Murphy Oil (MUR) 10-Q 2002 Q2 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 June 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 (State or other jurisdiction of incorporation or organization) 71-0361522 (I.R.S. Employer Identification Number)

200 Peach Street P. O. Box 7000, El Dorado, Arkansas (Address of principal executive offices) 71731-7000 (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.  þ  Yes  ¨  No

Number of shares of Common Stock, $1.00 par value, outstanding at June 30, 2002, was45,816,063.

PART I—FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)

	(Unaudited)
	June 30, 2002			December 31, 2001
ASSETS
Current Assets
Cash and cash equivalents	$	140,986		82,652
Accounts receivable, less allowance for doubtful accounts of $11,487 in 2002 and $11,263 in 2001		383,660		262,022
Inventories
Crude oil and blend stocks		96,923		38,917
Finished products		100,466		85,133
Materials and supplies		60,061		49,098
Prepaid expenses		76,443		61,062
Deferred income taxes		20,466		19,777
Total current assets		879,005		598,661
Property, plant and equipment, at cost less accumulated depreciation and amortization of $3,425,548 in 2002 and $3,277,673 in 2001		2,754,150		2,525,807
Goodwill, net		52,908		50,412
Deferred charges and other assets		92,493		84,219
Total assets	$	3,778,556		3,259,099
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	50,441		48,250
Accounts payable and accrued liabilities		584,799		463,429
Income taxes		52,656		48,378
Total current liabilities		687,896		560,057
Notes payable		712,845		416,061
Nonrecourse debt of a subsidiary		92,456		104,724
Deferred income taxes		329,432		302,868
Accrued dismantlement costs		169,569		160,764
Accrued major repair costs		46,416		44,570
Deferred credits and other liabilities		168,504		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		547,098		527,126
Retained earnings		1,078,797		1,096,567
Accumulated other comprehensive loss		(25,649	)	(83,309	)
Unamortized restricted stock awards		(231	)	(968	)
Treasury stock, 2,959,251 shares of Common Stock in 2002, 3,444,234 shares in 2001, at cost		(77,352	)	(90,028	)
Total stockholders’ equity		1,571,438		1,498,163
Total liabilities and stockholders’ equity	$	3,778,556		3,259,099

See Notes to Consolidated Financial Statements, page 5.

The Exhibit Index is on page 20.

1

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars, except per share amounts)

	Three Months Ended June 30,					Six Months Ended June 30,
	2002			2001		2002		2001
REVENUES
Crude oil and natural gas sales	$	259,873		232,952		454,806		470,151
Petroleum product sales		734,680		778,071		1,258,410		1,450,302
Crude oil trading sales		90,889		157,866		154,109		396,326
Other operating revenues		48,276		128,145		95,293		165,950
Interest and other nonoperating revenues		999		3,345		2,002		7,035
Total revenues		1,134,717		1,300,379		1,964,620		2,489,764
COSTS AND EXPENSES
Crude oil, products and related operating expenses		914,394		922,413		1,600,476		1,835,624
Exploration expenses, including undeveloped lease amortization		61,767		41,589		103,788		79,550
Selling and general expenses		23,129		24,983		45,491		46,029
Depreciation, depletion and amortization		84,682		58,256		155,371		112,488
Amortization of goodwill		—		785		— ��		1,573
Interest expense		13,287		9,702		22,829		19,446
Interest capitalized		(4,607	)	(4,333	)	(9,424	)	(7,919	)
Total costs and expenses		1,092,652		1,053,395		1,918,531		2,086,791
Income before income taxes		42,065		246,984		46,089		402,973
Income tax expense		28,136		84,416		29,626		142,569
NET INCOME	$	13,929		162,568		16,463		260,404
NET INCOME PER COMMON SHARE
Basic	$	.30		3.60		.36		5.77
Diluted	$	.30		3.56		.36		5.72
Average Common shares outstanding
Basic		45,784,073		45,206,604		45,635,493		45,139,453
Diluted		46,133,432		45,644,457		46,029,510		45,490,094

See Notes to Consolidated Financial Statements, page 5.

2

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)

	Three Months Ended June 30,				Six Months Ended June 30,
	2002		2001		2002		2001
Net income	$	13,929	162,568		16,463		260,404
Other comprehensive income (loss), net of tax
Cash flow hedges
Net derivative gains		4,675	1,454		7,622		2,053
Reclassification adjustments		945	(232	)	(2,378	)	1,346
Total cash flow hedges		5,620	1,222		5,244		3,399
Net gain (loss) from foreign currency translation		57,412	29,571		52,416		(21,868	)
Other comprehensive income (loss) before cumulative effect of accounting change		63,032	30,793		57,660		(18,469	)
Cumulative effect of accounting change (Note B)		—	—		—		6,642
Other comprehensive income (loss)		63,032	30,793		57,660		(11,827	)
COMPREHENSIVE INCOME	$	76,961	193,361		74,123		248,577

See Notes to Consolidated Financial Statements, page 5.

3

MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)

	Six Months Ended June 30,
	2002			2001
OPERATING ACTIVITIES
Net income	$	16,463		260,404
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		155,371		112,488
Provisions for major repairs		9,332		11,051
Expenditures for major repairs		(9,805	)	(9,861	)
Dry holes		72,844		46,572
Amortization of undeveloped leases		12,267		10,852
Amortization of goodwill		—		1,573
Deferred and noncurrent income tax charges		11,215		41,491
Pretax gains from disposition of assets		(5,700	)	(95,246	)
Net increase in operating working capital other than cash and cash equivalents		(96,364	)	(35,852	)
Other operating activities—net		5,349		8,447
Net cash provided by operating activities		170,972		351,919
INVESTING ACTIVITIES
Property additions and dry holes		(416,239	)	(393,823	)
Proceeds from sale of assets		28,648		159,079
Other investing activities—net		2		(258	)
Net cash required by investing activities		(387,589	)	(235,002	)
FINANCING ACTIVITIES
Increase (decrease) in notes payable		298,112		(9,714	)
Decrease in nonrecourse debt of a subsidiary		(13,629	)	(7,201	)
Cash dividend paid		(34,233	)	(33,835	)
Proceeds from exercise of stock options and employee stock purchase plan		23,024		14,333
Other financing activities—net		(2,526	)	(2,000	)
Net cash provided (required) by financing activities		270,748		(38,417	)
Effect of exchange rate changes on cash and cash equivalents		4,203		(5,234	)
Net increase in cash and cash equivalents		58,334		73,266
Cash and cash equivalents at January 1		82,652		132,701
Cash and cash equivalents at June 30	$	140,986		205,967
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid	$	10,916		79,828
Interest paid, net of amounts capitalized		9,082		7,908

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.

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 six months ended June 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 June 30, 2002 was $52.9 million. The change in the carrying amount of goodwill for the period ended June 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 six-month period ended June 30, 2001, excluding goodwill amortization of $1.6 million ($.03 basic and diluted earnings per share), was $262 million. Adjusted basic and diluted earnings per share for the six-month period ended June 30, 2001 were $5.80 and $5.76, 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.

5

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B—New Accounting Principles (Contd.)

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 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 increased AOCL for the six months ended June 30, 2002 and 2001 by $5.2 million and $3.4 million, net of $3.6 million and $2.7 million in income taxes, and increased income by an insignificant amount for the same periods, but did not affect income per diluted share. For the six months ended June 30, 2002, gains of $2.4 million, net of $1.4 million in taxes, were reclassified from AOCL to earnings. In the first six months of 2001, losses of $1.3 million, net of $1.2 million in taxes, 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, 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 refinery waste site. 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.

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 June 30, 2002.

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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 June 30, 2002 the Company had contingent liabilities of $34.5 million under certain financial guarantees and $31.4 million on outstanding letters of credit.

Note E—Earnings per Share

Net income was used as the numerator in computing both basic and diluted income per Common share for the three-month and six-month periods ended June 30, 2002 and 2001. The following table reconciles the weighted-average shares outstanding used for these computations.

	Three Months Ended June 30,		Six Months Ended June 30,
	2002	2001	2002	2001
	(Weighted-average shares)
Reconciliation of Shares Outstanding
Basic method	45,784,073	45,206,604	45,635,493	45,139,453
Dilutive stock options	349,359	437,853	394,017	350,641
Diluted method	46,133,432	45,644,457	46,029,510	45,490,094

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 June 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 2.02% at June 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 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 June 30, 2002 and 2001, the income effect from cash

7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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 June 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 from July 2002 to 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 each month 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 June 30, 2002, Murphy’s earnings were increased by $.3 million from recognition of the ineffective portions of cash flow hedging arising from the natural gas swaps and collars in the United States and western Canada. Murphy’s earnings in the 2001 period were not significantly affected by cash flow hedging ineffectiveness.

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 six-month period ended June 30, 2002, pretax gains of $3.6 million were reclassified from AOCL into earnings. No gains were reclassified into earnings in the second quarter of 2002 or in the six-month period ended June 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 $4 million in after-tax gains 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 June 30, 2002 and December 31, 2001 were as follows.

	June 30, 2002			December 31, 2001
	(Millions of dollars)
Foreign currency translation loss, net	$	(35.4	)	(87.8	)
Cash flow hedge gains, net		9.8		4.5
Accumulated other comprehensive loss	$	(25.6	)	(83.3	)

Note H—Financing Arrangements

In May 2002, the Company sold $350 million of 6.375 percent coupon 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 will use the remaining proceeds to fund ongoing capital projects and for other general purposes.

Note I—Property, Plant and Equipment

During May, the Company and the U.S. government reached an agreement in principle where the U.S. government will pay 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. There will be no gain or loss recorded in connection with the agreement, and after receipt of the proceeds, Murphy will have 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 June 30, 2002		Three Months Ended June 30, 2002				Three Months Ended June 30, 2001
			External Revenues	Intersegment Revenues	Income (Loss)		External Revenues	Intersegment Revenues	Income (Loss)
	(Millions of dollars)
Exploration and production*
United States	$	644.5	30.7	12.7	(4.1	)	53.2	13.7	24.6
Canada		1,340.9	181.7	—	54.0		119.3	9.1	23.8
United Kingdom		239.9	39.0	—	9.2		51.2	—	21.4
Ecuador		76.5	7.9	—	3.3		10.2	—	4.3
Malaysia		41.6	—	—	(32.1	)	—	—	(7.8	)
Other international		7.9	.5	—	(.7	)	.4	—	(5.7	)
Total		2,351.3	259.8	12.7	29.6		234.3	22.8	60.6
Refining and marketing
United States		955.5	773.9	—	(9.8	)	838.7	—	34.3
United Kingdom		205.2	100.0	—	1.8		83.7	—	2.0
Canada		1.1	—	—	—		140.4	.1	68.4
Total		1,161.8	873.9	—	(8.0	)	1,062.8	.1	104.7
Total operating segments		3,513.1	1,133.7	12.7	21.6		1,297.1	22.9	165.3
Corporate and other		265.5	1.0	—	(7.6	)	3.3	—	(2.7	)
Total consolidated	$	3,778.6	1,134.7	12.7	14.0		1,300.4	22.9	162.6

	Six Months Ended June 30, 2002					Six Months Ended June 30, 2001
	External Revenues		Intersegment Revenues	Income (Loss)		External Revenues	Intersegment Revenues	Income (Loss)
	(Millions of dollars)
Exploration and production*
United States	$	53.8	22.6	(6.7	)	132.6	30.9	55.7
Canada		302.3	—	71.8		219.0	30.0	51.9
United Kingdom		84.5	—	22.4		101.5	—	41.5
Ecuador		13.5	—	4.1		20.3	—	8.1
Malaysia		—	—	(40.1	)	—	—	(9.0	)
Other international		1.1	—	(1.2	)	.9	—	(7.0	)
Total		455.2	22.6	50.3		474.3	60.9	141.2
Refining and marketing
United States		1,322.3	—	(21.3	)	1,544.9	—	49.3
United Kingdom		185.1	—	(.4	)	162.2	—	3.8
Canada		—	—	—		301.4	.2	71.2
Total		1,507.4	—	(21.7	)	2,008.5	.2	124.3
Total operating segments		1,962.6	22.6	28.6		2,482.8	61.1	265.5
Corporate and other		2.0	—	(12.1	)	7.0	—	(5.1	)
Total consolidated	$	1,964.6	22.6	16.5		2,489.8	61.1	260.4

* Additional details about results of operations are presented in the tables on page 17.

10

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

Results of Operations

Murphy’s net income in the second quarter of 2002 totaled $14 million, $.30 a diluted share, compared to income of $95 million, $2.08 a diluted share, before a special item in the second quarter a year ago. Net income for the second quarter of 2001 totaled $162.6 million, $3.56 a diluted share, and included a gain on sale of Canadian pipeline assets of $67.6 million, $1.48 a diluted share.

In the current quarter, the Company’s exploration and production operations earned $29.6 million, a decrease of $31 million from $60.6 million earned in the 2001 period. The decline in income was primarily the result of significantly lower North American natural gas sales prices and higher exploration expenses partially offset by higher oil and gas sales volumes. The Company’s refining and marketing operations incurred a loss of $8 million in the 2002 period compared to earnings of $37.1 million before special items for the three months ended June 30, 2001. Due to negative margins throughout much of the period, Murphy’s U.S. operations lost $9.8 million in the just completed quarter compared to a profit of $34.3 million in the same quarter a year ago.

For the first six months of 2002, net income totaled $16.5 million, $.36 a diluted share, compared to income of $192.8 million, $4.24 a diluted share, before a special item for the first half of 2001. Net income a year ago was $260.4 million, $5.72 a diluted share, including an after-tax benefit of $67.6 million, $1.48 a diluted share, from the sale of the Company’s pipeline assets in Canada.

Exploration and production earnings in the first six months of 2002 were down $90.9 million from the prior year, mainly due to decreases in North American natural gas sales prices and higher exploration expenses, partially offset by record crude oil and natural gas sales volumes. The Company’s refining and marketing operations incurred a loss of $21.7 million in the first half of 2002 compared to earnings of $56.7 million before a special item in the 2001 period. U.S. refining margins were significantly lower in the 2002 period compared to a year ago.

The Company’s worldwide effective tax rate is significantly higher than the expected tax rate primarily because no tax benefit has been recorded for exploration expenses incurred in Malaysia.

Exploration and Production

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

	Income (Loss)
	Three Months Ended June 30,					Six Months Ended June 30,
	2002			2001		2002		2001
	(Millions of dollars)
Exploration and production
United States	$	(4.1	)	24.6		(6.7	)	55.7
Canada		54.0		23.8		71.8		51.9
United Kingdom		9.2		21.4		22.4		41.5
Ecuador		3.3		4.3		4.1		8.1
Malaysia		(32.1	)	(7.8	)	(40.1	)	(9.0	)
Other International		(.7	)	(5.7	)	(1.2	)	(7.0	)
Total	$	29.6		60.6		50.3		141.2

Exploration and production operations in the United States reported a loss of $4.1 million in the second quarter of 2002 compared to earnings of $24.6 million a year ago. This decline was primarily due to lower sales prices for natural gas and oil, lower oil and natural gas sales volumes, and a $19.9 million increase in exploration expenses. Sales of natural gas averaged 99 million cubic feet a day, down from 119 million in the second quarter of 2001 due to lower production in the Gulf of Mexico. U.S. production expenses were up $1.6 million or 13%, primarily because of higher well workover costs.

Operations in the United States for the six months ended June 30, 2002 reflected a loss of $6.7 million compared to earnings of $55.7 million from 2001. The decrease was primarily 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.

11

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

Results of Operations (Contd.)

Exploration and Production(Contd.)

Operations in Canada earned $54 million this quarter compared to $23.8 million a year ago as record production of oil and natural gas were offset by declines in average oil and natural gas sales prices. Also exploration expenses in the 2002 period declined $19.2 million from a year ago. Oil and gas liquids sales in Canada averaged 55,916 barrels a day, an increase of 50% over the prior year, primarily because of higher sales volumes at Hibernia and initial production and sales from the Terra Nova field in 2002, partially offset by a lower production at Syncrude due to maintenance activities. Canadian natural gas sales averaged 231 million cubic feet a day in the current quarter, up 52%, with the increase primarily attributable to higher production from the Ladyfern field. Higher oil and gas sales volumes caused a $7.2 million increase in Canadian production expenses in the 2002 quarter over the 2001 period.

In the first half of 2002, Canada operations earned $71.8 million compared to $51.9 million a year ago. Higher sales volumes for oil and natural gas were offset by declines in average oil and natural gas sales prices. Exploration expenses also declined $9.6 million versus 2001.

U.K. operations earned $9.2 million in the current quarter, down from $21.4 million in the prior year. Revenues from sales of oil and gas liquids in the United Kingdom decreased 16% primarily due to the timing of liftings and lower sales prices for U.K. crude oil. Income for the 2002 six-month period was $22.4 million compared to $41.5 million a year ago. The decline was primarily due to lower sales prices for U.K. crude oil, higher production 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. Based on current Company estimates, the net effect of these changes is expected to reduce U.K. income during the last half of 2002 by approximately $4 million.

Operations in Ecuador earned $3.3 million in the second quarter of 2002 compared to $4.3 million a year ago, while Malaysia and other international operations reported losses of $32.1 million and $.7 million, respectively, compared to losses of $7.8 million and $5.7 million in 2001. The higher loss in Malaysia in the current period was primarily due to dry holes costs associated with two unsuccessful deepwater wells in Block K. The higher loss in other international operations in the 2001 period was the result of an unsuccessful well offshore Ireland. Crude oil sales in Ecuador decreased 29% which more than offset an increase in the average sales price. Sales volumes in Ecuador were adversely affected by pipeline restrictions. Production expenses in Ecuador decreased by $.9 million in the 2002 period.

For the first six months of 2002, earnings in Ecuador were $4.1 million compared to $8.1 million for the 2001 period, while Malaysia and other international operations reported losses of $40.1 million and $1.2 million, respectively, compared to losses of $9 million and $7 million a year ago. Sales volumes in Ecuador decreased 31% in the first half of 2002 due to pipeline capacity restrictions. The higher loss in Malaysia was primarily due to the previously mentioned dry holes.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $23.88 a barrel in the current quarter, an increase of 4% from the average of $22.97 in the 2001 period. The increase in the average price in 2002 versus 2001 was due to much stronger heavy oil prices in the 2002 period. Average crude oil and liquids production was a quarterly record of 78,050 barrels a day, up 20% over last year, while average sales volumes increased 19% to 83,313 barrels a day due to initial production and sales from Terra Nova. North American natural gas sales prices averaged $3.03 per MCF in the second quarter compared to $4.33 per MCF in the same quarter of 2001. Total natural gas sales volumes were also a Company record and averaged 336 million cubic feet a day in 2002, up 18% from the 2001 quarter. The tables on page 17 provide additional details of the results of exploration and production operations for the first half of each year.

12

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

Results of Operations (Contd.)

Exploration and Production(Contd.)

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

	Three Months Ended June 30,			Six Months Ended June 30,
	2002		2001	2002	2001
Net crude oil, condensate and gas liquids produced—barrels per day		78,050	64,913	76,181	66,973
United States		5,768	6,033	5,975	5,770
Canada—light		3,107	4,314	3,585	4,448
—heavy		9,469	11,647	9,595	12,320
—offshore		26,317	8,980	23,057	8,967
—synthetic		8,828	9,254	10,078	9,800
United Kingdom		19,796	19,242	19,415	20,029
Ecuador		4,765	5,443	4,476	5,639
Net crude oil, condensate and gas liquids sold—barrels per day		83,313	69,932	81,769	67,855
United States		5,768	6,033	5,975	5,770
Canada—light		3,107	4,314	3,585	4,448
—heavy		9,469	11,647	9,595	12,320
—offshore		34,512	12,030	28,010	9,606
—synthetic		8,828	9,254	10,078	9,800
United Kingdom		17,348	20,650	20,282	19,734
Ecuador		4,281	6,004	4,244	6,177
Net natural gas sold—thousands of cubic feet per day		335,954	283,979	322,696	266,486
United States		99,312	119,150	100,297	121,981
Canada		231,154	152,469	215,408	129,366
United Kingdom		5,488	12,360	6,991	15,139
Total net hydrocarbons produced—equivalent barrels per day(1)		134,042	112,243	129,964	111,387
Total net hydrocarbons sold—equivalent barrels per day(1)		139,305	117,262	135,552	112,269
Weighted average sales prices Crude oil and condensate—dollars a barrel(2)
United States	$	24.84	25.52	22.48	26.45
Canada(3)—light		24.67	24.52	20.41	24.75
—heavy		17.49	10.86	15.42	10.11
—offshore		25.47	26.76	24.13	26.84
—synthetic		26.06	27.55	23.36	27.88
United Kingdom		23.56	25.91	22.03	26.47
Ecuador		20.54	18.63	17.74	18.18
Natural gas—dollars a thousand cubic feet
United States(2)	$	3.46	4.89	3.03	6.07
Canada(3)		2.85	3.89	2.52	4.67
United Kingdom(3)		2.84	2.26	2.91	2.42

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

(2) Includes intracompany transfers at market prices.

(3) U.S. dollar equivalent.

13

ITEM2.    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 June 30,				Six Months Ended June 30,
	2002			2001	2002		2001
	(Millions of dollars)
Refining and marketing
United States	$	(9.8	)	34.3	(21.3	)	49.3
United Kingdom		1.8		2.0	(.4	)	3.8
Canada		—		.8	—		3.6
Income (loss) before special items		(8.0	)	37.1	(21.7	)	56.7
Gain on sale of assets		—		67.6	—		67.6
Total income (loss)	$	(8.0	)	104.7	(21.7	)	124.3

Refining and marketing operations in the United States reported a loss of $9.8 million during the second quarter of 2002 compared to earnings of $34.3 million in the same period a year ago. The Company’s U.S. refining margins were significantly lower in the current quarter compared to margins in the same quarter of 2001. U.S. petroleum product sales averaged 179,376 barrels a day in 2002, a 6.4% increase from the second quarter of 2001. Earnings in the United Kingdom were $1.8 million in the 2002 period compared to $2 million a year ago. Worldwide refinery inputs were 161,363 barrels a day in the second quarter of 2002 compared to 172,890 in the 2001 quarter, and petroleum product sales were 214,708 barrels a day, up from 192,167 a year ago. U.S. refinery inputs were significantly lower in the 2002 period due to unscheduled outages of FCC units at the Meraux refinery. Earnings from purchasing, transporting and reselling crude oil in Canada were $.8 million in the 2001 quarter. The Company sold its Canadian pipeline and trucking operations in May 2001 resulting in a net gain of $67.6 million.

Refinery and marketing operations in the United States in the first half of 2002 reported a loss of $21.3 million compared to earnings of $49.3 million in the 2001 period. U.S. refining margins were negative during much of the current period compared to the positive 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 $.4 million in the six months ended June 30, 2002 compared to earnings of $3.8 million in 2001 due to lower refinery margins compared to the same period a year ago. Prior to the sale in the second quarter 2001, the Company earned $3.6 million from purchasing, transporting and reselling crude oil in Canada.

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2002	2001	2002	2001
Refinery inputs—barrels a day	161,363	172,890	157,952	175,777
United States	123,568	147,751	120,660	149,692
United Kingdom	37,795	25,139	37,292	26,085
Petroleum products sold—barrels a day	214,708	192,167	203,079	190,643
United States	179,376	168,537	168,501	166,559
Gasoline	112,651	93,102	104,821	89,723
Kerosine	4,582	9,101	6,505	10,731
Diesel and home heating oils	39,071	39,958	37,407	41,322
Residuals	14,323	17,948	13,687	17,914
Asphalt, LPG and other	8,749	8,428	6,081	6,869
United Kingdom	35,332	23,630	34,578	24,084
Gasoline	12,865	9,502	12,856	9,440
Kerosine	2,438	1,418	2,546	1,997
Diesel and home heating oils	15,276	8,484	14,570	7,947
Residuals	3,412	1,196	3,116	1,857
LPG and other	1,341	3,030	1,490	2,843

14

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Corporate and other

The net costs of corporate activities, which include interest income and expense and corporate overhead not allocated to operating functions, was $7.6 million in the current quarter compared to $2.7 million in the 2001 quarter. In the first six months of 2002, corporate activities reflected a net cost of $12.1 million compared to $5.1 million a year ago. The net costs in both the 2002 periods increased compared to the respective 2001 period due to a decrease in interest income earned caused by lower levels of invested cash balances coupled with higher net interest expense due to increased long-term borrowings.

Financial Condition

Net cash provided by operating activities was $171 million for the first six months of 2002 compared to $351.9 million for the same period in 2001. Changes in operating working capital other than cash and cash equivalents used cash of $96.4 million and $35.9 million in the first six 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 $9.8 million in the current year and $9.9 million in 2001. Other predominant uses of cash in each year were for capital expenditures, which including amounts expensed, are summarized in the following table, and for dividends, which totaled $34.2 million in 2002 and $33.8 in 2001.

	Six Months Ended June 30,
	2002			2001
	(Millions of dollars)
Capital Expenditures
Exploration and production	$	325.3		344.9
Refining and marketing		109.1		67.0
Corporate and other		.5		4.1
Total capital expenditures		434.9		416.0
Geological, geophysical and other exploration expenses charged to income		(18.7	)	(22.2	)
Total property additions and dry holes	$	416.2		393.8

Working capital at June 30, 2002 was $191.1 million, up $152.5 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 LIFO accounting were $109.7 million below current costs at June 30, 2002.

At June 30, 2002, long-term notes payable of $712.8 million were up $296.7 million from December 31, 2001 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 will use the remaining proceeds to fund ongoing capital projects and for other general purposes. Long-term nonrecourse debt of a subsidiary was $92.5 million, down $12.2 million from December 31, 2001, primarily due to repayments. A summary of capital employed at June 30, 2002 and December 31, 2001 follows.

	June 30, 2002			December 31, 2001
	Amount		%	Amount	%
	(Millions of dollars)
Capital Employed
Notes payable	$	712.8	30	416.1	21
Nonrecourse debt of a subsidiary		92.5	4	104.7	5
Stockholders’ equity		1,571.4	66	1,498.2	74
	$	2,376.7	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 of Disposal of Long-Lived Assets effective, January 1, 2002.

15

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Outlook

For the third quarter of 2002, the Company expects worldwide production to average approximately 117,000 barrels of oil equivalent a day, with lower volumes due to downtime for routine maintenance at Hibernia, Terra Nova and North Sea fields, and expected production decline at the Ladyfern field. Sales volumes are projected to average approximately 111,000 barrels of oil equivalent per day. In July 2002, the Company’s U.S. refining and marketing operations were experiencing losses due to negative refining margins.

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.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company was a party to interest rate swaps at June 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 June 30, 2002, the interest rate to be received by the Company averaged 2.02%. 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 $3.2 million at June 30, 2002.

At June 30, 2002, 12% of the Company’s debt had variable interest rates and 4.6% was denominated in Canadian dollars. Based on debt outstanding at June 30, 2002, a 10% increase in variable interest rates would increase the Company’s interest expense approximately $.1 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 June 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 an MMBTU and to receive the average NYMEX price for the final three trading days of the month. At June 30, 2002, the estimated fair value of these agreements was recorded as an asset of $9.8 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $3.2 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 June 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 through October 2002. The swaps are for a combined notional volume that averages 47,700 MMBTU equivalents a day through October 2002 and require Murphy to pay the average relevant index price for each month 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 June 30, 2002, the estimated fair value of these agreements was recorded as an asset of $7.4 million. A 10% increase in the average index price of natural gas would have reduced this asset by $2.9 million, while a 10% decrease would have increased the asset by a similar amount.

16

OIL AND GAS OPERATING RESULTS (unaudited)

	United States			Canada	United Kingdom	Ecuador	Malaysia		Other		Synthetic Oil- Canada	Total
	(Millions of dollars)
Three Months Ended June 30, 2002
Oil and gas sales, other operating revenues	$	43.4		160.8	39.0	7.9	—		.5		20.9	272.5
Production expenses		14.2		25.4	8.4	3.1	—		—		11.1	62.2
Depreciation, depletion and amortization		10.0		50.0	8.1	1.3	.2		—		2.1	71.7
Exploration expenses
Dry holes		17.5		1.0	—	—	31.2		—		—	49.7
Geological and geophysical		1.3		1.3	—	—	.2		—		—	2.8
Other		1.8		.4	.3	—	.5		—		—	3.0
		20.6		2.7	.3	—	31.9		—		—	55.5
Undeveloped lease amortization		2.7		3.6	—	—	—		—		—	6.3
Total exploration expenses		23.3		6.3	.3	—	31.9		—		—	61.8
Selling and general expenses		2.2		3.6	.8	.2	—		1.4		—	8.2
Income tax provisions (benefits)		(2.2	)	26.7	12.2	—	—		(.2	)	2.5	39.0
Results of operations (excluding   corporate overhead and interest)	$	(4.1	)	48.8	9.2	3.3	(32.1	)	(.7	)	5.2	29.6
Three Months Ended June 30, 2001
Oil and gas sales, other operating revenues	$	66.9		105.1	51.2	10.2	—		.4		23.3	257.1
Production expenses		12.6		18.2	7.6	4.0	—		—		13.3	55.7
Depreciation, depletion and amortization		10.4		23.7	8.9	1.8	.1		—		2.1	47.0
Goodwill amortization		—		.8	—	—	—		—		—	.8
Exploration expenses
Dry holes		.2		19.8	—	—	3.8		3.8		—	27.6
Geological and geophysical		—		1.6	.1	—	2.6		.5		—	4.8
Other		1.1		.6	.3	—	1.3		.3		—	3.6
		1.3		22.0	.4	—	7.7		4.6		—	36.0
Undeveloped lease amortization		2.1		3.5	—	—	—		—		—	5.6
Total exploration expenses		3.4		25.5	.4	—	7.7		4.6		—	41.6
Selling and general expenses		2.9		3.0	.6	.1	—		1.6		—	8.2
Income tax provisions (benefits)		13.0		15.0	12.3	—	—		(.1	)	3.0	43.2
Results of operations (excluding   corporate overhead and interest)	$	24.6		18.9	21.4	4.3	(7.8	)	(5.7	)	4.9	60.6
Six Months Ended June 30, 2002
Oil and gas sales, other operating revenues	$	76.4		259.7	84.5	13.5	—		1.1		42.6	477.8
Production expenses		28.2		45.5	19.8	6.4	—		—		24.0	123.9
Depreciation, depletion and amortization		19.8		84.8	17.9	2.6	.5		.1		4.2	129.9
Exploration expenses
Dry holes		22.5		13.4	—	—	36.9		—		—	72.8
Geological and geophysical		3.3		9.1	—	—	.6		—		—	13.0
Other		2.2		1.0	.5	—	2.1		(.1	)	—	5.7
		28.0		23.5	.5	—	39.6		(.1	)	—	91.5
Undeveloped lease amortization		5.2		7.1	—	—	—		—		—	12.3
Total exploration expenses		33.2		30.6	.5	—	39.6		(.1	)	—	103.8
Selling and general expenses		6.1		6.9	1.6	.4	—		2.6		.1	17.7
Income tax provisions (benefits)		(4.2	)	29.7	22.3	—	—		(.3	)	4.7	52.2
Results of operations (excluding   corporate overhead and interest)	$	(6.7	)	62.2	22.4	4.1	(40.1	)	(1.2	)	9.6	50.3
Six Months Ended June 30, 2001			��
Oil and gas sales, other operating revenues	$	163.5		199.5	101.5	20.3	—		.9		49.5	535.2
Production expenses		24.8		36.3	14.8	8.4	—		—		28.5	112.8
Depreciation, depletion and amortization		20.7		41.9	18.7	3.6	.2		.1		4.2	89.4
Goodwill amortization		—		1.6	—	—	—		—		—	1.6
Exploration expenses
Dry holes		15.7		23.2	.1	—	3.8		3.8		—	46.6
Geological and geophysical		3.7		9.0	.1	—	2.9		.6		—	16.3
Other		1.4		1.3	.5	—	2.1		.6		—	5.9
		20.8		33.5	.7	—	8.8		5.0		—	68.8
Undeveloped lease amortization		4.1		6.7	—	—	—		—		—	10.8
Total exploration expenses		24.9		40.2	.7	—	8.8		5.0		—	79.6
Selling and general expenses		6.7		5.1	1.2	.2	—		3.0		—	16.2
Income tax provisions (benefits)		30.7		32.8	24.6	—	—		(.2	)	6.5	94.4
Results of operations (excluding   corporate overhead and interest)	$	55.7		41.6	41.5	8.1	(9.0	)	(7.0	)	10.3	141.2

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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 liability.

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 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At the annual meeting of security holders on May 8, 2002, the directors proposed by management were elected with a tabulation of votes to the nearest share as shown below.

	For	Withheld
George S. Dembroski	41,372,784	767,074
Claiborne P. Deming	41,581,176	558,682
H. Rodes Hart	41,432,020	707,838
Robert A. Hermes	41,584,917	554,941
Michael W. Murphy	41,475,856	664,002
R. Madison Murphy	41,580,019	559,839
William C. Nolan Jr.	41,265,346	874,512
William L. Rosoff	41,585,410	554,448
David J. H. Smith	41,644,766	495,092
Caroline G. Theus	41,474,582	665,276

The security holders approved the Company’s annual Incentive Compensation Plan and the performance criteria thereof by a vote of 41,414,183 shares in favor, 674,245 shares against and 51,430 shares not voted. Also the performance criteria for the Company’s Long-Term Incentive Plan was approved by a vote of 41,713,854 shares in favor, 309,312 shares against and 116,692 shares not voted. In addition, the earlier appointment by the Board of Directors of KPMG LLP as independent auditors for 2002 was approved, with 41,436,260 shares voted in favor, 661,329 shares voted in opposition and 42,269 shares not voted.

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ITEM 6.    EXHIBITS AND REPORTS ON FORM 8-K

(a)	The Exhibit Index on page 20 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 April 26, 2002 that included the Company’s News Release, dated April 24, 2002, announcing the Company’s earnings and certain other financial information for the three-month period ended March 31, 2002.
(c)	A report on Form 8-K was filed on May 3, 2002 that included the Second Supplemental Indenture, dated May 2, 2002, between the Company and SunTrust Bank as Trustee (“the Trustee”).

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)

August 2, 2002

(Date)

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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 filed herewith
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.

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