MURPHY OIL CORP /DE - 10-Q 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 March 31, 2004

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		71-0361522
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification Number)

200 Peach Street
P. O. Box 7000, El Dorado, Arkansas		71731-7000
(Address of principal executive offices)		(Zip Code)

(870) 862-6411

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes ¨ No

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). þ Yes ¨ No

Number of shares of Common Stock, $1.00 par value, outstanding at March 31, 2004 was 91,975,758.

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)


	(Unaudited) March 31, 2004			December 31, 2003
ASSETS
Current assets
Cash and cash equivalents	$	297,386		252,425
Accounts receivable, less allowance for doubtful accounts of $11,027 in 2004 and $10,735 in 2003		509,564		450,201
Inventories, at lower of cost or market
Crude oil and blend stocks		49,030		46,626
Finished products		133,740		157,078
Materials and supplies		64,544		66,806
Prepaid expenses		37,558		44,779
Deferred income taxes		21,099		20,940

Total current assets		1,112,921		1,038,855
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $2,915,084 in 2004 and $3,472,133 in 2003		3,146,860		3,530,800
Goodwill, net		46,426		64,873
Deferred charges and other assets		69,576		78,119
Assets held for sale		457,792		—

Total assets	$	4,833,575		4,712,647

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	66,018		67,224
Accounts payable and accrued liabilities		773,239		659,609
Income taxes		76,164		83,493

Total current liabilities		915,421		810,326
Notes payable		1,000,344		1,061,410
Nonrecourse debt of a subsidiary		22,559		28,897
Deferred income taxes		393,693		421,700
Asset retirement obligations		196,063		252,397
Accrued major repair costs		23,851		20,513
Deferred credits and other liabilities		170,452		166,521
Liabilities associated with assets held for sale		84,644		—
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		508,529		504,809
Retained earnings		1,437,755		1,357,910
Accumulated other comprehensive income		59,658		65,246
Unamortized restricted stock awards		(5,237	)	—
Treasury stock, 2,637,621 shares of Common Stock in 2004 and 2,742,781 shares in 2003, at cost		(68,770	)	(71,695	)

Total stockholders’ equity		2,026,548		1,950,883

Total liabilities and stockholders’ equity	$	4,833,575		4,712,647

See Notes to Consolidated Financial Statements, page 5.

The Exhibit Index is on page 22.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars, except per share amounts)


	Three Months Ended March 31,
	2004			2003*
REVENUES
Sales and other operating revenues	$	1,616,566		1,257,170
Gain on sale of assets		29,207		24
Interest and other income		2,299		975

Total revenues		1,648,072		1,258,169

COSTS AND EXPENSES
Crude oil, natural gas and product purchases		1,167,265		904,693
Operating expenses		168,410		142,896
Exploration expenses, including undeveloped lease amortization		49,149		15,399
Selling and general expenses		30,681		28,933
Depreciation, depletion and amortization		80,196		57,176
Accretion on discounted liabilities		2,507		2,471
Interest expense		14,288		13,961
Interest capitalized		(4,252	)	(9,536	)

Total costs and expenses		1,508,244		1,155,993

Income from continuing operations before income taxes		139,828		102,176
Income tax expense		59,132		19,319

Income from continuing operations		80,696		82,857
Discontinued operations, net of tax		17,543		11,248
Cumulative effect of change in accounting principle, net of tax		—		(6,993	)

NET INCOME	$	98,239		87,112

INCOME (LOSS) PER COMMON SHARE – BASIC
Income from continuing operations	$	.88		.91
Discontinued operations		.19		.12
Cumulative effect of change in accounting principle		—		(.08	)

NET INCOME – BASIC	$	1.07		.95

INCOME (LOSS) PER COMMON SHARE – DILUTED
Income from continuing operations	$	.86		.90
Discontinued operations		.19		.12
Cumulative effect of change in accounting principle		—		(.08	)

NET INCOME – DILUTED	$	1.05		.94

Average common shares outstanding – basic		91,925,678		91,738,379
Average common shares outstanding – diluted		93,173,199		92,349,666

*	Reclassified to conform to 2004 presentation.

See Notes to Consolidated Financial Statements, page 5.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)


	Three Months Ended March 31,
	2004			2003
Net income	$	98,239		87,112
Other comprehensive income (loss), net of tax
Cash flow hedges
Net derivative gains (losses)		2,388		(19,687	)
Reclassification adjustments		(3,108	)	18,449

Total cash flow hedges		(720	)	(1,238	)
Net gain (loss) from foreign currency translation		(4,868	)	52,647
Minimum pension liability adjustment		—		(707	)

COMPREHENSIVE INCOME	$	92,651		137,814

See Notes to Consolidated Financial Statements, page 5.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)


	Three Months Ended March 31,
	2004			2003
OPERATING ACTIVITIES
Income from continuing operations	$	80,696		82,857
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation, depletion and amortization		80,196		57,176
Provisions for major repairs		7,612		6,410
Expenditures for major repairs and asset retirement obligations		(6,358	)	(3,694	)
Dry holes		42,104		2,936
Amortization of undeveloped leases		3,907		3,342
Accretion on discounted liabilities		2,507		2,471
Deferred and noncurrent income tax charges (benefits)		8,787		(17,001	)
Pretax gains from disposition of assets		(29,207	)	(24	)
Net decrease in operating working capital other than cash and cash equivalents		75,243		34,509
Other		205		(5,905	)

Net cash provided by continuing operations		265,692		163,077
Net cash provided by discontinued operations		40,183		49,469

Net cash provided by operating activities		305,875		212,546

INVESTING ACTIVITIES
Property additions and dry holes		(195,516	)	(158,100	)
Proceeds from sales of assets		37,140		8,006
Other – net		(893	)	30
Investing activities of discontinued operations		(15,837	)	(25,181	)

Net cash required by investing activities		(175,106	)	(175,245	)

FINANCING ACTIVITIES
Increase (decrease) in notes payable		(60,534	)	42,024
Decrease in nonrecourse debt of a subsidiary		(7,879	)	(9,056	)
Proceeds from exercise of stock options and employee stock purchase plans		926		943
Cash dividends paid		(18,394	)	(18,353	)
Other		—		(72	)

Net cash provided by (used in) financing activities		(85,881	)	15,486

Effect of exchange rate changes on cash and cash equivalents		73		(855	)

Net increase in cash and cash equivalents		44,961		51,932
Cash and cash equivalents at January 1		252,425		164,957

Cash and cash equivalents at March 31	$	297,386		216,889

SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid	$	58,779		33,993
Interest capitalized in excess of amounts paid		(471	)	(6,357	)

See Notes to Consolidated Financial Statements, page 5.

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, 2003. In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at March 31, 2004, and the results of operations and cash flows for the three-month periods ended March 31, 2004 and 2003, 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 2003 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three months ended March 31, 2004 are not necessarily indicative of future results.

Note B – Discontinued Operations

The Company’s Canadian subsidiaries began marketing most of their Western Canadian conventional oil and gas assets (sale properties) in February 2004, and in early April entered into two binding agreements to sell these assets for total proceeds of C$830 million. Sale of assets under one agreement occurred on April 22, 2004. Closing of the other transaction is expected in May and will be subject to due diligence provisions and normal regulatory approvals. The Company expects to utilize the proceeds of the sales to fund operations in Malaysia and other areas and/or to repay debt under revolving credit agreements. The sale properties produce about 20,000 barrels of oil equivalent per day and have total reserves of approximately 46 million barrels equivalent from heavy oil, light oil, and natural gas properties. The operating results from the sale properties have been reported as discontinued operations beginning in the first quarter of 2004. Operating results for the quarter ended March 31, 2003 have been reclassified to conform to this presentation. At March 31, 2004, the major assets (liabilities) associated with the sale properties were as follows:


(Thousands of dollars)	March 31, 2004
Property, plant and equipment, net of accumulated depreciation, depletion and amortization	$	433,609
Goodwill, net		17,716
Other assets		6,467

Assets held for sale	$	457,792

Deferred income taxes	$	(32,570	)
Asset retirement obligations		(52,074	)

Liabilities associated with assets held for sale	$	(84,644	)

Revenues from the sale properties in the first quarter of 2004 and 2003 were $52.7 million and $64.1 million, respectively. Comparable pretax earnings from the sale properties were $28.9 million in the first quarter of 2004 and $23.1 million in the first quarter of 2003. Income tax expense associated with discontinued operations amounted to $11.4 million in the first quarter of 2004 and $11.9 million in the same quarter of 2003.

Note C – Employee and Retiree Pension and Postretirement Plans

The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Employee and Retiree Benefit Plans (Contd.)

The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2004 and 2003.


	Pension Benefits					Postretirement Benefits
(Thousands of dollars)	2004			2003		2004		2003
Service cost	$	2,362		2,071		362		316
Interest cost		4,960		5,050		982		942
Expected return on plan assets		(4,766	)	(4,757	)	—		—
Amortization of prior service cost		(71	)	(486	)	(206	)	(24	)
Amortization of transitional asset		102		10		—		—
Recognized actuarial loss		1,071		985		523		341

Net periodic benefit expense	$	3,658		2,873		1,661		1,575

Murphy previously disclosed in its financial statements for the year ended December 31, 2003, that it expected to contribute $3.6 million to its domestic defined benefit pension plans and $4.6 million to its postretirement benefits plan during 2004. As of March 31, 2004, $.3 million and $.6 million of contributions have been made to the domestic defined benefit pension plans and postretirement benefits plan, respectively. Murphy presently anticipates contributing an additional $7.3 million in the aggregate to fund its domestic plans in 2004. Murphy anticipates contributing $1.5 million in 2004 to fund its existing foreign defined benefit pension plans. Total funding for the Company’s domestic and foreign defined benefits pension and postretirement benefits plans is anticipated to be $9.7 million.

On December 8, 2003, the President signed the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). Among other provisions, the Act will provide prescription drug coverage under Medicare beginning in 2006. Generally, companies that provide qualifying prescription drug coverage that is deemed actuarially equivalent to medicare coverage for retirees aged 65 and above will be eligible to receive a federal subsidy equal to 28% of drug costs between $250 and $5,000 per annum for each covered individual that does not elect to receive coverage under the new prescription drug Medicare Part D. The Company currently provides prescription drug coverage to qualifying retirees under its retiree medical plan. The Company recognized $.1 million in estimated benefits related to the Act in the first quarter of 2004. The Financial Accounting Standards Board has not issued final guidance on accounting for the federal subsidy. Therefore, these benefits could be changed when final authoritative accounting guidance is issued in the future.

Note D – 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 March 31, 2004 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 averaged 1.11% at March 31, 2004. 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 March 31, 2004 and 2003, the income effect from cash flow hedging ineffectiveness of interest rates was insignificant. The fair value of the interest rate swaps is 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

•

Natural Gas Fuel Price Risks – The Company purchases natural gas as fuel at its Meraux, Louisiana and Superior, Wisconsin refineries, 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 financial contracts known as natural gas swaps with a remaining notional volume as of March 31, 2004 of 7.4 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, Natural Gas and Product Purchases in the income statements in the periods in which the hedged natural gas fuel purchases affect earnings. During 2003, the Company determined that natural gas swap contract notional volumes exceeded forecasted 2004 natural gas purchases at its Meraux, Louisiana refinery while the ROSE unit is out of service. Accordingly, natural gas swap contracts with a notional volume of 3.4 MMBTU no longer qualified as a cash flow hedge. Therefore, 1.3 MMBTU of these contracts were redesignated as a cash flow hedge of natural gas the Company will purchase at its Superior refinery during 2004, and the remaining 2.1 MMBTU not qualifying as a hedge have been marked to fair value through earnings during 2004. During the first quarter 2004 the Company entered into 4.3 MMBTU in natural gas price swap agreements that effectively fixed the settlement price of the contracts maturing in April through October 2004. The critical terms of all the 2004 contracts are nearly identical. Murphy is required to pay the average NYMEX price for the final three trading days of the month and receive an average natural gas price of $5.235. The natural gas swap contracts designated as hedges of natural gas the Company will purchase in 2005 through 2006 at the Meraux refinery still qualify as cash flow hedges. For the periods ended March 31, 2004 and 2003, the income effect from cash flow hedging ineffectiveness for these contracts was insignificant. During the three-month period ended March 31, 2004, the Company received approximately $5.4 million for maturing swap agreements.

•

Natural Gas Sales Price Risks – The sales price of natural gas produced by the Company is subject to commodity price risk. During the first quarter of 2004 Murphy entered into natural gas put options covering a combined United States natural gas sales volume averaging 25,000 MMBTU per day. The strike price provides the Company with a floor price of $4.00 per MMBTU and settles monthly from April 2004 through October 2004. During 2003 Murphy hedged the cash flow risk associated with the sales price for a portion of the natural gas it produced in the United States and Canada by entering into financial contracts known as natural gas swaps and collars. The swaps covered a combined notional volume averaging 24,200 MMBTU equivalents per day and required 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 were for a combined notional volume averaging 26,700 MMBTU equivalents per day and based upon the relevant index prices provided 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, collars and puts 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 periods ended March 31, 2004 and 2003, Murphy’s earnings were not significantly affected by cash flow hedging ineffectiveness.

During the three-month period ended March 31, 2003, the Company paid approximately $7 million for settlement of natural gas swap and collar agreements in the U.S. and Canada.

The fair value of the natural gas fuel swaps and the natural gas sales swaps and collars are both based on the average fixed price of the instruments and the published NYMEX and AECO “C” index futures price or natural gas price quotes from counterparties.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – 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 hedged the cash flow risk associated with the sales price for a portion of the crude oil it produced in the United States and Canada during 2003 by entering into financial contracts known as crude oil swaps. A portion of the swaps covered a notional volume of 22,000 barrels per day of light oil and required 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 were heavy oil swaps with a notional volume of 10,000 barrels per day (which equated to approximately 7,700 barrels per day of the Company’s heavy oil production) that required 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 were deferred in AOCI and subsequently reclassified into Sales and Other Operating Revenues in the income statement in the periods in which the hedged crude oil sales affected earnings. In the first quarter of 2003, cash flow hedging ineffectiveness relating to the crude oil sales swaps increased Murphy’s after-tax earnings by $.7 million.

During the three-month period ended March 31, 2003 the Company paid approximately $24.9 million for settlement of maturing 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.

During the next twelve months, the Company expects to reclassify approximately $6.6 million in net after-tax gains 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.

Note E – Asset Retirement Obligations

On January 1, 2003, the Company adopted Statement of Financial Accounting Standards 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 is 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 March 31, 2004 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – Asset Retirement Obligations (Contd.)

A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligations is shown in the following table.


(Thousands of dollars)	2004			2003
Balance at January 1	$	252,397		160,543
Transition adjustment		—		92,500
Accretion expense		3,272		3,115
Liabilities incurred		3,047		—
Liabilities settled		(3,770	)	(1,353	)
Revisions of previous estimates		(5,393	)	—
Changes due to translation of foreign currencies		(1,416	)	4,393

Balance at March 31	$	248,137		259,198

Accretion expense of $.8 million and $.6 million shown in the above table were included in discontinued operating results for the three months ended March 31, 2004 and 2003, respectively. Of the balance of asset retirement obligations at March 31, 2004 shown in the above table, $52.1 million has been included in Liabilities Associated With Assets Held for Sale in the Consolidated Balance Sheet.

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 months ended March 31, 2004 and 2003. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended March 31
(Weighted-average shares)	2004	2003
Basic method	91,925,678	91,738,379
Dilutive stock options	1,247,521	611,287

Diluted method	93,173,199	92,349,666

There were no antidilutive options for the periods ended March 31, 2004 and 2003.

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 periods ended March 31, 2004 and 2003, would be the pro forma amounts shown in the following table.


(Thousands of dollars except per share data)		2004			2003
Net income – As reported		$	98,239		87,112
Restricted stock compensation expense included in income, net of tax			194		197
Total stock-based compensation expense using fair value method for all awards, net of tax			(1,484	)	(1,264	)

Net income – Pro forma		$	96,949		86,045

Net income per share –	As reported, basic	$	1.07		.95
	Pro forma, basic		1.05		.94
	As reported, diluted		1.05		.94
	Pro forma, diluted		1.04		.93

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note G – Accumulated Other Comprehensive Income

The components of Accumulated Other Comprehensive Income (AOCI) on the Consolidated Balance Sheets at March 31, 2004 and December 31, 2003 are presented in the following table.


(Thousands of dollars)	March 31, 2004			December 31, 2003
Foreign currency translation, net	$	83,721		88,589
Cash flow hedging, net		8,738		9,458
Minimum pension liability, net		(32,801	)	(32,801	)

Accumulated other comprehensive income	$	59,658		65,246

The effect of SFAS Nos. 133/138, Accounting for Derivative Investments and Hedging Activities, decreased AOCI for the three months ended March 31, 2004 by $.7 million, net of $.4 million in income taxes, and hedging ineffectiveness was not significant. During 2004 gains of $3.1 million, net of $1.7 million in taxes, were reclassified from AOCI to earnings. AOCI decreased for the three months ended March 31, 2003 by $1.2 million, net of $1.3 million in income taxes, and hedging ineffectiveness increased net income by $.6 million, net of $.5 million in income taxes. For the 2003 period losses of $18.4 million, net of $12.9 million in taxes, were reclassified from AOCI to earnings.

Note H – 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, five terminals, and approximately 82 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, which is generally provided for by the Company’s asset retirement obligation.

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 U.S. Environmental Protection Agency (EPA) currently considers the Company 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. Based on currently available information, the Company believes that it is a de minimus party as to ultimate responsibility at both Superfund sites. 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 two sites 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.

Note I – 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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Other Contingencies (Contd.)

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$3.61 billion. The Company believes that the counterclaim is without merit and that the amount of damages sought is frivolous. Trial will likely begin in January 2005. While the litigation is in the discovery stage 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 20, 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, numerous class action lawsuits have been filed seeking damages for area residents. All the lawsuits have been administratively consolidated into a single legal action in St. Bernard Parish, Louisiana, except for one such action which was filed in federal court. Additionally, individual residents of Orleans Parish, Louisiana, have filed an action in that venue. The Company maintains liability insurance that covers such matters, and it recorded the applicable insurance deductible as an expense in 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 about the outcome, 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 March 31, 2004, the Company had contingent liabilities of $9 million under a financial guarantee and $38.9 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Business Segments


	Total Assets at March 31, 2004		Three Mos. Ended March 31, 2004				Three Mos. Ended March 31, 2003
(Millions of dollars)	Total Assets at March 31, 2004		External Revenues	Interseg. Revenues	Income (Loss)		External Revenues	Interseg. Revenues	Income (Loss)
Exploration and production*
United States	$	776.4	131.3	—	36.5		50.7	—	12.8
Canada		1,092.1	112.5	30.0	53.6		104.5	13.0	44.7
United Kingdom		199.1	38.4	—	13.8		58.2	—	19.1
Ecuador		106.4	16.4	—	2.9		11.3	—	5.5
Malaysia		305.4	25.6	—	(4.0	)	—	—	(5.5	)
Other		17.2	1.0	—	(1.6	)	.7	—	(.9	)

Total		2,496.6	325.2	30.0	101.2		225.4	13.0	75.7

Refining and marketing
North America		1,286.2	1,187.8	—	(10.5	)	909.5	—	(6.4	)
United Kingdom		243.8	132.8	—	4.1		122.3	—	2.9

Total		1,530.0	1,320.6	—	(6.4	)	1,031.8	—	(3.5	)

Total operating segments		4,026.6	1,645.8	30.0	94.8		1,257.2	13.0	72.2
Corporate and other		349.2	2.3	—	(14.1	)	1.0	—	10.7

Total from continuing operations		4,375.8	1,648.1	30.0	80.7		1,258.2	13.0	82.9
Discontinued operations		457.8	—	—	17.5		—	—	11.2
Cumulative effect of change in accounting principle		—	—	—	—		—	—	(7.0	)

Total	$	4,833.6	1,648.1	30.0	98.2		1,258.2	13.0	87.1

*	Additional details about results of oil and gas operations are presented in the tables on page 19.

Note K – Accounting Matters

In July 2003 the FASB undertook to review whether mineral interests in properties (mineral leases) held by oil and gas companies should be recorded and disclosed as intangible assets under the guidance of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. The FASB is considering whether an oil and gas company’s investment in mineral leases should be classified as intangible assets. SFAS No. 141 and SFAS No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets. Under SFAS No. 141 and SFAS No. 142, intangible assets should be separately reported on the Balance Sheet, with accompanying disclosures in the notes to the financial statements. SFAS No. 142 does not change the accounting prescribed in SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and is silent about whether its disclosure provisions apply to oil and gas companies. The Company does not believe that SFAS No. 141 and SFAS No. 142 change the classification and disclosure of oil and gas mineral leases and it continues to classify these assets as part of Property, Plant and Equipment in the Consolidated Balance Sheet and does not provide the additional disclosures for these assets. The EITF has added the discussion of oil and gas mineral leases to its agenda, which may result in a change in the recording and disclosure of oil and gas mineral leases. Should the EITF determine that oil and gas mineral leases are intangible assets in accordance with SFAS No. 141 and SFAS No. 142, the Company would reclassify $115 million and $143 million as intangible undeveloped mineral interests at March 31, 2004 and December 31, 2003, respectively. In addition, a reclassification of $5 million and $8 million would be made as intangible developed mineral interests at March 31, 2004 and December 31, 2003, respectively. Both intangible assets would be presented net of accumulated amortization. Historically, undeveloped mineral leases have been amortized over the life of the lease period, while developed mineral leases have been amortized using the units of production method over the expected life of proved reserves. The amounts included herein are based on our understanding of the issue on the EITF’s agenda. If all mineral leases associated with oil and gas properties are deemed to be intangible assets in accordance with SFAS No. 141 and SFAS No. 142 by the EITF:

•

These assets would not be included in Property, Plant and Equipment on our Consolidated Balance Sheet

•

We do not believe that our net income or cash flows from operations would be materially affected because the amortization of these assets would not be different than the method currently used by the Company

•

Disclosures required by SFAS No. 141 and SFAS No. 142 relative to intangible assets would be included in the notes to the financial statements

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

Results of Operations

Murphy’s net income in the first quarter of 2004 was $98.2 million, $1.05 a diluted share, compared to net income of $87.1 million, $.94 per diluted share, in the same quarter a year ago. The improvement in the 2004 period was attributable to better exploration and production earnings, partially offset by higher losses in refining and marketing operations and higher net costs from corporate activities. The Company has two binding agreements to sell most of its conventional oil and gas assets in Western Canada. One sale agreement closed on April 22 and the other transaction is expected to close in May. The operating results related to the assets held for sale have been presented as discontinued operations in all periods presented. Earnings from discontinued operations were $17.5 million, $.19 per share, in 2004 and $11.2 million, $.12 per share, in 2003. Earnings from continuing operations were $80.7 million, $.86 per share, in 2004 and $82.9 million, $.90 per share, in 2003. The Company recorded a charge of $7 million, $.08 per share, in 2003 upon adoption of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

Murphy’s income from continuing exploration and production operations was $101.2 million in the first quarter of 2004 compared to $75.7 million in the first quarter a year ago. The improvement was the result of higher realized sales prices for crude oil, higher oil and natural gas sales volumes, and a $15.4 million gain on disposal of several minor natural gas properties. The Company’s refining and marketing operations incurred a loss of $6.4 million in the 2004 quarter compared to a loss of $3.5 million in the 2003 quarter. The larger loss was primarily due to poorer performance at the Meraux refinery, which is operating at less than optimum capacity during integration of a new unit and the rebuilding of the Residual Oil Supercritical Extractor (ROSE) unit. Corporate functions reflected a loss of $14.1 million in the 2004 quarter compared to income of $10.7 million in the same period in 2003. The 2004 period included higher net interest costs primarily due to lower capitalized interest since start-up of the Medusa and Habanero fields and completion of the Meraux refinery expansion in the fourth quarter 2003. The 2003 period included a $20.1 million benefit from resolution of prior-years U.S. tax matters.

Exploration and Production

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


	Income (Loss)
	Three Months Ended March 31,
(Millions of dollars)	2004			2003
Exploration and production
United States	$	36.5		12.8
Canada		53.6		44.7
United Kingdom		13.8		19.1
Ecuador		2.9		5.5
Malaysia		(4.0	)	(5.5	)
Other International		(1.6	)	(.9	)

Total	$	101.2		75.7

Exploration and production operations in the United States reported earnings of $36.5 million in the first quarter of 2004 compared to $12.8 million in the 2003 quarter. This increase was due to higher crude oil and natural gas sales volumes, primarily from the Medusa and Habanero fields, which came on stream in the fourth quarter of 2003, and higher crude oil sales prices. Also contributing to the improved results were $15.4 million in gains on disposal of several minor natural gas properties onshore United States. Production expenses and depreciation expense increased due to higher crude oil and natural gas sales volumes. Exploration expense increased $24 million over the 2003 period primarily due to increased dry hole costs in the Gulf of Mexico in the 2004 period.

Earnings from continuing operations in Canada were $53.6 million in the 2004 quarter versus $44.7 million in the 2003 quarter. The increase was primarily due to higher offshore and synthetic oil sales volumes and prices, partially offset by decreased light oil sales volumes. The Company’s Canadian subsidiaries entered into two binding agreements in early April to dispose of most of their Western Canadian conventional assets for total proceeds of C$830 million. Sale of assets under one agreement occurred on April 22, 2004. Closing of the other transaction is expected in May and is subject to due diligence provisions and normal regulatory approvals.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

The sale assets produce about 20,000 barrels of oil equivalent per day and have total reserves of approximately 46 million barrels equivalent from light oil, heavy oil, and natural gas properties.

U.K. operations earned $13.8 million in the 2004 period versus $19.1 million in the same quarter a year ago. Lower sales volumes for crude oil and lower realized selling prices during the period were the primary reasons for the lower earnings. The Company sold its interests in the Ninian and Columba fields in mid-2003.

Operations in Ecuador earned $2.9 million in 2004 compared to $5.5 million a year ago. Revenues increased due to higher sales volumes partially offset by lower sales prices. Higher sales volumes were attributable to start-up of a new third-party owned heavy oil pipeline in 2003. Higher costs for operating and depreciation expenses essentially offset higher revenues. Income tax expense was $2.6 million in 2004 and nil in 2003.

Malaysia reported a loss of $4 million in the first quarter of 2004 compared to a $5.5 million loss in the same period in 2003. Exploration expenses increased $9.1 million in the 2004 period due to higher dry hole costs, but these higher costs were more than offset by operating profits from the Company’s West Patricia field, which came on stream in May 2003.

On a worldwide basis, the Company’s crude oil and condensate sales price averaged $30.95 per barrel for the current quarter compared to $27.90 per barrel in the first quarter of 2003. In the first quarter of 2003, the Company’s hedging program reduced the average worldwide crude oil sales price by $3.16 per barrel. Average crude oil and liquids production from continuing operations was 95,128 barrels per day, up 40% over last year, and average sales volumes increased 32% to 94,180 barrels a day. The increase in oil production and sales volumes are primarily due to the Medusa and Habanero fields in the deepwater Gulf of Mexico and the West Patricia field in shallow-water Malaysia, all of which came on stream in mid to late 2003. North American natural gas sales prices averaged $5.88 per thousand cubic feet (MCF) in the most recent quarter compared to $5.95 per MCF in the same quarter of 2003. The Company’s 2003 hedging program reduced the average North American natural gas sales price by $.49 per MCF in the first quarter of 2003. Total natural gas sales volumes from continuing operations averaged 124 million cubic feet a day in 2004, up 7% from a year ago. The increase is primarily attributable to gas production from the new Medusa and Habanero fields partially offset by declines in Western Canada natural gas production.

Additional details about results of oil and gas operations are presented in the tables on page 19.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Selected operating statistics for the three-month periods ended March 31, 2004 and 2003 follow.


	Three Months Ended March 31,
	2004		2003
Net crude oil, condensate and gas liquids produced – barrels per day		102,426	74,984
Continuing operations		95,128	67,813
United States		18,705	3,319
Canada – light		731	1,612
– heavy		4,381	3,938
– offshore		28,879	27,792
– synthetic		12,527	9,343
United Kingdom		11,680	18,439
Malaysia		10,420	—
Ecuador		7,805	3,370
Discontinued operations		7,298	7,171

Net crude oil, condensate and gas liquids sold – barrels per day		101,478	78,299
Continuing operations		94,180	71,128
United States		18,705	3,319
Canada – light		731	1,612
– heavy		4,381	3,938
– offshore		30,486	29,807
– synthetic		12,527	9,343
United Kingdom		11,680	18,618
Ecuador		7,625	4,491
Malaysia		8,045	—
Discontinued operations		7,298	7,171

Net natural gas sold – thousands of cubic feet per day		212,555	228,164
Continuing operations		124,160	115,729
United States		98,515	77,958
Canada		14,564	26,135
United Kingdom		11,081	11,636
Discontinued operations		88,395	112,435

Total net hydrocarbons produced – equivalent barrels per day (1)		137,852	113,011

Total net hydrocarbons sold – equivalent barrels per day (1)		136,904	116,326

Weighted average sales prices
Crude oil and condensate – dollars a barrel (2)
United States	$	31.77	24.78	(4)
Canada (3) – light		33.59	29.55
– heavy		16.63	12.40	(4)
– offshore		31.54	28.12	(4)
– synthetic		34.56	25.63	(4)
United Kingdom		31.61	32.46
Malaysia		34.82	—
Ecuador		23.68	27.88

Natural gas – dollars a thousand cubic feet
United States (2)	$	5.97	6.30	(4)
Canada (3)		5.29	4.90	(4)
United Kingdom (3)		4.72	3.51

(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)	Includes the effects of the Company’s 2003 hedging program.

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

Results of Operations (Contd.)

Refining and Marketing

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


	Income (Loss)
	Three Months Ended March 31,
(Millions of dollars)	2004			2003
Refining and marketing
North America	$	(10.5	)	(6.4	)
United Kingdom		4.1		2.9

Total	$	(6.4	)	(3.5	)

Refining and marketing operations in North America reported a loss of $10.5 million during the first quarter of 2004 compared to a loss of $6.4 million in the same period a year ago. The larger loss was primarily attributable to poorer performance at the Meraux refinery, which is operating at less than optimum capacity during integration of a new unit and the rebuilding of the ROSE unit. The first quarter 2004 results also included a net after-tax gain of $3 million from sale of the Company’s jointly owned terminals in the U.S. Refining and marketing operations in the U.K. earned $4.1 million in the 2004 period, up from a $2.9 million profit in the same quarter of 2003, with the improved earnings based on better operating margins during the latest quarter. Worldwide refinery inputs were 170,888 barrels per day in the first quarter of 2004 compared to 160,940 barrels per day in the 2003 quarter. The 2003 quarter was lower due to operating problems encountered at the Company’s Meraux refinery. Petroleum product sales were a record 301,718 barrels a day, up from 228,261 a year ago. The Company was operating 136 more gasoline stations at Wal-Mart sites at March 31, 2004 compared to March 31, 2003.

Selected operating statistics for the three-month periods ended March 31, 2004 and 2003 follow.


	Three Months Ended March 31,
	2004	2003
Refinery inputs – barrels per day	170,888	160,940
North America	135,035	124,778
United Kingdom	35,853	36,162

Petroleum products sold – barrels per day	301,718	228,261
North America	266,630	195,689
Gasoline	183,480	130,489
Kerosine	8,307	7,969
Diesel and home heating oils	58,522	37,687
Residuals	13,076	14,421
Asphalt, LPG and other	3,245	5,123
United Kingdom	35,088	32,572
Gasoline	12,472	10,001
Kerosine	3,294	2,546
Diesel and home heating oils	12,944	13,177
Residuals	4,142	4,506
LPG and other	2,236	2,342

Corporate and other

Corporate activities, which include interest income and expense and corporate overhead not allocated to operating functions, reported a loss of $14.1 million in the 2004 quarter compared to income of $10.7 million in the first quarter of 2003. The 2004 period included lower interest capitalization because of start-up of the Medusa and Habanero fields and completion of the Meraux refinery expansion in late 2003. The 2003 period included a $20.1 million benefit from resolutions of prior years’ U.S. tax matters.

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

Financial Condition

Net cash provided by continuing operating activities was $265.7 million for the first three months of 2004 compared to $163.1 million during the same period in 2003. Changes in operating working capital other than cash and cash equivalents provided cash of $75.2 million in the first quarter of 2004 and $34.5 million in the 2003 period.

Other predominant uses of cash in both years were for dividends, which totaled $18.4 million in 2004 and 2003 and for capital expenditures, which, including amounts expensed, are summarized in the following table.


	Three Months Ended March 31,
(Millions of dollars)	2004			2003
Capital expenditures – continuing operations
Exploration and production	$	164.2		116.6
Refining and marketing		34.1		50.4
Corporate and other		.3		.2

Total capital expenditures – continuing operations		198.6		167.2
Geological, geophysical and other exploration expenses charged to income		(3.1	)	(9.1	)

Total property additions and dry holes – continuing operations	$	195.5		158.1

Working capital at March 31, 2004 was $197.5 million, down $31 million from December 31, 2003. This level of working capital does not fully reflect the Company’s liquidity position, because the lower historical costs assigned to inventories under last-in first-out accounting were $198.6 million below fair value at March 31, 2004.

At March 31, 2004, long-term notes payable of $1,000.3 million were down $61.1 million from December 31, 2003 due to repayments of borrowings under existing revolving credit facilities. Long-term nonrecourse debt of a subsidiary was $22.6 million, down $6.3 million from December 31, 2003 due to scheduled repayments. A summary of capital employed at March 31, 2004 and December 31, 2003 follows.


(Millions of dollars)	March 31, 2004			Dec. 31, 2003
	Amount		%	Amount		%
Capital Employed
Notes payable	$	1,000.3	32.8		1,061.4	34.9
Nonrecourse debt of a subsidiary		22.6	.7		28.9	1.0
Stockholders’ equity		2,026.5	66.5		1,950.9	64.1

Total capital employed	$	3,049.4	100.0	$	3,041.2	100.0

Accounting and Other Matters

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

Accounting and Other Matters (Contd.)

mineral leases have been amortized over the life of the lease period, while developed mineral leases have been amortized using the units of production method over the expected life of proved reserves. The amounts included herein are based on our understanding of the issue on the EITF’s agenda. If all mineral leases associated with oil and gas properties are deemed to be intangible assets in accordance with SFAS No. 141 and SFAS No. 142 by the EITF:

•

These assets would not be included in Property, Plant and Equipment on our Consolidated Balance Sheet

•

Disclosures required by SFAS No. 141 and SFAS No. 142 relative to intangible assets would be included in the notes to the financial statements

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 March 31, 2004, the Company has a receivable of approximately $9.5 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

Crude oil and natural gas sales prices have remained strong during April 2004. Production from continuing operations is expected to average 117,000 barrels of oil equivalent per day in the second quarter 2004. The Front Runner field, in the deepwater Gulf of Mexico, is expected to start up production in the fourth quarter 2004. A portion of the previously announced sale of Western Canadian assets closed in April 2004, and the sale of the remaining assets is expected to close in May 2004. In April, the Company’s Board of Directors approved a development plan for the Kikeh field in deepwater Block K, Malaysia. PETRONAS and the Company’s 20% partner, PETRONAS Carigali, must also approve the Kikeh development plan. The development plan calls for first production in late 2007. North American refining and marketing margins have improved early in the second quarter 2004 compared to the just completed first quarter.

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

CONTINUING OIL AND GAS OPERATING RESULTS (unaudited)


(Millions of dollars)	United States		Canada	United King- dom	Ecua- dor	Malay- sia		Other		Synthetic Oil – Canada	Total
Three Months Ended March 31, 2004
Oil and gas sales and other operating revenues	$	131.3	103.1	38.4	16.4	25.6		1.0		39.4	355.2
Production expenses		17.9	9.2	6.4	7.9	2.7		—		19.7	63.8
Depreciation, depletion and amortization		16.9	25.9	7.3	2.9	5.3		—		2.7	61.0
Accretion expense		.9	.7	.7	—	.1		.1		.1	2.6
Exploration expenses
Dry holes		28.6	—	—	—	13.4		.1		—	42.1
Geological and geophysical		1.3	.7	—	—	.1		.2		—	2.3
Other		.4	.2	.1	—	—		.1		—	.8

		30.3	.9	.1	—	13.5		.4		—	45.2
Undeveloped lease amortization		3.3	.6	—	—	—		—		—	3.9

Total exploration expenses		33.6	1.5	.1	—	13.5		.4		—	49.1

Selling and general expenses		5.8	2.4	.8	.1	1.3		2.2		.2	12.8
Income tax provisions (benefits)		19.7	20.9	9.3	2.6	6.7		(.1	)	5.6	64.7

Results of operations (excluding corporate overhead and interest)	$	36.5	42.5	13.8	2.9	(4.0	)	(1.6	)	11.1	101.2

Three Months Ended March 31, 2003
Oil and gas sales and other operating revenues	$	50.7	96.0	58.2	11.3	—		.7		21.5	238.4
Production expenses		7.8	8.2	11.5	4.2	—		—		14.4	46.1
Depreciation, depletion and amortization		8.3	21.7	9.6	1.5	.2		.1		2.0	43.4
Accretion expense		.8	.5	.9	—	—		.1		.1	2.4
Exploration expenses
Dry holes		2.9	—	—	—	—		—		—	2.9
Geological and geophysical		3.6	.3	—	—	4.4		—		—	8.3
Other		.5	.1	.1	—	—		.1		—	.8

		7.0	.4	.1	—	4.4		.1		—	12.0
Undeveloped lease amortization		2.6	.8	—	—	—		—		—	3.4

Total exploration expenses		9.6	1.2	.1	—	4.4		.1		—	15.4

Selling and general expenses		4.6	2.2	1.1	.1	.9		1.6		.1	10.6
Income tax provisions (benefits)		6.8	20.8	15.9	—	—		(.3	)	1.6	44.8

Results of operations (excluding corporate overhead and interest)	$	12.8	41.4	19.1	5.5	(5.5	)	(.9	)	3.3	75.7

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 D 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 March 31, 2004 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 March 31, 2004, the interest rate to be received by the Company averaged 1.11%. 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 $1.2 million at March 31, 2004, with the offsetting loss recorded in Accumulated Other Comprehensive Income (AOCI) in Stockholders’ Equity.

At March 31, 2004, 37% of the Company’s debt had variable interest rates and 2% was denominated in Canadian dollars. Based on debt outstanding at March 31, 2004, a 10% increase in variable interest rates would increase the Company’s interest expense approximately $.6 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 $.4 million for debt denominated in Canadian dollars.

Murphy was a party to natural gas price swap agreements at March 31, 2004 for a remaining notional volume of 7.4 MMBTU that are intended to hedge the financial exposure of its Meraux, Louisiana and Superior, Wisconsin refineries to fluctuations in the future price of a portion of natural gas to be purchased for fuel from April 1, 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 March 31, 2004, the estimated fair value of these agreements was recorded as an asset of $22 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $3.9 million, while a 10% decrease would have reduced the asset by a similar amount. Additionally, the Company was a party to natural gas price swap agreements at March 31, 2004 for a total notional volume of 4.3 MMBTU that effectively fixed the settlement price for the natural gas purchase swaps maturing in April through October 2004. The terms are nearly identical to the aforementioned swaps and require Murphy to pay the average NYMEX price for the final three trading days of the month and receive an average natural gas price of $5.235. At March 31, 2004 the estimated fair value of these agreements was recorded as a liability of $2.9 million. A 10% increase in the average index price of natural gas would have increased this liability by $2.5 million, while a 10% decrease would have reduced this liability by a similar amount.

At March 31, 2004, the Company was a party to natural gas put options covering 5.3 MMBTU in future natural gas sales during April through October. The options are intended to hedge the financial exposure of the Company’s natural gas sales in the U.S. should the future selling price during the contract period fall below a $4.00 floor price. At March 31, 2004, the estimated fair value of these agreements was recorded as an asset valued at less than $.1 million. A 10% change in the price of natural gas would not have a significant impact on this asset.

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 the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, 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 Rules 13a-15 under the Securities Exchange Act of 1934) are effective 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 first quarter of 2004 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)	The Exhibit Index on page 22 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 February 5, 2004 that included the Company’s news release announcing the Company’s earnings and certain other financial information as of and for the three-month and twelve months periods that ended December 31, 2003.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


*MURPHY OIL CORPORATION*
(Registrant)

By		/s/ JOHN W. ECKART

		John W. Eckart, Controller
		(Chief Accounting Officer and Duly Authorized Officer)

May 7, 2004

(Date)

EXHIBIT INDEX


Exhibit No.

3.2*		By-Laws of Murphy Oil Corporation as amended effective February 4, 2004

12.1*		Computation of Ratio of Earnings to Fixed Charges

31.1*		Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*		Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32		Certifications 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.