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, 2013

¨	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
		71731-7000
(Address of principal executive offices)		(Zip Code)

(870) 862-6411

(Registrant’s telephone number, including area code)

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

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

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

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

Number of shares of Common Stock, $1.00 par value, outstanding at March 31, 2013 was 190,973,679.

MURPHY OIL CORPORATION

TABLE OF CONTENTS


	Page
Part I – Financial Information		2
Item 1. Financial Statements		2
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		27

Item 1. Legal Proceedings		27

Item 1A. Risk Factors		28

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		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, 2013			December 31, 2012
ASSETS
Current assets
Cash and cash equivalents	$	1,117,105			947,316
Canadian government securities with maturities greater than 90 days at the date of acquisition		215,538			115,603
Accounts receivable, less allowance for doubtful accounts of $6,677 in 2013 and $6,697 in 2012		1,676,172			1,853,364
Inventories, at lower of cost or market
Crude oil		136,723			226,541
Finished products		210,812			266,307
Materials and supplies		282,066			259,462
Prepaid expenses		390,163			335,831
Deferred income taxes		64,958			89,040
Assets held for sale		5,266			15,119

Total current assets		4,098,803			4,108,583
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $8,444,828 in 2013 and $8,138,587 in 2012		13,421,164			13,011,606
Goodwill		42,034			43,103
Deferred charges and other assets		141,156			151,183
Assets held for sale		48,528			208,168

Total assets	$	17,751,685			17,522,643

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	46			46
Accounts payable and accrued liabilities		2,890,094			3,141,717
Income taxes payable		365,471			219,847
Liabilities associated with assets held for sale		16,472			47,471

Total current liabilities		3,272,083			3,409,081
Long-term debt		2,507,311			2,245,201
Deferred income taxes		1,547,193			1,544,336
Asset retirement obligations		745,311			724,273
Deferred credits and other liabilities		503,149			516,540
Liabilities associated with assets held for sale		38,144			141,177
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 194,683,376 shares in 2013 and 194,616,470 shares in 2012		194,683			194,616
Capital in excess of par value		867,047			873,934
Retained earnings		8,018,316			7,717,389
Accumulated other comprehensive income		294,371			408,901
Treasury stock, 3,709,697 shares of Common Stock in 2013 and 3,975,153 shares of Common Stock in 2012, at cost		(235,923	)		(252,805	)

Total stockholders’ equity		9,138,494			8,942,035

Total liabilities and stockholders’ equity	$	17,751,685			17,522,643

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,
	2013			2012*
REVENUES
Sales and other operating revenues	$	6,647,944			6,953,861
Gain on sale of assets		40			90
Interest and other income (loss)		(8,030	)		2,985

Total revenues		6,639,954			6,956,936

COSTS AND EXPENSES
Crude oil and product purchases		4,999,645			5,514,379
Operating expenses		599,102			488,485
Exploration expenses, including undeveloped lease amortization		108,493			52,927
Selling and general expenses		109,742			88,159
Depreciation, depletion and amortization		393,754			332,588
Accretion of asset retirement obligations		12,165			9,446
Interest expense		27,028			11,739
Interest capitalized		(13,388	)		(6,423	)

Total costs and expenses		6,236,541			6,491,300

Income from continuing operations before income taxes		403,413			465,636
Income tax expense		195,443			184,198

Income from continuing operations		207,970			281,438
Income from discontinued operations, net of taxes		152,629			8,633

NET INCOME	$	360,599			290,071

NET INCOME PER COMMON – BASIC
Income from continuing operations	$	1.09			1.45
Income from discontinued operations		0.80			0.05

Net income	$	1.89			1.50

NET INCOME PER COMMON – DILUTED
Income from continuing operations	$	1.08			1.44
Income from discontinued operations		0.80			0.05

Net income	$	1.88			1.49

Average Common shares outstanding
Basic		190,810,201			193,922,260
Diluted		191,765,395			194,884,733

*	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,
	2013			2012
Net income	$	360,599			290,071
Other comprehensive income, net of income taxes
Net gain (loss) from foreign currency translation		(117,754	)		82,252
Retirement and postretirement benefit plan		2,738			2,708
Deferred loss on interest rate hedges:
Reduction of deferred loss on interest rate hedge		0			2,983
Amount of loss reclassified to interest expense in consolidated statements of income		486			0

Other comprehensive income (loss)		(114,530	)		87,943

COMPREHENSIVE INCOME	$	246,069			378,014

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,
	2013			2012¹
OPERATING ACTIVITIES
Net income	$	360,599			290,071
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations		(152,629	)		(8,633	)
Depreciation, depletion and amortization		393,754			332,588
Amortization of deferred major repair costs		5,949			5,911
Expenditures for asset retirements		(15,881	)		(6,957	)
Dry hole costs		41,011			620
Amortization of undeveloped leases		15,390			28,632
Accretion of asset retirement obligations		12,165			9,446
Deferred and noncurrent income tax charges		25,341			8,072
Pretax gain from disposition of assets		(40	)		(90	)
Net decrease in noncash operating working capital		211,462			301,071
Other operating activities, net		10,114			16,823

Net cash provided by continuing operations		907,235			977,554
Net cash provided by discontinued operations		13,892			13,452

Net cash provided by operating activities		921,127			991,006

INVESTING ACTIVITIES
Property additions and dry hole costs		(1,035,021	)		(561,705	)
Proceeds from sale of assets		29			123
Purchases of investment securities²		(230,320	)		(469,564	)
Proceeds from maturity of investment securities²		130,385			507,305
Expenditures for major repairs		(4,894	)		0
Investing activities of discontinued operations
Sales proceeds		211,549			0
Property additions and other		(7,974	)		(5,559	)
Other – net		2,306			3,889

Net cash required by investing activities		(933,940	)		(525,511	)

FINANCING ACTIVITIES
Borrowing (repayment) of notes payable		261,989			(11	)
Proceeds from exercise of stock options and employee stock purchase plans		1,281			6,599
Excess tax benefits related to exercise of stock options		0			1,037
Withholding tax on stock-based incentive awards		(7,337	)		(5,501	)
Issue cost of debt facility		(91	)		0
Cash dividends paid		(59,672	)		(53,383	)

Net cash provided (required) by financing activities		196,170			(51,259	)

Effect of exchange rate changes on cash and cash equivalents		(13,568	)		8,540

Net increase in cash and cash equivalents		169,789			422,776
Cash and cash equivalents at January 1		947,316			513,873

Cash and cash equivalents at March 31	$	1,117,105			936,649

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,
	2013			2012
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued		0			0

Common Stock – par $1.00, authorized 450,000,000 shares, issued 194,683,376 shares at March 31, 2013 and 194,345,426 shares at March 31, 2012
Balance at beginning of period	$	194,616			193,909
Exercise of stock options		67			212
Awarded restricted stock		0			224

Balance at end of period		194,683			194,345

Capital in Excess of Par Value
Balance at beginning of period		873,934			817,974
Exercise of stock options, including income tax benefits		743			7,976
Restricted stock transactions and other		(24,480	)		(5,501	)
Stock-based compensation		16,903			12,932
Other		(53	)		0

Balance at end of period		867,047			833,381

Retained Earnings
Balance at beginning of period		7,717,389			7,460,942
Net income for the period		360,599			290,071
Cash dividends		(59,672	)		(53,383	)

Balance at end of period		8,018,316			7,697,630

Accumulated Other Comprehensive Income
Balance at beginning of period		408,901			310,420
Foreign currency translation gain (loss), net of income taxes		(117,754	)		82,252
Retirement and postretirement benefit plan adjustments, net of income taxes		2,738			2,708
Change in deferred loss on interest rate hedges, net of income taxes		486			2,983

Balance at end of period		294,371			398,363

Treasury Stock
Balance at beginning of period		(252,805	)		(4,848	)
Sale of stock under employee stock purchase plans		337			212
Awarded restricted stock		16,545			0

Balance at end of period		(235,923	)		(4,636	)

Total Stockholders’ Equity	$	9,138,494			9,119,083

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, 2012. 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, 2013, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended March 31, 2013 and 2012, 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 2012 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the three-month period ended March 31, 2013 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, 2013, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $444.2 million. The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2013 and 2012.


(Thousands of dollars)	2013			2012
Beginning balance at January 1	$	445,697			556,412
Additions pending the determination of proved reserves		26,929			49,524
Reclassifications to proved properties based on the determination of proved reserves		(28,398	)		(42,431	)

Balance at March 31	$	444,228			563,505

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
	2013						2012
(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	$	56,324		6		3		109,907		29		5
One to two years		40,721		3		1		141,441		16		4
Two to three years		79,446		8		2		55,922		9		2
Three years or more		267,737		24		5		256,235		35		5

	$	444,228		41		11		563,505		89		16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Of the $387.9 million of exploratory well costs capitalized more than one year at March 31, 2013, $272.7 million is in Malaysia and $115.2 million is in the U.S. 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 2012, the Company announced that its Board of Directors had approved a plan to separate its U.S. retail marketing business into a separate publicly owned company. In 2010, the Company announced that its Board of Directors had approved plans to exit the U.K. refining and marketing business. These operations are presented as the U.S. and U.K. refining and marketing segments in Note P. The separation of the U.S. retail marketing business is expected to be completed during 2013. The sale process for the U.K. downstream assets continues in 2013. Based on current market conditions, it is possible that the Company could incur a loss when the U.K. downstream assets are sold. If the separation of the U.S. retail marketing business and the sale of the U.K. downstream assets continue to progress, the results of these operations are likely to be presented as discontinued operations in future periods when the operations no longer qualify as continuing operations under U.S. generally accepted accounting principles.

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, 2013 and December 31, 2012, the carrying values of inventories under the LIFO method were $623.7 million and $571.2 million, respectively, less than such inventories would have been valued using the first-in, first-out (FIFO) method.

Note D – Discontinued Operations

The Company sold certain oil and gas assets in the United Kingdom during the three months ended March 31, 2013. The after-tax gain on sale of the two assets was $147.4 million in the three months ended March 31, 2013. One remaining oil and gas producing asset is expected to be sold in the second quarter 2013. The Company has accounted for these U.K. upstream operations as discontinued operations in its consolidated financial statements for all periods presented.

The results of operations associated with these discontinued operations for the three-month periods ended March 31, 2013 and 2012 were as follows:


(Thousands of dollars)	2013			2012
Revenues	$	166,522			37,583
Income before income taxes, including gain on disposal of $74,928 during 2013		89,521			22,973
Income tax expense (benefit)		(63,108	)		14,340

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 1.25% above LIBOR based on the Company’s current credit rating as of March 31, 2013. In addition, facility fees of 0.25% are charged on the full $1.5 billion 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 October 2015.

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)	2013			2012
Net (increase) decrease in operating working capital other than cash and cash equivalents:
Decrease in accounts receivable	$	182,714			69,126
Decrease in inventories		126,826			4,962
Increase in prepaid expenses		(54,119	)		(51,508	)
Decrease in deferred income tax assets		24,082			5,522
Increase (decrease) in accounts payable and accrued liabilities		(191,616	)		229,804
Increase in current income tax liabilities		123,575			43,165

Total	$	211,462			301,071

Supplementary disclosures:
Cash income taxes paid	$	47,877			160,210
Interest paid more (less) than amounts capitalized		(10,519	)		490

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 benefit plans, which are not funded, that cover most active and retired U.S. employees. Additionally, most U.S. retired employees are covered by a life insurance benefit plan. 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, 2013 and 2012.


	Three Months Ended March 31,
	Pension Benefits						Other Postretirement Benefits
(Thousands of dollars)	2013			2012			2013			2012
Service cost	$	7,603			5,888			1,167			1,041
Interest cost		6,431			7,292			1,234			1,449
Expected return on plan assets		(5,700	)		(6,305	)		0			0
Amortization of prior service cost		276			312			(42	)		(46	)
Amortization of transitional liability		120			111			2			2
Recognized actuarial net loss		3,532			3,767			457			489

Net periodic benefit expense	$	12,262			11,065			2,818			2,935

During the three-month period ended March 31, 2013, the Company made contributions of $17.4 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2013 for the Company’s defined benefit pension and postretirement plans is anticipated to be $31.1 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 significantly affect the Company’s consolidated financial statements as of March 31, 2013 and December 31, 2012 and for the three-month periods ended March 31, 2013 and 2012. 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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 2012 Annual Incentive Plan (2012 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 2012 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 2012 Long-Term Incentive Plan (2012 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock and other stock-based incentives 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 2012 Long-Term Plan expires in 2022. A total of 8,700,000 shares are issuable during the life of the 2012 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.

On February 5, 2013, the Committee granted stock options for 1,123,300 shares at an exercise price of $60.015 per share. The Black-Scholes valuation for these awards was $15.81 per option. The Committee also granted 443,700 performance-based restricted stock units on that date. The fair value of the performance-based restricted stock units, using a Monte Carlo valuation model, ranged from $39.50 to $54.82 per unit. Additionally, on February 5, 2013, the Committee granted 851,000 stock appreciation rights (SAR) and 93,200 units of restricted stock-cash (RSU-C) to certain employees. The SAR and RSU-C are to be settled in cash, net of applicable income taxes, and are accounted for as liability-type awards. The initial fair values of these SAR were equivalent to the stock options granted, while the initial value of RSU-C were equivalent to restricted stock units granted. On February 6, 2013, the Committee granted 36,600 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 $60.30 per share.

Cash received from options exercised under all share-based payment arrangements for the three-month periods ended March 31, 2013 and 2012 was $1.3 million and $6.6 million, respectively. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $1.4 million and $2.0 million for the three-month periods ended March 31, 2013 and 2012, 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)	2013		2012
Compensation charged against income before tax benefit	$	17,833		13,042
Related income tax benefit recognized in income		3,755		3,978

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, 2013 and 2012. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended March 31,
(Weighted-average shares)	2013		2012
Basic method		190,810,201		193,922,260
Dilutive stock options and restricted stock units		955,194		962,473

Diluted method		191,765,395		194,884,733

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Earnings per Share (Contd.)

Outstanding options to purchase shares of Common stock were not included in the computation of diluted EPS during the 2013 and 2012 periods when the incremental shares from assumed conversion were antidilutive. These included 3,794,002 shares at a weighted average share price of $62.18 in the 2013 period and 2,834,487 shares at a weighted average share price of $66.51 in the 2012 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 2013 and 2012, the Company’s effective income tax rates were as follows:


	2013			2012
Three months ended March 31		48.4	%		39.6	%

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, 2013, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2009; Canada – 2007; United Kingdom – 2011; 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 were accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in Accumulated Other Comprehensive Income until the anticipated transactions occur.

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 with solubles that it will sell in the future at its ethanol production facilities in the United States. At March 31, 2013 and 2012, the Company had open physical delivery commitment contracts for purchase of approximately 18.7 million and 11.7 million bushels of corn, respectively, for processing at its ethanol plants. For both periods ending March 31, 2013 and 2012, the Company had open physical delivery commitment contracts for sale of approximately 0.9 million equivalent bushels of wet and dried distillers grain with solubles. To manage the price risk associated with certain of these physical delivery commitments which have fixed prices, at March 31, 2013 and 2012, the Company had outstanding derivative contracts with a net volume of approximately 6.0 million and 11.7 million bushels, respectively, that mature at future prices in effect on the expected date of delivery under the physical delivery commitment contracts. Additionally, at March 31, 2013, the Company had outstanding derivative contracts to sell 2.1 million bushels of corn and buy them back when certain corn inventories are expected to be processed at the Hankinson, North Dakota, and Hereford, Texas facilities. The impact of marking to market these commodity derivative contracts reduced income before taxes by $0.6 million and $0.1 million for the three months ended March 31, 2013 and 2012, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Financial Instruments and Derivatives (Contd.)

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, 2013 and 2012 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, 2013 and 2012 were approximately $274.0 million and $373.6 million, respectively. Short-term derivative instrument contracts totaling $20.0 million and $46.0 million U.S. dollars were also outstanding at March 31, 2013 and 2012, 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 reduced income before taxes by $2.7 million for the three-month period ended March 31, 2013 and increased income before taxes by $6.6 million for the three-month period ended March 31, 2012.

At March 31, 2013 and December 31, 2012, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

March 31, 2013

December 31, 2012

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity

Accounts receivable

2,158

Accounts receivable

3,043

Commodity

Accounts payable

(2,805

)

Accounts payable

(102

)

Foreign currency

Accounts payable

(2,718

)

Accounts payable

(1,031

)

For the three-month periods ended March 31, 2013 and 2012, 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) Type of Derivative Contract	Statement of Income Location	Three Months Ended March 31,
(Thousands of dollars) Type of Derivative Contract	Statement of Income Location	2013			2012
Commodity	Crude oil and product purchases	$	(4,210	)		645
Foreign currency	Interest and other income (loss)		(2,818	)		17,515

		$	(7,028	)		18,160

Interest Rate Risks

The Company had ten-year notes totaling $350 million that matured on May 1, 2012. The Company expected to replace these notes at maturity with new ten-year notes, and it therefore had risk associated with the interest rate related to the anticipated sale of these notes in 2012. To manage this risk, in 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps that matured in May 2012. The Company utilized hedge accounting to defer any gain or loss on these contracts associated with the payment of interest on these anticipated notes in 2012 through 2022. During the three-month period ended March 31, 2013, $0.7 million of the deferred loss on the interest rate swaps was charged to income. The remaining loss deferred on these matured contracts at March 31, 2013 was $17.6 million, which is recorded, net of income taxes, in Accumulated Other Comprehensive Income in the Consolidated Balance Sheet. The Company expects to charge approximately $2.2 million of this deferred loss to income in the form of interest expense during the remaining nine months of 2013. There was no impact in the Consolidated Statement of Income during the three-month period ended March 31, 2012 related to these interest rate derivative contracts.

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Financial Instruments and Derivatives (Contd.)

The carrying value of assets and liabilities recorded at fair value on a recurring basis at March 31, 2013 and December 31, 2012 are presented in the following table.


	March 31, 2013											December 31, 2012
(Thousands of dollars)	Level 1			Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total
Assets
Commodity derivative contracts	$	0			2,158			0		2,158			0			3,043			0		3,043

Liabilities
Nonqualified employee savings plans	$	(10,816	)		0			0		(10,816	)		(10,293	)		0			0		(10,293	)
Foreign currency exchange derivative contracts		0			(2,718	)		0		(2,718	)		0			(1,031	)		0		(1,031	)
Commodity derivative contracts		0			(2,805	)		0		(2,805	)		0			(102	)		0		(102	)

	$	(10,816	)		(5,523	)		0		(16,339	)		(10,293	)		(1,133	)		0		(11,426	)

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 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. 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.

The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. Derivative assets and liabilities which have offsetting positions at March 31, 2013 and December 31, 2012 are presented in the following tables.


	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Assets Presented in the Consolidated Balance Sheet
(Thousands of dollars) At March 31, 2013
Commodity derivatives	$	1,528		(936	)		592


At December 31, 2012
Commodity derivatives	$	1,383		(441	)		942


	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Consolidated Balance Sheet			Net Amounts of Liabilities Presented in the Consolidated Balance Sheet
(Thousands of dollars)
At March 31, 2013
Commodity derivatives	$	325		(43	)		282


At December 31, 2012
Commodity derivatives	$	1,830		(1,728	)		102

All commodity derivatives above are corn-based contracts associated with the Company’s two U.S. ethanol plants. Net derivative assets in the table above are included in Accounts Receivable presented in the table on the prior page and are included in Accounts Receivable on the Consolidated Balance Sheet; likewise, net derivative liabilities in the above table are included in Accounts Payable in the table on the prior page and are included in Accounts Payable

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Financial Instruments and Derivatives (Contd.)

and Accrued Liabilities on the Consolidated Balance Sheet. Separate derivative agreements exist for each of the ethanol plants and at March 31, 2013 one plant has a net receivable and the other has a net payable for derivative contracts. These contracts permit net settlement and the Company generally avails itself of this right to settle net. At March 31, 2013 cash deposits of $11.6 million related to commodity derivative contracts were reported in Prepaid Expenses in the Consolidated Balance Sheet. These cash deposits have not been used to reduce the reported net liabilities on the corn-based derivative contracts at March 31, 2013.

Note L – Accumulated Other Comprehensive Income

The components of Accumulated Other Comprehensive Income (AOCI) on the Consolidated Balance Sheets at March 31, 2013 and December 31, 2012 and the changes during the three months ended March 31, 2013 are presented net of taxes in the following table.


							Changes in AOCI
							Three Months Ended March 31, 2013
	AOCI Components						Changes Before Reclassi- fications			Reclassi- fications from AOCI
(Thousands of dollars)	March 31, 2013			Dec. 31, 2012			Changes Before Reclassi- fications			Reclassi- fications from AOCI
Foreign currency translation gains, net of tax	$	495,738			613,492			(117,754	)		0
Retirement and postretirement benefit plan losses, net of tax		(183,801	)		(186,539	)		(347	)		3,085
Loss deferred on settled interest rate derivative contracts, net of tax		(17,566	)		(18,052	)		0			486

Accumulated other comprehensive income	$	294,371			408,901			(118,101	)		3,571

The following table presents further information about amounts reclassified from Accumulated Other Comprehensive Income during the three-month period ended March 31, 2013.


(Thousands of dollars)	Amounts Reclassified from AOCI			Affected Line Item in Consolidated Statement of Income


Amortization of retirement and postretirement plan items:
Actuarial net loss	$	3,989	*
Prior service cost		234	*
Transitional liability		122	*

		4,345		Total expense before tax
		1,260		Tax benefit

		3,085		Expense net of tax


Deferred loss on interest rate derivative hedges		741		Interest expense
		255		Tax benefit

		486		Net of tax

Total reclassifications for period	$	3,571		Net of tax

*	These AOCI components are included in the computation of net periodic benefit expense. See Note G for additional information.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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.

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, 2013, the Company had contingent liabilities of $178.5 million on outstanding letters of credit. The Company has not accrued a liability in its balance sheet related to these letters of credit because it is believed that the likelihood of having these drawn is remote.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note N – Accounting Matters

In December 2011, the Financial Accounting Standards Board (FASB) issued an accounting standards update that requires enhanced 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 was effective for all interim and annual periods beginning on or after January 1, 2013. These disclosures are presented in Note K.

In February 2013, the FASB issued an accounting standards update that requires additional disclosures for reclassification adjustments from accumulated other comprehensive income (AOCI). These additional disclosures include changes in AOCI balances by component and significant items reclassified out of AOCI. These disclosures must be presented either on the face of the affected financial statement or in the notes to the financial statements. The disclosures are effective for Murphy Oil beginning in the first quarter of 2013 and are to be provided on a prospective basis. These disclosures are presented in Note L.

Note O – Commitments

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2013 heavy oil and natural gas sales volumes in Western Canada. The heavy oil sales contracts call for deliveries of 4,000 barrels per day in May and June 2013 that achieve netback values ranging from US$50.28 to US$50.30 per barrel. The natural gas contracts call for deliveries between April through December that average approximately 73 million cubic feet per day at prices ranging from Cdn$3.69 to Cdn$3.87 per MCF, with the contracts calling for delivery at the NOVA inventory transfer sales point. These oil and natural gas contracts have been accounted for as normal sales for accounting purposes.

Note P – Business Segments


(Millions of dollars)	Total Assets at March 31, 2013		Three Months Ended March 31, 2013						Three Months Ended March 31, 2012
			External Revenues			Income (Loss)			External Revenues		Income (Loss)
			External Revenues			Income (Loss)			External Revenues		Income (Loss)
Exploration and production*
United States	$	3,650.9		408.9			93.8			221.1		50.8
Canada		4,357.6		260.8			13.3			307.0		73.3
Malaysia		4,940.9		560.0			205.2			564.0		224.1
Republic of the Congo		135.6		69.5			(14.8	)		57.6		1.6
Other		110.8		(0.2	)		(65.6	)		0.0		(36.8	)

Total		13,195.8		1,299.0			231.9			1,149.7		313.0

Refining and marketing
United States		1,776.3		4,019.5			29.4			4,264.2		(7.2	)
United Kingdom		1,091.5		1,329.5			(4.1	)		1,540.0		3.0

Total		2,867.8		5,349.0			25.3			5,804.2		(4.2	)

Total operating segments		16,063.6		6,648.0			257.2			6,953.9		308.8
Corporate		1,634.3		(8.0	)		(49.2	)		3.0		(27.3	)

Total continuing operations		17,697.9		6,640.0			208.0			6,956.9		281.5
Discontinued operations, net of tax		53.8		0.0			152.6			0.0		8.6

Total	$	17,751.7		6,640.0			360.6			6,956.9		290.1

*	Additional details about results of oil and gas operations are presented in the tables on page 20.

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

Results of Operations

Murphy’s net income in the first quarter of 2013 was $360.6 million ($1.88 per diluted share) compared to net income of $290.1 million ($1.49 per diluted share) in the first quarter of 2012. The 2013 and 2012 results included $152.6 million ($0.80 per diluted share) and $8.6 million ($0.05 per diluted share), respectively, of income from discontinued operations. Excluding discontinued operations, income in the 2013 first quarter was below 2012 results, primarily related to higher costs for exploration, administration, financing and income taxes. These higher costs were partially offset by improved results for the Company’s refining and marketing operations in the current year.

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


	Income (Loss)
	Three Months Ended March 31,
(Millions of dollars)	2013			2012
Exploration and production	$	231.9			313.0
Refining and marketing		25.3			(4.2	)
Corporate		(49.2	)		(27.3	)

Income from continuing operations		208.0			281.5
Discontinued operations		152.6			8.6

Net income	$	360.6			290.1

In the 2013 first quarter, the Company’s exploration and production operations earned $231.9 million compared to $313.0 million in the 2012 quarter. Income in the 2013 quarter was favorably impacted by higher crude oil sales volumes, but this was more than offset by higher exploration and extraction costs in the current quarter. The Company’s refining and marketing operations generated a profit of $25.3 million in the 2013 first quarter compared to a loss of $4.2 million in the same quarter of 2012. The improvement in downstream results arose in the U.S., which experienced stronger marketing margins for retail and wholesale operations. Results for the U.K. downstream segment were down in 2013 due to weaker refining margins coupled with lower crude oil throughputs associated with planned maintenance at the Milford Haven refinery. The corporate function had after-tax costs of $49.2 million in the 2013 first quarter compared to after-tax costs of $27.3 million in the 2012 period with the unfavorable variance in 2013 primarily due to higher expenses associated with administration and debt financing.

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)	2013			2012
Exploration and production
United States	$	93.8			50.8
Canada		13.3			73.3
Malaysia		205.2			224.1
Republic of the Congo		(14.8	)		1.6
Other International		(65.6	)		(36.8	)

Total	$	231.9			313.0

United States exploration and production operations had earnings of $93.8 million in the first quarter of 2013 compared to earnings of $50.8 million in the 2012 quarter. Earnings improved in 2013 primarily due to higher crude oil sales 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, 2013, nine rigs were actively drilling in the Eagle Ford Shale on behalf of the Company. U.S. results in 2013 were unfavorably affected by lower crude oil sales prices, but this was mostly offset by both higher natural gas sales prices and higher natural gas sales volumes in the current year. Production and depreciation expenses in the U.S. increased $41.9 million and $67.4 million, respectively, in 2013 compared to 2012 mostly due to higher production in the Eagle Ford Shale. Exploration expenses in the 2013 quarter were $5.8 million above 2012 levels due to higher costs for seismic in the Gulf of Mexico, partially offset by lower leasehold amortization in the Eagle Ford Shale in the latest quarter. Selling and general expenses in the 2013 period increased $4.0 million from the prior year primarily due to higher costs for employee compensation and other professional services.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Operations in Canada had earnings of $13.3 million in the first quarter 2013 compared to earnings of $73.3 million in the 2012 quarter. Canadian earnings decreased in the 2013 quarter due to a combination of lower oil sales prices, lower oil sales volumes at Terra Nova and Syncrude, and higher exploration expenses in the current period. Oil production decreased in the 2013 quarter compared to 2012 primarily due to lower volumes at Syncrude. Heavy oil production in 2013 at Seal was slightly above the prior year as a fire at a tank battery in the Seal area led to downtime for repairs that otherwise offset higher daily volumes when production was online. Natural gas sales volumes decreased in 2013 due to virtually no development drilling in the Tupper and Tupper West areas in the current year. Oil sales prices in 2013 were below the prior year in all areas, but heavy oil prices were especially weak, averaging more than $23.00 per barrel below 2012 sales prices. Exploration expenses in 2013 were $23.9 million above the prior year primarily due to dry hole costs associated with drilling in the Muskwa Shale area of Alberta. Although hydrocarbons were found at Rainbow, well flows were insufficient and the associated drilling costs were expensed.

Operations in Malaysia reported earnings of $205.2 million in the 2013 quarter compared to earnings of $224.1 million during the same period in 2012. Earnings in 2013 were below 2012 levels in Malaysia primarily due to lower natural gas sales prices and lower sales volumes for gas fields offshore Sarawak. Production expense was lower in the 2013 period by $2.6 million primarily due to lower workover costs at the Kikeh field partially offset by higher expenses for planned maintenance at the Sarawak onshore gas receiving facility. Depreciation expense was $21.2 million more in the 2013 quarter due to higher capital amortization unit rates partially offset by lower overall natural gas sales volumes.

Operations in Republic of the Congo had a loss of $14.8 million in the first quarter of 2013 compared to income of $1.6 million in the 2012 quarter. Production expense in 2013 was $58.9 million more than the prior year due to higher charges for ongoing production operations and costs of $11.3 million for a well workover. A significant Azurite field oil well went off production in the first quarter of 2012, which led to reduced daily production for the field in the last nine months of 2012 and the first quarter of 2013 compared to prior periods. With the lower production levels, the Company sells only about one oil cargo per year, whereas in earlier periods sales generally occurred each quarter. Although oil sales volumes were only slightly higher in 2013 than in 2012, production expense for the 2013 quarter increased more dramatically as the current quarter included costs associated with approximately 12 months of production operations, while the 2012 period included costs for approximately on calendar quarter of operations. The 2013 quarter had no depreciation expense due to the write-off of the remaining property costs for the Azurite field in 2012.

Other international operations reported a loss of $65.6 million in the first quarter of 2013 compared to a loss of $36.8 million in the 2012 period. The unfavorable variance in the current quarter was primarily associated with higher costs for unsuccessful exploratory drilling costs and acquisition of geophysical data in 2013. Dry hole expense of $9.4 million in 2013 included unsuccessful drilling costs at a shallow-water prospect in Cameroon and final costs for the previously drilled Eupheme well offshore Australia. Higher geophysical costs in 2013 were primarily associated with seismic data and other studies in Australia, Cameroon and Indonesia.

On a worldwide basis, the Company’s crude oil, condensate and gas liquids sales prices averaged $96.00 per barrel in the first quarter 2013 compared to $97.78 in the 2012 period. Total hydrocarbon production averaged 201,876 barrels of oil equivalent per day in the 2013 first quarter, up from 195,096 barrels equivalent per day produced in the 2012 quarter. Average crude oil and liquids production was 126,888 barrels per day in the first quarter of 2013 compared to 107,490 barrels per day in the first quarter of 2012, with the 18% increase primarily attributable to higher production in the Eagle Ford Shale area in South Texas, where an ongoing development program continues. Oil production in the Gulf of Mexico also increased in 2013 due to additional working interests acquired in late 2012 at the Thunder Hawk and Front Runner fields. Synthetic crude oil production was lower in 2013 primarily due to less reliable operations in the current quarter. Crude oil production in Malaysia was higher in 2013 due to a late 2012 production start up at the Kakap field, offshore Sabah. Oil production in the Republic of Congo at the Azurite field was lower in 2013 due to field decline and a well that went off production during the 2012 first quarter. North American natural gas sales prices averaged $3.11 per thousand cubic feet (MCF) in the 2013 quarter compared to $2.56 per MCF in the same quarter of 2012. Natural gas produced in 2013 at fields offshore Sarawak was sold at $6.82 per MCF, compared to a sale price of $7.80 per MCF in the 2012 quarter. Natural gas sales volumes averaged almost 450 million cubic feet per day in the first quarter 2013, down from 525 million cubic feet per day in the 2012 quarter. The 14% reduction in natural gas sales volumes in 2013 was primarily due to lower natural gas production at the Tupper and Tupper West areas in British Columbia in the 2013 quarter. Development drilling activities in the Tupper area have been voluntarily curtailed for the last several months due to weak North American gas sales prices. Additionally, 2013 natural gas sales volumes from fields offshore Sarawak were below 2012 levels primarily due to planned maintenance at our gas receiving facility.

Additional details about results of oil and gas operations are presented in the tables on page 20.

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, 2013 and 2012 follow.


	Three Months Ended March 31,
	2013		2012
Net crude oil, condensate and gas liquids produced – barrels per day		126,888		107,490
Continuing operations		125,239		104,419
United States		40,062		20,280
Canada – light		228		205
– heavy		8,519		8,406
– offshore		9,243		9,377
– synthetic		12,417		13,311
Malaysia		53,355		49,959
Republic of the Congo		1,415		2,881
Discontinued operations – United Kingdom		1,649		3,071
Net crude oil, condensate and gas liquids sold – barrels per day		131,479		108,562
Continuing operations		129,925		105,427
United States		40,062		20,280
Canada – light		228		205
– heavy		8,519		8,406
– offshore		7,943		8,619
– synthetic		12,417		13,311
Malaysia		53,914		48,703
Republic of the Congo		6,842		5,903
Discontinued operations – United Kingdom		1,554		3,135
Net natural gas sold – thousands of cubic feet per day		449,925		525,635
Continuing operations		447,014		521,894
United States		59,484		51,231
Canada		191,799		242,285
Malaysia – Sarawak		149,083		184,635
– Kikeh		46,648		43,743
Discontinued operations – United Kingdom		2,911		3,741

Total net hydrocarbons produced – equivalent barrels per day (1)		201,876		195,096
Total net hydrocarbons sold – equivalent barrels per day (1)		206,467		196,168

Weighted average sales prices Crude oil, condensate and natural gas liquids – dollars per barrel (2)
United States	$	106.53		110.08
Canada (3) – light		81.91		91.40
– heavy		28.04		51.14
– offshore		111.44		118.39
– synthetic		94.30		96.95
Malaysia (4)		94.44		94.74
Republic of the Congo (4)		112.89		107.26
Discontinued operations – United Kingdom		113.19		120.01
Natural gas – dollars per thousand cubic feet
United States (2)	$	3.51		2.64
Canada (3)		2.99		2.54
Malaysia – Sarawak (4)		6.82		7.80
– Kikeh		0.24		0.24
Discontinued operations – United Kingdom (3)		12.30		9.58

(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)


			Canada
(Millions of dollars)	United States		Conventional			Synthetic		Malaysia			Republic of the Congo		Other			Total
Three Months Ended March 31, 2013
Oil and gas sales and other operating revenues	$	408.9		155.4			105.4		560.0			69.5		(.2	)		1,299.0
Production expenses		90.4		43.4			56.0		86.6			75.9		—			352.3
Depreciation, depletion and amortization		130.4		81.5			13.7		133.9			—		1.2			360.7
Accretion of assets retirement obligations		3.3		1.5			2.7		3.3			1.1		—			11.9
Exploration expenses
Dry holes		.7		30.5			—		.4			—		9.4			41.0
Geological and geophysical		12.7		.1			—		.3			—		26.4			39.5
Other		1.5		.3			—		—			.1		10.7			12.6

		14.9		30.9			—		.7			.1		46.5			93.1
Undeveloped lease amortization		6.1		5.3			—		—			—		4.0			15.4

Total exploration expenses		21.0		36.2			—		.7			.1		50.5			108.5

Selling and general expenses		16.1		6.4			.2		.5			.5		13.7			37.4

Results of operations before taxes		147.7		(13.6)			32.8		335.0			(8.1)		(65.6)			428.2
Income tax provisions (benefits)		53.9		(2.8	)		8.7		129.8			6.7		—			196.3

Results of operations (excluding corporate overhead and interest)		$93.8		(10.8)			24.1		205.2			(14.8)		(65.6)			231.9


Three Months Ended March 31, 2012
Oil and gas sales and other operating revenues	$	221.1		189.4			117.6		564.0			57.6		—			1,149.7
Production expenses		48.5		44.4			52.6		89.2			17.0		—			251.7
Depreciation, depletion and amortization		63.0		77.2			13.3		112.7			33.8		.6			300.6
Accretion of assets retirement obligations		2.8		1.3			2.0		2.9			.2		—			9.2
Exploration expenses
Dry holes		—		.8			—		—			—		(.2	)		.6
Geological and geophysical		.2		4.2			—		(.1	)		.1		6.9			11.3
Other		3.9		.2			—		—			.2		8.1			12.4

		4.1		5.2			—		(.1	)		.3		14.8			24.3
Undeveloped lease amortization		11.1		7.1			—		—			—		10.4			28.6

Total exploration expenses		15.2		12.3			—		(.1	)		.3		25.2			52.9

Selling and general expenses		12.1		4.1			.2		.3			.9		11.0			28.6

Results of operations before taxes		79.5		50.1			49.5		359.0			5.4		(36.8	)		506.7
Income tax provisions		28.7		13.8			12.5		134.9			3.8		—			193.7

Results of operations (excluding corporate overhead and interest)	$	50.8		36.3			37.0		224.1			1.6		(36.8	)		313.0

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

Results of Operations (Contd.)

Refining and Marketing

The Company has announced its intention to separate its U.S. retail marketing business into a separate publicly owned company. The Company has also announced its intention to sell its U.K. refining and marketing operations. The separation process for the U.S. retail marketing business and the sale process for the U.K. downstream operations continue to progress.

The United States downstream 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)	2013			2012
Refining and marketing – continuing operations
United States	$	29.4			(7.2	)
United Kingdom		(4.1	)		3.0

Total	$	25.3			(4.2	)

United States downstream results from continuing operations improved from a loss of $7.2 million in the 2012 first quarter to a profit of $29.4 million in the 2013 quarter. The favorable 2013 result was primarily due to stronger U.S. marketing results compared to the prior year’s quarter. U.S. retail margins averaged $0.110 per gallon in 2013 and $0.071 per gallon in 2012. The Company closed the first quarter 2013 with 1,172 retail stations in the U.S., an increase of 39 sites compared to a year ago. The Company signed a contract with Walmart Stores in late 2012 that will provide access to more than 200 additional station sites at Walmart Supercenters over the next three years. Overall, the retail fuel business sold 1.8% more fuel volume in the 2013 quarter compared to 2012, but volume on a per-store basis in the 2013 quarter was 1.5% below 2012. Sales volumes were adversely affected by one less calendar day in the 2013 quarter. Total margin on sales of merchandise was about 1% lower in 2013 compared to 2012, primarily due to less sales volumes, mostly caused by one less day in the current quarter, and weaker average sales prices for cigarettes in the current period. Operating results for other marketing operations in the U.S. also improved in 2013 compared to the prior year due to both higher per gallon margins for fuel moved through product terminals and higher prices for ethanol renewable identification numbers (RINs) sold in 2013. Earnings from ethanol production operations were slightly higher in 2013 than 2012, primarily due to improved sales prices for dried distillers grain at the Hankinson, North Dakota plant, which more than offset weaker ethanol crush spreads at the Hereford, Texas plant in the current year.

Refining and marketing operations in the United Kingdom had a net loss of $4.1 million in the first quarter of 2013 compared to income of $3.0 million in the same quarter of 2012. The U.K. results in 2013 were unfavorably affected compared to 2012 by weaker margins at the Milford Haven, Wales refinery in the current quarter. The U.K. refining and marketing operations had a negative net margin of $0.03 per barrel in 2013, unfavorable to the positive margin of $0.79 per barrel in 2012. Crude oil throughput volumes at the Milford Haven refinery were also lower at 112,411 barrels per day during the 2013 quarter compared to throughputs of 127,001 barrels per day in the 2012 quarter. The Milford Haven refinery had certain units down for scheduled maintenance in the 2013 quarter. U.K. marketing operating results were stronger during 2013 than in the prior year due to improved margins for retail station and wholesale fuel operations.

Worldwide petroleum product sales were 424,072 barrels per day in the 2013 quarter, down from 450,527 barrels per day a year ago. The decrease in 2013 sales volumes compared to the prior year was attributable to lower U.S. fuel sales volumes through product terminals, plus lower motor fuel production available for sale in the U.K. due to planned maintenance carried out at the Milford Haven refinery.

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, 2013 and 2012 follow.


	Three Months Ended March 31,
	2013			2012
United States retail marketing:
Fuel margin per gallon*	$	0.110		$	0.071
Gallons sold per store month		250,952			254,806
Merchandise sales revenue per store month	$	146,986		$	152,923
Merchandise margin as a percentage of merchandise sales		12.9	%		13.0	%
Store count at end of period (Company operated)		1,172			1,133

United Kingdom refining and marketing – unit margins per barrel	$	(0.03	)	$	0.79

Petroleum products sold – barrels per day		424,072			450,527
United States		305,794			319,976
Gasoline		264,765			274,391
Kerosine		192			216
Diesel and home heating oils		40,837			45,369
United Kingdom		118,278			130,551
Gasoline		44,510			44,679
Kerosine		15,105			15,872
Diesel and home heating oils		42,031			43,683
Residuals		12,698			15,698
LPG and other		3,934			10,619

U.K. refinery inputs – barrels per day		115,768			130,750
Milford Haven, Wales – crude oil		112,411			127,001
– other feedstocks		3,357			3,749

U.K. refinery yields – barrels per day		115,768			130,750
Gasoline		40,420			44,573
Kerosine		15,465			16,089
Diesel and home heating oils		40,604			40,340
Residuals		12,135			15,586
LPG and other		4,160			10,593
Fuel and loss		2,984			3,569

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

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

Results of Operations (Contd.)

Corporate

Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had net costs of $49.2 million in the 2013 first quarter compared to net costs of $27.3 million in the first quarter of 2012. The results for corporate activities were unfavorable in 2013 compared to 2012 primarily due to higher expenses associated with administration and debt financing in the just completed quarter. The Company also incurred after-tax losses of $4.1 million in the 2013 quarter on transactions denominated in foreign currencies compared to after-tax losses of $1.5 million in the 2012 quarter. Higher administrative costs in 2013 were primarily associated with overall employee compensation and professional fees associated with the upcoming separation of the U.S. retail marketing business. The Company’s net interest expense increased in 2013 due to higher average borrowing levels partially offset by larger amounts of interest costs capitalized to oil field development projects.

Discontinued Operations

The Company sold two U.K. oil and gas properties in the first quarter 2013. See Note D of the consolidated financial statements for further information. The Company has accounted for U.K. oil and gas assets as discontinued operations in all periods presented. Income from discontinued operations was $152.6 million in the first three months of 2013, compared to income of $8.6 million in the 2012 quarter. The 2013 quarter included a $147.4 million after-tax gain on disposal of the two properties. The one remaining field at Mungo/Monan is expected to be sold in the second quarter 2013.

Financial Condition

Net cash provided by operating activities was $921.1 million for the first three months of 2013 compared to $991.0 million during the same period in 2012. Cash provided by operating activities of discontinued operations was $13.9 million and $13.4 million in the 2013 and 2012 periods, respectively. Changes in operating working capital other than cash and cash equivalents provided cash of $211.5 million in the first three months of 2013, compared to cash provided of $301.1 million in the first three months of 2012. Cash was provided by working capital in 2013 primarily due to a combination of higher income taxes payable and lower accounts receivable at March 31, 2013 compared to December 31, 2012. Cash of $130.4 million in the 2013 period and $507.3 million in 2012 was generated from maturity of Canadian government securities that had maturity dates greater than 90 days at time of acquisition. The sale of two oil and gas properties in the United Kingdom provided cash proceeds of $211.5 million in the 2013 quarter.

Significant uses of cash in both years were for dividends, which totaled $59.7 million in 2013 and $53.4 million in 2012, and for property additions and dry holes, which including amounts expensed, were $1,035.0 million and $561.7 million in the three-month periods ended March 31, 2013 and 2012, respectively. The purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $230.3 million in the 2013 period and $469.6 million in the 2012 period. Cash used for property additions and other investing activities of discontinued operations totaled $8.0 million in 2013 and $5.6 million in 2012. Total accrual basis capital expenditures were as follows:


	Three Months Ended March 31,
(Millions of dollars)	2013		2012
Capital expenditures – continuing operations
Exploration and production	$	966.0		706.7
Refining and marketing		70.4		22.8
Corporate and other		3.8		1.8

Total capital expenditures – continuing operations	$	1,040.2		731.3

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

Financial Condition (Contd.)

A reconciliation of property additions and dry hole costs in the Consolidated Statements of Cash Flows to total capital expenditures for continuing operations follows.


	Three Months Ended March 31,
(Millions of dollars)	2013			2012
Property additions and dry hole costs per cash flow statements	$	1,035.0			561.7
Geophysical and other exploration expenses		52.1			23.7
Capital expenditure accrual changes		(46.9	)		145.9

Total capital expenditures – continuing operations	$	1,040.2			731.3

Working capital (total current assets less total current liabilities) at March 31, 2013 was $826.7 million, an increase of $127.2 million from December 31, 2012. 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 $623.7 million below fair value at March 31, 2013.

At March 31, 2013, long-term notes payable of $2,507.3 million had increased $262.1 million from December 31, 2012. A summary of capital employed at March 31, 2013 and December 31, 2012 follows.


(Millions of dollars)	March 31, 2013					Dec. 31, 2012
Capital employed	Amount		%			Amount		%
Long-term debt	$	2,507.3		21.5	%	$	2,245.2		20.1	%
Stockholders’ equity		9,138.5		78.5			8,942.0		79.9

Total capital employed	$	11,645.8		100.0	%	$	11,187.2		100.0	%

The Company’s ratio of earnings to fixed charges was 11.0 to 1 for the three-month period ended March 31, 2013.

Cash and invested cash are maintained in several operating locations outside the United States. At March 31, 2013, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included approximately $290 million in Canada, $181 million in the U.K. and $758 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 United States.

Accounting and Other Matters

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

Accounting and Other Matters (Contd.)

The United States Congress passed the Dodd-Frank Act (the Act) in 2010. As mandated by the Act, the U.S. Securities and Exchange Commission (SEC) has recently issued rules regarding annual disclosures for purchases of “conflict minerals” and payments made to the U.S. Federal and all foreign governments by extractive industries, including oil and gas companies. These two rules are described below.

•

“Conflict minerals”’ are defined as tin, tantalum, tungsten and gold which originate from the Democratic Republic of Congo or adjoining countries. The Company is currently investigating whether its activities will require an annual “conflict minerals” filing. If applicable, the first annual report for conflict minerals must be filed by May 31, 2014 for the calendar year of 2013.

•

Due to its activities as a worldwide exploration company and a producer of oil and natural gas in several countries, the Company will be required to report annual payments made to the U.S. Federal and all foreign governments. The recent SEC rules require disclosures of (a) the type and total amount of payments made for each project associated with extraction activities, and (b) the type and total amount of payments made to each government. The types of payments covered by the rules include taxes, royalties, fees, production entitlements, bonuses and other material benefits that are part of the commonly recognized revenue stream for oil and gas companies. The annual disclosure filing must be made within 150 days of the fiscal year-end (May 30, 2014 for the 2013 filing) and will first be required for fiscal years ending after September 30, 2013. The transition rules for 2013 allow Murphy’s first filing to disclose payments for the period from October 1 to December 31, 2013. The oil and gas industry has challenged in U.S. Federal court the rules set forth by the SEC. The Company cannot predict the outcome of this court challenge.

Outlook

Average crude oil prices in April 2013 weakened compared to the average price during the first quarter of 2013 due to concerns about global economic growth, particularly in China and other Asian countries. North American natural gas prices, however, strengthened in April 2013 principally due to cooler than normal spring temperatures across much of the continent. The Company expects its total oil and natural gas production to average about 202,000 barrels of oil equivalent per day in the second quarter 2013. U.S. retail marketing margins improved in April versus the average margins achieved in the first quarter 2013. The Company currently anticipates total capital expenditures for the full year 2013 to be approximately $4.4 billion.

The Company will primarily fund its capital program in 2013 using operating cash flow, but will supplement funding where necessary using borrowings under available credit facilities. The Company’s 2013 budget calls for borrowings of long-term debt during the year to fund a portion of the capital program. If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that higher than anticipated borrowings might be required during the year to maintain funding of the Company’s ongoing development projects. Additionally, the 2013 budget assumes further share repurchases under the previously announced share buyback program of up to $1.0 billion. Through March 31, 2013, the Company had funded a $250 million accelerated share repurchase program with a major financial institution. The level of these share repurchases is expected to influence the amount of borrowings under credit facilities during 2013.

The Company has announced that it plans to exit the U.K. refining and marketing business. The sale process for this U.K. business continues to progress in early 2013. Should the Company be unable to sell its U.K. refining and marketing assets on acceptable terms, this could require additional borrowings under credit facilities during 2013.

In 2012, the Company announced its intention to separate its U.S. retail marketing business into a stand-alone publicly owned company. At the present time, this separation is expected to be completed in 2013. The Company expects that the stand-alone U.S. retail marketing business will have outstanding debt and will provide Murphy Oil Corporation with a cash dividend upon separation. The level of this cash dividend also could influence the amount of debt outstanding for Murphy Oil during 2013.

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

Outlook (Contd.)

After the anticipated separation of the U.S. retail marketing business from Murphy Oil Corporation during 2013, and the desired sale of the U.K. downstream business, the Company is expected to be fundamentally different. The Company will have significantly lower sales revenue as the U.S. and U.K. businesses generated about 80% of Murphy’s consolidated revenue during the first quarter 2013. For the first quarter 2013, the combined U.S. and U.K. businesses generated about 10% of income from continuing operations before considering unallocated corporate net costs. Also, the two businesses made up about 82% of the Company’s workforce at March 31, 2013. The Company also anticipates that without these operations, it may no longer qualify as a member of the Fortune 500 group of companies. Murphy Oil is anticipated to be an independent oil and gas company in the future and will not have a significant refining and marketing business as a diversification to its oil and gas business. This decrease in size and change in diversification could impact its credit rating, and could, although not expected to, impact its ability to repay long-term debt obligations when due.

As noted above, crude oil sales prices weakened in April 2013. Should these prices continue to weaken in the future, it is possible that certain investments in oil 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 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, customer demand for our products, adverse foreign exchange movements, political and regulatory instability, and uncontrollable natural hazards. Factors that could cause the forecasted separation of its U.S. retail marketing business, as discussed in this Form 10-Q, not to occur include, but are not limited to, a failure to obtain necessary regulatory approvals, a failure to obtain assurances of anticipated tax treatment, a deterioration in the business or prospects of Murphy or its U.S. retail marketing business, adverse developments in Murphy or its U.S. retail marketing business’ markets, and adverse developments in the U.S. or global capital markets, credit markets or economies generally. Additionally, the Company may be unable to sell its U.K. downstream business as it desires to do because it may fail to execute a sale of these operations on acceptable terms. For further discussion of risk factors, see Murphy’s 2012 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, 2013 to hedge the purchase price of corn and the sales prices 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 increased the recorded net liability associated with these derivative contracts by approximately $1.7 million, while a 10% decrease would have reduced 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, 2013 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 increased the recorded net liability associated with these contracts by approximately $26.9 million, while a 10% weakening of the U.S. dollar would have decreased the recorded net liability by approximately $31.5 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, 2013 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, a subsidiary of 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 had issued a civil penalty notice of approximately $1.7 million. In March 2013, the EA withdrew its penalty notice and the matter was closed.

In March 2013, a subsidiary of the Company paid a fine amounting to $151,250 to the U.S. Department of Transportation for violations of the pipeline and hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS) of 49 C.F.R.R. Part 195 from an on-site pipeline safety inspection of its former Superior, Wisconsin refinery. The subsidiary had recorded an expense related to this fine in a prior year.

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 2012 Form 10-K filed on February 28, 2013. The Company has not identified any additional risk factors not previously disclosed in its 2012 Form 10-K report.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Murphy Oil Corporation

Issuer Purchases of Equity Securities


Period	Total Number of Shares Purchased*		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs*
January 1, 2013 to January 31, 2013		—	$	—		—	$	750,000,000
February 1, 2013 to February 28, 2013		—		—		—		750,000,000
March 1, 2013 to March 31, 2013		—		—		—		750,000,000

Total January 1, 2013 to March 31, 2013		—		—		—		750,000,000

On October 16, 2012, the Company announced that its Board of Directors had authorized a buyback of up to $1.0 billion of the Company’s Common stock. On December 10, 2012, the Company announced that it had entered into a variable term, capped accelerated share repurchase transaction (ASR) with a major financial institution to repurchase an aggregate of $250 million of the Company’s Common stock. The total aggregate number of shares repurchased pursuant to this ASR will be determined by reference to the Rule 10b-18 volume-weighted price of the Company’s Common stock, less a fixed discount, over the term of the ASR, subject to a minimum number of shares. The ASR is expected to be completed in May 2013. Through March 31, 2013, the minimum amount of Common stock totaling 3,867,550 shares had been delivered to the Company pursuant to the ASR. Any remaining shares will be delivered to the Company upon the completion of the ASR program.

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, 2013

(Date)

EXHIBIT INDEX


Exhibit No.

12.1*		Computation of Ratio of Earnings to Fixed Charges

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

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

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

101. INS*		XBRL Instance Document

101. SCH*		XBRL Taxonomy Extension Schema Document

101. CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101. DEF*		XBRL Taxonomy Extension Definition Linkbase Document

101. LAB*		XBRL Taxonomy Extension Labels Linkbase Document

101. PRE*		XBRL Taxonomy Extension Presentation Linkbase

*	Filed herewith.

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