Murphy Oil 10Q 2008 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

For the quarterly period ended September 30, 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.

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨

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 September 30, 2008 was190,484,694.

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 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) September 30, 2008			December 31, 2007
ASSETS
Current assets
Cash and cash equivalents	$	828,100		673,707
Canadian government securities with maturities greater than 90 days at the date of acquisition		611,110		—
Accounts receivable, less allowance for doubtful accounts of $7,379 in 2008 and $7,484 in 2007		1,431,346		1,420,601
Inventories, at lower of cost or market
Crude oil and blend stocks		189,237		159,379
Finished products		253,289		315,977
Materials and supplies		178,638		151,291
Prepaid expenses		77,721		79,585
Deferred income taxes		68,436		86,252

Total current assets		3,637,877		2,886,792

Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $3,799,516 in 2008 and $3,516,338 in 2007		7,628,956		7,109,822
Goodwill		42,805		51,450
Deferred charges and other assets		521,132		487,785

Total assets	$	11,830,770		10,535,849

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	2,946		5,208
Notes payable		—		7,561
Accounts payable and accrued liabilities		1,834,319		1,987,710
Income taxes payable		471,835		108,783

Total current liabilities		2,309,100		2,109,262

Notes payable		1,066,170		1,513,015
Nonrecourse debt of a subsidiary		—		3,141
Deferred income taxes		1,023,270		916,910
Asset retirement obligations		363,759		336,107
Deferred credits and other liabilities		548,966		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 191,022,032 shares in 2008 and 189,972,970 shares in 2007		191,022		189,973
Capital in excess of par value		618,579		547,185
Retained earnings		5,477,781		3,983,998
Accumulated other comprehensive income		246,130		351,765
Treasury stock, 537,338 shares of Common Stock in 2008 and 258,821 shares in 2007, at cost		(14,007	)	(6,747	)

Total stockholders’ equity		6,519,505		5,066,174

Total liabilities and stockholders’ equity	$	11,830,770		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 September 30,					Nine Months Ended September 30,
	2008			2007		2008		2007
REVENUES
Sales and other operating revenues	$	8,203,293		4,773,039		22,961,306		12,815,223
Gain on sale of assets		336		224		134,582		1,032
Interest and other income		(17,596	)	7,469		(13,974	)	12,988

Total revenues		8,186,033		4,780,732		23,081,914		12,829,243

COSTS AND EXPENSES
Crude oil and product purchases		6,495,942		3,909,009		18,312,432		10,288,096
Operating expenses		440,697		320,037		1,272,782		926,472
Exploration expenses, including undeveloped lease amortization		83,440		42,531		210,336		121,035
Selling and general expenses		56,552		65,591		171,009		173,309
Depreciation, depletion and amortization		174,635		114,289		512,729		337,016
Impairment of long-lived assets		—		—		—		40,708
Accretion of asset retirement obligations		5,346		4,197		15,630		11,461
Interest expense		16,622		19,837		59,326		52,447
Interest capitalized		(7,292	)	(12,419	)	(20,236	)	(43,664	)
Minority interest		—		(448	)	298		(424	)

Total costs and expenses		7,265,942		4,462,624		20,534,306		11,906,456

Income before income taxes		920,091		318,108		2,547,608		922,787
Income tax expense		335,669		118,573		934,990		362,376

NET INCOME	$	584,422		199,535		1,612,618		560,411

NET INCOME PER COMMON SHARE
BASIC	$	3.08		1.06		8.51		2.99
DILUTED		3.04		1.04		8.39		2.94

Average common shares outstanding – basic		189,787,636		188,239,267		189,499,657		187,716,385
Average common shares outstanding – diluted		192,243,448		191,193,266		192,219,610		190,764,460

See Notes to Consolidated Financial Statements on page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2008			2007	2008		2007
Net income	$	584,422		199,535	1,612,618		560,411

Other comprehensive income (loss), net of tax
Foreign currency translation		(93,818	)	102,088	(105,852	)	211,845
Retirement and postretirement benefit plan adjustments		822		1,461	217		7,089

COMPREHENSIVE INCOME	$	491,426		303,084	1,506,983		779,345

See Notes to Consolidated Financial Statements on page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)


	Nine Months Ended September 30,
	2008			2007
OPERATING ACTIVITIES
Net income	$	1,612,618		560,411
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		512,729		337,016
Impairment of long-lived assets		—		40,708
Amortization of deferred major repair costs		20,551		15,894
Expenditures for asset retirements		(7,213	)	(4,642	)
Dry hole costs		53,883		37,570
Amortization of undeveloped leases		85,428		20,811
Accretion of asset retirement obligations		15,630		11,461
Deferred and noncurrent income tax charges		217,347		31,599
Pretax gains from disposition of assets		(134,582	)	(1,032	)
Net (increase) decrease in noncash operating working capital		184,478		(199,639	)
Other		35,795		64,867

Net cash provided by operating activities		2,596,664		915,024

INVESTING ACTIVITIES
Property additions and dry hole costs		(1,560,146	)	(1,279,470	)
Proceeds from sales of assets		361,339		18,751
Purchases of marketable securities		(611,110	)	(59,821	)
Expenditures for major repairs		(38,665	)	(9,304	)
Other – net		(13,690	)	(9,069	)

Net cash required by investing activities		(1,862,272	)	(1,338,913	)

FINANCING ACTIVITIES
Increase in notes payable		—		668,323
Reductions in notes payable		(447,195	)	—
Decrease in nonrecourse debt of a subsidiary		(5,235	)	(4,886	)
Proceeds from exercise of stock options and employee stock purchase plans		21,463		33,837
Excess tax benefits related to exercise of stock options		18,667		21,069
Cash dividends paid		(118,835	)	(91,802	)
Other		—		(759	)

Net cash (required by) provided by financing activities		(531,135	)	625,782

Effect of exchange rate changes on cash and cash equivalents		(48,864	)	44,382

Net increase in cash and cash equivalents		154,393		246,275
Cash and cash equivalents at January 1		673,707		543,390

Cash and cash equivalents at September 30	$	828,100		789,665

SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid, net of refunds	$	254,138		249,057

Interest paid in excess of interest capitalized		30,542		5,090

See Notes to Consolidated Financial Statements on page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)


	Nine Months Ended September 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 191,022,032 shares in 2008 and 189,522,070 shares in 2007
Balance at beginning of period	$	189,973		187,692
Exercise of stock options		1,049		1,798
Issuance of time-based restricted stock		—		32

Balance at end of period		191,022		189,522

Capital in Excess of Par Value
Balance at beginning of period		547,185		454,860
Exercise of stock options, including income tax benefits		41,328		55,038
Restricted stock transactions and other		6,966		3,794
Stock-based compensation		23,100		17,759
Sale of stock under employee stock purchase plans		—		785

Balance at end of period		618,579		532,236

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		1,612,618		560,411
Cash dividends		(118,835	)	(91,802	)

Balance at end of period		5,477,781		3,813,431

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 (losses) gains, net of income taxes		(106,076	)	211,845
Retirement and postretirement benefit plan adjustments, net of income taxes		441		7,089

Balance at end of period		246,130		352,278

Treasury Stock
Balance at beginning of period		(6,747	)	(3,110	)
Sale of stock under employee stock purchase plans		419		812
Cancellation and forfeitures of performance-based restricted stock		(7,679	)	(4,594	)

Balance at end of period		(14,007	)	(6,892	)

Total Stockholders’ Equity	$	6,519,505		4,880,575

See notes to consolidated financial statements on 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 September 30, 2008, and the results of operations, cash flows and changes in stockholders’ equity for the three-month and nine-month periods ended September 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 nine-month periods ended September 30, 2008 are not necessarily indicative of future results.

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 September 30, 2008, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $306.0 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 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		40,694		8,700
Reclassifications to proved properties based on the determination of proved reserves		(6,869	)	(7,168	)

Balance at September 30	$	305,980		316,977

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.


	September 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	$	44,495	4	4	$	16,235	11	2
One to two years		16,063	7	1		137,559	21	3
Two to three years		124,380	20	3		83,200	10	3
Three years or more		121,042	13	4		79,983	7	3

	$	305,980	44	12	$	316,977	49	11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Of the $261.5 million of exploratory well costs capitalized more than one year at September 30, 2008, $169.3 million is in Malaysia, $60.3 million is in the Republic of Congo, $26.8 million is in the U.S., and $5.1 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 now frozen 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 nine-month periods ended September 30, 2008 and 2007.


	Three Months Ended September 30,
	2008			2007		2008		2007
(Thousands of dollars)	Pension Benefits					Postretirement Benefits
Service cost	$	4,517		2,865		629		560
Interest cost		6,756		6,440		1,285		1,092
Expected return on plan assets		(5,818	)	(5,702	)	—		—
Amortization of prior service cost		511		398		(67	)	(67	)
Amortization of transitional asset		(126	)	(164	)	—		—
Recognized actuarial loss		1,029		1,510		421		399

Net periodic benefit expense	$	6,869		5,347		2,268		1,984


	Nine Months Ended September 30,
	2008			2007		2008		2007
(Thousands of dollars)	Pension Benefits					Postretirement Benefits
Service cost	$	13,617		8,308		1,866		1,634
Interest cost		20,170		18,712		3,820		3,140
Expected return on plan assets		(17,504	)	(16,653	)	—		—
Amortization of prior service cost		1,195		1,094		(198	)	(191	)
Amortization of transitional asset		(389	)	(398	)	—		—
Recognized actuarial loss		3,070		4,350		1,251		1,145

Net periodic benefit expense	$	20,159		15,413		6,739		5,728

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%.

During the nine-month period ended September 30, 2008, the Company made contributions of $46.9 million to domestic and foreign retirement plans and $3.1 million to the postretirement benefit plan. Remaining funding in 2008 for the Company’s defined benefit pension plans and postretirement plan are anticipated to be $9.8 million and $1.6 million, respectively.

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 nine-month periods ended September 30, 2008 and 2007 was $21.5 million and $33.8 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $20.5 million and $24.1 million for the nine-month periods ended September 30, 2008 and 2007, respectively.

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


	Nine Months Ended September 30,
*(Thousands of dollars)*	2008		2007
Compensation charged against income before tax benefit	$	23,856	22,080
Related income tax benefit recognized in income		7,820	7,626

Note E – Earnings per Share

Net income was used as the numerator in computing both basic and diluted income per Common share for the three-month and nine-month periods ended September 30, 2008 and 2007. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended September 30,		Nine Months Ended September 30,
(Weighted-average shares)	2008	2007	2008	2007
Basic method	189,787,636	188,239,267	189,499,657	187,716,385
Dilutive stock options	2,455,812	2,953,999	2,719,953	3,048,075

Diluted method	192,243,448	191,193,266	192,219,610	190,764,460

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 929,071 shares at a weighted average share price of $72.745 in each 2008 period and 1,545,650 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 use derivatives with leveraged or complex features. Derivative instruments are traded primarily with 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 September 30, 2008 and 2007 to manage the cost of about 0.9 million barrels and 1.7 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 charge of $15.9 million and $7.1 million in the nine-month periods ended September 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. There were no short-term derivative instruments outstanding at September 30, 2008 to manage the risk of foreign currency exchange.

Note G – Accumulated Other Comprehensive Income

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


(Thousands of dollars)	September 30, 2008			Dec. 31, 2007
Foreign currency translation gains, net of tax	$	322,686		428,538
Retirement and postretirement benefit plan adjustments, net of tax		(76,556	)	(76,773	)

Accumulated other comprehensive income	$	246,130		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.

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Environmental and Other Contingencies(Contd.)

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 three 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 these 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 three sites or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the three 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 September 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’s position is 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.

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Environmental and Other Contingencies(Contd.)

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 September 30, 2008, the Company had contingent liabilities of $8.5 million under a financial guarantee and $128.4 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.)

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.

In June 2008, the FASB issued FASB Staff Position on EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities (FSP EITF 03-6-1). This statement provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings per share (EPS) calculation under the two-class method. All prior-period EPS calculations must be adjusted retrospectively. This statement is effective for the Company in 2009. Although the Company is in the process of evaluating this statement, it does not expect the effect of adopting this statement in 2009 to have a significant impact on its prior-period EPS calculations.

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 September 30, 2008 are presented in the following table.


(thousands of dollars)	September 30, 2008		Fair Value Measurements at Reporting Date Using
(thousands of dollars)	September 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
Canadian government securities with maturities greater than 90 days at the date of acquisition	$	611,110	611,110	—	—

Total assets at fair value	$	611,110	611,110	—	—

Liabilities
Nonqualified employee savings plan	$	8,573	8,573	—	—
Commodity derivatives		15,892	—	15,892	—

Total liabilities at fair value	$	24,465	8,573	15,892	—

Market value for Canadian government securities approximates cost plus earned interest.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Business Segments


(Millions of dollars)	Total Assets at Sept. 30, 2008		Three Months Ended September 30, 2008					Three Months Ended September 30, 2007
(Millions of dollars)	Total Assets at Sept. 30, 2008		External Revenues		Inter- segment Revenues	Income (Loss)		External Revenues	Inter- segment Revenues	Income (Loss)
Exploration and production*
United States	$	1,333.5	142.5		—	41.0		101.4	—	24.8
Canada		2,182.0	286.8		81.5	166.8		237.9	45.9	107.1
United Kingdom		196.7	62.9		—	20.5		38.3	—	11.0
Malaysia		2,570.9	649.2		—	308.3		33.4	—	4.3
Ecuador		90.8	18.6		—	(.6	)	36.3	—	10.3
Other		355.0	1.5		—	(6.1	)	1.0	—	(6.7	)

Total		6,728.9	1,161.5		81.5	529.9		448.3	45.9	150.8

Refining and marketing
North America		2,560.8	5,665.9		—	91.3		3,992.9	—	63.9
United Kingdom		1,050.8	1,376.2		—	(5.5	)	332.0	—	9.3

Total		3,611.6	7,042.1		—	85.8		4,324.9	—	73.2

Total operating segments		10,340.5	8,203.6		81.5	615.7		4,773.2	45.9	224.0
Corporate		1,490.3	(17.6	)	—	(31.3	)	7.5	—	(24.5	)

Total	$	11,830.8	8,186.0		81.5	584.4		4,780.7	45.9	199.5


	Nine Months Ended September 30, 2008						Nine Months Ended September 30, 2007
(Millions of dollars)	External Revenues			Inter- segment Revenues	Income (Loss)		External Revenues	Inter- segment Revenues	Income (Loss)
Exploration and production*
United States	$	468.1		—	159.5		300.0	—	59.3
Canada		1,063.1		131.7	554.5		635.4	91.0	263.6
United Kingdom		186.5		—	67.0		121.1	—	37.9
Malaysia		1,657.9		—	776.4		126.3	—	29.2
Ecuador		60.7		—	.9		98.8	—	24.3
Other		2.3		—	(23.2	)	2.9	—	(25.4	)

Total		3,438.6		131.7	1,535.1		1,284.5	91.0	388.9

Refining and marketing
North America		15,728.9		—	97.3		10,685.1	—	205.6
United Kingdom		3,928.4		—	76.0		846.6	—	27.5

Total		19,657.3		—	173.3		11,531.7	—	233.1

Total operating segments		23,095.9		131.7	1,708.4		12,816.2	91.0	622.0
Corporate		(14.0	)	—	(95.8	)	13.0	—	(61.6	)

Total	$	23,081.9		131.7	1,612.6		12,829.2	91.0	560.4

*	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 third quarter of 2008 was $584.4 million, $3.04 per diluted share, compared to net income of $199.5 million, $1.04 per diluted share, in the third quarter of 2007. The higher income in 2008 primarily related to improved earnings in both the Company’s exploration and production and refining and marketing businesses, partially offset by higher net costs for corporate activities.

For the first nine months of 2008, net income totaled $1.613 billion, $8.39 per diluted share, compared to net income of $560.4 million, $2.94 per diluted share, for the same period in 2007. The higher nine-month income in 2008 compared to 2007 was primarily attributable to higher earnings in the exploration and production business, partially offset by weaker earnings for refining and marketing operations and higher net corporate costs.

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


	Income (Loss)
	Three Months Ended September 30,					Nine Months Ended September 30,
(Millions of dollars)	2008			2007		2008		2007
Exploration and production	$	529.9		150.8		1,535.1		388.9
Refining and marketing		85.8		73.2		173.3		233.1
Corporate		(31.3	)	(24.5	)	(95.8	)	(61.6	)

Net income	$	584.4		199.5		1,612.6		560.4

In the 2008 third quarter, the Company’s exploration and production operations earned $529.9 million compared to $150.8 million in the 2007 quarter. Income in the 2008 quarter was favorably affected by higher crude oil and natural gas sales prices and higher crude oil sales volumes. Exploration expenses were $83.4 million in the third quarter of 2008 compared to $42.5 million in the same period of 2007. The Company’s refining and marketing operations generated income of $85.8 million in the 2008 third quarter compared to income of $73.2 million in the same quarter of 2007. The third quarter 2008 benefited from much stronger U.S. retail marketing margins compared to 2007, but refining margins in the U.S. and U.K. were significantly weaker in the 2008 period. The after-tax costs of the corporate function were $31.3 million in the 2008 third quarter compared to $24.5 million in the 2007 period with the cost increase due to higher net interest costs and larger foreign exchange losses in 2008.

For the nine months of 2008, the Company’s exploration and production operations earned $1.535 billion compared to $388.9 million in the 2007 period. Earnings in 2008 benefited from significantly higher realized oil sales prices, higher oil sales volumes, and gains on sale of assets. The Company’s refining and marketing operations had earnings of $173.3 million in the first nine months of 2008, compared to earnings of $233.1 million in the same 2007 period. The 2008 period included lower earnings in the North American downstream business compared to a year ago, primarily caused by significantly weaker refining margins in 2008, but partially offset by stronger margins in U.S. retail marketing operations. Earnings 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 acquisition of the remaining 70% interest in the Milford Haven refinery in December 2007. Corporate after-tax costs were $95.8 million in the 2008 period compared to costs of $61.6 million in the 2007 period. Higher net interest expense, 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 September 30,					Nine Months Ended September 30,
(Millions of dollars)	2008			2007		2008		2007
Exploration and production
United States	$	41.0		24.8		159.5		59.3
Canada		166.8		107.1		554.5		263.6
United Kingdom		20.5		11.0		67.0		37.9
Malaysia		308.3		4.3		776.4		29.2
Ecuador		(.6	)	10.3		.9		24.3
Other International		(6.1	)	(6.7	)	(23.2	)	(25.4	)

Total	$	529.9		150.8		1,535.1		388.9

Third quarter 2008 vs. 2007

United States exploration and production operations reported quarterly earnings of $41.0 million in the third quarter of 2008 compared to earnings of $24.8 million in the 2007 quarter. U.S. earnings were higher in the 2008 period due mostly to higher oil and natural gas sales prices. Lower U.S. oil production volumes and lower natural gas sales volumes were mostly attributable to production shut-in in the Gulf of Mexico associated with Hurricanes Gustav and Ike. Depreciation expense in the U.S. was higher in 2008 primarily due to higher per-unit depletion rates. U.S. exploration expenses in the 2008 period increased $11.3 million from the prior year primarily due to higher dry hole costs and higher leasehold amortization, somewhat offset by lower geological and geophysical expenses. Selling and general expenses in the U.S. were lower in the 2008 period than in 2007 due to a real estate donation in the prior year.

Operations in Canada earned $166.8 million in the third quarter 2008 compared to $107.1 million in the 2007 quarter. Canadian earnings improved in the 2008 quarter mostly due to higher oil sales prices. Oil production and sales volumes declined in the 2008 period compared to 2007 primarily due to less oil produced offshore Eastern Canada and in the heavy oil area of Western Canada. Natural gas sales volumes declined in 2008 mostly due to sale of Berkana Energy in January 2008. Depreciation expense was lower in 2008 due to less oil and natural gas production and sales of properties. Exploration expense was $10.0 million higher in the 2008 period due to more lease amortization expense attributable to the Tupper natural gas area in British Columbia, but partially offset by lower dry hole and geophysical expenses. The 2007 quarter included $8.3 million in income tax benefits related to adjustments of estimated prior-period taxes.

United Kingdom operations earned $20.5 million in the 2008 quarter, up from $11.0 million in the 2007 quarter. The 2008 improvement was primarily due to higher crude oil and natural gas sales prices in the current quarter. In addition, the 2008 quarter included higher U.K. crude oil and natural gas sales volumes. Production and depreciation expenses were higher in the 2008 period in the U.K. primarily due to the increase in crude oil and natural gas sales volumes.

Operations in Malaysia reported earnings of $308.3 million in the 2008 quarter compared to earnings of $4.3 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 continued ramp-up of production during 2008 at the Kikeh field. Kikeh came on production in the third quarter of 2007, but the first sale from this field occurred in the fourth quarter of 2007. Production and depreciation expenses were higher in Malaysia in the current period also due to higher sales volumes. Malaysian exploration expense was higher in 2008 due to an unsuccessful exploration well in Block K. Selling and general expense in Malaysia 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 resulted in a net loss of $0.6 million in the third quarter of 2008 compared to a profit of $10.3 million in the 2007 period. The 2008 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, lower crude oil sales volumes, and an unfavorable income tax adjustment in 2008 related to the prior year. Beginning in mid- October 2007, the government of Ecuador claimed 99% of crude oil sales prices that exceeded a benchmark price,

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Third quarter 2008 vs. 2007 (Contd.)

which was approximately $24.31 per barrel in September 2008. Prior to this change, the government’s revenue sharing was 50% of realized prices that exceeded the benchmark price. Production expense in Ecuador was lower in 2008 due to less crude oil sales volumes. See page 25 for further discussion regarding Ecuador.

Other international operations reported a loss of $6.1 million in the third quarter of 2008 compared to a loss of $6.7 million in the 2007 period. The favorable variance was primarily related to slightly lower administrative costs in the 2008 quarter.

On a worldwide basis, the Company’s crude oil, condensate and natural gas liquids prices averaged $107.98 per barrel in the third quarter 2008 compared to $63.96 per barrel in the 2007 period. Average oil and gas liquids production was 118,797 barrels per day in the third quarter of 2008 compared to 87,962 barrels per day in the third quarter of 2007, with the increase primarily attributable to ramp-up of production at the Kikeh field in Malaysia during the 2008 period. Crude oil production was lower in the U.S. in 2008 mostly due to shut-in of Gulf of Mexico fields caused by two hurricanes during the third quarter. Certain offshore oil and natural gas production remained shut-in during October and early November 2008. There was no Canadian light oil production in the 2008 third quarter due to sale of the Company’s interest in Berkana Energy in January 2008. Canadian heavy oil production was lower in the 2008 quarter compared to 2007 due to sale of the Lloydminster area properties during the second quarter of 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 increase in the government revenue share in October 2007. North American natural gas sales prices averaged $11.51 per thousand cubic feet (MCF) in the most recent quarter compared to $6.22 per MCF in the same quarter of 2007. Natural gas sales volumes averaged 46 million cubic feet per day in the third quarter 2008, down from 56 million cubic feet per day in the 2007 quarter, due to a combination of lower volumes in Canada caused by the sale of Berkana Energy in January 2008 and Gulf of Mexico fields shut-in during the third quarter of 2008 due to two hurricanes during the period. Natural gas sales volumes increased in the U.K. in 2008 primarily due to higher volumes sold from the Amethyst and Mungo/Monan offshore fields.

The sales prices for crude oil and natural gas have declined significantly in the fourth quarter 2008 compared to the average prices in the third quarter and for the first nine months of 2008.

Nine months 2008 vs. 2007

U.S. E&P operations produced income of $159.5 million for the nine months ended September 30, 2008 compared to income of $59.3 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 in the U.S. were lower in 2008 mostly due to less costs for workovers and other field maintenance. U.S. depreciation expense was unfavorable in 2008 due to higher per-unit depletion rates compared to 2007. Exploration expenses in the 2008 period in the U.S. were $2.0 million lower than 2007 due to less dry holes expense in 2008, but partially offset by higher geological and geophysical and leasehold amortization expenses in 2008.

Canadian operations earned $554.5 million in the 2008 period compared to $263.6 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 Canadian production expenses in 2008 were mostly related to higher energy costs at Syncrude. Lower depreciation expense in 2008 in Canada was attributable to less oil and natural gas volumes produced and sold. Exploration expenses in Canada were $58.3 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, but these were partially offset by lower dry hole expense during 2008.

Income in the U.K. for the nine-month period in 2008 was $67.0 million compared to $37.9 million a year ago, with the increase primarily due to higher oil and natural gas sales prices and higher natural gas sales volumes, partially offset by lower crude oil sales volumes.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Nine months 2008 vs. 2007 (Contd.)

Malaysia operations earned $776.4 million in the first nine months of 2008 compared to earnings of $29.2 million in the 2007 period. The earnings improvement was primarily caused by crude oil sales volumes associated with the Kikeh field, offshore Sabah, which commenced production in the third quarter of 2007. Production at Kikeh increased during 2008 as more wells came on stream. Average crude oil sales prices were also significantly higher in 2008 than in 2007. Production and depreciation expenses in Malaysia were significantly higher and were related to the increase in Kikeh field production. Malaysian exploration expense was higher in 2008 mostly due to more costs for unsuccessful exploration drilling during 2008. Selling and general expense in Malaysia declined in 2008 due to higher levels of costs charged to production and development operations.

Earnings in Ecuador were $0.9 million for the first nine months of 2008 compared to $24.3 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 that took effect in October 2007. See page 25 for further discussion regarding Ecuador.

Other international operations reported a loss of $23.2 million in the first nine months of 2008 compared to a loss of $25.4 million in the 2007 period. The smaller loss in the 2008 period was primarily due to lower geophysical expenses in the Republic of Congo, but partially offset by higher costs in 2008 for exploration and administrative activities in other foreign jurisdictions.

For the first nine months of 2008, the Company’s sales price for crude oil, condensate and natural gas liquids averaged $100.53 per barrel compared to $56.10 per barrel in 2007. Crude oil, condensate and gas liquids production in the first nine months of 2008 averaged 114,559 barrels per day compared to 84,169 barrels per day a year ago. The increase was mostly attributable to Kikeh field production, offshore Malaysia, which continued to ramp up during 2008, but production volumes were lower in the Gulf of Mexico mostly caused by shut-in of fields due to third quarter hurricanes. Production in the heavy oil area of Western Canada was lower mostly due to the sale of the Lloydminster property in the second quarter 2008. Oil production was lower at the West Patricia field, offshore Sarawak, Malaysia, due to both field decline and a lower percentage of production allocable to the Company under the production sharing contract. The average sales price for North American natural gas in the first nine months of 2008 was $10.27 per MCF, up from $7.16 per MCF in 2007. Natural gas sales volumes in 2008 were 57 million cubic feet per day compared to 58 million cubic feet per day in 2007, with the decrease due mostly to wells shut-in by two hurricanes in the third quarter 2008. Lower natural gas volumes in Canada were caused by the sale of the Company’s interest in 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 nine-month periods ended September 30, 2008 and 2007 follow.


	Three Months Ended September 30,			Nine Months Ended September 30,
	2008		2007	2008	2007
Net crude oil, condensate and gas liquids produced – barrels per day		118,797	87,962	114,559	84,169
United States		9,151	11,680	11,373	13,069
Canada – light		—	640	62	587
– heavy		7,254	11,144	8,801	11,197
– offshore		16,379	20,248	17,214	19,862
– synthetic		13,110	14,423	11,953	12,865
United Kingdom		2,713	3,575	4,917	5,108
Malaysia		63,144	17,358	52,673	12,473
Ecuador		7,046	8,894	7,566	9,008

Net crude oil, condensate and gas liquids sold – barrels per day		117,891	78,702	118,395	82,245
United States		9,151	11,680	11,373	13,069
Canada – light		—	640	62	587
– heavy		7,254	11,144	8,801	11,197
– offshore		15,014	20,153	16,132	20,151
– synthetic		13,110	14,423	11,953	12,865
United Kingdom		5,460	5,123	5,616	6,152
Malaysia		61,349	6,359	56,951	8,706
Ecuador		6,553	9,180	7,507	9,518

Net natural gas sold – thousands of cubic feet per day		45,948	55,712	56,518	57,784
United States		38,846	41,667	46,816	42,283
Canada		1,122	10,582	2,538	9,569
United Kingdom		5,980	3,463	7,164	5,932

Total net hydrocarbons produced – equivalent barrels per day (1)		126,455	97,247	123,979	93,800
Total net hydrocarbons sold – equivalent barrels per day (1)		125,549	87,987	127,815	91,876

Weighted average sales prices
Crude oil, condensate and natural gas liquids – dollars per barrel (2)
United States	$	118.87	70.50	108.99	59.55
Canada (3) – light		—	56.77	70.37	50.73
– heavy		80.87	34.91	70.97	32.43
– offshore		119.06	73.97	111.76	65.66
– synthetic		122.41	77.78	111.70	69.15
United Kingdom		111.89	75.88	106.48	65.68
Malaysia (4)		111.71	61.01	105.48	53.33
Ecuador (5)		30.40	43.07	29.20	38.00

Natural gas – dollars per thousand cubic feet
United States (2)	$	11.64	6.59	10.44	7.37
Canada (3)		7.05	4.74	7.19	6.21
United Kingdom (3)		11.81	7.17	11.21	6.84

(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 contract for Blocks K and SK 309.

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

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

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


(Millions of dollars)	United States		Canada		United Kingdom	Malaysia		Ecuador		Other		Synthetic Oil – Canada	Total
Three Months Ended September 30, 2008
Oil and gas sales and other revenues	$	142.5	219.7		62.9	649.2		18.6		1.5		148.6	1,243.0
Production expenses		15.8	20.0		10.9	65.1		7.6		—		45.5	164.9
Depreciation, depletion and amortization		25.2	25.6		7.3	63.4		10.1		.3		7.1	139.0
Accretion of asset retirement obligations		1.7	1.1		.6	1.4		—		.2		.1	5.1
Exploration expenses
Dry holes		17.9	—		—	25.0		—		—		—	42.9
Geological and geophysical		5.1	2.2		—	1.2		—		.7		—	9.2
Other		.5	.1		.1	(.1	)	—		1.8		—	2.4

		23.5	2.3		.1	26.1		—		2.5		—	54.5
Undeveloped lease amortization		6.8	22.0		—	—		—		.1		—	28.9

Total exploration expenses		30.3	24.3		.1	26.1		—		2.6		—	83.4

Selling and general expenses		6.1	2.9		1.8	(.6	)	.3		4.0		.3	14.8

Results of operations before taxes		63.4	145.8		42.2	493.8		.6		(5.6	)	95.6	835.8
Income tax expenses		22.4	45.8		21.7	185.5		1.2		.5		28.8	305.9

Results of operations (excluding corporate overhead and interest)	$	41.0	100.0		20.5	308.3		(.6	)	(6.1	)	66.8	529.9

Three Months Ended September 30, 2007
Oil and gas sales and other revenues	$	101.4	180.5		38.3	33.4		36.3		1.0		103.3	494.2
Production expenses		16.2	29.3		9.0	9.9		8.8		—		35.6	108.8
Depreciation, depletion and amortization		17.6	41.0		5.2	5.2		10.0		.2		7.3	86.5
Accretion of asset retirement obligations		1.1	1.3		.5	.9		—		.2		.2	4.2
Exploration expenses
Dry holes		4.5	6.9		—	(2.2	)	—		—		—	9.2
Geological and geophysical		9.5	4.2		—	9.0		—		.7		—	23.4
Other		.5	.1		.1	—		—		1.3		—	2.0

		14.5	11.2		.1	6.8		—		2.0		—	34.6
Undeveloped lease amortization		4.5	3.1		—	—		—		.3		—	7.9

Total exploration expenses		19.0	14.3		.1	6.8		—		2.3		—	42.5

Selling and general expenses		13.0	4.0		.9	1.6		.2		4.8		.2	24.7
Minority interest		—	(.4	)	—	—		—		—		—	(.4	)

Results of operations before taxes		34.5	91.0		22.6	9.0		17.3		(6.5	)	60.0	227.9
Income tax expenses		9.7	23.9		11.6	4.7		7.0		.2		20.0	77.1

Results of operations (excluding corporate overhead and interest)	$	24.8	67.1		11.0	4.3		10.3		(6.7	)	40.0	150.8

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2008 AND 2007


(Millions of dollars)	United States		Canada		United Kingdom	Malaysia		Ecuador	Other		Synthetic Oil – Canada	Total
Nine Months Ended September 30, 2008
Oil and gas sales and other revenues	$	468.1	807.6		186.5	1,657.9		60.7	2.3		387.2	3,570.3
Production expenses		48.5	66.5		24.1	174.1		24.9	—		146.5	484.6
Depreciation, depletion and amortization		80.8	85.5		21.3	166.9		32.2	.7		20.3	407.7
Accretion of asset retirement obligations		4.6	3.5		1.7	4.0		—	.6		.5	14.9
Exploration expenses
Dry holes		18.1	—		—	35.8		—	—		—	53.9
Geological and geophysical		27.2	14.8		—	13.4		—	1.4		—	56.8
Other		4.8	.3		.5	—		—	8.6		—	14.2

		50.1	15.1		.5	49.2		—	10.0		—	124.9
Undeveloped lease amortization		18.5	66.1		—	—		—	.8		—	85.4

Total exploration expenses		68.6	81.2		.5	49.2		—	10.8		—	210.3

Selling and general expenses		18.1	9.7		3.6	(.1	)	.6	12.8		.7	45.4
Minority interest		—	.3		—	—		—	—		—	.3

Results of operations before taxes		247.5	560.9		135.3	1,263.8		3.0	(22.6	)	219.2	2,407.1
Income tax expenses		88.0	159.1		68.3	487.4		2.1	.6		66.5	872.0

Results of operations (excluding corporate overhead and interest)	$	159.5	401.8		67.0	776.4		.9	(23.2	)	152.7	1,535.1

Nine Months Ended September 30, 2007
Oil and gas sales and other revenues	$	300.0	483.5		121.1	126.3		98.8	2.9		242.9	1,375.5
Production expenses		59.6	76.1		22.2	27.1		27.6	—		96.1	308.7
Depreciation, depletion and amortization		51.0	116.4		17.6	21.0		28.7	.5		19.1	254.3
Accretion of asset retirement obligations		2.9	3.5		1.5	2.5		—	.5		.5	11.4
Exploration expenses
Dry holes		32.0	7.8		—	(2.1	)	.3	(.4	)	—	37.6
Geological and geophysical		20.9	8.5		—	14.1		—	9.8		—	53.3
Other		4.3	.3		.3	—		—	4.4		—	9.3

		57.2	16.6		.3	12.0		.3	13.8		—	100.2
Undeveloped lease amortization		13.4	6.3		—	—		—	1.1		—	20.8

Total exploration expenses		70.6	22.9		.3	12.0		.3	14.9		—	121.0

Impairment of long-lived assets		2.6	—		—	—		—	—		—	2.6
Selling and general expenses		25.3	12.5		2.8	8.4		.7	11.7		.6	62.0
Minority interest		—	(.4	)	—	—		—	—		—	(.4	)

Results of operations before taxes		88.0	252.5		76.7	55.3		41.5	(24.7	)	126.6	615.9
Income tax expenses		28.7	75.8		38.8	26.1		17.2	.7		39.7	227.0

Results of operations (excluding corporate overhead and interest)	$	59.3	176.7		37.9	29.2		24.3	(25.4	)	86.9	388.9

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 September 30,				Nine Months Ended September 30,
(Millions of dollars)	2008			2007	2008	2007
Refining and marketing
North America	$	91.3		63.9	97.3	205.6
United Kingdom		(5.5	)	9.3	76.0	27.5

Total	$	85.8		73.2	173.3	233.1

The Company’s refining and marketing operations generated income of $85.8 million in the 2008 third quarter compared to earnings of $73.2 million in the same quarter of 2007. North American operations had a profit of $91.3 million in the 2008 period compared to $63.9 million in 2007. U.S. retail marketing margins improved significantly in the 2008 quarter compared to 2007. Refining margins in the U.S., however, were quite weak in the 2008 quarter, but were strong in the third quarter of 2007. Operations in the United Kingdom incurred a loss of $5.5 million in the third quarter of 2008 compared to earnings of $9.3 million in the same period a year ago. The 2008 quarter was adversely affected by weaker U.K. refinery margins. Worldwide petroleum product sales averaged 535,284 barrels per day in 2008, compared to 472,876 barrels per day in the same period in 2007. The 2008 sales volume increase was attributable to higher sales volumes in the U.K. associated with the Milford Haven refinery acquisition. Worldwide refinery inputs were 232,020 barrels per day in the third quarter of 2008 compared to 176,785 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. primarily due to a plant-wide turnaround at the Superior, Wisconsin refinery during the 2008 third quarter.

Refining and marketing operations in the first nine months of 2008 generated a profit of $173.3 million compared to a profit of $233.1 million in the 2007 period. In North America, the 2008 profit of $97.3 million was significantly lower than the 2007 profit of $205.6 million. Current year results were unfavorable mostly due to much weaker refining margins in 2008 compared to 2007. However, U.S. retail marketing margins improved in the 2008 period in comparison 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 $76.0 million in the first nine months of 2008 compared to earnings of $27.5 million in the 2007 period as 2008 benefitted from stronger refining margins on sale of petroleum products and a larger U.K. refining operation due to the Company’s purchase of the remaining 70% of the Milford Haven, Wales refinery in December 2007.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Refining and Marketing (Contd.)

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


	Three Months Ended September 30,		Nine Months Ended September 30,
	2008	2007	2008	2007
Refinery inputs – barrels per day	232,020	176,785	240,837	179,276
North America	120,793	140,886	127,709	145,413
United Kingdom	111,227	35,899	113,128	33,863

Petroleum products sold – barrels per day	535,284	472,876	536,291	444,845
North America	422,132	433,536	424,294	408,064
Gasoline	313,097	312,553	310,444	295,283
Kerosine	3,366	152	2,466	1,250
Diesel and home heating oils	78,563	88,894	89,364	85,565
Residuals	15,815	16,357	14,881	15,873
Asphalt, LPG and other	11,291	15,580	7,139	10,093
United Kingdom	113,152	39,340	111,997	36,781
Gasoline	30,200	15,023	34,065	12,798
Kerosine	18,912	3,670	14,473	3,499
Diesel and home heating oils	29,780	14,811	34,263	13,036
Residuals	15,562	3,895	14,053	3,549
LPG and other	18,698	1,941	15,143	3,899

Corporate

Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had net costs of $31.3 million in the 2008 third quarter compared to net costs of $24.5 million in the third quarter of 2007. Net costs increased in 2008 compared to 2007 due to a combination of higher net interest expense associated with higher average borrowing levels and lower amounts capitalized to oil and gas development projects, and higher losses on foreign exchange. The Company capitalized most of its interest expense to the Kikeh oil development project in the third quarter of 2007.

For the first nine months of 2008, corporate activities reflected net costs of $95.8 million compared to net costs of $61.6 million a year ago. The increase in the nine-month costs for 2008 related to higher foreign exchange losses, higher net interest expense due mostly to lower interest capitalized to development projects, and higher administrative costs. Total after-tax costs for foreign currency exchange movements were $27.9 million in the 2008 nine-month period compared to $7.3 million in the same 2007 period.

Financial Condition and Liquidity

At September 30, 2008, the Company’s total Cash and Cash Equivalents was $828.1 million, and Canadian Government Securities with Maturities Greater than 90 Days at the Date of Acquisition totaled another $611.1 million. The Company has a committed revolving loan facility with 25 U.S. and foreign banks totaling $1.962 billion, of which $1.494 billion was unused at September 30, 2008. The capacity of the committed loan facility is reduced to $1.905 billion between June 2010 and June 2011 and is further reduced to $1.828 billion from June 2011 to maturity in June 2012. Based on currently available information, the Company does not anticipate any banks being unable to meet their obligations under the committed facility should the Company need to borrow under the facilities. The Company also has uncommitted loan facilities of approximately $100 million U.S. dollar equivalents; no amounts were borrowed under these facilities at September 30, 2008. There is no guarantee that the Company could access borrowings under these uncommitted loan facilities. The Company does not anticipate any banks that hold Company cash and any governments that have issued debt securities owned by the Company failing to meet their obligations. The Company believes that with its present cash, invested cash and loan facilities there is adequate sources of financing to meet its anticipated needs. The Company has not experienced any significant credit related losses.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Financial Condition and Liquidity (Contd.)

Net cash provided by operating activities was $2.597 billion for the first nine months of 2008 compared to $915.0 million during the same period in 2007. Changes in operating working capital other than cash and cash equivalents provided cash of $184.5 million in the first nine months of 2008, but used cash of $199.6 million in the 2007 period.

Other predominant uses of cash in both years were for dividends, which totaled $118.8 million in 2008 and $91.8 million in 2007, and for property additions and dry holes, which, including amounts expensed, were $1.560 billion and $1.279 billion in the nine-month periods ended September 30, 2008 and 2007, respectively. Total capital expenditures were as follows:


	Nine Months Ended September 30,
(Millions of dollars)	2008		2007
Capital Expenditures
Exploration and production	$	1,351.4	1,231.4
Refining and marketing		319.5	206.2
Corporate and other		2.3	3.0

Total capital expenditures		1,673.2	1,440.6

Working capital (total current assets less total current liabilities) at September 30, 2008 was $1.329 billion, up $551 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 $981 million below fair value at September 30, 2008.

At September 30, 2008, long-term notes payable of $1.066 billion had been reduced by $450 million compared to December 31, 2007. A summary of capital employed at September 30, 2008 and December 31, 2007 follows.


	Sept. 30, 2008				Dec. 31, 2007
(Millions of dollars)	Amount		%		Amount		%
Capital employed
Notes payable	$	1,066.2	14.1	%	$	1,513.0	23.0	%
Nonrecourse debt of a subsidiary		—	—			3.2	0.1
Stockholders’ equity		6,519.5	85.9			5,066.2	76.9

Total capital employed	$	7,585.7	100.0	%	$	6,582.4	100.0	%

The Company’s ratio of earnings to fixed charges was 32.3 to 1 for the nine-month period ended September 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 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, 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 $24.31 per barrel at September 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. In October 2008 the government of Ecuador notified the Company and its partners that a new contract must be agreed to or the government will terminate the contract. Further discussions with the government are expected. Commencing with the April 2008 revenue sharing, which was scheduled to be paid in June 2008, 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 of $77.2 million at September 30, 2008 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 September 30, 2008 amounted to $80.1 million.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Outlook

Worldwide crude oil and North American natural gas prices have weakened considerably in October 2008 compared to the average price during the third quarter of 2008. The Company’s consolidated net income is expected to be unfavorably impacted by these significant price declines for oil and natural gas. The Company expects its oil and natural gas production to average about 141,000 barrels of oil equivalent per day in the fourth quarter. Following Hurricanes Gustav and Ike in the third quarter 2008, certain oil and natural gas production in the Gulf of Mexico remains shut-in in October and early November pending restart of pipelines owned and operated by other companies. During October 2008, U.S. retail marketing margins had improved due to falling wholesale gasoline prices, but refining margins have been relatively weak due to lower demand for refined products. The Company currently anticipates total capital expenditures for the full year 2008 to be approximately $2.4 billion.

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 September 30, 2008 to hedge the cost of about 1.8 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 liability associated with this derivative contract by approximately $0.6 million, while a 10% decrease would have reduced the asset 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 September 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

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 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 July 30, 2008 that included a News Release announcing the Company’s earnings and certain other financial information for the three-month and six-month periods ended June 30, 2008.

(c)	A report on Form 8-K was filed on August 6, 2008 announcing management changes effective January 1, 2009, an amendment to the Company’s By-Laws, and an increase in the Company’s cash dividend rate.

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)

November 7, 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.

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Murphy Oil (MUR) 10-Q2008 Q3 Quarterly report

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