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,~~June 30, 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,~~June 30, 2014 was~~179,446,784.~~177,571,522.

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 and Financial Condition		1719

Item 3. Quantitative and Qualitative Disclosures About Market Risk		2732

Item 4. Controls and Procedures		2732

Part II – Other Information

Item 1. Legal Proceedings		2732

Item 1A. Risk Factors		2733

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		2834

Item 6. Exhibits		2834

Signature		2935

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


	(Unaudited)
	June 30, 2014			December 31, 2013
ASSETS
Current assets
Cash and cash equivalents	$	661,086			750,155
Canadian government securities with maturities greater than 90 days at the date of acquisition		427,372			374,842
Accounts receivable, less allowance for doubtful accounts of $1,609 in 2014 and 2013		1,053,122			999,872
Inventories, at lower of cost or market
Crude oil		38,119			40,077
Materials and supplies		251,375			254,118
Prepaid expenses		125,046			83,856
Deferred income taxes		59,619			61,991
Assets held for sale		617,194			943,732

Total current assets		3,232,933			3,508,643
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $9,318,710 in 2014 and $8,540,239 in 2013		14,196,884			13,481,055
Goodwill		40,083			40,259
Deferred charges and other assets		101,883			98,123
Assets held for sale		302,151			381,404

Total assets	$	17,873,934			17,509,484

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	35,100			26,249
Accounts payable and accrued liabilities		2,257,458			2,335,712
Income taxes payable		302,028			222,930
Liabilities associated with assets held for sale		255,935			639,140

Total current liabilities		2,850,521			3,224,031
Long-term debt, including capital lease obligation		3,786,494			2,936,563
Deferred income taxes		1,507,484			1,466,100
Asset retirement obligations		905,467			852,488
Deferred credits and other liabilities		331,144			339,028
Liabilities associated with assets held for sale		93,927			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 195,017,103 shares in 2014 and 194,920,155 shares in 2013		195,017			194,920
Capital in excess of par value		886,292			902,633
Retained earnings		8,231,331			8,058,792
Accumulated other comprehensive income		172,531			172,119
Treasury stock, 17,445,581 shares of Common Stock in 2014 and 11,513,642 shares of Common Stock in 2013, at cost		(1,086,274	)		(732,734	)

Total stockholders’ equity		8,398,897			8,595,730

Total liabilities and stockholders’ equity	$	17,873,934			17,509,484

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page ~~30.~~36.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME (unaudited)

(Thousands of dollars, except per share amounts)


							Three Months Ended						Six Months Ended
	Three Months Ended March 31,						June 30,						June 30,
	2014			2013*			2014			2013*			2014			2013*
REVENUES
Sales and other operating revenues	$	1,281,208			1,298,928		$	1,357,905			1,315,600			2,639,113			2,614,526
Interest and other income (loss)		5,192			(7,990	)		(8,884	)		16,386			(3,692	)		8,398

Total revenues		1,286,400			1,290,938			1,349,021			1,331,986			2,635,421			2,622,924

COSTS AND EXPENSES
Lease operating expenses		262,255			337,223			285,865			251,775			548,120			588,998
Severance and ad valorem taxes		26,326			15,063			28,893			20,334			55,219			35,397
Exploration expenses, including undeveloped lease amortization		138,466			108,493			134,812			88,772			273,278			197,265
Selling and general expenses		92,026			81,467			95,000			86,904			187,026			168,371
Depreciation, depletion and amortization		396,249			363,142			458,993			381,384			855,242			744,526
Impairment of assets								0			21,587			0			21,587
Accretion of asset retirement obligations		12,065			11,896			12,327			11,961			24,392			23,857
Interest expense		32,886			27,028			33,769			29,593			66,655			56,621
Interest capitalized		(8,868	)		(13,388	)		(5,053	)		(14,478	)		(13,921	)		(27,866	)
Other expense		814			0			(178	)		0			636			0

Total costs and expenses		952,219			930,924			1,044,428			877,832			1,996,647			1,808,756

Income from continuing operations before income taxes		334,181			360,014			304,593			454,154			638,774			814,168
Income tax expense		164,895			177,331			161,925			194,265			326,820			371,596

Income from continuing operations		169,286			182,683			142,668			259,889			311,954			442,572
Income (loss) from discontinued operations, net of taxes		(14,033	)		177,916			(13,256	)		142,755			(27,289	)		320,671

NET INCOME	$	155,253			360,599		$	129,412			402,644			284,665			763,243

INCOME PER COMMON SHARE – BASIC
PER COMMON SHARE – BASIC
Income from continuing operations	$	0.94			0.96		$	0.80			1.38			1.73			2.33
Income (loss) from discontinued operations		(0.08	)		0.93			(0.08	)		0.75			(0.15	)		1.69

Net income	$	0.86			1.89		$	0.72			2.13			1.58			4.02

INCOME PER COMMON SHARE – DILUTED
PER COMMON SHARE – DILUTED
Income from continuing operations	$	0.93			0.95		$	0.79			1.37			1.72			2.32
Income (loss) from discontinued operations		(0.08	)		0.93			(0.07	)		0.75			(0.15	)		1.68

Net income	$	0.85			1.88		$	0.72			2.12			1.57			4.00

Average Common shares outstanding
Average common shares outstanding
Basic		181,367,565			190,810,201			178,500,440			189,002,146			180,003,605			189,753,673
Diluted		182,576,570			191,765,395			180,045,020			189,944,793			181,327,914			190,702,248

*	Reclassified to conform to current ~~presentation.~~presentation – See Note D.

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


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2014		2013			2014			2013
Net income	$	129,412		402,644			284,665			763,243
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation		133,559		(117,254	)		(3,045	)		(235,008	)
Retirement and postretirement benefit plans		1,026		4,532			2,491			7,270
Deferred loss on interest rate hedges reclassified to interest expense		483		484			966			970

Other comprehensive income (loss)		135,068		(112,238	)		412			(226,768	)

COMPREHENSIVE INCOME	$	264,480		290,406			285,077			536,475

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,						Six Months Ended June 30,
	2014			2013¹			2014			2013¹
OPERATING ACTIVITIES
Net income	$	155,253			360,599		$	284,665			763,243
Adjustments to reconcile net income to net cash provided by operating activities:
Adjustments to reconcile net income to net cash provided by operating activities
Loss (income) from discontinued operations		14,033			(177,916	)		27,289			(320,671	)
Depreciation, depletion and amortization		396,249			363,142			855,242			744,526
Impairment of assets								0			21,587
Amortization of deferred major repair costs		2,741			1,990			4,313			4,415
Dry hole costs		87,909			41,011			127,827			81,305
Amortization of undeveloped leases		12,830			15,390			37,764			32,052
Accretion of asset retirement obligations		12,065			11,896			24,392			23,857
Deferred and noncurrent income tax charges		23,167			25,326			18,122			72,745
Pretax gain from disposition of assets		(19	)		(42	)
Net decrease in noncash operating working capital		18,673			100,949
Pretax loss from disposition of assets								4,997			224
Net (increase) decrease in noncash operating working capital								48,449			(131,812	)
Other operating activities, net		2,973			(13,896	)		22,106			(22,487	)

Net cash provided by continuing operations		725,874			728,449			1,455,166			1,268,984
Net cash provided by discontinued operations		10,005			192,678			4,517			400,026

Net cash provided by operating activities		735,879			921,127			1,459,683			1,669,010

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:
Property additions and dry hole costs²								(1,840,544	)		(1,853,902	)
Proceeds from sales of assets								3,089			130
Purchase of investment securities³								(372,861	)		(373,196	)
Proceeds from maturity of investment securities³								320,331			358,915
Investing activities of discontinued operations
Sales proceeds		0			211,549			0			282,202
Other		(4,866	)		(82,264	)
Property additions and other								(9,092	)		(122,807	)
Other – net		(3,736	)		2,122			(13,007	)		1,718

Net cash required by investing activities		(1,001,955	)		(933,940	)		(1,912,084	)		(1,706,940	)

FINANCING ACTIVITIES
Borrowings of long-term debt		479,000			261,989
Borrowings of long-term debt²								850,000			461,978
Purchase of treasury stock		(250,000	)		0			(375,000	)		(250,000	)
Proceeds from exercise of stock options		0			1,281
Proceeds from exercise of stock options and employee stock purchase plans								0			2,628
Withholding tax on stock-based incentive awards		(6,319	)		(7,337	)		(6,784	)		(8,966	)
Cash dividends paid		(56,073	)		(59,672	)		(112,126	)		(119,376	)
Other		(240	)		(91	)
Other – net								(1,224	)		(2,724	)

Net cash provided by financing activities		166,368			196,170			354,866			83,540

Effect of exchange rate changes on cash and cash equivalents		(1,835	)		(13,568	)		8,466			(18,500	)

Net increase (decrease) in cash and cash equivalents		(101,543	)		169,789			(89,069	)		27,110
Cash and cash equivalents at January 1		750,155			947,316			750,155			947,316

Cash and cash equivalents at March 31	$	648,612			1,117,105
Cash and cash equivalents at June 30							$	661,086			974,426

¹	Reclassified to conform to current ~~presentation.~~presentation – See Note D.

²	Excludes non-cash asset and long-term obligation of $356,170 in 2013 associated with lease commencement for production equipment at the Kakap field offshore Malaysia.

³	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,						Six Months Ended June 30,
	2014			2013			2014			2013
Cumulative Preferred Stock – par $100, authorized 400,000 shares, none issued		0			0			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
Common Stock– par $1.00, authorized 450,000,000 shares, issued 195,017,103 at June 30, 2014 and 194,770,571 shares at June 30, 2013
Balance at beginning of period	$	194,920			194,616		$	194,920			194,616
Exercise of stock options		26			67			97			155

Balance at end of period		194,946			194,683			195,017			194,771

Capital in Excess of Par Value
Balance at beginning of period		902,633			873,934			902,633			873,934
Exercise of stock options, including income tax effects		(10,765	)		743
Exercise of stock options, including income tax benefits								(11,232	)		1,928
Restricted stock transactions and other		(26,400	)		(24,480	)		(27,970	)		(24,485	)
Stock-based compensation		11,190			16,903			22,884			30,327
Other		(11	)		(53	)		(23	)		(87	)

Balance at end of period		876,647			867,047			886,292			881,617

Retained Earnings
Balance at beginning of period		8,058,792			7,717,389			8,058,792			7,717,389
Net income for the period		155,253			360,599			284,665			763,243
Cash dividends		(56,073	)		(59,672	)		(112,126	)		(119,376	)

Balance at end of period		8,157,972			8,018,316			8,231,331			8,361,256

Accumulated Other Comprehensive Income
Balance at beginning of period		172,119			408,901			172,119			408,901
Foreign currency translation loss, net of income taxes		(136,604	)		(117,754	)		(3,045	)		(235,008	)
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
Retirement and postretirement benefit plans, net of income taxes								2,491			7,270
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes								966			970

Balance at end of period		37,463			294,371			172,531			182,133

Treasury Stock
Balance at beginning of period		(732,734	)		(252,805	)		(732,734	)		(252,805	)
Purchase of treasury shares		(250,000	)		0			(375,000	)		(250,000	)
Sale of stock under employee stock purchase plans		132			337			275			655
Awarded restricted stock, net of forfeitures		19,652			16,545			21,185			16,545

Balance at end of period		(962,950	)		(235,923	)		(1,086,274	)		(485,605	)

Total Stockholders’ Equity	$	8,304,078			9,138,494		$	8,398,897			9,134,172

See notes to Consolidated Financial Statements, page 7.7

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,~~June 30, 2014, and the results of operations, cash flows and changes in stockholders’ equity for the ~~interim~~three-month and six-month periods ended ~~March 31,~~June 30, 2014 and 2013, in conformity with accounting principles generally accepted in the United ~~States.~~States of America (U.S.). In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the ~~United States,~~U.S., 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~~and six-month periods ended ~~March 31,~~June 30, 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,~~June 30, 2014, the Company had total capitalized exploratory well costs pending the determination of proved reserves of ~~$395.9~~$396.4 million. The following table reflects the net changes in capitalized exploratory well costs during the ~~three-month~~six-month periods ended ~~March 31,~~June 30, 2014 and 2013.


(Thousands of dollars)	2014		2013			2014		2013
Beginning balance at January 1	$	393,030		445,697		$	393,030		445,697
Additions pending the determination of proved reserves		2,919		26,929			3,376		27,129
Reclassifications to proved properties based on the determination of proved reserves		0		(28,398	)		0		(28,398	)

Balance at March 31	$	395,949		444,228
Balance at June 30						$	396,406		444,428

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												June 30,
	2014						2013						2014						2013
(Thousands of dollars)	Amount		No. of Wells		No. of Projects		Amount		No. of Wells		No. of Projects		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	$	32,192		2		1	$	49,994		3		1
One to two years		56,702		6		1		40,721		3		1		50,333		3		1		37,898		5		1
Two to three years		31,224		2		0		79,446		8		2		37,969		5		0		73,863		7		3
Three years or more		275,831		22		7		267,737		24		5		275,912		22		7		282,673		26		5

	$	395,949		32		9		444,228		41		11	$	396,406		32		9	$	444,428		41		10

Of the ~~$363.8~~$364.2 million of exploratory well costs capitalized more than one year at ~~March 31,~~June 30, 2014, ~~$213.8~~$214.2 million is in Malaysia, ~~$116.2~~$116.3 million is in the U.S. and ~~$33.8~~$33.7 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.

See also Note E for discussion regarding a capital lease of production equipment at the Kakap field.

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,~~June 30, 2014 and December 31, 2013, the carrying ~~values~~value of inventories under the LIFO method ~~were $201.6~~was $161.2 million and $268.6 million, respectively, less than such inventories would have been valued using the first-in, first-out (FIFO) method. These inventories are included in assets held for sale on the Consolidated Balance Sheet.

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~~previously reported as a separate segment within the Company’s former refining and marketing business. ~~The Company announced on April 3,~~On July 31, 2014, Murphy signed an agreement to sell the ~~start of~~Milford Haven, Wales, refinery and terminal assets. Pending regulatory approval and subject to other material conditions, this transaction is scheduled to be completed by October 31, 2014. Additionally, a ~~consultation period with employees~~separate transaction for sale of the U.K. ~~downstream subsidiary as to the future of this subsidiary and its Milford Haven refinery.~~retail marketing business is at an advanced stage.

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 U.S. downstream operations were previously reported as a separate segment within the Company’s former refining and marketing business.

The Company also sold ~~certain~~its oil and gas assets in the United Kingdom during ~~the three months ended March 31,~~ 2013. ~~The after-tax gain~~After-tax gains on sale of the ~~U.K. oil and gas~~ assets ~~was $147.4~~were $68.8 million in the three months ended ~~March 31,~~June 30, 2013 and $216.2 million in the six months ended June 30, 2013. The Company has accounted for these U.K. upstream operations as discontinued operations in its ~~2013~~ consolidated financial ~~statements.~~statements for all periods presented.

The results of operations associated with these discontinued operations for the three-month and six-month periods ended ~~March 31,~~June 30, 2014 and 2013 were as follows:


	Three Months						Three Months					Six Months
	Ended March 31,						Ended June 30,					Ended June 30,
(Thousands of dollars)	2014			2013			2014			2013		2014			2013
Revenues	$	1,432,386			5,515,538		$	811,134			5,964,045		2,243,520			11,479,583

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 before income taxes, including pretax gain on disposals of $55,640 and $130,568 during the three-month and six-month periods in 2013							$	(16,938	)		184,418		(34,233	)		317,339
Income tax expense (benefit)								(3,682	)		41,663		(6,944	)		(3,332	)

Income (loss) from discontinued operations	$	(14,033	)		177,916		$	(13,256	)		142,755		(27,289	)		320,671

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Discontinued Operations (Contd.)

The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations reflected as held for sale on the Company’s consolidated balance sheets at June 30, 2014 and December 31, 2013:


	June 30,		December 31,
(Millions of dollars)	2014		2013
Current assets
Cash	$	242,438		301,302
Accounts receivable		165,972		302,059
Inventories		126,656		254,240
Other		82,128		86,131

Total current assets held for sale	$	617,194		943,732

Non-current assets
Property, plant and equipment, net	$	279,555		360,347
Other		22,596		21,057

Total non-current assets held for sale	$	302,151		381,404

Current liabilities
Accounts payable	$	255,470		637,432
Other		465		1,708

Total current liabilities associated with assets held for sale	$	255,935		639,140

Non-current liabilities
Deferred income taxes payable	$	75,896		68,096
Deferred credits and other liabilities		18,031		27,448

Total non-current liabilities associated with assets held for sale	$	93,927		95,544

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,~~June 30, 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.

During June 2013, the Company and its partners entered into a 25-year lease of production equipment at the Kakap field offshore Malaysia. The lease has been accounted for as a capital lease, and payments under the agreement are to be made over a 15-year period through June 2028. Current maturities and long-term debt on the Consolidated Balance Sheet include $35.1 million and $341.7 million associated with this lease at June 30, 2014.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Cash Flow Disclosures

Additional disclosures regarding cash flow activities are provided below.


	Three Months						Six Months
	Ended March 31,						Ended June 30,
(Thousands of dollars)	2014			2013			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
Net (increase) decrease in operating working capital other than cash and cash equivalents:
Increase in accounts receivable							$	(53,133	)		(367,478	)
Decrease (increase) in inventories								5,574			(11,154	)
Increase in prepaid expenses		(42,128	)		(53,970	)		(41,191	)		(112,303	)
Decrease in deferred income tax assets		6,845			27,427			1,895			75,616
Decrease in accounts payable and accrued liabilities		(4,923	)		(66,680	)
Increase in accounts payable and accrued liabilities								55,729			127,301
Increase in current income tax liabilities		65,172			128,023			79,575			156,206

Total	$	18,673			100,949		$	48,449			(131,812	)

Supplementary disclosures (including discontinued operations):
Cash income taxes paid	$	101,295			47,877		$	234,071			196,923
Interest paid less than amounts capitalized		(4,303	)		(10,519	)
Interest paid, net of amounts capitalized								41,922			25,010

Note G – Employee and Retiree Benefit Plans

The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most 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. Employees hired after August 30, 2013 will only accrue plan benefits under the 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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended ~~March 31,~~June 30, 2014 and 2013.


	Three Months Ended March 31,												Three Months Ended June 30,
							Other												Other
	Pension Benefits						Postretirement Benefits						Pension Benefits						Postretirement Benefits
(Thousands of dollars)	2014			2013			2014			2013			2014			2013			2014			2013
Service cost	$	6,556			7,603			672			1,167		$	6,284			7,094			672			1,230
Interest cost		8,215			6,431			1,278			1,234			8,253			7,700			1,277			1,279
Expected return on plan assets		(8,480	)		(5,700	)		0			0			(8,528	)		(7,569	)		0			0
Amortization of prior service cost		225			276			(21	)		(42	)		228			303			(20	)		(44	)
Amortization of transitional liability		208			120			1			2
Amortization of transitional asset														212			121			2			2
Recognized actuarial loss		1,733			3,532			59			457			1,733			4,759			59			473

Net periodic benefit expense	$	8,457			12,262			1,989			2,818		$	8,182			12,408			1,990			2,940


													Six Months Ended June 30,
																			Other
													Pension Benefits						Postretirement Benefits
(Thousands of dollars)													2014			2013			2014			2013
Service cost													$	12,840			14,697			1,344			2,397
Interest cost														16,468			14,131			2,555			2,513
Expected return on plan assets														(17,008	)		(13,269	)		0			0
Amortization of prior service cost														453			579			(41	)		(86	)
Amortization of transitional asset														420			241			3			4
Recognized actuarial loss														3,466			8,291			118			930

Net periodic benefit expense													$	16,639			24,670			3,979			5,758

During the ~~three-month~~six-month period ended ~~March 31,~~June 30, 2014, the Company made contributions of ~~$10.6~~$36.2 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~~$15.6 million.

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)~~

Note H – Incentive Plans

The costs resulting from all share-based payment transactions are recognized as an expense 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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Incentive Plans (Contd.)

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.~~$55.82 per share. 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~~six-month period ended ~~March 31,~~June 30, 2013 was ~~$1.3~~$2.6 million. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled ~~$0.7~~$3.1 million and ~~$1.4~~$3.0 million for the ~~three-month~~six-month periods ended ~~March 31,~~June 30, 2014 and 2013, respectively.

Amounts recognized in the ~~Consolidated Statements of Income~~financial statements 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.)~~


	Six Months Ended
	June 30,
(Thousands of dollars)	2014		2013
Compensation charged against income before tax benefit	$	32,142		35,142
Related income tax benefit recognized in income		9,978		7,246

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~~three-month and six-month periods ended ~~March 31,~~June 30, 2014 and 2013. The following table reconciles the weighted-average shares outstanding used for these computations.


					Three Months Ended				Six Months Ended
	Three Months Ended March 31,				June 30,				June 30,
(Weighted-average shares)	2014		2013		2014		2013		2014		2013
Basic method		181,367,565		190,810,201		178,500,440		189,002,146		180,003,605		189,753,673
Dilutive stock options and restricted stock units		1,209,005		955,194		1,544,580		942,647		1,324,309		948,575

Diluted method		182,576,570		191,765,395		180,045,020		189,944,793		181,327,914		190,702,248

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				Six Months Ended
	Three Months Ended March 31,				June 30,				June 30,
	2014		2013		2014		2013		2014		2013
Antidilutive stock options excluded from diluted shares		1,555,015		3,794,002		1,161,442		1,731,425		1,810,012		1,414,286
Weighted average price of these options	$	58.97	$	62.18	$	60.02	$	63.52	$	58.90	$	64.39

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Income Taxes

The Company’s effective income tax rate generally exceeds the statutory U.S. ~~Federal statutory~~ tax rate of ~~35.0%~~35%. The effective tax rate is calculated as the amount of income tax expense divided by income before income tax expense. For the three-month and six-month periods in 2014 and 2013, the Company’s effective income tax rates were as follows:

2014 2013
Three months ended March 31
49.3 % 49.3 %


	2014			2013
Three months ended June 30		53.2	%		42.8	%
Six months ended June 30		51.2	%		45.6	%

The effective tax rates for the periods presented exceeded the U.S. ~~Federal~~statutory tax rate of ~~35.0%~~35% due to several factors, including: the effects of income generated in foreign tax jurisdictions, certain of which have income 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,~~June 30, 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~~Risk Management

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~~reclassified to Interest Expense in the Consolidated Statements of ~~Income.~~

Income over the period until the associated notes mature in 2022.

~~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~~July 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,~~June 30, 2014 were as follows:


	Volumes
Dates	~~Volumes~~ (barrels per day)		Swap Prices
~~April – June 2014~~		~~24,000~~	$	~~96.41 per barrel~~
~~July –~~ July–September 2014		~~20,000~~26,000	$	~~94.32~~94.89 per barrel
~~October –~~ October–December 2014		~~12,000~~16,000	$	~~91.72~~92.33 per barrel

The fair value of these open commodity derivative contracts was a net liability of ~~$18.8~~$36.9 million at ~~March 31,~~June 30, 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~~June 30, 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~~June 30, 2013 were approximately ~~$133.5 million and $274.0 million, respectively.~~$153.4 million. There were no open ringgit contracts at June 30, 2014. Short-term derivative instrument contracts totaling ~~$23.0~~$33.0 million and ~~$20.0~~$48.0 million U.S. dollars were also outstanding at ~~March 31,~~June 30, 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~~$0.7 million for the ~~three-month~~six-month period ended ~~March 31,~~June 30, 2014 and reduced income before taxes by ~~$2.7~~$5.6 million for the ~~three-month~~six-month period ended ~~March 31,~~June 30, 2013.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

At ~~March 31,~~June 30, 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

June 30, 2014

December 31, 2013

(Thousands of dollars)

Asset (Liability) Derivatives

Type of Derivative Contract

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Balance Sheet Location

Fair Value

Commodity

Accounts payable

(21,367

)

Accounts receivable

1,970

Accounts payable

(36,926

)

Accounts receivable

1,970

Foreign currency

Accounts receivable

3,411

Accounts payable

(1,038

)

Foreign exchange

Accounts receivable

650

Accounts payable

(1,038

)

For the three-month and six-month periods ended ~~March 31,~~June 30, 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.)~~


		Gain (Loss)
		Three Months Ended						Six Months Ended
(Thousands of dollars)	Statement of Income	June 30,						June 30,
Type of Derivative Contract	Location	2014			2013			2014			2013
Commodity	Crude oil and product purchases	$	(36,041	)		0			(54,455	)		0
Commodity	Discontinued operations		0			2,834			0			(1,376	)
Foreign exchange	Interest and other income		1,464			(1,328	)		4,900			(4,146	)

		$	(34,577	)		1,506			(49,555	)		(5,522	)

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~~six-month periods ended ~~March 31,~~June 30, 2014 and 2013, ~~$0.7~~$1.5 million of the deferred loss on the interest rate swaps was charged to income as a component of Interest ~~Expense in the Consolidated Statements of Income.~~Expense. The remaining loss deferred on these matured contracts at ~~March 31,~~June 30, 2014 was ~~$24.1~~$23.4 million, which is recorded, net of income taxes of $8.2 million, in Accumulated Other Comprehensive Income in the Consolidated Balance Sheet. The Company expects to charge approximately ~~$2.2~~$1.5 million of this deferred loss to income in the form of interest expense during the remaining ~~nine~~six 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,~~June 30, 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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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


	June 30, 2014								December 31, 2013
(Thousands of dollars)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Foreign currency exchange derivative contracts	$	0		650		0		650		0		0		0		0
Commodity derivative contracts		0		0		0		0		0		1,970		0		1,970

	$	0		650		0		650		0		1,970		0		1,970

Liabilities
Nonqualified employee savings plans	$	14,439		0		0		14,439		13,267		0		0		13,267
Commodity derivative contracts		0		36,926		0		36,926		0		0		0		0
Foreign currency exchange derivative contracts		0		0		0		0		0		1,038		0		1,038

	$	14,439		36,926		0		51,365		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,~~June 30, 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 June 30, 2014 and the changes during the ~~three months~~six-month period ended ~~March 31,~~June 30, 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			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		$	305,192			(116,956	)		(16,117	)		172,119
Components of other comprehensive income (loss):
Before reclassifications to income		(136,604	)		236			0			(136,368	)		(3,045	)		31			0			(3,014	)
Reclassifications to income		0			1,229	²		483	³		1,712			0			2,460	²		966	³		3,426

Net other comprehensive income (loss)		(136,604	)		1,465			483			(134,656	)		(3,045	)		2,491			966			412

Balance at March 31, 2014		168,588			(115,491	)		(15,634	)		37,463
Balance at June 30, 2014													$	302,147			(114,465	)		(15,151	)		172,531

¹	All amounts are presented net of income taxes.

Reclassifications before taxes of ~~$1,878~~$3,758 for the ~~three-month~~six-month period ended ~~March 31,~~June 30, 2014 are included in the computation of net periodic benefit expense. See Note G for additional information. Related income taxes of ~~$649~~$1,298 for the ~~three-month~~six-month period ended ~~March 31,~~June 30, 2014 are included in Income tax expense.

Reclassifications before taxes of ~~$741~~$1,482 for the ~~three-month~~six-month period ended ~~March 31,~~June 30, 2014 are included in Interest expense. Related income taxes of ~~$258~~$516 for the ~~three-month~~six-month period ended ~~March 31,~~June 30, 2014 are included in Income tax expense.

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

~~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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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~~through 2016 natural gas sales volumes in Western Canada. The heavy oil blend sales contracts call for deliveries of 4,000 barrels per day in ~~April~~July through December 2014 that achieve netback values that average Cdn$~~55.14~~54.89 per barrel. The natural gas contracts call for deliveries ~~between April~~from July 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~~in 2015 and ~~December 2015~~2016 of approximately 65 million cubic feet per day and 10 million cubic feet per day, respectively, 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~~May 2014, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) addressing recognition of revenue from contracts with customers. When adopted, this guidance will supersede current revenue recognition rules currently followed by the Company. The core principle of the new ASU is that ~~changed~~an entity should recognize revenue to depict the transfer of promised goods or services to customers that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU provides five steps for an entity to apply in recognizing revenue, including: (1) identify the customer contract; (2) identify the contractual performance obligations; (3) determine the transaction price; (4) allocate the transaction price to the contractual performance obligations; and (5) recognize revenue when the performance obligation is satisfied. The new ASU also requires additional disclosures regarding significant contracts with customers. The new ASU will be effective for the Company on January 1, 2017, and early adoption is not permitted. For transition purposes, the new ASU permits either (a) a retrospective application to all years presented, or (b) an alternative transition method whereby the new guidance is only applied to contracts not completed at the date of initial application. The vast majority of the Company’s revenue is recognized when oil and natural gas produced by the Company is delivered and legal ownership of these products has transferred to the purchaser. Based on the Company’s present understanding, the accounting for oil and gas sales revenue is not expected to be significantly altered by the new ASU. The Company has not yet selected which transition method it will use.

In April 2014, the FASB issued an ASU that will change the requirements for reporting discontinued ~~operations.~~operations after its adoption. 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.

1517

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Business Segments


			Three Months Ended					Three Months Ended								Three Months Ended						Three Months Ended
			March 31, 2014					March 31, 2013¹								June 30, 2014						June 30, 2013¹
(Millions of dollars)	Total Assets at March 31, 2014		External Revenues		Income (Loss)			External Revenues			Income (Loss)			Total Assets at June 30, 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		$	5,377.5		507.3			101.7			444.2			122.9
Canada		3,957.1		297.7		67.6			260.8			13.3			4,126.5		262.8			52.9			316.8			51.7
Malaysia		6,076.1		492.8		162.3			560.0			205.2			6,087.0		583.0			172.3			554.7			213.5
Other		142.9		0.0		(122.4	)		69.3			(80.4	)		135.4		(0.2	)		(126.1	)		(0.4	)		(97.9	)

Total exploration and production		15,143.9		1,276.0		210.6			1,299.0			231.9			15,726.4		1,352.9			200.8			1,315.3			290.2
Corporate		1,147.2		10.4		(41.3	)		(8.1	)		(49.2	)		1,228.2		(3.9	)		(58.1	)		16.7			(30.3	)

Assets/revenue/income from continuing operations		16,291.1		1,286.4		169.3			1,290.9			182.7			16,954.6		1,349.0			142.7			1,332.0			259.9
Discontinued operations, net of tax		1,260.0		0.0		(14.0	)		0.0			177.9			919.3		0.0			(13.3	)		0.0			142.7

Total	$	17,551.1		1,286.4		155.3			1,290.9			360.6		$	17,873.9		1,349.0			129.4			1,332.0			402.6


	Six Months Ended						Six Months Ended
	June 30, 2014						June 30, 2013¹
	External			Income			External		Income
(Millions of dollars)	Revenues			(Loss)			Revenues		(Loss)
Exploration and production²
United States	$	992.8			204.8			853.1		216.7
Canada		560.5			120.5			577.6		65.0
Malaysia		1,075.8			334.6			1,114.7		418.7
Other		(0.2	)		(248.5	)		68.9		(178.3	)

Total exploration and production		2,628.9			411.4			2,614.3		522.1
Corporate		6.5			(99.4	)		8.6		(79.5	)

Revenue/income from continuing operations		2,635.4			312.0			2,622.9		442.6
Discontinued operations, net of tax		0.0			(27.3	)		0.0		320.6

Total	$	2,635.4			284.7			2,622.9		763.2

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.~~pages 25 and 26.

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.

1618

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

Results of Operations

Murphy’s income by operating business is presented below.


	Income (Loss)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Millions of dollars)	2014			2013			2014			2013
Exploration and production	$	200.8			290.2			411.4			522.1
Corporate and other		(58.1	)		(30.3	)		(99.4	)		(79.5	)

Income from continuing operations		142.7			259.9			312.0			442.6
Discontinued operations		(13.3	)		142.7			(27.3	)		320.6

Net income	$	129.4			402.6			284.7			763.2

Murphy’s net income in the ~~first~~second quarter of 2014 was ~~$155.3~~$129.4 million ($~~0.85~~0.72 per diluted share) compared to net income of ~~$360.6~~$402.6 million ($~~1.88~~2.12 per diluted share) in the ~~first~~second quarter of 2013. The 2014 ~~results~~second quarter included a loss from discontinued operations of ~~$14.0~~$13.3 million ($~~0.08~~0.07 per diluted share) primarily related to refining and marketing operations in the ~~2013 results included income from discontinued~~U.K., which are held for sale. Discontinued operations reflected a profit of ~~$177.9~~$142.7 million ($~~0.93 per diluted share). Excluding discontinued operations, income from continuing operations was $169.3 million ($0.93~~0.75 per diluted share) in the ~~first~~second quarter 2013, including a $68.8 million gain on sale of ~~2014 compared~~U.K. oil and gas assets, plus earnings of $77.9 million from U.S. retail marketing operations that were spun off to ~~$182.7~~shareholders on August 30, 2013. Income from continuing operations decreased from $259.9 million ($~~0.95~~1.37 per diluted share) in the ~~same~~2013 quarter ~~of 2013. The 2014 continuing operating results were below 2013 results primarily due~~ to ~~higher exploration costs of $30.0~~$142.7 million ($0.79 per diluted share) 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

2014. In the 2014 ~~first~~second quarter, the Company’s exploration and production continuing operations earned ~~$210.6~~$200.8 million compared to ~~$231.9~~$290.2 million in the 2013 quarter. Income in the 2014 quarter was ~~favorably~~unfavorably impacted compared to 2013 by higher costs for oil and gas extraction and exploration activities, partially offset by higher oil sales ~~volumes, but this was more than offset by higher exploration costs in the current quarter.~~volumes. The corporate function had after-tax costs of ~~$41.3~~$58.1 million in the 2014 ~~first~~second quarter compared to after-tax costs of ~~$49.2~~$30.3 million in the 2013 period with the ~~improvement~~unfavorable variance in the current period mostly due to higher net interest expense and unfavorable effects of foreign currency exchange.

For the first six months of 2014, net income totaled $284.7 million ($1.57 per diluted share) compared to net income of $763.2 million ($4.00 per diluted share) for the same period in 2013. Earnings in the first six months of 2014 included a loss from discontinued operations of $27.3 million ($0.15 per diluted share) compared to a profit of $320.6 million ($1.68 per diluted share) in the 2013 period. Discontinued operations in the 2013 period included after-tax gains of $216.2 million from sale of U.K. oil and gas assets, plus earnings of $107.3 million from U.S. retail marketing operations spun off on August 30, 2013. Continuing operations earned $312.0 million ($1.72 per diluted share) in the first six months of 2014, down from $442.6 million ($2.32 per diluted share) in the 2013 period. In the first six months of 2014, the Company’s exploration and production operations earned $411.4 million from continuing operations compared to $522.1 million in the same period of 2013. Earnings in 2014 were below the 2013 period primarily due to ~~more~~higher exploration and depreciation expenses. These variances were partially offset by a favorable impact from higher oil and North American natural gas sales prices. Corporate after-tax costs were $99.4 million in the 2014 period compared to after-tax costs of $79.5 million in the 2013 period as the current period had higher interest expense and an unfavorable variance for the effects ~~from transactions dominated in~~of foreign ~~currencies.~~currency exchange.

Exploration and Production

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


							Income (Loss)
	Income (Loss)						Three Months Ended						Six Months Ended
	Three Months Ended March 31,						June 30,						June 30,
(Millions of dollars)	2014			2013			2014			2013			2014			2013
Exploration and production – continuing operations
Exploration and production
United States	$	103.1			93.8		$	101.7			122.9			204.8			216.7
Canada		67.6			13.3			52.9			51.7			120.5			65.0
Malaysia		162.3			205.2			172.3			213.5			334.6			418.7
Other International		(122.4	)		(80.4	)		(126.1	)		(97.9	)		(248.5	)		(178.3	)

Total	$	210.6			231.9		$	200.8			290.2			411.4			522.1

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

Results of Operations(Contd.)

Exploration and Production (Contd.)

Second quarter 2014 vs. 2013

United States exploration and production operations ~~generated earnings~~reported a profit of ~~$103.1~~$101.7 million in the ~~first~~second quarter of 2014 compared to ~~earnings~~a profit of ~~$93.8~~$122.9 million in the 2013 quarter. Earnings ~~improved~~were $21.2 million lower in the 2014 quarter compared to the same period in 2013 as higher oil and natural gas sales volumes were more than offset by the impacts of derivative contracts and higher expenses. Revenue in the U.S. rose $63.1 million in the second quarter 2014 primarily due to higher oil and natural gas volumes produced and sold in the Eagle Ford Shale in South Texas, where a significant development drilling program is ongoing with eight active land rigs. Revenue in 2014 was unfavorably affected by $16.4 million for payments under matured West Texas Intermediate (WTI) oil derivative contracts, and by $18.1 million to recognize the fair value at June 30, 2014 of open crude oil sales derivative contracts covering certain future 2014 production in the Eagle Ford Shale. The WTI contracts that matured during the second quarter reduced the realized sales price for Eagle Ford Shale crude oil by $4.21 per barrel. Although U.S. oil prices in the 2014 quarter were below 2013, principally due to the crude oil contracts, natural gas prices were stronger compared to a year earlier. Lease operating, production tax and depreciation expenses increased $16.7 million, $8.3 million and $50.9 million, respectively, in 2014 compared to 2013 due to both higher production in the Eagle Ford Shale area and start up of the Dalmatian field in the Gulf of Mexico. Exploration expense was up $12.4 million in 2014 primarily related to higher amortization expense associated with certain Eagle Ford Shale leases that were not extended. Selling and general expenses in the 2014 period increased $5.1 million from the prior year primarily due to higher staffing costs.

Operations in Canada had earnings of $52.9 million in the second quarter 2014 compared to earnings of $51.7 million in the 2013 quarter. Canadian earnings were $1.2 million higher in the 2014 quarter as stronger profits for conventional oil and natural gas operations were offset by weaker profits for synthetic oil operations. Conventional operations improved in 2014 mostly due to no repeat of a 2013 period impairment charge of $21.6 million to write down wells performing below expectations in the Kainai area of Southern Alberta, plus higher oil and natural gas sales prices. Sales prices for crude oil and natural gas increased in all Canadian producing areas in the second quarter of 2014 compared to the prior year. Oil production declined in Canada in the 2014 period compared to 2013 primarily due to lower volumes at Syncrude, where more downtime for maintenance was experienced in the current quarter, and lower volumes of heavy oil produced in the Seal area of Alberta due to well decline. Natural gas sales volumes decreased in 2014 due to lower production in the Tupper area of Western Canada. Production and depreciation expenses for conventional oil and natural gas operations in Canada were lower in 2014 by $11.8 million and $23.5 million, respectively, due primarily to less heavy oil and natural gas production volumes in 2014. Synthetic oil operations incurred higher production expenses of $3.0 million in 2014, despite having lower oil production, due to added equipment repair costs in the latter period.

Operations in Malaysia reported earnings of $172.3 million in the 2014 quarter compared to earnings of $213.5 million during the same period in 2013. Earnings were down $41.2 million in 2014 in Malaysia primarily from a combination of lower sales volumes from the Kikeh oil field offshore Sabah and lower realized sales prices for oil and natural gas produced offshore Sarawak. These impacts were partially offset by higher crude oil production and sales volumes for new oil fields offshore Sarawak and at Siakap North offshore Sabah. The 2014 quarter included a significantly larger impact from contractually required revenue sharing with the local government. This unfavorable impact between quarters primarily affected oil and natural gas prices at fields offshore Sarawak. Lease operating expense increased in the 2014 period by $34.8 million primarily due to a favorable adjustment in 2013 associated with finalization of gas liquids processing fees retroactive to the beginning of this production, plus higher costs during 2014 associated with oil production at new fields offshore Sarawak and at Siakap North. Depreciation expense was $52.7 million more in 2014 compared to the ~~prior year.~~2013 quarter primarily due to the current quarter including a higher cost mix associated with new oil production offshore Sarawak and at the Siakap North field offshore Sabah. Selling and general expense rose $4.9 million in 2014 due to higher staffing costs being only partially recovered through joint operating agreements with partners.

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

Results of Operations(Contd.)

Exploration and Production (Contd.)

Second quarter 2014 vs. 2013 (Contd.)

Other international operations reported a loss of $126.1 million in the second quarter of 2014 compared to a loss of $97.9 million in the 2013 quarter. The $28.2 million increase in costs in the current quarter was primarily related to higher seismic costs associated with prospects in Namibia, Vietnam, Australia and at areas along the Atlantic Margin. Additionally, an expense was incurred in connection with relinquishing the exploration license on the South Barito block onshore Indonesia.

Total hydrocarbon production averaged 210,191 barrels of oil equivalent per day in the 2014 second quarter, up from the 207,401 barrel equivalents per day produced in the 2013 quarter. Average crude oil and condensate production was ~~achieved~~130,750 barrels per day in the second quarter of 2014 compared to 131,758 barrels per day in the second quarter of 2013. Crude oil production increased in the Eagle Ford Shale area of South Texas ~~where an~~in 2014 due to a significant ongoing development ~~project is proceeding. At March 31,~~drilling and completion program. Heavy oil production from the Seal area in Western Canada was lower in 2014 due to field declines. Oil production at Syncrude was lower in 2014 due to downtime associated with repairs of two coking units during a portion of the current quarter. Oil production offshore Eastern Canada was lower during 2014 primarily due to more downtime for equipment repairs at the Terra Nova field. On a worldwide basis, the Company’s crude oil and condensate prices averaged $93.56 per barrel in the second quarter 2014 compared to $92.80 in the 2013 period. The average sales prices for U.S. natural gas liquids was $29.32 per barrel in the 2014 quarter compared to $28.63 per barrel in 2013. Natural gas sales volumes averaged 425 million cubic feet per day in the second quarter 2014, down from 431 million cubic feet per day in the 2013 quarter. The decrease in natural gas sales volumes in 2014 was primarily attributable to lower gas volumes produced in the Tupper area in Western Canada as development drilling activities have been below spending levels needed to fully offset normal well decline during recent periods of relatively low sales prices in the Canadian market. Additionally, natural gas sales volumes from offshore Sarawak fields in 2014 were less than 2013 due to both performance issues at the third party receiving facility and a lower entitlement allocation to the Company ~~employed eight~~under the production sharing contract. Natural gas sales volumes increased in the U.S. in 2014 due to ongoing development drilling ~~rigs~~in the Eagle Ford Shale and start up of the Dalmatian field in the Gulf of Mexico. North American natural gas sales prices averaged $4.03 per thousand cubic feet (MCF) in the 2014 quarter compared to $3.63 per MCF in the same quarter of 2013. The average realized price for natural gas produced in 2014 at fields offshore Sarawak was $5.32 per MCF, compared to a price of $6.98 per MCF in the 2013 quarter. The Sarawak price declined in 2014 primarily due to higher revenue sharing with the government.

Six months 2014 vs. 2013

U.S. E&P operations had income of $204.8 million for the six months ended June 30, 2014 compared to income of $216.7 million in the 2013 period. The 2014 income reduction of $11.9 million was primarily caused by higher exploration expense, which increased $21.1 million in the current year due to higher costs for an unsuccessful exploration well that spud in late 2013 in the Gulf of Mexico, and higher amortization expense associated with certain Eagle Ford Shale leases that were not extended. The 2014 period benefited from higher crude oil production volumes, primarily at the Eagle Ford Shale area. The 2014 period also had higher average realized natural gas sales prices compared to 2013, but realized oil prices were lower year over year. The oil price decline in 2014 was partially caused by net payments of $17.9 million under matured WTI oil contracts. These contracts reduced the Eagle Ford Shale realized oil price by $2.38 per barrel of crude oil produced and sold. In addition, revenue in the U.S. was reduced by $36.5 million to recognize the fair value of remaining open WTI crude oil contracts, which cover a portion of Eagle Ford Shale oil production for the last six months of 2014. Lease operating, production tax and depreciation expenses were higher by $15.7 million, $19.3 million and $88.6 million, respectively, in 2014 than 2013 mostly due to production growth in the Eagle Ford Shale. ~~U.S. results also benefited in 2014 from higher natural gas sales prices, but results were unfavorably affected~~Selling and general expenses rose 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$12.0 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, primarily driven by increased staffing and support costs.

Canadian operations had income of $120.5 million in the first half of 2014 compared to income of $65.0 million a year ago. Operating results for conventional operations improved $74.2 million during the first half of 2014, but this was somewhat offset by lower earnings of $18.7 million for synthetic oil operations. Sales revenue within conventional operations for 2014 was about even with the prior year as better heavy oil and natural gas sales prices mostly offset lower heavy oil and natural gas sales volumes. Lease operating and depreciation expenses for conventional operations were lower by $13.5 million and $37.2 million, respectively, in 2014 mostly related to lower sales volumes

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

Results of Operations(Contd.)

Exploration and Production (Contd.)

Six months 2014 vs. 2013 (Contd.)

in the current year. Exploration expenses in 2014 were $30.4 million less than 2013 primarily due to prior-year dry hole costs at Rainbow in the Muskwa Shale area of Northern Alberta. Impairment expense of $21.6 million in 2013 related to a write down of wells performing below expectations in the Kainai area of Southern Alberta. Synthetic oil operations earnings declined in 2014 primarily due to lower production volumes caused by two coking units being idled for repairs during a portion of the second quarter 2014. Additionally, synthetic oil operations incurred higher lease operating costs of $12.0 million in the current year due to a combination of higher natural gas costs used in production operations and more equipment repair costs.

Malaysia operations earned $334.6 million in the first half of 2014 compared to earnings of $418.7 million in the 2013 period. Earnings were down $84.1 million in 2014 primarily due to lower crude oil sales volumes at the Kikeh field, offshore Sabah, lower realized sales prices for Sarawak natural gas production, and higher extraction costs. Higher crude oil volumes sold at new fields offshore Sarawak partially offset these unfavorable variances. The 2014 period experienced higher revenue sharing with the local government under the existing production sharing contracts. Lease operating expense in 2014 was higher than in 2013 by $29.5 million primarily due to a benefit in the prior year for a retroactive processing fee adjustment related to gas liquids processing. Depreciation expense was up $61.8 million in 2014 primarily due to higher average per-unit depreciation rates for new Malaysian production volumes at offshore Sarawak fields and at the Siakap North field offshore Sabah. Selling and general expenses rose $7.8 million in 2014 compared to the prior year due to higher staffing costs.

Other international operations reported a loss of $248.5 million in the first six months of 2014 compared to a loss of $178.3 million in the 2013 period. The 2014 period included higher dry hole costs of $71.3 million, which were primarily associated with unsuccessful wildcat drilling offshore Cameroon. The current period included higher geological and geophysical expense of $7.3 million, principally for seismic data acquired in Namibia. Other exploration expenses were $9.0 million higher in the current year, mostly attributable to an expense incurred in connection with relinquishing the exploration license on the South Barito block onshore Indonesia. Selling and general expenses increased $7.4 million in 2014 due to higher staffing costs to support foreign exploration activities. The first half of 2013 included oil revenue and associated production expense at the Azurite field, offshore Republic of the Congo. The field ceased production in late 2013.

Total worldwide production averaged 207,329 barrels of oil equivalent per day during the six months ended June 30, 2014, an increase from 204,653 barrels of oil equivalent produced in the same period in 2013. Crude oil, condensate and gas liquids production in the first half of 2014 averaged 131,159 barrels per day compared to 128,910 barrels per day a year ago. Higher oil production in the Eagle Ford Shale, ~~area. Exploration expenses~~where additional wells have been brought on production as part of a significant ongoing development drilling and completion program, more than offset oil production declines in certain other areas. Heavy oil production in Canada declined in 2014 in the Seal area of Western Canada. Synthetic oil production in Canada also was lower in 2014 ~~quarter were $8.7 million above 2013 levels~~ due to more downtime for equipment repairs in the current period. Oil production offshore Eastern Canada was lower in 2014 due to less production at both ~~carryover dry hole expense associated with~~the Hibernia and Terra Nova fields. Lower oil production in 2014 in Malaysia was primarily attributable to less net oil volumes produced at the Kikeh field, but partially offset by higher volumes at new oil fields offshore Sarawak and at Siakap North, offshore Sabah. Production at the Kikeh field was unfavorably affected by downtime for hook-up of the Siakap North field and a ~~well drilled~~rig fire in early 2014. Full field start-up at the non-operated Kakap field offshore Sabah is scheduled for the second half of 2014. For the first six months of 2014, the Company’s sales price for crude oil and condensate averaged $95.57 per barrel, up from $94.24 per barrel in 2013. The sales price for U.S. natural gas liquids averaged $31.59 per barrel in 2014. Natural gas sales volumes decreased from 441 million cubic feet per day in 2013 to 413 million cubic feet per day in 2014, with the reduction due to lower gas production volumes in the Tupper area in British Columbia, where drilling activity has been curtailed due to weak North American natural gas sales prices in recent years. Natural gas sales volumes in 2014 in the U.S. increased due to drilling in the Eagle Ford Shale area and ~~higher costs for seismic~~start-up of the Dalmatian field in the Gulf of Mexico. ~~Selling and general expenses~~The average sales price for North American natural gas in the first six months of 2014 ~~period increased $6.9 million~~was $4.08 per MCF, up from ~~the prior year~~$3.36 per MCF realized in 2013. Natural gas production at fields offshore Sarawak was sold at an average realized price of $5.87 per MCF in 2014 compared to $7.03 per MCF in 2013. The Sarawak gas price was lower in 2014 primarily due to higher ~~costs for employee compensation, professional services~~levels of revenue sharing with the local government during the current year.

Additional details about results of oil and ~~home office support.~~gas operations are presented in the tables on pages 25 and 26.

1722

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 and six-month periods ended ~~March 31,~~June 30, 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.~~


	Three Months					Six Months
	Ended June 30,					Ended June 30,
	2014			2013		2014		2013
Net crude oil and condensate produced – barrels per day		130,750			131,758		131,159		128,910
Continuing operations		130,750			130,791		131,159		127,604
United States – Eagle Ford Shale		42,382			34,261		41,573		29,710
– Gulf of Mexico and other		11,561			10,631		11,605		12,658
Canada – light		48			162		38		195
– heavy		7,533			10,920		7,763		9,726
– offshore		7,991	��		9,641		8,416		9,443
– synthetic		9,576			13,000		11,624		12,710
Malaysia – Sarawak		17,876			6,674		18,528		5,983
– Block K		33,783			44,268		31,612		45,855
Republic of the Congo		—			1,234		—		1,324
Discontinued operations – United Kingdom		—			967		—		1,306
Net crude oil and condensate sold – barrels per day		137,852			133,897		132,639		132,538
Continuing operations		137,852			132,942		132,639		131,285
United States – Eagle Ford Shale		42,382			34,261		41,573		29,710
– Gulf of Mexico and other		11,561			10,631		11,605		12,658
Canada – light		48			162		38		195
– heavy		7,533			10,920		7,763		9,726
– offshore		8,887			10,145		9,374		9,050
– synthetic		9,576			13,000		11,624		12,710
Malaysia – Sarawak		19,617			6,517		20,081		6,644
– Block K		38,248			47,306		30,581		47,190
Republic of the Congo		—			—		—		3,402
Discontinued operations – United Kingdom		—			955		—		1,253
Net natural gas liquids produced – barrels per day¹		8,583			3,759		7,389		2,316
United States – Eagle Ford Shale		5,383			2,099		4,844		1,173
– Gulf of Mexico and other		2,399			1,033		1,747		524
Canada		24			—		23		—
Malaysia – Sarawak		777			627		775		619
Net natural gas liquids sold – barrels per day¹		7,886			3,209		7,174		1,770
United States – Eagle Ford Shale		5,383			2,099		4,844		1,173
– Gulf of Mexico and other		2,399			1,033		1,747		524
Canada		24			—		23		—
Malaysia – Sarawak		80			77		560		73
Net natural gas sold – thousands of cubic feet per day		425,148			431,302		412,686		440,562
Continuing operations		425,148			430,913		412,686		438,919
United States – Eagle Ford Shale		30,295			19,906		28,895		20,535
– Gulf of Mexico and other		51,311			31,871		42,543		35,074
Canada		134,828			169,166		141,360		180,420
Malaysia – Sarawak		161,343			167,447		161,501		158,316
– Block K		47,371			42,523		38,387		44,574
Discontinued operations – United Kingdom		—			389		—		1,643
Total net hydrocarbons produced – equivalent barrels per day²		210,191			207,401		207,329		204,653
Total net hydrocarbons sold – equivalent barrels per day²		216,596			208,990		208,594		207,735

*¹	U.S. and Canada NGLs were included in the wet natural gas stream during early 2013.

²	Natural gas converted on an energy equivalent basis of 6:11.

1923

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

Results of Operations(Contd.)


	Three Months Ended March 31,				Three Months Ended June 30,				Six Months Ended June 30,
Exploration and Production (Continued)	2014		2013
Exploration and Production (Contd.)					2014		2013		2014		2013
Weighted average sales prices
Crude oil and condensate – dollars per barrel
United States – Eagle Ford Shale	$	97.47		105.41	$	95.88		101.38		96.65		103.07
– Gulf of Mexico and other		100.25		108.43		101.88		103.92		101.06		106.55
Canada (1) – light		95.09		81.91		97.69		85.92		96.31		83.64
– heavy		51.13		28.04		61.34		49.90		56.21		39.87
– offshore		107.51		111.44		109.42		102.47		108.42		106.39
– synthetic		95.34		94.30		102.77		98.64		98.42		96.53
Malaysia (2)		100.60		94.44
Malaysia – Sarawak (2)						88.17		94.23		95.32		98.45
– Block K (2)						91.61		89.97		97.16		91.35
Republic of the Congo (2)		—		112.89		—		—		—		112.89
United Kingdom – discontinued operations		—		113.19
Discontinued operations – United Kingdom						—		101.40		—		108.58
Natural gas liquids – dollars per barrel
United States – Eagle Ford Shale		33.63		—	$	27.70		27.06		30.36		27.06
– Gulf of Mexico and other		38.61		—		32.69		31.69		34.67		31.69
Canada		72.14		—
Malaysia		92.78		101.59
Canada (1)						96.63		—		82.65		—
Malaysia – Sarawak (2)						78.46		101.84		86.60		104.10
Natural gas – dollars per thousand cubic feet
United States – Eagle Ford Shale	$	4.58		3.69	$	4.30		4.18		4.43		3.92
– Gulf of Mexico and other		5.03		3.42		4.46		4.52		4.68		3.89
Canada (1)		3.87		2.99		3.80		3.40		3.83		3.19
Malaysia – Sarawak (2)		5.59		6.82		5.32		6.98		5.87		7.03
– Block K		0.24		0.24		0.23		0.24		0.24		0.24
United Kingdom – discontinued operations (1)		—		12.30
Discontinued operations – United Kingdom						—		12.47		—		12.32

(1)	U.S. dollar equivalent.

(2)	Prices are net of payments under the terms of the respective production sharing contracts.

2024

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

Results of Operations(Contd.)

Exploration and Production (Contd.)

OIL AND GAS OPERATING RESULTS ~~(unaudited)~~– THREE MONTHS ENDED JUNE 30, 2014 AND 2013


			Canada														Canada
(Millions of dollars)	United States		Conven- tional			Syn- thetic		Malaysia		Other			Total		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
Three Months Ended June 30, 2014
Oil and gas sales and other operating revenues															$	507.3		173.7			89.1		583.0		(0.2	)		1,352.9
Lease operating expenses		76.5		40.8			63.7		81.3		—			262.3		81.6		39.7			60.8		103.7		—			285.8
Severance and ad valorem taxes		23.9		1.3			1.1		—		—			26.3		26.5		1.2			1.2		—		—			28.9
Depreciation, depletion and amortization		168.1		67.8			14.1		143.0		1.1			394.1		188.6		62.4			12.3		192.4		1.2			456.9
Accretion of asset retirement obligations		4.1		1.5			2.3		4.1		—			12.0		4.3		1.6			2.3		4.2		—			12.4
Exploration expenses
Dry holes		6.8		—			—		—		81.1			87.9		0.7		—			—		—		39.2			39.9
Geological and geophysical		14.5		0.1			—		—		15.5			30.1		1.3		0.1			—		—		37.9			39.3
Other		1.7		0.3			—		—		5.6			7.6		2.4		0.2			—		—		28.1			30.7

		23.0		0.4			—		—		102.2			125.6		4.4		0.3			—		—		105.2			109.9
Undeveloped lease amortization		6.7		4.9			—		—		1.3			12.9		18.7		5.0			—		—		1.2			24.9

Total exploration expenses		29.7		5.3			—		—		103.5			138.5		23.1		5.3			—		—		106.4			134.8

Selling and general expenses		23.0		7.9			0.3		3.4		17.1			51.7		24.6		7.2			0.2		5.0		19.0			56.0
Other expenses		—		0.1			—		—		0.7			0.8		0.5		—			—		—		(0.7	)		(0.2	)

Results of operations before taxes		160.2		55.5			36.0		261.0		(122.4	)		390.3		158.1		56.3			12.3		277.7		(126.1	)		378.3
Income tax provisions		57.1		14.5			9.4		98.7		—			179.7		56.4		12.5			3.2		105.4		—			177.5

Results of operations (excluding corporate overhead and interest)		103.1		41.0			26.6		162.3		(122.4	)		210.6	$	101.7		43.8			9.1		172.3		(126.1	)		200.8

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
Three Months Ended June 30, 2013
Oil and gas sales and other operating revenues															$	444.2		200.1			116.7		554.7		(0.4	)		1,315.3
Lease operating expenses		77.5		42.5			54.7		86.6		75.9			337.2		64.9		51.5			57.8		68.9		8.7			251.8
Severance and ad valorem taxes		12.9		0.9			1.3		—		—			15.1		18.2		0.9			1.2		—		—			20.3
Depreciation, depletion and amortization		130.4		81.5			13.7		133.9		1.2			360.7		137.7		85.9			14.0		139.7		1.4			378.7
Accretion of asset retirement obligations		3.3		1.5			2.7		3.3		1.1			11.9		3.3		1.5			2.5		3.4		1.3			12.0
Impairment of properties																—		21.6			—		—		—			21.6
Exploration expenses
Dry holes		0.7		30.5			—		0.4		9.4			41.0		—		(0.1	)		—		0.8		39.6			40.3
Geological and geophysical		12.7		0.1			—		0.3		26.4			39.5		0.4		(0.7	)		—		0.8		19.7			20.2
Other		1.5		0.3			—		—		10.8			12.6		3.1		0.3			—		—		8.2			11.6

		14.9		30.9			—		0.7		46.6			93.1		3.5		(0.5	)		—		1.6		67.5			72.1
Undeveloped lease amortization		6.1		5.3			—		—		4.0			15.4		7.2		5.3			—		—		4.2			16.7

Total exploration expenses		21.0		36.2			—		0.7		50.6			108.5		10.7		4.8			—		1.6		71.7			88.8

Selling and general expenses		16.1		6.4			0.2		0.5		14.2			37.4		19.5		4.9			0.2		0.1		14.5			39.2

Results of operations before taxes		147.7		(13.6	)		32.8		335.0		(73.7	)		428.2		189.9		29.0			41.0		341.0		(98.0	)		502.9
Income tax provisions (benefits)		53.9		(2.8	)		8.7		129.8		6.7			196.3		67.0		7.6			10.7		127.5		(0.1	)		212.7

Results of operations (excluding corporate overhead and interest)		93.8		(10.8	)		24.1		205.2		(80.4	)		231.9	$	122.9		21.4			30.3		213.5		(97.9	)		290.2

~~Due to the shutdown~~

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

Results of ~~production operations in Republic of the Congo in late 2013, the Company now includes the results of these operations in the Other exploration~~Operations(Contd.)

Exploration and ~~production segment in the above table.~~Production (Contd.)

21OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 30, 2014 AND 2013


			Canada
(Millions of dollars)	United States		Conven- tional			Syn- thetic		Malaysia		Other			Total
Six Months Ended June 30, 2014
Oil and gas sales and other operating revenues	$	992.8		353.9			206.6		1,075.8		(0.2	)		2,628.9
Lease operating expenses		158.1		80.5			124.5		185.0		—			548.1
Severance and ad valorem taxes		50.4		2.5			2.3		—		—			55.2
Depreciation, depletion and amortization		356.7		130.2			26.4		335.4		2.3			851.0
Accretion of asset retirement obligations		8.4		3.1			4.6		8.3		—			24.4
Exploration expenses
Dry holes		7.5		—			—		—		120.3			127.8
Geological and geophysical		15.8		0.2			—		—		53.4			69.4
Other		4.1		0.5			—		—		33.7			38.3

		27.4		0.7			—		—		207.4			235.5
Undeveloped lease amortization		25.4		9.9			—		—		2.5			37.8

Total exploration expenses		52.8		10.6			—		—		209.9			273.3

Selling and general expenses		47.6		15.1			0.5		8.4		36.1			107.7
Other expenses		0.5		0.1			—		—		—			0.6

Results of operations before taxes		318.3		111.8			48.3		538.7		(248.5	)		768.6
Income tax provisions		113.5		27.0			12.6		204.1		—			357.2

Results of operations (excluding corporate overhead and interest)	$	204.8		84.8			35.7		334.6		(248.5	)		411.4

Six Months Ended June 30, 2013
Oil and gas sales and other operating revenues	$	853.1		355.5			222.1		1,114.7		68.9			2,614.3
Lease operating expenses		142.4		94.0			112.5		155.5		84.6			589.0
Severance and ad valorem taxes		31.1		1.8			2.5		—		—			35.4
Depreciation, depletion and amortization		268.1		167.4			27.7		273.6		2.6			739.4
Accretion of asset retirement obligations		6.6		3.0			5.2		6.7		2.4			23.9
Impairment of properties		—		21.6			—		—		—			21.6
Exploration expenses
Dry holes		0.7		30.4			—		1.2		49.0			81.3
Geological and geophysical		13.1		(0.6	)		—		1.1		46.1			59.7
Other		4.6		0.6			—		—		19.0			24.2

		18.4		30.4			—		2.3		114.1			165.2
Undeveloped lease amortization		13.3		10.6			—		—		8.2			32.1

Total exploration expenses		31.7		41.0			—		2.3		122.3			197.3

Selling and general expenses		35.6		11.3			0.4		0.6		28.7			76.6

Results of operations before taxes		337.6		15.4			73.8		676.0		(171.7	)		931.1
Income tax provisions		120.9		4.8			19.4		257.3		6.6			409.0

Results of operations (excluding corporate overhead and interest)	$	216.7		10.6			54.4		418.7		(178.3	)		522.1

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~~$58.1 million in the 2014 ~~first~~second quarter compared to net costs of ~~$49.2~~$30.3 million in the ~~first quarter of 2013. The net~~2013 second quarter. Net costs ~~for corporate activities~~ in ~~2014~~the current year were ~~less than 2013 primarily~~$27.8 million above the prior year due to ~~more favorable~~unfavorable impacts from ~~transactions denominated in~~ foreign ~~currencies~~currency exchange and ~~lower corporate administrative costs, but these were somewhat offset by~~ higher net interest ~~expense~~expense. Net after-tax losses of $7.2 million were incurred 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, while the 2013 quarter had net after-tax gains of $16.2 million. The increase in net interest expense was mostly associated with higher borrowing levels in the current year, coupled with lower financing costs being allocated to development projects in 2014.

For the first six months of 2014, corporate activities reflected net costs of $99.4 million compared to annet costs of $79.5 million a year ago. Six-month corporate costs in 2014 were unfavorable to 2013 by $19.9 million mostly related to higher interest expense and unfavorable foreign exchange impacts. Net interest expense was higher in 2014 compared to 2013 primarily due to larger average borrowings and lower levels of finance costs allocated to development projects in the current year. Total after-tax ~~loss of~~losses associated with foreign currency transactions were $4.1 million in the ~~2013 quarter. Additionally, corporate activities in~~ 2014 ~~benefited from lower levels~~period compared to after-tax gains of ~~administrative costs after allocation to exploration and production or discontinued operations. The Company’s net interest expense increased $10.4~~$12.2 million in ~~2014 due to higher average borrowing levels coupled with lower levels~~the first six months of ~~interest capitalized to oil field development projects.~~2013.

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,~~June 30, 2014. ~~Weaker~~The Company ceased processing crude oil throughputs at the Milford Haven, Wales refinery in May 2014 due to weak operating ~~results~~margins. Weak refining margins, plus fewer crude oil barrels processed to cover ongoing operating costs, led to larger losses for this business in the 2014 quarter compared to the prior ~~year were primarily attributable~~year. On July 31, 2014 the Company signed an agreement to ~~lower refining margins in~~sell the ~~current period.~~Milford Haven, Wales refinery and terminal assets. Pending regulatory approval and subject to other material conditions, this transaction is scheduled to be completed by October 31, 2014. Additionally, a separate transaction for the sale of the Company’s U.K. retail marketing business is at an advanced stage.

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

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~~three-month and six-month periods ended ~~March 31,~~June 30, 2013 included an after-tax ~~gain~~gains of ~~$147.4~~$68.8 million onand $216.2 million, respectively, from the sale of ~~two~~these properties.

The after-tax results of these operations for the ~~2013~~three-month and six-month periods ended June 30, 2014 ~~first quarters~~and 2013 are reflected in the following table.


	Three Months Ended March 31,						Three Months Ended June 30,						Six Months Ended June 30,
(Millions of dollars)	2014			2013			2014			2013			2014			2013
U.K. refining and marketing	$	(13.8	)		(4.1	)	$	(13.2	)		(5.7	)		(27.0	)		(9.8	)
U.S. refining and marketing		—			29.4			—			77.9			—			107.3
U.K. exploration and production		(0.2	)		152.6			(0.1	)		70.5			(0.3	)		223.1

Income (loss) from discontinued operations	$	(14.0	)		177.9		$	(13.3	)		142.7			(27.3	)		320.6

2227

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 and six-month periods ended ~~March 31,~~June 30, 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.)~~


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
U.K. refining and marketing – unit margins per barrel of petroleum products sold	$	(1.72	)		(0.27	)		(1.15	)		(0.16	)
U.K. petroleum products sold – barrels per day		72,217			137,517			99,783			127,950
Gasoline		25,090			49,103			35,449			46,819
Kerosine		6,732			15,370			12,409			15,238
Diesel and home heating oils		27,612			51,103			34,817			46,592
Residuals		7,227			16,869			8,723			14,795
LPG and other		5,556			5,072			8,385			4,506
U.K. refinery inputs – barrels per day		52,321			133,220			85,752			124,542
Milford Haven, Wales – crude oil		50,279			130,324			82,741			121,417
– other feedstocks		2,042			2,896			3,011			3,125
U.K. refinery yields – barrels per day		52,321			133,220			85,752			124,542
Gasoline		22,381			47,292			31,931			43,875
Kerosine		7,201			17,058			11,985			16,266
Diesel and home heating oils		18,427			48,626			28,239			44,637
Residuals		4,837			15,309			8,040			13,731
LPG and other		(2,761	)		1,757			3,137			2,952
Fuel and loss		2,236			3,178			2,420			3,081

Financial Condition

Net cash provided by operating activities was ~~$735.9~~$1,459.7 million for the first ~~three~~six months of 2014 compared to ~~$921.1~~$1,669.0 million during the same period in 2013. ~~Cash provided by operating activities of~~Excluding discontinued operations, ~~was $10.0 million and $192.7~~cash flow from continuing operations increased from $1,269.0 million in the first six months of 2013 to $1,455.2 million in the same 2014 ~~and 2013 periods, respectively.~~period. Changes in operating working capital other than cash and cash equivalents ~~provided~~from continuing operations generated cash of ~~$18.7~~$48.8 million induring the first ~~three~~six months of 2014, ~~compared to~~but these working capital changes required cash ~~provided~~ of ~~$100.9~~$131.8 million in ~~the first three months~~2013. Other significant sources 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~~cash included $320.3 million in the 2014 period and ~~$130.4~~$358.9 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~~all U.K. oil and gas properties ~~in the United Kingdom provided~~generated cash proceeds of ~~$211.5~~$282.2 million during 2013. The Company borrowed $850.0 million and $462.0 million in the six-month periods of 2014 and 2013, ~~quarter.~~respectively, to fund capital development activities and repurchase Company stock.

~~Significant uses~~The most significant use of cash in both years ~~were for dividends, which totaled $56.1 million in 2014 and $59.7 million in 2013, and~~was for property additions and dry holes for continuing operations, which including amounts expensed, were ~~$996.2~~$1,840.5 million and ~~$965.4~~$1,853.9 million in the ~~three-month~~six-month periods ended ~~March 31,~~June 30, 2014 and 2013, respectively. Total cash dividends to shareholders amounted to $112.1 million in 2014 and $119.4 million in 2013. The Company paid quarterly dividends on outstanding Common stock of $0.3125 per share in each of the first two quarters of 2014 and 2013. The Company expended $375.0 million to acquire 5,991,489 shares of Common stock through share repurchases during the first six months of 2014. In the first six months of 2013, the Company spent $250.0 million to repurchase Common shares. Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of ~~$240.8~~$372.9 million in the 2014 period and ~~$230.3~~$373.2 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.

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

Financial Condition (Contd.)

Total accrual basis capital expenditures ~~were as follows:~~for continuing operations follow.

   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


	Six Months Ended
	June 30,
(Millions of dollars)	2014		2013
Capital Expenditures
Exploration and production	$	1,853.1		1,960.5
Corporate		3.2		6.6

Total capital expenditures, including discontinued operations	$	1,856.3		1,967.1

The reduction in capital expenditures in the exploration and production business in 2014 was primarily attributable to lower levels of development spend in Malaysia, but this was somewhat offset by more drilling and development activities in the Eagle Ford Shale area and higher spend on lease acquisitions in the Gulf of Mexico in the current year. Capital expenditures exclude production equipment leased at the Kakap field, offshore Malaysia, during 2013.

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)
   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


	Six Months Ended
	June 30,
(Millions of dollars)	2014			2013
Property additions and dry hole costs per cash flow statements	$	1,840.5			1,853.9
Geophysical and other exploration expenses		107.7			83.9
Capital expenditure accrual changes		(91.9	)		29.3

Total capital expenditures	$	1,856.3			1,967.1

Working capital (total current assets less total current liabilities) at ~~March 31,~~June 30, 2014 was ~~$316.7~~$382.4 million, ~~an increase of $32.1~~$97.8 million ~~from~~more than December 31, ~~2013. This level of working~~2013, with the increase primarily due to lower accounts payable owed on 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 valueprojects at ~~March 31,~~June 30, 2014.

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

~~Financial Condition~~~~(Contd.)~~

At ~~March 31,~~June 30, 2014, long-term debt of ~~$3,415.6~~$3,786.5 million had increased ~~$479.0~~by $849.9 million ~~from~~compared to December 31, 2013. A summary of capital employed at ~~March 31,~~June 30, 2014 and December 31, 2013 follows.


	March 31, 2014					Dec. 31, 2013					June 30, 2014					Dec. 31, 2013
(Millions of dollars)	Amount		%			Amount		%			Amount		%			Amount		%
Capital employed
Long-term debt, including capital lease obligation	$	3,415.6		29.1	%	$	2,936.6		25.5	%
Long-term debt											$	3,786.5		31.1	%	$	2,936.6		25.5	%
Stockholders’ equity		8,304.1		70.9			8,595.7		74.5			8,398.9		68.9			8,595.7		74.5

Total capital employed	$	11,719.7		100.0	%	$	11,532.3		100.0	%	$	12,185.4		100.0	%	$	11,532.3		100.0	%

The Company’s ratio of earnings to fixed charges was ~~8.4~~7.5 to 1 for the ~~three-month~~six-month period ended ~~March 31,~~June 30, 2014.

Cash and invested cash are maintained in several operating locations outside the United States. At ~~March 31,~~June 30, 2014, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included U.S. dollar equivalents of approximately ~~$450.2~~$500 million in Canada, ~~and $529.0~~$509 million in ~~Malaysia.~~Malaysia and $242 million in the United Kingdom. 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~~spur 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.

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

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~~was required to 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 isdid not ~~required to~~ file an annual “conflict minerals” ~~report.~~report for 2013.

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 SEC has targeted the first quarter of 2015 for issuance of new rules on this matter. The Company cannot predict how the SEC will alter its rules based on the Court’s findings.

In May 2014, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) addressing recognition of revenue from contracts with customers. When adopted, this guidance will supersede current revenue recognition rules currently followed by the Company. The core principle of the new ASU is that an entity should recognize revenue to depict the transfer of promised goods or services to customers that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU provides five steps for an entity to apply in recognizing revenue, including: (1) identify the customer contract; (2) identify the contractual performance obligations; (3) determine the transaction price; (4) allocate the transaction price to the contractual performance obligations; and (5) recognize revenue when the performance obligation is satisfied. The new ASU also requires additional disclosures regarding significant contracts with customers. The new ASU will be effective for the Company on January 1, 2017, and early adoption is not permitted. For transition purposes, the new ASU permits either (a) a retrospective application to all years presented, or (b) an alternative transition method whereby the new guidance is only applied to contracts not completed at the date of initial application. The vast majority of the Company’s revenue is recognized when oil and natural gas produced by the Company is delivered and legal ownership of these products has transferred to the purchaser. Based on the Company’s present understanding, the accounting for oil and gas sales revenue is not expected to be significantly altered by the new ASU. The Company has not yet selected which transition method it will use.

In April 2014, the FASB issued an ASU that will change the requirements for reporting discontinued operations after its adoption. 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.

Outlook

Average worldwide crude oil prices in ~~April~~July 2014 ~~have been mixed compared~~were similar to the average price during the ~~first~~second quarter of 2014, with certain indices trading higher and certain below the prior quarter. North American natural gas prices, however, have weakened in ~~April~~July 2014 principally due to ~~warmer spring~~milder than normal summer temperatures across much of the continent. The Company expects its total oil and natural gas production to average ~~near 217,000~~225,000 barrels of oil equivalent per day in the ~~second~~third quarter 2014. The Company currently anticipates total capital expenditures for the full year 2014 to be approximately $3.8 billion.

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

Outlook(Contd.)

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,~~July 31, 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~~signed an agreement to sell the Milford Haven, ~~refinery. The~~Wales, refinery and terminal assets. Pending regulatory approval and subject to other material conditions, this transaction is scheduled to be completed by October 31, 2014. Additionally, the Company continues to ~~explore its options regarding~~advance the negotiation for sale of the U.K. ~~downstream~~marketing business. Should the Company be unable to ~~sell~~complete the sale of 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,~~July 31, 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

Commodities

Contract or
Location

Dates

Average
Volumes per Day

Average Prices

U.S. Oil

West Texas Intermediate

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

Jul. – Dec.2014

110 mmcf/d

Cdn$4.04 per mcf

Jan. – Dec. 2015

65 mmcf/d

Cdn$4.13 per mcf

Jan. – Dec. 2016

10 mmcf/d

Cdn$4.13 per mcf

Canadian Heavy Oil

Seal Blend

Jul. – Sep.2014

4,000 bbls/d

$56.14 per bbl.

Oct. – Dec. 2014

4,000 bbls/d

$53.63 per bbl.

Represents average netback prices to the Company.

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.

2631

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,~~June 30, 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~~$40.0 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,~~June 30, 2014 to hedge the value of the U.S. dollar against ~~two foreign currencies~~the Canadian dollar during ~~the second quarter of~~July 2014. A 10% strengthening of the U.S. dollar against ~~these foreign currencies~~the Canadian dollar would have decreased the recorded net asset associated with these contracts by approximately ~~$15.7~~$3.1 million, while a 10% weakening of the U.S. dollar would have increased the recorded net asset by approximately ~~$16.6~~$3.7 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,~~June 30, 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.

PART II – OTHER INFORMATION(Contd.)

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~~A risk ~~factors~~factor not previously disclosed in its 2013 Form 10-K ~~report.~~report is included below.

Hydraulic fracturing exposes the Company to operational and regulatory risks.

The Company uses a technique known as hydraulic fracturing whereby water, sand and other chemicals are injected into deep oil and gas bearing reservoirs. This process creates fractures in the rock formation within the reservoir which enables oil and natural gas to migrate to the wellbore. The Company primarily uses this technique in the Eagle Ford Shale in South Texas and in Western Canada. Our hydraulic fracturing operations subject us to operational risks inherent in the drilling and production of oil and natural gas, including relating to underground migration or surface spillage due to releases of oil, natural gas, formation water or well fluids, as well as any related surface or ground water contamination, including from petroleum constituents or hydraulic fracturing chemical additives. Ineffective containment of surface spillage and surface or ground water contamination resulting from our hydraulic fracturing operations, including from petroleum constituents or hydraulic fracturing chemical additives, could result in environmental pollution, remediation expenses and third party claims alleging damages, which could adversely affect our financial condition and results of operations. In addition, hydraulic fracturing requires significant quantities of water. Any diminished access to water for use in the process could curtail our operations or otherwise result in operational delays or increased costs.

Hydraulic fracturing is generally regulated by the states, although certain hydraulic fracturing activities are also subject to existing and proposed federal regulations, including pursuant to the Safe Drinking Water Act and the Clean Air Act. In June 2011, the State of Texas adopted a law requiring public disclosure of information regarding components used in the hydraulic fracturing process. Similar disclosure requirements have also been implemented or proposed in other states and by the United States. The Canadian provinces of British Columbia and Alberta have also issued regulations related to hydraulic fracturing activities under their jurisdictions. It is possible that these and other jurisdictions may adopt further laws or regulations which could render the process less effective, drive up its costs or otherwise prohibit hydraulic fracturing activities in certain locations. If any such action is taken in the future, our production levels could be adversely affected or our costs of drilling and completion could be increased.

2733

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    —


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
April 1, 2014 to April 30, 2014		—	$	—			—		$	—
May 1, 2014 to May 31, 2014		1,973,417		67.57	²		1,973,417	^1,2		—
June 1, 2014 to June 30, 2014		—		—			—			—

Total April 1, 2014 to June 30, 2014		1,973,417		63.34			1,973,417

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~~February 5, 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~~May 2014 and the Company received an additional ~~284,743~~123,380 shares upon completion of the ASR program. This brought the total number of shares acquired under this ASR transaction to 4,141,452, with the average purchase price equal to $60.37 per share. This transaction completed the $1.0 billion stock buyback program authorized by the Company’s Board of Directors as announced on October 16, 2012.

³²

On ~~February 5,~~May 20, 2014, the Company announced that it had entered into a ~~$250~~$125 million variable term, capped ASR transaction with a major financial institution. The ASR transaction was structured similarly to the previous ASR transactions. In ~~February,~~May, the Company received the minimum number of shares under the transaction, which totaled ~~4,018,072~~1,850,037 shares. Additional shares may be received upon maturity of this ASR transaction in the ~~second~~third quarter of 2014.

ITEM 6. EXHIBITS

The Exhibit Index on page 3036 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

2834

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,~~August 5, 2014

(Date)

2935

EXHIBIT INDEX


Exhibit No.

4.1		5-Year Revolving Credit Agreement dated June 14, 2011

4.2		Commitment Increase and Maturity Extension Agreement dated May 23, 2013.

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.

3036


	(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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company