Edgar Filing: MURPHY OIL CORP /DE

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

For the quarterly period ended June 30, 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). x Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange act.

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

Number of shares of Common Stock, $1.00 par value, outstanding at June 30, 2009 was 190,816,602.

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		18

Item 3. Quantitative and Qualitative Disclosures About Market Risk		29

Item 4. Controls and Procedures		29

Part II – Other Information

Item 1. Legal Proceedings		30

Item 1A. Risk Factors		30

Item 4. Submission of Matters to a Vote of Security Holders		31

Item 6. Exhibits and Reports on Form 8-K		31

Signature		32

PART I – FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)


	(Unaudited)
	June 30, 2009			December 31, 2008
ASSETS
Current assets
Cash and cash equivalents	$	507,083		666,110
Canadian government securities with maturities greater than 90 days at the date of acquisition		584,682		420,340
Accounts receivable, less allowance for doubtful accounts of $7,758 in 2009 and $7,303 in 2008		1,157,585		1,033,996
Inventories, at lower of cost or market
Crude oil and blend stocks		151,266		98,217
Finished products		415,130		315,340
Materials and supplies		207,067		190,616
Prepaid expenses		131,788		92,544
Deferred income taxes		38,138		29,801

Total current assets		3,192,739		2,846,964
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $4,033,429 in 2009 and $3,824,393 in 2008		8,297,448		7,727,718
Goodwill		39,201		37,370
Deferred charges and other assets		579,880		537,046

Total assets	$	12,109,268		11,149,098


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	—		2,572
Accounts payable and accrued liabilities		1,599,209		1,434,202
Income taxes payable		310,302		451,372

Total current liabilities		1,909,511		1,888,146

Notes payable		1,531,326		1,026,222
Deferred income taxes		957,726		878,131
Asset retirement obligations		422,663		435,589
Deferred credits and other liabilities		650,422		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 191,522,141 in 2009 and 191,248,941 shares in 2008		191,522		191,249
Capital in excess of par value		657,356		631,859
Retained earnings		5,792,031		5,557,483
Accumulated other comprehensive income (loss)		15,103		(87,697	)
Treasury stock, 705,539 shares of Common Stock in 2009 and 535,135 shares in 2008, at cost		(18,392	)	(13,949	)

Total stockholders’ equity		6,637,620		6,278,945


Total liabilities and stockholders’ equity	$	12,109,268		11,149,098

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page 33.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars, except per share amounts)


	Three Months Ended June 30,					Six Months Ended June 30,
	2009			2008*		2009		2008*
REVENUES
Sales and other operating revenues	$	4,495,994		8,249,207		7,912,421		14,715,875
Gain on sale of assets		3,570		91,860		3,585		134,246
Interest and other income		56,282		3,151		85,392		3,622

Total revenues		4,555,846		8,344,218		8,001,398		14,853,743


COSTS AND EXPENSES
Crude oil and product purchases		3,574,531		6,660,439		6,130,575		11,816,490
Operating expenses		373,889		423,524		736,250		815,048
Exploration expenses, including undeveloped lease amortization		34,946		60,400		146,051		126,896
Selling and general expenses		61,602		55,374		118,434		114,148
Depreciation, depletion and amortization		197,429		155,320		392,198		315,945
Accretion of asset retirement obligations		6,164		5,128		12,417		10,284
Redetermination of Terra Nova working interest		35,091		—		35,091		—
Interest expense		13,184		21,551		25,172		42,704
Interest capitalized		(12,127	)	(5,995	)	(22,450	)	(12,944	)

Total costs and expenses		4,284,709		7,375,741		7,573,738		13,228,571


Income from continuing operations before income taxes		271,137		968,477		427,660		1,625,172
Income tax expense		110,293		349,961		195,576		598,450


Income from continuing operations		160,844		618,516		232,084		1,026,722
Income (loss) from discontinued operations, net of income taxes		(2,074	)	688		97,790		1,474


NET INCOME	$	158,770		619,204		329,874		1,028,196


INCOME PER COMMON SHARE – BASIC
Income from continuing operations	$	.84		3.26		1.22		5.42
Income (loss) from discontinued operations		(.01	)	.01		.51		.01

Net income – Basic	$	.83		3.27		1.73		5.43


INCOME PER COMMON SHARE – DILUTED
Income from continuing operations	$	.84		3.22		1.21		5.35
Income (loss) from discontinued operations		(.01	)	—		.51		.01

Net income – Diluted	$	.83		3.22		1.72		5.36


Average common shares outstanding – basic		190,746,583		189,564,247		190,633,781		189,372,416
Average common shares outstanding – diluted		192,380,595		192,263,483		192,189,238		191,832,034

*	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 June 30,			Six Months Ended June 30,
	2009		2008	2009	2008
Net income	$	158,770	619,204	329,874	1,028,196

Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation		179,504	11,525	98,517	(12,034	)
Retirement and postretirement benefit plan gains (losses)		2,095	884	4,283	(605	)


COMPREHENSIVE INCOME	$	340,369	631,613	432,674	1,015,557

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)


	Six Months Ended June 30,
	2009			2008¹
OPERATING ACTIVITIES
Net income	$	329,874		1,028,196
Income from discontinued operations		97,790		1,474

Income from continuing operations		232,084		1,026,722
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation, depletion and amortization		392,198		315,945
Amortization of deferred major repair costs		12,729		13,176
Expenditures for asset retirements		(36,686	)	(2,928	)
Dry hole costs		68,476		11,005
Amortization of undeveloped leases		53,664		56,515
Accretion of asset retirement obligations		12,417		10,284
Deferred and noncurrent income tax charges		24,239		162,553
Pretax gain from disposition of assets		(3,585	)	(134,246	)
Net increase in noncash operating working capital		(193,135	)	(34,527	)
Other operating activities, net		(49,571	)	25,321

Net cash provided by continuing operations		512,830		1,449,820
Net cash provided (required) by discontinued operations		(328	)	58,766

Net cash provided by operating activities		512,502		1,508,586


INVESTING ACTIVITIES
Property additions and dry hole costs		(1,004,897	)	(1,010,329	)
Proceeds from sales of assets		1,160		360,677
Purchase of investment securities²		(1,185,757	)	(345,072	)
Proceeds from maturity of investment securities²		1,021,415		—
Expenditures for major repairs		(12,952	)	(33,152	)
Other – net		(15,251	)	(11,615	)
Investing activities of discontinued operations
Sales proceeds		78,908		—
Other		(845	)	(4,587	)

Net cash required by investing activities		(1,118,219	)	(1,044,078	)


FINANCING ACTIVITIES
Increase in notes payable		505,000		27,000
Decrease in nonrecourse debt of a subsidiary		(2,572	)	(5,235	)
Proceeds from exercise of stock options and employee stock purchase plans		5,429		20,443
Excess tax benefits related to exercise of stock options		2,031		18,310
Cash dividends paid		(95,326	)	(71,227	)

Net cash provided (required) by financing activities		414,562		(10,709	)


Effect of exchange rate changes on cash and cash equivalents		32,128		(11,001	)


Net increase (decrease) in cash and cash equivalents		(159,027	)	442,798
Cash and cash equivalents at January 1		666,110		673,707


Cash and cash equivalents at June 30	$	507,083		1,116,505


SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid	$	87,411		161,745

Interest paid, net of amounts capitalized		1,607		29,774

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)


	Six Months Ended June 30,
	2009			2008
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued		—		—


Common Stock – par $1.00, authorized 450,000,000 shares, issued 191,522,141 shares at June 30, 2009 and 190,973,101 shares at June 30, 2008
Balance at beginning of period	$	191,249		189,973
Exercise of stock options		273		1,000

Balance at end of period		191,522		190,973


Capital in Excess of Par Value
Balance at beginning of period		631,859		547,185
Exercise of stock options, including income tax benefits		7,870		39,958
Restricted stock transactions and other		5,439		6,961
Stock-based compensation		11,783		15,307
Sale of stock under employee stock purchase plans		405		—

Balance at end of period		657,356		609,411


Retained Earnings
Balance at beginning of period		5,557,483		3,983,998
Net income for the period		329,874		1,028,196
Cash dividends		(95,326	)	(71,227	)

Balance at end of period		5,792,031		4,940,967


Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		(87,697	)	351,765
Foreign currency translation gains (losses), net of income taxes		98,517		(12,034	)
Retirement and postretirement benefit plan gains (losses), net of income taxes		4,283		(605	)

Balance at end of period		15,103		339,126


Treasury Stock
Balance at beginning of period		(13,949	)	(6,747	)
Sale of stock under employee stock purchase plans		629		363
Cancellation of performance-based restricted stock and forfeitures		(5,072	)	(7,650	)

Balance at end of period		(18,392	)	(14,034	)


Total Stockholders’ Equity	$	6,637,620		6,066,443

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 June 30, 2009, and the results of operations, cash flows and changes in stockholders’ equity for the three-month and six-month periods ended June 30, 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-month and six-month periods ended June 30, 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. 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 $103.6 million, net of income taxes of $14.0 million, from the sale of the Ecuador properties in 2009. 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	$	105,185
Other noncurrent liabilities		35

Liabilities associated with assets sold	$	105,220

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


	Six Months Ended June 30,
(Thousands of dollars)	2009		2008
Revenues, including a pretax gain on sale of $117,557 in 2009	$	125,654	43,138
Income before income tax expense		110,551	2,344
Income tax expense		12,761	870

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 June 30, 2009, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $375.1 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 30, 2009 and 2008.


(Thousands of dollars)	2009		2008
Beginning balance at January 1	$	310,118	272,155
Additions pending the determination of proved reserves		65,012	16,748
Reclassifications to proved properties based on the determination of proved reserves		—	(6,869	)

Balance at June 30	$	375,130	282,034

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


	June 30,
	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	$	93,446	29	6	$	19,891	2	1
One to two years		18,046	10	1		26,473	11	1
Two to three years		26,271	2	2		122,796	19	2
Three years or more		237,367	8	6		112,874	11	6

	$	375,130	49	15	$	282,034	43	10

Of the $281.7 million of exploratory well costs capitalized more than one year at June 30, 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 $6.5 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 the U.K. further studies to evaluate the discovery are ongoing, 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 D – Insurance Matters

The Company maintains insurance coverage related to losses of production and profits for occurrences such as storms, fires and other issues. During the second quarter 2009, the Company received insurance proceeds to settle business interruption claims related to downtime following a fire at the Meraux, Louisiana refinery in June 2003. Additionally, other insurance proceeds were received during the second quarter 2009 related to damages at the Meraux refinery caused by Hurricane Katrina in 2005. Gains of $21.9 million were recorded in Sales and Other Operating Revenues in the respective Consolidated Statements of Income for the three-month and six-month periods ended June 30, 2009.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – Employee and Retiree Benefit Plans

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

The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June 30, 2009 and 2008.


	Three Months Ended June 30,
	Pension Benefits					Other Postretirement Benefits
(Thousands of dollars)	2009			2008		2009		2008
Service cost	$	4,335		4,562		817		628
Interest cost		7,306		6,673		1,449		1,285
Expected return on plan assets		(4,900	)	(5,829	)	—		—
Amortization of prior service cost		420		340		(69	)	(66	)
Amortization of transitional asset		(114	)	(131	)	—		—
Recognized actuarial loss		3,074		1,025		439		421

		10,121		6,640		2,636		2,268
Special termination benefits expense		1,867		—		—		—
Curtailment expense		972		—		—		—

Net periodic benefit expense	$	12,960		6,640		2,636		2,268


	Six Months Ended June 30,
	Pension Benefits					Other Postretirement Benefits
(Thousands of dollars)	2009			2008		2009		2008
Service cost	$	8,453		9,100		1,593		1,237
Interest cost		14,294		13,414		2,840		2,535
Expected return on plan assets		(10,246	)	(11,686	)	—		—
Amortization of prior service cost		818		684		(135	)	(131	)
Amortization of transitional asset		(220	)	(263	)	—		—
Recognized actuarial loss		6,018		2,041		860		830

		19,117		13,290		5,158		4,471
Special termination benefits expense		1,867		—		—		—
Curtailment expense		972		—		—		—

Net periodic benefit expense	$	21,956		13,290		5,158		4,471

The increase in net periodic benefit expense in 2009 compared to 2008 is primarily due to the decline in value of pension plan assets during the last year. Special termination and curtailment expenses in 2009 related to an early retirement program for certain employees.

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 other postretirement benefits plan during 2009. The anticipated defined benefit pension plan contributions included $30.0 million of voluntary contributions in the U.S. During the six-month period ended June 30, 2009, the Company made contributions of $25.4 million (including $15.0 million of voluntary contributions to the U.S. defined benefit pension plans) and remaining funding in 2009 for the Company’s domestic and foreign defined benefit pension and postretirement plans is anticipated to be $29.7 million.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – 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. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, was $42.42 per unit. Also in February 2009 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 six-month periods ended June 30, 2009 and 2008 was $5.4 million and $20.4 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $2.6 million and $20.2 million for the six-month periods ended June 30, 2009 and 2008, respectively.

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


	Six Months Ended June 30,
*(Thousands of dollars)*	2009		2008
Compensation charged against income before tax benefit	$	12,060	16,158
Related income tax benefit recognized in income		3,314	5,321

Note G – Earnings per Share

Net income was used as the numerator in computing both basic and diluted income per Common share for the three-month and six-month periods ended June 30, 2009 and 2008. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended June 30,		Six Months Ended June 30,
(Weighted-average shares)	2009	2008	2009	2008
Basic method	190,746,583	189,564,247	190,633,781	189,372,416
Dilutive stock options and restricted stock units	1,634,012	2,699,236	1,555,457	2,459,618

Diluted method	192,380,595	192,263,483	192,189,238	191,832,034

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 1,922,000 shares at a weighted average share price of $56.96 in each 2009 period and 928,500 shares at a weighted average share price of $72.745 in each 2008 period.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – 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 both June 30, 2009 and 2008 to manage the cost of about 0.7 million barrels of crude oil at the Company’s refineries. The impact on consolidated income from continuing operations before income taxes from marking these derivative contracts to market as of the balance sheet dates was a charge of $0.4 million and a benefit of $1.0 million, respectively, in the six-month periods ended June 30, 2009 and 2008.

•

Foreign Currency Exchange Risks – The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. Short-term derivative instruments were outstanding at June 30, 2009 and 2008 to manage the risk of approximately $21 million and $83 million, respectively, of U.S. dollar balances associated with the Company’s Canadian operation. Short-term derivative instruments were outstanding at June 30, 2009 and 2008 to manage the risk of approximately $50 million and $97 million equivalent of ringgit balances, respectively, in the Company’s Malaysian operations. The impact on consolidated income from continuing operations before taxes from marking these derivative contracts to market as of the balance sheet dates was a gain of $1.6 million and a charge of $1.1 million, respectively, in the six-month periods ended June 30, 2009 and 2008.

At June 30, 2009, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.


	June 30, 2009
	Asset Derivatives			Liability Derivatives
(Thousands of dollars)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity derivative contracts	—	$	—	Accounts Payable and Accrued Liabilities	$	16,730

Foreign exchange derivative contracts	Accounts Receivable		1,778	Accounts Payable and Accrued Liabilities		178

For the six-month period ended June 30, 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.


	Six Months Ended June 30, 2009
(Thousands of dollars)	Location of Gain (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
Commodity derivative contracts	Crude Oil and Product Purchases	$	(24,878	)
Foreign exchange derivative contracts	Interest and Other Income		4,272

		$	(20,606	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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 June 30, 2009 are presented in the following table.


	June 30, 2009			Fair Value Measurements at Reporting Date Using
(Thousands of dollars)	June 30, 2009			Quoted Prices in Active Markets for Identical Assets (Liabilities) (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets
Derivative assets	$	1,778		—		1,778		—

Liabilities
Derivative liabilities	$	(16,908	)	—		(16,908	)	—
Nonqualified employee savings plan		(8,610	)	(8,610	)	—		—

	$	(25,518	)	(8,610	)	(16,908	)	—

Note I – Accumulated Other Comprehensive Income (Loss)

The components of Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheets at June 30, 2009 and December 31, 2008 are presented in the following table.


(Thousands of dollars)	June 30, 2009			Dec. 31, 2008
Foreign currency translation gains, net of tax	$	144,034		45,517
Retirement and postretirement benefit plan losses, net of tax		(128,931	)	(133,214	)

Accumulated other comprehensive income (loss)	$	15,103		(87,697	)

Note J – 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 affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Because governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Environmental and Other Contingencies (Contd.)

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.

A settlement of class action litigation regarding 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 was approved by the U.S. District Court for the Eastern District of Louisiana on January 30, 2007. The majority of the settlement of $330 million was paid by the Company’s insurers; the Company recorded an expense of $18 million in 2006 related to settlement costs not expected to be covered by insurance. Remaining litigation arising out of this incident includes one opt out from the class action and less than 50 individual claims outside of the class. In August 2007, four high level excess insurers instituted arbitration proceedings against the Company to determine their coverage obligations with respect to costs associated with the oil spill and ensuing litigation. As of June 2009, three of the four excess insurers have settled with the Company and withdrawn from the arbitration proceedings. An arbitral tribunal heard the matter as to the one remaining insurer in London in July 2009, and a decision is pending. The Company believes that insurance coverage should be afforded and that neither the ultimate resolution of the remaining litigation nor the insurance arbitration will have a material adverse effect on its net income, financial condition or liquidity in a future period.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Environmental and Other Contingencies (Contd.)

Litigation arising out of a June 10, 2003 fire in the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery was settled in July 2009 and memorialized via a filing in the U.S. District Court for the Eastern District of Louisiana on July 24, 2009. An arbitral tribunal is scheduled to hear the Company’s claim for indemnity from one of its insurers, AEGIS, in September, 2009. The Company believes that insurance coverage does apply for this matter. The Company continues to believe that the ultimate resolution of the June 2003 ROSE fire litigation, including associated insurance coverage issues, 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 12.0%. 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 approximately January 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 would reduce the Company’s interest at Terra Nova. During the second quarter 2009, the Company recorded a $35.1 million pretax charge ($24.7 million after tax) to reflect the estimated liability that will be owed through June 2009 activity for the anticipated reduction in working interest to 11.5%. The final results of the arbitration process could further reduce the Company’s working interest. The Company cannot predict at this time how its final ownership interest will be affected by the redetermination process, and it is unable to determine whether the ultimate 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 June 30, 2009, the Company had contingent liabilities of $7.8 million under a financial guarantee and $132.5 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to the financial guarantee and letters of credit because it is believed that the likelihood of having these drawn is remote.

Note K – 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 six-month period ended June 30, 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Accounting Matters (Contd.)

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 H 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 May 2009, the FASB issued SFAS No. 165, Subsequent Events, which was adopted by the Company at June 30, 2009. This statement clarified the accounting for and disclosure of subsequent events that occur after the balance sheet date through the date of issuance of the applicable financial statements. The adoption of this statement did not have a significant effect on the Company’s consolidated financial statements. See Note M for further disclosures.

In June 2009, the FASB issued SFAS No. 166, Accounting for Transfers of Financial Assets — an amendment of FASB Statement No. 140. This statement makes the concept of a qualifying special-purpose entity as defined in SFAS No. 140 no longer relevant for accounting purposes. Therefore, formerly qualifying special-purpose entities must be reevaluated for consolidation by reporting entities in accordance with the applicable consolidation guidance. This statement is effective for the Company beginning on January 1, 2010. The Company is currently evaluating this statement and is unable to predict at this time how it will impact its consolidated financial statements in future periods.

In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R). This statement requires a company to perform an analysis to determine whether its variable interests give it a controlling financial interest in a variable interest entity. The primary beneficiary of a variable interest entity has both the power to direct the activities of the entity that most significantly impact the entity’s economic performance and the obligation to absorb potentially significant losses of the entity or the right to receive potentially significant benefits from the entity. A company is required to make ongoing reassessments of whether it is the primary beneficiary of a variable interest entity. This statement also amends previous guidance for determining whether an entity is considered a variable interest entity. This statement is effective for the Company beginning on January 1, 2010. The Company is currently evaluating this statement and is unable to predict at this time how it will impact its consolidated financial statements in future periods.

In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. This statement, which is effective for interim and annual periods ending after September 15, 2009 (the third calendar quarter for Murphy Oil), recognizes the FASB Accounting Standards Codification as the single source of authoritative nongovernment U.S. generally accepted accounting principles. The codification supersedes all existing accounting standards documents issued by the FASB, and establishes that all other accounting literature not included in the codification will be considered nonauthoritative. Although the codification does not change U.S. generally accepted accounting principles, it does reorganize the principles into accounting topics using a consistent structure. The codification also includes relevant U.S. Securities and Exchange Commission guidance following the same topical structure. Beginning with the Company’s third quarter 2009 financial reports, all references to U.S. generally accepted accounting principles will use the new topical guidelines established with the codification. Otherwise, this new standard is not expected to have a material impact on the Company’s consolidated financial statements in future periods.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Accounting Matters (Contd.)

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,

•

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Business Segments


	Total Assets at June 30, 2009		Three Mos. Ended June 30, 2009				Three Mos. Ended June 30, 2008¹
(Millions of dollars)	Total Assets at June 30, 2009		External Revenues	Inter- Segment Revenues	Income (Loss)		External Revenues		Inter- segment Revenues	Income (Loss)
Exploration and production²
United States	$	1,659.2	82.9	—	3.9		182.5		—	71.4
Canada		2,178.9	165.7	9.5	(6.4	)	450.2		26.8	236.4
United Kingdom		205.7	15.1	—	3.6		37.5		—	14.4
Malaysia		2,961.8	306.2	—	127.2		544.1		—	263.4
Other		629.2	.2	—	(10.0	)	(.6	)	—	(9.1	)

Total		7,634.8	570.1	9.5	118.3		1,213.7		26.8	576.5

Refining and marketing
North America		2,367.2	3,241.4	—	21.4		5,532.8		—	5.0
United Kingdom		873.3	688.0	—	6.4		1,594.6		—	72.3

Total		3,240.5	3,929.4	—	27.8		7,127.4		—	77.3

Total operating segments		10,875.3	4,499.5	9.5	146.1		8,341.1		26.8	653.8
Corporate		1,234.0	56.3	—	14.8		3.1		—	(35.3	)

Revenue/income from continuing operations		—	4,555.8	9.5	160.9		8,344.2		26.8	618.5
Discontinued operations, net of tax		—	—	—	(2.1	)	—		—	0.7

Total	$	12,109.3	4,555.8	9.5	158.8		8,344.2		26.8	619.2


	Six Months Ended June 30, 2009					Six Months Ended June 30, 2008¹
(Millions of dollars)	External Revenues		Inter- segment Revenues	Income (Loss)		External Revenues	Inter- segment Revenues	Income (Loss)
Exploration and production²
United States	$	153.9	—	(3.4	)	325.6	—	118.5
Canada		279.1	30.6	(5.8	)	776.2	50.3	387.7
United Kingdom		26.8	—	7.0		123.6	—	46.5
Malaysia		643.6	—	244.7		1,008.7	—	468.1
Other		.7	—	(73.9	)	.8	—	(17.1	)

Total		1,104.1	30.6	168.6		2,234.9	50.3	1,003.7

Refining and marketing
North America		5,638.0	—	36.0		10,063.0	—	6.0
United Kingdom		1,173.9	—	2.6		2,552.2	—	81.5

Total		6,811.9	—	38.6		12,615.2	—	87.5

Total operating segments		7,916.0	30.6	207.2		14,850.1	50.3	1,091.2
Corporate		85.4	—	24.9		3.6	—	(64.5	)

Revenue/income from continuing operations		8,001.4	30.6	232.1		14,853.7	50.3	1,026.7
Discontinued operations, net of tax		—	—	97.8		—	—	1.5

Total	$	8,001.4	30.6	329.9		14,853.7	50.3	1,028.2

¹	Reclassified to conform to current presentation.

²	Additional details about results of oil and gas operations are presented in the tables on pages 23 and 24.

Note M– Subsequent Events

The Company has evaluated subsequent events through the date of issuance of these consolidated financial statements (August 7, 2009). In certain cases, events that occur after the balance sheet date lead to recognition and/or disclosure in the consolidated financial statements.

ITEM 2.

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

Results of Operations

Murphy’s net income in the second quarter of 2009 was $158.8 million ($0.83 per diluted share) compared to net income of $619.2 million ($3.22 per diluted share) in the second quarter of 2008. The lower income in 2009 primarily related to lower sales prices for the Company’s crude oil and natural gas production and lower earnings in the refining and marketing operations. Discontinued operations, associated with the Ecuador properties sold in March 2009, had an after-tax loss of $2.1 million ($0.01 per diluted share) in the second quarter 2009 and after-tax income of $0.7 million (nil per diluted share) in the 2008 quarter. Income from continuing operations was $160.9 million ($0.84 per diluted share) in 2009 quarter compared to $618.5 million ($3.22 per diluted share) in the 2008 quarter. The second quarter 2009 included a $24.7 million after-tax charge associated with an anticipated reduction of the Company’s working interest in the Terra Nova field, offshore Eastern Canada. The quarter also included after-tax gains of $13.4 million from settlements with insurers related to property damaged by a fire and hurricane in prior years at the Meraux, Louisiana refinery. Net income in the second quarter 2008 included an after-tax gain of $67.9 million on sale of Lloydminster heavy oil properties in Western Canada.

For the first six months of 2009, net income totaled $329.9 million ($1.72 per diluted share) compared to net income of $1,028.2 million ($5.36 per diluted share) for the same period in 2008. The lower six-month net income in 2009 compared to 2008 was also primarily attributable to lower crude oil and natural gas sales prices. The 2009 six-month net income included income from discontinued operations of $97.8 million ($0.51 per diluted share) with this amount primarily being generated from a gain on sale of operations in Ecuador in March 2009. Income from discontinued operations in the six-month period of 2008 was $1.5 million ($0.01 per diluted share). The six-month period in 2009 included the aforementioned $24.7 million after-tax charge for an anticipated Terra Nova working interest reduction and the $13.4 million of after-tax gains from insurance settlements. The six-month period in 2008 included after-tax gains of $108.3 million on sale of the Company’s interest in Berkana Energy Corporation and Lloydminster properties.

Murphy’s income from continuing operations by operating segment is presented below.


	Income (Loss)
	Three Months Ended June 30,				Six Months Ended June 30,
(Millions of dollars)	2009		2008		2009	2008
Exploration and production	$	118.3	576.5		168.6	1,003.7
Refining and marketing		27.8	77.3		38.6	87.5
Corporate		14.8	(35.3	)	24.9	(64.5	)

Income from continuing operations	$	160.9	618.5		232.1	1,026.7

In the 2009 second quarter, the Company’s continuing exploration and production operations earned $118.3 million compared to $576.5 million in the 2008 quarter. Income in the 2009 quarter was unfavorably affected by lower crude oil and natural gas sales prices compared to 2008, a $24.7 million after-tax charge for an anticipated reduction in the Company’s working interest in the Terra Nova field, and lower gains on property disposals. The 2008 second quarter included a $67.9 million after-tax gain on sale of Lloydminster properties. Exploration expenses were $35.0 million in the second quarter of 2009 compared to $60.4 million in the same period of 2008. The Company’s refining and marketing operations generated income of $27.8 million in the 2009 second quarter compared to income of $77.3 million in the same quarter of 2008. Refining and marketing margins improved and gains from insurance settlements were realized in North America in the second quarter 2009, but income for the United Kingdom downstream business was significantly lower in the 2009 second quarter due mostly to much weaker refining margins. The 2009 quarter included after-tax gains of $13.4 million from insurance settlements at the Meraux refinery. The corporate function generated after-tax benefits of $14.8 million in the 2009 second quarter compared to after-tax costs of $35.3 million in the 2008 period with the improvement in 2009 mostly due to favorable foreign currency exchange effects and lower net interest expense.

The Company’s continuing exploration and production operations earned $168.6 million in the first half of 2009 compared to $1,003.7 million in the same period of 2008. Earnings in 2009 were adversely impacted by significantly lower realized oil and natural gas sales prices, the aforementioned charge for an anticipated working interest redetermination at the Terra Nova field, and lower gains on sale of assets. The Company’s refining and marketing operations had earnings of $38.6 million in the first six months of 2009 compared to earnings of $87.5 million in the same 2008 period. The 2009 period included stronger results in the North American downstream business compared to a year ago based on better operating margins and insurance settlements, but income

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

from downstream operations in the U.K. were significantly lower in 2009 compared to 2008 due to weaker margins in refining operations. Corporate after-tax benefits were $24.9 million in the 2009 period compared to after-tax costs of $64.5 million in the 2008 period. Favorable foreign currency exchange results and lower net interest expense accounted for the improved results in 2009.

Exploration and Production

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


	Income (Loss)
	Three Months Ended June 30,					Six Months Ended June 30,
(Millions of dollars)	2009			2008		2009		2008
Exploration and production
United States	$	3.9		71.4		(3.4	)	118.5
Canada		(6.4	)	236.4		(5.8	)	387.7
United Kingdom		3.6		14.4		7.0		46.5
Malaysia		127.2		263.4		244.7		468.1
Other International		(10.0	)	(9.1	)	(73.9	)	(17.1	)

Total	$	118.3		576.5		168.6		1,003.7

Second quarter 2009 vs. 2008

United States exploration and production operations reported quarterly earnings of $3.9 million in the second quarter of 2009 compared to earnings of $71.4 million in the 2008 quarter. Earnings were lower in the 2009 period due mostly to weaker oil and natural gas sales prices. Depreciation expense was $15.8 million higher in 2009 due to higher oil and natural gas production volumes and higher per unit depletion rates in 2009. Exploration expenses in the 2009 period decreased $11.0 million from the prior year primarily due to lower seismic acquisition costs.

Operations in Canada lost $6.4 million in the second quarter 2009 compared to a profit of $236.4 million in the 2008 quarter. Canadian earnings decreased in the 2009 quarter mostly due to lower oil sales prices, an after-tax charge of $24.7 million in 2009 associated with an anticipated reduction of the Company’s working interest at the Terra Nova field, and no repeat of a $67.9 million after-tax gain on sale of Lloydminster heavy oil properties in the 2008 quarter in Western Canada. Oil production and sales volumes declined in the 2009 period compared to 2008 primarily due to lower oil produced offshore Eastern Canada and at Syncrude and sale of the Lloydminster heavy oil field late in the second quarter of 2008. Natural gas volumes increased in 2009 mostly due to start-up of Tupper area production in December 2008. Production expenses in Canada were favorable in 2009 due primarily to lower energy costs at Syncrude, partially offset by expenses at the Tupper area that was not producing in the 2008 period. Depreciation expenses were higher in the 2009 quarter primarily due to the new natural gas production at Tupper. Exploration expenses were $4.2 million lower in the 2009 period due to less geophysical expense at the Tupper area.

United Kingdom operations earned $3.6 million in the 2009 quarter, down from $14.4 million in the 2008 quarter. The decline was primarily due to lower crude oil and natural gas sales prices and lower natural gas sales volumes in the 2009 quarter compared to 2008.

Operations in Malaysia reported earnings of $127.2 million in the 2009 quarter compared to earnings of $263.4 million during the same period in 2008. The earnings reduction in 2009 in Malaysia was primarily caused by lower crude oil sales prices. The 2009 quarter benefited from higher sales volumes of crude oil and natural gas. Production expense was lower in the 2009 period due to no sales volumes in the current quarter at the West Patricia field. Depreciation expense increased in the 2009 period due to higher oil and natural gas sales volumes compared to the 2008 quarter. Exploration expense was lower in 2009 due to costs for an unsuccessful exploration well in Block K during the 2008 period.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Second quarter 2009 vs. 2008 (Contd.)

Other international operations reported a loss of $10.0 million in the second quarter of 2009 compared to a loss of $9.1 million in the 2008 period. The unfavorable variance was primarily related to higher costs of administration in other foreign jurisdictions in the 2009 period.

On a worldwide basis, the Company’s crude oil, condensate and gas liquids prices averaged $53.55 per barrel in the second quarter 2009 compared to $115.35 in the 2008 period. Average crude oil and liquids production was 118,145 barrels per day in the second quarter of 2009 compared to 111,493 barrels per day in the second quarter of 2008, with the increase primarily attributable to ramp-up of the Kikeh field in Malaysia. Crude oil production in the heavy oil area in Canada was lower in 2009 mostly due to sale of the Lloydminster field late in the second quarter of 2008. Canadian offshore crude oil production fell in 2009 due to decline at the Hibernia field and more equipment downtime and a higher royalty rate at the Terra Nova field. Synthetic oil production was lower in 2009 than 2008 due to more downtime at Syncrude. There was no oil production from discontinued operations in the 2009 quarter due to the Company selling its Ecuador operations in March 2009. North American natural gas sales prices averaged $3.25 per thousand cubic feet (MCF) in the most recent quarter compared to $11.70 per MCF in the same quarter of 2008. Natural gas sales volumes averaged 147 million cubic feet per day in the second quarter 2009, up from 55 million cubic feet per day in the 2008 quarter, primarily due to new production volumes at the Tupper area in Canada and the Kikeh field offshore Malaysia, both of which commenced production in December 2008. U.S. natural gas sales volumes increased in the 2009 quarter due to higher volumes at the Front Runner field. Natural gas sales volumes declined in the U.K. in 2009 primarily due to downtime for repairs at the Amethyst field in the North Sea.

Six months 2009 vs. 2008

U.S. E&P operations had a loss of $3.4 million for the six months ended June 30, 2009 compared to income of $118.5 million in the 2008 period. The 2009 period had lower oil and natural gas sales prices, but benefited from higher oil sales volumes. Production expenses were lower in 2009 mostly due to less costs for workovers and other field maintenance. Depreciation expense increased in 2009 due to the higher sales volumes plus higher per-unit depletion rates compared to 2008. Exploration expense in the 2009 period was $8.6 million below 2008 levels due to significantly lower geological and geophysical expenses in the current period, but partially offset by higher dry hole costs in 2009.

Canadian operations lost $5.8 million in the first half of 2009 compared to a profit of $387.7 million a year ago. Lower sales prices for crude oil and natural gas, an after-tax charge of $24.7 million in 2009 for an anticipated reduction of the Company’s working interest in the Terra Nova field, and a 2008 after-tax gain of $108.3 million on sales of properties primarily led to the reduction in 2009 earnings. Lower production expense in 2009 was mostly related to lower energy costs at Syncrude. Higher depreciation expense in 2009 was attributable to more natural gas sales volumes after start-up of production at Tupper. Exploration expenses were $16.5 million lower in 2009 primarily due to less seismic costs in the current period.

Income in the U.K. for the six-month period in 2009 was $7.0 million compared to $46.5 million a year ago with the decline in earnings primarily due to lower oil and natural gas sales prices and lower crude oil and natural gas sales volumes. Production and depreciation expenses were down in 2009 compared to 2008 in association with the lower oil and gas sales volumes.

Malaysia operations earned $244.7 million in the first half of 2009 compared to earnings of $468.1 million in the 2008 period. Earnings were down in 2009 primarily due to lower crude oil sales prices. Sales volumes for oil and natural gas were higher in the 2009 period than 2008 due to ramp-up of oil production at Kikeh and start-up of natural gas production at Kikeh in December 2008. Production expense was lower in the 2009 period due to lower sales volumes and cost reductions in the current period at the West Patricia field. Depreciation expense was higher in 2009 and related to the additional Kikeh field production. Exploration expense was $9.1 million lower in 2009 mostly due to costs for 3-D seismic acquisition and processing in Block P, offshore Sabah, in 2008 that did not repeat. Selling and general expense declined in 2009 due to higher levels of costs charged to production and development operations.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Six months 2009 vs. 2008 (Contd.)

Other international operations reported a loss of $73.9 million in the first six months of 2009 compared to a loss of $17.1 million in the 2008 period. The larger loss in the 2009 period was primarily due to higher dry hole costs in Australia and higher geophysical expenses offshore Suriname in 2009. Higher administrative costs in 2009 primarily related to more office costs in the Republic of the Congo.

For the first six months of 2009, the Company’s sales price for crude oil, condensate and gas liquids averaged $47.09 per barrel compared to $101.65 per barrel in 2008. Crude oil, condensate and gas liquids production in the first half of 2009 averaged 128,673 barrels per day compared to 112,416 barrels per day a year ago. The increase was mostly attributable to Kikeh field production, offshore Malaysia, but production volumes were lower in the heavy oil producing area of Western Canada following the sale of the Lloydminster field in 2008, the Terra Nova field offshore Eastern Canada, the U.K. due to lower production levels at the Schiehallion field, and the West Patricia field, offshore Sarawak, Malaysia. Discontinued operations crude oil volumes are associated with oil fields in Ecuador that were sold in March 2009. The average sales price for North American natural gas in the first six months of 2009 was $3.89 per MCF, down from $9.83 per MCF realized in 2008. Natural gas sales volumes were up from 62 million cubic feet per day in 2008 to 129 million cubic feet per day in 2009, with the increase due mostly to natural gas production volumes from the Tupper area in British Columbia and the Kikeh field in Malaysia, both of which came onstream in December 2008.

Additional details about results of oil and gas operations are presented in the tables on pages 23 and 24.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Selected operating statistics for the three-month and six-month periods ended June 30, 2009 and 2008 follow.


	Three Months Ended June 30,			Six Months Ended June 30,
	2009		2008	2009	2008
Net crude oil, condensate and gas liquids produced – barrels per day		118,145	111,493	128,673	112,416
Continuing operations		118,145	103,716	126,017	104,587
United States		13,529	12,880	13,399	12,496
Canada – light		—	—	—	93
– heavy		6,923	9,259	7,178	9,583
– offshore		12,441	16,555	13,983	17,636
– synthetic		10,102	11,305	11,774	11,368
United Kingdom		3,556	5,335	4,159	6,031
Malaysia		71,594	48,382	75,524	47,380
Discontinued operations		—	7,777	2,656	7,829

Net crude oil, condensate and gas liquids sold – barrels per day		112,538	110,366	123,362	118,649
Continuing operations		112,538	103,613	121,020	110,660
United States		13,529	12,880	13,399	12,496
Canada – light		—	—	—	93
– heavy		6,923	9,259	7,178	9,583
– offshore		16,291	16,241	14,883	16,697
– synthetic		10,102	11,305	11,774	11,368
United Kingdom		2,638	2,618	2,552	5,695
Malaysia		63,055	51,310	71,234	54,728
Discontinued operations		—	6,753	2,342	7,989

Net natural gas sold – thousands of cubic feet per day		147,433	54,739	129,471	61,861
United States		48,702	44,806	50,992	50,845
Canada		52,841	2,068	41,340	3,254
United Kingdom		3,093	7,865	2,794	7,762
Malaysia		42,797	—	34,345	—

Total net hydrocarbons produced – equivalent barrels per day (1)		142,717	120,616	150,252	122,726
Total net hydrocarbons sold – equivalent barrels per day (1)		137,110	119,489	144,941	128,959

Weighted average sales prices – Crude oil, condensate and gas liquids – dollars per barrel (2)
United States	$	54.94	117.99	46.37	105.25
Canada (3) – light		—	—	—	70.37
– heavy		41.48	81.76	31.50	67.19
– offshore		56.01	121.21	49.79	108.44
– synthetic		58.72	129.51	50.71	114.96
United Kingdom		57.51	121.77	51.40	103.86
Malaysia (4)		52.95	115.45	49.04	101.86

Natural gas – dollars per thousand cubic feet
United States (2)	$	3.54	11.83	4.36	9.98
Canada (3)		2.98	8.80	3.31	7.44
United Kingdom (3)		4.48	11.46	5.78	10.98
Malaysia		0.23	—	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 the 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 – THREE MONTHS ENDED JUNE 30, 2009 AND 2008


(Millions of dollars)	United States			Canada		United Kingdom	Malaysia		Other		Synthetic Oil – Canada	Total
Three Months Ended June 30, 2009
Oil and gas sales and other revenues	$	82.9		121.2		15.1	306.2		.2		54.0	579.6
Production expenses		15.7		26.7		3.6	39.6		—		44.9	130.5
Depreciation, depletion and amortization		44.2		47.0		3.2	61.8		.3		5.9	162.4
Accretion of asset retirement obligations		1.7		1.0		.3	1.9		.2		1.0	6.1
Exploration expenses
Dry holes		(.6	)	—		—	.1		1.5		—	1.0
Geological and geophysical		.8		.3		—	.4		.7		—	2.2
Other		2.8		.1		.2	—		.7		—	3.8

		3.0		.4		.2	.5		2.9		—	7.0
Undeveloped lease amortization		7.0		19.7		—	—		1.3		—	28.0

Total exploration expenses		10.0		20.1		.2	.5		4.2		—	35.0

Terra Nova working interest redetermination		—		35.1		—	—		—		—	35.1
Selling and general expenses		5.1		4.3		.8	(.9	)	5.4		.2	14.9

Results of operations before taxes		6.2		(13.0	)	7.0	203.3		(9.9	)	2.0	195.6
Income tax provisions (benefits)		2.3		(4.9	)	3.4	76.1		.1		.3	77.3

Results of operations (excluding corporate overhead and interest)	$	3.9		(8.1	)	3.6	127.2		(10.0	)	1.7	118.3


Three Months Ended June 30, 2008*
Oil and gas sales and other revenues	$	182.5		343.0		37.5	544.1		(.6	)	134.0	1,240.5
Production expenses		15.8		22.6		3.2	55.6		—		52.9	150.1
Depreciation, depletion and amortization		28.4		30.0		3.7	51.4		.2		6.5	120.2
Accretion of asset retirement obligations		1.5		1.1		.6	1.3		.2		.2	4.9
Exploration expenses
Dry holes		(.3	)	—		—	11.1		—		—	10.8
Geological and geophysical		11.9		2.1		—	(.5	)	.1		—	13.6
Other		2.8		.1		.3	.1		3.7		—	7.0

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

Total exploration expenses		21.0		24.3		.3	10.7		4.1		—	60.4

Selling and general expenses		4.9		3.2		.8	(.7	)	4.3		.2	12.7

Results of operations before taxes		110.9		261.8		28.9	425.8		(9.4	)	74.2	892.2
Income tax provisions (benefits)		39.5		76.5		14.5	162.4		(.3	)	23.1	315.7

Results of operations (excluding corporate overhead and interest)	$	71.4		185.3		14.4	263.4		(9.1	)	51.1	576.5

*	Reclassified to conform to current presentation.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2009 AND 2008


(Millions of dollars)	United States			Canada		United Kingdom	Malaysia		Other		Synthetic Oil – Canada		Total
Six Months Ended June 30, 2009
Oil and gas sales and other revenues	$	153.9		201.6		26.8	643.6		.7		108.1		1,134.7
Production expenses		30.9		48.4		5.5	89.1		–		89.8		263.7
Depreciation, depletion and amortization		87.5		81.5		5.3	135.5		.7		12.2		322.7
Accretion of asset retirement obligations		3.4		2.0		.8	3.6		.3		2.0		12.1
Exploration expenses
Dry holes		10.8		—		—	13.8		43.9		—		68.5
Geological and geophysical		1.6		1.3		—	.2		12.9		—		16.0
Other		4.4		.2		.2	—		3.1		—		7.9

		16.8		1.5		.2	14.0		59.9		—		92.4
Undeveloped lease amortization		12.9		38.9		—	—		1.9		—		53.7

Total exploration expenses		29.7		40.4		.2	14.0		61.8		—		146.1

Terra Nova working interest redetermination		—		35.1		—	—		—		—		35.1
Selling and general expenses		10.5		7.8		1.6	(.8	)	11.7		.4		31.2

Results of operations before taxes		(8.1	)	(13.6	)	13.4	402.2		(73.8	)	3.7		323.8
Income tax provisions		(4.7	)	(2.9	)	6.4	157.5		.1		(1.2	)	155.2

Results of operations (excluding corporate overhead and interest)	$	(3.4	)	(10.7	)	7.0	244.7		(73.9	)	4.9		168.6


Six Months Ended June 30, 2008*
Oil and gas sales and other revenues	$	325.6		587.9		123.6	1,008.7		.8		238.6		2,285.2
Production expenses		32.7		46.8		13.2	109.0		–		101.0		302.7
Depreciation, depletion and amortization		55.6		59.9		14.0	103.5		.4		13.2		246.6
Accretion of asset retirement obligations		2.9		2.4		1.1	2.6		.4		.4		9.8
Exploration expenses
Dry holes		.2		—		—	10.8		—		—		11.0
Geological and geophysical		22.1		12.6		—	12.2		.7		—		47.6
Other		4.3		.2		.4	.1		6.8		—		11.8

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

Total exploration expenses		38.3		56.9		.4	23.1		8.2		—		126.9

Selling and general expenses		12.0		6.8		1.8	.5		8.8		.4		30.3

Results of operations before taxes		184.1		415.1		93.1	770.0		(17.0	)	123.6		1,568.9
Income tax provisions		65.6		113.3		46.6	301.9		.1		37.7		565.2

Results of operations (excluding corporate overhead and interest)	$	118.5		301.8		46.5	468.1		(17.1	)	85.9		1,003.7

*	Reclassified to conform to current presentation.

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
	Three Months Ended June 30,			Six Months Ended June 30,
	2009		2008	2009	2008
(Millions of dollars)
Refining and marketing
North America	$	21.4	5.0	36.0	6.0
United Kingdom		6.4	72.3	2.6	81.5

Total	$	27.8	77.3	38.6	87.5

The Company’s refining and marketing operations generated income of $27.8 million in the 2009 second quarter compared to earnings of $77.3 million in the same quarter of 2008. North American operations had a profit of $21.4 million in the 2009 period compared to $5.0 million in 2008. Refining and retail marketing margins in the U.S. were improved in the second quarter of 2009 compared to 2008. Additionally, the 2009 quarter included $13.4 million of after-tax gains on settlement of insurance claims related to property damaged in prior years by a fire and hurricane at the Meraux, Louisiana refinery. Earnings in the United Kingdom were $6.4 million in the second quarter of 2009 compared to earnings of $72.3 million in the same period a year ago. Refining margins were much weaker in the 2009 quarter following strong U.K. refinery margins a year ago. Worldwide petroleum product sales averaged 538,596 barrels per day in 2009, compared to 549,539 barrels per day in the same period in 2008. The 2009 sales volume decrease was attributable to lower sales volumes at the Company’s U.K. refining operations. Worldwide refinery inputs were 248,364 barrels per day in the second quarter of 2009 compared to 246,080 in the 2008 quarter.

Refining and marketing operations in the first half of 2009 generated a profit of $38.6 million compared to a profit of $87.5 million in the 2008 period. In North America, the 2009 profit of $36.0 million was significantly above the 2008 profit of $6.0 million. Current year results were favorable mostly due to stronger refining margins in the 2009 period compared to 2008, and after-tax gains of $13.4 million on insurance settlements at the Meraux refinery in the 2009 period. Results in the United Kingdom reflected earnings of $2.6 million in the first six months of 2009 compared to earnings of $81.5 million in the 2008 period. The reduction was primarily due to significantly weaker refining margins on sale of petroleum products in 2009 compared to 2008.

Selected operating statistics for the three-month and six-month periods ended June 30, 2009 and 2008 follow.


	Three Months Ended June 30,		Six Months Ended June 30,
	2009	2008	2009	2008
Refinery inputs – barrels per day	248,364	246,080	241,855	245,294
North America	141,710	126,860	139,228	131,205
United Kingdom	106,654	119,220	102,627	114,089

Petroleum products sold – barrels per day	538,596	549,539	521,333	536,800
North America	429,821	423,363	418,097	425,387
Gasoline	321,714	310,422	311,151	309,103
Kerosine	9,267	88	12,222	2,011
Diesel and home heating oils	75,295	92,520	72,955	94,824
Residuals	14,221	15,550	14,907	14,409
Asphalt, LPG and other	9,324	4,783	6,862	5,040
United Kingdom	108,775	126,176	103,236	111,413
Gasoline	31,799	41,394	29,669	36,019
Kerosine	9,936	14,196	10,349	12,229
Diesel and home heating oils	41,155	45,488	38,033	36,529
Residuals	11,418	14,200	9,507	13,290
LPG and other	14,467	10,898	15,678	13,346

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Corporate

Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had net benefits of $14.8 million in the 2009 second quarter compared to net costs of $35.3 million in the second quarter of 2008. The results of corporate activities improved in 2009 compared to 2008 due to favorable after-tax results of foreign currency exchange and lower net interest expense. Total after-tax benefits from foreign currency transactions were $33.6 million in the 2009 quarter compared to net costs of $4.8 million in the 2008 quarter. In addition, net interest expense was lower in 2009 compared to 2008 due to a combination of lower interest rates on outstanding borrowings and higher amounts of interest capitalized to ongoing oil and natural gas development projects.

For the first six months of 2009, corporate activities reflected net benefits of $24.9 million compared to net costs of $64.5 million a year ago. The reduction in six-month costs in 2009 compared to 2008 also related to improved foreign exchange effects and lower net interest expense. Total after-tax benefits for foreign currency exchange movements were $59.7 million in the 2009 period compared to net costs of $10.7 million in the first six months of 2008. Net interest expense was favorable in 2009 compared to 2008 due to lower interest rates on borrowed funds and more interest capitalized to oil and gas development projects.

Financial Condition

Net cash provided by operating activities was $512.5 million for the first six months of 2009 compared to $1,508.6 million during the same period in 2008. Changes in operating working capital other than cash and cash equivalents used cash of $193.1 million in the first six months of 2009 and $34.5 million in the first six months of 2008.

Other predominant uses of cash in both years were for dividends, which totaled $95.3 million in 2009 and $71.2 million in 2008, and for property additions and dry holes, which, including amounts expensed, were $1,004.9 million and $1,010.3 million in the six-month periods ended June 30, 2009 and 2008, respectively. The Company increased the annualized dividend rate from $0.75 per share to $1.00 per share beginning in the third quarter of 2008. Total capital expenditures for continuing operations were as follows:


	Six Months Ended June 30,
(Millions of dollars)	2009		2008
Capital Expenditures – Continuing operations
Exploration and production	$	925.0	863.1
Refining and marketing		102.2	220.2
Corporate and other		1.7	1.8

Total capital expenditures – continuing operations		1,028.9	1,085.1

Working capital (total current assets less total current liabilities) at June 30, 2009 was $1,283.2 million, an increase of $324.4 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 $525.4 million below fair value at June 30, 2009.

At June 30, 2009, long-term notes payable of $1,531.3 million had increased in total by $505.1 million compared to December 31, 2008. A summary of capital employed at June 30, 2009 and December 31, 2008 follows.


	June 30, 2009			Dec. 31, 2008
(Millions of dollars)	Amount		%	Amount		%
Capital employed
Notes payable	$	1,531.3	18.7		1,026.2	14.0
Stockholders’ equity		6,637.6	81.3		6,279.0	86.0

Total capital employed	$	8,168.9	100.0	$	7,305.2	100.0

The Company’s ratio of earnings to fixed charges was 11.7 to 1 for the six-month period ended June 30, 2009.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Accounting and Other Matters

Recent Accounting Pronouncements

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Accounting and Other Matters (Contd.)

Recent Accounting Pronouncements (Contd.)

In June 2009, the FASB issed SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. This statement, which is effective for interim and annual periods ending after September 15, 2009 (the third calendar quarter for Murphy Oil), recognizes the FASB Accounting Standards Codification as the single source of authoritative nongovernment U.S. generally accepted accounting principles. The codification supersedes all existing accounting standards documents issued by the FASB, and establishes that all other accounting literature not included in the codification will be considered nonauthoritative. Although the codification does not change U.S. generally accepted accounting principles, it does reorganize the principles into accounting topics using a consistent structure. The codification also includes relevant U.S. Securities and Exchange Commission guidance following the same topical structure. Beginning with the Company’s third quarter 2009 financial reports, all references to U.S. generally accepted accounting principles will use the new topical guidelines established with the codification. Otherwise, this new standard is not expected to have a material impact on the Company’s consolidated financial statements in future periods.

Outlook

Average crude oil prices in July 2009 improved slightly compared to the average price during the second quarter of 2009. The Company expects its oil and natural gas production to average about 169,000 barrels of oil equivalent per day in the third quarter 2009. U.S. downstream margins had improved during July 2009 due to stronger demand for refined products, but U.K. downstream margins had weakened considerably during July compared to the second quarter 2009 average. The Company currently anticipates total capital expenditures for the full year 2009 to be approximately $2.1 billion.

Forward-Looking Statements

This Form 10-Q contains forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. These statements, which express management’s current views concerning future events or results, are subject to inherent risks and uncertainties. Factors that could cause actual results to differ materially from those expressed or implied in our forward-looking statements include, but are not limited to, the volatility and level of crude oil and natural gas prices, the level and success rate of our exploration programs, our ability to maintain production rates and replace reserves, political and regulatory instability, and uncontrollable natural hazards. For further discussion of risk factors, see Murphy’s 2008 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

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 H 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 June 30, 2009 to hedge the cost of about 0.7 million barrels of crude oil at the Company’s refineries. A 10% increase in the respective benchmark price of crude oil would have increased the recorded liability associated with these derivative contracts by approximately $5.2 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 the value for an equivalent volume of crude oil feedstocks.

There were short-term derivative foreign exchange contracts in place at June 30, 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 reduced the recorded net asset associated with these contracts by approximately $6.6 million, while a 10% weakening of the U.S. dollar would have increased the recorded net asset by approximately $8.1 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 June 30, 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

A settlement of class action litigation regarding 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 was approved by the U.S. District Court for the Eastern District of Louisiana on January 30, 2007. The majority of the settlement of $330 million was paid by the Company’s insurers; the Company recorded an expense of $18 million in 2006 related to settlement costs not expected to be covered by insurance. Remaining litigation arising out of this incident includes one opt out from the class action and less than 50 individual claims outside of the class. In August 2007, four high level excess insurers instituted arbitration proceedings against the Company to determine their coverage obligations with respect to costs associated with the oil spill and ensuing litigation. As of June 2009, three of the four excess insurers have settled with the Company and withdrawn from the arbitration proceedings. An arbitral tribunal heard the matter as to the one remaining insurer in London in July 2009, and a decision is pending. The Company believes that coverage should be afforded and that 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 herein 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 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At the annual meeting of security holders on May 13, 2009, the directors proposed by management were elected with a tabulation of votes to the nearest share as shown below.


	For	Withheld
Frank W. Blue	169,456,028	1,304,884
Claiborne P. Deming	169,094,643	1,666,269
Robert A. Hermes	164,541,069	6,219,843
James V. Kelley	164,964,509	5,796,403
R. Madison Murphy	159,449,361	11,311,551
William C. Nolan Jr.	164,108,033	6,652,880
Ivar B. Ramberg	169,476,637	1,284,276
Neal E. Schmale	164,121,844	6,639,068
David J. H. Smith	169,351,127	1,409,786
Caroline G. Theus	168,745,620	2,015,293
David M. Wood	169,112,802	1,648,110

Regarding a shareholder proposal seeking amendments to the Company’s equal employment opportunity policy, no representative of the proponent was present at the meeting. Accordingly, no formal vote was taken on the matter. Nevertheless, the Company tabulated the votes cast in pre-meeting proxy voting which indicated that the proposal would not have carried had it been presented at the meeting.

The earlier appointment by the Audit Committee of the Board of Directors of KPMG LLP as independent registered public accounting firm for 2009 was approved with 168,244,959 shares voted in favor and 2,428,897 shares voted in opposition.

ITEM 6.

EXHIBITS AND REPORTS ON FORM 8-K

(a)	The Exhibit Index on page 33 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 May 6, 2009 that included a News Release announcing the Company’s earnings for the three-month period ended March 31, 2009.

SIGNATURE

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


*MURPHY OIL CORPORATION*
(Registrant)

By		/s/ JOHN W. ECKART
		John W. Eckart, Vice President
		and Controller (Chief Accounting Officer and Duly Authorized Officer)

August 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

101		Interactive Data Files

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

Attached as Exhibit 101 to this report are documents formatted in XBRL (Extensible Business Reporting Language). Users of this data are advised pursuant to Rule 406T of Regulation S-T that the interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of section 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise not subject to liability under these sections. The financial information contained in the XBRL-related documents is “unaudited” or “unreviewed.”

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