September 30, 2002 and December 31, 2001 were as follows.

	September 30, 2002			December 31, 2001
	(Millions of dollars)
Foreign currency translation loss, net	$	(71.0	)	(87.8	)
Cash flow hedge gains, net		4.0		4.5
Accumulated other comprehensive loss	$	(67.0	)	(83.3	)

Note H – Financing Arrangements

In May 2002, the Company sold $350 million of 6.375 percent notes due in 2012. Interest is payable November 1, 2002 and semiannually thereafter. The Company used a portion of the net proceeds to refinance outstanding indebtedness under existing credit facilities and used the remaining proceeds to fund ongoing capital projects and for other general purposes.

Note I – Property, Plant and Equipment

During the third quarter of 2002, the Company recorded a noncash charge of $9.1 million for impairment of certain nonoperated Gulf of Mexico natural gas properties. After related income tax benefits, this write-down reduced net income by $5.9 million. The impairment was caused by downward revisions of natural gas reserves due to poor well performance. The carrying value of impaired properties was reduced to the asset’s fair value based on projected future discounted net cash flows, using the Company’s estimate of commodity prices.

During May, the Company and the U.S. government reached an agreement in principle where the U.S. government paid Murphy $23 million to relinquish seven of nine leases in the Destin Dome field off the coast of Florida. As part of the agreement, the Company will have a 100% interest in the remaining two Destin Dome leases. These leases will run through 2022, with no development application allowed until at least 2012. The Company must obtain permission of both the U.S. government and the State of Florida to perform development operations during the 20-year lease term. No gain or loss was recorded in connection with the agreement, and the proceeds were recorded as a reduction of Property, Plant and Equipment. Murphy has approximately $22.5 million of net costs in Property, Plant and Equipment associated with the remaining two leases. Should the U.S. government and/or the State of Florida refuse to permit development by the Company prior to expiration of the leases, the Company’s net investment would be impaired and charged to expense.

9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Business Segments

	Total Assets at September 30, 2002		Three Months Ended September 30, 2002				Three Months Ended September 30, 2001
			External Revenues	Inter-segment Revenues	Income (Loss)		External Revenues	Inter-segment Revenues	Income (Loss)
	(Millions of dollars)
Exploration and production*
United States	$	639.4	43.3	11.3	11.0		31.2	12.9	4.6
Canada		1,248.4	93.3	26.4	28.4		77.2	24.4	21.0
United Kingdom		254.4	38.8	—	11.2		55.8	—	20.7
Ecuador		77.8	11.5	—	5.4		7.1	—	3.0
Malaysia		78.0	—	—	1.1		—	—	(16.4	)
Other international		7.8	.4	—	(1.2	)	.3	—	(.4	)
Total		2,305.8	187.3	37.7	55.9		171.6	37.3	32.5
Refining and marketing
North America		995.3	839.7	—	(13.1	)	827.9	—	9.2
United Kingdom		231.6	98.0	—	(.7	)	112.4	—	5.0
Total		1,226.9	937.7	—	(13.8	)	940.3	—	14.2
Total operating segments		3,532.7	1,125.0	37.7	42.1		1,111.9	37.3	46.7
Corporate and other		248.3	2.4	—	(4.7	)	3.0	—	(5.0	)
Total consolidated	$	3,781.0	1,127.4	37.7	37.4		1,114.9	37.3	41.7

	Nine Months Ended September 30, 2002					Nine Months Ended September 30, 2001
	External Revenues		Inter-segment Revenues	Income (Loss)		External Revenues	Inter-segment Revenues	Income (Loss)
	(Millions of dollars)
Exploration and production*
United States	$	97.1	33.9	4.3		163.8	43.8	60.3
Canada		361.0	61.0	100.2		286.8	63.8	72.9
United Kingdom		123.3	—	33.6		157.3	—	62.2
Ecuador		25.0	—	9.5		27.4	—	11.1
Malaysia		—	—	(39.0	)	—	—	(25.4	)
Other international		1.5	—	(2.4	)	1.2	—	(7.4	)
Total		607.9	94.9	106.2		636.5	107.6	173.7
Refining and marketing
North America		2,162.0	—	(34.4	)	2,674.2	.2	129.7
United Kingdom		283.1	—	(1.1	)	274.6	—	8.8
Total		2,445.1	—	(35.5	)	2,948.8	.2	138.5
Total operating segments		3,053.0	94.9	70.7		3,585.3	107.8	312.2
Corporate and other		4.4	—	(16.8	)	10.0	—	(10.1	)
Total consolidated	$	3,057.4	94.9	53.9		3,595.3	107.8	302.1

* Additional details about results of operations are presented in the tables on page 18.

10

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULT OF OPERATIONS

Results of Operations

Murphy’s net income in the third quarter of 2002 totaled $37.4 million, $.81 per diluted share, compared to net income of $41.7 million, $.91 per diluted share in the third quarter a year ago. Results for the third quarter 2002 included special items that increased net income by $7.9 million, $.17 per diluted share. Two essentially offsetting special items in the third quarter of 2001 had no effect on diluted earnings per share. The 2002 special items included income of $14.7 million for settlement of U.S. tax matters and an after-tax gain of $2.3 million for sale of an asset. Additionally, the Company recorded an after-tax charge of $5.9 million for the write-down of certain nonoperated Gulf of Mexico properties and $3.2 million for estimated self-insured costs to repair tropical storm damages in the Gulf of Mexico.

The Company’s revenues and crude oil, products and related operating expenses for the three-month and nine-month periods ended September 30, 2002 and 2001 have been reduced by approximately 2% compared to the amounts reflected in the Company’s October 29, 2002 press release to eliminate intracompany sales of crude oil inadvertantly included in revenues and crude oil, products and related operating expenses. This correction had no effect on the Company’s net income for any periods.

In the current quarter, the Company’s exploration and production operations earned $48 million excluding special items, an increase of $21.3 million compared to the 2001 period. Significantly lower exploration expense, particularly in Malaysia, was the primary reason for the increase in earnings in the 2002 period. The Company’s refining and marketing operations incurred a loss of $13.8 million in the 2002 period compared to earnings of $19.6 million before special items for the three months ended September 30, 2001. Refining margins in both the U.S. and U.K. were under extreme pressure throughout the 2002 period as sales prices for refined products did not match the high price of crude oil feedstocks. In response to negative margins, the Company curtailed crude runs at its Meraux refinery for much of the recently completed quarter.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $25.52 a barrel in the current quarter, an increase of 9% from the average of $23.37 in the 2001 period. The increase in the average oil price in 2002 was due to tensions in the Middle East. Average crude oil and liquids production was 70,569 barrels a day, up 9% over last year, while average sales volumes decreased 10% to 57,718 barrels a day due to timing of liftings. North American natural gas sales prices averaged $2.81 per MCF in the third quarter compared to $2.75 per MCF in the same quarter of 2001. Total natural gas sales volumes averaged 288 million cubic feet a day in 2002, down 2% from the 2001 quarter. The tables on page 18 provide additional details of the results of exploration and production operations for the first nine months of each year.

For the first nine months of 2002, net income totaled $53.9 million, $1.17 per diluted share, compared to income of $302.1 million, $6.63 per diluted share, for the nine months ended September 30, 2001. The current period included special items that increased net income by $7.9 million, $.17 per diluted share, while the 2001 period included a $67.6 million gain, $1.48 a diluted share, on the sale of the Company’s pipeline assets in Canada.

Exploration and production earnings before special items in the first nine months of 2002 were down $69.6 million from the prior year, with the decrease mainly attributable to a 38% decline in North American natural gas sales prices. The Company’s refining and marketing operations incurred a loss of $35.5 million in the nine months ended September 30, 2002 compared to earnings of $76.3 million before special items in the 2001 period. This decline in earnings was primarily the result of significantly weaker U.S. refining margins.

The Company’s worldwide effective tax rate in the current quarter is significantly lower than the expected tax rate due to benefits from settlement of tax matters.

11

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production

Results of exploration and production operations are presented by geographic segment below.

	Income (Loss)
	Three Months Ended September 30,					Nine Months Ended September 30,
	2002			2001		2002		2001
	(Millions of dollars)
Exploration and production
United States	$	3.1		4.6		(3.6	)	60.3
Canada		28.4		15.2		100.2		67.1
United Kingdom		11.2		20.7		33.6		62.2
Ecuador		5.4		3.0		9.5		11.1
Malaysia		1.1		(16.4	)	(39.0	)	(25.4	)
Other international		(1.2	)	(.4	)	(2.4	)	(7.4	)
Income before special items		48.0		26.7		98.3		167.9
Settlement of tax matters		14.7		—		14.7		—
Gain on sale of assets		2.3		—		2.3		—
Impairment of properties		(5.9	)	—		(5.9	)	—
Loss from storm damage		(3.2	)	—		(3.2	)	—
Benefit from tax rate change		—		5.8		—		5.8
Total income	$	55.9		32.5		106.2		173.7

Exploration and production operations in the United States reported earnings of $3.1 million before special items in the third quarter of 2002 compared to earnings of $4.6 million a year ago. This decline was mainly due to lower oil and natural gas sales volumes, partially offset by a decrease in exploration expenses. Sales of natural gas averaged 91 million cubic feet a day, down from 111 million in the third quarter of 2001 due to lower production in the Gulf of Mexico.

Operations in the United States for the nine months ended September 30, 2002 reflected a loss of $3.6 million before special items compared to earnings of $60.3 million for 2001. The decrease was due to lower natural gas sales prices and lower production volumes in the Gulf of Mexico, coupled with higher exploration expenses and increased well workover costs.

Operations in Canada earned $28.4 million this quarter compared to $15.2 million, before a special item, a year ago as production increases of oil and natural gas were coupled with increases in average oil and natural gas sales prices. Natural gas swap and collar agreements increased the average sales price realized for Canadian natural gas by $.33 per MCF during the third quarter 2002. Also exploration expenses in the 2002 period declined from a year ago, due to lower dry holes expense. Oil and gas liquids sales in Canada averaged 32,127 barrels a day, an increase of 3% over the prior year. Canadian natural gas sales averaged 193 million cubic feet a day in the current quarter, up 9% with the increase mainly attributable to higher production from the Ladyfern field. Higher oil and gas sales volumes caused a 6% increase in Canadian production expenses in the 2002 quarter over the 2001 period.

In the first nine months of 2002, Canadian operations earned $100.2 million compared to $67.1 million, before the aforementioned special item in the 2001 period. Higher sales volumes for oil and natural gas were offset by declines in average oil and natural gas sales prices. Exploration expenses also declined $19.2 million versus 2001, due to lower dry holes expense.

U.K. operations earned $11.2 million in the current quarter, down from $20.7 million in the prior year. Sales volumes of oil and gas liquids in the United Kingdom decreased 36% primarily due to the timing of liftings. Exploration expense increased $3.1 million due to a dry hole in the 2002 quarter. Income for the 2002 nine-month period was $33.6 million compared to $62.2 million a year ago. The decline was due to lower sales prices and volumes for crude oil, higher production expenses, increased exploration expenses and a one-time tax adjustment. In April 2002, U.K. tax authorities announced a corporation tax rate 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%. During the second quarter of 2002, the Company recorded a $2 million tax charge due to the rate change.

12

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Operations in Ecuador earned $5.4 million in the third quarter of 2002 compared to $3 million a year ago, while Malaysia reported earnings of $1.1 million and other international operations reported a loss of $1.2 million in the third quarter of 2002 compared to losses of $16.4 million and $.4 million in the same quarter of 2001. Crude oil sales in Ecuador increased 40% and the average sales price for crude oil increased by 15%. Production expenses in Ecuador increased by $1.5 million in the 2002 period. Exploration expenses in Malaysia were $17.6 million lower in the 2002 period than in 2001 due to credit adjustments to prior dry holes drilled of approximately $1.8 million in the current period and $15.8 million less geological and geophysical and other exploration costs versus the 2001 period.

For the first nine months of 2002, earnings in Ecuador were $9.5 million compared to $11.1 million for the 2001 period, while Malaysia and other international operations reported losses of $39 million and $2.4 million, respectively in 2002, compared to losses of $25.4 million and $7.4 million a year ago. Sales volumes in Ecuador decreased 13% in the first nine months of 2002 due to pipeline capacity restrictions, but results benefited from a 6% increase in the average crude sales price. Malaysia losses increased in 2002 by $13.6 million mainly due to higher dry holes expense of $31.3 million, partially offset by a $18.1 million decline in geological and geophysical and other exploratory costs. The higher loss in other international operations in the 2001 period was the result of an unsuccessful well offshore Ireland.

Selected operating statistics for the three-month and nine-month periods ended September 30, 2002 and 2001 follow.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2002	2001	2002	2001
Net crude oil, condensate and gas liquids produced–barrels per day	70,569	64,779	74,290	66,232
United States	5,011	5,607	5,650	5,714
Canada–light	3,032	4,113	3,399	4,335
–heavy	9,298	11,199	9,495	11,942
–offshore	20,725	8,977	22,271	8,970
–synthetic	12,922	9,156	11,036	9,583
United Kingdom	14,810	20,400	17,864	20,154
Ecuador	4,771	5,327	4,575	5,534
Net crude oil, condensate and gas liquids sold–barrels per day	57,718	64,099	73,663	66,587
United States	5,011	5,607	5,650	5,714
Canada–light	3,032	4,113	3,399	4,335
–heavy	9,298	11,199	9,495	11,942
–offshore	6,875	6,714	20,887	8,632
–synthetic	12,922	9,156	11,036	9,583
United Kingdom	14,852	23,219	18,452	20,907
Ecuador	5,728	4,091	4,744	5,474
Net natural gas sold–thousands of cubic feet per day	288,440	294,808	311,151	276,030
United States	90,904	110,917	97,132	118,253
Canada	192,592	176,129	207,718	145,124
United Kingdom	4,944	7,762	6,301	12,653
Total net hydrocarbons produced–equivalent barrels per day (1)	118,642	113,914	126,149	112,237
Total net hydrocarbons sold–equivalent barrels per day (1)	105,791	113,234	125,522	112,592

13

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

	Three Months Ended September 30,			Nine Months Ended September 30,
	2002		2001	2002	2001
Weighted average sales prices
Crude oil and condensate–dollars a barrel (2)
United States	$	26.59	26.08	23.71	26.93
Canada (3)–light		25.24	23.55	21.88	24.34
–heavy		19.92	16.50	16.91	12.13
–offshore		27.00	24.18	24.45	26.14
–synthetic		27.73	26.43	25.09	27.41
United Kingdom		27.52	25.45	23.57	26.09
Ecuador		21.65	18.75	19.35	18.33
Natural gas–dollars a thousand cubic feet
United States (2)	$	3.34	3.35	3.13	5.23
Canada (3)		2.56	2.38	2.53	3.73
United Kingdom (3)		1.81	2.00	2.62	2.33

(1) Natural gas converted on an energy equivalent basis of 6:1

(2) Includes intracompany transfers at market prices.

(3) U.S. dollar equivalent.

Refining and Marketing

Results of refining and marketing operations are presented below by geographic segment.

	Income (Loss)
	Three Months Ended September 30,					Nine Months Ended September 30,
	2002			2001		2002		2001
Refining and marketing
North America	$	(13.1	)	14.6		(34.4	)	67.5
United Kingdom		(.7	)	5.0		(1.1	)	8.8
Income (loss) before special items		(13.8	)	19.6		(35.5	)	76.3
Gain on sale of assets		—		—		—		67.6
Provision for environmental matters		—		(5.5	)	—		(5.5	)
Benefit from tax rate change		—		.1		—		.1
Total income (loss)	$	(13.8	)	14.2		(35.5	)	138.5

Refining and marketing operations in North America reported a loss of $13.1 million during the third quarter of 2002 compared to earnings of $14.6 million, before a special item, in the same period a year ago. The Company recorded a $5.5 million provision for environmental matters in the 2001 period. The Company’s U.S. refining margins were significantly lower in the current quarter compared to margins in the same quarter of 2001. North American petroleum product sales averaged 180,570 barrels a day in 2002, a slight increase from the third quarter of 2001. The United Kingdom reported a loss of $.7 million in the 2002 period compared to a profit of $5 million a year ago due to significant pressure on margins. Worldwide refinery inputs were 144,895 barrels a day in the third quarter of 2002 compared to 179,195 in the 2001 quarter. In response to extremely weak margins, the Company curtailed crude runs at its Meraux, Louisiana refinery for a portion of the 2002 quarter. Petroleum product sales were 212,757 barrels a day, down from 215,091 a year ago. The Company sold its Canadian pipeline and trucking operations in May 2001 resulting in a net gain of $67.6 million.

Refining and marketing operations in North America in the first nine months of 2002 reported a loss of $34.4 million compared to earnings of $67.5 million, before the previously mentioned special item in the 2001 period. U.S. refining margins were much weaker during most of the current period compared to the margins experienced a year ago. The 2002 results include a net gain of $3.5 million from sale of the Company’s interest in Butte Pipe Line. Results in the United Kingdom reflected a loss of $1.1 million in the nine months ended September 30, 2002 compared to earnings of $8.8 million in 2001 due to lower refinery margins compared to the same period a year ago.

14

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Selected operating statistics for the three-month and nine-month periods ended September 30, 2002 and 2001 follow.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2002	2001	2002	2001
Refinery inputs – barrels a day	144,895	179,195	153,552	176,928
North America	111,913	141,438	117,712	146,910
United Kingdom	32,982	37,757	35,840	30,018
Petroleum products sold – barrels a day	212,757	215,091	206,339	198,879
North America	180,570	179,114	172,568	170,789
Gasoline	117,840	98,554	109,208	92,699
Kerosine	3,900	7,022	5,628	9,481
Diesel and home heating oils	32,279	41,079	35,679	41,240
Residuals	11,849	16,349	13,067	17,386
Asphalt, LPG and other	14,702	16,110	8,986	9,983
United Kingdom	32,187	35,977	33,771	28,090
Gasoline	10,076	12,248	11,919	10,387
Kerosine	2,656	3,361	2,583	2,456
Diesel and home heating oils	13,866	13,955	14,333	9,972
Residuals	2,594	4,754	2,939	2,832
LPG and other	2,995	1,659	1,997	2,443

Corporate and other

The net costs of corporate activities, which include interest income and expense and corporate overhead not allocated to operating functions, was $4.7 million in the current quarter compared to $4.6 million in the 2001 quarter. In the first nine months of 2002, corporate activities reflected a net cost of $16.8 million compared to $9.7 million a year ago. The net costs in the nine-month 2002 period increased compared to the respective 2001 period primarily due to higher net interest expense resulting from increased average borrowings under long-term notes and less interest income from lower invested balances.

Financial Condition

Net cash provided by operating activities was $267.7 million for the first nine months of 2002 compared to $526.9 million for the same period in 2001. Changes in operating working capital other than cash and cash equivalents used cash of $118.2 million and $13.9 million in the first nine months of 2002 and 2001, respectively. Cash from operating activities was reduced by expenditures for refinery turnarounds and abandonment of oil and gas properties totaling $11.8 million in the current year and $14.1 million in 2001. Other predominant uses of cash in each year were for dividends, which totaled $52.6 million in 2002 and $50.8 million in 2001, and for capital expenditures, which including amounts expensed, are summarized in the following table.

	Nine Months Ended September 30,
	2002			2001
	(Millions of dollars)
Capital Expenditures
Exploration and production	$	464.1		514.5
Refining and marketing		175.0		110.3
Corporate and other		.6		5.2
Total capital expenditures		639.7		630.0
Geological, geophysical and other exploration expenses charged to income		(24.6	)	(42.3	)
Total property additions and dry holes	$	615.1		587.7

Working capital at September 30, 2002 was $192.6 million, $154 million higher than 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 LIFO accounting were $122.6 million below current costs at September 30, 2002.

15

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

At September 30, 2002, borrowings under long-term notes of $797.6 million were up $381.5 million from December 31, 2001 primarily due to issuance of $350 million of 6.375% notes in May 2002. The Company used a portion of the net proceeds to refinance outstanding indebtedness under existing credit facilities and used the remaining proceeds to fund ongoing capital projects and for other general purposes. Long-term nonrecourse debt of a subsidiary was $77.4 million, down $27.3 million from December 31, 2001, mainly due to repayments. A summary of capital employed at September 30, 2002 and December 31, 2001 follows.

	September 30, 2002			December 31, 2001
Capital Employed	Amount		%	Amount	%
	(Millions of dollars)
Notes payable	$	797.6	33	416.1	21
Nonrecourse debt of a subsidiary		77.4	3	104.7	5
Stockholders’ equity		1,549.8	64	1,498.2	74
	$	2,424.8	100	2,019.0	100

Accounting 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 or Disposal of Long-Lived Assets effective, January 1, 2002.

Other Matters

Murphy holds a 20% interest in Block 16 Ecuador, where the Company and its partners produce oil for export. In 2001, the local tax authorities announced that Value Added Taxes (VAT) paid on goods and services related to Block 16 and many oil fields held by other oil companies will no longer be reimbursed. In response to this announcement, oil producers have filed actions in the Ecuador Tax Court seeking determination that the VAT in question is reimbursable. As of September 30, 2002, the Company has a receivable of approximately $6 million related to VAT. Murphy believes that its claim for reimbursement of VAT under applicable Ecuador tax law is valid, and it does not expect that the resolution of this matter will have a material adverse affect on the Company’s financial position.

Outlook

For the fourth quarter of 2002, the Company expects worldwide production to average approximately 122,000 barrels of oil equivalent a day, with production anticipated at about 125,000 per day for the full year 2002. Although production at Terra Nova and Hibernia are near their peak after downtime for maintenance in the third quarter, the effect of tropical storms in the Gulf of Mexico are expected to reduce production in the fourth quarter by approximately 2,000 barrels of oil equivalents a day. In October 2002, the Company’s U.S. refining margins improved slightly.

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.

16

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company was a party to interest rate swaps at September 30, 2002 with notional amounts totaling $50 million that were designed to hedge fluctuations in cash flows of a similar amount of variable-rate debt. These swaps mature in 2004. The swaps require the Company to pay an average interest rate of 6.17% over their composite lives, and at September 30, 2002, the interest rate to be received by the Company averaged 1.83%. 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 $4.1 million at September 30, 2002.

At September 30, 2002, 20% of the Company’s debt had variable interest rates and 4.9% was denominated in Canadian dollars. Based on debt outstanding at September 30, 2002, a 10% increase in variable interest rates would increase the Company’s interest expense approximately $.2 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 $.8 million for debt denominated in Canadian dollars.

Murphy was a party to natural gas price swap agreements at September 30, 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 a portion of natural gas to be purchased for fuel during 2004 through 2006. In each month of settlement, the swaps require Murphy to pay an average natural gas price of $2.78 per MMBTU and to receive the average NYMEX price for the final three trading days of the month. At September 30, 2002, the estimated fair value of these agreements was recorded as an asset of $9.2 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $3.3 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 September 30, 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 in October 2002. The swaps are for a combined notional volume that averages 47,700 MMBTU equivalents a day in October 2002 and require Murphy to pay the average relevant index price for October and receive an average price of $3.38 per MMBTU. The collars are for a combined notional volume of 48,000 MMBTU equivalents a day and based upon the relevant index prices provide Murphy with an average floor price of $2.73 per MMBTU and an average ceiling price of $4.88 per MMBTU. At September 30, 2002, the estimated fair value of these agreements was recorded as an asset of $.2 million, which will be recorded in income in October 2002. A 10% increase or decrease in the average index price of natural gas would not have a significant effect on the recorded amount.

ITEM 4.    CONTROLS AND PROCEDURES

Company management, including the Principal Executive Officer and Principal Financial Officer, have evaluated the effectiveness of disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based on that evaluation, these officers have concluded that the disclosure controls and procedures are effective in ensuring that all material information required to be filed in this quarterly report has been made known to them in a timely fashion. There have been no significant changes in internal controls, or in factors that could significantly affect internal controls, subsequent to the date the evaluation was completed.

17

OIL AND GAS OPERATING RESULTS¹ (unaudited)

	United States			Canada	United Kingdom	Ecuador	Malaysia		Other		Synthetic Oil– Canada	Total
	(Millions of dollars)
Three Months Ended September 30, 2002
Oil and gas sales, other operating revenues	$	38.7		86.8	38.8	11.5	—		.4		32.9	209.1
Production expenses		11.9		18.5	6.7	4.2	—		—		12.1	53.4
Depreciation, depletion and amortization		9.9		31.9	8.3	1.7	.2		.1		2.3	54.4
Exploration expenses
Dry holes		3.3		.9	3.2	—	(1.8	)	—		—	5.6
Geological and geophysical		1.7		1.4	—	—	.4		.2		—	3.7
Other		1.2		.6	.2	—	.1		.1		—	2.2
		6.2		2.9	3.4	—	(1.3	)	.3		—	11.5
Undeveloped lease amortization		2.7		3.4	—		—		—		—	6.1
Total exploration expenses		8.9		6.3	3.4	—	(1.3	)	.3		—	17.6
Selling and general expenses		3.4		3.7	.8	.2	—		1.7		.1	9.9
Income tax provisions (benefits)		1.5		10.4	8.4	—	—		(.5	)	6.0	25.8
Results of operations (excluding corporate overhead and interest)	$	3.1		16.0	11.2	5.4	1.1		(1.2	)	12.4	48.0
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	.1		.1		2.0	46.4
Goodwill		—		.8	—	—	—		—		—	.8
Exploration expenses
Dry holes		8.0		11.3	—	—	—		(.3	)	—	19.0
Geological and geophysical		1.7		.7	—	—	14.2		(.5	)	—	16.1
Other		1.0		.4	.3	—	2.1		.2		—	4.0
		10.7		12.4	.3	—	16.3		(.6	)	—	39.1
Undeveloped lease amortization		2.9		3.5	—	—	—		—		—	6.4
Total exploration expenses		13.6		15.9	.3	—	16.3		(.6	)	—	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	(16.4	)	(.4	)	5.4	26.7
Nine Months Ended September 30, 2002
Oil and gas sales, other operating revenues	$	115.1		346.5	123.3	25.0	—		1.5		75.5	686.9
Production expenses		40.1		64.0	26.5	10.6	—		—		36.1	177.3
Depreciation, depletion and amortization		29.7		116.7	26.2	4.3	.7		.2		6.5	184.3
Exploration expenses
Dry holes		25.8		14.3	3.2	—	35.1		—		—	78.4
Geological and geophysical		5.0		10.5	—	—	1.0		.2		—	16.7
Other		3.4		1.6	.7	—	2.2		—		—	7.9
		34.2		26.4	3.9	—	38.3		.2		—	103.0
Undeveloped lease amortization		7.9		10.5	—	—	—		—		—	18.4
Total exploration expenses		42.1		36.9	3.9	—	38.3		.2		—	121.4
Selling and general expenses		9.5		10.6	2.4	.6	—		4.3		.2	27.6
Income tax provisions (benefits)		(2.7	)	40.1	30.7	—	—		(.8	)	10.7	78.0
Results of operations (excluding
corporate overhead and interest)	$	(3.6	)	78.2	33.6	9.5	(39.0	)	(2.4	)	22.0	98.3
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	.3		.2		6.2	135.8
Goodwill		—		2.4	—	—	—		—		—	2.4
Exploration expenses
Dry holes		23.7		34.5	.1	—	3.8		3.5		—	65.6
Geological and geophysical		5.4		9.7	.1	—	17.1		.1		—	32.4
Other		2.4		1.7	.8	—	4.2		.8		—	9.9
		31.5		45.9	1.0	—	25.1		4.4		—	107.9
Undeveloped lease amortization		7.0		10.2	—	—	—		–		—	17.2
Total exploration expenses		38.5		56.1	1.0	—	25.1		4.4		—	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	(25.4	)	(7.4	)	15.7	167.9

¹ Excludes special items.

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PART II – OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

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. 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.

On March 5, 2002, two of the Company’s subsidiaries filed suit against Enron Canada Corp. (“Enron”) to collect approximately $2.1 million owed to Murphy under canceled gas sales contracts. On May 1, 2002, Enron counterclaimed for approximately $19.8 million allegedly owed by Murphy under those same agreements. Although the lawsuit, in the Court of Queen’s Bench, Alberta, is in its early stages and no assurance can be given, the Company does not believe that the Enron counterclaim is meritorious and does not believe that the ultimate resolution of this matter 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 23 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

(b) A report on Form 8-K was filed on August 5, 2002 that included the Company’s Principal Executive Officer and Principal Financial Officer sworn statements pursuant to Securities and Exchange Commission Order No. 4-460.

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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 8, 2002

        (Date)

20

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Claiborne P. Deming, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Murphy Oil Corporation;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 8, 2002

/s/ Claiborne P. Deming            

Claiborne P. Deming

Principal Executive Officer

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CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Steven A. Cossé, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Murphy Oil Corporation;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: November 8, 2002

/s/ Steven A. Cossé            

Steven A. Cossé

Principal Financial Officer

22

EXHIBIT INDEX

Exhibit No.		Incorporated by Reference to
3.1	Certificate of Incorporation of Murphy Oil Corporation as amended, effective May 17, 2001	Exhibit 3.1 of Murphy’s Form 10-Q report for the quarterly period ended June 30, 2001
3.2	By-Laws of Murphy Oil Corporation as amended effective May 8, 2002	Exhibit 3.2 of Murphy’s Form 10-Q report for the quarterly period ended June 30, 2002
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 Second Supplemental Indenture between Murphy Oil Corporation and SunTrust Bank, as Trustee	Exhibit 4.1 of Murphy’s Form 8-K report filed May 3, 2002 under the Securities Exchange Act of 1934
4.2	Form of Indenture and Form of Supplemental Indenture between Murphy Oil Corporation and SunTrust Bank, as Trustee	Exhibits 4.1 and 4.2 of Murphy’s Form 8-K report filed April 29, 1999 under the Securities Exchange Act of 1934
4.3	Rights Agreement dated as of December 6, 1989 between Murphy Oil Corporation and Harris Trust Company of New York, as Rights Agent	Exhibit 4.3 of Murphy’s Form 10-K report for the year ended December 31, 1999
4.4	Amendment No. 1 dated as of April 6, 1998 to Rights Agreement dated as of December 6, 1989 between Murphy Oil Corporation and Harris Trust Company of New York, as Rights Agent	Exhibit 3 of Murphy’s Form 8-A/A, Amendment No. 1, filed April 14, 1998 under the Securities Exchange Act of 1934
4.5	Amendment No. 2 dated as of April 15, 1999 to Rights Agreement dated as of December 6, 1989 between Murphy Oil Corporation and Harris Trust Company of New York, as Rights Agent	Exhibit 4 of Murphy’s Form 8-A/A, Amendment No. 2, filed April 19, 1999 under the Securities Exchange Act of 1934
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
99.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Exhibit 99.1 filed herewith
99.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Exhibit 99.2 filed herewith

Exhibits other than those listed above have been omitted since they are either not required or not applicable.

23