Edgar Filing: MURPHY OIL CORP /DE

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Form 10-Q

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, 2008

¨	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 a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

Number of shares of Common Stock, $1.00 par value, outstanding at June 30, 2008 was 190,434,726.

MURPHY OIL CORPORATION

TABLE OF CONTENTS


		Page
Part I – Financial Information
	Item 1. Financial Statements
	Consolidated Balance Sheets	2
	Consolidated Statements of Income	3
	Consolidated Statements of Comprehensive Income	4
	Consolidated Statements of Cash Flows	5
	Consolidated Statements of Stockholders’ Equity	6
	Notes to Consolidated Financial Statements	7

	Item 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition	15

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	26

	Item 4. Controls and Procedures	26

Part II – Other Information

	Item 1. Legal Proceedings	27

	Item 1A. Risk Factors	27

	Item 4. Submission of Matters to a Vote of Security Holders	28

	Item 6. Exhibits and Reports on Form 8-K	28

Signature		29

PART I – FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)


	(Unaudited) June 30, 2008			December 31, 2007
ASSETS
Current assets
Cash and cash equivalents	$	1,116,505		673,707
Short-term investments in marketable securities		345,072		—
Accounts receivable, less allowance for doubtful accounts of $7,373 in 2008 and $7,484 in 2007		1,867,986		1,420,601
Inventories, at lower of cost or market
Crude oil and blend stocks		151,640		159,379
Finished products		432,317		315,977
Materials and supplies		172,794		151,291
Prepaid expenses		81,147		79,585
Deferred income taxes		89,484		86,252

Total current assets		4,256,945		2,886,792
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $3,672,435 in 2008 and $3,516,338 in 2007		7,430,872		7,109,822
Goodwill		44,605		51,450
Deferred charges and other assets		498,774		487,785

Total assets	$	12,231,196		10,535,849


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	3,070		5,208
Notes payable		—		7,561
Accounts payable and accrued liabilities		2,366,712		1,987,710
Income taxes payable		325,711		108,783

Total current liabilities		2,695,493		2,109,262

Notes payable		1,540,118		1,513,015
Nonrecourse debt of a subsidiary		—		3,141
Deferred income taxes		1,036,177		916,910
Asset retirement obligations		360,425		336,107
Deferred credits and other liabilities		532,540		564,374
Minority interest		—		26,866

Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued		—		—
Common Stock, par $1.00, authorized 450,000,000 shares, issued 190,973,101 shares in 2008 and 189,972,970 shares in 2007		190,973		189,973
Capital in excess of par value		609,411		547,185
Retained earnings		4,940,967		3,983,998
Accumulated other comprehensive income		339,126		351,765
Treasury stock, 538,375 shares of Common Stock in 2008 and 258,821 shares in 2007, at cost		(14,034	)	(6,747	)

Total stockholders’ equity		6,066,443		5,066,174

Total liabilities and stockholders’ equity	$	12,231,196		10,535,849

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page 30.

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,
	2008			2007		2008		2007
REVENUES
Sales and other operating revenues	$	8,268,139		4,614,598		14,758,013		8,042,184
Gain on sale of assets		91,860		455		134,246		808
Interest and other income		3,151		(1,426	)	3,622		5,519

Total revenues		8,363,150		4,613,627		14,895,881		8,048,511


COSTS AND EXPENSES
Crude oil and product purchases		6,660,439		3,654,703		11,816,490		6,379,087
Operating expenses		431,205		309,952		832,085		606,435
Exploration expenses, including undeveloped lease amortization		60,400		30,168		126,896		78,504
Selling and general expenses		55,569		54,729		114,457		107,718
Depreciation, depletion and amortization		165,272		114,740		338,094		222,727
Impairment of long-lived assets		—		40,708		—		40,708
Accretion of asset retirement obligations		5,128		3,802		10,284		7,264
Interest expense		21,551		17,121		42,704		32,610
Interest capitalized		(5,995	)	(16,588	)	(12,944	)	(31,245	)
Minority interest		—		(2	)	298		24

Total costs and expenses		7,393,569		4,209,333		13,268,364		7,443,832

Income before income taxes		969,581		404,294		1,627,517		604,679
Income tax expense		350,377		154,052		599,321		243,803

NET INCOME	$	619,204		250,242		1,028,196		360,876


INCOME PER COMMON SHARE
NET INCOME – BASIC	$	3.27		1.33		5.43		1.93
NET INCOME – DILUTED	$	3.22		1.32		5.36		1.90
Average common shares outstanding – basic		189,564,247		187,615,633		189,372,416		187,361,136
Average common shares outstanding – diluted		192,263,483		190,160,989		191,832,034		189,954,414

See Notes to Consolidated Financial Statements, page 7.

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,
	2008		2007	2008		2007
Net income	$	619,204	250,242	1,028,196		360,876
Other comprehensive income (loss), net of tax
Foreign currency translation		11,525	100,277	(12,034	)	109,757
Retirement and postretirement benefit plan adjustments		884	5,628	(605	)	5,628

COMPREHENSIVE INCOME	$	631,613	356,147	1,015,557		476,261

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)


	Six Months Ended June 30,
	2008			2007
OPERATING ACTIVITIES
Net income	$	1,028,196		360,876
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		338,094		222,727
Impairment of long-lived assets		—		40,708
Amortization of deferred major repair costs		13,176		10,062
Expenditures for asset retirements		(2,928	)	(3,872	)
Dry hole costs		11,005		28,420
Amortization of undeveloped leases		56,515		12,846
Accretion of asset retirement obligations		10,284		7,264
Deferred and noncurrent income tax charges		162,553		18,971
Pretax gain from disposition of assets		(134,246	)	(808	)
Net (increase) decrease in noncash operating working capital		616		(31,522	)
Other operating activities, net		25,321		17,639

Net cash provided by operating activities		1,508,586		683,311


INVESTING ACTIVITIES
Property additions and dry hole costs		(1,014,916	)	(813,426	)
Proceeds from sales of assets		360,677		17,944
Purchase of marketable securities		(345,072	)	—
Expenditures for major repairs		(33,152	)	(8,214	)
Other – net		(11,615	)	(6,924	)

Net cash required by investing activities		(1,044,078	)	(810,620	)


FINANCING ACTIVITIES
Increase in notes payable		27,000		279,950
Decrease in nonrecourse debt of a subsidiary		(5,235	)	(4,884	)
Proceeds from exercise of stock options and employee stock purchase plans		20,443		20,791
Excess tax benefits related to exercise of stock options		18,310		10,706
Cash dividends paid		(71,227	)	(56,420	)
Other		—		(759	)

Net cash provided (required) by financing activities		(10,709	)	249,384

Effect of exchange rate changes on cash and cash equivalents		(11,001	)	27,991

Net increase in cash and cash equivalents		442,798		150,066
Cash and cash equivalents at January 1		673,707		543,390

Cash and cash equivalents at June 30	$	1,116,505		693,456


SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid	$	161,745		143,319
Interest paid more than (less than) amounts capitalized		29,774		(66	)

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)


	Six Months Ended June 30,
	2008			2007
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued		—		—

Common Stock – par $1.00, authorized 450,000,000 shares, issued 190,973,101 shares at June 30, 2008 and 188,767,558 shares at June 30, 2007
Balance at beginning of period	$	189,973		187,692
Exercise of stock options		1,000		1,043
Issuance of time-lapse restricted stock		—		33

Balance at end of period		190,973		188,768


Capital in Excess of Par Value
Balance at beginning of period		547,185		454,860
Exercise of stock options, including income tax benefits		39,958		30,717
Restricted stock transactions and other		6,961		3,794
Stock-based compensation		15,307		11,365
Sale of stock under employee stock purchase plans		—		584

Balance at end of period		609,411		501,320


Retained Earnings
Balance at beginning of period		3,983,998		3,349,832
Cumulative effect of changes in accounting principles		—		(5,010	)
Net income for the period		1,028,196		360,876
Cash dividends		(71,227	)	(56,420	)

Balance at end of period		4,940,967		3,649,278


Accumulated Other Comprehensive Income
Balance at beginning of period		351,765		131,999
Cumulative effect of change in accounting principle		—		1,345
Foreign currency translation gains (losses), net of income taxes		(12,034	)	109,757
Retirement and postretirement benefit plan adjustments, net of income taxes		(605	)	5,628

Balance at end of period		339,126		248,729


Treasury Stock
Balance at beginning of period		(6,747	)	(3,110	)
Sale of stock under employee stock purchase plans		363		620
Cancellation of performance-based restricted stock and forfeitures		(7,650	)	(4,396	)

Balance at end of period		(14,034	)	(6,886	)

Total Stockholders’ Equity	$	6,066,443		4,581,209

See notes to consolidated financial statements, page 7

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 2 through 6 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, 2007. 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, 2008, and the results of operations, cash flows and changes in stockholders’ equity for the three-month and six-month periods ended June 30, 2008 and 2007, in conformity with accounting principles generally accepted in the United States. In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the United States, management has made a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Actual results may differ from the estimates.

Financial statements and notes to consolidated financial statements included in this Form 10-Q report should be read in conjunction with the Company’s 2007 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and six-month periods ended June 30, 2008 are not necessarily indicative of future results.

The financial information for the second quarter and first six months of 2008, as furnished to the SEC on Form 8-K on July 30, 2008, is amended with the filing of this Form 10-Q to include subsequent exploration expense of $12.5 million ($7.8 million after tax).

Note B – Property, Plant and Equipment

The FASB Staff Position (FSP) 19-1 applies to companies that use the successful efforts method of accounting and it clarifies that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

At June 30, 2008, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $282.0 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2008 and 2007.


(Thousands of dollars)	2008			2007
Beginning balance at January 1	$	272,155		315,445
Additions pending the determination of proved reserves		16,748		19,063
Reclassifications to proved properties based on the determination of proved reserves		(6,869	)	(7,168	)

Balance at June 30	$	282,034		327,340

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed for each individual well and the number of projects for which exploratory well costs have been capitalized. The projects are aged based on the last well drilled in the project.


	June 30,
	2008				2007
(Thousands of dollars)	Amount		No. of Wells	No. of Projects	Amount		No. of Wells	No. of Projects
Aging of capitalized well costs:
Zero to one year	$	19,891	2	1	$	36,561	15	1
One to two years		26,473	11	1		133,806	24	1
Two to three years		122,796	19	2		130,973	13	7
Three years or more		112,874	11	6		26,000	3	2

	$	282,034	43	10	$	327,340	55	11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note B – Property, Plant and Equipment (Contd.)

Of the $262.1 million of exploratory well costs capitalized more than one year at June 30, 2008, $169.5 million is in Malaysia, $60.2 million is in the Republic of Congo, $27.0 million is in the U.S., and $5.4 million is in Canada. In Malaysia either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. In the Republic of Congo a development program is underway for the offshore Azurite field. In the U.S. drilling and development operations are planned, and in Canada a continuing drilling and development program is underway.

In May 2008, the Company sold its interest in the Lloydminster area properties in Western Canada for a pretax gain of $91.3 million ($67.9 million after-tax). In January 2008, the Company sold its interest in Berkana Energy Corporation and recorded a pretax gain of $42.3 million ($40.4 million after-tax).

Note C – Employee and Retiree Benefit 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.

The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June 30, 2008 and 2007.


	Three Months Ended June 30,
	2008			2007		2008		2007
(Thousands of dollars)	Pension Benefits					Postretirement Benefits
Service cost	$	4,562		2,759		628		537
Interest cost		6,673		6,268		1,285		1,024
Expected return on plan assets		(5,829	)	(5,605	)	—		—
Amortization of prior service cost		340		350		(66	)	(62	)
Amortization of transitional asset		(131	)	(121	)	—		—
Recognized actuarial loss		1,025		1,451		421		373

Net periodic benefit expense	$	6,640		5,102		2,268		1,872


	Six Months Ended June 30,
	2008			2007		2008		2007
(Thousands of dollars)	Pension Benefits					Postretirement Benefits
Service cost	$	9,100		5,443		1,237		1,074
Interest cost		13,414		12,272		2,535		2,048
Expected return on plan assets		(11,686	)	(10,951	)	—		—
Amortization of prior service cost		684		696		(131	)	(124	)
Amortization of transitional asset		(263	)	(234	)	—		—
Recognized actuarial loss		2,041		2,840		830		746

Net periodic benefit expense	$	13,290		10,066		4,471		3,744

The increase in net periodic benefit expense in 2008 compared to 2007 is primarily due to the December 1, 2007 purchase of the remaining 70% interest in the Milford Haven, Wales refinery.

Beginning in 2008 the Company has reduced its expected annual return on U.S. retirement plan assets from 7.0% to 6.5%.

Murphy previously disclosed in its financial statements for the year ended December 31, 2007, that it expected to contribute $56.6 million to its defined benefit pension plans and $4.7 million to its postretirement benefits plan during 2008. During the six-month period ended June 30, 2008, the Company made contributions of $31.7 million and remaining funding in 2008 for the Company’s domestic and foreign defined benefit pension and postretirement plans is anticipated to be $29.6 million.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Incentive Plans

SFAS No. 123R, Share Based Payment, requires that the cost resulting from all share-based payment transactions be recognized as an expense in the financial statements using a fair value-based measurement method over the periods that the awards vest. The Company adopted SFAS No. 123R on January 1, 2006. Prior to 2006, the Company used APB No. 25 to account for stock-based compensation.

The 2007 Annual Incentive Plan (2007 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and other key employees. Cash awards under the 2007 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. The 2007 Long-Term Incentive Plan (2007 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units, performance units, performance shares, dividend equivalents and other stock-based incentives. The 2007 Long-Term Plan expires in 2017. A total of 6,700,000 shares are issuable during the life of the 2007 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding. The Employee Stock Purchase Plan was amended to increase the number of shares authorized to be issued under the plan from 600,000 to 980,000, and to extend the term of the plan through June 30, 2017. The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors.

In February 2008, the Committee granted stock options for 932,500 shares at an exercise price of $72.745 per share. The Black-Scholes valuation for these awards was $17.69 per option. The Committee also granted 328,000 performance-based restricted stock units and 60,000 shares of time-lapse restricted stock units in February 2008 under the 2007 Long-Term Plan approved by shareholders on May 9, 2007. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, was $59.445 per unit, while the time-lapse restricted stock units were valued at $71.78 per unit. Also in February the Committee granted 24,930 shares of time-lapse restricted stock to the Company’s Directors under the 2003 Director Plan. These shares vest on the third anniversary of the date of grant. The fair value of these awards was estimated based on the fair market value of the Company’s stock on the date of grant, which was $71.78 per share.

Cash received from options exercised under all share-based payment arrangements for the six-month periods ended June 30, 2008 and 2007 was $20.4 million and $20.8 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $20.2 million and $12.5 million for the six-month periods ended June 30, 2008 and 2007, respectively.

Amounts recognized in the financial statements with respect to share-based plans are as follows.


	Six Months Ended June 30,
*(Thousands of dollars)*	2008		2007
Compensation charged against income before tax benefit	$	16,158	13,495
Related income tax benefit recognized in income		5,321	4,721

Note E – Earnings per Share

Net income was used as the numerator in computing both basic and diluted income per Common share for the three-month and six-month periods ended June 30, 2008 and 2007. 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)	2008	2007	2008	2007
Basic method	189,564,247	187,615,633	189,372,416	187,361,136
Dilutive stock options	2,699,236	2,545,356	2,459,618	2,593,278

Diluted method	192,263,483	190,160,989	191,832,034	189,954,414

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – Earnings per Share (Contd.)

Certain options to purchase shares of common stock were outstanding during the 2008 and 2007 periods but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. These included 928,500 shares at a weighted average share price of $72.745 in each 2008 period and 1,548,929 shares at a weighted average share price of $53.70 in each 2007 period.

Note F – Financial Instruments and Risk Management

Murphy periodically 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. The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks.

•

Crude Oil Purchase Price Risks – The Company purchases crude oil as feedstock at its U.S. and U.K. refineries and is therefore subject to commodity price risk. Short-term derivative instruments were outstanding at June 30, 2008 and 2007 to manage the cost of about 0.7 million barrels and 1.2 million barrels, respectively, of crude oil at the Company’s Meraux, Louisiana refinery. The impact on consolidated income before taxes from marking these derivative contracts to market as of the balance sheet date was a benefit of $1.0 million and a charge of $1.9 million in the six-month periods ended June 30, 2008 and 2007, respectively.

•

Foreign Currency Exchange Risks – The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. Short-term derivative instruments were outstanding at June 30, 2008 to manage the risk of $83 million of U.S. dollar balances associated with the Company’s Canadian operation and the risk of $97 million equivalent of Ringgit balances in the Company’s Malaysian operations. The impact on consolidated income before taxes from marking these derivative contracts to market as of the balance sheet date was a charge of $1.1 million in the six-month period ended June 30, 2008.

Note G – Accumulated Other Comprehensive Income

The components of Accumulated Other Comprehensive Income (AOCI) on the Consolidated Balance Sheets at June 30, 2008 and December 31, 2007 are presented in the following table.


(Thousands of dollars)	June 30, 2008			Dec. 31, 2007
Foreign currency translation gains, net of tax	$	416,504		428,538
Retirement and postretirement benefit plan adjustments, net of tax		(77,378	)	(76,773	)

Accumulated other comprehensive income	$	339,126		351,765

Note H – Environmental and 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, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Environmental and Other Contingencies (Contd.)

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 125 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. Although regulatory authorities may require more costly alternatives than the proposed processes, the cost of such potential alternative processes is not expected to exceed the accrued liability by a material amount.

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 minimis party as to ultimate responsibility at both Superfund sites. The Company has not recorded a liability for remedial costs on 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 believes that its share of the ultimate costs to clean-up the two Superfund sites will be immaterial and will not have a material adverse effect on its net income, financial condition or liquidity 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 the Company’s future net income, cash flows or liquidity.

On September 9, 2005, a class action lawsuit was filed in federal court in the Eastern District of Louisiana seeking unspecified damages to the class comprised of residents of St. Bernard Parish caused by a release of crude oil at Murphy Oil USA, Inc.’s (a wholly-owned subsidiary of Murphy Oil Corporation) Meraux, Louisiana, refinery as a result of flood damage to a crude oil storage tank following Hurricane Katrina. Additional class action lawsuits were consolidated with the first suit into a single action in the U.S. District Court for the Eastern District of Louisiana. In September 2006, the Company reached a settlement with class counsel and on October 10, 2006, the court granted preliminary approval of a class action Settlement Agreement. A Fairness Hearing was held January 4, 2007 and the court entered its ruling on January 30, 2007 approving the class settlement. The majority of the settlement of $330 million will be paid by insurance. The Company recorded an expense of $18 million in 2006 related to settlement costs not expected to be covered by insurance. As part of the settlement, all properties in the class area received a fair and equitable cash payment and have had residual oil cleaned. As part of the settlement, the Company offered to purchase all properties in an agreed area adjacent to the west side of the Meraux refinery; these property purchases and associated remediation have been paid by the Company at a cost of $55 million. As of June 30, 2008, the Company has fulfilled its obligations under the Class Action Settlement Agreement. Approximately 40 non-class action suits regarding the oil spill have been filed and remain pending. The Company believes that insurance coverage exists and it does not expect to incur significant costs associated with this litigation. On August 14, 2007, four of the Company’s high level excess insurers noticed the Company for arbitration in London. The insurers do not deny coverage, but seek arbitration as to whether and to what extent expenditures made by the Company in resolving the oil spill litigation have reached the attachment point for covered loss under their respective policies. The Company is of the position that full coverage should be afforded. Accordingly, the Company believes neither the ultimate resolution of the remaining litigation nor the insurance arbitration will have a material adverse effect on its net income, financial condition or liquidity in a future period.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Environmental and Other Contingencies (Contd.)

St. Bernard Parish amended their petition to include a direct action against certain of the Company’s liability insurers. The St. Bernard Parish action has since been removed to federal court, which issued an order on July 25, 2008 denying plaintiff’s request to certify the case as a class action. In responding to this direct action, one of the Company’s insurers, AEGIS, has raised lack of coverage as a defense. The Company believes that this contention lacks merit and has been advised by counsel that the applicable policy does provide coverage for the underlying incident. Because the Company believes that insurance coverage exists for this matter, it does not expect to incur any significant costs associated with the lawsuits. Accordingly, the Company continues to believe that the ultimate resolution of the June 2003 ROSE fire litigation will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. 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 net income, financial condition or liquidity 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, 2008, the Company had contingent liabilities of $8.5 million under a financial guarantee and $199.9 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.

Note I – Accounting Matters

In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, Fair Value Measurements (SFAS No. 157). This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements, and where applicable simplifies and codifies related guidance within GAAP and does not require any new fair value measurements. The statement was originally effective for fiscal years beginning January 1, 2008. On February 12, 2008, the FASB issued FSP No. 157-2 that delayed for one year the effective date of SFAS No. 157 for most nonfinancial assets and nonfinancial liabilities. Provisions of the statement are to be applied prospectively except in limited situations. The Company adopted this statement as of January 1, 2008 and the adoption had no material impact on its consolidated financial statements. See further disclosures at Note J.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159). This pronouncement permits companies with eligible financial assets and financial liabilities to measure these items at fair value in the financial statements. This option to measure at fair value is both instrument specific and irrevocable. If the fair value option is elected, certain additional disclosures are required and financial statements for periods prior to the adoption may not be restated. The Company adopted this standard as of January 1, 2008, but the Company chose not to elect fair value measurement for any financial assets and financial liabilities, and therefore, the adoption of SFAS No. 159, had no impact on the Company’s consolidated balance sheet or consolidated statement of income.

In June 2007, the FASB ratified the Emerging Issues Task Force’s Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF No. 06-11). This new guidance was effective for the Company beginning in January 2008 and required that income tax benefits received by the Company for dividends paid on share-based incentive awards be recorded in Capital in Excess of Par Value in Stockholders’ Equity. Under certain circumstances, such tax benefits received on awards that do not vest could be reclassified to reduce income tax expense in the Consolidated Statements of Income. The effect of adopting EITF No. 06-11 was not material to the Company’s consolidated financial statements.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51. Upon adoption, this statement will require noncontrolling interests to be reclassified as equity, and consolidated net income and comprehensive income shall include the respective results attributable to noncontrolling interests. This statement is effective for the Company beginning January 1, 2009. It is to be applied prospectively and early adoption is not permitted. The Company does not expect this statement to have a significant effect on its consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Accounting Matters (Contd.)

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations. This statement establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquired business. It also establishes how to recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, if applicable. This statement shall be applied prospectively by the Company to any business combination that occurs on or after January 1, 2009. Early application is prohibited. Assets and liabilities that arise from business combinations occurring prior to 2009 shall not be adjusted upon application of this statement. This statement will impact the recognition and measurement of assets and liabilities in business combinations that occur after 2008, and the Company is unable to predict at this time how the application of this statement will affect its financial statements in future periods.

In March 2008, the FASB issued SFAS No. 161, Disclosure about Derivative Instruments and Hedging Activities. This statement is effective for the Company beginning in January 2009, and it expands required disclosures regarding derivative instruments to include qualitative information about objectives and strategies for using derivatives, quantities disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk related contingent features in derivative agreements. The Company does not expect this statement to have a significant effect on its consolidated financial statements.

Note J – Assets and Liabilities Measured at Fair Value

As described in Note I, the Company adopted SFAS No. 157, Fair Value Measurements (SFAS No. 157), on January 1, 2008, other than for nonrecurring nonfinancial assets and liabilities, which will be effective for the Company on January 1, 2009. SFAS No. 157 establishes a fair value hierarchy based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.

The fair value measurements for the Company’s financial assets and liabilities accounted for at fair value on a recurring basis at June 30, 2008 are presented in the following table.


			Fair Value Measurements at Reporting Date Using
(thousands of dollars)	June 30, 2008		Quoted Prices in Active Markets for Identical Assets (Liabilities) (Level 1)	Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
Assets
Short-term investments in marketable securities	$	345,072	345,072	—	—
Commodity derivatives		1,016	—	1,016	—

Total assets at fair value	$	346,088	345,072	1,016	—

Liabilities
Foreign exchange derivatives	$	1,097	—	1,097	—
Nonqualified employee savings plan		11,472	11,472	—	—

Total liabilities at fair value	$	12,569	11,472	1,097	—

Short-term investments in marketable securities represent investment in Canadian securities with maturity dates greater than 90 days at the date of acquisition. Market value for these securities approximates cost plus earned interest.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Business Segments


			Three Mos. Ended June 30, 2008					Three Mos. Ended June 30, 2007
(Millions of dollars)	Total Assets at June 30, 2008		External Revenues		Inter- segment Revenues	Income (Loss)		External Revenues		Inter- segment Revenues	Income (Loss)
Exploration and production*
United States	$	1,328.1	182.5		—	71.4		104.7		—	23.8
Canada		2,208.1	450.3		26.7	236.4		218.1		22.0	91.0
United Kingdom		208.8	37.5		—	14.4		45.3		—	14.8
Malaysia		2,510.3	544.1		—	263.4		48.8		—	15.1
Ecuador		117.7	18.9		—	.7		37.1		—	9.9
Other		334.8	(.6	)	—	(9.1	)	.8		—	(5.3	)

Total		6,707.8	1,232.7		26.7	577.2		454.8		22.0	149.3

Refining and marketing
North America		2,779.1	5,532.8		—	5.0		3,871.7		—	107.2
United Kingdom		1,202.8	1,594.6		—	72.3		288.5		—	17.0

Total		3,981.9	7,127.4		—	77.3		4,160.2		—	124.2

Total operating segments		10,689.7	8,360.1		26.7	654.5		4,615.0		22.0	273.5
Corporate		1,541.5	3.1		—	(35.3	)	(1.4	)	—	(23.2	)

Total	$	12,231.2	8,363.2		26.7	619.2		4,613.6		22.0	250.3


	Six Months Ended June 30, 2008					Six Months Ended June 30, 2007
(Millions of dollars)	External Revenues		Inter- segment Revenues	Income (Loss)		External Revenues	Inter- segment Revenues	Income (Loss)
Exploration and production*
United States	$	325.6	—	118.5		198.6	—	34.5
Canada		776.3	50.2	387.7		397.5	45.1	156.5
United Kingdom		123.6	—	46.5		82.8	—	26.9
Malaysia		1,008.7	—	468.1		92.9	—	24.9
Ecuador		42.1	—	1.5		62.5	—	14.0
Other		.8	—	(17.1	)	1.9	—	(18.7	)

Total		2,277.1	50.2	1,005.2		836.2	45.1	238.1

Refining and marketing
North America		10,063.0	—	6.0		6,692.2	—	141.7
United Kingdom		2,552.2	—	81.5		514.6	—	18.2

Total		12,615.2	—	87.5		7,206.8	—	159.9

Total operating segments		14,892.3	50.2	1,092.7		8,043.0	45.1	398.0
Corporate		3.6	—	(64.5	)	5.5	—	(37.1	)

Total	$	14,895.9	50.2	1,028.2		8,048.5	45.1	360.9

*	Additional details about results of oil and gas operations are presented in the tables on pages 20 and 21.

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 2008 was $619.2 million, $3.22 per diluted share, compared to net income of $250.3 million, $1.32 per diluted share, in the second quarter of 2007. The higher income in 2008 primarily related to improved earnings in the Company’s exploration and production business, but this was partially offset by lower earnings in the refining and marketing operations and higher net costs for corporate activities. Net income in the second quarter 2008 included an after-tax gain of $67.9 million on sale of Lloydminster heavy oil properties in Western Canada. Net income in the second quarter 2007 included after-tax costs of $24.0 million for closure of 55 retail gasoline stations in the U.S. and Canada and non-cash income tax benefits of $4.8 million related to an enacted Canadian income tax rate reduction.

For the first six months of 2008, net income totaled $1,028.2 million, $5.36 per diluted share, compared to net income of $360.9 million, $1.90 per diluted share, for the same period in 2007. The higher six-month income in 2008 compared to 2007 was primarily attributable to higher earnings in the exploration and production business, partially offset by weaker earnings in 2008 in the refining and marketing operations.

Murphy’s net income by operating segment is presented below.


	Income (Loss)
	Three Months Ended June 30,					Six Months Ended June 30,
(Millions of dollars)	2008			2007		2008		2007
Exploration and production	$	577.2		149.3		1,005.2		238.1
Refining and marketing		77.3		124.2		87.5		159.9
Corporate		(35.3	)	(23.2	)	(64.5	)	(37.1	)

Net income	$	619.2		250.3		1,028.2		360.9

In the 2008 second quarter, the Company’s exploration and production operations earned $577.2 million compared to $149.3 million in the 2007 quarter. Income in the 2008 quarter was favorably affected by higher crude oil and natural gas sales prices, higher crude oil sales volumes and a $67.9 million after-tax gain on sale of Lloydminster properties. Income in the 2007 quarter included non-cash Canadian income tax benefits of $4.8 million related to an enacted tax rate reduction. Exploration expenses were $60.4 million in the second quarter of 2008 compared to $30.1 million in the same period of 2007. The Company’s refining and marketing operations generated income of $77.3 million in the 2008 second quarter compared to income of $124.2 million in the same quarter of 2007. North American refining margins were much weaker in the second quarter 2008 compared to the 2007 period, but income for the United Kingdom downstream business improved significantly in the 2008 second quarter due to stronger refining margins and a larger refining operation in the current period following the acquisition of 70% of the Milford Haven, Wales refinery in December 2007. The 2007 second quarter included $24.0 million of after-tax costs related to closure of 55 North American gasoline stations. The after-tax costs of the corporate function were $35.3 million in the 2008 second quarter compared to $23.2 million in the 2007 period with the cost increase due to higher net interest costs and administrative costs in 2008.

Net income was $1,028.2 million in the first six months of 2008 compared to $360.9 million in the same 2007 period. The Company’s exploration and production operations earned $1,005.2 million in the first half of 2008 compared to $238.1 million in the same period of 2007. Earnings in 2008 benefited from significantly higher realized oil prices, higher oil and gas sales volumes, and gains on sale of assets. The 2007 six-month period included non-cash Canadian income tax benefits of $4.8 million. The Company’s refining and marketing operations had earnings of $87.5 million in the first six months of 2008, compared to earnings of $159.9 million in the same 2007 period. The 2008 period included weaker results in the North American downstream business compared to a year ago, but income from downstream operations in the U.K. improved in 2008 compared to 2007 due to better margins in refining operations and higher sales volumes due to the Milford Haven refinery acquisition in December 2007. Corporate after-tax costs were $64.5 million in the 2008 period compared to costs of $37.1 million in the 2007 period. Higher net interest expenses, unfavorable foreign currency exchange results and higher administrative expenses accounted for the higher net costs in 2008.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production

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


	Income (Loss)
	Three Months Ended June 30,					Six Months Ended June 30,
(Millions of dollars)	2008			2007		2008		2007
Exploration and production
United States	$	71.4		23.8		118.5		34.5
Canada		236.4		91.0		387.7		156.5
United Kingdom		14.4		14.8		46.5		26.9
Malaysia		263.4		15.1		468.1		24.9
Ecuador		.7		9.9		1.5		14.0
Other International		(9.1	)	(5.3	)	(17.1	)	(18.7	)

Total	$	577.2		149.3		1,005.2		238.1

Second quarter 2008 vs. 2007

United States exploration and production operations reported quarterly earnings of $71.4 million in the second quarter of 2008 compared to earnings of $23.8 million in the 2007 quarter. Earnings were higher in the 2008 period due mostly to higher oil and natural gas sales prices. Lower oil production volumes were mostly attributable to less production in the Gulf of Mexico. Production expense in the 2008 period was less than 2007 due mostly to lower workover and maintenance expenses. Depreciation expense was higher in 2008 primarily due to higher per unit depletion rates. Exploration expenses in the 2008 period decreased $2.6 million from the prior year primarily due to lower dry hole costs, somewhat offset by higher geological and geophysical expenses.

Operations in Canada earned $236.4 million in the second quarter 2008 compared to $91.0 million in the 2007 quarter. Canadian earnings improved in the 2008 quarter mostly due to higher oil sales prices and a $67.9 million after-tax gain on sale of Lloydminster heavy oil properties in Western Canada. Oil production and sales volumes declined in the 2008 period compared to 2007 primarily due to lower oil produced offshore Eastern Canada. Natural gas volumes declined in 2008 mostly due to sale of Berkana Energy in January 2008. Production expenses in Canada were unfavorable in 2008 due primarily to higher energy costs at Syncrude. Depreciation expenses were lower due to less oil and natural gas production and sale of properties. Exploration expenses were $21.1 million higher in the 2008 period due to more lease amortization expense attributable to the Tupper natural gas area in British Columbia. The 2007 quarter included $4.8 million in non-cash income tax benefits related to an enacted Federal tax rate reduction.

United Kingdom operations earned $14.4 million in the 2008 quarter, down slightly from $14.8 million in the 2007 quarter. The decline was primarily due to lower crude oil sales volumes in the 2008 quarter compared to 2007, but was mostly offset by higher sales prices for crude oil and natural gas and higher natural gas sales volumes. Production and depreciation expenses were less in 2008 due to the lower crude oil sales volumes.

Operations in Malaysia reported earnings of $263.4 million in the 2008 quarter compared to earnings of $15.1 million during the same period in 2007. The earnings improvement in 2008 in Malaysia was primarily due to higher crude oil sales volumes caused by the start-up of the Kikeh field in the third quarter of 2007. Production and depreciation expenses were higher in the current period also due to higher sales volumes. Exploration expense was higher in 2008 due to an unsuccessful exploration well in Block K. Selling and general expense was lower in the 2008 period due to higher charges to production and development operations under the joint operating agreement at Kikeh.

Operations in Ecuador earned $0.7 million in the second quarter of 2008 compared to $9.9 million in the 2007 period. The 2008 period results were unfavorable primarily due to a combination of lower realized oil sales prices caused by higher revenue sharing taken by the Ecuadorian government in the 2008 quarter and lower crude oil sales volumes. Beginning in mid-October 2007, the government claimed 99% of crude oil sales prices that exceeded a benchmark price, which was approximately $23.88 per barrel in June 2008. Prior to this change, the government’s revenue sharing was 50% of realized prices that exceeded the benchmark price. Production expense was lower in 2008 due to less crude oil sales volumes.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Second quarter 2008 vs. 2007 (Contd.)

Other international operations reported a loss of $9.1 million in the second quarter of 2008 compared to a loss of $5.3 million in the 2007 period. The unfavorable variance was primarily related to higher exploration and administrative costs in 2008 for Indonesia, Australia and other foreign jurisdictions.

On a worldwide basis, the Company’s crude oil and condensate prices averaged $110.14 per barrel in the second quarter 2008 compared to $57.19 in the 2007 period. Average crude oil and liquids production was 111,493 barrels per day in the second quarter of 2008 compared to 79,949 barrels per day in the second quarter of 2007, with the increase primarily attributable to start-up of the Kikeh field in Malaysia in the third quarter 2007. Crude oil production was lower in the U.S. in 2008 mostly due to field decline at Front Runner in the Gulf of Mexico. Canadian light oil production was less in 2008 due to the sale of Berkana Energy in January 2008. Canadian offshore crude oil production fell in 2008 due to a production decline at the Hibernia field and more equipment downtime and a higher royalty rate at the Terra Nova field. Ecuador oil production was lower in 2008 due to less drilling activity in Block 16 following the change to increase the government revenue share in 2007. North American natural gas sales prices averaged $11.70 per thousand cubic feet (MCF) in the most recent quarter compared to $8.02 per MCF in the same quarter of 2007. Natural gas sales volumes averaged 55 million cubic feet per day in the second quarter 2008, down from 57 million cubic feet per day in the 2007 quarter, primarily due to lower volumes in Canada caused by the sale of Berkana Energy in January 2008. U.S. natural gas sales volumes increased in the 2008 quarter due to new drilling in the Tahoe field and start-up of the Mondo NW field in July 2007. Natural gas sales increased in the U.K. in 2008 primarily due to higher volumes sold from the Mungo/Monan fields in the North Sea.

Six months 2008 vs. 2007

U.S. E&P operations produced income of $118.5 million for the six months ended June 30, 2008 compared to income of $34.5 million in the 2007 period. The 2008 period had higher oil and natural gas sales prices and higher natural gas sales volumes, but lower crude oil sales volumes. Production expenses were lower in 2008 mostly due to less costs for workovers and other field maintenance. Depreciation expense was unfavorable in 2008 due to higher per-unit depletion rates compared to 2007. Exploration expenses in the 2008 period were $13.3 million lower than 2007 due to virtually no dry holes expense in 2008, but partially offset by higher geological and geophysical expenses in 2008.

Canadian operations earned $387.7 million in the first half of 2008 compared to $156.5 million a year ago. Higher sales prices for crude oil and natural gas and after-tax gains of $108.3 million on sales of properties primarily led to the increase in earnings. Higher production expenses in 2008 were mostly related to higher energy costs at Syncrude. Lower depreciation expense in 2008 was attributable to less volumes produced and sold. Exploration expenses were $48.3 million higher in 2008 primarily due to more seismic costs and higher undeveloped lease amortization for new acreage acquired at the Tupper field in British Columbia.

Income in the U.K. for the six-month period in 2008 was $46.5 million compared to $26.9 million a year ago with the increase primarily due to higher oil and natural gas sales prices, partially offset by lower crude oil sales volumes.

Malaysia operations earned $468.1 million in the first half of 2008 compared to earnings of $24.9 million in the 2007 period. The earnings improvement was primarily caused by higher crude oil sales volumes associated with the start-up of the Kikeh field, offshore Sabah, in the third quarter of 2007. Average crude oil sales prices were also significantly higher in 2008 than in 2007. Production and depreciation expenses were significantly higher and were related to the new Kikeh field production. Exploration expense was higher in 2008 mostly due to 3-D seismic acquisition and processing over a portion of Block P, offshore Sabah, and an unsuccessful exploration well in Block K. Selling and general expense declined in 2008 due to higher levels of costs charged to production and development operations.

Earnings in Ecuador were $1.5 million for the first six months of 2008 compared to $14.0 million for the 2007 period. The earnings decline in 2008 was due to higher revenue sharing with the government for sales prices above a benchmark price. In addition, crude oil production and associated sales volumes were lower in 2008 due to less spending on development drilling following the increase in government revenue sharing in 2007.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Six months 2008 vs. 2007 (Contd.)

Other international operations reported a loss of $17.1 million in the first six months of 2007 compared to a loss of $18.7 million in the 2007 period. The smaller loss in the 2008 period was primarily due to higher geophysical expenses in the Republic of Congo in 2007, but partially offset by higher costs in 2008 for exploration and administrative activities in other foreign jurisdictions.

For the first six months of 2008, the Company’s sales price for crude oil and condensate averaged $96.73 per barrel compared to $52.47 per barrel in 2007. Crude oil, condensate and gas liquids production in the first half of 2008 averaged 112,416 barrels per day compared to 82,241 barrels per day a year ago. The increase was mostly attributable to Kikeh field production, offshore Malaysia, but production volumes were lower at the Front Runner field in the Gulf of Mexico, the heavy oil producing area of Western Canada, the Terra Nova field offshore Eastern Canada, and the West Patricia field, offshore Sarawak, Malaysia. The average sales price for North American natural gas in the first six months of 2008 was $9.83 per MCF, up from $7.64 per MCF in 2007. Natural gas sales volumes were up from 59 million cubic feet per day in 2007 to 62 million cubic feet per day in 2008, with the increase due mostly to higher gas production volumes from the Tahoe and Mondo NW fields in the deepwater Gulf of Mexico, but partially offset by lower gas volumes in Canada caused by the sale of Berkana Energy in January 2008.

Additional details about results of oil and gas operations are presented in the tables on pages 20 and 21.

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, 2008 and 2007 follow.


	Three Months Ended June 30,			Six Months Ended June 30,
	2008		2007	2008	2007
Net crude oil, condensate and gas liquids produced – barrels per day		111,493	79,949	112,416	82,241
United States		12,880	13,458	12,496	13,775
Canada – light		—	592	93	560
– heavy		9,259	9,554	9,583	11,224
– offshore		16,555	20,843	17,636	19,666
– synthetic		11,305	11,427	11,368	12,073
United Kingdom		5,335	5,461	6,031	5,887
Malaysia		48,382	9,578	47,380	9,990
Ecuador		7,777	9,036	7,829	9,066

Net crude oil, condensate and gas liquids sold – barrels per day		110,366	83,629	118,649	84,046
United States		12,880	13,458	12,496	13,775
Canada – light		—	592	93	560
– heavy		9,259	9,554	9,583	11,224
– offshore		16,241	21,705	16,697	20,150
– synthetic		11,305	11,427	11,368	12,073
United Kingdom		2,618	6,859	5,695	6,675
Malaysia		51,310	9,885	54,728	9,899
Ecuador		6,753	10,149	7,989	9,690

Net natural gas sold – thousands of cubic feet per day		54,739	56,579	61,861	58,837
United States		44,806	41,879	50,845	42,596
Canada		2,068	8,655	3,254	9,054
United Kingdom		7,865	6,045	7,762	7,187

Total net hydrocarbons produced – equivalent barrels per day (1)		120,616	89,379	122,726	92,047
Total net hydrocarbons sold – equivalent barrels per day (1)		119,489	93,059	128,959	93,852

Weighted average sales prices – Crude oil and condensate – dollars per barrel (2)
United States	$	117.99	59.39	105.25	54.84
Canada (3) – light		—	49.66	70.37	50.40
– heavy		81.76	29.65	67.19	31.18
– offshore		121.21	67.19	108.44	61.43
– synthetic		129.51	69.92	114.96	63.91
United Kingdom		121.77	66.68	103.86	61.59
Malaysia (4)		115.45	55.47	101.86	51.66
Ecuador (5)		30.17	40.14	28.46	35.55

Natural gas – dollars per thousand cubic feet
United States (2)	$	11.83	8.18	9.98	7.76
Canada (3)		8.80	7.22	7.44	7.08
United Kingdom (3)		11.46	6.58	10.98	6.76

(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)	Prices are net of payments under the terms of the production sharing contracts for Blocks SK 309 and K.

(5)	All prices are net of revenue sharing with the Ecuadorian government.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED JUNE 30, 2008 AND 2007


(Millions of dollars)	United States			Canada		United Kingdom	Malaysia		Ecuador	Other		Synthetic Oil – Canada	Total
Three Months Ended June 30, 2008
Oil and gas sales and other revenues	$	182.5		343.0		37.5	544.1		18.9	(.6	)	134.0	1,259.4
Production expenses		15.8		22.6		3.2	55.6		7.7	—		52.9	157.8
Depreciation, depletion and amortization		28.4		30.0		3.7	51.4		9.9	.2		6.5	130.1
Accretion of asset retirement obligations		1.5		1.1		.6	1.3		—	.2		.2	4.9
Exploration expenses
Dry holes		(.3	)	—		—	11.1		—	—		—	10.8
Geological and geophysical		11.9		2.1		—	(.5	)	—	.1		—	13.6
Other		2.8		.1		.3	.1		—	3.7		—	7.0

		14.4		2.2		.3	10.7		—	3.8		—	31.4
Undeveloped lease amortization		6.6		22.1		—	—		—	.3		—	29.0

Total exploration expenses		21.0		24.3		.3	10.7		—	4.1		—	60.4

Selling and general expenses		4.9		3.2		.8	(.7	)	.2	4.3		.2	12.9

Results of operations before taxes		110.9		261.8		28.9	425.8		1.1	(9.4	)	74.2	893.3
Income tax provisions (benefits)		39.5		76.5		14.5	162.4		.4	(.3	)	23.1	316.1

Results of operations (excluding corporate overhead and interest)	$	71.4		185.3		14.4	263.4		.7	(9.1	)	51.1	577.2


Three Months Ended June 30, 2007
Oil and gas sales and other revenues	$	104.7		167.5		45.3	48.8		37.1	.8		72.6	476.8
Production expenses		17.2		26.6		7.3	10.1		9.7	—		29.0	99.9
Depreciation, depletion and amortization		16.7		40.0		6.6	7.5		10.2	.2		6.0	87.2
Accretion of asset retirement obligations		1.0		1.2		.5	.9		—	.1		.1	3.8
Exploration expenses
Dry holes		14.3		(.1	)	—	.1		.1	(.4	)	—	14.0
Geological and geophysical		1.6		1.5		—	.3		—	1.7		—	5.1
Other		3.3		.1		.1	—		—	1.0		—	4.5

		19.2		1.5		.1	.4		.1	2.3		—	23.6
Undeveloped lease amortization		4.4		1.7		—	—		—	.4		—	6.5

Total exploration expenses		23.6		3.2		.1	.4		.1	2.7		—	30.1

Impairment of long-lived assets		2.6		—		—	—		—	—		—	2.6
Selling and general expenses		6.8		4.4		.9	3.0		.3	2.9		.2	18.5

Results of operations before taxes		36.8		92.1		29.9	26.9		16.8	(5.1	)	37.3	234.7
Income tax provisions		13.0		28.4		15.1	11.8		6.9	.2		10.0	85.4

Results of operations (excluding corporate overhead and interest)	$	23.8		63.7		14.8	15.1		9.9	(5.3	)	27.3	149.3

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2008 AND 2007


(Millions of dollars)	United States		Canada	United Kingdom	Malaysia	Ecuador	Other		Synthetic Oil – Canada	Total
Six Months Ended June 30, 2008
Oil and gas sales and other revenues	$	325.6	587.9	123.6	1,008.7	42.1	.8		238.6	2,327.3
Production expenses		32.7	46.5	13.2	109.0	17.3	—		101.0	319.7
Depreciation, depletion and amortization		55.6	59.9	14.0	103.5	22.1	.4		13.2	268.7
Accretion of asset retirement obligations		2.9	2.4	1.1	2.6	—	.4		.4	9.8
Exploration expenses
Dry holes		.2	—	—	10.8	—	—		—	11.0
Geological and geophysical		22.1	12.6	—	12.2	—	.7		—	47.6
Other		4.3	.2	.4	.1	—	6.8		—	11.8

		26.6	12.8	.4	23.1	—	7.5		—	70.4
Undeveloped lease amortization		11.7	44.1	—	—	—	.7		—	56.5

Total exploration expenses		38.3	56.9	.4	23.1	—	8.2		—	126.9

Selling and general expenses		12.0	6.8	1.8	.5	.3	8.8		.4	30.6
Minority interest		—	.3	—	—	—	—		—	.3

Results of operations before taxes		184.1	415.1	93.1	770.0	2.4	(17.0	)	123.6	1,571.3
Income tax provisions		65.6	113.3	46.6	301.9	.9	.1		37.7	566.1

Results of operations (excluding corporate overhead and interest)	$	118.5	301.8	46.5	468.1	1.5	(17.1	)	85.9	1,005.2


Six Months Ended June 30, 2007
Oil and gas sales and other revenues	$	198.6	303.0	82.8	92.9	62.5	1.9		139.6	881.3
Production expenses		43.4	46.8	13.2	17.2	18.8	—		60.5	199.9
Depreciation, depletion and amortization		33.4	75.4	12.4	15.8	18.7	.3		11.8	167.8
Accretion of asset retirement obligations		1.8	2.2	1.0	1.6	—	.3		.3	7.2
Exploration expenses
Dry holes		27.5	.9	—	.1	.3	(.4	)	—	28.4
Geological and geophysical		11.4	4.3	—	5.1	—	9.1		—	29.9
Other		3.8	.2	.2	—	—	3.1		—	7.3

		42.7	5.4	.2	5.2	.3	11.8		—	65.6
Undeveloped lease amortization		8.9	3.2	–	–	–	.8		—	12.9

Total exploration expenses		51.6	8.6	.2	5.2	.3	12.6		—	78.5

Impairment of long-lived assets		2.6	—	—	—	—	—		—	2.6
Selling and general expenses		12.3	8.5	1.9	6.8	.5	6.9		.4	37.3

Results of operations before taxes		53.5	161.5	54.1	46.3	24.2	(18.2	)	66.6	388.0
Income tax provisions		19.0	51.9	27.2	21.4	10.2	.5		19.7	149.9

Results of operations (excluding corporate overhead and interest)	$	34.5	109.6	26.9	24.9	14.0	(18.7	)	46.9	238.1

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,
(Millions of dollars)	2008		2007	2008	2007
Refining and marketing
North America	$	5.0	107.2	6.0	141.7
United Kingdom		72.3	17.0	81.5	18.2

Total	$	77.3	124.2	87.5	159.9

The Company’s refining and marketing operations generated income of $77.3 million in the 2008 second quarter compared to earnings of $124.2 million in the same quarter of 2007. North American operations had a profit of $5.0 million in the 2008 period compared to $107.2 million in 2007. Refining margins in the U.S. were quite weak in the second quarter of 2008 as refined product sales prices did not keep pace with rising crude oil prices. U.S. refining margins were very strong in the second quarter of 2007. The 2007 second quarter included $24.0 million of after-tax costs associated with closure of 55 retail gasoline stations in the U.S. and Canada. Earnings in the United Kingdom were $72.3 million in the second quarter of 2008 compared to earnings of $17.0 million in the same period a year ago. The 2008 quarter benefited from stronger U.K. refinery margins and a larger U.K. refining operation due to the Company’s purchase of 70% of the Milford Haven, Wales refinery in December 2007. Worldwide petroleum product sales averaged 549,539 barrels per day in 2008, compared to 439,099 barrels per day in the same period in 2007. The 2008 sales volume increase was attributable to both higher U.S. sales volumes at the Company’s retail marketing operations and higher sales volumes in the U.K. associated with the Milford Haven refinery acquisition. Worldwide refinery inputs were 246,080 barrels per day in the second quarter of 2008 compared to 181,149 in the 2007 quarter. Refinery inputs in 2008 increased in the U.K. due to the Milford Haven acquisition, but were lower in the U.S. due to a plant-wide turnaround at the Superior, Wisconsin refinery during the second quarter.

Refining and marketing operations in the first half of 2008 generated a profit of $87.5 million compared to a profit of $159.9 million in the 2007 period. In North America, the 2008 profit of $6.0 million was significantly lower than the 2007 profit of $141.7 million. Current year results were unfavorable mostly due to much weaker refining margins in the 2008 period compared to 2007. The 2007 period included after-tax costs of $24.0 million related to closing 55 retail gasoline stations in North America. Results in the United Kingdom reflected earnings of $81.5 million in the first six months of 2008 compared to earnings of $18.2 million in the 2007 period. The increase was primarily due to stronger refining margins on sale of petroleum products in 2008 and the benefit from higher volumes related to the Milford Haven refinery acquisition.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Refining and Marketing (Contd.)

Selected operating statistics for the three-month and six-month periods ended June 30, 2008 and 2007 follow.


	Three Months Ended June 30,		Six Months Ended June 30,
	2008	2007	2008	2007
Refinery inputs – barrels per day	246,080	181,149	245,294	180,542
North America	126,860	145,289	131,205	147,714
United Kingdom	119,220	35,860	114,089	32,828

Petroleum products sold – barrels per day	549,539	439,099	536,800	430,597
North America	423,363	402,720	425,387	395,117
Gasoline	310,422	298,161	309,103	286,505
Kerosine	88	209	2,011	1,808
Diesel and home heating oils	92,520	79,559	94,824	83,873
Residuals	15,550	15,897	14,409	15,627
Asphalt, LPG and other	4,783	8,894	5,040	7,304
United Kingdom	126,176	36,379	111,413	35,480
Gasoline	41,394	11,174	36,019	11,667
Kerosine	14,196	3,667	12,229	3,412
Diesel and home heating oils	45,488	11,870	36,529	12,134
Residuals	14,200	3,674	13,290	3,373
LPG and other	10,898	5,994	13,346	4,894

Corporate

Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had net costs of $35.3 million in the 2008 second quarter compared to net costs of $23.2 million in the second quarter of 2007. Net costs increased in 2008 compared to 2007 due to a combination of higher administrative expenses due mostly to increased staffing costs and higher net interest expense associated with higher average borrowing levels and lower amounts capitalized to oil and gas development projects. The Company capitalized most of its interest expense to the Kikeh oil development project in the second quarter of 2007.

For the first six months of 2008, corporate activities reflected net costs of $64.5 million compared to net costs of $37.1 million a year ago. The increase in six-month costs in 2008 related to higher foreign exchange losses, higher net interest expense due mostly to lower interest capitalized to development projects in the latter period, and higher administrative costs. Total after-tax costs for foreign currency exchange movements were $10.7 million in the 2008 period compared to $5.5 million in the first six months of 2007.

Financial Condition

Net cash provided by operating activities was $1,508.6 million for the first six months of 2008 compared to $683.3 million during the same period in 2007. Changes in operating working capital other than cash and cash equivalents provided cash of $0.6 million in the first six months of 2008, but used cash of $31.5 million in the 2007 period.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Financial Condition (Contd.)

Other predominant uses of cash in both years were for dividends, which totaled $71.2 million in 2008 and $56.4 million in 2007, and for property additions and dry holes, which, including amounts expensed, were $1,014.9 million and $813.4 million in the six-month periods ended June 30, 2008 and 2007, respectively. Total capital expenditures were as follows:


	Six Months Ended June 30,
(Millions of dollars)	2008		2007
Capital Expenditures
Exploration and production	$	867.7	787.2
Refining and marketing		220.2	98.3
Corporate and other		1.8	2.1

Total capital expenditures		1,089.7	887.6

Working capital (total current assets less total current liabilities) at June 30, 2008 was $1,561.4 million, up $783.9 million from December 31, 2007. 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 $1,204.2 million below fair value at June 30, 2008.

At June 30, 2008, long-term notes payable of $1,540.1 million had increased in total by $27.1 million compared to December 31, 2007. A summary of capital employed at June 30, 2008 and December 31, 2007 follows.


	June 30, 2008			Dec. 31, 2007
(Millions of dollars)	Amount		%	Amount		%
Capital employed
Notes payable	$	1,540.1	20.2	$	1,513.0	23.0
Nonrecourse debt of a subsidiary		—	—		3.2	0.1
Stockholders’ equity		6,066.4	79.8		5,066.2	76.9

Total capital employed	$	7,606.5	100.0	$	6,582.4	100.0

The Company’s ratio of earnings to fixed charges was 29.0 to 1 for the six-month period ended June 30, 2008.

Accounting and Other Matters

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159). This pronouncement permits companies with eligible financial assets and financial liabilities to measure these items at fair value in the financial statements. This option to measure at fair value is both instrument specific and irrevocable. If the fair value option is elected, certain additional disclosures are required and financial statements for periods prior to the adoption may not be restated. This pronouncement was effective January 1, 2008 for the Company. The Company chose not to elect fair value measurement for any financial assets and financial liabilities, and therefore, the adoption of SFAS No. 159, had no impact on the Company’s consolidated balance sheet or consolidated statement of income.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Accounting and Other Matters (Contd.)

In June 2007, the FASB ratified the Emerging Issues Task Force’s Issue No. 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF 06-11). This new guidance was effective for the Company beginning January 1, 2008 and required that income tax benefits received by the Company for dividends paid on share-based incentive awards be recorded in Capital in Excess of Par Value in Stockholders’ Equity. Under certain circumstances, such tax benefits received on awards that do not vest could be reclassified to reduce income tax expense in the Consolidated Statements of Income. The effect of adopting EITF No. 06-11 was not material to the Company’s consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, Disclosure about Derivative Instruments and Hedging Activities. This statement is effective for the Company beginning in January 2009, and it expands required disclosures regarding derivative instruments to include qualitative information about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. The Company does not expect this statement to have a significant effect on its consolidated financial statements.

Murphy holds a 20% interest in Block 16 Ecuador, where the Company and its partners produce oil for export. On October 18, 2007, the government of Ecuador enacted into law a levy that increases from 50% to 99% its share of oil sales prices that exceed a threshold reference price that was about $23.88 per barrel at June 30, 2008. The Company and its partners in Block 16 have filed for arbitration with an international arbitrator as permitted by its participation contract. The Company has also filed for arbitration under the bilateral investment treaty between the U.S. and Ecuador. While arbitration proceedings are ongoing the Block 16 partners have been negotiating contractual changes with the Ecuadorian government. Such negotiations have thus far been unsuccessful. Commencing with the April revenue sharing, which was scheduled to be paid in June, the Company and its partners ceased to pay any of the 99% revenue sharing to the Ecuadorian government pending the completion of arbitration proceedings. The Company continues to reduce its recorded revenue and has accrued a liability for the entire 99% revenue sharing without prejudice to the claims in the arbitration. Should the arbitration, negotiations and other designated security arrangements fail to permit the Company to recover its investment, the Company could have to record an impairment charge to reduce its investment in Block 16 in a future period. The Company’s carrying value of fixed assets in Ecuador at June 30, 2008 amounted to $90 million.

Outlook

Average crude oil prices in July 2008 weakened somewhat compared to the average price during the second quarter of 2008. The Company expects its oil and natural gas production to average about 128,000 barrels of oil equivalent per day in the third quarter. U.S. downstream margins had improved during July 2008 due to the easing of crude oil prices, but U.K. downstream margins had weakened considerably during July compared to the second quarter of 2008 average. The Company currently anticipates total capital expenditures for the full year 2008 to be approximately $3.0 billion.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

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 F to this Form 10-Q report, Murphy periodically makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions. There were short-term derivative contracts in place at June 30, 2008 to hedge the cost of about 0.7 million barrels of crude oil at the Meraux refinery. A 10% increase in the price of West Texas Intermediate crude oil would have increased the asset associated with this derivative contract by approximately $0.4 million, while a 10% decrease would have reduced the asset by a similar amount. In addition, there were short-term contracts existing at June 30, 2008 to hedge approximately US$83 million in Canada and US$97 million equivalent Malaysian ringgits. A 10% increase in the value of the U.S. dollar against the Canadian dollar and Malaysian ringgit would have increased the Company’s liability associated with the derivative contracts by approximately $16.4 million, while a 10% decrease would have decreased the net liability by a similar amount.

ITEM 4.

CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company 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(e) and 15d-15(e) 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 have been no changes in the Company’s internal control over financial reporting during the quarter ended June 30, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

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, 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. On May 5, 2004, plaintiffs in the consolidated action in St. Bernard Parish amended their petition to include a direct action against certain of the Company’s liability insurers. The St. Bernard Parish action has since been removed to federal court, which issued an order on July 25, 2008 denying plaintiff’s request to certify the case as a class action. In responding to this direct action, one of the Company’s insurers, AEGIS, has raised lack of coverage as a defense. The Company believes that this contention lacks merit and has been advised by counsel that the applicable policy does provide coverage for the underlying incident. Because the Company believes that insurance coverage exists for this matter, it does not expect to incur any significant costs associated with the lawsuits. Accordingly, the Company continues to believe that the ultimate resolution of the June 2003 ROSE fire litigation will not have a material adverse effect on its net income, financial condition or liquidity in a future period.

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. 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 net income, financial condition or liquidity in a future period.

ITEM 1A.

RISK FACTORS

The Company has not identified any additional risk factors not previously disclosed in its Form 10-K filed on February 29, 2008.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At the annual meeting of security holders on May 14, 2008, the directors proposed by management were elected with a tabulation of votes to the nearest share as shown below.


	For	Withheld
Frank W. Blue	165,359,315	3,426,646
Claiborne P. Deming	165,684,801	3,101,160
Robert A. Hermes	161,109,087	7,676,874
James V. Kelley	161,131,195	7,654,766
R. Madison Murphy	152,776,119	16,009,842
William C. Nolan Jr.	164,381,596	4,404,365
Ivar B. Ramberg	166,268,874	2,517,087
Neal E. Schmale	161,113,583	7,672,378
David J. H. Smith	161,276,748	7,509,213
Caroline G. Theus	165,426,335	3,359,626

The 2008 Stock Plan for Non-Employee Directors was approved with 137,210,314 shares voted in favor and 20,146,994 shares voted in opposition.

A shareholder proposal concerning the Company’s non-discrimination in employment policy was defeated with 12,951,226 shares voted in favor and 132,791,921 shares voted in opposition.

The earlier appointment by the Audit Committee of the Board of Directors of KPMG LLP as independent registered public accounting firm for 2008 was approved with 165,577,639 shares voted in favor and 1,929,799 shares voted in opposition.

ITEM 6.

EXHIBITS AND REPORTS ON FORM 8-K

(a)	The Exhibit Index on page 30 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 7, 2008 announcing that the Company’s Stockholder Rights Plan dated December 6, 1989 and subsequently amended on April 6, 1998 and April 15, 1999 had expired normally on April 6, 2008.

(c)	A report on Form 8-K was filed on May 1, 2008 that included a News Release dated April 30, 2008 announcing the Company’s earnings and certain other financial information for the three-month period ended March 31, 2008.

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, Vice President and Controller (Chief Accounting Officer and Duly Authorized Officer)

August 8, 2008

(Date)

EXHIBIT INDEX


Exhibit No.
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.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company