Murphy Oil (MUR) 10-Q 2010 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

For the quarterly period ended March 31, 2010

OR

¨ 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.

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

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

Number of shares of Common Stock, $1.00 par value, outstanding at March 31, 2010 was191,482,649.

MURPHY OIL CORPORATION

TABLE OF CONTENTS

	Page
Part I – Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets	2
Consolidated Statements of Income	3
Consolidated Statements of Comprehensive Income	4
Consolidated Statements of Cash Flows	5
Consolidated Statements of Stockholders’ Equity	6
Notes to Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3. Quantitative and Qualitative Disclosures About Market Risk	27
Item 4. Controls and Procedures	27
Part II – Other Information
Item 1. Legal Proceedings	28
Item 1A. Risk Factors	28
Item 6. Exhibits and Reports on Form 8-K	28
Signature	29

1

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)

	(Unaudited)
	March 31, 2010			December 31, 2009
ASSETS
Current assets
Cash and cash equivalents	$	299,973		301,144
Canadian government securities with maturities greater than 90 days at the date of acquisition		895,643		779,025
Accounts receivable, less allowance for doubtful accounts of $7,872 in 2010 and $7,761 in 2009		1,390,131		1,463,297
Inventories, at lower of cost or market
Crude oil and blend stocks		157,817		128,936
Finished products		377,659		384,250
Materials and supplies		218,733		220,796
Prepaid expenses		91,290		83,218
Deferred income taxes		54,713		15,029
Total current assets		3,485,959		3,375,695
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $5,057,057 in 2010 and $4,714,826 in 2009		9,307,027		9,065,088
Goodwill		42,115		40,652
Deferred charges and other assets		334,741		274,924
Total assets	$	13,169,842		12,756,359
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	29		38
Accounts payable and accrued liabilities		2,003,515		1,794,406
Income taxes payable		447,836		387,164
Total current liabilities		2,451,380		2,181,608
Long-term debt		1,231,235		1,353,183
Deferred income taxes		1,052,274		1,018,767
Asset retirement obligations		502,331		476,938
Deferred credits and other liabilities		379,037		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 191,988,394 shares in 2010 and 191,797,600 shares in 2009		191,988		191,798
Capital in excess of par value		688,344		680,509
Retained earnings		6,305,396		6,204,316
Accumulated other comprehensive income		381,041		287,187
Treasury stock, 505,745 shares of Common Stock in 2010 and 682,222 shares of Common Stock in 2009, at cost		(13,184	)	(17,784	)
Total stockholders’ equity		7,553,585		7,346,026
Total liabilities and stockholders’ equity	$	13,169,842		12,756,359

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page 30.

2

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars, except per share amounts)

	Three Months Ended March 31,
	2010			2009
REVENUES
Sales and other operating revenues	$	5,228,675		3,416,427
Gain on sale of assets		676		15
Interest and other income (expense)		(49,191	)	29,110
Total revenues		5,180,160		3,445,552
COSTS AND EXPENSES
Crude oil and product purchases		3,978,959		2,556,044
Operating expenses		465,607		362,361
Exploration expenses, including undeveloped lease amortization		66,364		111,105
Selling and general expenses		65,131		56,832
Depreciation, depletion and amortization		292,680		194,769
Accretion of asset retirement obligations		7,613		6,253
Redetermination of Terra Nova working interest		5,516		—
Interest expense		14,809		11,988
Interest capitalized		(2,665	)	(10,323	)
Total costs and expenses		4,894,014		3,289,029
Income from continuing operations before income taxes		286,146		156,523
Income tax expense		137,255		85,283
Income from continuing operations		148,891		71,240
Income from discontinued operations, net of income taxes		—		99,864
NET INCOME	$	148,891		171,104
INCOME PER COMMON SHARE – BASIC
Income from continuing operations	$	0.78		0.37
Income from discontinued operations		—		0.53
Net Income – Basic	$	0.78		0.90
INCOME PER COMMON SHARE – DILUTED
Income from continuing operations	$	0.77		0.37
Income from discontinued operations		—		0.52
Net income – Diluted	$	0.77		0.89
Average Common shares outstanding – basic		191,219,265		190,545,771
Average Common shares outstanding – diluted		192,929,735		192,281,803

See Notes to Consolidated Financial Statements, page 7.

3

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)

	Three Months Ended March 31,
	2010		2009
Net income	$	148,891	171,104
Other comprehensive income, net of income taxes
Net gain (loss) from foreign currency translation		91,660	(80,987	)
Retirement and postretirement benefit plan adjustments		2,194	2,188
COMPREHENSIVE INCOME	$	242,745	92,305

See Notes to Consolidated Financial Statements, page 7.

4

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)

	Three Months Ended March 31,
	2010			2009
OPERATING ACTIVITIES
Net income	$	148,891		171,104
Income from discontinued operations		—		99,864
Income from continuing operations		148,891		71,240
Adjustments to reconcile income from continuing operations to net cash provided by operating activities
Depreciation, depletion and amortization		292,680		194,769
Amortization of deferred major repair costs		7,181		6,501
Expenditures for asset retirements		(7,521	)	(2,098	)
Dry hole costs		22,274		67,471
Amortization of undeveloped leases		20,857		25,734
Accretion of asset retirement obligations		7,613		6,253
Deferred and noncurrent income tax charges (benefits)		18,272		(785	)
Pretax gain from disposition of assets		(676	)	(15	)
Net decrease in noncash operating working capital		244,327		44,970
Other operating activities, net		75,499		(36,589	)
Net cash provided by continuing operations		829,397		377,451
Net cash provided by discontinued operations		—		2,576
Net cash provided by operating activities		829,397		380,027
INVESTING ACTIVITIES
Property additions and dry hole costs		(481,005	)	(511,358	)
Purchases of investment securities*		(630,169	)	(599,751	)
Proceeds from maturity of investment securities*		513,551		406,528
Expenditures for major repairs		(50,516	)	(7,408	)
Proceeds from sales of assets		1,545		116
Other – net		(7,580	)	(1,836	)
Investing activities of discontinued operations
Sales proceeds		—		78,908
Other		—		(845	)
Net cash required by investing activities		(654,174	)	(635,646	)
FINANCING ACTIVITIES
Repayment of notes payable		(122,000	)	(30,000	)
Repayment of nonrecourse debt of a subsidiary		—		(2,572	)
Proceeds from exercise of stock options and employee stock purchase plans		5,620		4,420
Withholding tax on stock-based incentive awards		(4,930	)	—
Excess tax benefits related to exercise of stock options		191		1,957
Cash dividends paid		(47,811	)	(47,639	)
Net cash required by financing activities		(168,930	)	(73,834	)
Effect of exchange rate changes on cash and cash equivalents		(7,464	)	(9,254	)
Net decrease in cash and cash equivalents		(1,171	)	(338,707	)
Cash and cash equivalents at January 1		301,144		666,110
Cash and cash equivalents at March 31	$	299,973		327,403
SUPPLEMENTAL DISCLOSURES OF CASH FLOW ACTIVITIES
Cash income taxes paid	$	122,959		82,401
Interest paid more than (less than) amounts capitalized	$	911		(8,975	)

* Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

See Notes to Consolidated Financial Statements, page 7.

5

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)

	Three Months Ended March 31,
	2010			2009
Cumulative Preferred Stock– par $100, authorized 400,000 shares, none issued		—		—
Common Stock– par $1.00, authorized 450,000,000 shares, issued 191,988,394 shares at March 31, 2010 and 191,508,641 shares at March 31, 2009
Balance at beginning of period	$	191,798		191,249
Exercise of stock options		190		260
Balance at end of period		191,988		191,509
Capital in Excess of Par Value
Balance at beginning of period		680,509		631,859
Exercise of stock options, including income tax benefits		5,300		7,440
Restricted stock transactions and other		(9,229	)	5,439
Amortization, forfeitures and other		11,502		8,114
Sale of stock under employee stock purchase plans		262		191
Balance at end of period		688,344		653,043
Retained Earnings
Balance at beginning of period		6,204,316		5,557,483
Net income for the period		148,891		171,104
Cash dividends		(47,811	)	(47,639	)
Balance at end of period		6,305,396		5,680,948
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		287,187		(87,697	)
Foreign currency translation gains (losses), net of income taxes		91,660		(80,987	)
Retirement and postretirement benefit plan adjustments, net of income taxes		2,194		2,188
Balance at end of period		381,041		(166,496	)
Treasury Stock
Balance at beginning of period		(17,784	)	(13,949	)
Sale of stock under employee stock purchase plans		301		587
Awarded restricted stock, net of forfeitures		4,299		—
Cancellation of performance-based restricted stock and forfeitures		—		(5,440	)
Balance at end of period		(13,184	)	(18,802	)
Total Stockholders’ Equity	$	7,553,585		6,340,202

See notes to consolidated financial statements, page 7.

6

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 March 31, 2010, and the results of operations, cash flows and changes in stockholders’ equity for the three-month periods ended March 31, 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 months ended March 31, 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. The Ecuador properties sold included 20% interests in producing Block 16 and the nearby Tivacuno area. The Company recorded a preliminary gain of $104.0 million, net of income taxes of $14.0 million, from the sale of the Ecuador properties. 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 at the date of sale were as follows:

(Thousands of dollars)
Current assets	$	4,214
Property, plant and equipment, net of accumulated depreciation, depletion and amortization		65,178
Other noncurrent assets		683
Assets sold	$	70,075
Current liabilities	$	105,185
Other noncurrent liabilities		35
Liabilities associated with assets sold	$	105,220

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

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

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.

7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

At March 31, 2010, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $379.2 million. The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2010 and 2009.

(Thousands of dollars)	2010		2009
Beginning balance at January 1	$	369,862	310,118
Additions pending the determination of proved reserves		9,310	2,326
Reclassifications to proved properties based on the determination of proved reserves		—	—
Balance at March 31	$	379,172	312,444

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

	March 31
	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	$	122,085	14	6	31,261	3	2
One to two years		32,400	4	2	18,046	2	2
Two to three years		17,946	2	2	71,101	14	3
Three years or more		206,741	32	4	192,036	25	5
	$	379,172	52	14	312,444	44	12

Of the $257.1 million of exploratory well costs capitalized more than one year at March 31, 2010, $177.7 million is in Malaysia, $59.8 million is in the U.S., $10.1 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 Canada a continuing drilling and development program is underway, and in the U.K. further studies to evaluate the discovery are ongoing.

Note D – Employee and Retiree Benefit Plans

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

The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2010 and 2009.

	Three Months Ended March 31,
	Pension Benefits					Other Postretirement Benefits
(Thousands of dollars)	2010			2009		2010		2009
Service cost	$	5,259		4,118		888		776
Interest cost		7,448		6,988		1,431		1,391
Expected return on plan assets		(5,851	)	(5,346	)	—		—
Amortization of prior service cost		387		398		(64	)	(66	)
Amortization of transitional asset		(127	)	(106	)	—		—
Recognized actuarial loss		2,965		2,944		578		421
Net periodic benefit expense	$	10,081		8,996		2,833		2,522

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

During the three-month period ended March 31, 2010, the Company made contributions of $3.7 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 $22.3 million.

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

The Company provides a health care benefit plan to eligible U.S. employees and most U.S. retired employees. The new law did not significantly affect the Company’s consolidated financial statements as of March 31, 2010 and for the three-month period 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 E – 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 three-month periods ended March 31, 2010 and 2009 was $5.6 million and $4.4 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $2.5 million for each of the three-month periods ended March 31, 2010 and 2009.

9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – Incentive Plans(Contd.)

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

	Three Months Ended March 31
(Thousands of dollars)	2010		2009
Compensation charged against income before tax benefit	$	11,932	8,127
Related income tax benefit recognized in income		3,181	2,707

Note F – Earnings per Share

Net income was used as the numerator in computing both basic and diluted income per Common share for the three months ended March 31, 2010 and 2009. The following table reconciles the weighted-average shares outstanding used for these computations.

	Three Months Ended March 31
(Weighted-average shares)	2010	2009
Basic method	191,219,265	190,545,771
Dilutive stock options	1,710,470	1,736,032
Diluted method	192,929,735	192,281,803

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 3,271,753 shares at a weighted average share price of $54.27 in 2010 and 3,354,875 shares at a weighted average share price of $55.71 in 2009.

Note G – Financial Instruments and Risk Management

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

• Crude Oil Purchase Price Risks – The Company purchases crude oil as feedstock at its U.S. and U.K. refineries and is therefore subject to commodity price risk. Short-term derivative instruments were outstanding at March 31, 2009 to manage the cost of about 0.5 million barrels of crude oil at the Company’s Meraux, Louisiana and Superior, Wisconsin refineries. The total impact of marking these contracts to market increased income from continuing operations before income taxes by $0.2 million in the three-month period ended March 31, 2009. There were no open crude oil purchase derivative contracts at March 31, 2010.

• Foreign Currency Exchange Risks – The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. Short-term derivative instruments were outstanding at March 31, 2010 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 March 31, 2010 and 2009 were approximately $361 million and $140 million, respectively. Short-term derivative instruments were outstanding at March 31, 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 $45.0 million and $16.0 million U.S. dollar contracts were outstanding at March 31, 2010 and 2009, respectively, related to these Canadian receivables. The impact on consolidated income from continuing operations before income taxes from marking these derivative contracts to market was a gain of $14.3 million for first quarter 2010 and loss of $0.5 million for first quarter 2009. The outstanding Malaysian instruments mature by December 2010 and the outstanding Canadian instruments mature in April 2010.

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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

	March 31, 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 payable and accrued liabilities	$	(2,344	)	Accounts receivable	$	2,296
Foreign exchange derivative contracts	Accounts receivable		14,466		Accounts receivable		340

For the three-month periods ended March 31, 2010 and 2009, the gains and losses recognized in the consolidated statement of income for derivative instruments not designated as hedging instruments are presented in the following table.

	Three Months Ended March 31, 2010				Three Months Ended March 31, 2009
(Thousands of dollars)	Location of Gain or (Loss) Recognized in Income on Derivative	Amount of Gain (Loss) Recognized in Income on Derivative			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	$	(2,162	)	Crude oil and product purchases	$	(4,684	)
Foreign exchange derivative contracts	Interest and other income		14,330		Interest and other income		(550	)
		$	12,168			$	(5,234	)

The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet. The fair value measurements for these assets and liabilities at March 31, 2010 and December 31, 2009 are presented in the following table.

	March 31, 2010			Fair Value Measurements at Reporting Date Using
(Thousands of dollars)				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 assets	$	14,466		—		14,466		—
Liabilities
Commodity derivative liabilities	$	(2,344	)	—		(2,344	)	—
Nonqualified employee savings plan		(5,723	)	(5,723	)	—		—
	$	(8,067	)	(5,723	)	(2,344	)	—

	Dec. 31, 2009			Fair Value Measurements at Reporting Date Using
(Thousands of dollars)				Quoted Prices in Active Markets for Identical Assets (Liabilities) (Level 1)		Significant Other Observable Inputs (Level 2)	Significant Unobservable Inputs (Level 3)
Assets
Derivative assets	$	2,636		—		2,636	—
Liabilities
Nonqualified employee savings plan	$	(5,691	)	(5,691	)	—	—

11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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. Fair value of this liability was based on quoted prices for these equity securities and mutual funds. The fair value of commodity derivatives was determined based on market quotes for WTI crude and foreign currency exchange contracts at the balance sheet date. The income effect of the changes in the fair value of nonqualified employee savings plan is recorded in Selling and General Expense in the Consolidated Statement of Income. The change in fair value of commodity derivatives is recorded in Crude Oil and Product Purchases and the change in fair value of foreign currency exchange derivatives is recorded in Interest and Other Income (Loss).

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.

Note H – Accumulated Other Comprehensive Income

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

(Thousands of dollars)	March 31, 2010			Dec. 31, 2009
Foreign currency translation gains, net of tax	$	513,128		421,468
Retirement and postretirement benefit plan losses, net of tax		(132,087	)	(134,281	)
Accumulated other comprehensive income	$	381,041		287,187

Note I – Environmental and Other Contingencies

The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax increases and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations 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

12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Environmental and Other Contingencies(Contd.)

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.

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 March 31, 2010, the Company had contingent liabilities of $7.8 million under a financial guarantee and $59.4 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 J – 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.

13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – 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%, subject to the results of the ongoing arbitration process between the operator and certain other owners. Upon completion of the arbitration process, which is anticipated to occur in late 2010, 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 $89.0 million through March 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 L – Accounting Matters

The Company adopted new guidance issued by the Financial Accounting Standards Board (FASB) regarding accounting for transfers of financial assets effective January 1, 2010. This guidance makes the concept of a qualifying special-purpose entity as defined previously no longer relevant for accounting purposes. Therefore, formerly qualifying special-purpose entities must be reevaluated for consolidation by reporting entities in accordance with the applicable consolidation guidance. This adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted, effective January 1, 2010, new guidance issued by the FASB that requires a company to perform an analysis to determine whether its variable interests give it a controlling financial interest in a variable interest entity. The primary beneficiary of a variable interest entity has both the power to direct the activities of the entity that most significantly impact the entity’s economic performance and the obligation to absorb potentially significant losses of the entity or the right to receive potentially significant benefits from the entity. A company is required to make ongoing reassessments of whether it is the primary beneficiary of a variable interest entity. This guidance also amends previous guidance for determining whether an entity is considered a variable interest entity. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted new accounting guidance issued by the FASB for noncontrolling interests in consolidated financial statements effective January 1, 2009. This guidance was applied prospectively, except for presentation and disclosure requirements which are applied retrospectively. This guidance required noncontrolling interests to be reclassified as equity, and consolidated net income and comprehensive income shall include the respective results attributable to noncontrolling interests. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted new accounting guidance covering business combinations effective January 1, 2009. The new guidance established principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquired business. It also established how to recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, if applicable. This guidance impacts the recognition and measurement of assets and liabilities in business combinations that occur beginning in 2009. Assets and liabilities that arose from business combinations that occurred prior to 2009 are not affected by this guidance. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements. The Company is unable to predict how the application of this guidance will affect its financial statements in future periods.

The Company adopted new accounting guidance which addresses disclosures about derivative instruments and hedging activities in January 2009. This guidance expands required disclosures regarding derivative instruments to include qualitative information about objectives and strategies for using derivatives, quantities disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk related contingent features in derivative agreements.

14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Accounting Matters (Contd.)

In 2009, the Company adopted new accounting guidance for determining whether instruments granted in share-based payment transactions are participating securities. This guidance specifies that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings per share (EPS) calculation under the two-class method, and also requires that all prior-period EPS calculations be adjusted retrospectively. The adoption of this guidance did not have a significant impact on the Company’s prior-period EPS calculations.

The Company adopted new accounting guidance addressing certain equity method investment accounting considerations in January 2009, which has been applied prospectively. The guidance addresses how to initially measure contingent consideration for an equity method investment, how to recognize other-than-temporary impairments of an equity method investment, and how an equity method investor is to account for a share issuance by an investee. The adoption of this guidance did not have a significant impact on the Company’s consolidated financial statements.

The Company adopted new accounting guidance addressing subsequent events effective June 30, 2009. The guidance clarified the accounting for and disclosure of subsequent events that occur after the balance sheet date through the date of issuance of the applicable financial statements. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The FASB’s Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles guidance became effective for interim and annual periods ended after September 15, 2009 (the third calendar quarter for Murphy Oil) and it recognized the FASB Accounting Standards Codification as the single source of authoritative nongovernment U.S. generally accepted accounting principles. The codification superseded all existing accounting standards documents issued by the FASB, and established that all other accounting literature not included in the codification is considered nonauthoritative. Although the codification does not change U.S. generally accepted accounting principles, it does reorganize the principles into accounting topics using a consistent structure. The codification also includes relevant U.S. Securities and Exchange Commission guidance following the same topical structure. For periods ending after September 15, 2009, all references to U.S. generally accepted accounting principles will use the new topical guidelines established with the codification. Otherwise, this new standard is not expected to have a material impact on the Company’s consolidated financial statements in future periods.

The FASB has provided additional guidance regarding disclosures about postretirement benefit plan assets, including how asset investment allocation decisions are made, the fair value of each major category of plan assets, and how fair value is determined for each major asset category. This guidance was effective for the Company as of December 31, 2009. Upon adoption, no comparative disclosures were required for earlier years presented.

In December 2008, the U.S. Securities and Exchange Commission adopted revisions to oil and natural gas reserves reporting requirements which became effective for the Company at year-end 2009. The primary changes to reserves reporting included:

• A revised definition of proved reserves, including the use of unweighted average oil and natural gas prices in effect at the beginning of each month during the year to compute such reserves,

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

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

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

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

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

The Company utilized this new guidance at year-end 2009 to determine its proved reserves and to develop associated disclosures. The Company has thus far chosen not to provide voluntary disclosures of probable and possible reserves in its filings with the Securities and Exchange Commission.

15

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note M – Business Segments

	Total Assets at March 31, 2010
			Three Mos. Ended March 31, 2010					Three Mos. Ended March 31,  20091
(Millions of dollars)			External Revenues		Interseg. Revenues	Income (Loss)		External Revenues	Interseg. Revenues	Income (Loss)
Exploration and production2
United States	$	1,527.7	175.0		—	18.7		71.0	—	(7.3	)
Canada		2,726.7	203.3		19.6	49.2		113.4	21.1	.6
Malaysia		3,228.6	503.9		—	173.5		337.4	—	117.5
United Kingdom		213.8	52.4		—	16.6		11.7	—	3.4
Republic of the Congo		571.9	28.3		—	2.5		—	—	.3
Other		41.8	2.3		—	(13.5	)	.5	—	(64.2	)
Total		8,310.5	965.2		19.6	247.0		534.0	21.1	50.3
Refining and marketing
United States manufacturing		1,261.6	116.2		640.2	(23.6	)	65.2	512.7	8.3
United States marketing		1,425.4	3,605.6		—	8.9		2,331.4	—	6.3
United Kingdom		914.4	542.4		—	(15.0	)	485.9	—	(3.8	)
Total		3,601.4	4,264.2		640.2	(29.7	)	2,882.5	512.7	10.8
Total operating segments		11,911.9	5,229.4		659.8	217.3		3,416.5	533.8	61.1
Corporate and other		1,257.9	(49.2	)	—	(68.4	)	29.1	—	10.1
Revenue/income from continuing operations		13,169.8	5,180.2		659.8	148.9		3,445.6	533.8	71.2
Discontinued operations, net of tax		—	—		—	—		—	—	99.9
Total	$	13,169.8	5,180.2		659.8	148.9		3,445.6	533.8	171.1

¹ Reclassified to conform to current presentation.

² Additional details about results of oil and gas operations are presented in the tables on page 21.

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 N – Subsequent Event

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 March 31, 2010 is included in Property, Plant and Equipment in the consolidated balance sheet pending resolution of its potential participation in replacement production sharing contracts.

16

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

Results of Operations

Murphy’s net income in the first quarter of 2010 was $148.9 million ($0.77 per diluted share) down from net income of $171.1 million ($0.89 per diluted share) in the same quarter of 2009. The 2010 quarterly results included net after-tax losses of $41.3 million ($0.21 per diluted share) on transactions denominated in foreign currencies, while the 2009 results included after-tax gains of $26.1 million ($0.14 per diluted share) on these transactions. Net income in 2009 included income from discontinued operations of $99.9 million ($0.52 per diluted share) with this income mostly being generated from a gain on sale of the Company’s Ecuador operations in March 2009. Income from continuing operations for the three-month periods ended March 31, 2010 and 2009 was $148.9 million ($0.77 per diluted share) and $71.2 million ($0.37 per diluted share), respectively. The 109% improvement in income from continuing operations in 2010 was attributable to substantially higher income from the Company’s exploration and production business partially offset by unfavorable results from refining and marketing operations and corporate activities. Murphy’s income from continuing operations by type of business is presented below.

	Income (Loss)
	Three Months Ended March 31,
(Millions of dollars)	2010			2009
Exploration and production	$	247.0		50.3
Refining and marketing		(29.7	)	10.8
Corporate		(68.4	)	10.1
Income from continuing operations	$	148.9		71.2

Murphy’s income from continuing exploration and production operations was $247.0 million in the first quarter of 2010 compared to $50.3 million in the same quarter of 2009. The almost four-fold increase in 2010 income compared to 2009 was primarily driven by a combination of higher realized sales prices for crude oil and natural gas, higher natural gas sales volumes and lower exploration expenses in the current period. Exploration expense in the 2010 period was $66.3 million, down from $111.1 million in 2009. Murphy’s refining and marketing operations incurred a loss of $29.7 million in the 2010 quarter compared to earnings of $10.8 million in the 2009 quarter. This unfavorable variance was principally attributable to much weaker refining margins and downtime for refinery turnarounds in the U.S. and U.K. Corporate functions reflected net costs of $68.4 million in the 2010 first quarter compared to a net benefit of $10.1 million in 2009. The increase in net corporate costs in 2010 mostly reflected significant after-tax losses on transactions denominated in foreign currencies in 2010 compared to after-tax gains in the 2009 quarter.

Exploration and Production

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

	Income (Loss)
	Three Months Ended March 31,
(Millions of dollars)	2010			2009
Exploration and production – continuing operations
United States	$	18.7		(7.3	)
Canada		49.2		0.6
Malaysia		173.5		117.5
United Kingdom		16.6		3.4
Republic of the Congo		2.5		0.3
Other International		(13.5	)	(64.2	)
Total – continuing operations	$	247.0		50.3

In the United States, exploration and production operations had income of $18.7 million in the first quarter of 2010 compared to a loss of $7.3 million in the 2009 quarter. This favorable result in 2010 compared to the prior year was primarily due to higher crude oil and natural gas sales prices and higher crude oil sales volumes. Partial offsets were lower natural gas sales volumes and higher expenses for production, exploration, depreciation and administration. Production expense in the U.S. was higher in the 2010 period due to more oil production compared to 2009, with the increase primarily due to production at the Thunder Hawk field in the Gulf of Mexico, which came onstream in the third quarter of 2009. Depreciation expense also rose in 2010 primarily due to higher production volumes at Thunder Hawk. Exploration expenses in the U.S. of $28.0 million were up $8.3 million in 2010 due to higher amortization expense for undeveloped leases held in the Eagle Ford shale area of South Texas and higher geophysical costs for seismic acquisition in the Gulf of Mexico. Dry hole expense was lower in 2010 than 2009 due to unsuccessful onshore Louisiana drilling in the prior year. Administrative costs increased in 2010 primarily due to higher employee costs and a lower percentage of overhead charged to partners.

17

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

Results of Operations (Contd.)

Exploration and Production(Contd.)

Earnings from operations in Canada were $49.2 million in the 2010 quarter compared to $0.6 million in the 2009 quarter. Canadian operations realized higher crude oil sales prices, higher sales volumes and sales prices for natural gas, and lower exploration expenses in the current period. The 2010 period had unfavorable variances for crude oil sales volumes, production and depreciation expenses, and costs associated with a redetermination of working interests at the Terra Nova field, offshore Newfoundland. Natural gas sales volumes were higher in the 2010 quarter due to continued ramp-up of production in the Tupper area in Western Canada. Production expenses in Canada were unfavorable in 2010 due to higher costs at Syncrude and higher natural gas production at Tupper. Depreciation expense increased in the 2010 period compared to 2009 due mostly to more Tupper natural gas sales volumes and higher unit rates at Syncrude. Exploration expenses in Canada were $7.4 million in 2010 compared to $20.3 million in 2009, and the reduction was due primarily to lower undeveloped leasehold amortization costs incurred in 2010 for the Tupper West natural gas area. The expense associated with Terra Nova redetermination relates to an anticipated cash settlement for revenues, net of expenses, that will be required upon final working interest redetermination, which is currently expected in late 2010. The Company’s original 12.0% working interest could be reduced to approximately 10.5% upon completion of the redetermination process. While the redetermination process continues, the Company continues to be allocated and sells 12% of crude oil production at Terra Nova.

Operations in Malaysia reported a profit of $173.5 million in the first quarter of 2010 compared to a profit of $117.5 million in the same period in 2009. The 2010 results were favorable to 2009 primarily due to higher crude oil sales prices. Production volumes for natural gas increased during the 2010 period related to a Sarawak gas field that started up in the third quarter of 2009 and higher demand for natural gas volumes at the Kikeh field, offshore Sabah. Although crude oil liquids production volumes declined slightly during the 2010 period, sales volumes rose due to the timing of scheduling sales of oil through periodic oil tanker loadings at the Kikeh field. Production and depreciation expenses in Malaysia rose in 2010 mostly due to higher overall natural gas sales volumes. Dry hole costs were higher in the 2010 quarter than in 2009 primarily due to more unsuccessful wildcat drilling costs in the current quarter in deepwater blocks offshore Sabah. Certain exploration expenses in Malaysia do not receive income tax benefits at the present time.

U.K. operations earned $16.6 million in the 2010 period versus $3.4 million in the same quarter a year ago, with the improvement due to a combination of higher crude oil sales prices, and higher crude oil and natural gas sales volumes. Crude oil sales volumes increased primarily at the Schiehallion field where a sale occurred in the 2010 period, whereas no sale occurred at this field during the 2009 quarter. Natural gas sales volumes were higher in 2010 than 2009 due to gas produced at the Amethyst field in the current period, while the field was off production for the entire first quarter of the prior year because of major equipment failure. Production and depreciation expenses increased in 2010 compared to 2009 in the U.K. due to the higher oil and natural gas sales volumes.

Operations in Republic of the Congo had income of $2.5 million in the first quarter of 2010 compared to income of $0.3 million in the comparable 2009 quarter. Income in the current period was associated with crude oil sales volumes following start-up of production in the third quarter 2009. Production and depreciation expenses increased in 2010 associated with the crude oil production activities.

Other international operations reported a loss of $13.5 million in the 2010 period versus a loss of $64.2 million in the same period for 2009. The smaller loss in 2010 was primarily due to unsuccessful exploratory drilling costs in 2009 offshore Western Australia and more 3-D seismic expense in 2009 for Block 37 offshore Suriname.

On a worldwide basis, the Company’s crude oil, condensate and natural gas liquids sales price averaged $64.89 per barrel for the 2010 first quarter compared to $43.15 per barrel in the first quarter of 2009. The 50% increase in average realized crude oil sales price was below the 82% increase between periods in the West Texas Intermediate (WTI) benchmark because of several factors. The benchmark price for crude oil in Malaysia did not increase as much as WTI and the Company is required under its production sharing contract to share a portion of higher sales prices with the government in Malaysia. Additionally, in the Republic of the Congo, oil sales prices were based on one January cargo sold at a time when oil prices were near the low during the first quarter. The Company’s production from continuing operations averaged 196,226 barrels of oil equivalent per day during the first quarter 2010, an increase of 29% compared to the 2009 first quarter. Crude oil and

18

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

Results of Operations (Contd.)

Exploration and Production(Contd.)

liquids production from continuing operations averaged 139,060 barrels per day in the 2010 quarter, 4% higher than the 133,977 barrels per day produced in the 2009 period. Oil production in the United States was higher in 2010 than 2009 due to production at the Thunder Hawk field in the deepwater Gulf of Mexico, following start-up of the field in the third quarter 2009. Heavy oil production in Western Canada was lower in the 2010 first quarter compared to the 2009 period primarily at the Seal area due to a higher overall royalty rate resulting from project payout and higher net profits. Production volumes offshore Eastern Canada were lower in 2010 versus 2009 due to higher net profits royalty rates at Hibernia and Terra Nova coupled with field decline at Terra Nova. Synthetic net oil production at Syncrude in northern Alberta decreased in 2010 compared to 2009 primarily due to a higher net profits royalty rate attributable to stronger oil prices. Oil production declined somewhat in Malaysia in 2010 due to a lower percentage of Kikeh field production allocated to the Company, partially offset by condensate produced at the Sarawak natural gas field that started up in the third quarter of 2009. Production in the U.K. was unfavorable in 2010 due to lower volumes produced at the Schiehallion field caused by equipment downtime. Oil production in Republic of the Congo in the first quarter 2010 was generated from the Azurite field, which commenced production in the third quarter 2009. Average oil sales volumes for continuing operations increased from 129,595 barrels per day in the 2009 first quarter to 145,783 barrels per day in 2010. The higher crude oil sales volumes were attributable to the Kikeh field in Block K, offshore Sabah Malaysia, where sales volumes are affected by the timing of periodic oil tanker loadings, and sales volumes at the Thunder Hawk and Azurite fields after start-up of oil production at both fields in the third quarter 2009. North American natural gas sales prices averaged $5.14 per thousand cubic feet (MCF) in the 2010 first quarter compared to $4.66 per MCF in the same quarter of 2009. Total natural gas sales volumes averaged 343 million cubic feet per day in 2010, an increase of more than 200% from the 111 million cubic feet per day sold in the same period of 2009. The increase in 2010 was attributable to natural gas production offshore Sarawak Malaysia and at the Thunder Hawk field in the Gulf of Mexico that both commenced in the third quarter 2009, higher natural gas volumes produced in 2010 attributable to ramp-up of production at the Tupper area in Western Canada, and higher natural gas sales volumes at the Kikeh field due to more uptime at the onshore processing plant owned by a third party. Natural gas sales volumes in the U.K. were higher in 2010 than in 2009 primarily due to the Amethyst field being shut-in for the entire 2009 quarter due to equipment failure.

Additional details about results of oil and gas operations are presented in the tables on page 21.

19

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

Results of Operations (Contd.)

Exploration and Production(Contd.)

Selected operating statistics for the three-month periods ended March 31, 2010 and 2009 follow.

	Three Months Ended March 31,
	2010		2009
Net crude oil, condensate and gas liquids produced – barrels per day		139,060	139,318
Continuing operations		139,060	133,977
United States		21,648	13,268
Canada  – light		51	—
– heavy		6,483	7,436
– offshore		12,600	15,542
– synthetic		12,379	13,464
Malaysia		78,098	79,498
United Kingdom		4,087	4,769
Republic of the Congo		3,714	—
Discontinued operations		—	5,341
Net crude oil, condensate and gas liquids sold – barrels per day		145,783	134,306
Continuing operations		145,783	129,595
United States		21,648	13,268
Canada  – light		51	—
– heavy		6,483	7,436
– offshore		12,181	13,459
– synthetic		12,379	13,464
Malaysia		82,585	79,504
United Kingdom		7,220	2,464
Republic of the Congo		3,236	—
Discontinued operations		—	4,711
Net natural gas sold – thousands of cubic feet per day		342,995	111,309
United States		43,803	53,307
Canada		79,783	29,711
Malaysia  – Sarawak		158,576	—
– Kikeh		55,119	25,799
United Kingdom		5,714	2,492
Total net hydrocarbons produced – equivalent barrels per day (1)		196,226	157,870
Total net hydrocarbons sold – equivalent barrels per day (1)		202,949	152,858
Weighted average sales prices
Crude oil, condensate and natural gas liquids – dollars per barrel (2)
United States	$	75.57	37.55
Canada (3)  – light		78.06	—
– heavy		54.97	22.30
– offshore		75.38	42.17
– synthetic		78.71	44.63
Malaysia (4)		58.16	45.90
United Kingdom		75.75	44.79
Republic of the Congo		68.19	—
Natural gas – dollars per thousand cubic feet
United States (2)	$	5.76	5.12
Canada (3)		4.80	3.84
Malaysia  – Sarawak		4.58	—
– Kikeh		0.23	0.23
United Kingdom (3)		5.78	7.40

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

(2) Includes intracompany transfers at market prices.

(3) U.S. dollar equivalent.

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

20

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

Results of Operations (Contd.)

Exploration and Production(Contd.)

OIL AND GAS OPERATING RESULTS (unaudited)

(Millions of dollars)	United States			Canada		Malaysia		United Kingdom	Republic of the Congo		Other		Synthetic Oil –   Canada		Total
Three Months Ended March 31, 2010
Oil and gas sales and other operating revenues	$	175.0		135.2		503.9		52.4	28.3		2.3		87.7		984.8
Production expenses		32.8		25.8		83.8		9.2	11.9		—		51.8		215.3
Depreciation, depletion and amortization		75.4		46.1		105.9		8.3	9.4		.3		10.0		255.4
Accretion of assets retirement obligations		1.7		1.2		2.3		.5	.1		.1		1.6		7.5
Exploration expenses
Dry holes		.1		—		22.6		—	(.4	)	—		—		22.3
Geological and geophysical		12.4		.6		.2		.4	.3		2.1		—		16.0
Other		2.6		.1		—		.1	.3		4.1		—		7.2
		15.1		.7		22.8		.5	.2		6.2		—		45.5
Undeveloped lease amortization		12.9		6.7		—		—	—		1.2		—		20.8
Total exploration expenses		28.0		7.4		22.8		.5	.2		7.4		—		66.3
Terra Nova working interest redetermination		—		5.5		—		—	—		—		—		5.5
Selling and general expenses		8.0		3.6		.1		.9	(.9	)	7.2		.2		19.1
Results of operations before taxes		29.1		45.6		289.0		33.0	7.6		(12.7	)	24.1		415.7
Income tax provisions		10.4		13.6		115.5		16.4	5.1		.8		6.9		168.7
Results of operations (excluding corporate overhead and interest)	$	18.7		32.0		173.5		16.6	2.5		(13.5	)	17.2		247.0
Three Months Ended March 31, 2009*
Oil and gas sales and other operating revenues	$	71.0		80.4		337.4		11.7	—		.5		54.1		555.1
Production expenses		15.2		21.7		49.5		1.9	—		—		44.9		133.2
Depreciation, depletion and amortization		43.3		34.5		73.7		2.1	—		.4		6.3		160.3
Accretion of asset retirement obligations		1.7		1.0		1.7		.5	—		.1		1.0		6.0
Exploration expenses
Dry holes		11.4		—		13.7		—	—		42.4		—		67.5
Geological and geophysical		.8		1.0		(.2	)	—	—		12.2		—		13.8
Other		1.6		.1		—		—	(.3	)	2.7		—		4.1
		13.8		1.1		13.5		—	(.3	)	57.3		—		85.4
Undeveloped lease amortization		5.9		19.2		—		—	—		.6		—		25.7
Total exploration expenses		19.7		20.3		13.5		—	(.3	)	57.9		—		111.1
Selling and general expenses		5.4		3.5		.1		.8	—		6.3		.2		16.3
Results of operations before taxes		(14.3	)	(.6	)	198.9		6.4	.3		(64.2	)	1.7		128.2
Income tax provisions (benefits)		(7.0	)	2.0		81.4		3.0	—		—		(1.5	)	77.9
Results of operations (excluding corporate overhead and interest)	$	(7.3	)	(2.6	)	117.5		3.4	.3		(64.2	)	3.2		50.3

* Reclassified to conform to current presentation.

21

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

Results of Operations (Contd.)

Refining and Marketing

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

	Income (Loss)
	Three Months Ended March 31,
	2010		2009
Refining and marketing
United States
Manufacturing	(23.6	)	8.3
Marketing	8.9		6.3
Total – United States	(14.7	)	14.6
United Kingdom	(15.0	)	(3.8	)
Total	(29.7	)	10.8

United States manufacturing operations generated a loss of $23.6 million in the 2010 first quarter compared to earnings of $8.3 million during the first quarter of 2009. The unfavorable result in 2010 was primarily due to very weak U.S. refining margins and a six-week complete plant turnaround at the Meraux refinery in the just completed quarter. The WTI Gulf Coast 2-1-1 crack spread was about $3.00 per barrel lower in the first quarter of 2010 than in the same period in 2009. An ethanol production facility in Hankinson, North Dakota, that was acquired in October 2009, was profitable in the first quarter 2010.

United States marketing operations generated income of $8.9 million in the three months ended March 31, 2010, compared to income of $6.3 million in the 2009 period. The improved results in the 2010 quarter were mostly due to retail marketing margins in the U.S. which increased by about $0.03 per gallon compared to the same period in 2009. This improvement in retail margins in 2010 was somewhat tempered by tighter wholesale product margins in the current period. Although overall sales volumes at the U.S. retail stations in 2010 were about flat with 2009, sales volumes per store month were lower by about 2% compared to the prior year.

Refining and marketing operations in the United Kingdom had a loss of $15.0 million in the first quarter of 2010 compared to a loss of $3.8 million in the same quarter of 2009. Results in the U.K. in 2010 were hurt by a decrease in demand for refined products primarily related to severe winter storms early in the 2010 quarter, which led to very weak refining margins, especially early in the quarter. Additionally, the Milford Haven refinery was shut down for turnaround during March 2010 and is expected to restart in early May. A capital project being completed during the turnaround will expand the crude oil throughput capacity of the refinery from 108,000 to 130,000 barrels per day.

Worldwide refinery inputs were 169,600 barrels per day in the first quarter of 2010 compared to 235,274 barrels per day in the 2009 quarter. The decline in refinery inputs in 2010 was primarily due to turnarounds at the Meraux and Milford Haven plants during the quarter. Petroleum product sales were 478,692 barrels per day in the 2010 quarter, down from 503,878 barrels per day a year ago. This reduction was also mostly due to the aforementioned refinery turnarounds at Meraux and Milford Haven.

22

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

Results of Operations (Contd.)

Refining and Marketing (Contd.)

Selected operating statistics for the three-month periods ended March 31, 2010 and 2009 follow.

	Three Months Ended March 31,
	2010			2009
Refinery inputs – barrels per day		169,600			235,274
United States		102,822			136,719
Crude oil – Meraux, Louisiana		66,777			99,799
– Superior, Wisconsin		31,868			31,549
Other feedstocks		4,177			5,371
United Kingdom		66,778			98,555
Crude oil – Milford Haven, Wales		61,042			97,129
Other feedstocks		5,736			1,426
Refinery yields – barrels per day		169,600			235,274
United States		102,822			136,719
Gasoline		43,677			55,916
Kerosine		7,469			13,239
Diesel and home heating oils		25,282			37,501
Residuals		13,918			15,735
Asphalt, LPG and other		11,336			13,035
Fuel and loss		1,140			1,293
United Kingdom		66,778			98,555
Gasoline		18,281			22,838
Kerosine		9,819			12,313
Diesel and home heating oils		18,279			33,859
Residuals		7,180			8,149
Asphalt, LPG and other		10,735			17,009
Fuel and loss		2,484			4,387
Petroleum products sold – barrels per day		478,692			503,878
Total United States		410,674			406,243
United States Manufacturing		99,883			126,634
Gasoline		50,770			55,917
Kerosine		7,469			13,239
Diesel and home heating oils		25,282			37,501
Residuals		13,356			15,601
Asphalt, LPG and other		3,006			4,376
United States Marketing		394,310			386,263
Gasoline		316,588			312,412
Kerosine		7,183			15,207
Diesel and other		70,539			58,644
United States Intercompany Elimination		(83,519	)		(106,654	)
Gasoline		(50,768	)		(55,913	)
Kerosine		(7,469	)		(13,240	)
Diesel and other		(25,282	)		(37,501	)
United Kingdom		68,018			97,635
Gasoline		16,943			27,515
Kerosine		9,882			10,767
Diesel and home heating oils		21,697			34,876
Residuals		8,276			7,575
LPG and other		11,220			16,902
Unit margins per barrel:
United States refining1		(4.23	)		1.09
United Kingdom refining and marketing		(3.23	)		0.08
United States retail marketing:
Fuel margin per gallon2	$	0.081		$	0.050
Gallons sold per store month		292,122			299,192
Merchandise sales revenue per store month	$	138,456		$	116,869
Merchandise margin as a percentage of merchandise sales		12.3	%		13.9	%
Store count at end of period (Company operated)		1,055			1,027

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.

23

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 $68.4 million in the 2010 first quarter compared to a net benefit of $10.1 million in the first quarter of 2009. The results for corporate activities were unfavorable in 2010 compared to 2009 primarily due to after-tax losses of $41.3 million in the 2010 quarter on transactions denominated in foreign currencies compared to an after-tax profit of $26.1 million in the 2009 quarter. The foreign exchange loss in 2010 was primarily associated with a stronger U.S. dollar compared to the British sterling and a weaker dollar compared to the Malaysian ringgit. The weaker British sterling in 2010 led to foreign currency losses on dollar based liabilities in the sterling functional U.K. downstream operations, and the stronger Malaysian ringgit led to foreign currency losses on ringgit based income tax liabilities in the dollar functional Malaysian oil and gas operations. The foreign exchange benefit in 2009 mostly related to a stronger U.S. dollar versus the Malaysian ringgit, which led to currency gains for Malaysian income tax liabilities to be paid in the local currency. Higher net interest expense in the 2010 quarter compared to 2009 was attributable to a combination of higher average debt levels and lower amounts of interest capitalized to ongoing oil and gas development projects.

Financial Condition

Net cash provided by operating activities was $829.4 million for the first three months of 2010 compared to $380.0 million during the same period in 2009. Changes in operating working capital other than cash and cash equivalents generated cash of $244.3 million in the first quarter of 2010 and $45.0 million in the first quarter of 2009. The cash generated in the 2010 quarter from working capital changes essentially related to a $244.4 million recovery of U.S. federal royalties paid in prior years. Cash of $513.6 million and $406.5 million in the 2010 and 2009 quarters, respectively, 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 $47.8 million in 2010 and $47.6 million in 2009, and for property additions and dry holes, which, including amounts expensed, were $481.0 million and $511.4 million in the three month periods ended March 31, 2010 and 2009, respectively. Additionally, cash of $630.2 million and $599.8 million was used to purchase Canadian government securities with maturity dates greater than 90 days during the three months ended March 31, 2010 and 2009, respectively. The Company expended $50.5 million in the first three months of 2010 on major repairs, up from $7.4 million in the 2009 period, with the increase due to planned major turnarounds at the Meraux, Louisiana and Milford Haven, Wales refineries during the 2010 period. Total capital expenditures for continuing operations on an accrual basis were as follows:

	Three Months Ended March 31,
(Millions of dollars)	2010		2009
Capital expenditures – continuing operations
Exploration and production	$	442.2	430.9
Refining and marketing		80.8	48.6
Corporate and other		1.7	1.2
Total capital expenditures – continuing operations	$	524.7	480.7

Working capital (total current assets less total current liabilities) at March 31, 2010 was $1,034.6 million, down $159.5 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 $566.3 million below fair value at March 31, 2010.

At March 31, 2010, total long-term debt of $1,231.2 million had decreased by $122.0 million compared to December 31, 2009. A summary of capital employed at March 31, 2010 and December 31, 2009 follows.

	March 31, 2010			Dec. 31, 2009
(Millions of dollars)	Amount		%	Amount		%
Capital employed
Long-term debt	$	1,231.2	14.0		1,353.2	15.6
Stockholders’ equity		7,553.6	86.0		7,346.0	84.4
Total capital employed	$	8,784.8	100.0	$	8,699.2	100.0

The Company’s ratio of earnings to fixed charges was 14.0 to 1 for the three-month period ended March 31, 2010.

24

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

Accounting and Other Matters

The Company adopted new guidance issued by the Financial Accounting Standards Board (FASB) regarding accounting for transfers of financial assets effective January 1, 2010. This guidance makes the concept of a qualifying special-purpose entity as defined previously no longer relevant for accounting purposes. Therefore, formerly qualifying special-purpose entities must be reevaluated for consolidation by reporting entities in accordance with the applicable consolidation guidance. This adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted, effective January 1, 2010, new guidance issued by the FASB that requires a company to perform an analysis to determine whether its variable interests give it a controlling financial interest in a variable interest entity. The primary beneficiary of a variable interest entity has both the power to direct the activities of the entity that most significantly impact the entity’s economic performance and the obligation to absorb potentially significant losses of the entity or the right to receive potentially significant benefits from the entity. A company is required to make ongoing reassessments of whether it is the primary beneficiary of a variable interest entity. This guidance also amends previous guidance for determining whether an entity is considered a variable interest entity. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted new accounting guidance issued by the FASB for noncontrolling interests in consolidated financial statements effective January 1, 2009. This guidance was applied prospectively, except for presentation and disclosure requirements which are applied retrospectively. This guidance required noncontrolling interests to be reclassified as equity, and consolidated net income and comprehensive income shall include the respective results attributable to noncontrolling interests. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

The Company adopted new accounting guidance covering business combinations effective January 1, 2009. The new guidance established principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquired business. It also established how to recognize and measure goodwill acquired in the business combination or a gain from a bargain purchase, if applicable. This guidance impacts the recognition and measurement of assets and liabilities in business combinations that occur beginning in 2009. Assets and liabilities that arose from business combinations that occurred prior to 2009 are not affected by this guidance. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements. The Company is unable to predict how the application of this guidance will affect its financial statements in future periods.

The Company adopted new accounting guidance which addresses disclosures about derivative instruments and hedging activities in January 2009. This guidance expands required disclosures regarding derivative instruments to include qualitative information about objectives and strategies for using derivatives, quantities disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk related contingent features in derivative agreements.

In 2009, the Company adopted new accounting guidance for determining whether instruments granted in share-based payment transactions are participating securities. This guidance specifies that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings per share (EPS) calculation under the two-class method, and also requires that all prior-period EPS calculations be adjusted retrospectively. The adoption of this guidance did not have a significant impact on the Company’s prior-period EPS calculations.

The Company adopted new accounting guidance addressing certain equity method investment accounting considerations in January 2009, which has been applied prospectively. The guidance addresses how to initially measure contingent consideration for an equity method investment, how to recognize other-than-temporary impairments of an equity method investment, and how an equity method investor is to account for a share issuance by an investee. The adoption of this guidance did not have a significant impact on the Company’s consolidated financial statements.

The Company adopted new accounting guidance addressing subsequent events effective June 30, 2009. The guidance clarified the accounting for and disclosure of subsequent events that occur after the balance sheet date through the date of issuance of the applicable financial statements. The adoption of this guidance did not have a significant effect on the Company’s consolidated financial statements.

25

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

Accounting and Other Matters (Contd.)

The FASB’s Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles guidance became effective for interim and annual periods ended after September 15, 2009 (the third calendar quarter for Murphy Oil) and it recognized the FASB Accounting Standards Codification as the single source of authoritative nongovernment U.S. generally accepted accounting principles. The codification superseded all existing accounting standards documents issued by the FASB, and established that all other accounting literature not included in the codification is considered nonauthoritative. Although the codification does not change U.S. generally accepted accounting principles, it does reorganize the principles into accounting topics using a consistent structure. The codification also includes relevant U.S. Securities and Exchange Commission guidance following the same topical structure. For periods ending after September 15, 2009, all references to U.S. generally accepted accounting principles will use the new topical guidelines established with the codification. Otherwise, this new standard is not expected to have a material impact on the Company’s consolidated financial statements in future periods.

The FASB has provided additional guidance regarding disclosures about postretirement benefit plan assets, including how asset investment allocation decisions are made, the fair value of each major category of plan assets, and how fair value is determined for each major asset category. This guidance was effective for the Company as of December 31, 2009. Upon adoption, no comparative disclosures were required for earlier years presented.

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

• A revised definition of proved reserves, including the use of unweighted average oil and natural gas prices in effect at the beginning of each month during the year to compute such reserves,

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

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

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

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

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

The Company utilized this new guidance at year-end 2009 to determine its proved reserves and to develop associated disclosures. The Company has thus far chosen not to provide voluntary disclosures of probable and possible reserves in its filings with the Securities and Exchange Commission.

Outlook

Average crude oil prices in April 2010 rose slightly compared to the average price during the first quarter 2009. The Company expects its oil and natural gas production to average about 188,000 barrels of oil equivalent per day in the second quarter 2010, while sales volumes are expected to be approximately 184,000 barrels of oil equivalent per day during the quarter. Production volumes are projected to be lower in the second quarter 2010 than in the first quarter primarily in Malaysia due to a mechanical issue at a third party operated LNG facility that will reduce Sarawak gas sales and due to well intervention work on a subsea oil producing well that will reduce oil production at the Kikeh field. The Company still anticipates total production volumes of 200,000 barrels of oil equivalent per day for the full year 2010. U.S. downstream margins in April 2010 have shown some improvement compared to the first quarter. The Milford Haven, Wales refinery will start back up in early May following an extensive turnaround. The Company currently anticipates total capital expenditures for the full year 2010 to be approximately $2.5 billion.

26

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

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 G to this Form 10-Q report, Murphy periodically makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

There were short-term derivative foreign exchange contracts in place at March 31, 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 increased the recorded liability associated with these contracts by approximately $6.2 million, while a 10% weakening of the U.S. dollar would have reduced the recorded liability by approximately $5.0 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 March 31, 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

27

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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 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

In April 2010, a drilling accident and subsequent oil spill occurred in the Gulf or Mexico at a property owned by other companies. At the present time, the Company is uncertain how the accident and oil spill will affect its U.S. and worldwide operations. The impacts could include a disruption of operations at the Meraux, Louisiana, refinery and further regulations and/or restrictions covering offshore drilling operations.

See additional risk factors previously disclosed in the Company’s Form 10-K filed on February 26, 2010.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) The Exhibit Index on page 30 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

(b) A report on Form 8-K was filed on January 27, 2010 that included a News Release announcing the Company’s earnings and certain other financial information for the three-month and twelve-month periods ended December 31, 2009.

(c) A report on Form 8-K was filed on February 4, 2010 that included amended By-Laws that changed the number of directors from eleven to ten effective May 12, 2010.

28

SIGNATURE

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

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

May 7, 2010

      (Date)

29

EXHIBIT INDEX

Exhibit No.
12.1*	Computation of Ratio of Earnings to Fixed Charges
31.1*	Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101	Interactive Data Files

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

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

Exhibits other than those listed above have been omitted since they are either not required or not applicable.

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