Edgar Filing: MURPHY OIL CORP /DE

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

For the quarterly period ended June 30, 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. þ 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). þ 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 þ No

Number of shares of Common Stock, $1.00 par value, outstanding at June 30, 2010 was 191,793,286.

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 June 30,					Six Months Ended June 30,
	2010			2009		2010		2009
REVENUES
Sales and other operating revenues	$	5,592,353		4,495,994		10,821,028		7,912,421
Gain on sale of assets		113		3,570		789		3,585
Interest and other income (expense)		(535	)	56,282		(49,726	)	85,392

Total revenues		5,591,931		4,555,846		10,772,091		8,001,398


COSTS AND EXPENSES
Crude oil and product purchases		4,253,167		3,574,531		8,232,126		6,130,575
Operating expenses		460,244		373,889		925,851		736,250
Exploration expenses, including undeveloped lease amortization		53,093		34,946		119,457		146,051
Selling and general expenses		68,851		61,602		133,982		118,434
Depreciation, depletion and amortization		288,212		197,429		580,892		392,198
Accretion of asset retirement obligations		7,844		6,164		15,457		12,417
Redetermination of Terra Nova working interest		5,346		35,091		10,862		35,091
Interest expense		13,893		13,184		28,702		25,172
Interest capitalized		(3,696	)	(12,127	)	(6,361	)	(22,450	)

Total costs and expenses		5,146,954		4,284,709		10,040,968		7,573,738


Income from continuing operations before income taxes		444,977		271,137		731,123		427,660
Income tax expense		172,688		110,293		309,943		195,576

Income from continuing operations		272,289		160,844		421,180		232,084
Income (loss) from discontinued operations, net of income taxes		—		(2,074	)	—		97,790


NET INCOME	$	272,289		158,770		421,180		329,874

INCOME PER COMMON SHARE – BASIC
Income from continuing operations	$	1.42		0.84		2.20		1.22
Income (loss) from discontinued operations		—		(0.01	)	—		0.51

Net income – Basic	$	1.42		0.83		2.20		1.73


INCOME PER COMMON SHARE – DILUTED
Income from continuing operations	$	1.41		0.84		2.18		1.21
Income (loss) from discontinued operations		—		(0.01	)	—		0.51

Net income – Diluted	$	1.41		0.83		2.18		1.72


Average common shares outstanding – basic		191,585,996		190,746,583		191,394,728		190,633,781
Average common shares outstanding – diluted		193,169,099		192,380,595		192,821,487		192,189,238

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) June 30, 2010			December 31, 2009
ASSETS
Current assets
Cash and cash equivalents	$	398,820		301,144
Canadian government securities with maturities greater than 90 days at the date of acquisition		802,761		779,025
Accounts receivable, less allowance for doubtful accounts of $8,003 in 2010 and $7,761 in 2009		1,324,420		1,463,297
Inventories, at lower of cost or market
Crude oil and blend stocks		333,204		128,936
Finished products		462,857		384,250
Materials and supplies		225,594		220,796
Prepaid expenses		97,470		83,218
Deferred income taxes		70,653		15,029

Total current assets		3,715,779		3,375,695
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $5,294,371 in 2010 and $4,714,826 in 2009		9,416,226		9,065,088
Goodwill		40,195		40,652
Deferred charges and other assets		375,116		274,924

Total assets	$	13,547,316		12,756,359

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	2,431		38
Accounts payable and accrued liabilities		2,243,386		1,794,406
Income taxes payable		477,834		387,164

Total current liabilities		2,723,651		2,181,608
Long-term debt		1,226,606		1,353,183
Deferred income taxes		1,056,767		1,018,767
Asset retirement obligations		487,247		476,938
Deferred credits and other liabilities		386,077		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 192,280,606 shares in 2010 and 191,797,600 shares in 2009		192,281		191,798
Capital in excess of par value		706,265		680,509
Retained earnings		6,529,796		6,204,316
Accumulated other comprehensive income		251,329		287,187
Treasury stock, 487,320 shares of Common Stock in 2010 and 682,222 shares of Common Stock in 2009, at cost		(12,703	)	(17,784	)

Total stockholders’ equity		7,666,968		7,346,026

Total liabilities and stockholders’ equity	$	13,547,316		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 June 30,				Six Months Ended June 30,
	2010			2009	2010		2009
Net income	$	272,289		158,770	421,180		329,874

Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation		(132,045	)	179,504	(40,385	)	98,517
Retirement and postretirement benefit plan adjustments		2,333		2,095	4,527		4,283


COMPREHENSIVE INCOME	$	142,577		340,369	385,322		432,674

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)


	Six Months Ended June 30,
	2010			2009
OPERATING ACTIVITIES
Net income	$	421,180		329,874
Income from discontinued operations		—		97,790

Income from continuing operations		421,180		232,084
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation, depletion and amortization		580,892		392,198
Amortization of deferred major repair costs		16,150		12,729
Expenditures for asset retirements		(25,280	)	(36,686	)
Dry hole costs		29,841		68,476
Amortization of undeveloped leases		48,378		53,664
Accretion of asset retirement obligations		15,457		12,417
Deferred and noncurrent income tax charges		33,233		24,239
Pretax gain from disposition of assets		(789	)	(3,585	)
Net decrease (increase) in noncash operating working capital		249,780		(193,135	)
Other operating activities, net		78,901		(49,571	)

Net cash provided by continuing operations		1,447,743		512,830
Net cash provided (required) by discontinued operations		—		(328	)

Net cash provided by operating activities		1,447,743		512,502


INVESTING ACTIVITIES
Property additions and dry hole costs		(992,256	)	(1,004,897	)
Proceeds from sales of assets		1,792		1,160
Purchase of investment securities*		(1,263,026	)	(1,185,757	)
Proceeds from maturity of investment securities*		1,239,290		1,021,415
Expenditures for major repairs		(89,102	)	(12,952	)
Other – net		(23,110	)	(15,251	)
Investing activities of discontinued operations
Sales proceeds		—		78,908
Other		—		(845	)

Net cash required by investing activities		(1,126,412	)	(1,118,219	)


FINANCING ACTIVITIES
Repayment of notes payable		(122,019	)	505,000
Repayment of nonrecourse debt of a subsidiary		(2,269	)	(2,572	)
Proceeds from exercise of stock options and employee stock purchase plans		14,798		5,429
Excess tax benefits related to exercise of stock options		483		2,031
Withholding tax on stock-based incentive awards		(5,170	)	—
Cash dividends paid		(95,700	)	(95,326	)

Net cash provided (required) by financing activities		(209,877	)	414,562

Effect of exchange rate changes on cash and cash equivalents		(13,778	)	32,128

Net increase (decrease) in cash and cash equivalents		97,676		(159,027	)
Cash and cash equivalents at January 1		301,144		666,110

Cash and cash equivalents at June 30	$	398,820		507,083

*	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)


	Six Months Ended June 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 192,280,606 shares at June 30, 2010 and 191,522,141 shares at June 30, 2009
Balance at beginning of period	$	191,798		191,249
Exercise of stock options		483		273

Balance at end of period		192,281		191,522


Capital in Excess of Par Value
Balance at beginning of period		680,509		631,859
Exercise of stock options, including income tax benefits		14,668		7,870
Restricted stock transactions and other		(9,688	)	5,439
Stock-based compensation		20,299		11,783
Sale of stock under employee stock purchase plans		477		405

Balance at end of period		706,265		657,356


Retained Earnings
Balance at beginning of period		6,204,316		5,557,483
Net income for the period		421,180		329,874
Cash dividends		(95,700	)	(95,326	)

Balance at end of period		6,529,796		5,792,031


Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		287,187		(87,697	)
Foreign currency translation gains (losses), net of income taxes		(40,385	)	98,517
Retirement and postretirement benefit plan adjustments, net of income taxes		4,527		4,283

Balance at end of period		251,329		15,103


Treasury Stock
Balance at beginning of period		(17,784	)	(13,949	)
Sale of stock under employee stock purchase plans		518		629
Awarded restricted stock, net of forfeitures		4,305		—
Cancellation of performance-based restricted stock and forfeitures		258		(5,072	)

Balance at end of period		(12,703	)	(18,392	)


Total Stockholders’ Equity	$	7,666,968		6,637,620

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 June 30, 2010, and the results of operations, cash flows and changes in stockholders’ equity for the three-month and six-month periods ended June 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 six-month periods ended June 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)	Six Months Ended June 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 June 30, 2010, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $430.4 million. The following table reflects the net changes in capitalized exploratory well costs during the six-month periods ended June 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		60,562	65,012
Reclassifications to proved properties based on the determination of proved reserves		—	—

Balance at June 30	$	430,424	375,130

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


	June 30,
	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	$	103,705	14	5	$	93,446	8	6
One to two years		102,446	10	4		18,046	2	1
Two to three years		17,946	2	2		26,271	10	2
Three years or more		206,327	32	4		237,367	29	6

	$	430,424	58	15	$	375,130	49	15

Of the $326.7 million of exploratory well costs capitalized more than one year at June 30, 2010, $197.3 million is in Malaysia, $95.8 million is in the U.S., $14.5 million is in Republic of the Congo, $9.6 million is in Canada, and $9.5 million is in the U.K. 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.

The Company has been informed by PETRONAS that following the execution of the Exchange of Letters between Malaysia and the Sultanate of Brunei on March 16, 2009, the offshore exploration areas designated as Block L and Block M are no longer a part of Malaysia. As a consequence, the production sharing contracts covering Blocks L and M, awarded in 2003 to PETRONAS Carigali Sdn Bhd and Murphy, were formally terminated by letter dated April 7, 2010. Murphy’s potential participation in replacement production sharing contracts covering these areas is under discussion. The Company’s remaining net investment in Block L of $12.2 million at June 30, 2010 is included in Property, Plant and Equipment in the consolidated balance sheet pending resolution of its potential participation in replacement production sharing contracts.

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 June 30, 2010 and December 31, 2009, the carrying value of inventories under the LIFO method was $604.2 million and $551.2 million, respectively, less than such inventories would have been valued using the first-in, first-out (FIFO) method.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – Cash Flow Disclosures

Additional disclosures regarding cash flow activities are provided below.


	Six Months Ended June 30,
	2010			2009
Supplementary disclosures:
Cash income taxes paid	$	243,648		87,411
Interest paid, net of amounts capitalized		20,408		1,607


Noncash changes in operating working capital:
Accounts receivable	$	138,577		(96,467	)
Inventories		(287,653	)	(156,520	)
Prepaid expenses		(11,347	)	(41,364	)
Deferred income tax assets		(55,625	)	(8,338	)
Accounts payable and accrued liabilities		375,159		251,294
Current income tax liabilities		90,669		(141,740	)

Total	$	249,780		(193,135	)

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 six-month periods ended June 30, 2010 and 2009.


	Three Months Ended June 30,
	Pension Benefits					Other Postretirement Benefits
(Thousands of dollars)	2010			2009		2010		2009
Service cost	$	5,197		4,335		920		817
Interest cost		7,433		7,306		1,474		1,449
Expected return on plan assets		(5,891	)	(4,900	)	—		—
Amortization of prior service cost		384		420		(66	)	(69	)
Amortization of transitional asset		(129	)	(114	)	—		—
Recognized actuarial loss		2,988		3,074		596		439

		9,982		10,121		2,924		2,636
Special termination benefits expense		—		1,867		—		—
Curtailment expense		—		972		—		—

Net periodic benefit expense	$	9,982		12,960		2,924		2,636


	Six Months Ended June 30,
	Pension Benefits					Other Postretirement Benefits
(Thousands of dollars)	2010			2009		2010		2009
Service cost	$	10,456		8,453		1,808		1,593
Interest cost		14,881		14,294		2,905		2,840
Expected return on plan assets		(11,742	)	(10,246	)	—		—
Amortization of prior service cost		771		818		(130	)	(135	)
Amortization of transitional asset		(256	)	(220	)	—		—
Recognized actuarial loss		5,953		6,018		1,174		860

		20,063		19,117		5,757		5,158
Special termination benefits expense		—		1,867		—		—
Curtailment expense		—		972		—		—

Net periodic benefit expense	$	20,063		21,956		5,757		5,158

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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

During the six-month period ended June 30, 2010, the Company made contributions of $11.0 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 $16.1 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 June 30, 2010 and for the three-month and six-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 June 30, 2017. The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors.

In February 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 six-month periods ended June 30, 2010 and 2009 was $14.8 million and $5.4 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $5.9 million and $2.6 million for the six-month periods ended June 30, 2010 and 2009, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note G – Incentive Plans (Contd.)

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


	Six Months Ended June 30,
*(Thousands of dollars)*	2010		2009
Compensation charged against income before tax benefit	$	21,048	12,060
Related income tax benefit recognized in income		4,744	3,314

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 six-month periods ended June 30, 2010 and 2009. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended June 30,		Six Months Ended June 30,
(Weighted-average shares)	2010	2009	2010	2009
Basic method	191,585,996	190,746,583	191,394,728	190,633,781
Dilutive stock options and restricted stock units	1,583,103	1,634,012	1,426,759	1,555,457

Diluted method	193,169,099	192,380,595	192,821,487	192,189,238

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 2,263,204 shares at a weighted average share price of $58.77 in each 2010 period and 1,922,000 shares at a weighted average share price of $56.96 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 six-month periods in 2010 and 2009, the Company’s effective income tax rates were as follows:


	2010		2009
Three months ended June 30	38.8	%	40.7	%
Six months ended June 30	42.4	%	45.7	%

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 rates for the three-month and six-month periods in 2010 benefited 1.3% and 0.8%, respectively, for an income tax adjustment in the U.K.

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 June 30, 2010, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2006; Canada – 2005; United Kingdom – 2007; and Malaysia – 2006.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Financial Instruments and Risk Management

Murphy periodically utilizes derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes, and it does not use derivatives with leveraged or complex features. Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges. The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks.

•

Commodity Purchase Price Risks – The Company purchases crude oil as feedstock at its U.S. and U.K. refineries and is therefore subject to commodity price risk. Short-term derivative instruments were outstanding at both June 30, 2010 and 2009 to manage the cost of about 1.1 million barrels and 0.7 million barrels, respectively, of crude oil at the Company’s refineries. Additionally, the Company purchases corn to supply its ethanol production facility and is subject to commodity price risk. The Company had derivative contracts to manage the purchase price of approximately 2.9 million bushels of corn at June 30, 2010. The impact on consolidated income from continuing operations before income taxes from marking to market these derivative contracts as of the balance sheet dates was a benefit of $2.3 million and $0.4 million, respectively, in the six-month periods ended June 30, 2010 and 2009.

•

Foreign Currency Exchange Risks – The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. Short-term derivative instruments were outstanding at June 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 such Malaysian ringgit contracts outstanding at June 30, 2010 and 2009 were approximately $281.0 million and $50.0 million, respectively. Short-term derivative instruments were outstanding at June 30, 2010 and 2009 to manage the risk of certain U.S. dollar accounts receivable associated with sale of the Company’s Canadian crude oil. A total of $54.0 million and $21.0 million U.S. dollar contracts were outstanding at June 30, 2010 and 2009, respectively, related to these Canadian receivables. The impact on consolidated income from continuing operations before income taxes from marking to market these derivative contracts as of the balance sheet dates were gains of $15.7 million and $1.6 million, respectively, in the six-month periods ended June 30, 2010 and 2009.

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


	June 30, 2010				December 31, 2009
	Asset (Liability) Derivatives				Asset (Liability) Derivatives
(Thousands of dollars)	Balance Sheet Location	Fair Value			Balance Sheet Location	Fair Value
Commodity derivative contracts	Accounts receivable	$	2,903		Accounts receivable	$	2,296
Foreign exchange derivative contracts	Accounts receivable		8,353		Accounts receivable		340
Foreign exchange derivative contracts	Accounts payable		(764	)	Accounts payable		—

For the six-month periods ended June 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.


	Six Months Ended June 30, 2010			Six Months Ended June 30, 2009
(Thousands of dollars)	Location of Gain or (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative		Location of Gain or (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative
Commodity derivative contracts	Crude oil and product purchases	$	610	Crude oil and product purchases	$	(24,878	)
Foreign exchange derivative contracts	Interest and other income		15,727	Interest and other income		4,272

		$	16,337		$	(20,606	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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 fair value measurements for these assets and liabilities at June 30, 2010 and December 31, 2009 are presented in the following table.


				Fair Value Measurements at Reporting Date Using
(Thousands of dollars)	June 30, 2010			Quoted Prices in Active Markets for Identical Assets (Liabilities) (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets
Foreign exchange derivative contracts	$	8,353		—		8,353		—
Commodity derivative contracts		2,903		—		2,903		—

	$	11,256		—		11,256		—

Liabilities
Nonqualified employee savings plan	$	(5,681	)	(5,681	)	—		—
Foreign exchange derivative contracts		(764	)	—		(764	)	—

	$	(6,445	)	(5,681	)	(764	)	—


				Fair Value Measurements at Reporting Date Using
(Thousands of dollars)	Dec. 31, 2009			Quoted Prices in Active Markets for Identical Assets (Liabilities) (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets
Commodity derivative contracts	$	2,296		—		2,296		—
Foreign exchange derivative contracts		340		—		340		—

	$	2,636		—		2,636		—

Liabilities
Nonqualified employee savings plan	$	(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.

Note K – Accumulated Other Comprehensive Income

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


(Thousands of dollars)	June 30, 2010			Dec. 31, 2009
Foreign currency translation gains, net of tax	$	381,083		421,468
Retirement and postretirement benefit plan losses, net of tax		(129,754	)	(134,281	)

Accumulated other comprehensive income	$	251,329		287,187

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – 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 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Environmental and Other Contingencies (Contd.)

Litigation arising out of a June 10, 2003 fire in the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery was settled in July 2009 and memorialized via a filing in the U.S. District Court for the Eastern District of Louisiana on July 24, 2009. An arbitral tribunal 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 June 30, 2010, the Company had contingent liabilities of $7.8 million under a financial guarantee and $215.4 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to these letters of credit because it is believed that the likelihood of having these drawn is remote.

Note M – 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 N – 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 $94.4 million through June 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.

Note O – 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note O – Accounting Matters (Contd.)

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 P – Insurance Matters

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note Q – Business Segments


	Total Assets at June 30, 2010		Three Mos. Ended June 30, 2010						Three Mos. Ended June 30, 2009¹
(Millions of dollars)	Total Assets at June 30, 2010		External Revenues			Inter- segment Revenues	Income (Loss)		External Revenues	Inter- segment Revenues	Income (Loss)
Exploration and production²
United States	$	1,458.3		167.6		—	14.5		82.9	—	3.9
Canada		2,687.2		232.2		8.7	62.3		165.7	9.5	(6.4	)
Malaysia		3,226.2		429.4		—	158.2		306.2	—	127.2
United Kingdom		203.6		29.1		—	8.4		15.1	—	3.6
Republic of the Congo		618.3		25.4		—	(8.9	)	—	—	1.8
Other		39.0		.3		—	(15.4	)	.2	—	(11.8	)

Total		8,232.6		884.0		8.7	219.1		570.1	9.5	118.3

Refining and marketing
United States manufacturing		1,316.2		210.9		1,047.2	9.8		135.4	721.5	14.3
United States marketing		1,519.4		4,080.9		—	69.6		3,106.0	—	7.1
United Kingdom		1,214.1		416.6		—	4.4		688.0	—	6.4

Total		4,049.7		4,708.4		1,047.2	83.8		3,929.4	721.5	27.8

Total operating segments		12,282.3		5,592.4		1,055.9	302.9		4,499.5	731.0	146.1
Corporate		1,265.0		(.5	)	—	(30.6	)	56.3	—	14.8

Revenue/income from continuing operations		13,547.3		5,591.9		1,055.9	272.3		4,555.8	731.0	160.9
Discontinued operations, net of tax		—		—		—	—		—	—	(2.1	)

Total	$	13,547.3		5,591.9		1,055.9	272.3		4,555.8	731.0	158.8


			Six Months Ended June 30, 2010						Six Months Ended June 30, 2009¹
(Millions of dollars)			External Revenues			Inter- segment Revenues	Income (Loss)		External Revenues	Inter- segment Revenues	Income (Loss)
Exploration and production²
United States			$	342.6		—	33.2		153.9	—	(3.4	)
Canada				423.5		40.3	111.5		279.1	30.6	(5.8	)
Malaysia				933.3		—	331.7		643.6	—	244.7
United Kingdom				81.5		—	25.0		26.8	—	7.0
Republic of the Congo				53.7		—	(6.4	)	—	—	2.1
Other				2.6		—	(28.9	)	.7	—	(76.0	)

Total				1,837.2		40.3	466.1		1,104.1	30.6	168.6

Refining and marketing
United States manufacturing				339.1		1,675.4	(13.8	)	200.6	1,234.2	22.6
United States marketing				7,686.5		—	78.5		5,437.4	—	13.4
United Kingdom				959.0		—	(10.6	)	1,173.9	—	2.6

Total				8,984.6		1,675.4	54.1		6,811.9	1,234.2	38.6

Total operating segments				10,821.8		1,715.7	520.2		7,916.0	1,264.8	207.2
Corporate				(49.7	)	—	(99.0	)	85.4	—	24.9

Revenue/income from continuing operations				10,772.1		1,715.7	421.2		8,001.4	1,264.8	232.1
Discontinued operations, net of tax				—		—	—		—	—	97.8

Total			$	10,772.1		1,715.7	421.2		8,001.4	1,264.8	329.9

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 Q – 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. 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.

Note R – Subsequent Event

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 will be placed for sale, are essentially encompassed within the U.S. manufacturing and U.K. refining and marketing segments presented in Note Q. The Company currently anticipates the sale of these operations to be completed in the first quarter of 2011.

ITEM 2.

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

Results of Operations

Murphy’s net income in the second quarter of 2010 was $272.3 million ($1.41 per diluted share) compared to net income of $158.8 million ($0.83 per diluted share) in the second quarter of 2009. The income improvement in 2010 primarily related to higher sales prices for the Company’s crude oil production, higher crude oil and natural gas sales volumes and higher margins on U.S. retail marketing operations. Discontinued operations, associated with the Ecuador properties sold in March 2009, had an after-tax loss of $2.1 million ($0.01 per diluted share) in the second quarter 2009. Income from continuing operations was $272.3 million ($1.41 per diluted share) in the 2010 quarter compared to $160.9 million ($0.84 per diluted share) in the 2009 quarter. The second quarter 2009 included a $24.7 million after-tax charge associated with an anticipated reduction of the Company’s working interest in the Terra Nova field, offshore Eastern Canada. The prior-year quarter also included after-tax gains of $13.4 million from settlements with insurers related to property damaged by a fire and hurricane in prior years at the Meraux, Louisiana refinery.

For the first six months of 2010, net income totaled $421.2 million ($2.18 per diluted share) compared to net income of $329.9 million ($1.72 per diluted share) for the same period in 2009. The favorable six-month net income in 2010 compared to 2009 was also primarily attributable to higher crude oil sales prices and sales volumes. The 2009 six-month net income included income from discontinued operations of $97.8 million ($0.51 per diluted share) with this amount primarily being generated from an after-tax gain of $103.6 million on sale of operations in Ecuador in March 2009. Income from continuing operations was $421.2 million ($2.18 per diluted share) in the six months ended June 30, 2010 and was $232.1 million ($1.21 per diluted share) in the six months ended June 30, 2009. The six-month period in 2009 included the aforementioned $24.7 million after-tax charge for an anticipated Terra Nova working interest reduction and the $13.4 million after-tax gain from insurance settlements.

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


	Income (Loss)
	Three Months Ended June 30,				Six Months Ended June 30,
(Millions of dollars)	2010			2009	2010		2009
Exploration and production	$	219.1		118.3	466.1		168.6
Refining and marketing		83.8		27.8	54.1		38.6
Corporate		(30.6	)	14.8	(99.0	)	24.9

Income from continuing operations	$	272.3		160.9	421.2		232.1

In the 2010 second quarter, the Company’s continuing exploration and production operations earned $219.1 million compared to $118.3 million in the 2009 quarter. Income in the 2010 quarter was favorably impacted by higher crude oil sales prices compared to 2009, higher sales levels of crude oil and natural gas, and also lower after-tax charges for an anticipated reduction in the Company’s working interest in the Terra Nova field. Exploration expenses were $53.2 million in the second quarter of 2010 compared to $35.0 million in the same period of 2009. The Company’s refining and marketing operations generated income of $83.8 million in the 2010 second quarter compared to income of $27.8 million in the same quarter of 2009. U.S. retail marketing margins improved in the 2010 quarter, but the 2010 results for the U.S. manufacturing segment declined as the prior period included after-tax gains of $13.4 million from insurance settlements at the Meraux refinery. The corporate function had after-tax costs of $30.6 million in the 2010 second quarter compared to after-tax benefits of $14.8 million in the 2009 period with the unfavorable variance in 2010 mostly due to losses on transactions denominated in foreign currencies in 2010 compared to gains on such transactions in the 2009 quarter.

The Company’s continuing exploration and production operations earned $466.1 million in the first half of 2010 compared to $168.6 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 $54.1 million in the first six months of 2010 compared to earnings of $38.6 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 downstream operations in the U.K. were significantly lower in 2010 compared to 2009 due to weaker margins in refining operations and turnarounds in 2010 at the Meraux, Louisiana, and Milford Haven, Wales, refineries. Corporate after-tax costs were $99.0 million in the 2010 period compared to after-tax benefits of $24.9 million in the 2009 period. The current 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 June 30,					Six Months Ended June 30,
(Millions of dollars)	2010			2009		2010		2009
Exploration and production – continuing operations
United States	$	14.5		3.9		33.2		(3.4	)
Canada		62.3		(6.4	)	111.5		(5.8	)
Malaysia		158.2		127.2		331.7		244.7
United Kingdom		8.4		3.6		25.0		7.0
Republic of the Congo		(8.9	)	1.8		(6.4	)	2.1
Other International		(15.4	)	(11.8	)	(28.9	)	(76.0	)

Total – continuing operations	$	219.1		118.3		466.1		168.6

Second quarter 2010 vs. 2009

United States exploration and production operations reported quarterly earnings of $14.5 million in the second quarter of 2010 compared to earnings of $3.9 million in the 2009 quarter. Earnings improved in the 2010 period due mostly to higher oil and natural gas sales prices and sales volumes. Oil and natural gas production volumes were higher in 2010 due to the Thunder Hawk field, which came on production in the third quarter 2009. Production expenses increased $18.0 million in 2010 compared to 2009 mostly due to Thunder Hawk production. Depreciation expense was $35.9 million higher in 2010 due to higher oil and natural gas production volumes and higher per unit depletion rates in 2010. Exploration expenses in the 2010 period increased $16.1 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 and higher seismic costs in the Gulf of Mexico.

Operations in Canada had earnings of $62.3 million in the second quarter 2010 compared to a loss of $6.4 million in the 2009 quarter. Canadian earnings increased in the 2010 quarter mostly due to higher oil sales prices, higher natural gas sales prices and sales volumes, and lower after-tax charges in 2010 associated with an anticipated reduction of the Company’s working interest at the Terra Nova field. Oil production increased in the 2010 period compared to 2009 primarily due to less downtime for maintenance at Syncrude in 2010. Natural gas volumes increased in 2010 mostly due to continued ramp-up of Tupper area production. Production and depreciation expenses for synthetic oil operations in Canada were unfavorable in 2010 due primarily to higher production volumes at Syncrude. Exploration expenses were $12.1 million lower in the 2010 period primarily due to less leasehold amortization expense at the Tupper West area.

Operations in Malaysia reported earnings of $158.2 million in the 2010 quarter compared to earnings of $127.2 million during the same period in 2009. Earnings rose in 2010 in Malaysia primarily caused by higher crude oil sales prices. The 2010 quarter also benefited from higher sales volumes of crude oil and natural gas. Production and depreciation expenses were higher in the 2010 period by $30.7 million and $29.1 million, respectively, due to larger oil and natural gas sales volumes compared to the 2009 quarter. Exploration expense was $8.2 million higher in 2010 due to remaining dry hole costs for the Batai well.

United Kingdom operations earned $8.4 million in the 2010 quarter compared to $3.6 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. Expenses for production operations and depreciation were higher in 2010 than 2009 due to the higher volumes of crude oil and natural gas sold.

Operations in Republic of the Congo generated a loss of $8.9 million in the second quarter of 2010 compared to income of $1.8 million in the 2009 quarter. The offshore Azurite field commenced oil production in the third quarter of 2009. Development operations continued at Azurite during the 2010 quarter as the Company brought onstream the second producing well. Due to delays and complications with completing wells, production levels have, thus far, been below Company expectations at the Azurite field. Production levels at Azurite are expected to ramp-up as additional wells are brought onstream. Exploration expenses in 2010 included 3D seismic acquired over a portion of the northern MPN offshore block. Income taxes during the 2010 period related to taxes associated with Azurite production volumes. The income in the second quarter of 2009 arose due to administrative exploratory costs charged to Azurite field development activities as permitted by the joint venture agreement.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Other international operations reported a loss of $15.4 million in the second quarter of 2010 compared to a loss of $11.8 million in the 2009 period. The unfavorable variance in the just completed quarter was primarily related to higher administrative costs in foreign jurisdictions in the 2010 period.

On a worldwide basis, the Company’s crude oil, condensate and gas liquids prices averaged $64.68 per barrel in the second quarter 2010 compared to $53.55 in the 2009 period. Total hydrocarbon production averaged 189,951 barrels of oil equivalent per day in the 2010 second quarter, a 33% increase from the 142,717 barrels equivalent per day produced in the 2009 quarter. Average crude oil and liquids production was 131,983 barrels per day in the second quarter of 2010 compared to 118,145 barrels per day in the second quarter of 2009, with the 12% increase primarily attributable to oil production at the Thunder Hawk field in the Gulf of Mexico and the Azurite field offshore Republic of the Congo, both of which started up in the third quarter 2009. 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 resulting from project payout and higher net profits. Synthetic oil production was higher in 2010 than 2009 due to higher gross production at Syncrude caused by less downtime for maintenance, but partially offset by a higher net profit royalty at this operation. Crude oil production in Malaysia declined in the 2010 quarter compared to 2009 due to a lower percentage of Kikeh production allocable to the Company under the production sharing contract during 2010. North American natural gas sales prices averaged $4.16 per thousand cubic feet (MCF) in the 2010 quarter compared to $3.25 per MCF in the same quarter of 2009. Natural gas produced in 2010 at an offshore Sarawak field was sold at $5.10 per MCF. Natural gas sales volumes averaged almost 348 million cubic feet per day in the second quarter 2010, up 136% from sales of 147 million cubic feet per day in the 2009 quarter. The increase in natural gas sales volumes in 2010 was primarily due to natural gas production volumes in 2010 offshore Sarawak Malaysia and at the Thunder Hawk field in the Gulf of Mexico, both of which commenced production in the third quarter 2009. Additionally, more natural gas was sold from the Kikeh field to meet third party demand during 2010.

Six months 2010 vs. 2009

U.S. E&P operations had income of $33.2 million for the six months ended June 30, 2010 compared to a loss of $3.4 million in the 2009 period. The 2010 period had higher oil and natural gas sales prices, and also benefited from higher oil and natural gas sales volumes. Production expenses were $35.6 million higher in 2009 mostly due to higher oil and natural gas production volumes. Depreciation expense increased $68.0 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 $24.4 million above 2009 levels primarily due to geophysical 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 $111.5 million in the first half of 2010 compared to a loss of $5.8 million a year ago. Higher sales prices for crude oil and natural gas and lower charges of $24.2 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 and depreciation expenses increased $13.6 million and $21.6 million, respectively, in 2010 mostly related to higher volumes of natural gas produced at Tupper and synthetic crude oil produced at Syncrude. Exploration expenses were $25.0 million lower in 2010 primarily due to less lease amortization costs at the Tupper West area in the current period.

Malaysia operations earned $331.7 million in the first half of 2010 compared to earnings of $244.7 million in the 2009 period. Earnings were stronger in 2010 primarily due to higher crude oil sales prices. Sales volumes for natural gas were higher in the 2010 period than 2009 due to start-up of natural gas production at a Sarawak gas field 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 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 were higher $65.0 million and $61.3 million, respectively, in the 2010 period due to larger oil and natural gas sales volumes. Exploration expense was $17.5 million higher in 2010 mostly due to more costs for unsuccessful exploration drilling in the 2010 period.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Exploration and Production (Contd.)

Income in the U.K. for the six-month period in 2010 was $25.0 million compared to $7.0 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 $8.7 million and $8.8 million, respectively, in 2010 compared to 2009 in association with higher oil and natural gas sales volumes.

Operations in Republic of the Congo had a loss of $6.4 million for the six-month period ended June 30, 2010, compared to income of $2.1 million in the 2009 period. The offshore Azurite oil field commenced production in the third quarter 2009, but production has been below Company expectations to date. Geophysical costs in the 2010 period were primarily related to a 3D seismic acquisition covering a portion of the offshore MPN block. Income in 2009 related to administrative costs charged to Azurite development activities as permitted by the joint venture agreement with partners.

Other international operations reported a loss of $28.9 million in the first six months of 2010 compared to a loss of $76.0 million in the 2009 period. The lower loss in the 2010 period primarily related to higher costs in 2009 for unsuccessful exploratory drilling in Australia and geophysical expenses offshore Suriname.

For the first six months of 2010, the Company’s sales price for crude oil, condensate and gas liquids averaged $64.59 per barrel compared to $48.01 per barrel in 2009. Total worldwide production averaged 193,071 barrels of oil equivalent per day during the six months ended June 30, 2010, an increase of 28% from the 150,252 barrels of oil equivalent produced in the same period in 2009. Crude oil, condensate and gas liquids production in the first half of 2010 averaged 135,502 barrels per day compared to 128,673 barrels per day a year ago. The 5% 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. 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 due to higher net profit royalty rates at both Hibernia and 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 six months of 2010 was $4.61 per MCF, up from $3.89 per MCF realized in 2009. Sarawak field natural gas production was sold at an average price of $4.87 per MCF in 2010. Natural gas sales volumes increased from 129 million cubic feet per day in 2009 to 345 million cubic feet per day in 2010, with the 167% 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 the Sarawak Malaysia gas field that started up 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 six-month periods ended June 30, 2010 and 2009 follow.


	Three Months Ended June 30,			Six Months Ended June 30,
Exploration and Production	2010		2009	2010	2009
Net crude oil, condensate and gas liquids produced – barrels per day		131,983	118,145	135,502	128,673
Continuing operations		131,983	118,145	135,502	126,017
United States		20,755	13,529	21,199	13,399
Canada – light		31	—	41	—
– heavy		5,920	6,923	6,200	7,178
– offshore		12,210	12,441	12,404	13,983
– synthetic		14,499	10,102	13,445	11,774
Malaysia		69,597	71,594	73,824	75,524
United Kingdom		4,103	3,556	4,095	4,159
Republic of the Congo		4,868	—	4,294	—
Discontinued operations		—	—	—	2,656

Net crude oil, condensate and gas liquids sold – barrels per day		131,810	112,538	138,758	123,362
Continuing operations		131,810	112,538	138,758	121,020
United States		20,755	13,529	21,199	13,399
Canada – light		31	—	41	—
– heavy		5,920	6,923	6,200	7,178
– offshore		12,833	16,291	12,509	14,883
– synthetic		14,499	10,102	13,445	11,774
Malaysia		70,351	63,055	76,434	71,234
United Kingdom		3,654	2,638	5,427	2,552
Republic of the Congo		3,767	—	3,503	—
Discontinued operations		—	—	—	2,342

Net natural gas sold – thousands of cubic feet per day		347,806	147,433	345,414	129,471
United States		57,649	48,702	50,764	50,992
Canada		87,862	52,841	83,845	41,340
Malaysia – Sarawak		126,469	—	142,434	—
– Kikeh		69,971	42,797	62,586	34,345
United Kingdom		5,855	3,093	5,785	2,794

Total net hydrocarbons produced – equivalent barrels per day (1)		189,951	142,717	193,071	150,252
Total net hydrocarbons sold – equivalent barrels per day (1)		189,778	137,110	196,327	144,941

Weighted average sales prices –
Crude oil, condensate and gas liquids – dollars per barrel (2)
United States	$	74.81	54.94	75.20	46.37
Canada (3) – light		74.87	—	76.83	—
– heavy		47.83	41.48	51.01	31.50
– offshore		75.14	56.01	74.98	49.79
– synthetic		75.84	58.72	76.59	50.71
Malaysia (4)		57.71	52.95	57.78	49.04
United Kingdom		77.43	57.51	76.32	51.40
Republic of the Congo		74.27	—	71.48	—
Natural gas – dollars per thousand cubic feet
United States (2)	$	4.23	3.54	4.88	4.36
Canada (3)		4.11	2.98	4.44	3.31
Malaysia – Sarawak		5.10	—	4.87	—
– Kikeh		0.23	0.23	0.23	0.23
United Kingdom (3)		5.97	4.48	5.88	5.78

(1)	Natural gas converted on an energy equivalent basis of 6:1.

(2)	Includes intracompany transfers at market prices.

(3)	U.S. dollar equivalent.

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

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

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


(Millions of dollars)	United States			Canada		Malaysia		United Kingdom	Republic of the Congo		Other		Synthetic Oil – Canada	Total
Three Months Ended June 30, 2010
Oil and gas sales and other operating revenues	$	167.6		140.9		429.4		29.1	25.4		.3		100.0	892.7
Production expenses		33.7		26.5		70.3		5.0	14.6		—		47.7	197.8
Depreciation, depletion and amortization		80.1		47.0		90.9		5.8	12.7		.3		12.2	249.0
Accretion of asset retirement obligations		1.7		1.2		2.4		.6	—		.1		1.6	7.6
Exploration expenses
Dry holes		—		—		7.9		—	.1		(.5	)	—	7.5
Geological and geophysical		4.7		(.1	)	.8		.1	3.1		1.3		—	9.9
Other		3.1		.1		—		.1	(.3	)	5.2		—	8.2

		7.8		—		8.7		.2	2.9		6.0		—	25.6
Undeveloped lease amortization		18.3		8.0		—		—	—		1.3		—	27.6

Total exploration expenses		26.1		8.0		8.7		.2	2.9		7.3		—	53.2

Terra Nova working interest redetermination		—		5.4		—		—	—		—		—	5.4
Selling and general expenses		5.4		2.9		.2		.7	.3		8.0		.2	17.7

Results of operations before taxes		20.6		49.9		256.9		16.8	(5.1	)	(15.4	)	38.3	362.0
Income tax provisions		6.1		15.0		98.7		8.4	3.8		—		10.9	142.9

Results of operations (excluding corporate overhead and interest)	$	14.5		34.9		158.2		8.4	(8.9	)	(15.4	)	27.4	219.1


Three Months Ended June 30, 2009*
Oil and gas sales and other operating revenues	$	82.9		121.2		306.2		15.1	—		.2		54.0	579.6
Production expenses		15.7		26.7		39.6		3.6	—		—		44.9	130.5
Depreciation, depletion and amortization		44.2		47.0		61.8		3.2	.1		.2		5.9	162.4
Accretion of asset retirement obligations		1.7		1.0		1.9		.3	—		.2		1.0	6.1
Exploration expenses
Dry holes		(.6	)	—		.1		—	—		1.5		—	1.0
Geological and geophysical		.8		.3		.4		—	—		.7		—	2.2
Other		2.8		.1		—		.2	(1.9	)	2.6		—	3.8

		3.0		.4		.5		.2	(1.9	)	4.8		—	7.0
Undeveloped lease amortization		7.0		19.7		—		—	—		1.3		—	28.0

Total exploration expenses		10.0		20.1		.5		.2	(1.9	)	6.1		—	35.0

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

Results of operations before taxes		6.2		(13.0	)	203.3		7.0	1.8		(11.7	)	2.0	195.6
Income tax provisions (benefits)		2.3		(4.9	)	76.1		3.4	—		.1		.3	77.3

Results of operations (excluding corporate overhead and interest)	$	3.9		(8.1	)	127.2		3.6	1.8		(11.8	)	1.7	118.3

*	Reclassified to conform to current presentation.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2010 AND 2009


(Millions of dollars)	United States			Canada		Malaysia		United Kingdom	Republic of the Congo		Other		Synthetic Oil – Canada		Total
Six Months Ended June 30, 2010
Oil and gas sales and other operating revenues	$	342.6		276.1		933.3		81.5	53.7		2.6		187.7		1,877.5
Production expenses		66.5		52.3		154.1		14.2	26.5		—		99.5		413.1
Depreciation, depletion and amortization		155.5		93.1		196.8		14.1	22.1		.6		22.2		504.4
Accretion of asset retirement obligations		3.4		2.4		4.7		1.1	.1		.2		3.2		15.1
Exploration expenses
Dry holes		.1		—		30.5		—	(.3	)	(.5	)	—		29.8
Geological and geophysical		17.1		.5		1.0		.5	3.4		3.4		—		25.9
Other		5.7		.2		—		.2	—		9.3		—		15.4

		22.9		.7		31.5		.7	3.1		12.2		—		71.1
Undeveloped lease amortization		31.2		14.7		—		—	—		2.5		—		48.4


Total exploration expenses		54.1		15.4		31.5		.7	3.1		14.7		—		119.5

Terra Nova working interest redetermination		—		10.9		—		—	—		—		—		10.9
Selling and general expenses		13.4		6.5		.3		1.6	(.6	)	15.2		.4		36.8

Results of operations before taxes		49.7		95.5		545.9		49.8	2.5		(28.1	)	62.4		777.7
Income tax provisions		16.5		28.6		214.2		24.8	8.9		.8		17.8		311.6

Results of operations (excluding corporate overhead and interest)	$	33.2		66.9		331.7		25.0	(6.4	)	(28.9	)	44.6		466.1


Six Months Ended June 30, 2009*
Oil and gas sales and other operating revenues	$	153.9		201.6		643.6		26.8	—		.7		108.1		1,134.7
Production expenses		30.9		48.4		89.1		5.5	—		—		89.8		263.7
Depreciation, depletion and amortization		87.5		81.5		135.5		5.3	.1		.6		12.2		322.7
Accretion of asset retirement obligations		3.4		2.0		3.6		.8	—		.3		2.0		12.1
Exploration expenses
Dry holes		10.8		—		13.8		—	—		43.9		—		68.5
Geological and geophysical		1.6		1.3		.2		—	—		12.9		—		16.0
Other		4.4		.2		—		.2	(2.2	)	5.3		—		7.9

		16.8		1.5		14.0		.2	(2.2	)	62.1		—		92.4
Undeveloped lease amortization		12.9		38.9		—		—	—		1.9		—		53.7

Total exploration expenses		29.7		40.4		14.0		.2	(2.2	)	64.0		—		146.1

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

Results of operations before taxes		(8.1	)	(13.6	)	402.2		13.4	2.1		(75.9	)	3.7		323.8
Income tax provisions (benefits)		(4.7	)	(2.9	)	157.5		6.4	—		.1		(1.2	)	155.2

Results of operations (excluding corporate overhead and interest)	$	(3.4	)	(10.7	)	244.7		7.0	2.1		(76.0	)	4.9		168.6

*	Reclassified to conform to current presentation.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Results of Operations (Contd.)

Refining and Marketing

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


	Income (Loss)
	Three Months Ended June 30,			Six Months Ended June 30,
(Millions of dollars)	2010		2009	2010		2009
Refining and marketing
United States manufacturing	$	9.8	14.3	(13.8	)	22.6
United States marketing		69.6	7.1	78.5		13.4
United Kingdom		4.4	6.4	(10.6	)	2.6

Total	$	83.8	27.8	54.1		38.6

The Company’s refining and marketing operations generated income of $83.8 million in the 2010 second quarter compared to earnings of $27.8 million in the same quarter of 2009. United States manufacturing operations had a profit of $9.8 million in the 2010 period compared to a profit of $14.3 million in 2009. Manufacturing operations in the 2009 quarter included $13.4 million of after-tax gains on settlement of insurance claims related to property damaged in prior years by a fire and hurricane at the Meraux, Louisiana refinery. United States marketing operations generated a profit of $69.6 million in the 2010 quarter, up from $7.1 million of income in the 2009 quarter. The improvement in 2010 was essentially due to retail marketing margins that improved $.084 per gallon in the current quarter compared to the 2009 quarter. Operating earnings in the United Kingdom were $4.4 million in the second quarter of 2010 compared to earnings of $6.4 million in the same period a year ago. The Milford Haven, Wales, refinery was shutdown for turnaround for a portion of the 2010 quarter and it experienced inefficient operations upon restart. Worldwide refinery inputs were 207,186 barrels per day in the second quarter of 2010 compared to 248,364 in the 2009 quarter, with the 2010 decline caused by the Milford Haven, Wales, turnaround. The U.K. operation had income tax benefits of $6.0 million in the second quarter of 2010. Worldwide petroleum product sales averaged 508,117 barrels per day in 2010, compared to 538,596 barrels per day in the same period in 2009. The 2010 sales volume decrease was attributable to lower sales volumes at the Company’s U.K. refining operations, primarily associated with a turnaround at the Milford Haven refinery that was completed in the second quarter 2010.

Refining and marketing operations in the first half of 2010 generated a profit of $54.1 million compared to a profit of $38.6 million in the 2009 period. In United States, manufacturing operations lost $13.8 million in the 2010 period, significantly below the 2009 profit of $22.6 million due to both after-tax gains of $13.4 million on insurance settlements at the Meraux refinery in the prior-year period and lower refining margins in 2010. The United States marketing business generated earnings of $78.5 million in the six-month period of 2010, compared to earnings of $13.4 million in 2009 as the retail margins were $.059 per gallon stronger during the 2010 period compared to the prior year. Results in the United Kingdom reflected a loss of $10.6 million in the first six months of 2010 compared to earnings of $2.6 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 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.)

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Refinery inputs – barrels per day		207,186			248,364			188,497			241,855
United States		158,635			141,710			130,883			139,228
Crude oil – Meraux, Louisiana		119,187			101,718			93,127			100,764
– Superior, Wisconsin		33,662			33,451			32,770			32,505
Other feedstocks		5,786			6,541			4,986			5,959
United Kingdom		48,551			106,654			57,614			102,627
Crude oil – Milford Haven, Wales		45,104			98,865			53,029			98,002
Other feedstocks		3,447			7,789			4,585			4,625

Refinery yields – barrels per day		207,186			248,364			188,497			241,855
United States		158,635			141,710			130,883			139,228
Gasoline		66,087			64,240			54,944			60,101
Kerosine		13,484			10,472			10,493			11,848
Diesel and home heating oils		43,499			41,523			34,441			39,523
Residuals		22,180			14,428			18,072			15,078
Asphalt		12,955			10,048			12,150			11,533
Fuel and loss		430			999			783			1,145
United Kingdom		48,551			106,654			57,614			102,627
Gasoline		8,390			28,104			13,308			25,486
Kerosine		6,843			11,012			8,323			11,659
Diesel and home heating oils		13,577			39,375			15,915			36,632
Residuals		3,958			11,240			5,560			9,703
Asphalt		13,263			13,618			12,006			15,304
Fuel and loss		2,520			3,305			2,502			3,843

Petroleum products sold – barrels per day		508,117			538,596			493,486			521,333
Total United States		459,277			429,821			435,110			418,097
United States Manufacturing		163,113			140,643			131,673			133,677
Gasoline		73,741			64,234			62,319			60,100
Kerosine		13,484			10,474			10,493			11,849
Diesel and home heating oils		43,499			42,557			34,441			40,043
Residuals		22,523			14,221			17,965			14,907
Asphalt, LPG and other		9,866			9,157			6,455			6,778
United States Marketing		426,888			406,447			410,689			396,411
Gasoline		333,781			321,889			325,232			311,236
Kerosine		11,766			9,265			9,487			12,221
Diesel and other		81,341			75,293			75,970			72,954
United States Intercompany Elimination		(130,724	)		(117,269	)		(107,252	)		(111,991	)
Gasoline		(73,743	)		(64,240	)		(62,319	)		(60,100	)
Kerosine		(13,482	)		(10,474	)		(10,492	)		(11,849	)
Diesel and other		(43,499	)		(42,555	)		(34,441	)		(40,042	)
United Kingdom		48,840			108,775			58,376			103,236
Gasoline		15,535			31,799			16,235			29,669
Kerosine		6,763			9,936			8,314			10,349
Diesel and home heating oils		19,034			41,155			20,358			38,033
Residuals		2,142			11,418			5,192			9,507
LPG and other		5,366			14,467			8,277			15,678
Unit margins per barrel:
United States refining¹	$	0.69		$	1.81		$	(1.23	)	$	1.46
United Kingdom refining and marketing		0.52			1.09			(1.65	)		0.61
United States retail marketing:
Fuel margin per gallon²	$	0.162		$	0.078		$	0.123		$	0.064
Gallons sold per store month		316,378			318,116			304,294			308,625
Merchandise sales revenue per store month	$	158,586		$	138,761		$	148,576		$	127,819
Merchandise margin as a percentage of merchandise sales		12.9	%		12.6	%		12.6	%		13.2	%
Store count at end of period (Company operated)		1,067			1,034

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 $30.6 million in the 2010 second quarter compared to net benefits of $14.8 million in the second quarter of 2009. The 2010 results of corporate activities were significantly unfavorable to 2009 primarily due to net after-tax losses of $1.6 million on transactions denominated in foreign currencies in the current quarter compared to net gains of $33.6 million in the comparable 2009 period. In addition, net interest expense was higher in 2010 compared to 2009 primarily due to lower amounts of interest capitalized to ongoing oil and natural gas development projects. Also, administrative costs were higher in 2010 than 2009 primarily due to higher compensation expense.

For the first six months of 2010, corporate activities reflected net costs of $99.0 million compared to net benefits of $24.9 million a year ago. Six-month corporate costs in 2010 were significantly unfavorable to 2009 mostly related to the effects of transactions denominated in foreign currencies and higher net interest expense. Total after-tax losses for foreign currency transactions were $42.9 million in the 2010 period compared to net benefits of $59.7 million in the first six 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 associated with increased employee compensation costs.

Financial Condition

Net cash provided by operating activities was $1,447.7 million for the first six months of 2010 compared to $512.5 million during the same period in 2009. Changes in operating working capital other than cash and cash equivalents provided cash of $249.8 million in the first six months of 2010, but used cash of $193.1 million in the first six 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 $1,239.3 million in the 2010 period and $1,021.4 million 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 $95.7 million in 2010 and $95.3 million in 2009, and for property additions and dry holes, which including amounts expensed, were $992.3 million and $1,004.9 million in the six-month periods ended June 30, 2010 and 2009, respectively. Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $1,263.0 million in the 2010 period and $1,185.8 million in the 2009 period. Total accrual basis capital expenditures for continuing operations were as follows:


	Six Months Ended June 30,
(Millions of dollars)	2010		2009
Capital Expenditures – Continuing operations
Exploration and production	$	906.8	925.0
Refining and marketing		189.5	102.2
Corporate and other		3.1	1.7

Total capital expenditures – continuing operations		1,099.4	1,028.9

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


	Six Months Ended June 30,
(Millions of dollars)	2010		2009
Property additions and dry hole costs per cash flow statements	$	992.3	1,004.9
Geophysical and other exploration expenses		41.3	23.9
Capital expenditure accrual changes		65.8	0.1

Total capital expenditures		1,099.4	1,028.9

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS (Contd.)

Financial Condition (Contd.)

Working capital (total current assets less total current liabilities) at June 30, 2010 was $992.1 million, a decrease of $202.0 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 $604.2 million below fair value at June 30, 2010.

At June 30, 2010, long-term notes payable of $1,226.6 million had decreased in total by $126.6 million compared to December 31, 2009. A summary of capital employed at June 30, 2010 and December 31, 2009 follows.


	June 30, 2010			Dec. 31, 2009
(Millions of dollars)	Amount		%	Amount	%
Capital employed
Long-term debt	$	1,226.6	13.8	1,353.2	15.6
Stockholders’ equity		7,667.0	86.2	7,346.0	84.4

Total capital employed	$	8,893.6	100.0	8,699.2	100.0

The Company’s ratio of earnings to fixed charges was 18.0 to 1 for the six-month period ended June 30, 2010.

Accounting and Other Matters

Outlook

Average crude oil prices in July 2010 improved slightly compared to the average price during the second quarter of 2010. The Company expects its oil and natural gas production to average about 180,000 barrels of oil equivalent per day in the third quarter 2010. U.S. retail marketing margins have eased a bit in July versus the average margins achieved in the second quarter 2010. Additionally, margins remained under pressure during July 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 makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions. There were short-term commodity derivative contracts in place at June 30, 2010 to hedge the purchase price of about 1.1 million barrels of crude oil at the Company’s refineries and 2.9 million bushels of corn at the Company’s ethanol production facility. A 10% increase in the respective benchmark price of those commodities would have reduced the recorded asset associated with these derivative contracts by approximately $8.4 million, while a 10% decrease would have increased the recorded asset by a similar amount. Changes in the fair value of these derivative contracts generally offset the changes in the value for an equivalent volume of crude oil feedstocks.

There were short-term derivative foreign exchange contracts in place at June 30, 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 $28.8 million, while a 10% weakening of the U.S. dollar would have increased the recorded net asset by approximately $35.0 million. Changes in the fair value of these derivative contracts generally offset the financial statement impact of an equivalent volume of foreign currency exposures associated with other assets and/or liabilities.

ITEM 4.

CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There have been no changes in the Company’s internal control over financial reporting during the quarter ended June 30, 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. President has placed a six-month moratorium on new drilling in the Gulf of Mexico. The moratorium has forced the Company to defer planned exploration drilling in the Gulf of Mexico. Further impacts of the accident and oil spill could include additional future regulations covering offshore drilling operations, higher costs for future drilling operations, and higher costs for offshore insurance. The Company is unable to predict when the drilling moratorium will be lifted and how the effects of the accident will ultimately impact its U.S. and worldwide operations.

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)
August 6, 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 Label 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