Edgar Filing: MURPHY OIL CORP /DE

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

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 September 30, 2010

¨	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 September 30, 2010 was 192,366,738.

MURPHY OIL CORPORATION

TABLE OF CONTENTS


	Page
Part I – Financial Information
Item 1. Financial Statements
Consolidated Statements of Income		2
Consolidated Balance Sheets		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		19

Item 3. Quantitative and Qualitative Disclosures About Market Risk		30

Item 4. Controls and Procedures		30

Part II – Other Information

Item 1. Legal Proceedings		31

Item 1A. Risk Factors		31

Item 6. Exhibits		31

Signature		32

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars, except per share amounts)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
REVENUES
Sales and other operating revenues	$	6,072,417			5,202,198			16,893,445			13,114,619
Gain on sale of assets		208			151			997			3,736
Interest and other income (expense)		(8,842	)		(18,592	)		(58,568	)		66,800

Total revenues		6,063,783			5,183,757			16,835,874			13,185,155


COSTS AND EXPENSES
Crude oil and product purchases		4,759,402			4,092,713			12,991,528			10,223,288
Operating expenses		506,996			421,621			1,432,847			1,157,871
Exploration expenses, including undeveloped lease amortization		62,046			37,899			181,503			183,950
Selling and general expenses		69,422			56,712			203,404			175,146
Depreciation, depletion and amortization		285,280			245,539			866,172			637,737
Accretion of asset retirement obligations		8,104			6,717			23,561			19,134
Redetermination of Terra Nova working interest		4,491			1,301			15,353			36,392
Interest expense		12,751			12,611			41,453			37,783
Interest capitalized		(4,708	)		(4,135	)		(11,069	)		(26,585	)

Total costs and expenses		5,703,784			4,870,978			15,744,752			12,444,716


Income from continuing operations before income taxes		359,999			312,779			1,091,122			740,439
Income tax expense		157,167			123,902			467,110			319,478


Income from continuing operations		202,832			188,877			624,012			420,961
Income from discontinued operations, net of income taxes		—			—			—			97,790


NET INCOME	$	202,832			188,877			624,012			518,751


INCOME PER COMMON SHARE – BASIC
Income from continuing operations	$	1.06			0.99			3.26			2.21
Income from discontinued operations		—			—			—			0.51

Net income – Basic	$	1.06			0.99			3.26			2.72


INCOME PER COMMON SHARE – DILUTED
Income from continuing operations	$	1.05			0.98			3.24			2.19
Income from discontinued operations		—			—			—			0.51

Net income – Diluted	$	1.05			0.98			3.24			2.70


Average common shares outstanding – basic		191,943,813			190,811,162			191,577,000			190,691,892
Average common shares outstanding – diluted		193,437,992			192,641,808			192,866,485			192,375,146

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page 33.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)


	(Unaudited) September 30, 2010			December 31, 2009
ASSETS
Current assets
Cash and cash equivalents	$	462,392			301,144
Canadian government securities with maturities greater than 90 days at the date of acquisition		630,248			779,025
Accounts receivable, less allowance for doubtful accounts of $8,081 in 2010 and $7,761 in 2009		1,363,300			1,463,297
Inventories, at lower of cost or market
Crude oil and blend stocks		209,327			128,936
Finished products		404,417			384,250
Materials and supplies		224,721			220,796
Prepaid expenses		88,169			83,218
Deferred income taxes		74,282			15,029

Total current assets		3,456,856			3,375,695

Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $5,665,235 in 2010 and $4,714,826 in 2009		9,846,026			9,065,088
Goodwill		41,550			40,652
Deferred charges and other assets		388,190			274,924


Total assets	$	13,732,622			12,756,359


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	10			38
Accounts payable and accrued liabilities		2,293,157			1,794,406
Income taxes payable		458,522			387,164

Total current liabilities		2,751,689			2,181,608

Long-term debt		1,024,339			1,353,183
Deferred income taxes		1,109,220			1,018,767
Asset retirement obligations		495,729			476,938
Deferred credits and other liabilities		384,726			379,837

Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued		—			—
Common Stock, par $1.00, authorized 450,000,000 shares, issued 192,835,791 shares in 2010 and 191,797,600 shares in 2009		192,836			191,798
Capital in excess of par value		737,223			680,509
Retained earnings		6,679,889			6,204,316
Accumulated other comprehensive income		369,198			287,187
Treasury stock, 469,053 shares of Common Stock in 2010 and 682,222 shares of Common Stock in 2009, at cost		(12,227	)		(17,784	)

Total stockholders’ equity		7,966,919			7,346,026


Total liabilities and stockholders’ equity	$	13,732,622			12,756,359

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 September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Net income	$	202,832		188,877		624,012		518,751

Other comprehensive income, net of tax
Net gain from foreign currency translation		115,670		145,066		75,285		243,583
Retirement and postretirement benefit plan adjustments		2,199		18,756		6,726		23,039


COMPREHENSIVE INCOME	$	320,701		352,699		706,023		785,373

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)


	Nine Months Ended September 30,
	2010			2009
OPERATING ACTIVITIES
Net income	$	624,012			518,751
Adjustments to reconcile net income to net cash provided by operating activities
Income from discontinued operations		—			(97,790	)
Depreciation, depletion and amortization		866,172			637,737
Amortization of deferred major repair costs		27,480			19,272
Expenditures for asset retirements		(34,376	)		(44,308	)
Dry hole costs		35,045			84,228
Amortization of undeveloped leases		76,816			66,534
Accretion of asset retirement obligations		23,561			19,134
Deferred and noncurrent income tax charges		42,268			46,454
Pretax gain from disposition of assets		(997	)		(3,736	)
Net (increase) decrease in noncash operating working capital		417,237			(139,029	)
Other operating activities, net		123,663			79,548

Net cash provided by continuing operations		2,200,881			1,186,795
Net cash required by discontinued operations		—			(328	)

Net cash provided by operating activities		2,200,881			1,186,467


INVESTING ACTIVITIES
Property additions and dry hole costs		(1,611,656	)		(1,542,032	)
Proceeds from sales of assets		2,195			1,570
Purchase of investment securities*		(1,862,609	)		(1,755,184	)
Proceeds from maturity of investment securities*		2,011,386			1,381,211
Expenditures for major repairs		(96,000	)		(15,528	)
Other – net		(31,225	)		(26,154	)
Investing activities of discontinued operations
Sales proceeds		—			78,908
Other		—			(845	)

Net cash required by investing activities		(1,587,909	)		(1,878,054	)


FINANCING ACTIVITIES
Borrowings (repayments) of long-term debt		(247,028	)		453,500
Repayment of nonrecourse debt of a subsidiary		(82,000	)		(2,572	)
Proceeds from exercise of stock options and employee stock purchase plans		26,100			8,594
Excess tax benefits related to exercise of stock options		9,585			2,474
Withholding tax on stock-based incentive awards		(5,170	)		—
Cash dividends paid		(148,439	)		(143,026	)

Net cash provided (required) by financing activities		(446,952	)		318,970


Effect of exchange rate changes on cash and cash equivalents		(4,772	)		21,574


Net increase (decrease) in cash and cash equivalents		161,248			(351,043	)
Cash and cash equivalents at January 1		301,144			666,110


Cash and cash equivalents at September 30	$	462,392			315,067

*	Investments are 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)


	Nine Months Ended September 30,
	2010			2009
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued		—			—

Common Stock – par $1.00, authorized 450,000,000 shares, issued 192,835,791 at September 30, 2010 and 191,626,348 shares at September 30, 2009
Balance at beginning of period	$	191,798			191,249
Exercise of stock options		1,038			377

Balance at end of period		192,836			191,626


Capital in Excess of Par Value
Balance at beginning of period		680,509			631,859
Exercise of stock options, including income tax benefits		34,973			10,894
Restricted stock transactions and other		(9,688	)		2,473
Stock-based compensation		30,712			19,871
Sale of stock under employee stock purchase plans		717			674

Balance at end of period		737,223			665,771


Retained Earnings
Balance at beginning of period		6,204,316			5,557,483
Net income for the period		624,012			518,751
Cash dividends		(148,439	)		(143,026	)

Balance at end of period		6,679,889			5,933,208


Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		287,187			(87,697	)
Foreign currency translation gains, net of income taxes		75,285			243,583
Retirement and postretirement benefit plan adjustments, net of income taxes		6,726			23,039

Balance at end of period		369,198			178,925


Treasury Stock
Balance at beginning of period		(17,784	)		(13,949	)
Sale of stock under employee stock purchase plans		994			932
Awarded restricted stock, net of forfeitures		4,305			—
Cancellation of performance-based restricted stock and forfeitures		258			(5,071	)

Balance at end of period		(12,227	)		(18,088	)


Total Stockholders’ Equity	$	7,966,919			6,951,442

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, 2009. In the opinion of Murphy’s management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company’s financial position at September 30, 2010, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2010 and 2009, 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 2009 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month and nine-month periods ended September 30, 2010 are not necessarily indicative of future results.

Note B – Discontinued Operations

On March 12, 2009, the Company sold its operations in Ecuador for net cash proceeds of $78.9 million, subject to post-closing adjustments. The acquirer also assumed certain tax and other liabilities associated with the Ecuador properties sold. These properties 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. 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 4.3 million barrels. All Ecuador operating results prior to the sale, and the resulting gain on disposal, have been reported as discontinued operations. 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 during 2009 from the sold properties, including the gain on sale.


(Thousands of dollars)	Nine months Ended September 30, 2009
Revenues, including a pretax gain on sale of $117,557	$	125,654
Income before income tax expense		110,551
Income tax expense		12,761

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Property, Plant and Equipment

Under U.S. generally accepted accounting principles for companies that use the successful efforts method of accounting, exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

At September 30, 2010, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $459.7 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2010 and 2009.


(Thousands of dollars)	2010		2009
Beginning balance at January 1	$	369,862		310,118
Additions pending the determination of proved reserves		89,797		115,334
Reclassifications to proved properties based on the determination of proved reserves		—		(60,251	)

Balance at September 30	$	459,659		365,201

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


	September 30,
	2010						2009
(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	$	83,642		13		5	$	113,145		10		6
One to two years		118,776		12		3		49,421		4		4
Two to three years		50,604		4		4		16,064		6		—
Three years or more		206,637		32		3		186,571		26		4

	$	459,659		61		15	$	365,201		46		14

Of the $376.0 million of exploratory well costs capitalized more than one year at September 30, 2010, $237.4 million is in Malaysia, $104.8 million is in the U.S., $14.9 million is in Republic of the Congo, $9.5 million is in the U.K., and $9.4 million is in Canada. In Malaysia either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. In the U.S. drilling and development operations are planned. In Republic of the Congo further appraisal drilling is planned. In Canada a continuing drilling and development program is underway and in the U.K. further studies to evaluate the discovery are ongoing.

In July 2010, the Company announced that its Board of Directors had approved plans to exit the U.S. refining and U.K. refining and marketing businesses. These operations, which have been placed for sale, are essentially encompassed within the U.S. manufacturing and U.K. refining and marketing segments presented in Note R. The Company currently anticipates the sale of these operations to be completed in 2011. The Company expects that the results of these operations will be presented as discontinued operations in future periods when the criteria for held for sale under U.S. generally accepted accounting principles have been met.

In August 2010, the Company purchased an unfinished ethanol plant in Hereford, Texas, for $40 million. The Company expects the construction of the plant to be completed and the plant to be in operation by the end of the first quarter of 2011. The allocation of the purchase price to the assets, which include land, buildings and equipment, will be finalized in the fourth quarter 2010.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Inventories

Inventories are carried at the lower of cost or market. The cost of crude oil and finished products is predominantly determined on the last-in, first-out (LIFO) method. At September 30, 2010 and December 31, 2009, the carrying value of inventories under the LIFO method was $612.1 million and $551.2 million, respectively, less than such inventories would have been valued using the first-in, first-out (FIFO) method.

Note E – Cash Flow Disclosures

Additional disclosures regarding cash flow activities are provided below.


	Nine Months Ended September 30
	2010			2009
Net (increase) decrease in operating working capital other than cash and cash equivalents:
(Increase) decrease in accounts receivable	$	99,628			(103,713	)
(Increase) decrease in inventories		(104,464	)		(167,292	)
(Increase) decrease in prepaid expenses		(2,045	)		989
(Increase) decrease in deferred income tax assets		(59,254	)		(5,173	)
Increase (decrease) in accounts payable and accrued liabilities		412,015			335,572
Increase (decrease) in current income tax liabilities		71,357			(199,412	)

Total	$	417,237			(139,029	)


Supplementary disclosures:
Cash income taxes paid	$	419,313			101,880
Interest paid, net of amounts capitalized		17,162			(233	)

Note F – 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 nine-month periods ended September 30, 2010 and 2009.


	Three Months Ended September 30,
	Pension Benefits						Other Postretirement Benefits
(Thousands of dollars)	2010			2009			2010			2009
Service cost	$	5,282			4,445			921			816
Interest cost		7,480			7,392			1,474			1,450
Expected return on plan assets		(5,933	)		(4,990	)		—			—
Amortization of prior service cost		387			429			(67	)		(68	)
Amortization of transitional asset		(127	)		(121	)		—			—
Recognized actuarial loss		2,995			3,086			596			438

Net periodic benefit expense	$	10,084			10,241			2,924			2,636

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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


	Nine Months Ended September 30,
	Pension Benefits						Other Postretirement Benefits
(Thousands of dollars)	2010			2009			2010			2009
Service cost	$	15,738			12,898			2,729			2,409
Interest cost		22,361			21,686			4,379			4,290
Expected return on plan assets		(17,675	)		(15,236	)		—			—
Amortization of prior service cost		1,158			1,247			(197	)		(203	)
Amortization of transitional asset		(383	)		(341	)		—			—
Recognized actuarial loss		8,948			9,104			1,770			1,298

		30,147			29,358			8,681			7,794
Special termination benefits expense		—			1,867			—			—
Curtailment expense		—			575			—			397

Net periodic benefit expense	$	30,147			31,800			8,681			8,191

Special termination and curtailment expenses in the nine-month 2009 period related to an early retirement program for certain employees in the United States.

During the nine-month period ended September 30, 2010, the Company made contributions of $18.8 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2010 for the Company’s defined benefit pension and postretirement plans is anticipated to be $8.3 million.

In March 2010, the U.S. enacted a health care reform law. Along with other provisions, the law (a) eliminates the tax free status of federal subsidies to companies with qualified retiree prescription drug plans that are actuarially equivalent to Medicare Part D plans beginning in 2013; (b) imposes a 40% excise tax on high-cost health plans as defined in the law beginning in 2018; (c) eliminates lifetime or annual coverage limits and required coverage for preventative health services beginning in September 2010; and (d) imposes a fee of $2 (subsequently adjusted for inflation) for each person covered by a health insurance policy beginning in September 2010.

The Company provides a health care benefit plan to eligible U.S. employees and most U.S. retired employees. The new law did not significantly affect the Company’s consolidated financial statements as of September 30, 2010 and for the three-month and nine-month periods then ended. The Company is still evaluating the various components of the new law and cannot predict with certainly all the ways it may impact the Company. However, based on the evaluation performed to date, the Company currently believes that the health care reform law will not have a material effect on its financial condition, net income or cash flow in future periods.

Note G – Incentive Plans

The costs resulting from all share-based payment transactions are 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 September 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note G – Incentive Plans (Contd.)

In February 2010, the Committee granted stock options for 1,605,628 shares at an exercise price of $52.845 per share. The Black-Scholes valuation for these awards was $18.75 per option. The Committee also granted 449,100 performance-based restricted stock units in February 2010 under the 2007 Long-Term Plan. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, ranged from $42.38 to $50.95 per unit. Also in February the Committee granted 43,370 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 $52.49 per share.

Cash received from options exercised under all share-based payment arrangements for the nine-month periods ended September 30, 2010 and 2009 was $26.1 million and $8.6 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $11.7 million and $3.5 million for the nine-month periods ended September 30, 2010 and 2009, respectively.

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


	Nine Months Ended September 30,
(Thousands of dollars)	2010		2009
Compensation charged against income before tax benefit	$	31,594		20,104
Related income tax benefit recognized in income		9,144		5,629

Note H – Earnings per Share

Net income was used as the numerator in computing both basic and diluted income per Common share for the three-month and nine-month periods ended September 30, 2010 and 2009. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended September 30,				Nine Months Ended September 30,
(Weighted-average shares)	2010		2009		2010		2009
Basic method		191,943,813		190,811,162		191,577,000		190,691,892
Dilutive stock options and restricted stock units		1,494,179		1,830,646		1,289,485		1,683,254

Diluted method		193,437,992		192,641,808		192,866,485		192,375,146

Certain options to purchase shares of common stock were outstanding during the 2010 and 2009 periods but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. These included 2,237,753 shares at a weighted average share price of $58.79 in each 2010 period and 1,872,625 shares at a weighted average share price of $56.74 in each 2009 period.

Note I – Income Taxes

The Company’s effective income tax rate generally exceeds the statutory U.S. tax rate of 35%. The effective tax rate is calculated as the amount of income tax expense divided by income before income tax expense. For the three-month and nine-month periods in 2010 and 2009, the Company’s effective income tax rates were as follows:


	2010			2009
Three months ended September 30		43.7	%		39.6	%
Nine months ended September 30		42.8	%		43.1	%

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Income Taxes (Contd.)

The effective tax rates for the periods presented exceeded the U.S. statutory tax rate of 35% due to several factors, including: the effects of income generated in foreign tax jurisdictions; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are available or are not presently being recorded due to a lack of reasonable certainty of adequate future revenue against which to utilize these expenses as deductions. The tax rate for the nine-month period in 2010 benefited 0.5% for an income tax adjustment in the U.K. Additionally, an enacted 1% tax rate reduction in the U.K. effective in April 2011 reduced the effective tax rate in the three-month and nine-month periods of 2010 by 0.5% and 0.2%, respectively.

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. As of September 30, 2010, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2007; Canada – 2006; United Kingdom – 2007; and Malaysia – 2006.

Note J – Financial Instruments and Derivatives

Murphy periodically utilizes derivative instruments to manage certain risks related to commodity prices and foreign currency exchange rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges. The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated any derivative contracts as hedges, and therefore, it recognizes all gains and losses on derivative contracts in its Consolidated Income Statement.

•

Commodity Purchase Price Risks – The Company is subject to commodity price risks related to crude oil and intermediate feedstocks it holds in inventory at its refineries. Short-term derivative instruments were outstanding at September 30, 2010 and 2009 to manage the cost of about 0.9 million barrels and 0.6 million barrels, respectively, of crude oil feedstocks at the Company’s U.S. refineries. At September 30, 2010, the Company also had open derivative contracts covering 0.4 million barrels of inventories of intermediate feedstocks to be processed at these refineries.

The Company is also subject to commodity price risk related to corn that it will purchase in the future for feedstock at its ethanol production facility in Hankinson, North Dakota. At September 30, 2010, the Company had open physical delivery fixed-price purchase commitment contracts for approximately 5.4 million bushels of corn for processing at its ethanol plant. The Company also had outstanding derivative contracts to sell an equivalent volume of these fixed-priced quantities and buy them back at future prices in effect on the expected date of delivery under the purchase commitment contracts.

•

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 September 30, 2010 and 2009 to manage the risk of certain income tax payments due in 2010 and later years that are payable in Malaysian ringgits. The equivalent U.S. dollars of Malaysian ringgit derivative contracts open at September 30, 2010 and 2009 were approximately $194.0 million and $100.0 million, respectively. Short-term derivative instruments were also outstanding at September 30, 2010 and 2009 to manage the risk of certain U.S. dollar accounts receivable associated with sale of crude oil production in Canada. A total of $107.0 million and $22.0 million U.S. dollar contracts were outstanding at September 30, 2010 and 2009, respectively, related to these Canadian receivables.

The Company has marked to market each of these open commodity and foreign currency exchange derivative contracts as well as the corn fixed-price purchase commitment contracts. The financial statement impacts for the respective periods are included in the following tables.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Financial Instruments and Derivatives (Contd.)

At September 30, 2010 and December 31, 2009, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

September 30, 2010

December 31, 2009

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity

Accounts receivable

376

Accounts receivable

2,296

Foreign exchange

Accounts receivable

14,187

Accounts receivable

340

For the three-month and nine-month periods ended September 30, 2010 and 2009, the gains and losses recognized in the consolidated statements of income for derivative instruments not designated as hedging instruments are presented in the following table.


			Gain (Loss)					Gain (Loss)
			Three Months Ended September 30,					Nine Months Ended
(Thousands of dollars)	Statement of Income Location		Three Months Ended September 30,					September 30,
Type of Derivative Contract	Statement of Income Location		2010			2009		2010			2009
Commodity		Crude oil and product purchases	$	(1,695	)		1,183		(1,085	)		(23,695	)
Foreign exchange		Interest and other income		13,954			908		29,681			5,180

			$	12,259			2,091		28,596			(18,515	)

Note K – Fair Value Measurements

The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet. The fair value hierarchy is based on the quality of inputs used to measure fair value, with Level 1 being the highest quality and Level 3 being the lowest quality. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants.

The carrying value of assets and liabilities recorded at fair value on a recurring basis at September 30, 2010 and December 31, 2009 are presented in the following table.


	September 30, 2010										December 31, 2009
(Thousands of dollars)	Level 1			Level 2		Level 3		Total			Level 1			Level 2		Level 3		Total
Assets
Foreign exchange derivative contracts	$	—			14,187		—		14,187			—			340		—		340
Commodity derivative contracts		—			376		—		376			—			2,296		—		2,296

	$	—			14,563		—		14,563			—			2,636		—		2,636

Liabilities
Nonqualified employee savings plans	$	(6,553	)		—		—		(6,553	)		(5,691	)		—		—		(5,691	)

	$	(6,553	)		—		—		(6,553	)		(5,691	)		—		—		(5,691	)

The fair value of commodity derivative contracts was determined based on market quotes for WTI crude and the fair value of foreign exchange derivative contracts was based on market quotes for similar contracts at the balance sheet date. The income effect of changes in fair value of commodity derivative contracts is recorded in Crude Oil and Product Purchases in the Consolidated Statement of Income and changes in fair value of foreign exchange derivative contracts is recorded in Interest and Other Income. The nonqualified employee savings plan is an unfunded savings plan through which the participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of nonqualified employee savings plan is recorded in Selling and General Expense.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Accumulated Other Comprehensive Income

The components of Accumulated Other Comprehensive Income on the Consolidated Balance Sheets at September 30, 2010 and December 31, 2009 are presented in the following table.


(Thousands of dollars)	Sept. 30, 2010			Dec. 31, 2009
Foreign currency translation gains, net of tax	$	496,753			421,468
Retirement and postretirement benefit plan losses, net of tax		(127,555	)		(134,281	)

Accumulated other comprehensive income	$	369,198			287,187

Note M – 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.

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 one Superfund site. In early 2010, the Company’s involvement with another Superfund site was settled for a de minimis cash settlement. The potential total cost to all parties to perform necessary remedial work at the one remaining Superfund site may be substantial. However, based on current negotiations and available

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note M – Environmental and Other Contingencies (Contd.)

information, the Company believes that it is a de minimis party as to ultimate responsibility at this Superfund site. 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 site or other Superfund sites. The Company believes that its share of the ultimate costs to clean-up the Superfund site 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.

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 heard the Company’s claim for indemnity from one of its insurers, AEGIS, in September 2009 and a decision is pending. 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.

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 September 30, 2010, the Company had contingent liabilities of $7.8 million under a financial guarantee and $154.5 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to these letters of credit because it is believed that the likelihood of having these drawn is remote.

Note N – Commitments

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2010 and 2011 natural gas sales volumes at the Tupper field in Western Canada. The contracts call for natural gas deliveries of approximately 33 million cubic feet per day during the remainder of 2010 at a price of Cdn$5.30 per thousand cubic feet and 34 million cubic feet per day in 2011 at a price of Cdn$6.26, with both contracts calling for delivery at the AECO “C” sales point. These contracts have been accounted for as a normal sale for accounting purposes.

Note O – Terra Nova Working Interest Redetermination

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. The operator of Terra Nova completed the initial redetermination assessment in 2009 and the matter is the subject of arbitration before final interests are determined. The Company anticipates that its working interest at Terra Nova will be reduced from its current 12.0% to approximately 10.5%. Upon completion of the arbitration process, the Company will be required to make a cash settlement payment to the Terra Nova partnership for the value of oil sold since about December 2004 related to the ultimate working interest reduction below 12.0%. The Company has recorded cumulative expense of $98.9 million through September 2010 based on the anticipated working interest reduction. The expense has been reflected as Redetermination of Terra Nova Working Interest in the respective Consolidated Statement of Income. The Company cannot predict the final outcome of the redetermination process, which is expected to be completed by the end of 2010.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Accounting Matters

The Company adopted new guidance issued by the Financial Accounting Standards Board (FASB) regarding accounting for transfers of financial assets effective January 1, 2010. This guidance makes the concept of a qualifying special-purpose entity as defined previously 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 adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted, effective January 1, 2010, new guidance issued by the FASB that 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 guidance also amends previous guidance for determining whether an entity is considered a variable interest entity. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

Note Q – Insurance Matters

The Company maintains insurance coverage related to property damage, liability, and losses of production and profits for occurrences such as storms, fires and other issues. During the third quarter 2009, certain insurance coverage matters were concluded regarding the crude oil spill that occurred at the Meraux, Louisiana refinery following Hurricane Katrina in 2005, and income of $6.5 million, including interest, was recorded in revenue in the Consolidated Statement of Income during the three-month period ended September 30, 2009. 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. Total income of $28.4 million was recorded in revenue for the nine-month period ended September 30, 2009 related to these various insurance matters.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note R – Business Segments


			Three Mos. Ended Sept. 30, 2010								Three Mos. Ended Sept. 30, 2009¹
(Millions of dollars)	Total Assets at Sept. 30, 2010		External Revenues			Inter- segment Revenues		Income (Loss)			External Revenues			Inter- segment Revenues		Income (Loss)
Exploration and production²
United States	$	1,467.5		155.2			—		14.6			138.5			—		6.0
Canada		2,953.6		170.5			33.5		39.1			163.6			21.8		44.6
Malaysia		3,297.6		453.4			—		167.6			416.3			—		156.2
United Kingdom		203.8		28.0			—		4.9			15.1			—		2.1
Republic of the Congo		629.3		46.6			—		(20.2	)		—			—		(11.5	)
Other		44.1		.4			—		(19.3	)		.3			—		(13.3	)

Total		8,595.9		854.1			33.5		186.7			733.8			21.8		184.1

Refining and marketing
United States manufacturing		1,337.9		271.1			983.6		10.2			187.9			806.0		1.6
United States marketing		1,533.8		4,017.0			—		54.2			3,529.0			—		44.7
United Kingdom		1,102.2		930.5			—		(13.8	)		751.7			—		(9.1	)

Total		3,973.9		5,218.6			983.6		50.6			4,468.6			806.0		37.2

Total operating segments		12,569.8		6,072.7			1,017.1		237.3			5,202.4			827.8		221.3
Corporate		1,162.8		(8.9	)		—		(34.5	)		(18.6	)		—		(32.4	)

Total	$	13,732.6		6,063.8			1,017.1		202.8			5,183.8			827.8		188.9


	Nine Months Ended Sept. 30, 2010								Nine Months Ended Sept. 30, 2009¹
(Millions of dollars)	External Revenues			Inter- segment Revenues		Income (Loss)			External Revenues		Inter- segment Revenues		Income (Loss)
Exploration and production²
United States	$	497.8			—		47.8			292.4		—		2.6
Canada		594.0			73.8		150.6			442.7		52.4		38.8
Malaysia		1,386.7			—		499.3			1,059.9		—		400.9
United Kingdom		109.5			—		29.9			41.9		—		9.1
Republic of the Congo		100.3			—		(26.6	)		—		—		(9.4	)
Other		3.0			—		(48.2	)		1.0		—		(89.3	)

Total		2,691.3			73.8		652.8			1,837.9		52.4		352.7

Refining and marketing
United States manufacturing		610.2			2,659.0		(3.6	)		388.5		2,040.2		24.2
United States marketing		11,703.5			—		132.7			8,966.4		—		58.1
United Kingdom		1,889.5			—		(24.4	)		1,925.6		—		(6.5	)

Total		14,203.2			2,659.0		104.7			11,280.5		2,040.2		75.8

Total operating segments		16,894.5			2,732.8		757.5			13,118.4		2,092.6		428.5
Corporate		(58.6	)		—		(133.5	)		66.8		—		(7.5	)

Revenue/income from continuing operations		16,835.9			2,732.8		624.0			13,185.2		2,092.6		421.0
Discontinued operations, net of tax		—			—		—			—		—		97.8

Total	$	16,835.9			2,732.8		624.0			13,185.2		2,092.6		518.8

¹	Reclassified to conform to current presentation.

²	Additional details about results of oil and gas operations are presented in the tables on pages 24 and 25.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note R – Business Segments (Contd.)

Due to a recent realignment of management responsibilities within the Company’s domestic downstream business, U.S. refining and marketing operating results have now been presented as separate segments for U.S. manufacturing operations and U.S. marketing operations. The Company believes this presentation better reflects the core businesses of its U.S. downstream subsidiaries. United States Manufacturing operations include two refineries and an ethanol production facility. The Company acquired an unfinished ethanol production facility in Hereford, Texas, in the third quarter 2010; the completion and start-up of this plant is expected by the end of the first quarter 2011. United States Marketing includes retail and wholesale fuel marketing operations. Prior year amounts have been reclassified to reflect the new segment presentation. Transactions between these two U.S. downstream segments are recorded at agreed transfer prices and eliminations have been made as necessary within the consolidated financial statements. The Company previously announced its intention to sell its two U.S. refineries and its U.K. downstream operations.

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

Results of Operations

Murphy’s net income in the third quarter of 2010 was $202.8 million ($1.05 per diluted share) compared to net income of $188.9 million ($0.98 per diluted share) in the third quarter of 2009. The income improvement in 2010 primarily related to higher sales prices for the Company’s crude oil and natural gas production, higher crude oil and natural gas sales volumes and higher earnings from U.S. downstream operations.

For the first nine months of 2010, net income totaled $624.0 million ($3.24 per diluted share) compared to net income of $518.8 million ($2.70 per diluted share) for the same period in 2009. The favorable nine-month net income in 2010 compared to 2009 was primarily attributable to higher crude oil sales prices and sales volumes. The 2009 nine-month net income included income from discontinued operations of $97.8 million ($0.51 per diluted share) with this amount primarily being generated from an after-tax gain of $103.6 million on sale of operations in Ecuador in March 2009. Income from continuing operations was $624.0 million ($3.24 per diluted share) in the nine months ended September 30, 2010 and was $421.0 million ($2.19 per diluted share) in the nine months ended September 30, 2009.

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


	Income (Loss)
	Three Months Ended September 30,						Nine Months Ended September 30,
(Millions of dollars)	2010			2009			2010			2009
Exploration and production	$	186.7			184.1			652.8			352.7
Refining and marketing		50.6			37.2			104.7			75.8
Corporate		(34.5	)		(32.4	)		(133.5	)		(7.5	)

Income from continuing operations	$	202.8			188.9			624.0			421.0

In the 2010 third quarter, the Company’s continuing exploration and production operations earned $186.7 million compared to $184.1 million in the 2009 quarter. Income in the 2010 quarter was favorably impacted by higher crude oil and natural gas sales prices and higher natural gas and oil sales volumes compared to 2009. However, exploration expenses were $62.0 million in the third quarter of 2010 compared to $37.9 million in the same period of 2009. The Company’s refining and marketing operations generated income of $50.6 million in the 2010 third quarter compared to income of $37.2 million in the same quarter of 2009. U.S. manufacturing and retail marketing operations had higher earnings in the 2010 quarter, but the 2010 results for the U.K. downstream segment declined due to weaker margins. The corporate function had after-tax costs of $34.5 million in the 2010 third quarter compared to costs of $32.4 million in the 2009 period with the unfavorable variance in 2010 mostly due to higher administrative expenses.

The Company’s continuing exploration and production operations earned $652.8 million in the first nine months of 2010 compared to $352.7 million in the same period of 2009. Earnings in 2010 compared favorably to the 2009 period primarily due to higher realized crude oil sales prices and higher crude oil and natural gas sales volumes. The Company’s refining and marketing operations had earnings of $104.7 million in the first nine months of 2010 compared to earnings of $75.8 million in the same 2009 period. The 2010 period included stronger results in the U.S. retail marketing business compared to a year ago based on better operating margins, but income from refining operations in the U.S. and U.K. were significantly lower in 2010 compared to 2009 due to weaker margins for refining operations and downtime for major turnarounds in 2010 at the Meraux, Louisiana, and Milford Haven, Wales, refineries. Corporate after-tax costs were $133.5 million in the 2010 nine-month period compared to costs of $7.5 million in the 2009 period. The 2010 period had an unfavorable impact from losses on transactions denominated in foreign currencies, while the prior year included gains from these transactions.

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

Results of Operations (Contd.)

Exploration and Production

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


	Income (Loss)
	Three Months Ended September 30,						Nine Months Ended September 30,
(Millions of dollars)	2010			2009			2010			2009
Exploration and production
United States	$	14.6			6.0			47.8			2.6
Canada		39.1			44.6			150.6			38.8
Malaysia		167.6			156.2			499.3			400.9
United Kingdom		4.9			2.1			29.9			9.1
Republic of the Congo		(20.2	)		(11.5	)		(26.6	)		(9.4	)
Other International		(19.3	)		(13.3	)		(48.2	)		(89.3	)

Total	$	186.7			184.1			652.8			352.7

Third quarter 2010 vs. 2009

United States exploration and production operations reported quarterly earnings of $14.6 million in the third quarter of 2010 compared to earnings of $6.0 million in the 2009 quarter. Earnings improved in the 2010 period due mostly to higher oil and natural gas sales prices. Oil and natural gas production volumes were higher in 2010 primarily due to the Thunder Hawk field, which came on production in the third quarter 2009. But oil and natural gas volume declines at mature fields in the Gulf of Mexico somewhat offset the volumes produced at Thunder Hawk. Depreciation expense was down $13.4 million in 2010 due to lower oil and natural gas production volumes and lower per unit depletion rates in 2010. Exploration expenses in the 2010 period increased $8.0 million from the prior year primarily due to higher seismic acquisition costs and undeveloped leasehold amortization in the Eagle Ford shale area in South Texas.

Operations in Canada had earnings of $39.1 million in the third quarter 2010 compared to earnings of $44.6 million in the 2009 quarter. Canadian earnings decreased in the 2010 quarter mostly due to lower oil sales volumes, higher extraction costs for synthetic operations and higher exploration expense. Oil production decreased in the 2010 period compared to 2009 primarily due to more downtime for maintenance at Syncrude in the current period. Natural gas volumes increased in 2010 mostly due to continued ramp-up of Tupper area production. Production expense was unfavorable in 2010 due primarily to higher maintenance costs during the period for synthetic oil operations at Syncrude. Exploration expenses were $4.5 million higher in the 2010 period primarily due to more leasehold amortization expense for undeveloped oil and gas prospective acreage in Alberta.

Operations in Malaysia reported earnings of $167.6 million in the 2010 third quarter compared to earnings of $156.2 million during the same period in 2009. Earnings rose in 2010 in Malaysia primarily caused by higher crude oil and natural gas sales prices. The 2010 quarter also benefited from higher natural gas sales volumes, which were mostly associated with stronger demand for production from offshore Sarawak gas fields. Oil production was lower in 2010 compared to 2009 due to less production at the Kikeh field, offshore Sabah. Depreciation expense was higher in the 2010 period by $17.3 million due to larger natural gas sales volumes compared to the 2009 quarter.

United Kingdom operations earned $4.9 million in the 2010 quarter compared to $2.1 million in the 2009 quarter. The improvement was primarily due to higher crude oil sales prices in the 2010 quarter compared to 2009. The 2010 quarter also benefited from higher crude oil and natural gas sales volumes and higher realized sales prices for natural gas. Production expense was lower in 2010 than 2009 due to less maintenance costs in the current period, while 2010 depreciation expense exceeded 2009 levels due to higher oil and gas sales volumes.

Operations in Republic of the Congo generated a loss of $20.2 million in the third quarter of 2010 compared to a loss of $11.5 million in the 2009 quarter. The offshore Azurite field commenced oil production in the third quarter of 2009, but the initial oil sale did not occur until quarter four of 2009. Development operations continued at Azurite during 2010 as the Company brought onstream the second producing well during the second quarter of the current year. Due to delays and complications with completing wells, production levels have, thus far, been below Company

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

expectations at the Azurite field. Production levels at Azurite are expected to ramp-up as additional wells are brought onstream. Expenses for production and depreciation relate to crude oil produced and sold at the Azurite field. Exploration expenses in 2010 primarily included 3D seismic acquired over a portion of the MPS and MPN offshore blocks. Exploration expenses in 2009 primarily related to costs for two unsuccessful exploratory wells in the MPS block. Income taxes during the 2010 quarter related to taxes associated with Azurite production volumes.

Other international operations reported a loss of $19.3 million in the third quarter of 2010 compared to a loss of $13.3 million in the 2009 period. The unfavorable variance in the just completed quarter was primarily related to higher 2010 seismic activity costs in Indonesia as well as higher administrative costs associated with exploration activities in this and other foreign jurisdictions.

On a worldwide basis, the Company’s crude oil, condensate and gas liquids prices averaged $65.45 per barrel in the third quarter 2010 compared to $61.13 in the 2009 period. Total hydrocarbon production averaged 181,733 barrels of oil equivalent per day in the 2010 third quarter, a 12% increase from the 162,004 barrels equivalent per day produced in the 2009 quarter. Average crude oil and liquids production was 119,899 barrels per day in the third quarter of 2010 compared to 131,637 barrels per day in the third quarter of 2009, with the decrease primarily attributable to lower oil production at the Kikeh field, offshore Sabah, Malaysia. Crude oil production in the heavy oil area in Canada was lower in 2010 mostly due to less production in the Seal area caused by a higher royalty rate. Synthetic oil production was lower in the 2010 quarter than 2009 due to lower gross production at Syncrude caused by more downtime for maintenance. North American natural gas sales prices averaged $4.24 per thousand cubic feet (MCF) in the 2010 third quarter compared to $3.01 per MCF in the same quarter of 2009. Natural gas produced in 2010 offshore Sarawak Malaysia was sold at $5.71 per MCF compared to an average of $3.31 per MCF during the 2009 third quarter. Natural gas sales volumes averaged 371 million cubic feet per day in the third quarter 2010, more than double the 182 million cubic feet per day of sales in the 2009 quarter. The significant increase in natural gas sales volumes in 2010 was primarily due to natural gas produced in 2010 offshore Sarawak Malaysia from fields that came on stream in September 2009 and were ramping up over the balance of 2009 and into 2010. Additionally, more natural gas was sold from the Kikeh field to meet third party demand during 2010, and natural gas production increased at Tupper in Western Canada as development of the field continued.

Nine months 2010 vs. 2009

U.S. E&P operations had income of $47.8 million for the nine months ended September 30, 2010 compared to income of $2.6 million in the 2009 period. The 2010 period had higher oil and natural gas sales prices, and also benefited from higher oil sales volumes. Production expenses were $38.2 million higher in 2010 mostly due to higher oil production volumes. Depreciation expense increased $54.6 million in 2010 due to the higher sales volumes plus higher per-unit depletion rates in 2010 compared to 2009. Exploration expense in the 2010 period was $32.4 million above 2009 levels primarily due to higher geophysical expenses and undeveloped lease amortization expenses at the Eagle Ford shale area in South Texas in the current period, partially offset by lower dry hole costs in 2010.

Canadian operations had income of $150.6 million in the first nine months of 2010 compared to income of $38.8 million a year ago. Higher sales prices for crude oil and natural gas, lower exploration expenses and lower charges of $21.0 million in 2010 for an anticipated reduction of the Company’s working interest in the Terra Nova field primarily led to the improvement in 2010 earnings. Production expense increased $24.7 million in 2010 mostly related to higher volumes of natural gas produced at Tupper and higher costs for synthetic crude oil produced at Syncrude. Depreciation expense increased in 2010 by $25.1 million mostly associated with higher production at Tupper and higher unit rates at Syncrude. Exploration expenses were $20.5 million lower in 2010 primarily due to less lease amortization costs at the Tupper West area in British Columbia in the current period.

Malaysia operations earned $499.3 million in the first nine months of 2010 compared to earnings of $400.9 million in the 2009 period. Earnings were stronger in 2010 primarily due to higher crude oil sales prices as well as higher natural gas sales volumes and prices from fields offshore Sarawak. Sales volumes for natural gas were higher in the 2010 period than 2009 due to start-up of natural gas production offshore Sarawak in the third quarter 2009 and higher gas volumes purchased by a third party in 2010 at the Kikeh field. Crude oil sales volumes at the Kikeh field were

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

higher in 2010 than 2009 despite overall lower net oil production due to the timing of completion of oil sales transactions. Production and depreciation expenses increased $66.6 million and $78.6 million, respectively, in the 2010 period due to higher oil and natural gas sales volumes. Exploration expense was $17.9 million higher in 2010 mostly due to more costs for unsuccessful exploration drilling in the 2010 period.

Income in the U.K. for the nine-month period in 2010 was $29.9 million compared to $9.1 million a year ago with the earnings increase primarily due to improved crude oil sales prices. In addition, 2010 had higher sales volumes for crude oil and natural gas compared to 2009. Production and depreciation expenses were higher $7.3 million and $10.7 million, respectively, in 2010 compared to 2009 in association with higher oil and natural gas sales volumes. Exploration expenses were higher in the 2010 period due to a dry hole drilled in the third quarter of the current year.

Operations in Republic of the Congo had a loss of $26.6 million for the nine-month period ended September 30, 2010, compared to a loss of $9.4 million in the 2009 period. The offshore Azurite oil field commenced production in the third quarter 2009, but production has thus far been below Company expectations due to delays in completing wells. Production and depreciation expenses incurred in 2010 were associated with the Azurite field. Geophysical costs in the 2010 period were primarily related to 3D seismic acquisition covering a portion of the offshore MPN block. Income taxes during 2010 related to taxes on Azurite production volumes.

Other international operations reported a loss of $48.2 million in the first nine months of 2010 compared to a loss of $89.3 million in the 2009 period. The lower loss in the 2010 period primarily related to costs in 2009 for unsuccessful exploratory drilling offshore Australia and higher geophysical expenses in 2009 offshore Suriname. However, the current year included higher administrative costs related to exploration activities in foreign jurisdictions.

For the first nine months of 2010, the Company’s sales price for crude oil, condensate and gas liquids averaged $65.06 per barrel compared to $52.59 per barrel in 2009. Total worldwide production averaged 189,250 barrels of oil equivalent per day during the nine months ended September 30, 2010, an increase of 23% from the 154,212 barrels of oil equivalent produced in the same period in 2009. Crude oil, condensate and gas liquids production in the first nine months of 2010 averaged 130,244 barrels per day compared to 129,672 barrels per day a year ago. The small increase was mostly attributable to two fields that started up in third quarter 2009 – Thunder Hawk field in the Gulf of Mexico and the Azurite field, offshore Republic of the Congo. The oil production at these two fields was mostly offset by lower production in other areas. Canadian heavy oil production was lower in 2010 than 2009 due to both field decline and a higher net profit royalty rate at the Seal heavy oil field in Alberta. Crude oil production offshore eastern Canada was lower in 2010 primarily due to a higher net profit royalty rate at Terra Nova. Synthetic oil production at Syncrude was higher in 2010 than 2009 due to less downtime in 2010 for maintenance, but partially offset by a higher net profit royalty rate. Crude oil production was lower in 2010 in Malaysia due to a smaller percentage of production being allocable to the Company during 2010 under the production sharing contract covering the Kikeh field. Crude oil volumes from discontinued operations in the prior year were associated with oil fields in Ecuador that were sold in March 2009. The average sales price for North American natural gas in the first nine months of 2010 was $4.48 per MCF, up from $3.50 per MCF realized in 2009. Sarawak field natural gas production was sold at an average price of $5.20 per MCF in 2010, up from $3.31 per MCF in 2009. Natural gas sales volumes increased from 147 million cubic feet per day in 2009 to 354 million cubic feet per day in 2010, with the 140% increase mostly due to continued ramp-up of natural gas production volumes from the Tupper area in British Columbia, which came onstream in December 2008, sales volumes at Sarawak Malaysia gas fields that initially came onstream in the third quarter 2009, and higher sales volumes to third parties from the Kikeh field, offshore Sabah, Malaysia.

Additional details about results of oil and gas operations are presented in the tables on pages 24 and 25.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Selected operating statistics for the three-month and nine-month periods ended September 30, 2010 and 2009 follow.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Net crude oil, condensate and gas liquids produced – barrels per day		119,899		131,637		130,244		129,672
Continuing operations		119,899		131,637		130,244		127,911
United States		19,404		19,639		20,594		15,502
Canada – light		47		21		43		8
– heavy		5,749		6,581		6,048		6,976
– offshore		10,534		10,538		11,774		12,822
– synthetic		12,044		13,804		12,973		12,458
Malaysia		63,794		76,290		70,444		75,782
United Kingdom		2,831		2,165		3,669		3,487
Republic of Congo		5,496		2,599		4,699		876
Discontinued operations		—		—		—		1,761

Net crude oil, condensate and gas liquids sold – barrels per day		122,574		128,187		133,304		124,988
Continuing operations		122,574		128,187		133,304		123,435
United States		19,404		19,639		20,594		15,502
Canada – light		47		21		43		8
– heavy		5,749		6,581		6,048		6,976
– offshore		10,055		9,554		11,682		13,087
– synthetic		12,044		13,804		12,973		12,458
Malaysia		64,547		76,386		72,428		72,970
United Kingdom		3,394		2,202		4,742		2,434
Republic of Congo		7,334		—		4,794		—
Discontinued operations		—		—		—		1,553

Net natural gas sold – thousands of cubic feet per day		371,005		182,199		354,038		147,240
United States		56,159		63,304		52,582		55,141
Canada		81,869		55,115		83,179		45,982
Malaysia – Sarawak		167,773		3,042		150,973		1,025
– Kikeh		59,538		57,980		61,559		42,310
United Kingdom		5,666		2,758		5,745		2,782

Total net hydrocarbons produced – equivalent barrels per day (1)		181,733		162,004		189,250		154,212
Total net hydrocarbons sold – equivalent barrels per day (1)		184,408		158,554		192,310		149,528

Weighted average sales prices
Crude oil, condensate and natural gas liquids – dollars per barrel (2)
United States	$	73.10		65.57		74.53		54.50
Canada (3) – light		68.33		66.66		73.75		62.82
– heavy		46.09		46.75		49.29		36.35
– offshore		75.52		67.94		75.29		54.25
– synthetic		74.80		66.54		76.04		56.62
Malaysia (4)		60.35		59.18		58.90		52.62
United Kingdom		77.22		68.93		76.53		56.75
Republic of the Congo		70.73		—		71.09		—
Natural gas – dollars per thousand cubic feet
United States (2)	$	4.51		3.33		4.75		3.96
Canada (3)		4.05		2.65		4.31		2.95
Malaysia – Sarawak		5.71		3.31		5.20		3.31
– Kikeh		0.23		0.24		0.23		0.23
United Kingdom (3)		7.24		3.91		6.33		5.15

(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 309/311 and K.

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

Results of Operations (Contd.)

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED SEPTEMBER 30, 2010 AND 2009


(Millions of dollars)	United States			Canada		Malaysia			United Kingdom		Republic of the Congo			Other			Synthetic Oil – Canada		Total
Three Months Ended September 30, 2010
Oil and gas sales and other operating revenues	$	155.2			121.0		453.4			28.0		46.6			.4			83.0		887.6
Production expenses		34.5			23.0		87.0			6.4		21.2			—			52.9		225.0
Depreciation, depletion and amortization		66.5			41.7		94.2			5.0		25.8			.4			10.8		244.4
Accretion of asset retirement obligations		1.8			1.2		2.5			.6		.1			.2			1.5		7.9
Exploration expenses
Dry holes		(.2	)		—		—			5.7		(.3	)		—			—		5.2
Geological and geophysical		2.1			.1		.9			.1		15.0			3.3			—		21.5
Other		.6			.1		—			—		—			6.2			—		6.9

		2.5			.2		.9			5.8		14.7			9.5			—		33.6
Undeveloped lease amortization		18.5			8.7		—			—		—			1.2			—		28.4

Total exploration expenses		21.0			8.9		.9			5.8		14.7			10.7			—		62.0

Terra Nova working interest redetermination		—			4.5		—			—		—			—			—		4.5
Selling and general expenses		9.3			2.4		.3			.7		(.5	)		8.4			.3		20.9

Results of operations before taxes		22.1			39.3		268.5			9.5		(14.7	)		(19.3	)		17.5		322.9
Income tax provisions		7.5			12.7		100.9			4.6		5.5			—			5.0		136.2

Results of operations (excluding corporate overhead and interest)	$	14.6			26.6		167.6			4.9		(20.2	)		(19.3	)		12.5		186.7


Three Months Ended September 30, 2009*
Oil and gas sales and other operating revenues	$	138.5			100.9		416.3			15.1		—			.3			84.5		755.6
Production expenses		31.9			23.3		85.4			7.8		—			—			41.5		189.9
Depreciation, depletion and amortization		79.9			41.3		76.9			3.1		—			.5			7.7		209.4
Accretion of asset retirement obligations		1.7			1.1		2.0			.4		—			.1			1.2		6.5
Exploration expenses
Dry holes		.9			—		.1			—		13.5			1.2			—		15.7
Geological and geophysical		1.2			3.0		.4			—		—			.5			—		5.1
Other		.6			.1		—			.1		(1.0	)		4.5			—		4.3

		2.7			3.1		.5			.1		12.5			6.2			—		25.1
Undeveloped lease amortization		10.3			1.3		—			—		—			1.2			—		12.8

Total exploration expenses		13.0			4.4		.5			.1		12.5			7.4			—		37.9

Terra Nova working interest redetermination		—			1.3		—			—		—			—			—		1.3
Selling and general expenses		2.8			4.3		(.6	)		.5		(1.0	)		5.6			.2		11.8

Results of operations before taxes		9.2			25.2		252.1			3.2		(11.5	)		(13.3	)		33.9		298.8
Income tax provisions		3.2			5.5		95.9			1.1		—			—			9.0		114.7

Results of operations (excluding corporate overhead and interest)	$	6.0			19.7		156.2			2.1		(11.5	)		(13.3	)		24.9		184.1

*	Reclassified to conform to current presentation.

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

Results of Operations (Contd.)

OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2010 AND 2009


(Millions of dollars)	United States			Canada		Malaysia			United Kingdom		Republic of the Congo			Other			Synthetic Oil – Canada		Total
Nine Months Ended September 30, 2010
Oil and gas sales and other operating revenues	$	497.8			397.1		1,386.7			109.5		100.3			3.0			270.7		2,765.1
Production expenses		101.0			75.3		241.1			20.6		47.7			—			152.4		638.1
Depreciation, depletion and amortization		222.0			134.8		291.0			19.1		47.9			1.0			33.0		748.8
Accretion of asset retirement obligations		5.2			3.6		7.2			1.7		.2			.4			4.7		23.0
Exploration expenses
Dry holes		(.1	)		—		30.5			5.7		(.6	)		(.5	)		—		35.0
Geological and geophysical		19.2			.6		1.9			.6		18.4			6.7			—		47.4
Other		6.3			.3		—			.2		—			15.5			—		22.3

		25.4			.9		32.4			6.5		17.8			21.7			—		104.7
Undeveloped lease amortization		49.7			23.4		—			—		—			3.7			—		76.8

Total exploration expenses		75.1			24.3		32.4			6.5		17.8			25.4			—		181.5

Terra Nova working interest redetermination		—			15.4		—			—		—			—			—		15.4
Selling and general expenses		22.7			8.9		.6			2.3		(1.1	)		23.6			.7		57.7

Results of operations before taxes		71.8			134.8		814.4			59.3		(12.2	)		(47.4	)		79.9		1,100.6
Income tax provisions		24.0			41.3		315.1			29.4		14.4			.8			22.8		447.8

Results of operations (excluding corporate overhead and interest)	$	47.8			93.5		499.3			29.9		(26.6	)		(48.2	)		57.1		652.8


Nine Months Ended September 30, 2009*
Oil and gas sales and other operating revenues	$	292.4			302.5		1,059.9			41.9		—			1.0			192.6		1,890.3
Production expenses		62.8			71.7		174.5			13.3		—			—			131.3		453.6
Depreciation, depletion and amortization		167.4			122.8		212.4			8.4		.1			1.1			19.9		532.1
Accretion of asset retirement obligations		5.1			3.1		5.6			1.2		—			.4			3.2		18.6
Exploration expenses
Dry holes		11.7			—		13.9			—		13.5			45.1			—		84.2
Geological and geophysical		2.8			4.3		.6			—		—			13.4			—		21.1
Other		5.0			.3		—			.3		(3.2	)		9.8			—		12.2

		19.5			4.6		14.5			.3		10.3			68.3			—		117.5
Undeveloped lease amortization		23.2			40.2		—			—		—			3.1			—		66.5

Total exploration expenses		42.7			44.8		14.5			.3		10.3			71.4			—		184.0

Terra Nova working interest redetermination		—			36.4		—			—		—			—			—		36.4
Selling and general expenses		13.3			12.1		(1.4	)		2.1		(1.0	)		17.3			.6		43.0

Results of operations before taxes		1.1			11.6		654.3			16.6		(9.4	)		(89.2	)		37.6		622.6
Income tax provisions (benefits)		(1.5	)		2.6		253.4			7.5		—			.1			7.8		269.9

Results of operations (excluding corporate overhead and interest)	$	2.6			9.0		400.9			9.1		(9.4	)		(89.3	)		29.8		352.7

*	Reclassified to conform to current presentation.

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

Results of Operations (Contd.)

Refining and Marketing

Due to a recent realignment of management responsibilities within the Company’s domestic downstream business, U.S. refining and marketing operating results have now been presented as separate segments for U.S. manufacturing operations and U.S. marketing operations. The Company believes this presentation better reflects the core businesses of its U.S. downstream subsidiaries. United States Manufacturing operations include two refineries and an ethanol production facility. United States Marketing includes retail and wholesale fuel marketing operations. Prior year amounts have been reclassified to reflect the new segment presentation. Transactions between these two U.S. downstream segments are recorded at agreed transfer prices and eliminations have been made as necessary within the consolidated financial statements. In July 2010, the Company announced that its Board of Directors had approved plans to exit the U.S. refining and U.K. refining and marketing businesses.

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


	Income (Loss)
	Three Months Ended September 30,						Nine months Ended September 30,
	2010			2009			2010			2009
(Millions of dollars)
Refining and marketing
United States manufacturing	$	10.2			1.6			(3.6	)		24.2
United States marketing		54.2			44.7			132.7			58.1
United Kingdom		(13.8	)		(9.1	)		(24.4	)		(6.5	)

Total	$	50.6			37.2			104.7			75.8

The Company’s refining and marketing operations generated income of $50.6 million in the 2010 third quarter compared to earnings of $37.2 million in the same quarter of 2009. United States manufacturing operations had income of $10.2 million in the 2010 period compared to a profit of $1.6 million in 2009. U.S. manufacturing operations had better earnings primarily due to profits at the Company’s Hankinson, North Dakota, ethanol plant, which was acquired in the fourth quarter 2009. The 2010 quarter also benefited from higher crude oil throughput due to more consistent operations during the period at the Company’s U.S. refineries. United States marketing operations generated a profit of $54.2 million in the 2010 quarter, up from $44.7 million of income in the 2009 quarter. The improvement in 2010 was essentially due to better merchandising and fuel margins in the current quarter compared to the 2009 quarter. The operating loss in the United Kingdom was $13.8 million in the third quarter of 2010 compared to a loss of $9.1 million in the same period a year ago. Operating margins at the Milford Haven, Wales, refinery were generally weaker in the 2010 quarter than in 2009. Worldwide refinery inputs were 267,988 barrels per day in the third quarter of 2010 compared to 250,081 in the 2009 quarter as all three refineries had improved throughputs compared to the prior year’s quarter. Worldwide petroleum product sales averaged 584,306 barrels per day in quarter three 2010, compared to 553,698 barrels per day in the same period in 2009. The 2010 sales volume increase was attributable to higher sales volumes in both the Company’s U.S. and U.K. marketing operations.

Refining and marketing operations in the first nine months of 2010 generated a profit of $104.7 million compared to a profit of $75.8 million in the 2009 period. In the United States, manufacturing operations lost $3.6 million in the 2010 period, significantly below the 2009 profit of $24.2 million due to both after-tax gains of $16.4 million on insurance settlements at the Meraux refinery in the prior-year period and weaker refining margins in 2010. The United States marketing business generated earnings of $132.7 million in the nine-month period of 2010, compared to earnings of $58.1 million in 2009 as retail margins were $0.04 per gallon stronger during the 2010 period compared to the prior year. Results in the United Kingdom reflected a loss of $24.4 million in the first nine months of 2010 compared to a loss of $6.5 million in the 2009 period. The reduction was primarily due to weaker refining margins on sale of petroleum products in 2010 compared to 2009 and lower production of finished products due to an approximate two-month shutdown for turnaround of the Milford Haven, Wales, refinery during 2010.

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

Results of Operations (Contd.)

Refining and Marketing (Contd.)

Selected operating statistics for the three-month and nine-month periods ended September 30, 2010 and 2009 follow.


	Three Months Ended September 30,						Nine months Ended September 30,
	2010			2009			2010			2009
Refinery inputs – barrels per day		267,988			250,081			215,285			244,627
United States		158,002			146,371			140,022			141,635
Crude oil – Meraux, Louisiana		111,543			102,865			99,333			101,472
– Superior, Wisconsin		36,568			33,295			34,050			32,771
Other feedstocks		9,891			10,211			6,639			7,392
United Kingdom		109,986			103,710			75,263			102,992
Crude oil – Milford Haven, Wales		105,552			95,753			70,729			97,244
Other feedstocks		4,434			7,957			4,534			5,748

Refinery yields – barrels per day		267,988			250,081			215,285			244,627
United States		158,002			146,371			140,022			141,635
Gasoline		62,873			64,594			57,616			61,615
Kerosine		8,950			9,581			9,973			11,084
Diesel and home heating oils		46,542			42,001			38,519			40,358
Residuals		19,105			15,707			18,420			15,290
Asphalt		18,684			12,637			14,352			11,905
Fuel and loss		1,848			1,851			1,142			1,383
United Kingdom		109,986			103,710			75,263			102,992
Gasoline		29,697			28,418			18,831			26,474
Kerosine		15,326			17,042			10,683			13,473
Diesel and home heating oils		34,503			33,831			22,179			35,688
Residuals		10,447			11,391			7,207			10,272
Asphalt		16,354			9,737			13,471			13,428
Fuel and loss		3,659			3,291			2,892			3,657

Petroleum products sold – barrels per day		584,306			553,698			524,092			532,240
Total United States		467,119			448,685			445,897			428,405
United States Manufacturing		160,902			146,075			141,523			137,855
Gasoline		70,328			64,596			65,018			61,615
Kerosine		8,952			9,579			9,973			11,084
Diesel and home heating oils		46,542			42,006			38,519			40,704
Residuals		18,516			14,734			18,151			14,849
Asphalt, LPG and other		16,564			15,160			9,862			9,603
United States Marketing		432,039			418,791			417,884			403,953
Gasoline		339,956			326,675			330,194			316,439
Kerosine		10,968			13,239			9,986			12,564
Diesel and other		81,115			78,877			77,704			74,950
United States Intercompany Elimination		(125,822	)		(116,181	)		(113,510	)		(113,403	)
Gasoline		(70,328	)		(64,596	)		(65,018	)		(61,615	)
Kerosine		(8,952	)		(9,579	)		(9,973	)		(11,084	)
Diesel and other		(46,542	)		(42,006	)		(38,519	)		(40,704	)
United Kingdom		117,187			105,013			78,195			103,835
Gasoline		30,389			28,491			21,005			29,272
Kerosine		15,587			16,853			10,765			12,541
Diesel and home heating oils		38,572			35,867			26,496			37,303
Residuals		11,786			10,068			7,414			9,696
LPG and other		20,853			13,734			12,515			15,023

Unit margins per barrel:
United States refining¹	$	0.23			0.22			(0.68	)		1.03
United Kingdom refining and marketing		(1.84	)		(0.78	)		(1.75	)		0.15

United States retail marketing:
Fuel margin per gallon²	$	0.137			0.133			0.128		$	0.088
Gallons sold per store month		313,140			320,460			307,276			312,597
Merchandise sales revenue per store month	$	161,352			147,753			152,875			134,497
Merchandise margin as a percentage of merchandise sales		13.5	%		12.2	%		13.0	%		12.8	%
Store count at end of period (Company operated)		1,083			1,037			1,083			1,037

¹	Represents refinery sales realizations less cost of crude and other feedstocks and refinery operating and depreciation expenses.

²	Represents net sales prices for fuel less purchased cost of fuel.

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 costs of $34.5 million in the 2010 third quarter compared to net costs of $32.4 million in the third quarter of 2009. The 2010 results of corporate activities were unfavorable to 2009 primarily due to higher administrative costs, mostly associated with staff compensation expense. Net after-tax losses on transactions denominated in foreign currencies in the current quarter were $15.8 million compared to net losses of $17.0 million in the comparable 2009 period.

For the first nine months of 2010, corporate activities reflected net costs of $133.5 million compared to net costs of $7.5 million a year ago. Nine-month corporate costs in 2010 were significantly unfavorable to 2009 primarily related to the effects of transactions denominated in foreign currencies, and higher expenses for interest and administration. Total after-tax losses for foreign currency transactions were $58.8 million in the 2010 period compared to net benefits of $42.7 million in the first nine months of 2009. Net interest expense was unfavorable in 2010 compared to 2009 due to higher average levels of borrowed funds and lower levels of interest capitalized to oil and gas development projects. Administrative expense was also higher in 2010 mostly associated with increased employee compensation costs.

Financial Condition

Net cash provided by operating activities was $2.20 billion for the first nine months of 2010 compared to $1.19 billion during the same period in 2009. Changes in operating working capital other than cash and cash equivalents provided cash of $417.2 million in the first nine months of 2010, but used cash of $139.0 million in the first nine months of 2009. Cash generated from working capital changes in the 2010 period included a $244.4 million recovery of U.S. federal royalties paid in prior years on oil and natural gas production in the Gulf of Mexico. Cash of $2.01 billion in the 2010 period and $1.38 billion in 2009 was generated from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition.

Significant uses of cash in both years were for dividends, which totaled $148.4 million in 2010 and $143.0 million in 2009, and for property additions and dry holes, which including amounts expensed, were $1.61 billion and $1.54 billion in the nine-month periods ended September 30, 2010 and 2009, respectively. Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $1.86 billion in the 2010 period and $1.76 billion in the 2009 period. Effective with the third quarter 2010, the Company’s annualized dividend rate was raised from $1.00 to $1.10 per share.

Total accrual basis capital expenditures for continuing operations were as follows:


	Nine months Ended September 30,
(Millions of dollars)	2010		2009
Capital Expenditures – Continuing operations
Exploration and production	$	1,460.7		1,442.8
Refining and marketing		294.9		179.3
Corporate and other		4.5		2.0

Total capital expenditures – continuing operations		1,760.1		1,624.1

A reconciliation of property additions and dry hole costs in the consolidated statements of cash flows to total capital expenditures follows.


	Nine months Ended September 30,
(Millions of dollars)	2010		2009
Property additions and dry hole costs per cash flow statements	$	1,611.7		1,542.0
Geophysical and other exploration expenses		69.7		33.3
Capital expenditure accrual changes		78.7		48.8

Total capital expenditures – continuing operations		1,760.1		1,624.1

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

Financial Condition (Contd.)

Working capital (total current assets less total current liabilities) at September 30, 2010 was $705.2 million, a decrease of $488.9 million from December 31, 2009. 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 $612.1 million below fair value at September 30, 2010.

At September 30, 2010, long-term notes payable of $1,024.3 million had decreased in total by $328.8 million compared to December 31, 2009. A summary of capital employed at September 30, 2010 and December 31, 2009 follows.


(Millions of dollars)	Sept. 30, 2010				Dec. 31, 2009
	Amount		%		Amount		%
Capital employed
Long-term debt	$	1,024.3		11.4		1,353.2		15.6
Stockholders’ equity		7,966.9		88.6		7,346.0		84.4

Total capital employed	$	8,991.2		100.0		8,699.2		100.0

The Company’s ratio of earnings to fixed charges was 18.3 to 1 for the nine-month period ended September 30, 2010.

Accounting and Other Matters

Outlook

Average West Texas Intermediate crude oil prices in October 2010 averaged over $80 per barrel, which was about $5 per barrel above the third quarter 2010 average price. The Company expects its oil and natural gas production to average about 198,000 barrels of oil equivalent per day in the fourth quarter 2010. U.S. retail marketing margins have fallen in October versus the average margins achieved in the third quarter 2010. Additionally, margins remained under pressure during October at the Company’s refineries. The Company currently anticipates total capital expenditures for the full year 2010 to be approximately $2.6 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 2009 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 J to this Form 10-Q report, Murphy periodically uses derivative commodity and financial instruments to manage risks associated with existing or anticipated transactions. There were short-term commodity derivative contracts in place at September 30, 2010 to hedge the value of about 0.9 million barrels of crude oil and 0.4 million barrels of intermediate products at the Company’s refineries. Additionally, on this date the Company had open fixed-price corn purchase commitments of approximately 5.3 million bushels of corn expected to be purchased and processed at the Company’s ethanol production facility. The Company also had open derivative contracts at that date to sell an equivalent amount of corn at these fixed prices and buy it back at future prices in effect at the time the corn is actually purchased. A 10% increase in the respective benchmark price of these commodities would have reduced the recorded asset associated with these derivative contracts by approximately $10.2 million, while a 10% decrease would have increased the recorded asset by a similar amount. Changes in the fair value of the Company’s derivative contracts generally offset the changes in the value for an equivalent volume of these feedstocks.

There were short-term derivative foreign exchange contracts in place at September 30, 2010 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 $25.1 million, while a 10% weakening of the U.S. dollar would have increased the recorded net asset by approximately $34.3 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 September 30, 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business. Based on information currently available to the Company, the ultimate resolution of environmental and legal matters referred to in this note is not expected to have a material adverse effect on the Company’s net income, financial condition or liquidity in a future period.

ITEM 1A. RISK FACTORS

The Company’s operations in the oil and gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A. Risk Factors in our 2009 Form 10-K filed on February 26, 2010.

In April 2010, a drilling accident and subsequent oil spill occurred in the Gulf of Mexico at a property owned by other companies. The U.S. government declared a moratorium on drilling in the Gulf of Mexico after this accident. The moratorium forced the Company to defer planned exploration drilling in the Gulf of Mexico. In October 2010, the U.S. government lifted the moratorium on drilling in the Gulf of Mexico. However, it is unclear how new government regulations will impact the issuance of permits to drill in the Gulf. New government regulations covering offshore drilling operations may lead to higher costs for future drilling operations and delays for approval of drilling permits. Additionally, the Company could face higher costs for offshore insurance. The Company is unable to predict when it will be able to resume drilling operations in the Gulf of Mexico and how new regulations and any associated higher costs will ultimately impact its U.S. and worldwide operations.

The existing 45-cent per gallon federal excise tax credit earned on ethanol blended with gasoline in the U.S. is scheduled to expire at December 31, 2010. The U.S. government is considering whether to extend this or similar credits in 2011 and beyond. The elimination or significant reduction of the ethanol credit could have a detrimental effect on the Company’s U.S. fuel business. The Company cannot predict at this time how ethanol credits will be altered beginning in 2011, and whether any such change will materially affect its operations in future periods.

ITEM 6. EXHIBITS

The Exhibit Index on page 33 of this Form 10-Q report lists the exhibits that are hereby filed, incorporated by reference, or furnished with this report.

SIGNATURE

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


*MURPHY OIL CORPORATION*
		(Registrant)

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

November 5, 2010

(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. INS		XBRL Instance Document

101. SCH		XBRL Taxonomy Extension Schema Document

101. CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101. DEF		XBRL Taxonomy Extension Definition Linkbase Document

101. LAB		XBRL Taxonomy Extension Labels Linkbase Document

101. PRE		XBRL Taxonomy Extension Presentation Linkbase

*	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