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, 2003

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            

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

x  Yes      ¨No            

Number of shares of Common Stock, $1.00 par value, outstanding at June 30, 2003 was 91,840,563.

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)

	(Unaudited) June 30, 2003			December 31, 2002
ASSETS
Current assets
Cash and cash equivalents	$	220,268		164,957
Accounts receivable, less allowance for doubtful accounts of $10,375 in 2003 and $9,307 in 2002		380,522		408,782
Inventories, at lower of cost or market
Crude oil and blend stocks		152,522		41,961
Finished products		104,741		94,158
Materials and supplies		70,651		65,225
Prepaid expenses		42,104		59,962
Deferred income taxes		16,577		19,115
Total current assets		987,385		854,160
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $3,271,032 in 2003 and $3,361,726 in 2002		3,361,745		2,886,599
Goodwill, net		59,552		51,037
Deferred charges and other assets		87,027		93,979
Total assets	$	4,495,709		3,885,775
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	61,569		57,104
Accounts payable and accrued liabilities		673,878		599,229
Income taxes		93,684		61,559
Total current liabilities		829,131		717,892
Notes payable		937,420		788,554
Nonrecourse debt of a subsidiary		49,673		74,254
Deferred income taxes		368,499		327,771
Asset retirement obligations		232,965		160,543
Accrued major repair costs		44,869		52,980
Deferred credits and other liabilities		160,884		170,228
Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued		—		—
Common Stock, par $1.00, authorized 200,000,000 shares, issued 94,613,379 shares		94,613		94,613
Capital in excess of par value		504,289		504,983
Retained earnings		1,267,257		1,137,177
Accumulated other comprehensive income (loss)		78,589		(66,790	)
Treasury stock, 2,772,816 shares of Common Stock in 2003 and 2,923,925 shares in 2002, at cost		(72,480	)	(76,430	)
Total stockholders’ equity		1,872,268		1,593,553
Total liabilities and stockholders’ equity	$	4,495,709		3,885,775

See Notes to Consolidated Financial Statements, page 5.

The Exhibit Index is on page 25.

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,
	2003			2002*		2003		2002*
REVENUES
Sales and other operating revenues	$	1,227,082		1,034,879		2,548,396		1,783,349
Gain (loss) on sale of assets		49,274		(36	)	49,298		5,700
Interest and other income		1,220		999		2,195		2,002
Total revenues		1,277,576		1,035,842		2,599,889		1,791,051
COSTS AND EXPENSES
Crude oil and product purchases		839,739		682,514		1,744,432		1,166,835
Operating expenses		162,585		135,787		316,598		264,149
Exploration expenses, including undeveloped lease amortization		33,118		61,767		57,268		103,788
Selling and general expenses		28,931		23,129		59,753		45,491
Depreciation, depletion and amortization		77,926		83,457		153,731		153,163
Accretion on discounted liabilities		3,170		—		6,285		—
Interest expense		14,272		13,287		28,233		22,829
Interest capitalized		(10,112	)	(4,607	)	(19,648	)	(9,424	)
Total costs and expenses		1,149,629		995,334		2,346,652		1,746,831
Income from continuing operations before income taxes		127,947		40,508		253,237		44,220
Income tax expense		48,261		27,591		79,446		28,972
Income from continuing operations		79,686		12,917		173,791		15,248
Discontinued operations, net of tax		—		1,012		—		1,215
Income before cumulative effect of change in accounting principle		79,686		13,929		173,791		16,463
Cumulative effect of change in accounting principle, net of tax		—		—		(6,993	)	—
NET INCOME	$	79,686		13,929		166,798		16,463
INCOME (LOSS) PER COMMON SHARE – BASIC
Income from continuing operations	$	.87		.14		1.90		.17
Discontinued operations		—		.01		—		.01
Cumulative effect of change in accounting principle		—		—		(.08	)	—
NET INCOME – BASIC	$	.87		.15		1.82		.18
INCOME (LOSS) PER COMMON SHARE – DILUTED
Income from continuing operations	$	.86		.14		1.88		.17
Discontinued operations		—		.01		—		.01
Cumulative effect of change in accounting principle		—		—		(.08	)	—
NET INCOME – DILUTED	$	.86		.15		1.80		.18
Average common shares outstanding – basic		91,817,165		91,568,146		91,776,458		91,270,986
Average common shares outstanding – diluted		92,503,242		92,266,864		92,464,624		92,059,020

*Reclassified to conform to 2003 presentation.

See Notes to Consolidated Financial Statements, page 5.

2

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)

	Three Months Ended June 30,				Six Months Ended June 30,
	2003			2002	2003		2002
Net income	$	79,686		13,929	166,798		16,463
Other comprehensive income, net of tax
Cash flow hedges
Net derivative gains (losses)		(4,468	)	4,675	(24,155	)	7,622
Reclassification adjustments		8,689		945	27,138		(2,378	)
Total cash flow hedges		4,221		5,620	2,983		5,244
Net gain from foreign currency translation		90,456		57,412	143,103		52,416
Minimum pension liability adjustment		—		—	(707	)	—
COMPREHENSIVE INCOME	$	174,363		76,961	312,177		74,123

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,
	2003			2002
OPERATING ACTIVITIES
Income from continuing operations	$	173,791		15,248
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation, depletion and amortization		153,731		153,163
Provisions for major repairs		15,830		9,332
Expenditures for major repairs and asset retirements		(26,335	)	(9,805	)
Dry holes		24,431		72,844
Amortization of undeveloped leases		13,179		12,267
Accretion on discounted liabilities		6,285		—
Deferred and noncurrent income tax benefits		4,330		11,215
Pretax gains from disposition of assets		(49,298	)	(5,700	)
Net (increase) decrease in operating working capital other than cash and cash equivalents		28,860		(96,364	)
Other		(5,672	)	5,349
Net cash provided by continuing operations		339,132		167,549
Net cash provided by discontinued operations		—		3,423
Net cash provided by operating activities		339,132		170,972
INVESTING ACTIVITIES
Property additions and dry holes		(453,235	)	(415,973	)
Proceeds from the sale of assets		69,035		28,648
Other – net		80		2
Investing activities of discontinued operations		—		(266	)
Net cash required by investing activities		(384,120	)	(387,589	)
FINANCING ACTIVITIES
Increase in notes payable		149,488		298,112
Decrease in nonrecourse debt of a subsidiary		(24,452	)	(13,629	)
Proceeds from exercise of stock options and employee stock purchase plans		2,348		23,024
Cash dividends paid		(36,718	)	(34,233	)
Other		(72	)	(2,526	)
Net cash provided by financing activities		90,594		270,748
Effect of exchange rate changes on cash and cash equivalents		9,705		4,203
Net increase in cash and cash equivalents		55,311		58,334
Cash and cash equivalents at January 1		164,957		82,652
Cash and cash equivalents at June 30	$	220,268		140,986
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid, net of refunds	$	16,583		10,916
Interest paid, net of amounts capitalized		7,057		9,082

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, 2002. In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at June 30, 2003, and the results of operations and cash flows for the three and six-month periods ended June 30, 2003 and 2002, in conformity with accounting principles generally accepted in the United States.

Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2002 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, 2003 are not necessarily indicative of future results.

Note B – New Accounting Principles

The Company adopted Emerging Issues Task Force (EITF) Topic 02-3 in the fourth quarter of 2002. Based on Topic 02-3, Murphy has reflected the results of its crude oil trading activities as net revenue in its income statement, and previously reported revenues and cost of sales in the six-month period ended June 30, 2002 have been reduced by equal and offsetting amounts, with no changes to net income or cash flows. The effect of this reclassification was a net reduction of both net sales and cost of crude oil and product purchases by approximately $90 million and $153 million for the three-month and six-month periods ended June 30, 2002.

On January 1, 2003, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is 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. 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. The asset retirement obligation is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that will be required in future periods due to the availability of additional information, including prices for oil field services, technological changes, governmental requirements and other factors. Upon adoption of SFAS No. 143, the Company recorded a charge of $7 million, net of $1.4 million in income taxes, as the cumulative effect of a change in accounting principle. The noncash transition adjustment increased property, plant and equipment, accumulated depreciation, and asset retirement obligations by $142.9 million, $58.8 million, and $92.5 million, respectively.

The majority of the asset retirement obligation (ARO) recognized by the Company at June 30, 2003 relates to the estimated costs to dismantle and abandon its investment in producing oil and gas properties and related equipment. A portion of the transition adjustment and ARO relates to its investment in retail gasoline stations. The Company did not record a retirement obligation for certain of its refining and marketing assets because sufficient information is presently not available to estimate a range of potential settlement dates for the obligation. In these cases, the obligation will be initially recognized in the period in which sufficient information exists to estimate the obligation.

5

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B – New Accounting Principles (Contd.)

A reconciliation of the 2003 changes in the asset retirement obligations liability is shown in the following table.

(Thousands of dollars)
December 31, 2002	$	160,543
Transition adjustment		92,500
Accretion expense		6,285
Liabilities incurred		14,150
Liabilities settled		(57,140	)
Changes due to translation of foreign currencies		16,627
June 30, 2003	$	232,965

Liabilities settled includes approximately $54.9 million in noncash reductions of asset retirement obligations associated with the sale of certain oil and gas producing properties.

The pro forma asset retirement obligations as of January 1, 2002 and June 30, 2002 were $220 million and $236.3 million, respectively. Pro forma net income for the three and six-month periods ended June 30, 2002, assuming SFAS No. 143 had been applied retroactively, is shown in the following table.

(Thousands of dollars except per share data)		Three Months Ended June 30, 2002	Six Months Ended June 30, 2002
Net income —	As reported	$13,929	16,463
	Pro forma	16,479	17,880
Net income per share —	As reported, basic	$      .15	.18
	Pro forma, basic	.18	.20
	As reported, diluted	.15	.18
	Pro forma, diluted	.17	.19

On January 1, 2003, the Company adopted SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections, and SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 145 amends existing guidance on reporting gains and losses on the extinguishment of debt to prohibit the classification of the gain or loss as extraordinary and also amends SFAS No. 13 to require sale-leaseback accounting for certain lease modifications that have economic effects similar to sale-leaseback transactions. SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue 94-3, Liability Recognition for certain Employee Termination Benefits and Other Costs to Exit an Activity. The adoption of these two accounting standards did not have a material effect on the Company’s financial statements.

Additionally, beginning January 1, 2003, the Company has applied Financial Accounting Standards Board (FASB) Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirement for Guarantees, Including Indirect Guarantees of Indebtedness to Others, an Interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34, and FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. Interpretation No. 45 elaborates on the disclosures to be made by a guarantor in its financial statements about its obligations under guarantees issued and requires under certain circumstances a guarantor to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. Interpretation No. 46 addresses the consolidation by business enterprises of variable interest entities as defined in the Interpretation. The application of these two FASB Interpretations did not have a material effect on the Company’s financial statements.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment of FASB Statement No. 123. This Statement amends SFAS No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. This Statement amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements, and these disclosures are included in the notes to these consolidated financial statements.

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B – New Accounting Principles (Contd.)

In April 2003, the FASB issued SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS 133, Accounting for Derivatives and Hedging Activities. SFAS 149 is effective for contracts entered into or modified after June 30, 2003, with all provisions applied prospectively. The Company’s adoption of this statement is not expected to have a material impact on the Company’s financial statements.

In May 2003, the FASB issued SFAS 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify an instrument that is within its scope as a liability. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective July 1, 2003. As of June 30, 2003, the Company had no financial instruments within the scope of SFAS 150.

Note C – Discontinued Operations

In December 2002, the Company sold its investment in Ship Shoal Block 113 in the Gulf of Mexico. Operations for the field in 2002 have been reported as Discontinued Operations in the Consolidated Statements of Income. Revenues and pretax earnings from the field were $4.4 million and $1.6 million, respectively, for the three-month period ended June 30, 2002 and $7.3 million and $1.9 million, respectively, for the first six months of 2002.

Note D – Environmental Contingencies

In addition to being 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 three refineries, 11 terminals, and approximately 80 service stations for which known or potential obligations for environmental remediation exist. In addition the Company operates or has operated numerous oil and gas fields that may require some form of remediation.

The Company’s liability for remedial obligations includes certain amounts that are based on anticipated regulatory approval for proposed remediation of former refinery waste sites. If regulatory authorities require more costly alternatives than the proposed processes, future expenditures could exceed the accrued liability 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 two Superfund sites. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. At one site the Company paid $6,500 to obtain release from further obligations. The Company’s insurance carrier has agreed to reimburse the $6,500. Based on currently available information, the Company believes that it is a de minimus party as to ultimate responsibility at the other Superfund site. The Company could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at the one remaining site or other Superfund sites. The Company does not believe that the ultimate costs to clean-up the two Superfund sites will have a material adverse effect on its net income or cash flows in a future period.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on future net income or cash flows.

7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – Other Contingencies

The Company’s operations and earnings have been and may be affected by various 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 and the protection and/or remediation of the environment; 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 and may be taken without full consideration of their consequences or in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

In December 2000, two of the Company’s Canadian subsidiaries, Murphy Oil Company Ltd. (MOCL) and Murphy Canada Exploration Company (MCEC) 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, the Predator Corporation Ltd. and Predator Energies Partnership (collectively Predator) and Ricks Nova Scotia Co. (Ricks), acquired the lands after first inappropriately obtaining confidential and proprietary data belonging to the Company and its partner. In January 2001, Ricks, 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 partner at cost. In 2001, Predator, representing the remaining undivided 25% of the lands in question, filed a counterclaim, as subsequently amended, against MOCL and MCEC and MOCL’s president individually seeking compensatory damages of C$4.61 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 June 10, 2003, a fire severely damaged the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery. The ROSE unit recovers feedstock from the heavy fuel oil stream for conversion into gasoline and diesel. Subsequent to the fire, 15 class action lawsuits have been filed seeking damages for area residents. The Company maintains liability insurance that covers such matters, and it recorded the applicable insurance deductible as an expense in the second quarter of 2003. Accordingly, the Company does not believe that the ultimate resolution of the class action litigation 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. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s earnings or financial condition in a future period.

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, 2003, the Company had contingent liabilities of $8.1 million under a financial guarantee and $41.8 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to these letters of credit because it is believed that the likelihood of having these drawn is remote.

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Earnings per Share and Stock Options

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, 2003 and 2002. The following table reconciles the weighted-average shares outstanding used for these computations.

	Three Months Ended June 30,		Six Months Ended June 30,
(Weighted-average shares)	2003	2002	2003	2002
Basic method	91,817,165	91,568,146	91,776,458	91,270,986
Dilutive stock options	686,077	698,718	688,166	788,034
Diluted method	92,503,242	92,266,864	92,464,624	92,059,020

The computation of earnings per share in the Consolidated Statements of Income did not consider outstanding options of 54,000 shares for the six-month period in 2003 because the effects of these options would have been antidilutive. Average exercise prices per share of the options not used were $47.16. There were no antidilutive options for the three-month periods ended June 30, 2003 and 2002 and the six-month period ended June 30, 2002.

The Company accounts for its stock options using the intrinsic-value based method of accounting as prescribed by Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. Under this method, compensation expense is not recorded for stock options since all option prices have been equal to or greater than the fair market value of the Company’s stock on the date of grant. The Company would record compensation expense for any stock options deemed to be variable in nature. The Company accrues compensation expense for restricted stock awards and adjusts such costs for changes in the fair market value of Common Stock. SFAS No. 123, Accounting for Stock-Based Compensation, established accounting and disclosure requirements using a fair-value based method for stock-based employee compensation plans. As allowed by SFAS No. 123, the Company has elected to continue to apply the intrinsic-value based method prescribed by APB No. 25 and has adopted only the disclosure requirements of SFAS No. 123. Had the Company recorded compensation expense for stock options as prescribed by SFAS No. 123, net income and earnings per share for the three-month and six-month periods ended June 30, 2003 and 2002, would be the pro forma amounts shown in the table below.

		Three Months Ended June 30,			Six Months Ended June 30,
(Thousands of dollars except per share data)		2003		2002	2003	2002
Net income   —	As reported	$	79,686	13,929	166,798	16,463
	Pro forma		78,322	12,492	164,367	13,893
Net income per share —	As reported, basic	$	.87	.15	1.82	.18
	Pro forma, basic		.85	.13	1.79	.15
	As reported, diluted		.86	.15	1.80	.18
	Pro forma, diluted		.84	.13	1.76	.15

Note G – Financial Instruments and Risk Management

Murphy utilizes derivative instruments 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 speculative 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, 2003 to hedge fluctuations in cash flows of a similar amount of variable rate debt. The 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

9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

averaged 1.21% at June 30, 2003. 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 Income (AOCI) 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, 2003 and 2002, 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 requirements and to Murphy’s natural gas swaps. The control system involves using analytical techniques, including various correlations of natural gas purchase prices to future 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 AOCI and is subsequently reclassified into Crude Oil and Product Purchases in the income statements in the periods in which the hedged natural gas fuel purchases affect earnings. For the periods ended June 30, 2003 and 2002, the income effect from cash flow hedging ineffectiveness for these contracts 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 its natural gas production in the United States and Canada during 2003 by entering into financial contracts known as natural gas swaps and collars. The swaps cover a combined notional volume averaging 24,200 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 $3.76 per MMBTU equivalent. The natural gas collars are for a combined notional volume averaging 26,700 MMBTU equivalents per day and based upon the relevant index prices provide Murphy with an average floor price of $3.24 per MMBTU and an average ceiling price of $4.64 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 fair values of the effective portions of the natural gas swaps and collars and changes thereto are deferred in AOCI and are subsequently reclassified into Sales and Other Operating Revenues in the income statement in the periods in which the hedged natural gas sales affect earnings. For the three-month and six-month periods ended June 30, 2003 and 2002, Murphy’s earnings were not significantly affected by cash flow hedging ineffectiveness from these contracts.

During the six-month period ended June 30, 2003, the Company paid approximately $10.6 million for settlement of natural gas swap and collar agreements in the U.S. and Canada, and during the same period in 2002, received approximately $1.8 million.

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 and AECO “C” index futures price or natural gas price quotes from counterparties.

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

• Crude Oil Sales Price Risks – The sales price of crude oil 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 its crude oil production in the United States and Canada during 2003 by entering into financial contracts known as crude oil swaps. A portion of the swaps cover a notional volume of 22,000 barrels per day of light oil and require Murphy to pay the average of the closing settlement price on the NYMEX for the Nearby Light Crude Futures Contract for each month and receive an average price of $25.30 per barrel. Additionally, there are heavy oil swaps with a notional volume of 10,000 barrels per day (which equates to approximately 7,700 barrels per day of the Company’s heavy oil production) that require Murphy to pay the arithmetic average of the posted price at the Kerrobert and Hardisty terminals in Canada for each month and receive an average price of $16.74 per barrel. Murphy has a risk management control system to monitor crude oil price risk attributable both to forecasted crude oil sales prices and to Murphy’s hedging instruments. The control system involves using analytical techniques, including various correlations of crude oil sales prices to futures prices, to estimate the impact of changes in crude oil prices on Murphy’s cash flows from the sale of light and heavy crude oil.

The fair values of the effective portions of the crude oil hedges and changes thereto are deferred in AOCI and are subsequently reclassified into Sales and Other Operating Revenues in the income statement in the periods in which the hedged crude oil sales affect earnings. In the first half of 2003, cash flow hedging ineffectiveness relating to the crude oil sales swaps increased Murphy’s after-tax earnings by $1.4 million.

During the six-month period ended June 30, 2003 the Company paid approximately $36.9 million for settlement of maturing crude oil sales swaps.

The fair value of the crude oil sales swaps are based on the average fixed price of the instruments and the published NYMEX index futures price or crude oil price quotes from counterparties.

• 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 certain crude oil purchases in 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 pretax gain of $7.7 million. The fair values of these settlement gains were recorded in AOCI at January 1, 2001 associated with adoption of SFAS No. 133 as part of the transition adjustment and were recognized as a reduction of costs of crude oil purchases in the period the forecasted transactions occurred. Pretax gains of $3.6 million were reclassified from AOCI into earnings during the six-month period ended June 30, 2002, but none of these gains were recorded in the second quarter of 2002.

During the next twelve months, the Company expects to reclassify approximately $12.1 million in net after-tax losses from AOCI into earnings as the forecasted transactions covered by hedging instruments actually occur. All forecasted transactions currently being hedged are expected to occur by December 2006.

11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Accumulated Other Comprehensive Income (Loss)

The components of Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheets at June 30, 2003 and December 31, 2002 are presented in the following table.

(Millions of dollars)	June 30, 2003			December 31, 2002
Foreign currency translation gain (loss)	$	86.2		(56.9	)
Cash flow hedging, net		(5.5	)	(8.5	)
Minimum pension liability, net		(2.1	)	(1.4	)
Accumulated other comprehensive income (loss)	$	78.6		(66.8	)

The effect of SFAS Nos. 133/138, Accounting for Derivative Instruments and Hedging Activities, increased AOCI for the three months ended June 30, 2003 by $4.2 million, net of $2.4 million in income taxes, and hedging ineffectiveness increased net income by $.8 million, net of $.4 million in income taxes. During the first half of 2003, hedging activities increased AOCI by $3 million, net of $1.2 million in income taxes, and hedging ineffectiveness increased income by $1.4 million, net of $.9 million in income taxes. For the first half of 2003 losses of $27.1 million, net of $19.2 million in taxes, were reclassified from AOCI to earnings. During the three-month period ended June 30, 2002, AOCI increased $5.6 million, net of $3.8 million in income taxes, and hedging ineffectiveness increased net income by $.3 million, net of $.2 in income taxes. During the six-month period ended June 30, 2002, hedging activities increased AOCI by $5.2 million, net of $3.6 million in income taxes, and hedging ineffectiveness increased income by $.4 million, net of $.2 million in income taxes. Gains of $2.4 million, net of $1.4 million in taxes, were reclassified from AOCI to earnings in the six-month period ended June 30, 2002.

12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Business Segments

			Three Months Ended June 30, 2003				Three Months Ended June 30, 2002
(Millions of dollars)	Total Assets at June 30, 2003		External Revenues	Inter-   segment Revenues	Income (Loss)		External Revenues	Inter-   segment Revenues	Income (Loss)
Exploration and production*
United States	$	761.3	49.9	–	2.8		38.3	.8	(5.1	)
Canada		1,490.6	146.4	12.3	42.5		165.8	15.9	54.0
United Kingdom		212.4	91.4	–	47.4		39.0	–	9.2
Ecuador		103.8	4.8	–	.8		7.9	–	3.3
Malaysia		189.1	–	–	(5.3	)	–	–	(32.1	)
Other		17.7	1.6	–	(.5	)	.5	–	(.7	)
Total		2,774.9	294.1	12.3	87.7		251.5	16.7	28.6
Refining and marketing
North America		1,174.3	866.2	–	(1.5	)	683.4	–	(9.8	)
United Kingdom		230.6	116.1	–	1.8		100.0	–	1.8
Total		1,404.9	982.3	–	.3		783.4	–	(8.0	)
Total operating segments		4,179.8	1,276.4	12.3	88.0		1,034.9	16.7	20.6
Corporate and other		315.9	1.2	–	(8.3	)	1.0	–	(7.6	)
Total from continuing operations	$	4,495.7	1,277.6	12.3	79.7		1,035.9	16.7	13.0

	Six Months Ended June 30, 2003					Six Months Ended June 30, 2002
(Millions of dollars)	External Revenues		Inter-   segment Revenues	Income (Loss)		External Revenues	Inter-   segment Revenues	Income (Loss)
Exploration and production*
United States	$	100.6	–	15.6		68.3	.9	(7.9	)
Canada		315.0	25.3	98.4		267.7	34.6	71.8
United Kingdom		149.6	–	66.5		84.5	–	22.4
Ecuador		16.1	–	6.3		13.5	–	4.1
Malaysia		–	–	(10.8	)	–	–	(40.1	)
Other		2.3	–	(1.4	)	1.1	–	(1.2	)
Total		583.6	25.3	174.6		435.1	35.5	49.1
Refining and marketing
North America		1,775.7	–	(7.9	)	1,173.3	–	(21.3	)
United Kingdom		238.4	–	4.7		180.7	–	(.4	)
Total		2,014.1	–	(3.2	)	1,354.0	35.5	(21.7	)
Total operating segments		2,597.7	25.3	171.4		1,789.1	35.5	27.4
Corporate and other		2.2	–	2.4		2.0	–	(12.1	)
Total from continuing operations	$	2,599.9	25.3	173.8		1,791.1	35.5	15.3

*Additional details about results of oil and gas operations are presented in the tables on page 21.

13

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

Results of Operations

Murphy’s net income in the second quarter of 2003 totaled $79.7 million, $.86 a diluted share, compared to net income of $14 million, $.15 a diluted share in the 2002 period. The second quarter 2003 period included a $34 million after-tax gain on sale of certain North Sea properties and $12.3 million in after-tax costs relating to a fire at the Company’s Meraux, Louisiana refinery. The after-tax refinery charges included $2.7 million related to deductibles and self insurance, $5.3 million to establish an allowance to reduce the carrying value of certain crude oil inventory that will be sold rather than processed, and $4.3 million for operating costs incurred at the refinery between June 10 and June 30.

In the current quarter, the Company’s exploration and production operations earned $87.7 million, an increase of $59.1 million from $28.6 million earned in the 2002 period. The increase in income was primarily the result of a $34 million after-tax gain on the sale of the Ninian and Columba fields in the U.K. North Sea and significantly lower exploration expenses in Malaysia. Higher North American natural gas prices were mostly offset by lower natural gas production and lower oil sales resulting from the timing of shipments. The Company’s refining and marketing operations earned income of $.3 million in the 2003 period compared to a loss of $8 million for the three months ended June 30, 2002. The 2003 period included after-tax costs of $12.3 million relating to the fire at the Company’s Meraux, Louisiana refinery. North American refining and marketing margins in the current quarter improved significantly compared to the 2002 period.

For the first six months of 2003, net income totaled $166.8 million, $1.80 a diluted share, compared to $16.5 million, $.18 a diluted share, for the first half of 2002. In addition to the aforementioned gain on sale of assets and costs related to the refinery fire, the 2003 period included a $20.1 million gain related to resolution of prior years’ income tax matters. Additionally, upon adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003, the Company recorded in the income statement an after-tax charge of $7 million, $.08 per share, as the cumulative effect of a change in accounting principle.

Exploration and production earnings in the first six months of 2003 were up $125.5 million from the prior year, mainly due to the gain on sale of North Sea properties, higher oil and natural gas sales prices and lower exploration expenses in Malaysia. The Company’s refining and marketing operations incurred a loss of $3.2 million in the first half of 2003, including the previously mentioned fire costs, compared to a loss of $21.7 million in the 2002 period. North American and U.K. refining margins were significantly higher in the 2003 period compared to the first six months of 2002.

Exploration and Production

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

	Income (Loss)
	Three Months Ended June 30,					Six Months Ended June 30,
(Millions of dollars)	2003			2002		2003		2002
Exploration and production
United States	$	2.8		(5.1	)	15.6		(7.9	)
Canada		42.5		54.0		98.4		71.8
United Kingdom		47.4		9.2		66.5		22.4
Ecuador		.8		3.3		6.3		4.1
Malaysia		(5.3	)	(32.1	)	(10.8	)	(40.1	)
Other International		(.5	)	(.7	)	(1.4	)	(1.2	)
Total	$	87.7		28.6		174.6		49.1

Exploration and production operations in the United States reported earnings of $2.8 million in the second quarter of 2003 compared to a loss of $5.1 million a year ago. This improvement was primarily due to higher sales prices for natural gas, partially offset by lower oil and natural gas production from fields in the Gulf of Mexico.

Operations in Canada earned $42.5 million this quarter compared to $54 million a year ago, as production of natural gas declined significantly and crude oil sales declined due to timing of shipments. Oil and gas liquids sales in Canada averaged 50,811 barrels a day, a decrease of 9% from the prior year, primarily because of lower offshore sales volumes. Canadian natural gas sales averaged 140 million cubic feet a day in the current quarter, down 39%, primarily due to lower production from the Ladyfern field.

14

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

U.K. operations earned $47.4 million in the current quarter, up from $9.2 million in the prior year. The 2003 period included a $34 million after-tax gain on sale of the Ninian and Columba fields. Higher sales prices for U.K. crude oil also contributed to higher earnings.

Operations in Ecuador earned $.8 million in the second quarter of 2003 compared to $3.3 million a year ago. The decline in Ecuador was primarily due to a 37% decrease in crude oil sales volumes, which were adversely affected by pipeline restrictions.

Malaysia and other international operations reported losses of $5.3 million and $.5 million, respectively, in the just completed quarter compared to losses of $32.1 million and $.7 million in 2002. The lower loss in Malaysia in the current period was primarily due to less dry holes expense as the 2002 second quarter included costs of two unsuccessful deepwater wells in Block K.

Operations in the United States for the six months ended June 30, 2003 produced income of $15.6 million compared to a loss of $7.9 million in 2002. The improvement was primarily due to higher oil and natural gas sales prices and less workovers and major field repairs in the latter period, partially offset by lower production of oil and natural gas.

In the first half of 2003, Canada operations earned $98.4 million compared to $71.8 million a year ago. Higher sales prices for oil and natural gas and lower exploration expenses of $14.6 million were partially offset by declines in natural gas sales volumes.

Income in the U.K. for the six-month period ended June 30, 2003 was $66.5 million compared to $22.4 million a year ago. The increase included the $34 after-tax million gain on sale of Ninian and Columba in 2003, but was also due to higher sales prices for U.K. crude oil, partially offset by lower sales volumes due to timing of liftings and the property sale.

For the first six months of 2003, earnings in Ecuador were $6.3 million compared to $4.1 million for the 2002 period. Higher crude oil sales price in Ecuador in the first half of 2003 more than offset the decline in oil sales volumes due to pipeline capacity restrictions.

Malaysia and other international operations reported losses of $10.8 million and $1.4 million, respectively, in the first half of 2003 compared to losses of $40.1 million and $1.2 million a year ago. The improvement in Malaysia in 2003 was primarily due to lower dry hole costs in 2002, but this was partially offset by increased geological and geophysical costs in the 2003 period.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $23.63 per barrel in the second quarter 2003 compared to $23.86 in the 2002 period. Average crude oil and liquids production was 82,488 barrels per day, a 6% increase from 2002 as production began at the West Patricia field in shallow-water Malaysia. Oil sales volumes averaged 74,316 barrels per day in the second quarter 2003, down 11% from 2002, primarily due to timing of oil sales off the east coast Canada and in Ecuador, and the sale of the Ninian and Columba properties. North American natural gas sales prices averaged $4.67 per MCF in the second quarter compared to $3.03 per MCF in the same quarter of 2002. Total natural gas sales volumes averaged 231 million cubic feet a day in the second quarter 2003, down 31% from the 2002 quarter primarily due to lower production from the Ladyfern field in western Canada and mature fields in the Gulf of Mexico.

For the first six months of 2003, the Company’s sales price for crude oil and condensate averaged $25.28 per barrel, a 16% increase from the 2002 period. Crude oil and condensate production increased 3% in the first half of 2003 and averaged 78,740 barrels per day. The increase was mostly attributable to first production from the West Patricia field in shallow-water Malaysia. Sales volumes for crude oil and condensate in the 2003 period was lower than production due to the timing of sales for Malaysia and offshore east coast Canada oil. Average sales prices for North American natural gas in the first six months of 2003 was $5.12 per MCF, up 91% from 2002. Total natural gas sales volume declined by 29% and averaged 230 million cubic feet per day in the 2003 period, with the reduction caused by lower production at the Ladyfern field in western Canada and in the Gulf of Mexico.

The tables on page 16 provide additional details of the results of exploration and production operations for the second quarter and first six months of each year.

15

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Selected operating statistics for the three-month and six-month periods ended June 30, 2003 and 2002 follow.

	Three Months Ended June 30,			Six Months Ended June 30,
	2003		2002	2003	2002
Net crude oil, condensate and gas liquids produced – barrels per day		82,488	78,050	78,740	76,181
Continuing operations		82,488	76,769	78,740	74,959
United States		4,019	4,487	3,654	4,753
Canada – light		2,992	3,107	3,212	3,585
– heavy		9,462	9,469	9,375	9,595
– offshore		30,743	26,317	29,276	23,057
– synthetic		10,431	8,828	9,890	10,078
United Kingdom		16,872	19,796	17,651	19,415
Malaysia		4,875	—	2,451	—
Ecuador		3,094	4,765	3,231	4,476
Discontinued operations		—	1,281	—	1,222
Net crude oil, condensate and gas liquids sold – barrels per day		74,316	83,313	76,262	81,769
Continuing operations		74,316	82,032	76,262	80,547
United States		4,049	4,487	3,654	4,753
Canada – light		2,992	3,107	3,212	3,585
– heavy		9,462	9,469	9,375	9,595
– offshore		27,926	34,512	28,861	28,010
– synthetic		10,431	8,828	9,890	10,078
United Kingdom		16,771	17,348	17,687	20,282
Ecuador		2,685	4,281	3,583	4,244
Malaysia		—	—	—	—
Discontinued operations		—	1,281	—	1,222
Net natural gas sold – thousands of cubic feet per day		231,057	335,954	229,619	322,696
Continuing operations		231,057	331,542	229,619	318,711
United States		83,553	94,900	80,771	96,312
Canada		139,863	231,154	139,220	215,408
United Kingdom		7,641	5,488	9,628	6,991
Discontinued operations		—	4,412	—	3,985
Total net hydrocarbons produced – equivalent barrels per day (1)		120,698	134,042	117,010	129,964
Total net hydrocarbons sold – equivalent barrels per day (1)		112,526	139,305	114,532	135,552
Weighted average sales prices
Crude oil and condensate – dollars a barrel (2)
United States (4)	$	24.69	24.58	24.73	22.18
Canada (3) – light		25.48	24.67	27.71	20.41
– heavy (4)		12.22	17.49	12.43	15.42
– offshore (4)		24.80	25.47	26.50	24.13
– synthetic (4)		26.67	26.06	26.18	23.36
United Kingdom		26.46	23.56	29.60	22.03
Ecuador		19.68	20.54	24.79	17.74
Natural gas – dollars a thousand cubic feet
United States (2) (4)	$	5.26	3.46	5.76	3.03
Canada (3) (4)		4.31	2.85	4.75	2.52
United Kingdom (3)		3.18	2.84	3.38	2.91

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

(2) Includes intracompany transfers at market prices.

(3) U.S. dollar equivalent.

(4) Three-month and six-month 2003 prices include the effects of the Company’s 2003 hedging program.

16

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

Results of Operations (Contd.)

Refining and Marketing

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

	Income (Loss)
	Three Months Ended June 30,					Six Months   Ended June 30,
	2003			2002		2003		2002
(Millions of dollars)
Refining and marketing
North America	$	(1.5	)	(9.8	)	(7.9	)	(21.3	)
United Kingdom		1.8		1.8		4.7		(.4	)
Total	$	.3		(8.0	)	(3.2	)	(21.7	)

Refining and marketing operations in North America reported a loss of $1.5 million during the second quarter of 2003, including $12.3 million in after-tax costs relating to a fire at the Company’s Meraux, Louisiana refinery, compared to a loss of $9.8 million in the same period a year ago. The Company’s North American refining and marketing margins were significantly higher in the current quarter compared to margins in the same quarter of 2002. Earnings in the United Kingdom were $1.8 million in the second quarter of both 2003 and 2002. Worldwide petroleum product sales averaged a record 274,034 barrels a day in 2003, a 28% increase from the second quarter of 2002. Worldwide refinery inputs were 137,749 barrels a day in the second quarter of 2003 compared to 161,363 in the 2002 quarter; inputs were adversely affected by the Meraux refinery fire on June 10, 2003.

Refining and marketing operations in North America in the first half of 2003 reported a loss of $7.9 million, including the net after-tax costs associated with the Meraux refinery fire, compared to a loss of $21.3 million in the 2002 period. North American refining and marketing margins improved significantly in the current period compared to 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 earnings of $4.7 million in the six months ended June 30, 2003 compared to a loss of $.4 million in 2002 due to higher refining and marketing margins compared to the same period a year ago.

Selected operating statistics for the three-month and six-month periods ended June 30, 2003 and 2002 follow.

	Three Months Ended June 30,		Six Months Ended June 30,
	2003	2002	2003	2002
Refinery inputs – barrels a day	137,749	161,363	149,280	157,952
North America	103,017	123,568	113,838	120,660
United Kingdom	34,732	37,795	35,442	37,292
Petroleum products sold – barrels a day	274,034	214,708	251,276	203,079
North America	237,809	179,376	216,866	168,501
Gasoline	166,603	112,651	148,646	104,821
Kerosene	5,540	4,582	6,747	6,505
Diesel and home heating oils	44,759	39,071	41,242	37,407
Residuals	12,784	14,323	13,598	13,687
Asphalt, LPG and other	8,123	8,749	6,633	6,081
United Kingdom	36,225	35,332	34,410	34,578
Gasoline	11,478	12,865	10,744	12,856
Kerosene	2,890	2,438	2,718	2,546
Diesel and home heating oils	14,483	15,276	13,834	14,570
Residuals	3,109	3,412	3,806	3,116
LPG and other	4,265	1,341	3,308	1,490

17

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

Results of Operations (Contd.)

Corporate and other

The net cost of corporate activities, which include interest income and expense and corporate overhead not allocated to operating functions, was $8.3 million in the current quarter compared to $7.6 million in the 2002 quarter. In the first six months of 2003, corporate activities reflected a net profit of $2.4 million compared to a net cost of $12.1 million a year ago. The six-month 2003 results included a $20.1 million gain from resolution of prior years’ income tax matters. Excluding the income tax resolution benefit, higher costs in the second quarter and first six months of 2003 compared to the comparable 2002 periods were attributable to higher retirement expenses and lower other income tax benefits, partially offset by a higher portion of interest costs being capitalized.

Financial Condition

Net cash provided by operating activities was $339.1 million for the first six months of 2003 compared to $171 million for the same period in 2002. Changes in operating working capital other than cash and cash equivalents provided cash of $28.9 million in the first six months of 2003 but used cash of $96.4 million in the first six months of 2002. Proceeds from the sale of assets provided cash of $69 million in the first six months of 2003 compared to $28.6 million in the same period in 2002. Cash from operating activities was reduced by expenditures for margin repairs and asset retirements totaling $26.3 million in the current year and $9.8 million in 2002.

Other predominant uses of cash in each year were for dividends, which totaled $36.7 million in 2003 and $34.2 million in 2002 and for capital expenditures, which including amounts expensed, are summarized in the following table.

	Six Months Ended June 30,
(Millions of dollars)	2003			2002
Capital Expenditures
Exploration and production	$	362.9		325.1
Refining and marketing		109.4		109.1
Corporate and other		.6		.5
Total capital expenditures		472.9		434.7
Geological, geophysical and other exploration expenses charged to income		(19.7	)	(18.7	)
Total property additions and dry holes	$	453.2		416.0

Working capital at June 30, 2003 was $158.3 million, up $22 million from December 31, 2002. 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 $142.9 million below current costs at June 30, 2003.

At June 30, 2003, long-term notes payable of $937.4 million were up $148.8 million from December 31, 2002 due to funding of the Company’s ongoing capital programs. Long-term nonrecourse debt of a subsidiary was $49.7 million, down $24.5 million from December 31, 2002, primarily due to repayments. A summary of capital employed at June 30, 2003 and December 31, 2002 follows.

(Millions of dollars)	June 30, 2003			Dec. 31, 2002
Capital Employed	Amount		%	Amount		%
Notes payable	$	937.4	33	$	788.6	32
Nonrecourse debt of a subsidiary		49.7	2		74.2	3
Stockholders’ equity		1,872.3	65		1,593.6	65
Total capital employed	$	2,859.4	100	$	2,456.4	100

Accounting and Other Matters

As described in Note B on page 5 of this Form 10-Q report, Murphy adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003.

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

Accounting and Other Matters (Contd.)

The SEC has requested that the FASB review the accounting for mineral leases held by oil and gas companies. The SEC has stated that they believe mineral leases should be classified as intangible assets. Should the FASB agree with the SEC’s view, the Company may be required to reclassify certain mineral lease assets, primarily in the form of lease bonuses, from tangible assets now recorded in Property, Plant and Equipment to intangible assets in the Balance Sheet. Such a reclassification is not expected to have a material effect on the Company’s net income or cash flow.

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 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 June 30, 2003, the Company has a receivable of approximately $7 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

The outlook for future oil, natural gas and refined product sales prices is uncertain. A number of factors could cause the prices for these products to weaken in future periods. The Company expects its production to average approximately 120,000 barrels of oil equivalent per day in the third quarter of 2003. The Company will drill three deepwater exploration wells in Malaysia in the third quarter of 2003. Therefore, exposure to dry hole expense will be abnormally high during the third quarter 2003. A fire at the Meraux, Louisiana refinery on June 10, 2003 destroyed the Residual Oil Supercritical Extraction (ROSE) unit. The refinery will be out of operations until September 2003 and will undergo a scheduled plant-wide turnaround prior to restart. During the turnaround, newly constructed equipment will be tied in. Upon completion of the turnaround and equipment tie-in, the plant will produce low-sulfur gasoline as required by new regulations beginning in 2004 and will also be capable of processing 125,000 barrels of crude oil per day. The Company has estimated that the time to rebuild the ROSE unit will be one year or more. Without the ROSE unit, which recovers feedstock from the heavy fuel oil stream for conversion into gasoline and diesel, the refinery will have to process a more expensive, sweeter crude oil.

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 is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note G to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

The Company was a party to interest rate swaps at June 30, 2003 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, 2003, the interest rate to be received by the Company averaged 1.21%. 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 million at June 30, 2003, with the offsetting loss recorded in Accumulated Other Comprehensive Income (AOCI) in Stockholders’ Equity.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK (Contd.)

At June 30, 2003, 32% of the Company’s debt had variable interest rates and 3.5% was denominated in Canadian dollars. Based on debt outstanding at June 30, 2003, a 10% increase in variable interest rates would increase the Company’s interest expense approximately $.4 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 less than $.1 million for debt denominated in Canadian dollars.

Murphy was a party to natural gas price swap agreements at June 30, 2003 for a total notional volume of 9.2 MMBTU that are intended to hedge 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 June 30, 2003, the estimated fair value of these agreements was recorded as an asset of $20.7 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $4.5 million, while a 10% decrease would have reduced the asset by a similar amount.

The Company was a party to natural gas swap agreements and natural gas collar agreements at June 30, 2003 that are intended to hedge the financial exposure of a portion of its 2003 U.S. and Canadian natural gas production to changes in gas sales prices. The swap agreements are for a combined notional volume that averages 24,200 MMBTU equivalents per day and require Murphy to pay the average relevant index price for each month and receive an average price of $3.76 per MMBTU equivalent. The collar agreements are for a combined notional volume of 26,700 MMBTU equivalents per day and based upon the relevant index prices provide Murphy with an average floor price of $3.24 per MMBTU and an average ceiling price of $4.64 per MMBTU. At June 30, 2003, the estimated fair value of these agreements was recorded as a liability of $7.2 million, with the offsetting loss recorded in AOCI in Stockholders’ Equity. A 10% increase in the average index price of natural gas would have increased this liability by $2.3 million, while a 10% decrease would have reduced the liability by a similar amount.

In addition, the Company was a party to crude oil swap agreements at June 30, 2003 that are intended to hedge the financial exposure of a portion of its 2003 U.S. and Canadian crude oil production to changes in crude oil sales prices. A portion of the swap agreements cover a notional volume of 22,000 barrels per day of light oil and require Murphy to pay the average of the closing settlement price on the NYMEX for the Nearby Light Crude Futures Contract for each month and receive an average price of $25.30 per barrel. Additionally, there are heavy oil swap agreements with a notional volume of 10,000 barrels per day (which equates to approximately 7,700 barrels per day of the Company’s heavy oil production) that require Murphy to pay the arithmetic average of the posted prices for each month at the Kerrobert and Hardisty terminals in Canada and receive an average price of $16.74 per barrel. At June 30, 2003, the estimated fair value of these agreements was recorded as a liability of $20.6 million, with the offsetting loss recorded in AOCI in Stockholders’ Equity. A 10% increase in the average index prices of light oil and heavy oil would have increased this liability by $15.3 million, while a 10% decrease would have reduced the liability by a similar amount.

ITEM 4. CONTROLS AND PROCEDURES

The Company, under the direction of its principal executive officer and principal financial officer, has established controls and procedures to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation during the quarter, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) are effective as of the end of the period covered by this report to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There were no significant changes in the Company’s internal controls over financial reporting that occurred during the most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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CONTINUING OIL AND GAS OPERATING RESULTS (unaudited)

(Millions of dollars)	United States			Canada	United King-   dom	Ecuador	Malaysia		Other		Synthetic Oil – Canada	Total
Three Months Ended June 30, 2003
Oil and gas sales and other revenues	$	49.9		133.3	91.4	4.8	–		1.6		25.4	306.4
Production expenses		8.9		20.0	9.3	2.8	–		–		14.9	55.9
Depreciation, depletion and amortization		9.2		42.4	8.4	1.1	.3		–		2.3	63.7
Accretion on discounted liabilities		.8		1.3	.8	–	.1		.1		.1	3.2
Exploration expenses
Dry holes		16.5		.9	–	–	–		(.1	)	–	17.3
Geological and geophysical		2.2		.4	–	–	3.1		–		–	5.7
Other		1.8		.7	.3	–	.5		–		–	3.3
		20.5		2.0	.3	–	3.6		(.1	)	–	26.3
Undeveloped lease amortization		2.8		4.1	–	–	–		–		–	6.9
Total exploration expenses		23.3		6.1	.3	–	3.6		(.1	)	–	33.2
Selling and general expenses		3.3		4.4	.5	.1	1.3		1.6		.2	11.4
Income tax provisions		1.6		21.9	24.7	–	–		.5		2.6	51.3
Results of operations (excluding corporate overhead and interest)	$	2.8		37.2	47.4	.8	(5.3	)	(.5	)	5.3	87.7
Three Months Ended June 30, 2002
Oil and gas sales and other revenues	$	39.1		160.8	39.0	7.9	–		.5		20.9	268.2
Production expenses		12.7		25.4	8.4	3.1	–		–		11.1	60.7
Depreciation, depletion and amortization		8.8		50.0	8.1	1.3	.2		–		2.1	70.5
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)		(2.8	)	26.7	12.2	–	–		(.2	)	2.5	38.4
Results of operations (excluding corporate overhead and interest)	$	(5.1	)	48.8	9.2	3.3	(32.1	)	(.7	)	5.2	28.6
Six Months Ended June 30, 2003
Oil and gas sales and other revenues	$	100.6		293.4	149.6	16.1	–		2.3		46.9	608.9
Production expenses		16.7		39.3	20.8	7.0	–		–		29.3	113.1
Depreciation, depletion and amortization		17.5		82.7	18.0	2.6	.5		.1		4.3	125.7
Accretion on discounted liabilities		1.6		2.5	1.7	–	.1		.2		.2	6.3
Exploration expenses
Dry holes		19.4		5.1	–	–	–		(.1	)	–	24.4
Geological and geophysical		5.8		1.9	–	–	7.5		–		–	15.2
Other		2.3		1.2	.4	–	.5		.1		–	4.5
		27.5		8.2	.4	–	8.0		–		–	44.1
Undeveloped lease amortization		5.4		7.8	–	–	–		–		–	13.2
Total exploration expenses		32.9		16.0	.4	–	8.0		–		–	57.3
Selling and general expenses		7.9		8.5	1.6	.2	2.2		3.2		.3	23.9
Income tax provisions		8.4		54.6	40.6	–	–		.2		4.2	108.0
Results of operations (excluding corporate overhead and interest)	$	15.6		89.8	66.5	6.3	(10.8	)	(1.4	)	8.6	174.6
Six Months Ended June 30, 2002
Oil and gas sales and other revenues	$	69.2		259.7	84.5	13.5	–		1.1		42.6	470.6
Production expenses		25.1		45.5	19.8	6.4	–		–		24.0	120.8
Depreciation, depletion and amortization		17.6		84.8	17.9	2.6	.5		.1		4.2	127.7
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)		(4.9	)	29.7	22.3	–	–		(.3	)	4.7	51.5
Results of operations (excluding corporate overhead and interest)	$	(7.9	)	62.2	22.4	4.1	(40.1	)	(1.2	)	9.6	49.1

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In December 2000, two of the Company’s Canadian subsidiaries, Murphy Oil Company Ltd. (MOCL) and Murphy Canada Exploration Company (MCEC) 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, the Predator Corporation Ltd. and Predator Energies Partnership (collectively Predator) and Ricks Nova Scotia Co. (Ricks), acquired the lands after first inappropriately obtaining confidential and proprietary data belonging to the Company and its partner. In January 2001, Ricks, 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 partner at cost. In 2001, Predator, representing the remaining undivided 25% of the lands in question, filed a counterclaim, as subsequently amended, against MOCL and MCEC and MOCL’s president individually seeking compensatory damages of C$4.61 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 June 10, 2003, a fire severely damaged the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery. The ROSE unit recovers feedstock from the heavy fuel oil stream for conversion into gasoline and diesel. Subsequent to the fire, 15 class action lawsuits have been filed seeking damages for area residents. The Company maintains liability insurance that covers such matters, and it recorded the applicable insurance deductible as an expense in the second quarter of 2003. Accordingly, the Company does not believe that the ultimate resolution of the class action litigation 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. Based on information currently available to the Company, the ultimate resolution of matters referred to in this Item is not expected to have a material adverse effect on the Company’s earnings or financial condition in a future period.

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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At the annual meeting of security holders on May 14, 2003, the directors proposed by management were elected with a tabulation of votes to the nearest share as shown below.

	For	Withheld
Frank W. Blue	84,755,469	2,954,885
George S. Dembroski	84,579,837	3,130,517
Claiborne P. Deming	85,024,422	2,685,932
H. Rodes Hart	84,675,573	3,034,781
Robert A. Hermes	85,167,993	2,542,361
R. Madison Murphy	67,080,538	20,629,816
William C. Nolan Jr.	67,911,011	19,799,343
Ivar B. Ramberg	85,310,684	2,399,670
David J. H. Smith	85,341,577	2,368,777
Caroline G. Theus	85,142,637	2,567,717

The security holders approved the Company’s Stock Plan for Non-Employer Directors by a vote of 81,187,465 shares in favor, 119,063 shares against and 6,403,825 shares not voted. An amendment to limit the term of the Company’s Management Incentive Plan to five years was approved by a vote of 85,707,078 shares in favor, 109,473 shares against, and 1,893,802 shares not voted. Also, the earlier appointment by the Board of Directors of KPMG LLP as independent auditors for 2003 was approved, with 85,395,947 shares voted in favor, 32,331 shares voted in opposition and 2,282,075 shares not voted. In addition, a shareholder proposal requesting the Company’s Board of Directors to redeem the Shareholder Rights Plan unless such plan is approved by a majority of shareholders was defeated by a vote of 44,041,291 shares voted against, 37,932,497 shares voted in favor, and 286,349 shares not voted.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) The Exhibit Index on page 25 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 30, 2003 that included the Company’s News Release, announcing the Company’s earnings and certain other financial information for the three month period ended March 31, 2003.

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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)

August 11, 2003

    (Date)

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EXHIBIT INDEX

Exhibit No.
3.2*	By-Laws of Murphy Oil Corporation as amended effective June 24, 2003
10.1*	1982 Stock Incentive Plan as amended May 14, 1997, December 1, 1999 and May 14, 2003
12.1*	Computation of Ratio of Earnings to Fixed Charges
31.1*	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* This exhibit is incorporated by reference within this Form 10-Q.

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

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