Edgar Filing: MURPHY OIL CORP /DE

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

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

For the quarterly period ended March 31, 2012

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

For the transition period from to

Commission File Number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		71-0361522
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

200 Peach Street P.O. Box 7000, El Dorado, Arkansas		71731-7000
(Address of principal executive offices)		(Zip Code)

(870) 862-6411

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). þ Yes ¨ No

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

¨ Yes þ No

Number of shares of Common Stock, $1.00 par value, outstanding at March 31, 2012 was 194,167,569.

MURPHY OIL CORPORATION

TABLE OF CONTENTS


	Page
Part I – Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets		2
Consolidated Statements of Income		3
Consolidated Statements of Comprehensive Income		4
Consolidated Statements of Cash Flows		5
Consolidated Statements of Stockholders’ Equity		6
Notes to Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Results of Operations and Financial Condition		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		28

Signature		29

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Thousands of dollars)


	(Unaudited) March 31, 2012			December 31, 2011
ASSETS
Current assets
Cash and cash equivalents	$	936,649			513,873
Canadian government securities with maturities greater than 90 days at the date of acquisition		494,352			532,093
Accounts receivable, less allowance for doubtful accounts of $7,813 in 2012 and $7,892 in 2011		1,485,059			1,554,184
Inventories, at lower of cost or market
Crude oil		243,600			189,320
Finished products		190,149			254,880
Materials and supplies		227,927			222,438
Prepaid expenses		144,905			93,397
Deferred income taxes		81,962			87,486

Total current assets		3,804,603			3,447,671
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $7,267,611 in 2012 and $6,861,494 in 2011		10,922,959			10,475,149
Goodwill		42,820			41,863
Deferred charges and other assets		166,566			173,455

Total assets	$	14,936,948			14,138,138

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	350,034			350,005
Accounts payable and accrued liabilities		2,650,907			2,273,139
Income taxes payable		244,948			201,784

Total current liabilities		3,245,889			2,824,928
Long-term debt		249,565			249,553
Deferred income taxes		1,282,338			1,230,111
Asset retirement obligations		613,538			615,545
Deferred credits and other liabilities		426,535			439,604
Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued		0			0
Common Stock, par $1.00, authorized 450,000,000 shares, issued 194,345,426 shares in 2012 and 193,909,200 shares in 2011		194,345			193,909
Capital in excess of par value		833,381			817,974
Retained earnings		7,697,630			7,460,942
Accumulated other comprehensive income		398,363			310,420
Treasury stock, 177,857 shares of Common Stock in 2012 and 185,992 shares of Common Stock in 2011, at cost		(4,636	)		(4,848	)

Total stockholders’ equity		9,119,083			8,778,397

Total liabilities and stockholders’ equity	$	14,936,948			14,138,138

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page 30.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars, except per share amounts)


	Three Months Ended March 31,
	2012			2011*
REVENUES
Sales and other operating revenues	$	6,991,356			6,266,009
Gain on sale of assets		90			53
Interest and other income		3,073			5,611

Total revenues		6,994,519			6,271,673


COSTS AND EXPENSES
Crude oil and product purchases		5,514,379			4,956,376
Operating expenses		493,861			464,760
Exploration expenses, including undeveloped lease amortization		53,015			96,274
Selling and general expenses		89,187			69,661
Depreciation, depletion and amortization		340,374			263,747
Accretion of asset retirement obligations		9,778			9,487
Redetermination of Terra Nova working interest		0			(5,351	)
Interest expense		11,739			11,719
Interest capitalized		(6,423	)		(6,433	)

Total costs and expenses		6,505,910			5,860,240

Income from continuing operations before income taxes		488,609			411,433
Income tax expense		198,538			172,991

Income from continuing operations		290,071			238,442
Income from discontinued operations, net of taxes		0			30,461

NET INCOME	$	290,071			268,903


NET INCOME PER COMMON – BASIC
Income from continuing operations	$	1.50			1.23
Income from discontinued operations		0.00			0.16

Net income	$	1.50			1.39


NET INCOME PER COMMON – DILUTED
Income from continuing operations	$	1.49			1.22
Income from discontinued operations		0.00			0.16

Net income	$	1.49			1.38

Average Common shares outstanding
Basic		193,922,260			193,092,509
Diluted		194,884,733			194,597,368

*	Reclassified to conform to current presentation.

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (unaudited)

(Thousands of dollars)


	Three Months Ended March 31,
	2012		2011
Net income	$	290,071		268,903

Other comprehensive income, net of income taxes
Net gain from foreign currency translation		82,252		99,654
Retirement and postretirement benefit plan amounts reclassified to net income		2,708		2,157
Reduction of deferred loss on interest rate hedges		2,983		0


COMPREHENSIVE INCOME	$	378,014		370,714

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)


	Three Months Ended March 31,
	2012			2011¹
OPERATING ACTIVITIES
Net income	$	290,071			268,903
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations		0			(30,461	)
Depreciation, depletion and amortization		340,374			263,747
Amortization of deferred major repair costs		5,911			5,683
Expenditures for asset retirements		(6,957	)		(6,479	)
Dry hole costs		620			35,804
Amortization of undeveloped leases		28,632			29,387
Accretion of asset retirement obligations		9,778			9,487
Deferred and noncurrent income tax charges		7,510			813
Pretax gain from disposition of assets		(90	)		(53	)
Net decrease (increase) in noncash operating working capital		298,334			(140,422	)
Other operating activities, net		16,823			38,554

Net cash provided by continuing operations		991,006			474,963
Net cash provided by discontinued operations		0			47,937

Net cash provided by operating activities		991,006			522,900


INVESTING ACTIVITIES
Property additions and dry hole costs		(567,264	)		(508,880	)
Proceeds from sale of assets		123			76
Purchases of investment securities²		(469,564	)		(428,253	)
Proceeds from maturity of investment securities²		507,305			587,795
Expenditures for major repairs		0			(32	)
Investing activities of discontinued operations		0			(15,471	)
Other – net		3,889			2,230

Net cash required by investing activities		(525,511	)		(362,535	)


FINANCING ACTIVITIES
Borrowing (repayment) of notes payable		(11	)		34,990
Proceeds from exercise of stock options and employee stock purchase plans		6,599			6,816
Excess tax benefits related to exercise of stock options		1,037			4,253
Withholding tax on stock-based incentive awards		(5,501	)		(8,014	)
Cash dividends paid		(53,383	)		(53,104	)

Net cash required by financing activities		(51,259	)		(15,059	)

Effect of exchange rate changes on cash and cash equivalents		8,540			8,288

Net increase in cash and cash equivalents		422,776			153,594
Cash and cash equivalents at January 1		513,873			535,825

Cash and cash equivalents at March 31	$	936,649			689,419

¹	Reclassified to conform to current presentation.

²	Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)


	Three Months Ended March 31,
	2012			2011
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued		0			0


Common Stock – par $1.00, authorized 450,000,000 shares, issued 194,345,426 shares at March 31, 2012 and 193,636,851 shares at March 31, 2011
Balance at beginning of period	$	193,909			193,294
Exercise of stock options		212			343
Awarded restricted stock		224			0

Balance at end of period		194,345			193,637


Capital in Excess of Par Value
Balance at beginning of period		817,974			767,762
Exercise of stock options, including income tax benefits		7,976			11,910
Restricted stock transactions and other		(5,501	)		(15,119	)
Stock-based compensation		12,932			10,137
Sale of stock under employee stock purchase plans		0			367

Balance at end of period		833,381			775,057


Retained Earnings
Balance at beginning of period		7,460,942			6,800,992
Net income for the period		290,071			268,903
Cash dividends		(53,383	)		(53,104	)

Balance at end of period		7,697,630			7,016,791


Accumulated Other Comprehensive Income
Balance at beginning of period		310,420			449,428
Foreign currency translation gains, net of income taxes		82,252			99,654
Retirement and postretirement benefit plan adjustments, net of income taxes		2,708			2,157
Reduction of deferred loss on interest rate hedges, net of income taxes		2,983			0

Balance at end of period		398,363			551,239


Treasury Stock
Balance at beginning of period		(4,848	)		(11,926	)
Sale of stock under employee stock purchase plans		212			231
Awarded restricted stock		0			6,208

Balance at end of period		(4,636	)		(5,487	)


Total Stockholders’ Equity	$	9,119,083			8,531,237

See notes to consolidated financial statements, page 7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

These notes are an integral part of the financial statements of Murphy Oil Corporation and Consolidated Subsidiaries (Murphy/the Company) on pages 2 through 6 of this Form 10-Q report.

Note A – Interim Financial Statements

The consolidated financial statements of the Company presented herein have not been audited by independent auditors, except for the Consolidated Balance Sheet at December 31, 2011. 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, 2012, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended March 31, 2012 and 2011, 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 2011 Form 10-K and Form 10-K/A reports, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month period ended March 31, 2012 are not necessarily indicative of future results.

Note B – Property, Plant and Equipment

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

At March 31, 2012, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $563.5 million. The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2012 and 2011.


(Thousands of dollars)	2012			2011
Beginning balance at January 1	$	556,412			497,765
Additions pending the determination of proved reserves		49,524			2,920
Reclassifications to proved properties based on the determination of proved reserves		(42,431	)		0

Balance at March 31	$	563,505			500,685

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
	2012						2011
(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	$	109,907		29		5		132,540		17		4
One to two years		141,441		16		4		119,789		12		4
Two to three years		55,922		9		2		33,289		4		2
Three years or more		256,235		35		5		215,067		32		5

	$	563,505		89		16		500,685		65		15

Of the $453.6 million of exploratory well costs capitalized more than one year at March 31, 2012, $264.3 million is in Malaysia, $134.6 million is in the U.S., $29.3 million is in Republic of the Congo, and $25.4 million is in Canada. In Malaysia either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. In the U.S. drilling and development operations are planned. In Republic of the Congo further appraisal drilling is planned. In Canada a drilling and development program continues.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Inventories

Inventories are carried at the lower of cost or market. The cost of crude oil and finished products is predominantly determined on the last-in, first-out (LIFO) method. At March 31, 2012 and December 31, 2011, the carrying values of inventories under the LIFO method were $713.1 million and $580.2 million, respectively, less than such inventories would have been valued using the first-in, first-out (FIFO) method.

Note D – Discontinued Operations

In 2010, the Company announced that its Board of Directors had approved plans to exit the U.S. refining and U.K. refining and marketing businesses. On September 30, 2011, the Company sold the Superior, Wisconsin refinery and related assets for $214 million, plus certain capital expenditures between July 25 and the date of closing and the fair value of all associated hydrocarbon inventories at these locations. On October 1, 2011, the Company sold the Meraux, Louisiana refinery and related assets for $325 million, plus the fair value of associated hydrocarbon inventories. The Company has accounted for operating results of the Superior, Wisconsin and Meraux, Louisiana refineries and associated marketing assets as discontinued operations, and all prior periods presented have been reclassified to conform to this presentation. The cash proceeds from these refinery sales were used to pay down outstanding loans under existing revolving credit facilities in 2011.

The results of operations associated with these discontinued operations for the three-month period ended March 31, 2011 were as follows:


(Thousands of dollars)	2011
Revenues	$	1,079,994
Income before income taxes		48,931
Income tax expense		18,470

The Company continues to offer for sale its U.K. refinery at Milford Haven, Wales and all U.K. product terminals and motor fuel stations. Based on current market conditions, it is possible that the Company could incur a loss on future sales of the U.K. downstream assets. Through March 31, 2012, the Company has accounted for U.K. downstream results as a component of continuing operations. If the sale of the U.K. assets continues to progress, the Company expects that the results of these operations to be sold will be presented as discontinued operations in future periods when the criteria for held for sale under U.S. generally accepted accounting principles have been met.

Note E – Financing Arrangements

The Company has a $1.5 billion committed credit facility that expires in June 2016. Borrowings under the facility bear interest at 1.5% above LIBOR based on the Company’s current credit rating as of March 31, 2012. Facility fees are due at varying rates on the commitment. The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through September 2012.

Ten year notes totaling $350 million, which matured on May 1, 2012, have been classified as Current maturities of long-term debt as of March 31, 2012. The notes were repaid using $350 million of borrowings from other existing credit facilities. The Company anticipates selling approximately $500 million of new ten-year notes during the second quarter 2012. If successful with this sale offering, the proceeds would be used to repay the borrowings incurred on May 1 under other credit facilities and for general corporate purposes.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Cash Flow Disclosures

Additional disclosures regarding cash flow activities are provided below.


	Three Months Ended March 31,
(Thousands of dollars)	2012			2011
Net (increase) decrease in operating working capital other than cash and cash equivalents:
(Increase) decrease in accounts receivable	$	69,126			(391,217	)
(Increase) decrease in inventories		4,962			12,032
(Increase) decrease in prepaid expenses		(51,508	)		(2,146	)
(Increase) decrease in deferred income tax assets		5,522			4,586
Increase (decrease) in accounts payable and accrued liabilities		227,067			236,926
Increase (decrease) in current income tax liabilities		43,165			(603	)

Total	$	298,334			(140,422	)

Supplementary disclosures:
Cash income taxes paid	$	160,210			147,547
Interest paid more (less) than amounts capitalized		490			(4,921	)

Note G – 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. In conjunction with the sale of the Superior, Wisconsin refinery in September 2011, the purchaser assumed the obligations associated with the defined benefit pension plan covering the refinery’s union employees. In conjunction with the sale of the Meraux refinery in October 2011, all benefits associated with the defined pension and other postretirement benefit plans were frozen.

The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2012 and 2011.


	Three Months Ended March 31,
	Pension Benefits						Other Postretirement Benefits
(Thousands of dollars)	2012			2011			2012			2011
Service cost	$	5,888			5,896			1,041			1,224
Interest cost		7,292			7,993			1,449			1,647
Expected return on plan assets		(6,305	)		(6,925	)		0			0
Amortization of prior service cost		312			344			(46	)		(64	)
Amortization of transitional (asset) liability		111			(51	)		2			2
Recognized actuarial net loss		3,767			2,576			489			753

Net periodic benefit expense	$	11,065			9,833			2,935			3,562

During the three-month period ended March 31, 2012, the Company made contributions of $19.6 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2012 for the Company’s defined benefit pension and postretirement plans is anticipated to be $25.8 million.

In March 2010, the United States Congress 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) eliminated lifetime or annual coverage limits and required coverage for preventative health services beginning in September 2010; and (d) imposed 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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

significantly affect the Company’s consolidated financial statements as of March 31, 2012 and 2011 and for the three-month periods then ended. The Company continues to evaluate the various components of the law as further guidance is issued and cannot predict with certainty 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 H – Incentive Plans

The costs resulting from all share-based payment transactions are recognized in the Consolidated Statements of Income using a fair value-based measurement method over the periods that the awards vest.

The 2007 Annual Incentive Plan (2007 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and other key employees. Cash awards under the 2007 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. The 2007 Long-Term Incentive Plan (2007 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units, performance units, performance shares, dividend equivalents and other stock-based incentives. The 2007 Long-Term Plan expires in 2017. A total of 6,700,000 shares are issuable during the life of the 2007 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding. The Company has an Employee Stock Purchase Plan that permits the issuance of up to 980,000 shares through September 30, 2017. The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors. At the Company’s annual stockholders’ meeting to be held on May 9, 2012, it is asking shareholders to approve replacement of the 2007 Annual Plan and the 2007 Long-Term Plan with the 2012 Annual Incentive Plan and 2012 Long-Term Incentive Plan, respectively. The new proposed plans can be found in the Company’s Definitive proxy statement (Definitive 14A) dated March 29, 2012.

On January 31, 2012, the Committee granted stock options for 1,643,000 shares at an exercise price of $59.655 per share. The Black-Scholes valuation for these awards was $17.74 per option. The Committee also granted 653,356 performance-based restricted stock units on that date under the 2007 Long-Term Plan. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, ranged from $54.90 to $63.64 per unit. On February 1, 2012, the Committee granted 40,260 shares of time-based restricted stock units to the Company’s Directors under the 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 $59.33 per share.

Cash received from options exercised under all share-based payment arrangements for the three-month periods ended March 31, 2012 and 2011 was $6.6 million and $6.8 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $2.0 million and $6.0 million for the three-month periods ended March 31, 2012 and 2011, respectively.

Amounts recognized in the Consolidated Statements of Income with respect to share-based plans are as follows:


	Three Months Ended March 31
(Thousands of dollars)	2012		2011
Compensation charged against income before tax benefit	$	13,042		10,226
Related income tax benefit recognized in income		3,978		2,989

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – 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, 2012 and 2011. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended March 31
(Weighted-average shares)	2012		2011
Basic method		193,922,260		193,092,509
Dilutive stock options and restricted stock units		962,473		1,504,859

Diluted method		194,884,733		194,597,368

Certain options to purchase shares of common stock were outstanding during the 2012 and 2011 periods but were not included in the computation of diluted EPS because the incremental shares from assumed conversion were antidilutive. These included 2,834,487 shares at a weighted average share price of $66.51 in the 2012 period and 697,994 shares at a weighted average share price of $67.64 in the 2011 period.

Note J – Income Taxes

The Company’s effective income tax rate generally exceeds the U.S. Federal statutory tax rate of 35.0%. The effective tax rate is calculated as the amount of income tax expense divided by income before income tax expense. For the three-month periods in 2012 and 2011, the Company’s effective income tax rates were as follows:


	2012			2011
Three months ended March 31		40.6	%		42.0	%

The effective tax rates for the periods presented exceeded the U.S. Federal tax rate of 35.0% due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have tax rates that are higher than the U.S. Federal rate; U.S. state tax expense; and certain expenses, including exploration and other expenses in certain foreign jurisdictions, for which no income tax benefits are available or are not presently being recorded due to a lack of reasonable certainty of adequate future revenue against which to utilize these expenses as deductions.

The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. As of March 31, 2012, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2008; Canada – 2007; United Kingdom – 2010; and Malaysia – 2006.

Note K – Financial Instruments and Derivatives

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. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Income. Certain interest rate derivative contracts are accounted for as hedges and the gain or loss associated with recording the fair value of these contracts has been deferred in Accumulated Other Comprehensive Income until the anticipated transactions occur.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Financial Instruments and Derivatives (Contd.)

Commodity Purchase Price Risks

The Company is subject to commodity price risk related to corn that it will purchase in the future for feedstock and to wet and dried distillers grain that it will sell in the future at its ethanol production facilities in the United States. At March 31, 2012 and 2011, the Company had open physical delivery fixed-price commitment contracts for purchase of approximately 11.7 million and 7.6 million bushels of corn, respectively, for processing at its ethanol plants. The Company also had outstanding derivative contracts to sell a similar volume of these fixed-price quantities and buy them back at future prices in effect on the expected date of delivery under the purchase commitment contracts. Also, at March 31, 2012, the Company had open physical delivery fixed-price commitment contracts for sale of approximately 0.9 million equivalent bushels of wet and dried distillers grain with outstanding derivative contracts to purchase a similar volume of these fixed-price quantities and sell them back at future prices in effect on the expected date of delivery under the sale commitment contracts. The impact of marking to market these commodity derivative contracts reduced income before taxes by $0.1 million in the three-month period ended March 31, 2012 and increased income before taxes by $1.8 million in the three-month period ended March 31, 2011.

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the United States. Short-term derivative instruments were outstanding at March 31, 2012 and 2011 to manage the risk of certain future income taxes that are payable in Malaysian ringgits. The equivalent U.S. dollars of Malaysian ringgit derivative contracts open at March 31, 2012 and 2011 were approximately $373.6 million and $405.0 million, respectively. Short-term derivative instrument contracts totaling $46.0 million and $27.0 million U.S. dollars were also outstanding at March 31, 2012 and 2011, respectively, to manage the risk of certain U.S. dollar accounts receivable associated with sale of crude oil production in Canada. The impact from marking to market these foreign currency derivative contracts increased income before taxes by $6.6 million and $12.4 million for the three-month periods ended March 31, 2012 and 2011, respectively.

At March 31, 2012 and December 31, 2011, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

March 31, 2012

December 31, 2011

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity

Accounts receivable

219

Accounts receivable

197

Commodity

Accounts payable

(286

)

Accounts payable

(489

)

Foreign currency

Accounts receivable

6,550

Accounts payable

(8,459

)

For the three-month periods ended March 31, 2012 and 2011, the gains and losses recognized in the consolidated statements of income for derivative instruments not designated as hedging instruments are presented in the following table.


		Gain (Loss)
(Thousands of dollars)	Statement of Income Location	Three Months Ended March 31,
Type of Derivative Contract	Statement of Income Location	2012		2011
Commodity	Crude oil and product purchases	$	645		(14,433	)
Foreign currency	Interest and other income		17,515		9,527

		$	18,160		(4,906	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Financial Instruments and Derivatives (Contd.)

Interest Rate Risks

The Company has ten-year notes totaling $350 million that matured on May 1, 2012. The Company currently anticipates replacing these notes soon after maturity with new ten-year notes, and it therefore has risk related to the interest rate associated with the anticipated sale of these notes in the second quarter of 2012. To manage this risk, in 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps that mature in May 2012. The Company utilizes hedge accounting to defer any gain or loss on these contracts until the payment of interest on these anticipated notes occurs. There was no impact in the 2012 and 2011 Consolidated Statements of Income associated with accounting for these interest rate derivative contracts.

At March 31, 2012 and December 31, 2011, the fair value of these interest rate derivative contracts, which have been designated as hedging instruments for accounting purposes, are presented in the following table.

March 31, 2012

December 31, 2011

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Interest rate

Accounts Payable

(21,337

)

Accounts Payable

(25,927

)

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

The carrying value of assets and liabilities recorded at fair value on a recurring basis at March 31, 2012 and December 31, 2011 are presented in the following table.


	March 31, 2012											December 31, 2011
(Thousands of dollars)	Level 1			Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total
Assets
Foreign currency exchange derivative contracts	$	0			6,550			0		6,550			0			0			0		0
Commodity derivative contracts		0			219			0		219			0			197			0		197

	$	0			6,769			0		6,769			0			197			0		197

Liabilities
Nonqualified employee savings plans	$	(8,803	)		0			0		(8,803	)		(8,030	)		0			0		(8,030	)
Foreign currency exchange derivative contracts		0			0			0		0			0			(8,459	)		0		(8,459	)
Commodity derivative contracts		0			(286	)		0		(286	)		0			(489	)		0		(489	)
Interest rate derivative contracts		0			(21,337	)		0		(21,337	)		0			(25,927	)		0		(25,927	)

	$	(8,803	)		(21,623	)		0		(30,426	)		(8,030	)		(34,875	)		0		(42,905	)

The fair value of commodity derivative contracts for corn and wet and dried distillers grain was determined based on market quotes for No. 2 yellow corn. The fair value of foreign exchange and interest rate derivative contracts was based on market quotes for similar contracts at the balance sheet date. The income effect of changes in fair value of commodity derivative contracts is recorded in Crude Oil and Product Purchases in the Consolidated Statements of Income and changes in fair value of foreign exchange derivative contracts is recorded in Interest and Other Income. There was no income effect for the change in fair value of interest rate derivative contracts. The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and General Expenses.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Accumulated Other Comprehensive Income

The components of Accumulated Other Comprehensive Income on the Consolidated Balance Sheets at March 31, 2012 and December 31, 2011 are presented net of taxes in the following table.


	March 31,			Dec. 31,
(Thousands of dollars)	2012			2011
Foreign currency translation gains, net of tax	$	578,413			496,161
Retirement and postretirement benefit plan losses, net of tax		(166,181	)		(168,889	)
Loss deferred for fair value of interest rate derivative contracts, net of tax		(13,869	)		(16,852	)

Accumulated other comprehensive income	$	398,363			310,420

Note M – Environmental and Other Contingencies

The Company’s operations and earnings have been and may be affected by various forms of governmental action both in the United States and throughout the world. Examples of such governmental action include, but are by no means limited to: tax increases and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. Because governmental actions are often motivated by political considerations and may be taken without full consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.

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

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup and the Company is investigating the extent of any such liability and the availability of applicable defenses. With the sale of the U.S. refineries in 2011, the Company retained certain liabilities related to environmental matters. The Company also has insurance covering certain levels of environmental exposures. The Company 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 U.S. Environmental Protection Agency (EPA) currently considers the Company to be a Potentially Responsible Party (PRP) at one Superfund site. 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note M – Environmental and Other Contingencies (Contd.)

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.

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, 2012, the Company had contingent liabilities of $324.3 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to these letters of credit because it is believed that the likelihood of having these drawn is remote.

Note N – Commitments

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2012 natural gas sales volumes in the Tupper area in Western Canada. The contracts call for natural gas deliveries of approximately 50 million cubic feet per day in 2012 at an average price of Cdn$4.43 per MCF, with the contracts calling for delivery at the AECO “C” sales point. These contracts have been accounted for as a normal sale for accounting purposes.

Note O – Terra Nova Working Interest Redetermination

The joint agreement between the owners of the Terra Nova field, offshore Eastern Canada, required a redetermination of working interests based on an analysis of reservoir quality among fault separated areas where varying ownership interests existed. Due to the redetermination process, the Company’s working interest at Terra Nova was reduced from its original 12.0% to 10.475% effective January 1, 2011. The Company made a cash settlement payment in the first quarter 2011 to certain Terra Nova partners for the value of oil sold since February 2005, net of adjustments for operating expenses and capital expenditures, related to the working interest reduction. The Company had recorded cumulative expense of $102.1 million through 2010 based on the working interest reduction. Based on the final settlement paid in 2011, the Company recorded a $5.4 million benefit in the first quarter of 2011 due to the ultimate cost of the redetermination settlement being less than originally estimated. The benefit has been reflected as Redetermination of Terra Nova Working Interest in the Consolidated Statement of Income for the three-month period ended March 31, 2011.

Note P – Accounting Matters

In September 2011, the Financial Accounting Standards Board (FASB) issued an accounting standards update that simplifies the annual goodwill impairment assessment process by permitting a company to assess whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount before applying the two-step goodwill impairment test. If a company concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying amount, the company would be required to conduct the current two-step goodwill impairment test. This change was effective for the Company for annual and interim goodwill impairment tests performed in 2012. The Company adopted the standard effective January 1, 2012 and the standard did not have a significant effect on its 2012 consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Accounting Matters (Contd.)

separate statement following the statement of income. The adoption of this standard did not have a significant effect on the Company’s consolidated financial statements. In December 2011, the FASB deferred the requirement for reclassification adjustments from accumulated other comprehensive income to be measured and presented by line item in the Statement of Income.

In December 2011, the FASB issued an accounting standards update that will enhance disclosures about financial instruments and derivative instruments that are either offset in the balance sheet or are subject to an enforceable master netting arrangement or similar agreement. The guidance will be effective for all interim and annual periods beginning on or after January 1, 2013. The Company does not expect this new guidance to have a significant effect on its consolidated financial statements.

Note Q – Business Segments


(Millions of dollars)	Total Assets		Three Mos. Ended March 31, 2012							Three Mos. Ended March 31, 2011
(Millions of dollars)	at March 31, 2012		External Revenues		Interseg. Revenues		Income (Loss)			External Revenues		Interseg. Revenues		Income (Loss)
Exploration and production*
United States	$	2,090.0		221.1		0		50.8			168.2		0		16.5
Canada		3,865.3		307.0		0		73.3			246.1		40.2		86.4
Malaysia		3,935.2		563.9		0		224.0			517.5		0		195.8
United Kingdom		199.2		37.6		0		8.7			30.2		0		9.0
Republic of the Congo		233.8		57.6		0		1.6			34.6		0		3.6
Other		74.8		0		0		(36.8	)		1.3		0		(50.9	)

Total		10,398.3		1,187.2		0		321.6			997.9		40.2		260.4

Refining and marketing
United States		1,841.0		4,264.2		0		(7.2	)		3,963.1		0		9.0
United Kingdom		1,163.5		1,540.0		0		3.0			1,305.1		0		(8.7	)

Total		3,004.5		5,804.2		0		(4.2	)		5,268.2		0		0.3

Total operating segments		13,402.8		6,991.4		0		317.4			6,266.1		40.2		260.7
Corporate		1,534.1		3.1		0		(27.3	)		5.6		0		(22.3	)

Assets/revenue/income from continuing operations		14,936.9		6,994.5		0		290.1			6,271.7		40.2		238.4
Discontinued operations, net of tax		0		0		0		0			0		0		30.5

Total	$	14,936.9		6,994.5		0		290.1			6,271.7		40.2		268.9

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

In 2010, the Company announced its intention to sell its two U.S. refineries and its U.K. downstream operations during 2011. On September 30, 2011, the Company completed the sale of the Superior, Wisconsin refinery and associated marketing assets. On October 1, 2011, the Company completed the sale of the Meraux, Louisiana refinery and associated marketing assets. The results of operations for the Superior and Meraux refineries and associated marketing assets have been reported as discontinued operations, net of income taxes, for all periods presented in the Consolidated Statement of Income and in the segment table above. Due to the sale of the two U.S. refineries, Company management has reevaluated the reportable segments for the downstream business. Based on this reevaluation, the U.S. downstream is now being presented as one reportable segment while the two refineries that formerly comprised the majority of the former U.S. manufacturing segment are presented in the segment table as discontinued operations. The Company continues to actively market for sale the U.K. downstream assets and expects that the results of these operations to be sold will be presented as discontinued operations in future periods when the criteria for held for sale under U.S. generally accepted accounting principles have been met.

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 2012 was $290.1 million ($1.49 per diluted share) compared to net income of $268.9 million ($1.38 per diluted share) in the first quarter of 2011. The 2011 results included $30.5 million ($0.16 per diluted share) of income from discontinued operations. Excluding discontinued operations, income in the 2012 first quarter exceeded 2011 results by $51.7 million ($0.27 per diluted share). The income improvement in 2012 primarily related to higher sales prices for the Company’s crude oil production and lower exploration expenses.

Murphy’s income by type of business is presented below.


	Income (Loss)
	Three Months Ended March 31,
(Millions of dollars)	2012			2011
Exploration and production	$	321.6			260.4
Refining and marketing		(4.2	)		0.3
Corporate		(27.3	)		(22.3	)

Income from continuing operations		290.1			238.4
Discontinued operations		0			30.5

Net income	$	290.1			268.9

In the 2012 first quarter, the Company’s exploration and production operations earned $321.6 million compared to $260.4 million in the 2011 quarter. Income in the 2012 quarter was favorably impacted by higher crude oil sales prices and lower exploration expenses compared to the 2011 first quarter. However, crude oil sales volumes in 2012 were below 2011 levels and North American natural gas sale prices in 2012 were significantly weaker than in 2011. The Company’s refining and marketing continuing operations incurred a loss of $4.2 million in the 2012 first quarter compared to income of $0.3 million in the same quarter of 2011. The most significant reduction in downstream results arose in U.S. operations, which experienced weaker retail fuel marketing margins. Results for the U.K. downstream segment improved in 2012 due to stronger refining margins coupled with higher crude oil throughputs at the Milford Haven refinery compared to a year earlier. The corporate function had after-tax costs of $27.3 million in the 2012 first quarter compared to after-tax costs of $22.3 million in the 2011 period with the unfavorable variance in 2012 primarily due to higher administrative expenses and lower interest income.

Exploration and Production

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


	Income (Loss)
	Three Months Ended March 31,
(Millions of dollars)	2012			2011
Exploration and production
United States	$	50.8			16.5
Canada		73.3			86.4
Malaysia		224.0			195.8
United Kingdom		8.7			9.0
Republic of the Congo		1.6			3.6
Other International		(36.8	)		(50.9	)

Total	$	321.6			260.4

United States exploration and production operations had earnings of $50.8 million in the first quarter of 2012 compared to earnings of $16.5 million in the 2011 quarter. Earnings improved in the 2012 period primarily due to higher realized crude oil sales prices and higher oil production volumes in the latest period. The increase in production was achieved in the Eagle Ford Shale area of South Texas, where an ongoing development project is proceeding. At March 31, 2012, ten rigs were actively drilling in the Eagle Ford Shale on behalf of the Company. U.S. results in 2012 were unfavorably affected by both lower natural gas sales prices and lower natural gas sales volumes. Production and depreciation expenses increased $7.4 million and $14.5 million, respectively, in 2012

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

compared to 2011 mostly due to higher production in the Eagle Ford Shale. Exploration expenses in the 2012 quarter were $25.6 million below 2011 levels due to lower costs for seismic and leasehold amortization in the Eagle Ford Shale in the latest quarter. Selling and general expenses in the 2012 period increased $2.7 million from the prior year primarily due to higher costs for employee compensation and other professional services.

Operations in Canada had earnings of $73.3 million in the first quarter 2012 compared to earnings of $86.4 million in the 2011 quarter. Canadian earnings decreased in the 2012 quarter due to a combination of lower natural gas sales prices, lower oil sales volumes, and higher exploration expenses in 2012; additionally, a nonrecurring $5.4 million pretax benefit was recognized in 2011 for final settlement of the Terra Nova field working interest redetermination process. Oil production decreased in the 2012 period compared to 2011 primarily due to lower volumes at Syncrude caused by unplanned maintenance during the current quarter. Heavy oil production at Seal increased in 2012 due to new producing wells added in the current quarter. Natural gas sales volumes increased in 2012 due to a full quarter of production from the Tupper West area in the current year. Tupper West was on production only for a portion of the 2011 first quarter following its start-up in February of last year. Production and depreciation expenses for conventional oil operations in Canada were unfavorable in 2012 by $13.5 million and $24.4 million, respectively, due primarily to higher natural gas volumes produced at Tupper West. Production expenses at Syncrude in 2012 were $5.9 million less than 2011 primarily due to lower costs for energy and incentive compensation.

Operations in Malaysia reported earnings of $224.0 million in the 2012 quarter compared to earnings of $195.8 million during the same period in 2011. Earnings rose in 2012 in Malaysia from a combination of higher crude oil sales prices and higher natural gas sales prices and sales volumes from fields offshore Sarawak. The 2012 quarter was unfavorably affected by lower crude oil sales volumes at the Kikeh field. Production expense was lower in the 2012 period by $13.9 million primarily due to less well maintenance work and lower sales volumes at Kikeh. Depreciation expense was $16.9 million higher in the 2012 quarter due to a higher capital amortization unit rate partially offset by lower overall crude oil and natural gas sales volumes.

United Kingdom operations had income of $8.7 million in the 2012 quarter compared to earnings of $9.0 million in the 2011 quarter. The lower income was primarily due to higher income tax rates in 2012 versus 2011. A 12% tax rate increase was enacted in mid 2011 that raised the U.K. effective tax rate on oil and gas company profits from 50% to 62%. Pretax results in 2012 were $4.8 million more than in 2011 due to higher crude oil sales prices and higher crude oil sales volumes, partially offset by lower natural gas sales prices and lower natural gas sales volumes. Depreciation expense increased $3.2 million in 2012 compared to 2011 primarily due to higher depreciation rates in the current year at the Schiehallion field, where the production facility will be shuttered and replaced earlier than previously estimated.

Operations in Republic of the Congo had income of $1.6 million in the first quarter of 2012 compared to income of $3.6 million in the 2011 quarter. Results were lower in the current period as higher extraction costs exceeded the favorable effects of higher oil sales volumes and higher oil sales prices. Production expense increased by $11.4 million in 2012 versus 2011 due to a higher volume of crude oil sales in the later period. Depreciation expense increased by $14.9 million in 2012 associated with higher oil sales volumes and a higher unit rate for capital amortization. Exploration expenses were $2.7 million less in the 2012 first quarter compared to 2011 as the prior year included costs for 3D seismic acquired over a portion of the offshore MPN and MPS blocks.

Other international operations reported a loss of $36.8 million in the first quarter of 2012 compared to a loss of $50.9 million in the 2011 period. The favorable variance in the current quarter was primarily associated with unsuccessful exploratory drilling costs in 2011 in Suriname. Other exploration expenses in 2012 were higher than the prior year, partially offsetting the lower costs of exploratory drilling. The 2012 quarter included seismic costs covering licenses offshore Brunei, as well as geophysical and lease amortization costs associated with exploration licenses in the Kurdistan region of Iraq.

F-18

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

On a worldwide basis, the Company’s crude oil, condensate and gas liquids sales prices averaged $97.78 per barrel in the first quarter 2012 compared to $86.73 in the 2011 period. Total hydrocarbon production averaged 195,096 barrels of oil equivalent per day in the 2012 first quarter, up from 182,152 barrels equivalent per day produced in the 2011 quarter. Average crude oil and liquids production was 107,490 barrels per day in the first quarter of 2012 compared to 113,313 barrels per day in the first quarter of 2011, with the reduction primarily attributable to lower gross oil produced at the Kikeh and Azurite fields. U.S. crude oil production in the 2012 first quarter was higher than 2011 and was primarily output from the Eagle Ford Shale area in South Texas, where an ongoing development program has continued in 2012. Canadian heavy crude oil production was higher in 2012 mostly due to drilling activity, with associated new wells coming on stream in the Seal area in the current year. Synthetic crude oil production was lower in 2012 primarily due to downtime for unplanned maintenance in the current quarter. Oil production in the Republic of Congo at the Azurite field was lower in 2012 due to field decline and a well that went off production due to mechanical issues during the current quarter. North American natural gas sales prices averaged $2.56 per thousand cubic feet (MCF) in the 2012 quarter compared to $4.35 per MCF in the same quarter of 2011. Natural gas produced in 2012 at fields offshore Sarawak was sold at $7.80 per MCF, compared to a sale price of $5.64 per MCF in the 2011 quarter. Natural gas sales volumes averaged more than 525 million cubic feet per day in the first quarter 2012, a quarterly record for Company production, and up from 413 million cubic feet per day in the 2011 quarter. The increase in natural gas sales volumes in 2012 was primarily due to a full three months of production at the Tupper West area in British Columbia in the 2012 quarter. The 2011 quarter included gas production at Tupper West for less than two months following the field’s February 2011 start-up. The Company also had higher natural gas production at nearby Tupper Main in 2012, as well as higher natural gas production from fields offshore Sarawak, with the latter attributable to higher customer demand and more consistent operations.

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

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, 2012 and 2011 follow.


	Three Months Ended March 31,
	2012		2011
Net crude oil, condensate and gas liquids produced – barrels per day		107,490		113,313
United States		20,280		16,817
Canada – light		205		35
– heavy		8,406		7,809
– offshore		9,377		8,804
– synthetic		13,311		14,902
Malaysia		49,959		55,216
United Kingdom		3,071		3,085
Republic of the Congo		2,881		6,645

Net crude oil, condensate and gas liquids sold – barrels per day		108,562		112,804
United States		20,280		16,817
Canada – light		205		35
– heavy		8,406		7,809
– offshore		8,619		9,090
– synthetic		13,311		14,902
Malaysia		48,703		57,717
United Kingdom		3,135		2,574
Republic of the Congo		5,903		3,860

Net natural gas sold – thousands of cubic feet per day		525,635		413,034
United States		51,231		54,260
Canada		242,285		117,294
Malaysia – Sarawak		184,635		170,554
– Kikeh		43,743		64,832
United Kingdom		3,741		6,094

Total net hydrocarbons produced – equivalent barrels per day (1)		195,096		182,152
Total net hydrocarbons sold – equivalent barrels per day (1)		196,168		181,643

Weighted average sales prices Crude oil, condensate and natural gas liquids – dollars per barrel (2)
United States	$	110.08		95.53
Canada (3) – light		91.40		92.17
– heavy		51.14		52.54
– offshore		118.39		102.14
– synthetic		96.95		94.35
Malaysia (4)		94.74		82.66
United Kingdom		120.01		106.24
Republic of the Congo (4)		107.26		99.48

Natural gas – dollars per thousand cubic feet
United States (2)	$	2.64		4.19
Canada (3)		2.54		4.42
Malaysia – Sarawak		7.80		5.64
– Kikeh		0.24		0.24
United Kingdom (3)		9.58		9.90

(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 terms of the respective production sharing contracts.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

OIL AND GAS OPERATING RESULTS (unaudited)


	United States		Canada					Malaysia			United King- dom		Republic of the Congo			Other			Total
(Millions of dollars)	United States		Conven- tional			Syn- thetic		Malaysia			United King- dom		Republic of the Congo			Other			Total
Three Months Ended March 31, 2012
Oil and gas sales and other operating revenues	$	221.1		189.4			117.6		563.9			37.6		57.6			—			1,187.2
Production expenses		48.5		44.4			52.6		89.2			5.4		17.0			—			257.1
Depreciation, depletion and amortization		63.0		77.2			13.3		112.7			7.8		33.8			.6			308.4
Accretion of assets retirement obligations		2.8		1.3			2.0		2.9			.3		.2			—			9.5
Exploration expenses
Dry holes		—		.8			—		—			—		—			(.2	)		.6
Geological and geophysical		.2		4.2			—		(.1	)		—		.1			6.9			11.3
Other		3.9		.2			—		—			.1		.2			8.1			12.5

		4.1		5.2			—		(.1	)		.1		.3			14.8			24.4
Undeveloped lease amortization		11.1		7.1			—		—			—		—			10.4			28.6

Total exploration expenses		15.2		12.3			—		(.1	)		.1		.3			25.2			53.0

Selling and general expenses		12.1		4.1			.2		.3			1.0		.9			11.0			29.6

Results of operations before taxes		79.5		50.1			49.5		358.9			23.0		5.4			(36.8	)		529.6
Income tax provisions		28.7		13.8			12.5		134.9			14.3		3.8			—			208.0

Results of operations (excluding corporate overhead and interest)	$	50.8		36.3			37.0		224.0			8.7		1.6			(36.8	)		321.6

Three Months Ended March 31, 2011
Oil and gas sales and other operating revenues	$	168.2		159.5			126.8		517.5			30.2		34.6			1.3			1,038.1
Production expenses		41.1		30.9			58.5		103.1			5.6		5.6			—			244.8
Depreciation, depletion and amortization		48.5		52.8			13.8		95.8			4.6		18.9			.4			234.8
Accretion of assets retirement obligations		2.4		1.3			1.9		2.6			.8		.2			.1			9.3
Exploration expenses
Dry holes		.9		—			—		.1			—		2.1			32.7			35.8
Geological and geophysical		18.2		1.5			—		—			.1		.8			.4			21.0
Other		3.3		.3			—		—			.1		.1			6.3			10.1

		22.4		1.8			—		.1			.2		3.0			39.4			66.9
Undeveloped lease amortization		18.4		6.9			—		—			—		—			4.1			29.4

Total exploration expenses		40.8		8.7			—		.1			.2		3.0			43.5			96.3

Terra Nova working interest redetermination		—		(5.4	)		—		—			—		—			—			(5.4	)
Selling and general expenses		9.4		3.3			.2		1.3			.8		(.4	)		7.8			22.4

Results of operations before taxes		26.0		67.9			52.4		314.6			18.2		7.3			(50.5	)		435.9
Income tax provisions		9.5		19.8			14.1		118.8			9.2		3.7			.4			175.5

Results of operations (excluding corporate overhead and interest)	$	16.5		48.1			38.3		195.8			9.0		3.6			(50.9	)		260.4

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

Results of Operations (Contd.)

Refining and Marketing

In 2010, the Company announced its intention to sell its three refineries and U.K. marketing operations during 2011. The Company sold the Superior, Wisconsin refinery and associated marketing assets on September 30, 2011, and also sold the Meraux, Louisiana refinery and associated marketing assets on October 1, 2011. The revenues and expenses for both refineries for all periods presented have been reported as discontinued operations, net of income taxes, in the Consolidated Statements of Income. The sale process for the U.K. downstream operations continues to progress. See Note D in the consolidated financial statements for further discussion.

The United States refining and marketing segment includes retail and wholesale fuel marketing operations and two ethanol production facilities. The United Kingdom refining and marketing segment includes the Milford Haven, Wales refinery and U.K. retail and other refined products marketing operations.

Murphy’s downstream income (loss) from continuing operations is presented below by segment.


	Income (Loss)
	Three Months Ended March 31,
(Millions of dollars)	2012			2011
Refining and marketing – continuing operations
United States	$	(7.2	)		9.0
United Kingdom		3.0			(8.7	)

Total	$	(4.2	)		0.3

United States downstream results from continuing operations declined from income of $9.0 million in the 2011 first quarter to a loss of $7.2 million in the 2012 quarter. The unfavorable 2012 result was primarily due to weaker U.S. retail marketing margins, which averaged $0.071 per gallon in 2012 and $0.091 per gallon in 2011. The Company was not able to fully pass on the higher wholesale gasoline purchase prices to retail customers at most of its U.S. stations during the 2012 quarter. Wholesale gasoline prices rose in concert with generally higher crude oil prices during the just completed quarter. Total margins on merchandise sales in the 2012 quarter were essentially level with 2011. Overall per-store retail fuel sales volumes in the 2012 quarter were below 2011 levels by about 6%. Earnings from ethanol production operations were lower in 2012 than 2011, primarily due to decreased margins at the Hankinson, North Dakota plant and below break-even results at the Hereford, Texas plant in the current year. The sales prices for ethanol did not keep pace with the rise in corn prices in the quarter ended March 31, 2012. The ramp-up of production at the Hereford plant, after start-up near the end of the first quarter of 2011, has met Company expectations.

Refining and marketing operations in the United Kingdom had income of $3.0 million in the first quarter of 2012 compared to a net loss of $8.7 million in the same quarter of 2011. The U.K. results in 2012 were favorably affected compared to 2011 by improved refining margins in the current quarter. The U.K. refining and marketing margin was $0.79 per barrel in 2012, up from a negative margin of $(0.61) per barrel in 2011. Crude oil throughput volumes at the Milford Haven refinery were also higher at 127,001 barrels per day during the 2012 quarter compared to throughputs of 121,326 barrels per day in the 2011 quarter.

Worldwide petroleum product sales (including discontinued operations in 2011) were 450,527 barrels per day in the 2012 quarter, down from 564,335 barrels per day a year ago. The decrease in 2012 sales volumes was partially attributed to the aforementioned lower U.S. retail gasoline sales volumes, but was also unfavorably affected by lower sales volumes of kerosine, diesel, residual fuels and asphalt following the sale of two U.S. refineries at the end of the third quarter 2011.

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, 2012 and 2011 follow.


	Three Months Ended March 31,
	2012			2011
United States retail marketing:
Fuel margin per gallon¹	$	0.071		$	0.091
Gallons sold per store month		254,806			272,159
Merchandise sales revenue per store month	$	152,923		$	148,365
Merchandise margin as a percentage of merchandise sales		13.0	%		13.7	%
Store count at end of period (Company operated)		1,133			1,110

United Kingdom refining and marketing – unit margins per barrel	$	0.79		$	(0.61	)

Petroleum products sold – barrels per day		450,527			564,335
United States		319,976			437,775	²
Gasoline		274,391			319,933
Kerosine		216			16,017
Diesel and home heating oils		45,369			81,062
Residuals		0			15,225
Asphalt, LPG and other		0			5,538
United Kingdom		130,551			126,560
Gasoline		44,679			26,682
Kerosine		15,872			15,560
Diesel and home heating oils		43,683			44,722
Residuals		15,698			11,527
LPG and other		10,619			28,069

U.K. refinery inputs – barrels per day		130,750			124,967
Milford Haven, Wales – crude oil		127,001			121,326
– other feedstocks		3,749			3,641

U.K. refinery yields – barrels per day		130,750			124,967
Gasoline		44,573			26,584
Kerosine		16,089			16,139
Diesel and home heating oils		40,340			42,824
Residuals		15,586			11,548
LPG and other		10,593			25,186
Fuel and loss		3,569			2,686

¹Represents net sales prices for fuel less purchased cost of fuel.

² Includes 153,746 bbls per day in 2011 related to discontinued operations.

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 $27.3 million in the 2012 first quarter compared to net costs of $22.3 million in the first quarter of 2011. The results for corporate activities were unfavorable in 2012 compared to 2011 primarily due to higher administrative expenses coupled with lower interest income earned in the just completed quarter. The Company incurred after-tax losses of $1.5 million in the 2012 quarter on transactions denominated in foreign currencies compared to after-tax losses of $1.1 million in the 2011 quarter.

Discontinued Operations

The Company sold the Superior, Wisconsin and Meraux, Louisiana refineries and related marketing assets near the end of the third quarter 2011. See Note D of the consolidated financial statement for further information. The Company has accounted for these assets as discontinued operations in all periods presented. Income from discontinued operations was $30.5 million in the first three months of 2011, but the 2012 quarter included no discontinued operating results. Discontinued operations in the first quarter of 2011 benefited from positive U.S. refining margins that averaged $2.93 per barrel of throughput by the refineries.

Financial Condition

Net cash provided by operating activities was $991.0 million for the first three months of 2012 compared to $522.9 million during the same period in 2011. Cash provided by operating activities of discontinued operations was $47.9 million in the 2011 period. Changes in operating working capital other than cash and cash equivalents provided cash of $298.3 million in the first three months of 2012, but used cash of $140.4 million in the first three months of 2011. Cash was provided by working capital in 2012 primarily due to a combination of higher accounts payable owed for worldwide E&P and downstream operations, higher income taxes payable and lower accounts receivable at March 31, 2012 compared to December 31, 2011. Cash of $507.3 million in the 2012 period and $587.8 million in 2011 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 $53.4 million in 2012 and $53.1 million in 2011, and for property additions and dry holes, which including amounts expensed, were $567.3 million and $508.9 million in the three-month periods ended March 31, 2012 and 2011, respectively. The purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $469.6 million in the 2012 period and $428.3 million in the 2011 period. Cash used for property additions and other investing activities of discontinued operations totaled $15.5 million in 2011. Total accrual basis capital expenditures were as follows:


	Three Months Ended March 31,
(Millions of dollars)	2012		2011
Capital expenditures
Exploration and production	$	715.1		517.1
Refining and marketing, including discontinued operations in 2011		22.8		47.9
Corporate and other		1.8		1.6

Total capital expenditures, including discontinued operations in 2011	$	739.7		566.6

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


	Three Months Ended March 31,
(Millions of dollars)	2012		2011
Property additions and dry hole costs per cash flow statements, including discontinued operations in 2011	$	567.3		526.8
Geophysical and other exploration expenses		23.8		31.1
Capital expenditure accrual changes, including discontinued operations in 2011		148.6		8.7

Total capital expenditures, including discontinued operations in 2011	$	739.7		566.6

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

Financial Condition (Contd.)

Working capital (total current assets less total current liabilities) at March 31, 2012 was $558.7 million, a decrease of $64.0 million from December 31, 2011. 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 $713.1 million below fair value at March 31, 2012.

At March 31, 2012, long-term notes payable of $249.6 million was unchanged from December 31, 2011. A summary of capital employed at March 31, 2012 and December 31, 2011 follows.


	March 31, 2012					Dec. 31, 2011
(Millions of dollars)	Amount		%			Amount		%
Capital employed
Long-term debt	$	249.6		2.7	%	$	249.6		2.8	%
Stockholders’ equity		9,119.1		97.3			8,778.4		97.2

Total capital employed	$	9,368.7		100.0	%	$	9,028.0		100.0	%

The Company’s ratio of earnings to fixed charges was 21.7 to 1 for the three-month period ended March 31, 2012.

Cash and invested cash are maintained in several operating locations outside the United States. At March 31, 2012, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included approximately $577 million in Canada, $242 million in the U.K. and $398 million in Malaysia. In certain cases, the Company could incur taxes or other costs should these cash balances be repatriated to the U.S. in future periods. This could occur due to withholding taxes and/or potential additional U.S. tax burden when less than the U.S. Federal tax rate of 35% has been paid for cash taxes in foreign locations. A lower cash tax rate is often paid in foreign countries in the early years of operations when accelerated tax deductions exist to incent oil and gas investments; cash tax rates are generally higher in later years after accelerated tax deductions in early years are exhausted. Canada collects a 5% withholding tax on any cash repatriated to the U.S.

Accounting and Other Matters

In June 2011, the FASB issued an accounting standards update that only permits two options for presentation of comprehensive income. Comprehensive income can be presented in (a) a single continuous Statement of comprehensive income, including total comprehensive income, the components of net income, and the components of other comprehensive income, or (b) in two separate but continuous statements for the Statement of Income and the Statement of Comprehensive Income. The new guidance was effective for the Company beginning in the first quarter of 2012. The Company adopted this guidance in 2012 and it continues to present comprehensive income in a separate statement following the statement of income. The adoption of this standard did not have a significant effect on the Company’s consolidated financial statements. In December 2011, the FASB deferred the requirement for reclassification adjustments from accumulated other comprehensive income to be measured and presented by line item in the Statement of Income.

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

Accounting and Other Matters (Contd.)

The United States Congress passed the Dodd-Frank Act in 2010. Among other requirements, the law requires companies in the oil and gas industry to disclose payments made to the U.S. Federal and all foreign governments. The SEC was directed to develop the reporting requirements in accordance with the law. The SEC has issued preliminary guidance and has sought feedback thereon from all interested parties. The preliminary rules indicated that payment disclosures would be required at a project level within the annual Form 10-K report beginning with the year ending December 31, 2012. The Company cannot predict the final disclosure requirements that will be required by the Dodd-Frank Act.

Outlook

Average crude oil prices in April 2012 were about level with the average price during the first quarter of 2012. North American natural gas prices, however, have fallen further in April 2012 due to lower than normal usage and higher than normal storage levels primarily due to unusually temperate spring weather throughout much of the mid and eastern U.S. The Company expects its total oil and natural gas production to average about 185,000 barrels of oil equivalent per day in the second quarter 2012. U.S. retail marketing margins have improved in April versus the average margins achieved in the first quarter 2012. The Company currently anticipates total capital expenditures for the full year 2012 to be approximately $3.7 billion.

On May 1, 2012, notes payable totaling $350 million matured and were repaid by borrowing $350 million under available credit facilities. The Company has undertaken a process to sell $500 million of notes payable under a shelf registration on file with the U.S. Securities and Exchange Commission. If successfully completed, the proceeds from the sale of these notes will be used to repay the amounts borrowed on May 1 under the credit facilities and for general corporate purposes. The associated forward starting interest rate swaps settled on May 1, 2012 at a net cost to the Company of $29.6 million.

We have been evaluating the potential to separate our U.S. downstream business into a separate publicly traded company. At March 31, 2012, our U.S. downstream business had $1.84 billion in assets. For the three months ended March 31, 2012, our U.S. downstream business generated $4.26 billion in revenues and incurred an after-tax loss of $7.2 million, and for the year ended December 31, 2011, it generated $17.5 billion in revenues and earned $223.6 million in income from continuing operations. Should a decision be made to separate our U.S. downstream business, the anticipated timing of the separation will be announced at the time. Some factors that could potentially affect the decision to separate include our future financial condition and operating results and economic, business, competitive and/or regulatory factors affecting our business and our industry. We cannot predict when, or if, the separation of our U.S. downstream business would take place, or on what terms such separation would be made.

The Company continues to offer for sale its U.K. refinery at Milford Haven, Wales and all U.K. product terminals and motor fuel stations. The Company cannot predict when, or if, the sale of these assets will take place or on what terms such a sale would be made.

As noted above, North American natural gas prices are extremely weak in April 2012. Should these prices remain weak for an extended period of time, or weaken further than the current level, it is possible that certain investments in natural gas properties could become impaired in a future period.

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 the Company’s 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, customer demand for our products, political and regulatory instability, and uncontrollable natural hazards. For further discussion of risk factors, see Murphy’s 2011 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 K to this Form 10-Q report, Murphy periodically makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions. There were short-term commodity derivative contracts in place at March 31, 2012 to hedge the purchase price of about 11.7 million bushels of corn and the sale price of about 0.9 million equivalent bushels of wet and dried distillers grain at the Company’s ethanol production facilities. A 10% increase in the respective benchmark price of these commodities would have reduced the recorded net liability associated with these derivative contracts by approximately $0.7 million, while a 10% decrease would have increased the recorded net liability by a similar amount. Changes in the fair value of these derivative contracts generally offset the changes in the value for an equivalent volume of these feedstocks.

There were short-term derivative foreign exchange contracts in place at March 31, 2012 to hedge the value of the U.S. dollar against two foreign currencies. A 10% strengthening of the U.S. dollar against these foreign currencies would have reduced the recorded net asset associated with these contracts by approximately $15.7 million, while a 10% weakening of the U.S. dollar would have increased the recorded net asset by approximately $11.3 million. Changes in the fair value of these derivative contracts generally offset the financial statement impact of an equivalent volume of foreign currency exposures associated with other assets and/or liabilities.

There were short-term derivative interest rate contracts in place at March 31, 2012 to hedge fluctuations in cash flows of anticipated future semi-annual interest payments attributable to changes in the benchmark interest rate. A 10% increase in the respective interest rate would have reduced the recorded liability associated with these derivative contracts by approximately $6.4 million, while a 10% decrease would have increased the recorded liability by approximately $4.9 million. See the Outlook section on page 26 for actual May 1, 2012 settlement value of these interest rate contracts.

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, 2012 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In 2011, Murphy was notified by the U.K. Environment Agency (EA) that it failed to surrender sufficient greenhouse gas emission allowances, which Murphy self-reported to the EA in 2010. The EA has issued a civil penalty notice of approximately $1.7 million. The Company is pursuing all available options regarding this matter.

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

ITEM 1A. RISK FACTORS

The Company’s operations in the oil and gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A. Risk Factors in our 2011 Form 10-K filed on February 28, 2012. The Company has not identified any additional risk factors not previously disclosed in its 2011 Form 10-K report.

ITEM 6. EXHIBITS

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

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, Senior Vice President and Controller (Chief Accounting Officer and Duly Authorized Officer)

May 7, 2012

(Date)

EXHIBIT INDEX


Exhibit No.

3.2*		By-Laws of Murphy Oil Corporation as amended effective April 3, 2012, as filed on Form 8-K on April 5, 2012.

12.1		Computation of Ratio of Earnings to Fixed Charges

31.1		Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification required by Rule 13a-14(a) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32		Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101. INS		XBRL Instance Document

101. SCH		XBRL Taxonomy Extension Schema Document

101. CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101. DEF		XBRL Taxonomy Extension Definition Linkbase Document

101. LAB		XBRL Taxonomy Extension Labels Linkbase Document

101. PRE		XBRL Taxonomy Extension Presentation Linkbase

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

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company