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10-Q 1 d707772d10q.htm FORM 10-Q 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, 2014

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

For the transition period from to

Commission File Number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)


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

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

(870) 862-6411

(Registrant’s telephone number, including area code)

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

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

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

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

Number of shares of Common Stock, $1.00 par value, outstanding at March 31, 2014 was 179,446,784.

MURPHY OIL CORPORATION

TABLE OF CONTENTS


	Page

Part I – Financial Information

Item 1. Financial Statements

Consolidated Balance Sheets		2

Consolidated Statements of Income		3

Consolidated Statements of Comprehensive Income		4

Consolidated Statements of Cash Flows		5

Consolidated Statements of Stockholders’ Equity		6

Notes to Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17

Item 3. Quantitative and Qualitative Disclosures About Market Risk		27

Item 4. Controls and Procedures		27

Part II – Other Information

Item 1. Legal Proceedings		27

Item 1A. Risk Factors		27

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, 2014			December 31, 2013
ASSETS
Current assets
Cash and cash equivalents	$	648,612			750,155
Canadian government securities with maturities greater than 90 days at the date of acquisition		372,003			374,842
Accounts receivable, less allowance for doubtful accounts of $1,609 in 2014 and 2013		1,007,125			999,872
Inventories, at lower of cost or market
Crude oil		38,104			40,077
Materials and supplies		255,132			254,118
Prepaid expenses		125,984			83,856
Deferred income taxes		55,146			61,991
Assets held for sale		871,453			943,732

Total current assets		3,373,559			3,508,643
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $8,850,951 in 2014 and $8,540,239 in 2013		13,654,991			13,481,055
Goodwill		38,702			40,259
Deferred charges and other assets		95,269			98,123
Assets held for sale		388,617			381,404

Total assets	$	17,551,138			17,509,484

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	30,647			26,249
Accounts payable and accrued liabilities		2,149,085			2,335,712
Income taxes payable		288,101			222,930
Liabilities associated with assets held for sale		589,011			639,140

Total current liabilities		3,056,844			3,224,031
Long-term debt, including capital lease obligation		3,415,621			2,936,563
Deferred income taxes		1,485,616			1,466,100
Asset retirement obligations		854,270			852,488
Deferred credits and other liabilities		337,957			339,028
Liabilities associated with assets held for sale		96,752			95,544
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 194,945,904 shares in 2014 and 194,920,155 shares in 2013		194,946			194,920
Capital in excess of par value		876,647			902,633
Retained earnings		8,157,972			8,058,792
Accumulated other comprehensive income		37,463			172,119
Treasury stock, 15,499,120 shares of Common Stock in 2014 and 11,513,642 shares of Common Stock in 2013, at cost		(962,950	)		(732,734	)

Total stockholders’ equity		8,304,078			8,595,730

Total liabilities and stockholders’ equity	$	17,551,138			17,509,484

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,
	2014			2013*
REVENUES
Sales and other operating revenues	$	1,281,208			1,298,928
Interest and other income (loss)		5,192			(7,990	)

Total revenues		1,286,400			1,290,938

COSTS AND EXPENSES
Lease operating expenses		262,255			337,223
Severance and ad valorem taxes		26,326			15,063
Exploration expenses, including undeveloped lease amortization		138,466			108,493
Selling and general expenses		92,026			81,467
Depreciation, depletion and amortization		396,249			363,142
Accretion of asset retirement obligations		12,065			11,896
Interest expense		32,886			27,028
Interest capitalized		(8,868	)		(13,388	)
Other expense		814			0

Total costs and expenses		952,219			930,924

Income from continuing operations before income taxes		334,181			360,014
Income tax expense		164,895			177,331

Income from continuing operations		169,286			182,683
Income (loss) from discontinued operations, net of taxes		(14,033	)		177,916

NET INCOME	$	155,253			360,599

INCOME PER COMMON SHARE – BASIC
Income from continuing operations	$	0.94			0.96
Income (loss) from discontinued operations		(0.08	)		0.93

Net income	$	0.86			1.89

INCOME PER COMMON SHARE – DILUTED
Income from continuing operations	$	0.93			0.95
Income (loss) from discontinued operations		(0.08	)		0.93

Net income	$	0.85			1.88

Average Common shares outstanding
Basic		181,367,565			190,810,201
Diluted		182,576,570			191,765,395

*	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,
	2014			2013
Net income	$	155,253			360,599
Other comprehensive loss, net of income taxes
Net loss from foreign currency translation		(136,604	)		(117,754	)
Retirement and postretirement benefit plan amounts reclassified to net income		1,465			2,738
Deferred loss on interest rate hedges reclassified to interest expense		483			486

Other comprehensive loss		(134,656	)		(114,530	)

COMPREHENSIVE INCOME	$	20,597			246,069

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,
	2014			2013¹
OPERATING ACTIVITIES
Net income	$	155,253			360,599
Adjustments to reconcile net income to net cash provided by operating activities:
Loss (income) from discontinued operations		14,033			(177,916	)
Depreciation, depletion and amortization		396,249			363,142
Amortization of deferred major repair costs		2,741			1,990
Dry hole costs		87,909			41,011
Amortization of undeveloped leases		12,830			15,390
Accretion of asset retirement obligations		12,065			11,896
Deferred and noncurrent income tax charges		23,167			25,326
Pretax gain from disposition of assets		(19	)		(42	)
Net decrease in noncash operating working capital		18,673			100,949
Other operating activities, net		2,973			(13,896	)

Net cash provided by continuing operations		725,874			728,449
Net cash provided by discontinued operations		10,005			192,678

Net cash provided by operating activities		735,879			921,127

INVESTING ACTIVITIES
Property additions and dry hole costs		(996,218	)		(965,412	)
Proceeds from sale of assets		26			0
Purchases of investment securities²		(240,802	)		(230,320	)
Proceeds from maturity of investment securities²		243,641			130,385
Investing activities of discontinued operations:
Sales proceeds		0			211,549
Other		(4,866	)		(82,264	)
Other – net		(3,736	)		2,122

Net cash required by investing activities		(1,001,955	)		(933,940	)

FINANCING ACTIVITIES
Borrowings of long-term debt		479,000			261,989
Purchase of treasury stock		(250,000	)		0
Proceeds from exercise of stock options		0			1,281
Withholding tax on stock-based incentive awards		(6,319	)		(7,337	)
Cash dividends paid		(56,073	)		(59,672	)
Other		(240	)		(91	)

Net cash provided by financing activities		166,368			196,170

Effect of exchange rate changes on cash and cash equivalents		(1,835	)		(13,568	)

Net increase (decrease) in cash and cash equivalents		(101,543	)		169,789
Cash and cash equivalents at January 1		750,155			947,316

Cash and cash equivalents at March 31	$	648,612			1,117,105

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,
	2014			2013
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued		0			0

Common Stock – par $1.00, authorized 450,000,000 shares, issued 194,945,904 shares at March 31, 2014 and 194,683,376 shares at March 31, 2013
Balance at beginning of period	$	194,920			194,616
Exercise of stock options		26			67

Balance at end of period		194,946			194,683

Capital in Excess of Par Value
Balance at beginning of period		902,633			873,934
Exercise of stock options, including income tax effects		(10,765	)		743
Restricted stock transactions and other		(26,400	)		(24,480	)
Stock-based compensation		11,190			16,903
Other		(11	)		(53	)

Balance at end of period		876,647			867,047

Retained Earnings
Balance at beginning of period		8,058,792			7,717,389
Net income for the period		155,253			360,599
Cash dividends		(56,073	)		(59,672	)

Balance at end of period		8,157,972			8,018,316

Accumulated Other Comprehensive Income
Balance at beginning of period		172,119			408,901
Foreign currency translation loss, net of income taxes		(136,604	)		(117,754	)
Retirement and postretirement benefit plan adjustments, net of income taxes		1,465			2,738
Change in deferred loss on interest rate hedges, net of income taxes		483			486

Balance at end of period		37,463			294,371

Treasury Stock
Balance at beginning of period		(732,734	)		(252,805	)
Purchase of treasury shares		(250,000	)		0
Sale of stock under employee stock purchase plans		132			337
Awarded restricted stock, net of forfeitures		19,652			16,545

Balance at end of period		(962,950	)		(235,923	)

Total Stockholders’ Equity	$	8,304,078			9,138,494

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, 2013. 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, 2014, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended March 31, 2014 and 2013, 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 2013 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, 2014 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, 2014, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $395.9 million. The following table reflects the net changes in capitalized exploratory well costs during the three-month periods ended March 31, 2014 and 2013.


(Thousands of dollars)	2014		2013
Beginning balance at January 1	$	393,030		445,697
Additions pending the determination of proved reserves		2,919		26,929
Reclassifications to proved properties based on the determination of proved reserves		0		(28,398	)

Balance at March 31	$	395,949		444,228

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
	2014						2013
(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	$	32,192		2		1		56,324		6		3
One to two years		56,702		6		1		40,721		3		1
Two to three years		31,224		2		0		79,446		8		2
Three years or more		275,831		22		7		267,737		24		5

	$	395,949		32		9		444,228		41		11

Of the $363.8 million of exploratory well costs capitalized more than one year at March 31, 2014, $213.8 million is in Malaysia, $116.2 million is in the U.S. and $33.8 million is in Brunei. In all three geographical areas either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note C – Inventories

Inventories are carried at the lower of cost or market. For the Company’s U.K. refining and marketing operations reported as discontinued operations, the cost of crude oil and finished products is predominantly determined on the last-in, first-out (LIFO) method. The U.K. inventories are reported within Current assets held for sale on the Consolidated Balance Sheet. At March 31, 2014 and December 31, 2013, the carrying values of inventories under the LIFO method were $201.6 million and $268.6 million, respectively, less than such inventories would have been valued using the first-in, first-out (FIFO) method.

Note D – Discontinued Operations

The Company has previously announced its intention to sell its U.K. refining and marketing operations. The Company has accounted for this U.K. downstream business as discontinued operations for all periods presented, including a reclassification of 2013 operating results and cash flows for this business to discontinued operations. The U.K. downstream operations were formerly reported as a separate segment within the Company’s refining and marketing business. The Company announced on April 3, 2014 the start of a consultation period with employees of the U.K. downstream subsidiary as to the future of this subsidiary and its Milford Haven refinery.

On August 30, 2013, Murphy Oil Corporation (the “Company”) distributed 100% of the outstanding common stock of Murphy USA Inc. (“MUSA”) to its shareholders in a generally tax-free spin-off for U.S. federal income tax purposes. Prior to the separation, MUSA held all of the Company’s U.S. downstream operations, including retail gasoline stations and other marketing assets, plus two ethanol production facilities. The shares of MUSA common stock are traded on the New York Stock Exchange under the ticker symbol “MUSA.” The Company has no continuing involvement with MUSA operations. Accordingly, the operating results and the cash flows for these former U.S. downstream operations have been reported as discontinued operations in the 2013 consolidated financial statements.

The Company also 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 U.K. oil and gas assets was $147.4 million in the three months ended March 31, 2013. The Company has accounted for these U.K. upstream operations as discontinued operations in its 2013 consolidated financial statements.

The results of operations associated with these discontinued operations for the three-month periods ended March 31, 2014 and 2013 were as follows:


	Three Months
	Ended March 31,
(Thousands of dollars)	2014			2013
Revenues	$	1,432,386			5,515,538

Income (loss) before income taxes, including a gain on disposal of $74,928 in 2013	$	(17,295	)		132,921
Income tax benefit		(3,262	)		(44,995	)

Income (loss) from discontinued operations	$	(14,033	)		177,916

Note E – Financing Arrangements and Debt

The Company has a $2.0 billion committed credit facility that expires in June 2017. Borrowings under the facility bear interest at 1.25% above LIBOR based on the Company’s current credit rating as of March 31, 2014. In addition, facility fees of 0.25% are charged on the full $2.0 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)	2014			2013
Net (increase) decrease in operating working capital other than cash and cash equivalents (from continuing operations):
Decrease (increase) in accounts receivable	$	(7,251	)		49,060
Decrease in inventories		958			17,089
Increase in prepaid expenses		(42,128	)		(53,970	)
Decrease in deferred income tax assets		6,845			27,427
Decrease in accounts payable and accrued liabilities		(4,923	)		(66,680	)
Increase in current income tax liabilities		65,172			128,023

Total	$	18,673			100,949

Supplementary disclosures (including discontinued operations):
Cash income taxes paid	$	101,295			47,877
Interest paid less than amounts capitalized		(4,303	)		(10,519	)

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.

Effective with the spin-off of Murphy’s former U.S. retail marketing operation, Murphy USA Inc. (MUSA) on August 30, 2013, significant modifications were made to the U.S. defined benefit pension plan. Certain Murphy employees’ benefits under the U.S. plan were frozen at that time. No further benefit service will accrue for the affected employees; however, the plan will recognize future eligible earnings after the spin-off date. In addition, all previously unvested benefits became fully vested at the spin-off date. For those affected active employees of the Company, additional U.S. retirement plan benefits will accrue in future periods under a cash balance formula. Upon the spin-off of MUSA, Murphy retained all vested pension defined benefit and other postretirement benefit obligations associated with current and former employees of this separated business. No additional benefit will accrue for any employees of MUSA under the Company’s retirement plan after the spin-off date.

The table that follows provides the components of net periodic benefit expense for the three-month periods ended March 31, 2014 and 2013.


	Three Months Ended March 31,
							Other
	Pension Benefits						Postretirement Benefits
(Thousands of dollars)	2014			2013			2014			2013
Service cost	$	6,556			7,603			672			1,167
Interest cost		8,215			6,431			1,278			1,234
Expected return on plan assets		(8,480	)		(5,700	)		0			0
Amortization of prior service cost		225			276			(21	)		(42	)
Amortization of transitional liability		208			120			1			2
Recognized actuarial loss		1,733			3,532			59			457

Net periodic benefit expense	$	8,457			12,262			1,989			2,818

During the three-month period ended March 31, 2014, the Company made contributions of $10.6 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2014 for the Company’s defined benefit pension and postretirement plans is anticipated to be $31.9 million.

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 4, 2014, the Committee granted stock options for 772,900 shares at an exercise price of $55.82 per share. The Black-Scholes valuation for these awards was $12.84 per option. The Committee also granted 464,300 performance-based restricted stock units (RSU) and 233,400 time-based RSU on that date. The fair value of the performance-based RSU, using a Monte Carlo valuation model, ranged from $33.90 to $51.30 per unit. The fair value of time-based RSU was estimated based on the fair market value of the Company’s stock on the date of grant, which was $55.82. Additionally, on February 4, 2014, the Committee granted 183,200 SAR and 170,900 units of cash-settled RSU (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 value of these SAR was equivalent to the stock options granted, while the initial value of RSU-C was equivalent to equity-settled restricted stock units granted. On February 5, 2014, the Committee granted 43,848 shares of time-based RSU 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 at $55.20 per unit.

Beginning January 1, 2014, all stock option exercises are non-cash transactions for the Company. The employee will receive net shares, after applicable withholding taxes, upon each exercise. Cash received from options exercised under all share-based payment arrangements for the three-month period ended March 31, 2013 was $1.3 million. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $0.7 million and $1.4 million for the three-month periods ended March 31, 2014 and 2013, 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)	2014		2013
Compensation charged against income before tax benefit	$	15,301		17,833
Related income tax benefit recognized in income		4,733		4,922

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Earnings per Share

Net income was used as the numerator in computing both basic and diluted income per Common share for the three-months ended March 31, 2014 and 2013. The following table reconciles the weighted-average shares outstanding used for these computations.


	Three Months Ended March 31,
(Weighted-average shares)	2014		2013
Basic method		181,367,565		190,810,201
Dilutive stock options and restricted stock units		1,209,005		955,194

Diluted method		182,576,570		191,765,395

The following table reflects certain options to purchase shares of common stock that were outstanding during the 2014 and 2013 periods but were not included in the computation of diluted EPS above because the incremental shares from assumed conversion were antidilutive.


	Three Months Ended March 31,
	2014		2013
Antidilutive stock options excluded from diluted shares		1,555,015		3,794,002
Weighted average price of these options	$	58.97	$	62.18

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 2014 and 2013, the Company’s effective income tax rates were as follows:


	2014			2013
Three months ended March 31		49.3	%		49.3	%

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, 2014, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2010; Canada – 2008; United Kingdom – 2011; and Malaysia – 2006.

Note K – Financial Instruments and Derivatives

Murphy 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 unrealized 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 loss associated with settlement of these contracts was deferred in Accumulated Other Comprehensive Income. This loss is being amortized as Interest Expense in the Consolidated Statements of Income.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Financial Instruments and Derivatives (Contd.)

Commodity Purchase Price Risks

The Company is subject to commodity price risk related to crude oil it will produce and sell in 2014. The Company has entered into a series of West Texas Intermediate (WTI) crude oil fixed-price swap financial contracts covering a portion of its Eagle Ford Shale production from April 2014 through December 2014. Under these contracts, which mature monthly, the Company will pay the average monthly price in effect and will receive the fixed contract prices. WTI open contracts at March 31, 2014 were as follows:


Dates	Volumes (barrels per day)		Swap Prices
April – June 2014		24,000	$	96.41 per barrel
July – September 2014		20,000	$	94.32 per barrel
October – December 2014		12,000	$	91.72 per barrel

The fair value of these open commodity derivative contracts was a net liability of $18.8 million at March 31, 2014. Subsequent to March 31, 2014 additional contracts have been executed. See page 26 of this Form 10-Q report.

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, 2014 and 2013 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, 2014 and 2013 were approximately $133.5 million and $274.0 million, respectively. Short-term derivative instrument contracts totaling $23.0 million and $20.0 million U.S. dollars were also outstanding at March 31, 2014 and 2013, respectively, to manage the risk of certain U.S. dollar accounts receivable associated with sale of crude oil production in Canada. The impact from marking to market these foreign currency derivative contracts increased income before taxes by $3.4 million for the three-month period ended March 31, 2014 and reduced income before taxes by $2.7 million for the three-month period ended March 31, 2013.

At March 31, 2014 and December 31, 2013, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

March 31, 2014

December 31, 2013

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity

Accounts payable

(21,367

)

Accounts receivable

1,970

Foreign currency

Accounts receivable

3,411

Accounts payable

(1,038

)

For the three-month periods ended March 31, 2014 and 2013, 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)
		Three Months Ended
(Thousands of dollars)	Statement of Income	March 31,
Type of Derivative Contract	Location	2014			2013
Commodity	Sales and other operating revenues	$	(18,414	)		0
Commodity	Discontinued operations		0			(4,210	)
Foreign currency	Interest and other income (loss)		3,436			(2,818	)

		$	(14,978	)		(7,028	)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Financial Instruments and Derivatives (Contd.)

Interest Rate Risks

In 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps to manage interest rate risk associated with $350 million of 10-year notes that were sold in May 2012. These interest rate swaps matured in May 2012. Under hedge accounting rules, the Company deferred a loss on these contracts to match the payment of interest on these notes through 2022. During each of the three-month periods ended March 31, 2014 and 2013, $0.7 million of the deferred loss on the interest rate swaps was charged to Interest Expense in the Consolidated Statements of Income. The remaining loss deferred on these matured contracts at March 31, 2014 was $24.1 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 2014.

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

The carrying value of assets and liabilities recorded at fair value on a recurring basis at March 31, 2014 and December 31, 2013 are presented in the following table.


	March 31, 2014								December 31, 2013
(Thousands of dollars)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Commodity derivative contracts	$	0		0		0		0		0		1,970		0		1,970
Foreign currency exchange derivative contracts		0		3,411		0		3,411		0		0		0		0

	$	0		3,411		0		3,411		0		1,970		0		1,970

Liabilities:
Nonqualified employee savings plans	$	13,393		0		0		13,393		13,267		0		0		13,267
Commodity derivative contracts		0		21,367		0		21,367		0		0		0		0
Foreign currency exchange derivative contracts		0		0		0		0		0		1,038		0		1,038

	$	13,393		21,367		0		34,760		13,267		1,038		0		14,305

The fair value of West Texas Intermediate (WTI) crude oil derivative contracts was determined based on active market quotes for WTI crude oil at the balance sheet dates. The fair value of foreign exchange derivative contracts was based on market quotes for similar contracts at the balance sheet dates. The income effect of changes in the fair value of crude oil derivative contracts is recorded in Sales and Other Operating Revenues 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 in the Consolidated Statements of Income.

The Company offsets certain assets and liabilities related to derivative contracts when the legal right of offset exists. There were no offsetting positions recorded at March 31, 2014 and December 31, 2013.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Accumulated Other Comprehensive Income

The components of Accumulated Other Comprehensive Income (AOCI) on the Consolidated Balance Sheets at March 31, 2014 and December 31, 2013 and the changes during the three months ended March 31, 2014 are presented net of taxes in the following table.


	Foreign Currency Translation Gains (Losses)¹			Retirement and Postretirement Benefit Plan Adjustments¹			Deferred Loss on Interest Rate Derivative Hedges¹			Total¹
(Thousands of dollars)
Balance at December 31, 2013		305,192			(116,956	)		(16,117	)		172,119
Components of other comprehensive income (loss):
Before reclassifications to income		(136,604	)		236			0			(136,368	)
Reclassifications to income		0			1,229	²		483	³		1,712

Net other comprehensive income (loss)		(136,604	)		1,465			483			(134,656	)

Balance at March 31, 2014		168,588			(115,491	)		(15,634	)		37,463

¹	All amounts are presented net of income taxes.

Reclassifications before taxes of $1,878 for the three-month period ended March 31, 2014 are included in the computation of net periodic benefit expense. See Note G for additional information. Related income taxes of $649 for the three-month period ended March 31, 2014 are included in Income tax expense.

³	Reclassifications before taxes of $741 for the three-month period ended March 31, 2014 are included in Interest expense. Related income taxes of $258 for the three-month period ended March 31, 2014 are included in Income tax expense.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note M – Environmental and Other Contingencies (Contd.)

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. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. 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) formerly considered the Company to be a Potentially Responsible Party (PRP) at one Superfund site. Based on evidence provided by the Company, the EPA has determined that the Company is no longer considered a PRP at this site.

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.

Note N – Commitments

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2014 heavy oil and 2014 and 2015 natural gas sales volumes in Western Canada. The heavy oil blend sales contracts call for deliveries of 4,000 barrels per day in April through December 2014 that achieve netback values that average Cdn$55.14 per barrel. The natural gas contracts call for deliveries between April through December 2014 that average approximately 110 million cubic feet per day at prices averaging Cdn$4.04 per MCF, with the contracts calling for delivery at the NOVA inventory transfer sales point. The Company also has natural gas sales contracts calling for deliveries between January and December 2015 of approximately 65 million cubic feet per day at prices that average Cdn$4.13 per MCF. These oil and natural gas contracts have been accounted for as normal sales for accounting purposes.

Note O – New Accounting Principles

In April 2014, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update that changed the requirements for reporting discontinued operations. Under the new guidance, only disposals of components of an entity that represent a strategic shift that has or will have a major effect on an entity’s operations and financial results will be reported as discontinued operations in the financial statements. Under prior guidance, a component of an entity that is a reportable segment, an operating segment, a reporting unit, a subsidiary, or an asset group that has been or will be eliminated from ongoing operations and for which the Company will not have any significant continuing involvement with the component after the disposal was generally reported as discontinued operations. The FASB anticipates that fewer component disposals will be reported as discontinued operations under the new guidance. The new guidance also requires expanded disclosures about discontinued operations. The new guidance will be effective for the Company beginning in 2015. The new guidance is not to be applied to a component that is classified as held for sale before the effective date of the guidance.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Business Segments


			Three Months Ended					Three Months Ended
			March 31, 2014					March 31, 2013¹
(Millions of dollars)	Total Assets at March 31, 2014		External Revenues		Income (Loss)			External Revenues			Income (Loss)
Exploration and production²
United States	$	4,967.8		485.5		103.1			408.9			93.8
Canada		3,957.1		297.7		67.6			260.8			13.3
Malaysia		6,076.1		492.8		162.3			560.0			205.2
Other		142.9		0.0		(122.4	)		69.3			(80.4	)

Total exploration and production		15,143.9		1,276.0		210.6			1,299.0			231.9
Corporate		1,147.2		10.4		(41.3	)		(8.1	)		(49.2	)

Assets/revenue/income from continuing operations		16,291.1		1,286.4		169.3			1,290.9			182.7
Discontinued operations, net of tax		1,260.0		0.0		(14.0	)		0.0			177.9

Total	$	17,551.1		1,286.4		155.3			1,290.9			360.6

¹	Reclassified to conform to current presentation.

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

Due to the shutdown of production operations in Republic of the Congo, the Company now includes the results of these operations in the Other exploration and production segment in the above table.

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 2014 was $155.3 million ($0.85 per diluted share) compared to net income of $360.6 million ($1.88 per diluted share) in the first quarter of 2013. The 2014 results included a loss from discontinued operations of $14.0 million ($0.08 per diluted share) and the 2013 results included income from discontinued operations of $177.9 million ($0.93 per diluted share). Excluding discontinued operations, income from continuing operations was $169.3 million ($0.93 per diluted share) in the first quarter of 2014 compared to $182.7 million ($0.95 per diluted share) in the same quarter of 2013. The 2014 continuing operating results were below 2013 results primarily due to higher exploration costs of $30.0 million in the most recent quarter.

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


	Income (Loss)
	Three Months Ended March 31,
(Millions of dollars)	2014			2013
Exploration and production	$	210.6			231.9
Corporate and other		(41.3	)		(49.2	)

Income from continuing operations	$	169.3			182.7

In the 2014 first quarter, the Company’s exploration and production operations earned $210.6 million compared to $231.9 million in the 2013 quarter. Income in the 2014 quarter was favorably impacted by higher oil sales volumes, but this was more than offset by higher exploration costs in the current quarter. The corporate function had after-tax costs of $41.3 million in the 2014 first quarter compared to after-tax costs of $49.2 million in the 2013 period with the improvement in 2014 primarily due to more favorable effects from transactions dominated in foreign currencies.

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)	2014			2013
Exploration and production – continuing operations
United States	$	103.1			93.8
Canada		67.6			13.3
Malaysia		162.3			205.2
Other International		(122.4	)		(80.4	)

Total	$	210.6			231.9

United States exploration and production operations generated earnings of $103.1 million in the first quarter of 2014 compared to earnings of $93.8 million in the 2013 quarter. Earnings improved in 2014 primarily due to higher crude oil production and sales volumes compared to the prior year. 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, 2014, the Company employed eight drilling rigs in the Eagle Ford Shale. U.S. results also benefited in 2014 from higher natural gas sales prices, but results were unfavorably affected by lower oil sales prices, an unfavorable mark-to-market adjustment on open crude oil swap contracts related to the Eagle Ford Shale, and higher expenses for exploration and production-related activities. The Company recorded a non-cash, unrealized pretax charge of $18.4 million during the first quarter of 2014 associated with marking-to-market open West Texas Intermediate crude oil swaps contracts. While lease operating expenses were relatively flat with the prior year, production taxes and depreciation expense in the U.S. increased $11.0 million and $37.7 million, respectively, in 2014 compared to 2013 mostly due to higher production in the Eagle Ford Shale area. Exploration expenses in the 2014 quarter were $8.7 million above 2013 levels due to both carryover dry hole expense associated with a well drilled in 2013 and higher costs for seismic in the Gulf of Mexico. Selling and general expenses in the 2014 period increased $6.9 million from the prior year primarily due to higher costs for employee compensation, professional services and home office support.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Operations in Canada had earnings of $67.6 million in the first quarter 2014 compared to earnings of $13.3 million in the 2013 quarter. Canadian earnings increased in the 2014 quarter due to a combination of higher oil sales volumes at Terra Nova and Syncrude, higher sales prices for heavy oil and natural gas production and lower exploration expenses in the current period. Oil sales volume increased in the 2014 quarter compared to 2013 primarily due to higher production at Syncrude and the timing of sales transactions at Terra Nova. Natural gas sales volumes decreased in 2014 due to the Company voluntarily restricting development drilling in recent years in the Tupper and Tupper West areas due to historically weak gas sales prices in this region during recent years. Oil sales prices in 2014 were above the prior year in most areas of Canada, especially in the heavy oil area where sales prices were extremely weak during the 2013 quarter. Exploration expense in 2014 was $30.9 million below the prior year primarily due to dry hole costs recorded in 2013 associated with drilling in the Muskwa Shale area of Alberta. Operating expense for the synthetic oil business increased $9.0 million in 2014 due to higher costs for fuel and maintenance at Syncrude. Depreciation expense for Canadian conventional operations declined $13.7 million in 2014 primarily due to lower levels of natural gas production compared to the prior year.

Operations in Malaysia reported earnings of $162.3 million in the 2014 quarter compared to earnings of $205.2 million during the same period in 2013. Earnings in 2014 were below 2013 levels in Malaysia primarily due to lower oil sales volumes at the Kikeh field, where production was shut-in for 18 days of the 2014 quarter to tie-in the new Siakap North-Petai (SNP) field to the Kikeh production facilities. The 2014 quarter benefited from higher average crude oil sales prices, but average prices for Sarawak gas production declined predominantly due to contractually required revenue sharing with the local government on a higher percentage of gas volumes produced. Lease operating expense in 2014 was $5.3 million below 2013 primarily due to lower oil sales volumes in the current quarter. Depreciation expense was $9.1 million more in the 2014 quarter due to higher capital amortization unit rates for the newer oil production areas, including offshore Sarawak oil fields and the Kakap field.

Other international operations reported a loss of $122.4 million in the first quarter of 2014 compared to a loss of $80.4 million in the 2013 period. The unfavorable variance in the current quarter was primarily associated with higher costs for unsuccessful exploratory drilling operations compared to 2013. Dry hole expense of $81.1 million in the 2014 quarter included an unsuccessful deepwater well drilled at the Bamboo prospect in the Ntem block, offshore Cameroon. Other exploration expenses in 2014 were lower by $18.8 million compared to 2013, primarily due to more geophysical costs in 2013 associated with seismic data and other studies in Australia, Cameroon and Indonesia. The 2013 first quarter included oil revenue and associated production expense at the Azurite field, offshore Republic of the Congo. This field ceased production in late 2013.

On a worldwide basis, the Company’s crude oil and condensate sales prices averaged $96.43 per barrel in the first quarter 2014 compared to $96.00 per barrel in the 2013 period. U.S. natural gas liquids (NGL) associated with Eagle Ford Shale production were sold at an average of $33.63 per barrel in the 2014 quarter. During the early part of 2013, these gas liquids were sold as part of the Eagle Ford Shale wet gas stream. Total hydrocarbon production averaged 204,436 barrels of oil equivalent per day in the 2014 first quarter, up from 201,876 barrels equivalent per day produced in the 2013 quarter. Average crude oil and gas liquids production was 137,755 barrels per day in the first quarter of 2014 compared to 126,888 barrels per day in the first quarter of 2013, with the more than 8% increase primarily attributable to higher crude oil and NGL production in the Eagle Ford Shale area in South Texas, where an ongoing development program continues. Crude oil production in Malaysia was lower in the 2014 quarter due to Kikeh wells shut-in for 18 days to tie-in the SNP field into the Kikeh production facility. North American natural gas sales prices averaged $4.15 per thousand cubic feet (MCF) in the 2014 quarter compared to $3.11 per MCF in the same quarter of 2013. Prices were stronger in the current year due to more severe winter weather across most of North America in 2014. Natural gas produced in 2014 at fields offshore Sarawak was sold at $5.59 per MCF, compared to a sale price of $6.82 per MCF in the 2013 quarter. The Sarawak gas price declined in 2014 due to contractually required revenue sharing with the local government for a larger portion of these gas volumes sold. Natural gas sales volumes averaged 400 million cubic feet per day in the first quarter 2014, down from 450 million cubic feet per day in the 2013 quarter. The 11% reduction in natural gas sales volumes in 2014 was primarily due to declining natural gas production at the Tupper and Tupper West areas in British Columbia. Development drilling activities in the Tupper area have been voluntarily curtailed in the last few years due to historically weak North American gas sales prices during recent years. Additionally, 2014 natural gas sales volumes from fields offshore Sabah were below 2013 levels primarily due to wells shut-in for tie-in of the SNP field into the Kikeh production facility during the 2014 quarter. Natural gas sales volumes from fields offshore Sarawak in Malaysia increased during the 2014 quarter due to higher product demand from the local purchaser.

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

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Selected operating statistics for the three-month periods ended March 31, 2014 and 2013 follow.


	Three Months Ended March 31,
Exploration and Production	2014		2013
Net crude oil and condensate produced – barrels per day		131,573		126,822
Continuing operations		131,573		125,173
United States – Eagle Ford Shale		40,755		25,345
– Gulf of Mexico and other		11,649		14,717
Canada – light		28		228
– heavy		7,996		8,519
– offshore		8,846		9,243
– synthetic		13,695		12,417
Malaysia		48,604		53,289
Republic of the Congo		—		1,415
Discontinued operations – United Kingdom		—		1,649
Net crude oil and condensate sold – barrels per day		127,368		131,410
Continuing operations		127,368		129,856
United States – Eagle Ford Shale		40,755		25,345
– Gulf of Mexico and other		11,649		14,717
Canada – light		28		228
– heavy		7,996		8,519
– offshore		9,866		7,943
– synthetic		13,695		12,417
Malaysia		43,379		53,845
Republic of the Congo		—		6,842
Discontinued operations – United Kingdom		—		1,554
Net natural gas liquids produced – barrels per day		6,182		66
United States – Eagle Ford Shale		4,299		—
– Gulf of Mexico and other		1,088		—
Canada		22		—
Malaysia		773		66
Net natural gas liquids sold – barrels per day		6,454		69
United States – Eagle Ford Shale		4,299		—
– Gulf of Mexico and other		1,088		—
Canada		22		—
Malaysia		1,045		69
Net natural gas sold – thousands of cubic feet per day		400,086		449,925
Continuing operations		400,086		447,014
United States – Eagle Ford Shale		27,479		21,171
– Gulf of Mexico and other		33,678		38,313
Canada		147,965		191,799
Malaysia – Sarawak		161,661		149,083
– Block K		29,303		46,648
Discontinued operations – United Kingdom		—		2,911
Total net hydrocarbons produced – equivalent barrels per day*		204,436		201,876
Total net hydrocarbons sold – equivalent barrels per day*		200,503		206,467

These operating statistics continue on the following page.

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

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

Results of Operations (Contd.)


	Three Months Ended March 31,
Exploration and Production (Continued)	2014		2013
Weighted average sales prices
Crude oil and condensate – dollars per barrel
United States – Eagle Ford Shale	$	97.47		105.41
– Gulf of Mexico and other		100.25		108.43
Canada (1) – light		95.09		81.91
– heavy		51.13		28.04
– offshore		107.51		111.44
– synthetic		95.34		94.30
Malaysia (2)		100.60		94.44
Republic of the Congo (2)		—		112.89
United Kingdom – discontinued operations		—		113.19
Natural gas liquids – dollars per barrel
United States – Eagle Ford Shale		33.63		—
– Gulf of Mexico and other		38.61		—
Canada		72.14		—
Malaysia		92.78		101.59
Natural gas – dollars per thousand cubic feet
United States – Eagle Ford Shale	$	4.58		3.69
– Gulf of Mexico and other		5.03		3.42
Canada (1)		3.87		2.99
Malaysia – Sarawak (2)		5.59		6.82
– Block K		0.24		0.24
United Kingdom – discontinued operations (1)		—		12.30

(1)	U.S. dollar equivalent.

(2)	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		Conven- tional			Syn- thetic		Malaysia		Other			Total
Three Months Ended March 31, 2014
Oil and gas sales and other revenues	$	485.5		180.2			117.5		492.8		—			1,276.0
Lease operating expenses		76.5		40.8			63.7		81.3		—			262.3
Severance and ad valorem taxes		23.9		1.3			1.1		—		—			26.3
Depreciation, depletion and amortization		168.1		67.8			14.1		143.0		1.1			394.1
Accretion of asset retirement obligations		4.1		1.5			2.3		4.1		—			12.0
Exploration expenses
Dry holes		6.8		—			—		—		81.1			87.9
Geological and geophysical		14.5		0.1			—		—		15.5			30.1
Other		1.7		0.3			—		—		5.6			7.6

		23.0		0.4			—		—		102.2			125.6
Undeveloped lease amortization		6.7		4.9			—		—		1.3			12.9

Total exploration expenses		29.7		5.3			—		—		103.5			138.5

Selling and general expenses		23.0		7.9			0.3		3.4		17.1			51.7
Other expenses		—		0.1			—		—		0.7			0.8

Results of operations before taxes		160.2		55.5			36.0		261.0		(122.4	)		390.3
Income tax provisions		57.1		14.5			9.4		98.7		—			179.7

Results of operations (excluding corporate overhead and interest)		103.1		41.0			26.6		162.3		(122.4	)		210.6

Three Months Ended March 31, 2013
Oil and gas sales and other revenues	$	408.9		155.4			105.4		560.0		69.3			1,299.0
Lease operating expenses		77.5		42.5			54.7		86.6		75.9			337.2
Severance and ad valorem taxes		12.9		0.9			1.3		—		—			15.1
Depreciation, depletion and amortization		130.4		81.5			13.7		133.9		1.2			360.7
Accretion of asset retirement obligations		3.3		1.5			2.7		3.3		1.1			11.9
Exploration expenses
Dry holes		0.7		30.5			—		0.4		9.4			41.0
Geological and geophysical		12.7		0.1			—		0.3		26.4			39.5
Other		1.5		0.3			—		—		10.8			12.6

		14.9		30.9			—		0.7		46.6			93.1
Undeveloped lease amortization		6.1		5.3			—		—		4.0			15.4

Total exploration expenses		21.0		36.2			—		0.7		50.6			108.5

Selling and general expenses		16.1		6.4			0.2		0.5		14.2			37.4

Results of operations before taxes		147.7		(13.6	)		32.8		335.0		(73.7	)		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		(80.4	)		231.9

Due to the shutdown of production operations in Republic of the Congo in late 2013, the Company now includes the results of these operations in the Other exploration and production segment in the above table.

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 $41.3 million in the 2014 first quarter compared to net costs of $49.2 million in the first quarter of 2013. The net costs for corporate activities in 2014 were less than 2013 primarily due to more favorable impacts from transactions denominated in foreign currencies and lower corporate administrative costs, but these were somewhat offset by higher net interest expense in the just completed quarter. The Company had after-tax gains of $3.1 million in the 2014 quarter on transactions denominated in foreign currencies compared to an after-tax loss of $4.1 million in the 2013 quarter. Additionally, corporate activities in 2014 benefited from lower levels of administrative costs after allocation to exploration and production or discontinued operations. The Company’s net interest expense increased $10.4 million in 2014 due to higher average borrowing levels coupled with lower levels of interest capitalized to oil field development projects.

Discontinued Operations

The Company has presented a number of businesses as discontinued operations in its consolidated financial statements. These businesses principally included:

•

U.K. refining and marketing company held for sale at March 31, 2014. Weaker operating results in the 2014 quarter compared to the prior year were primarily attributable to lower refining margins in the current period.

•

U.S. retail marketing company spun-off to shareholders on August 30, 2013. Results of operations were included in the Company’s 2013 financial statements through the date of spin-off.

•

U.K. oil and gas assets sold through a series of transactions in the first half of 2013. The Company’s 2013 financial statements included the results of operations through the respective dates the assets were sold, plus the cumulative gain realized upon sale. The three months ended March 31, 2013 included an after-tax gain of $147.4 million on sale of two properties.

The results of these operations for the 2013 and 2014 first quarters are reflected in the following table.


	Three Months Ended March 31,
(Millions of dollars)	2014			2013
U.K. refining and marketing	$	(13.8	)		(4.1	)
U.S. refining and marketing		—			29.4
U.K. exploration and production		(0.2	)		152.6

Income (loss) from discontinued operations	$	(14.0	)		177.9

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

Results of Operations (Contd.)

Discontinued Operations (Contd.)

Selected operating statistics for the U.K. refining and marketing operations for the three-month periods ended March 31, 2014 and 2013 follow.


	Three Months Ended March 31,
	2014			2013
United Kingdom refining and marketing – unit margins per barrel	$	(0.82	)		(0.03	)
Petroleum and other products sold in the U.K. – barrels per day		127,655			118,278
Gasoline		45,923			44,510
Kerosine		18,149			15,105
Diesel and home heating oils		42,102			42,031
Residuals		10,236			12,698
LPG and other		11,245			3,934
U.K. refinery inputs – barrels per day		119,555			115,768
Milford Haven, Wales – crude oil		115,564			112,411
– other feedstocks		3,991			3,357
U.K. refinery yields – barrels per day		119,555			115,768
Gasoline		41,587			40,420
Kerosine		16,822			15,465
Diesel and home heating oils		38,160			40,604
Residuals		11,279			12,135
LPG and other		9,101			4,160
Fuel and loss		2,606			2,984

The Company has announced that it plans to exit the U.K. refining and marketing business. On April 3, 2014, the Company announced that its U.K. downstream subsidiary had entered into a period of consultation with its employees concerning the future of the subsidiary and the Milford Haven refinery. The Company continues to explore its options regarding the U.K. downstream business. Should the Company be unable to sell its U.K. refining and marketing assets on acceptable terms, borrowings under credit facilities at the end of 2014 would be at a higher level than if the sale is successfully completed and available funds repatriated to the U.S. during 2014. The ultimate completion of the process to exit the U.K. refining and marketing business could lead to future financial accounting losses for the Company.

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

Financial Condition

Net cash provided by operating activities was $735.9 million for the first three months of 2014 compared to $921.1 million during the same period in 2013. Cash provided by operating activities of discontinued operations was $10.0 million and $192.7 million in the 2014 and 2013 periods, respectively. Changes in operating working capital other than cash and cash equivalents provided cash of $18.7 million in the first three months of 2014, compared to cash provided of $100.9 million in the first three months of 2013. Cash was provided by working capital in 2013 primarily due to higher income taxes payable in Malaysia during the first quarter of the prior year. Cash of $243.6 million in the 2014 period and $130.4 million in 2013 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 $56.1 million in 2014 and $59.7 million in 2013, and for property additions and dry holes for continuing operations, which including amounts expensed, were $996.2 million and $965.4 million in the three-month periods ended March 31, 2014 and 2013, respectively. The purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $240.8 million in the 2014 period and $230.3 million in the 2013 period. In the 2014 quarter, the Company paid $250.0 million to repurchase shares of its Common stock through an accelerated share repurchase (ASR) agreement with a major financial institution. Through March 31, 2014, the Company has received the minimum number of shares under the ASR totaling approximately 4,018,000. Additional shares may be received by the Company upon completion of the ASR in the second quarter. Cash used for property additions and other investing activities of discontinued operations totaled $4.9 million in 2014 and $82.3 million in 2013. Total accrual basis capital expenditures were as follows:


	Three Months Ended March 31,
(Millions of dollars)	2014		2013
Capital expenditures
Exploration and production, including discontinued operations	$	886.5		966.0
Refining and marketing, including discontinued operations		4.7		70.4
Corporate and other		0.7		3.8

Total capital expenditures, including discontinued operations	$	891.9		1,040.2

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


	Three Months Ended March 31,
(Millions of dollars)	2014			2013
Property additions and dry hole costs per cash flow statements, including discontinued operations	$	1,001.1			1,035.0
Geophysical and other exploration expenses		37.7			52.1
Capital expenditure accrual changes, including discontinued operations		(146.9	)		(46.9	)

Total capital expenditures, including discontinued operations	$	891.9			1,040.2

Working capital (total current assets less total current liabilities) at March 31, 2014 was $316.7 million, an increase of $32.1 million from December 31, 2013. This level of working capital does not fully reflect the Company’s liquidity position, because the Company’s U.K. refining and marketing business, accounted for as discontinued operations, has low historical costs assigned to inventories under last-in first-out accounting which were $201.6 million below fair value at March 31, 2014.

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

Financial Condition (Contd.)

At March 31, 2014, long-term debt of $3,415.6 million had increased $479.0 million from December 31, 2013. A summary of capital employed at March 31, 2014 and December 31, 2013 follows.


	March 31, 2014					Dec. 31, 2013
(Millions of dollars)	Amount		%			Amount		%
Capital employed
Long-term debt, including capital lease obligation	$	3,415.6		29.1	%	$	2,936.6		25.5	%
Stockholders’ equity		8,304.1		70.9			8,595.7		74.5

Total capital employed	$	11,719.7		100.0	%	$	11,532.3		100.0	%

The Company’s ratio of earnings to fixed charges was 8.4 to 1 for the three-month period ended March 31, 2014.

Cash and invested cash are maintained in several operating locations outside the United States. At March 31, 2014, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included approximately $450.2 million in Canada and $529.0 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

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) 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. “Conflict minerals”’ are defined as tin, tantalum, tungsten and gold which originate from the Democratic Republic of Congo or adjoining countries. For companies to whom the rule applies, the first annual report for conflict minerals must be filed no later than June 2, 2014 for the calendar year of 2013. Based on its assessment, the Company has determined that the rule does not currently apply to it and, therefore, it is not required to file an annual “conflict minerals” report.

On July 2, 2013, the United States District Court for the District of Columbia vacated the SEC’s rules regarding reporting of payments made to the U.S. Federal and foreign governments. The D.C. Court found that the SEC misread the Act to mandate public disclosure of reports and that the denial of exemptions in the case of countries that prohibit public disclosures was improper. The Court remanded the matter to the SEC, which has indicated that it will restart the rulemaking process. The Company cannot predict how the SEC will alter its rules based on the Court’s findings.

Outlook

Average worldwide crude oil prices in April 2014 have been mixed compared to the average price during the first quarter of 2014, with certain indices trading higher and certain below the prior quarter. North American natural gas prices, however, have weakened in April 2014 principally due to warmer spring temperatures across much of the continent. The Company expects its total oil and natural gas production to average near 217,000 barrels of oil equivalent per day in the second quarter 2014. The Company currently anticipates total capital expenditures for the full year 2014 to be approximately $3.8 billion.

The Company will primarily fund its capital program in 2014 using operating cash flow, but will supplement funding where necessary using borrowings under available credit facilities. The Company’s 2014 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.

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

Outlook (Contd.)

The Company has announced that it plans to exit the U.K. refining and marketing business. On April 3, 2014, the Company announced that its U.K. downstream subsidiary had entered into a period of consultation with its employees concerning the future of the subsidiary and the Milford Haven refinery. The Company continues to explore its options regarding the U.K. downstream business. Should the Company be unable to sell its U.K. refining and marketing assets on acceptable terms, borrowings under credit facilities at the end of 2014 would be at a higher level than if the sale is successfully completed and the available funds repatriated to the U.S. during 2014. The ultimate completion of the process to exit the U.K. refining and marketing business could lead to future financial accounting losses for the Company.

Should oil and/or natural gas prices weaken significantly in the future, it is possible that certain investments in oil properties could become impaired in a future period.

Through April 24, 2014, the Company has entered into derivative or forward fixed-price delivery contracts to manage risk associated with certain future oil and natural gas sales prices as well as Malaysian foreign currency-based tax payments as follows:

Commodities

Contract or
Location

Dates

Average
Volumes per Day

Average Prices

U.S. Oil

West Texas Intermediate

Apr. 2014

24,000 bbls/d

$96.41 per bbl.

May – June 2014

32,000 bbls/d

$97.11 per bbl.

Jul. – Sep. 2014

26,000 bbls/d

$94.89 per bbl.

Oct. – Dec. 2014

16,000 bbls/d

$92.33 per bbl.

Canadian Natural Gas

TCPL–NOVA System

Apr. – Dec. 2014

110 mmcf/d

Cdn$4.04 per mcf

Jan. – Dec. 2015

65 mmcf/d

Cdn$4.13 per mcf

Commodities

Contract

Dates

Average
Volumes per Day

Average
Netback Prices

Canadian Heavy Oil

Western Canadian Heavy

Apr. – Jun. 2014

4,000 bbls/d

$55.67 per bbl.

Jul. – Sep. 2014

4,000 bbls/d

$56.14 per bbl.

Oct. – Dec. 2014

4,000 bbls/d

$53.63 per bbl.

Foreign Currency

Dates

U.S. Dollars

Malaysian Ringgits

Currency Financial Swap

April 2014

44,458,000

MYR149,000,000

May 2014

44,698,000

MYR149,000,000

June 2014

44,339,000

MYR149,000,000

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 sale of the Company’s U.K. downstream 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 deterioration in the business or prospects of Murphy or its U.K. downstream subsidiary, adverse developments in Murphy or its U.K. downstream subsidiary’s markets, adverse developments in the U.S. or global capital markets, credit markets or economies generally, and a failure to execute a sale of these U.K. operations on acceptable terms. For further discussion of risk factors, see Murphy’s 2013 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 makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

There were commodity derivative contracts in place at March 31, 2014 covering certain future U.S. crude oil sales volumes in 2014. 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 $50.4 million, while a 10% decrease would have reduced the recorded net liability by a similar amount.

There were derivative foreign exchange contracts in place at March 31, 2014 to hedge the value of the U.S. dollar against two foreign currencies during the second quarter of 2014. A 10% strengthening of the U.S. dollar against these foreign currencies would have decreased the recorded net asset associated with these contracts by approximately $15.7 million, while a 10% weakening of the U.S. dollar would have increased the recorded net asset by approximately $16.6 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, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Murphy 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 2013 Form 10-K filed on February 28, 2014. The Company has not identified any additional risk factors not previously disclosed in its 2013 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 Programs¹
January 1, 2014 to January 31, 2014		284,743	$	—			284,743	²	$	250,000,000
February 1, 2014 to February 28, 2014		4,018,072		62.22	³		4,018,072	³		—
March 1, 2014 to March 31, 2014		—		—			—			—

Total January 1, 2014 to March 31, 2014		4,302,815		58.10			4,302,815			—

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. The buyback program has been extended to April 2014 by the Company’s Board. Through December 31, 2013, the Company had paid $750 million to buy back shares under this Board-approved repurchase program.

On November 11, 2013, 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 was 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 was completed in January 2014 and the Company received an additional 284,743 shares upon completion of the ASR program.

On February 5, 2014, the Company announced that it had entered into a $250 million variable term, capped ASR transaction with a major financial institution. The ASR transaction was structured similarly to the previous ASR transactions. In February, the Company received the minimum number of shares under the transaction, which totaled 4,018,072 shares. Additional shares may be received upon maturity of this ASR transaction in the second quarter of 2014.

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, 2014

(Date)

EXHIBIT INDEX


Exhibit No.

12		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

99.1		Form of time-based restricted stock unit grant agreement

99.2		Form of time-based restricted stock unit – cash grant agreement

99.3		Form of stock appreciation right (“SAR”)

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

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