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 March 31, 2009

¨	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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). ¨ 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 March 31, 2009 was 190,787,349.

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 Financial Condition and Results of Operations		16

Item 3. Quantitative and Qualitative Disclosures About Market Risk		23

Item 4. Controls and Procedures		23

Part II – Other Information

Item 1. Legal Proceedings		24

Item 1A. Risk Factors		25

Item 6. Exhibits and Reports on Form 8-K		25

Signature		26

PART I – FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)


	(Unaudited) March 31, 2009			December 31, 2008
ASSETS
Current assets
Cash and cash equivalents	$	327,403		666,110
Canadian government securities with maturities greater than 90 days at the date of acquisition		613,563		420,340
Accounts receivable, less allowance for doubtful accounts of $7,513 in 2009 and $7,303 in 2008		974,956		1,033,996
Inventories, at lower of cost or market
Crude oil and blend stocks		142,373		98,217
Finished products		348,936		315,340
Materials and supplies		184,668		190,616
Prepaid expenses		91,617		92,544
Deferred income taxes		33,852		29,801

Total current assets		2,717,368		2,846,964

Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $3,693,987 in 2009 and $3,824,393 in 2008		7,758,429		7,727,718
Goodwill		36,153		37,370
Deferred charges and other assets		552,926		537,046


Total assets	$	11,064,876		11,149,098


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	—		2,572
Accounts payable and accrued liabilities		1,396,431		1,434,202
Income taxes payable		398,783		451,372

Total current liabilities		1,795,214		1,888,146

Notes payable		996,274		1,026,222
Deferred income taxes		845,348		878,131
Asset retirement obligations		429,011		435,589
Deferred credits and other liabilities		658,827		642,065

Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued		—		—
Common Stock, par $1.00, authorized 450,000,000 shares, issued 191,508,641 shares in 2009 and 191,248,941 shares in 2008		191,509		191,249
Capital in excess of par value		653,043		631,859
Retained earnings		5,680,948		5,557,483
Accumulated other comprehensive loss		(166,496	)	(87,697	)
Treasury stock, 721,292 shares of Common Stock in 2009 and 535,135 shares in 2008, at cost		(18,802	)	(13,949	)

Total stockholders’ equity		6,340,202		6,278,945


Total liabilities and stockholders’ equity	$	11,064,876		11,149,098

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page 27.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars, except per share amounts)


	Three Months Ended March 31,
	2009			2008*
REVENUES
Sales and other operating revenues	$	3,416,427		6,466,668
Gain on sale of assets		15		42,386
Interest and other income		29,110		471

Total revenues		3,445,552		6,509,525


COSTS AND EXPENSES
Crude oil and product purchases		2,556,044		5,146,397
Operating expenses		362,361		401,178
Exploration expenses, including undeveloped lease amortization		111,105		66,496
Selling and general expenses		56,832		58,774
Depreciation, depletion and amortization		194,769		160,625
Accretion of asset retirement obligations		6,253		5,156
Interest expense		11,988		21,153
Interest capitalized		(10,323	)	(6,949	)

Total costs and expenses		3,289,029		5,852,830


Income from continuing operations before income taxes		156,523		656,695
Income tax expense		85,283		248,489


Income from continuing operations		71,240		408,206
Income from discontinued operations, net of income taxes		99,864		786


NET INCOME	$	171,104		408,992


INCOME PER COMMON SHARE – Basic
Income from continuing operations	$	0.37		2.16
Income from discontinued operations		0.53		—

Net Income – Basic	$	0.90		2.16


INCOME PER COMMON SHARE – Diluted
Income from continuing operations	$	0.37		2.13
Income from discontinued operations		0.52		0.01

Net income – Diluted	$	0.89		2.14


Average Common shares outstanding – basic		190,545,771		189,150,647
Average Common shares outstanding – diluted		192,281,803		191,550,683

*	Reclassified to conform to current presentation.

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 March 31,
	2009			2008
Net income	$	171,104		408,992

Other comprehensive income, net of income taxes
Net loss from foreign currency translation		(80,987	)	(23,559	)
Retirement and postretirement benefit plan gains (losses)		2,188		(1,489	)


COMPREHENSIVE INCOME	$	92,305		383,944

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)


	Three Months Ended March 31,
	2009			2008¹
OPERATING ACTIVITIES
Net income	$	171,104		408,992
Income from discontinued operations		99,864		786

Income from continuing operations		71,240		408,206
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation, depletion and amortization		194,769		160,625
Amortization of deferred major repair costs		6,501		6,636
Expenditures for asset retirements		(2,098	)	(1,211	)
Dry hole costs		67,471		241
Amortization of undeveloped leases		25,734		27,488
Accretion of asset retirement obligations		6,253		5,156
Deferred and noncurrent income tax charges (benefits)		(785	)	110,784
Pretax gain from disposition of assets		(15	)	(42,386	)
Net (increase) decrease in noncash operating working capital		44,970		(245,215	)
Other operating activities, net		(36,589	)	3,222

Net cash provided by continuing operations		377,451		433,546
Net cash provided by discontinued operations		2,576		12,983

Net cash provided by operating activities		380,027		446,529


INVESTING ACTIVITIES
Property additions and dry hole costs		(511,358	)	(506,657	)
Purchases of investment securities²		(599,751	)	—
Proceeds from maturity of investment securities²		406,528		—
Expenditures for major repairs		(7,408	)	(7,676	)
Proceeds from sales of assets		116		104,126
Other – net		(1,836	)	(5,749	)
Investing activities of discontinued operations
Sales proceeds		78,908		—
Other		(845	)	(3,705	)

Net cash required by investing activities		(635,646	)	(419,661	)


FINANCING ACTIVITIES
Increase (decrease) in notes payable		(30,000	)	202,921
Repayment of nonrecourse debt of a subsidiary		(2,572	)	(5,235	)
Proceeds from exercise of stock options and employee stock purchase plans		4,420		9,922
Excess tax benefits related to exercise of stock options		1,957		9,945
Cash dividends paid		(47,639	)	(35,564	)

Net cash provided (required) by financing activities		(73,834	)	181,989


Effect of exchange rate changes on cash and cash equivalents		(9,254	)	(13,435	)


Net increase (decrease) in cash and cash equivalents		(338,707	)	195,422
Cash and cash equivalents at January 1		666,110		673,707


Cash and cash equivalents at March 31	$	327,403		869,129


SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid	$	82,401		56,683

Interest paid more than (less than) amounts capitalized	$	(8,975	)	4,524

¹	Reclassified to conform to current presentation.

²	Represents cash invested in Canadian government securities with maturities greater than 90 days at the date of acquisition.

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)


	Three Months Ended March 31,
	2009			2008
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued		—		—


Common Stock – par $1.00, authorized 450,000,000 shares, issued 191,508,641 shares at March 31, 2009 and 190,499,101 shares at March 31, 2008
Balance at beginning of period	$	191,249		189,973
Exercise of stock options		260		526

Balance at end of period		191,509		190,499


Capital in Excess of Par Value
Balance at beginning of period		631,859		547,185
Exercise of stock options, including income tax benefits		7,440		20,261
Restricted stock transactions and other		5,439		6,962
Amortization, forfeitures and other		8,114		7,191
Sale of stock under employee stock purchase plans		191		—

Balance at end of period		653,043		581,599


Retained Earnings
Balance at beginning of period		5,557,483		3,983,998
Net income for the period		171,104		408,992
Cash dividends		(47,639	)	(35,564	)

Balance at end of period		5,680,948		4,357,426


Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		(87,697	)	351,765
Foreign currency translation losses, net of income taxes		(80,987	)	(23,559	)
Retirement and postretirement benefit plan gains (losses), net of income taxes		2,188		(1,489	)

Balance at end of period		(166,496	)	326,717


Treasury Stock
Balance at beginning of period		(13,949	)	(6,747	)
Sale of stock under employee stock purchase plans		587		164
Awarded restricted stock, net of forfeitures		—		637
Cancellation of performance-based restricted stock and forfeitures		(5,440	)	(7,598	)

Balance at end of period		(18,802	)	(13,544	)


Total Stockholders’ Equity	$	6,340,202		5,442,697

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, 2008. In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at March 31, 2009, and the results of operations, cash flows and changes in stockholders’ equity for the three-month periods ended March 31, 2009 and 2008, 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 2008 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three months ended March 31, 2009 are not necessarily indicative of future results.

Note B – Discontinued Operations

On March 12, 2009, the Company sold its operations in Ecuador for net cash proceeds of $78.9 million, subject to post-closing adjustments. The acquirer also assumed certain tax and other liabilities associated with the Ecuador properties sold. The Ecuador properties sold included 20% interests in producing Block 16 and the nearby Tivacuno area. The Company recorded a gain of $104.0 million, net of income taxes of $14.0 million, from the sale of the Ecuador properties. The Company used the proceeds of the sale to pay down debt and to partially fund ongoing development projects in other areas. At the time of the sale, the Ecuador properties produced approximately 6,700 net barrels per day of heavy oil and had net oil reserves of approximately 4.6 million barrels. Ecuador operating results prior to the sale, and the resulting gain on disposal, have been reported as discontinued operations. The consolidated financial statements for 2008 have been reclassified to conform to this presentation. In past reports, the operating results for the Ecuador properties were primarily included in the Ecuador segment in the Oil and Gas Operating Results table; interest expense associated with the business was previously included in Corporate results. The major assets (liabilities) associated with the Ecuador properties were as follows:


(Thousands of dollars)
Current assets	$	4,214
Property, plant and equipment, net of accumulated depreciation, depletion and amortization		65,178
Other noncurrent assets		683

Assets sold	$	70,075


Current liabilities	$	105,554
Other noncurrent liabilities		35

Liabilities associated with assets sold	$	105,589

The following table reflects the results of operations from the sold properties including the gain on sale.


	Three Months Ended March 31,
(Thousands of dollars)	2009		2008
Revenues, including a pretax gain on sale of $117,926 in 2009	$	126,023	23,206
Income before income tax expense		113,825	1,241
Income tax expense		13,961	455

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C– Property, Plant and Equipment

Financial Accounting Standards Board (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 March 31, 2009, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $312.4 million. The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2009 and 2008.


(Thousands of dollars)	2009		2008
Beginning balance at January 1	$	310,118	272,155
Additions pending the determination of proved reserves		2,326	15,051
Reclassifications to proved properties based on the determination of proved reserves		—	—

Balance at March 31	$	312,444	287,206

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.


	March 31
	2009				2008
(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	$	31,261	3	2	$	17,672	2	2
One to two years		18,046	2	2		71,145	14	3
Two to three years		71,101	14	3		97,773	15	2
Three years or more		192,036	25	5		100,616	10	4

	$	312,444	44	12	$	287,206	41	11

Of the $281.2 million of exploratory well costs capitalized more than one year at March 31, 2009, $177.7 million is in Malaysia, $60.3 million is in the Republic of Congo, $27.6 million is in the U.S., $9.6 million is in the U.K., and $6.0 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, in Canada a continuing drilling and development program is underway, and in the U.K. further studies to evaluate the discovery are ongoing.

In January 2008, the Company sold its interest in Berkana Energy Corporation and recorded a pretax gain of $41.7 million ($39.9 million after-tax).

Note D – 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2009 and 2008.


	Three Months Ended March 31,
	Pension Benefits					Other Postretirement Benefits
(Thousands of dollars)	2009			2008		2009		2008
Service cost	$	4,118		4,538		776		609
Interest cost		6,988		6,741		1,391		1,250
Expected return on plan assets		(5,346	)	(5,857	)	—		—
Amortization of prior service cost		398		344		(66	)	(65	)
Amortization of transitional asset		(106	)	(132	)	—		—
Recognized actuarial loss		2,944		1,016		421		409

Net periodic benefit expense	$	8,996		6,650		2,522		2,203

Murphy previously disclosed in its financial statements for the year ended December 31, 2008, that it expected to contribute $50.2 million to its defined benefit pension plans and $4.9 million to its postretirement benefits plan during 2009. The anticipated defined benefit pension plan contributions included $30.0 million of voluntary contributions. During the three-month period ended March 31, 2009, the Company made contributions of $18.3 million (including $15.0 million of voluntary contributions to the defined benefit pension plan), and remaining funding in 2009 for the Company’s domestic and foreign defined benefit pension and postretirement plans is anticipated to be $36.8 million.

Note E – Incentive Plans

Statement of Financial Accounting Standards (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 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 Company has an Employee Stock Purchase Plan that permits the issuance of up to 980,000 shares 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 2009, the Committee granted stock options for 1,057,000 shares at an exercise price of $43.95 per share. The Black-Scholes valuation for these awards was $15.15 per option. The Committee also granted 375,050 performance-based restricted stock units in February 2009 under the 2007 Long-Term Plan. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, was $42.42 per unit. Also in February the Committee granted 47,790 shares of time-lapse restricted stock to the Company’s Directors under the 2008 Non-employee 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 $44.65 per share.

Cash received from options exercised under all share-based payment arrangements for the three-month periods ended March 31, 2009 and 2008 was $4.4 million and $9.9 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $2.5 million and $10.7 million for the three-month periods ended March 31, 2009 and 2008, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – Incentive Plans (Contd.)

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


	Three Months Ended March 31
(Thousands of dollars)	2009		2008
Compensation charged against income before tax benefit	$	8,127	7,543
Related income tax benefit recognized in income		2,707	2,638

Note F – Earnings per Share

Net income was used as the numerator in computing both basic and diluted income per Common share for the three months ended March 31, 2009 and 2008. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended March 31
(Weighted-average shares)	2009	2008
Basic method	190,545,771	189,150,647
Dilutive stock options	1,736,032	2,400,036

Diluted method	192,281,803	191,550,683

Certain options to purchase shares of common stock were outstanding during the 2009 and 2008 periods but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. These included 3,354,875 shares at a weighted average share price of $55.71 in 2009 and 233,125 shares at a weighted average share price of $72.75 in 2008.

Note G – Financial Instruments and Risk Management

Murphy periodically utilizes derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest 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 March 31, 2009 and 2008 to manage the cost of about 0.5 million barrels and 1.5 million barrels, respectively, of crude oil at the Company’s Meraux, Louisiana and Superior, Wisconsin refineries. The total impact of marking these contracts to market increased income from continuing operations before income taxes by $0.2 million and $1.5 million in the three-month periods ended March 31, 2009 and 2008, respectively. The instruments outstanding at March 31, 2009 all mature by May 2009.

•

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 March 31, 2009 to manage the risk of certain income tax payments due in 2009 that are payable in Malaysian ringgits. The equivalent U.S. dollars of such Malaysian ringgit contracts outstanding at March 31, 2009 were approximately $140.3 million. Short-term derivative instruments were outstanding at March 31, 2009 and 2008 to manage the risk of certain U.S. dollar accounts receivable associated with sale of the Company’s Canadian crude oil. A total of $16.0 million U.S. dollar contracts were outstanding at March 31, 2009 related to these Canadian receivables. The effect of marking these contracts to market at March 31, 2009 and 2008 reduced first quarter 2009 and 2008 income from continuing operations before income taxes by $0.5 million and $0.6 million, respectively. The outstanding Malaysian instruments mature by July 2009 and the outstanding Canadian instruments mature in April 2009.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

At March 31, 2009, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.


	March 31, 2009
	Asset (Liability) Derivatives
(Thousands of dollars)	Balance Sheet Location	Fair Value
Commodity derivative contracts	Accounts payable and accrued liabilities	$	(1,545	)
Foreign exchange derivative contracts	Accounts payable and accrued liabilities		(483	)

For the three month period ended March 31, 2009, the gains and losses recognized in the consolidated statement of income for derivative instruments not designated as hedging instruments are presented in the following table.


	Three Months Ended March 31, 2009
(Thousands of dollars)	Location of Gain or (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
Commodity derivative contracts	Crude oil and product purchases	$	(4,684	)
Foreign exchange derivative contracts	Interest and other income		(550	)

		$	(5,234	)

The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet. The fair value measurements for these assets and liabilities at March 31, 2009 are presented in the following table.


				Fair Value Measurements at Reporting Date Using
(Thousands of dollars)	March 31, 2009			Quoted Prices in Active Markets for Identical Assets (Liabilities) (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets – None
Liabilities
Derivative liabilities	$	(2,028	)	—		(2,028	)	—
Nonqualified employee savings plan		(7,088	)	(7,088	)	—		—

	$	(9,116	)	(7,088	)	(2,028	)	—

Note H – Accumulated Other Comprehensive Loss

The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at March 31, 2009 and December 31, 2008 are presented in the following table.


(Thousands of dollars)	March 31, 2009			Dec. 31, 2008
Foreign currency translation gains (losses), net of tax	$	(35,470	)	45,517
Retirement and postretirement benefit plan losses, net of tax		(131,026	)	(133,214	)

Accumulated other comprehensive loss	$	(166,496	)	(87,697	)

Note I – 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; royalty and revenue sharing increases; 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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Environmental and Other Contingencies (Contd.)

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.

Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result.

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. While some of these historical properties are in various stages of negotiation, investigation, and/or cleanup, the Company is investigating the extent of any such liability and the availability of applicable defenses and believes costs related to these sites will not have a material adverse affect on Murphy’s net income, financial condition or liquidity in a future period.

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. Certain environmental expenditures are likely to be recovered by the Company from other sources, primarily environmental funds maintained by certain states. Since no assurance can be given that future recoveries from other sources will occur, the Company has not recorded a benefit for likely recoveries.

The U.S. Environmental Protection Agency (EPA) currently considers the Company to be 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. However, based on current negotiations and 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 two sites or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Environmental and Other Contingencies (Contd.)

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. 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 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. In April 2009, two of the four insurers agreed to a settlement with the Company and withdrew from the arbitral proceedings, which are scheduled to take place in London in the third quarter. 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.

The joint agreement between the owners of the Terra Nova field offshore eastern Canada requires a redetermination of working interests based on an analysis of reservoir quality among fault separated areas where varying ownership interests exist. Heretofore, the Company’s ownership interest has been 12%. The matter will be the subject of arbitration before final interests are established. This redetermination is expected to be finalized in 2010, and is retroactive to 2005. Upon completion of the redetermination process, a cash settlement is required among partners to balance cash flows retroactive to the effective date. The field’s operator has presented a preliminary indication that could reduce the Company’s interest at Terra Nova. The Company cannot predict at this time how its ownership interest will be affected by the redetermination process, and it is unable to determine whether settlement of this matter will have a material adverse effect on its net income 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 these matters 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 March 31, 2009, the Company had contingent liabilities of $7.8 million under a financial guarantee and $104.3 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to these letters of credit because it is believed that the likelihood of having these drawn is remote.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Accounting Matters

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51. This statement was adopted by the Company on January 1, 2009 and it is to be applied prospectively, except for presentation and disclosure requirements which are applied retrospectively. This statement requires noncontrolling interests to be reclassified as equity, and consolidated net income and comprehensive income shall include the respective results attributable to noncontrolling interests. The adoption of this statement did not have a significant effect on the Company’s consolidated financial statements.

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations. This statement was adopted by the Company as of January 1, 2009 and it 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. Assets and liabilities that arise from business combinations that occurred prior to 2009 are not affected by this statement. The adoption of this statement had no effect on the Company’s financial statements for the three-month period ended March 31, 2009. This statement will impact the recognition and measurement of assets and liabilities in business combinations that occur beginning in 2009, 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 was adopted by the Company 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. See Note G for further disclosures.

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, which was adopted by the Company in 2009, 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. The adoption of this statement did not have a significant impact on the Company’s prior-period EPS calculations.

In November 2008, the EITF published Issue No. 08-6, Equity Method Investment Accounting Considerations. This pronouncement was adopted by the Company in January 2009 and has been applied prospectively. The pronouncement gives guidance about how to initially measure contingent consideration for an equity method investment, how to recognize other-than-temporary impairments of an equity method investment, and how an equity method investor is to account for a share issuance by an investee. The adoption of this statement did not have a significant impact on the Company’s consolidated financial statements.

In December 2008, the FASB issued Staff Position No. FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets. This guidance will require additional disclosures about benefit plan assets, including how asset investment allocation decisions are made, the fair value of each major category of plan assets, and how fair value is determined for each major asset category. This guidance is effective for the Company as of December 31, 2009. Upon adoption, no comparative disclosures are required for earlier years presented. The Company does not expect the adoption of this standard to have a material impact on its consolidated financial statements in future periods.

In December 2008, the U.S. Securities and Exchange Commission adopted revisions to oil and natural gas reserve reporting requirements which are effective, as previously written, for the Company at year-end 2009. The primary changes to reserve reporting include:

•

A revised definition of proved reserves, including the use of unweighted average prices for a 12-month period to compute such reserves,

•

Expanding the definition of oil and gas producing activities to include non-traditional and unconventional resources, which includes the Company’s synthetic oil operations in Alberta,

•

Allowing companies to voluntarily disclose probable and possible reserves in SEC filings,

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Accounting Matters (Contd.)

•

Amending required proved reserve disclosures to include separate amounts for synthetic oil and gas,

•

Expanding disclosures of proved undeveloped reserves, including discussion of such proved undeveloped reserves five years old or more, and

•

Disclosure of the qualifications of the chief technical person who oversees the Company’s overall reserve process.

The Company is currently evaluating these new rules and cannot predict how the new rules will affect its future reporting of oil and natural gas reserves.

Note K – Business Segments


	Total Assets		Three Mos. Ended March 31, 2009				Three Mos. Ended March 31, 2008
(Millions of dollars)	at March 31, 2009		External Revenues	Interseg. Revenues	Income (Loss)		External Revenues	Interseg. Revenues	Income (Loss)
Exploration and production*
United States	$	1,508.0	71.0	—	(7.3	)	143.1	—	47.1
Canada		1,989.3	113.4	21.1	.6		326.0	23.5	151.3
United Kingdom		200.2	11.7	—	3.4		86.1	—	32.1
Malaysia		2,766.0	337.4	—	117.5		464.6	—	204.7
Other		488.8	.5	—	(63.9	)	1.4	—	(8.0	)

Total		6,952.3	534.0	21.1	50.3		1,021.2	23.5	427.2

Refining and marketing
North America		2,322.5	2,396.6	—	14.6		4,530.2	—	1.0
United Kingdom		771.1	485.9	—	(3.8	)	957.6	—	9.2

Total		3,093.6	2,882.5	—	10.8		5,487.8	—	10.2

Total operating segments		10,045.9	3,416.5	21.1	61.1		6,509.0	23.5	437.4
Corporate and other		1,019.0	29.1	—	10.1		.5	—	(29.2	)

Revenue/income from continuing operations		11,064.9	3,445.6	21.1	71.2		6,509.5	23.5	408.2
Discontinued operations, net of tax		—	—	—	99.9		—	—	.8

Total	$	11,064.9	3,445.6	21.1	171.1		6,509.5	23.5	409.0

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

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION

Results of Operations

Murphy’s net income in the first quarter of 2009 was $171.1 million, $0.89 per diluted share, down significantly from net income of $409.0 million, $2.14 per diluted share, in the same quarter of 2008. Net income includes income from discontinued operations in 2009 of $99.9 million, $0.52 per diluted share, with this income mostly being generated from a gain on sale of the Company’s Ecuador operations in March 2009. Income from discontinued operations in the first quarter of 2008 was $0.8 million, $0.01 per diluted share. In 2009, substantially lower income from the Company’s exploration and production business was partially offset by favorable results from corporate activities. Murphy’s income from continuing operations by operating segment is presented below.


	Income (Loss)
	Three Months Ended March 31,
(Millions of dollars)	2009		2008
Exploration and production	$	50.3	427.2
Refining and marketing		10.8	10.2
Corporate		10.1	(29.2	)

Income from continuing operations	$	71.2	408.2

Murphy’s income from continuing exploration and production operations was $50.3 million in the first quarter of 2009 compared to $427.2 million in the same quarter of 2008. Lower realized sales prices for crude oil and natural gas and higher exploration expenses were the primary reasons for the lower 2009 earnings. In addition, earnings in the 2008 quarter included a $39.9 million after-tax gain from sale of Berkana Energy in Canada. Exploration expense in the 2009 period was $111.1 million, up from $66.5 million in 2008. Murphy’s refining and marketing operations generated earnings of $10.8 million in the 2009 quarter compared to earnings of $10.2 million in the 2008 quarter. Corporate functions reflected a net benefit of $10.1 million in the 2009 first quarter compared to net costs of $29.2 million in 2008.

Exploration and Production

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


	Income (Loss)
	Three Months Ended March 31,
(Millions of dollars)	2009			2008
Exploration and production
United States	$	(7.3	)	47.1
Canada		0.6		151.3
United Kingdom		3.4		32.1
Malaysia		117.5		204.7
Other International		(63.9	)	(8.0	)

Total	$	50.3		427.2

In the United States, exploration and production operations had a loss of $7.3 million in the first quarter of 2009 compared to earnings of $47.1 million in the 2008 quarter. This unfavorable result was primarily due to lower oil and natural gas sales prices and higher exploration expenses. Production expense in the U.S. was less in the 2009 period due to lower operating costs compared to 2008. Depreciation expense rose in 2009 primarily due to higher per barrel equivalent amortization rates. Exploration expenses in the U.S. were $2.4 million higher in 2009 as more dry hole costs, primarily for an unsuccessful well in South Louisiana, were only partially offset by lower geophysical costs.

Earnings from operations in Canada were $0.6 million in the 2009 quarter versus $151.3 million in the 2008 quarter. The 2008 earnings included a $39.9 million after-tax gain on disposal of Berkana Energy. Canadian operations realized lower crude oil sales prices and had lower overall oil sales volumes in the current period. Natural gas sales volumes were higher in the 2009 quarter due to start-up of production in the Tupper area in British Columbia in December 2008, but natural gas sale prices were significantly lower in 2009. Production expenses in Canada were favorable in 2009 due to lower energy costs at Syncrude and the sale of the Lloydminster heavy oil field in the second quarter of 2008. Depreciation expense increased in the 2009 period compared to 2008 due mostly to the new Tupper natural gas sales volumes. Exploration expenses in Canada were $20.3 million in 2009 compared to $32.6 million in

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

2008, and the reduction was due to higher seismic costs incurred in 2008 in the Tupper natural gas area. The effective tax rate was low in Canada in 2008 due to a capital gain tax effect attributable to the profit on sale of Berkana Energy.

U.K. operations earned $3.4 million in the 2009 period versus $32.1 million in the same quarter a year ago, with the reduction due to a combination of lower crude oil and natural gas sales prices and lower crude oil and natural gas sales volumes. Production and depreciation expenses decreased in 2009 compared to 2008 in the U.K. due to the lower oil and gas sales volumes.

Operations in Malaysia reported a profit of $117.5 million in the first quarter of 2009 compared to a profit of $204.7 million in the same period in 2008. The 2009 results were unfavorable to 2008 essentially due to lower crude oil sales prices. Production volumes for crude oil and natural gas increased during the 2009 period at the Kikeh field. Depreciation expense in Malaysia rose significantly in 2009 due to Kikeh field production increases. Dry hole costs were higher in the 2009 quarter than in 2008 due to unsuccessful drilling in Block P, offshore Sabah. Geological and geophysical expenses were lower in 2009 primarily due to 3-D seismic acquisition and processing costs in Block P in the first quarter a year ago. Certain exploration expenses in Malaysia do not receive income tax benefits at the present time.

Other international operations reported a loss of $63.9 million in the 2009 period versus a loss of $8.0 million in the same period a year ago. The higher loss in 2009 was primarily due to unsuccessful exploratory drilling costs for the Abalone Deep well, offshore Western Australia, and 3-D seismic expense for Block 37 offshore Suriname.

On a worldwide basis, the Company’s crude oil, condensate and natural gas liquids sales price averaged $43.15 per barrel for the 2009 first quarter compared to $89.51 per barrel in the first quarter of 2008. Crude oil and liquids production averaged a quarterly record 139,318 barrels per day in the 2009 quarter, up from 113,339 barrels per day in the 2008 period. Average oil sales volumes increased from 126,932 barrels per day in 2008 to 134,306 barrels per day in 2009. The higher crude oil production and sales volumes were mostly attributable to the Kikeh field in Block K, offshore Sabah Malaysia, where additional production wells were drilled and put onstream during 2008. Oil production in the United States was higher in 2009 than 2008 due to better production at the Front Runner field in the deepwater Gulf of Mexico. Heavy oil production in Western Canada was lower in the 2009 first quarter compared to the 2008 period primarily due to the sale of the Lloydminster heavy oil property in the second quarter 2008. Synthetic oil production at Syncrude in northern Alberta was higher in 2009 than 2008 primarily caused by a lower royalty rate attributable to lower oil prices. Production volumes offshore Eastern Canada were lower in 2009 versus 2008 due to a combination of field decline and a higher net royalty rate. Production in the U.K. was lower in 2009 due to lower volumes produced at the Schiehallion field due to equipment downtime. North American natural gas sales prices averaged $4.66 per thousand cubic feet (MCF) in the 2009 first quarter compared to $8.40 per MCF in the same quarter of 2008. Total natural gas sales volumes averaged 111 million cubic feet per day in 2009, up from 69 million cubic feet per day in the same period last year. The increase in 2009 was primarily attributable to gas production from the Kikeh field offshore Sabah Malaysia and gas production in the Tupper area in Western Canada, both of which started up in December 2008. Natural gas sales volumes in the U.K. were lower in 2009 than in 2008 due to equipment failure at the Amethyst field that shut down production for the entire 2009 quarter.

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

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Selected operating statistics for the three-month periods ended March 31, 2009 and 2008 follow.


	Three Months Ended March 31,
	2009		2008
Net crude oil, condensate and gas liquids produced – barrels per day		139,318	113,339
Continuing operations		133,977	105,458
United States		13,268	12,112
Canada – light		—	186
– heavy		7,436	9,907
– offshore		15,542	18,717
– synthetic		13,464	11,431
United Kingdom		4,769	6,727
Malaysia		79,498	46,378
Discontinued operations		5,341	7,881

Net crude oil, condensate and gas liquids sold – barrels per day		134,306	126,932
Continuing operations		129,595	117,707
United States		13,268	12,112
Canada – light		–	186
– heavy		7,436	9,907
– offshore		13,459	17,153
– synthetic		13,464	11,431
United Kingdom		2,464	8,772
Malaysia		79,504	58,146
Discontinued operations		4,711	9,225

Net natural gas sold – thousands of cubic feet per day		111,309	68,983
United States		53,307	56,884
Canada		29,711	4,440
United Kingdom		2,492	7,659
Malaysia		25,799	—

Total net hydrocarbons produced – equivalent barrels per day (1)		157,870	124,836
Total net hydrocarbons sold – equivalent barrels per day (1)		152,858	138,429

Weighted average sales prices
Crude oil, condensate and natural gas liquids – dollars per barrel (2)
United States	$	37.55	92.03
Canada (3) – light		–	70.37
– heavy		22.30	53.57
– offshore		42.17	96.35
– synthetic		44.63	100.56
United Kingdom		44.79	98.51
Malaysia (4)		45.90	89.63

Natural gas – dollars per thousand cubic feet
United States (2)	$	5.12	8.52
Canada (3)		3.84	6.80
United Kingdom (3)		7.40	10.48
Malaysia		0.23	—

(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 production sharing contracts for Blocks SK 309 and K.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

OIL AND GAS OPERATING RESULTS (unaudited)


(Millions of dollars)	United States			Canada		United Kingdom	Malaysia		Other		Synthetic Oil – Canada		Total
Three Months Ended March 31, 2009
Oil and gas sales and other operating revenues	$	71.0		80.4		11.7	337.4		.5		54.1		555.1
Production expenses		15.2		21.7		1.9	49.5		—		44.9		133.2
Depreciation, depletion and amortization		43.3		34.5		2.1	73.7		.4		6.3		160.3
Accretion of asset retirement obligations		1.7		1.0		.5	1.7		.1		1.0		6.0
Exploration expenses
Dry holes		11.4		—		—	13.7		42.4		—		67.5
Geological and geophysical		.8		1.0		—	(.2	)	12.2		—		13.8
Other		1.6		.1		—	—		2.4		—		4.1

		13.8		1.1		—	13.5		57.0		—		85.4
Undeveloped lease amortization		5.9		19.2		—	—		.6		—		25.7

Total exploration expenses		19.7		20.3		—	13.5		57.6		—		111.1

Selling and general expenses		5.4		3.5		.8	.1		6.3		.2		16.3

Results of operations before taxes		(14.3	)	(.6	)	6.4	198.9		(63.9	)	1.7		128.2
Income tax provisions (benefits)		(7.0	)	2.0		3.0	81.4		—		(1.5	)	77.9

Results of operations (excluding corporate overhead and interest)	$	(7.3	)	(2.6	)	3.4	117.5		(63.9	)	3.2		50.3


Three Months Ended March 31, 2008
Oil and gas sales and other operating revenues	$	143.1		244.9		86.1	464.6		1.4		104.6		1,044.7
Production expenses		16.9		24.2		10.0	53.4		—		48.1		152.6
Depreciation, depletion and amortization		27.2		29.9		10.3	52.1		.2		6.7		126.4
Accretion of asset retirement obligations		1.4		1.3		.5	1.3		.2		.2		4.9
Exploration expenses
Dry holes		.5		—		—	(.3	)	—		—		.2
Geological and geophysical		10.2		10.5		—	12.7		.6		—		34.0
Other		1.5		.1		.1	—		3.1		—		4.8

		12.2		10.6		.1	12.4		3.7		—		39.0
Undeveloped lease amortization		5.1		22.0		—	—		.4		—		27.5

Total exploration expenses		17.3		32.6		.1	12.4		4.1		—		66.5

Selling and general expenses		7.1		3.6		1.0	1.2		4.5		.2		17.6

Results of operations before taxes		73.2		153.3		64.2	344.2		(7.6	)	49.4		676.7
Income tax provisions		26.1		36.8		32.1	139.5		.4		14.6		249.5

Results of operations (excluding corporate overhead and interest)	$	47.1		116.5		32.1	204.7		(8.0	)	34.8		427.2

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Refining and Marketing

Refining and marketing operations in North America had earnings of $14.6 million in the 2009 first quarter compared to earnings of $1.0 million during the first quarter of 2008. The improved results in 2009 were primarily due to higher U.S. refining margins in the just completed quarter compared to one year ago. U.S. refining margins in 2009 benefited from lower prices for crude oil feedstocks. The economic downturn in the United States in 2009 has led to reduced demand for refined products such as gasoline and diesel, which in turn led to lower retail marketing margins in the U.S. in the 2009 quarter compared to 2008. Refining and marketing operations in the United Kingdom had a loss of $3.8 million in the first quarter of 2009 compared to a profit of $9.2 million in the same quarter of 2008. Results in the U.K. were hurt by both a decrease in demand for refined products and unplanned downtime of the fluid catalytic cracking unit at the Milford Haven, Wales, refinery.

Worldwide refinery inputs were 235,274 barrels per day in the first quarter of 2009 compared to 244,508 barrels per day in the 2008 quarter. Petroleum product sales were 503,878 barrels per day in the 2009 quarter, down from 524,061 barrels per day a year ago.

Selected operating statistics for the three-month periods ended March 31, 2009 and 2008 follow.


	Three Months Ended March 31,
	2009	2008
Refinery inputs – barrels per day	235,274	244,508
North America	136,719	135,550
United Kingdom	98,555	108,958

Petroleum products sold – barrels per day	503,878	524,061
North America	406,243	427,411
Gasoline	300,470	307,784
Kerosine	15,210	3,934
Diesel and home heating oils	70,589	97,128
Residuals	15,601	13,268
Asphalt, LPG and other	4,373	5,297
United Kingdom	97,635	96,650
Gasoline	27,515	30,644
Kerosine	10,767	10,262
Diesel and home heating oils	34,876	27,570
Residuals	7,575	12,380
LPG and other	16,902	15,794

Corporate

Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, reported a net benefit of $10.1 million in the 2009 first quarter compared to net costs of $29.2 million in the first quarter of 2008. The results from corporate activities improved in 2009 compared to 2008 primarily due to a combination of favorable foreign currency exchange effects and lower net interest expense. The foreign currency exchange benefits occurred mostly in Malaysia where a stronger U.S. dollar led to foreign currency exchange gains on Malaysian income tax liabilities. Total after-tax profit for foreign exchange was $26.1 million in the 2009 quarter compared to a $4.8 million loss in 2008. The lower net interest expense was attributable to a combination of lower interest rates, lower average debt levels, and higher amounts of interest capitalized to ongoing oil and gas development projects.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Financial Condition

Net cash provided by operating activities was $380.0 million for the first three months of 2009 compared to $446.5 million during the same period in 2008. Changes in operating working capital other than cash and cash equivalents generated cash of $45.0 million in the first quarter of 2009 and used cash of $245.2 million in the first quarter of 2008.

Other predominant uses of cash in both years were for dividends, which totaled $47.6 million in 2009 and $35.6 million in 2008, and for property additions and dry holes, which, including amounts expensed, were $511.4 million and $506.7 million in the three month periods ended March 31, 2009 and 2008, respectively. Cash of $193.2 million was used to purchase Canadian government securities with maturity dates greater than 90 days during the three months ended March 31, 2009. Total capital expenditures for continuing operations were as follows:


	Three Months Ended March 31,
(Millions of dollars)	2009		2008
Capital expenditures – Continuing operations
Exploration and production	$	430.9	452.0
Refining and marketing		48.6	119.8
Corporate and other		1.2	1.0

Total capital expenditures – continuing operations	$	480.7	572.8

Working capital (total current assets less total current liabilities) at March 31, 2009 was 922.2 million, down $36.6 million from December 31, 2008. 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 $283.6 million below fair value at March 31, 2009.

At March 31, 2009, long-term notes payable of $996.3 million had decreased by $29.9 million compared to December 31, 2008. A summary of capital employed at March 31, 2009 and December 31, 2008 follows.


	March 31, 2009			Dec. 31, 2008
(Millions of dollars)	Amount		%	Amount		%
Capital employed
Notes payable	$	996.3	13.6	$	1,026.2	14.0
Stockholders' equity		6,340.2	86.4		6,279.0	86.0

Total capital employed	$	7,336.5	100.0	$	7,305.2	100.0

The Company’s ratio of earnings to fixed charges was 9.0 to 1 for the three-month period ended March 31, 2009. In May 2009, Standard & Poor’s maintained its “BBB” rating for the Company, but amended its outlook from negative to stable.

Accounting and Other Matters

Recent Accounting Pronouncements

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Accounting and Other Matters (Contd.)

Recent Accounting Pronouncements (Contd.)

Outlook

Average crude oil prices in April 2009 have risen slightly compared to the average price during the first quarter 2009. The Company expects its oil and natural gas production to average about 144,000 barrels of oil equivalent per day in the second quarter, while sales volumes are expected to be approximately 140,000 barrels of oil equivalent per day during the quarter. Production volumes are projected to be lower in the second quarter than in the first quarter due to sale of the Company’s operations in Ecuador, downtime associated with oil and natural gas production and handling operations at the Kikeh field, spring breakup in the heavy oil area of Canada, a turnaround at Syncrude, and maintenance for the Hibernia and Schiehallion fields. U.S. downstream margins continued to be squeezed during April 2009 due to weak demand for refined products in the U.S. and U.K. The Company currently anticipates total capital expenditures for the full year 2009 to be approximately $2.0 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 G 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 commodity derivative contracts in place at March 31, 2009 to hedge the cost of about 0.5 million barrels of crude oil at the Meraux and Superior refineries. A 10% increase in the price of West Texas Intermediate crude oil would have increased the recorded liability associated with these derivative contracts by approximately $2.6 million, while a 10% decrease would have reduced the recorded liability by a similar amount. Changes in the fair value of these derivative contracts generally offset the changes in value for an equivalent volume of crude oil feedstocks.

There were short-term derivative foreign exchange contracts in place at March 31, 2009 to hedge the value of the U.S. dollars against two foreign currencies. A 10% strengthening of the U.S. dollar against these foreign currencies would have increased the recorded liability associated with these contracts by approximately $14.1 million, while a 10% weakening of the U.S. dollar would have reduced the recorded liability by approximately $17.2 million. Changes in the fair value of these derivative contracts generally offset the financial statement impact of an equivalent volume of foreign currency exposures associated with other assets and/or liabilities.

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 March 31, 2009 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 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. 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 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. In April 2009, two of the four insurers agreed to a settlement with the Company and withdrew from the arbitral proceedings, which are scheduled to take place in London in the third quarter. 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.

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.

ITEM 1A.

RISK FACTORS

The Company has not identified any additional risk factors not previously disclosed in its Form 10-K filed on February 27, 2009.

ITEM 6.

EXHIBITS AND REPORTS ON FORM 8-K

(a)	The Exhibit Index on page 27 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 January 28, 2009 that included a News Release announcing the Company’s earnings and certain other financial information for the three-month and twelve-month periods ended December 31, 2008.

(c)	A report on Form 8-K was filed on February 26, 2009 that included a News Release announcing an adjustment to 2008 results due to subsequent exploration expense.

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)

May 7, 2009

(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