MUR 10-Q Quarterly Report June 30, 2015

MURPHY OIL CORP

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10-Q 1 mur-20150630x10q.htm 10-Q 10Q June 2015



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 June 30, 2015

OR

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

For the transition period from ________ to ________
Commission File Number 1-8590

MURPHY OIL CORPORATION
(Exact name of registrant as specified in its charter)


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

	200 Peach Street	71730-7000
P.O. Box 7000, El Dorado, Arkansas		(Zip Code)
(Address of principal executive offices)

(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.

Large accelerated filer [X] Accelerated filer [ ] Non-accelerated filer [ ] Smaller reporting company [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). [ ] Yes [X] No
Number of shares of Common Stock, $1.00 par value, outstanding at June 30, 2015 was 172,751,942 .

MURPHY OIL CORPORATION

TABLE OF CONTENTS


		Page
Part I – Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets		2
Consolidated Statements of Operations		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		19
Item 3. Quantitative and Qualitative Disclosures About Market Risk		30
Item 4. Controls and Procedures		31
Part II – Other Information		31
Item 1. Legal Proceedings		31
Item 1A. Risk Factors		31
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		32
Item 6. Exhibits		32
Signature		33

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS (unaudited)

(Thousands of dollars)



	June 30,		December 31,
	2015		2014*
ASSETS
Current assets
Cash and cash equivalents	$	909,268		1,193,308
Canadian government securities with maturities greater than 90 days at the date of acquisition		395,544		461,313
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2015 and $1,609 in 2014		542,417		873,277
Inventories, at lower of cost or market
Crude oil		42,441		51,757
Materials and supplies		166,866		190,976
Prepaid expenses		114,547		77,281
Deferred income taxes		48,551		55,107
Assets held for sale		279,799		376,130
Total current assets		2,499,433		3,279,149
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $9,070,951 in 2015 and $9,503,524 in 2014		12,577,749		13,331,047
Deferred charges and other assets		72,768		62,582
Assets held for sale		14		50,960
Total assets	$	15,149,964		16,723,738
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	14,942		465,388
Accounts payable and accrued liabilities		1,715,599		2,471,897
Income taxes payable		19,913		59,054
Liabilities associated with assets held for sale		56,334		151,548
Total current liabilities		1,806,788		3,147,887
Long-term debt, including capital lease obligation		3,264,868		2,517,669
Deferred income taxes		937,745		1,193,864
Asset retirement obligations		844,481		841,526
Deferred credits and other liabilities		429,485		441,048
Liabilities associated with assets held for sale		551		8,310
Stockholders’ equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued		–		–
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,055,724 shares in 2015 and 195,040,149 shares in 2014		195,056		195,040
Capital in excess of par value		892,553		906,741
Retained earnings		8,515,176		8,728,032
Accumulated other comprehensive loss		(429,917)		(170,255)
Treasury stock, 22,303,782 shares of Common Stock in 2015 and 17,540,636 shares of Common Stock in 2014, at cost		(1,306,822)		(1,086,124)
Total stockholders’ equity		7,866,046		8,573,434
Total liabilities and stockholders’ equity	$	15,149,964		16,723,738

* Reclassified to conform to current presentation.

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page 34 .

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(Thousands of dollars, except per share amounts)



		Three Months Ended		Six Months Ended
	June 30,			June 30,
	2015		2014	2015	2014
REVENUES
Sales and other operating revenues	$	718,621	1,357,905	1,467,771	2,639,113
Gain (loss) on sale of assets		18,246	–	154,123	(4,997)
Interest and other income (loss)		1,423	(8,884)	38,143	1,305
Total revenues		738,290	1,349,021	1,660,037	2,635,421
COSTS AND EXPENSES
Lease operating expenses		227,489	285,865	459,910	548,120
Severance and ad valorem taxes		19,043	28,893	39,834	55,219
Exploration expenses, including undeveloped lease amortization		64,959	134,812	193,693	273,278
Selling and general expenses		79,176	95,000	166,143	187,026
Depreciation, depletion and amortization		403,390	458,993	884,417	855,242
Accretion of asset retirement obligations		11,750	12,327	23,519	24,392
Interest expense		30,466	33,769	59,936	66,655
Interest capitalized		(1,823)	(5,053)	(3,208)	(13,921)
Other expense		13,931	(178)	63,612	636
Total costs and expenses		848,381	1,044,428	1,887,856	1,996,647
Income (loss) from continuing operations before income taxes		(110,091)	304,593	(227,819)	638,774
Income tax expense (benefit)		(21,105)	161,925	(142,363)	326,820
Income (loss) from continuing operations		(88,986)	142,668	(85,456)	311,954
Income (loss) from discontinued operations, net		15,152	(13,256)	(2,819)	(27,289)
NET INCOME (LOSS)	$	(73,834)	129,412	(88,275)	284,665
PER COMMON SHARE – BASIC
Income (loss) from continuing operations	$	(0.51)	0.80	(0.48)	1.73
Loss from discontinued operations		0.09	(0.08)	(0.02)	(0.15)
Net income (loss)	$	(0.42)	0.72	(0.50)	1.58
PER COMMON SHARE – DILUTED
Income (loss) from continuing operations	$	(0.51)	0.79	(0.48)	1.72
Loss from discontinued operations		0.09	(0.07)	(0.02)	(0.15)
Net income (loss)	$	(0.42)	0.72	(0.50)	1.57

Average Common shares outstanding
Basic		174,488,842	178,500,440	176,343,309	180,003,605
Diluted		174,488,842	180,045,020	176,343,309	181,327,914

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			Six Months Ended
	June 30,			June 30,
	2015		2014	2015	2014

Net income (loss)	$	(73,834)	129,412	(88,275)	284,665
Other comprehensive income (loss), net of tax
Net income (loss) from foreign currency translation		31,981	133,559	(266,614)	(3,045)
Retirement and postretirement benefit plans		2,695	1,026	5,989	2,491
Deferred loss on interest rate hedges reclassified to interest expense		481	483	963	966
Other comprehensive income (loss)		35,157	135,068	(259,662)	412
COMPREHENSIVE INCOME (LOSS)	$	(38,677)	264,480	(347,937)	285,077

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)



	Six Months Ended
	June 30,
	2015		2014
OPERATING ACTIVITIES
Net income (loss)	$	(88,275)	284,665
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities:
Loss from discontinued operations		2,819	27,289
Depreciation, depletion and amortization		884,417	855,242
Amortization of deferred major repair costs		3,404	4,313
Dry hole costs		99,023	127,827
Amortization of undeveloped leases		45,825	37,764
Accretion of asset retirement obligations		23,519	24,392
Deferred and noncurrent income tax charges (benefits)		(194,240)	18,122
Pretax (gains) losses from disposition of assets		(154,123)	4,997
Net decrease in noncash operating working capital		107,171	48,449
Other operating activities, net		(14,329)	22,106
Net cash provided by continuing operations activities		715,211	1,455,166
INVESTING ACTIVITIES
Property additions and dry hole costs		(1,433,615)	(1,840,544)
Proceeds from sales of property, plant and equipment		423,106	3,089
Purchase of investment securities*		(629,763)	(372,861)
Proceeds from maturity of investment securities*		663,343	320,331
Other investing activities, net		(20,568)	(13,007)
Net cash required by investing activities		(997,497)	(1,902,992)
FINANCING ACTIVITIES
Borrowings of debt		823,000	850,000
Repayments of debt		(450,000)	–
Repayment of capital lease obligation		(4,703)	–
Purchase of treasury stock		(250,000)	(375,000)
Withholding tax on stock-based incentive awards		(8,976)	(6,784)
Cash dividends paid		(124,581)	(112,126)
Other financing activities, net		(152)	(1,224)
Net cash provided (required) by financing activities		(15,412)	354,866
CASH FLOWS FROM DISCONTINUED OPERATIONS
Operating activities		(85,445)	4,517
Investing activities		5,322	(9,092)
Changes in cash included in current assets held for sale		89,226	–
Net increase (decrease) in cash and cash equivalents of discontinued operations		9,103	(4,575)
Effect of exchange rate changes on cash and cash equivalents		4,555	8,466
Net decrease in cash and cash equivalents		(284,040)	(89,069)
Cash and cash equivalents at January 1		1,193,308	750,155
Cash and cash equivalents at June 30	$	909,268	661,086

*I nvestments 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)




	Six Months Ended
	June 30,
	2015		2014
Cumulative Preferred Stock – par $100 , authorized 400,000 shares, none issued	$	–		–
Common Stock – par $1.00 , authorized 450,000,000 shares, issued 195,055,724 shar es at June 30, 2015 and 195,017,103 shares at June 30, 2014
Balance at beginning of period		195,040		194,920
Exercise of stock options		16		97
Balance at end of period		195,056		195,017
Capital in Excess of Par Value
Balance at beginning of period		906,741		902,633
Exercise of stock options, including income tax benefits		(376)		(11,232)
Restricted stock transactions and other		(38,032)		(27,970)
Stock-based compensation		24,285		22,884
Other		(65)		(23)
Balance at end of period		892,553		886,292
Retained Earnings
Balance at beginning of period		8,728,032		8,058,792
Net income (loss) for the period		(88,275)		284,665
Cash dividends		(124,581)		(112,126)
Balance at end of period		8,515,176		8,231,331
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		(170,255)		172,119
Foreign currency translation loss, net of income taxes		(266,614)		(3,045)
Retirement and postretirement benefit plans, net of income taxes		5,989		2,491
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes		963		966
Balance at end of period		(429,917)		172,531
Treasury Stock
Balance at beginning of period		(1,086,124)		(732,734)
Purchase of treasury shares		(250,000)		(375,000)
Sale of stock under employee stock purchase plans		246		275
Awarded restricted stock, net of forfeitures		29,056		21,185
Balance at end of period		(1,306,822)		(1,086,274)
Total Stockholders’ Equity	$	7,866,046		8,398,897

See Notes to C onsolidated Financial S tatements, page 7 .

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note A – Nature of Business and Interim Financial Statements

NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries. The Company produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide. The Company has an interest in a Canadian synthetic oil operation.

INTERIM FINANCIAL STATEMENTS – 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 June 3 0 , 2015 and December 31, 2014 , and the results of operations , cash flows and changes in stockholders’ equity for the interim periods ended June 3 0 , 2015 and 201 4 , in conformity with accounting principles generally accepted in the United States of America (U.S. ) . In preparing the financial statements of the Company in conformity with accounting principles generally accepted in the 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 20 1 4 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the six - month period ended June 3 0 , 2015 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 June 3 0 , 2015 , the Company had total capitalized exploratory well costs pending the determination of proved reserves of $ 122.1 million. The following table reflects the net changes in capitalized exploratory well costs during the six -month period s ended June 3 0 , 2015 and 2014.



(Thousands of dollars)	2015		2014
Beginning balance at January 1	$	120,455	393,030
Additions pending the determination of proved reserves		1,620	3,376
Reclassifications to proved properties based on the determination of proved reserves		–	–
Capitalized exploratory well costs charged to expense		–	–
Balance at June 30	$	122,075	396,406

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.



		June 30,
	2015				2014
(Thousands of dollars)	Amount		No. of Wells	No. of Projects	Amount		No. of Wells	No. of Projects
Aging of capitalized well costs:
Zero to one year	$	217	2	1	$	32,192	2	1
One to two years		32,192	2	1		50,333	3	1
Two to three years		27,842	2	–		37,969	5	–
Three years or more		61,824	4	2		275,912	22	7
	$	122,075	10	4	$	396,406	32	9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Of the $ 121.9 million of exploratory well costs capitalized more than one year at June 3 0 , 2015, $ 55.9 million is in the U.S. and $ 66 . 0 million is in Brunei. In both geo graphical areas , either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

During the first quarter 2015, t he Company completed the second phase of the sale of 30% of its oil and gas assets i n Malaysia and received net cash proceeds of $ 417 . 2 million . The Company recorded an after-tax gain on this sale of $ 199 . 5 million . Combined net cash proceeds received to date from the 30% sale, subject to final adjustments, totaled $ 1 . 88 billion.

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

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 c rude oil and finished products wa s predominantly determined on the last-in, first-out (LIFO) method. The sale of the U.K. refining and marketing operations was completed in June 2015 and a ll inventories reported under the LIFO method were included in the sale. At December 31, 201 4 , the carrying value of inventories under the LIFO method was $ 44.9 million less than such inventories would have been valued using the first-in, first-out (FIFO) method. These inventories are included in current assets held for sale on the Consolidated Balance Sheet.

Note D – Discontinued Operations

The Company has accounted for its U.K. refining and marketing operations as discontinued operations for all periods presented . T he Company completed its agreement to sell the remaining U.K. downstream assets at the end of the second quarter. The 2015 second quarter includes a n adjustment to the impairment previously recognized as a result of the final sale of the U.K. downstream assets.

The results of operations associated with these discontinued operations for the three-month and six-month period s ended June 3 0 , 2015 and 2014 were as follows:



	Three Months Ended			Six Months Ended
	June 30,			June 30,
(Thousands of dollars)		2015	2014	2015	2014
Revenues	$	153,107	811,134	382,496	2,243,520
Income (loss) before income taxes	$	21,046	(16,938)	337	(34,233)
Income tax expense (benefit)		5,894	(3,682)	3,156	(6,944)
Income (loss) from discontinued operations	$	15,152	(13,256)	(2,819)	(27,289)

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 C onsolidated B alance S heets at June 3 0 , 2015 and December 31, 201 4 .



	June 30,		December 31,
(Thousands of dollars)	2015		2014
Current assets
Cash	$	111,286	200,512
Accounts receivable		146,651	97,568
Inventories		325	42,161
Other		21,537	35,889
Total current assets held for sale	$	279,799	376,130
Non-current assets
Property, plant and equipment, net	$	–	50,947
Other		14	13
Total non-current assets held for sale	$	14	50,960
Current liabilities
Accounts payable	$	7,897	59,023
Other accrued taxes payable		31,519	40,653
Accrued compensation and severance		16,320	30,872
Refinery decommissioning cost		598	21,000
Total current liabilities associated with assets held for sale	$	56,334	151,548
Non-current liabilities
Deferred income taxes payable	$	–	3,873
Deferred credits and other liabilities		551	4,437
Total non-current liabilities associated with assets held for sale	$	551	8,310

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 June 3 0 , 2015 . In addition, facility fees of 0.25% are charged on the full $ 2 .0 billion commitment. The Company also had unused uncommitted credit facilities that totaled approximately $ 315.3 million at June 3 0 , 2015 . These uncommitted facilities may be withdrawn by the various banks at any time. 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.

T he Company and its partners are parties to 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 included $ 14.9 million and $ 213.2 million , respectively, associated with this lease at June 3 0 , 2015 .

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Cash Flow Disclosures

Additional disclosures regarding cash flow activities are provided below.



	Six Months Ended June 30,
(Thousands of dollars)	2015		2014
Net (increase) decrease in operating working capital other than cash and cash equivalents:
Decrease (increase) in accounts receivable	$	284,542	(53,133)
Decrease (increase) in inventories		(25,547)	5,574
Increase in prepaid expenses		(40,191)	(41,191)
Decrease in deferred income tax assets		5,092	1,895
Increase (decrease) in accounts payable and accrued liabilities		(84,781)	55,729
Increase (decrease) in current income tax liabilities		(31,944)	79,575
Total	$	107,171	48,449
Supplementary disclosures (including discontinued operations):
Cash income taxes paid, net of refunds	$	90,419	234,071
Interest paid, net of amounts capitalized		55,658	41,922
Non-cash investing activities, related to continuing operations:
Asset retirement costs capitalized	$	6,703	12,985
Decrease in capital expenditure accrual		336,952	96,479

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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.

The table that follows provides the components of net periodic benefit expense for the three-month and six-month periods ended June 3 0 , 2015 and 2014.



	Three Months Ended June 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)	2015		2014	2015		2014
Service cost	$	4,772	6,284		828		672
Interest cost		7,971	8,253		1,192		1,277
Expected return on plan assets		(8,724)	(8,528)		–		–
Amortization of prior service cost		198	228		(20)		(20)
Amortization of transitional asset		274	212		3		2
Recognized actuarial loss		3,891	1,733		190		59
		8,382	8,182		2,193		1,990
Special termination benefits		8,606	–		–		–
Curtailments		306	–		–		–
Net periodic benefit expense	$	17,294	8,182		2,193		1,990

	Six Months Ended June 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2015	2014	2015		2014
Service cost	$	9,853	12,840		1,656		1,344
Interest cost		15,921	16,468		2,384		2,555
Expected return on plan assets		(17,411)	(17,008)		–		–
Amortization of prior service cost		393	453		(41)		(41)
Amortization of transitional asset		545	420		3		3
Recognized actuarial loss		7,782	3,466		385		118
		17,083	16,639		4,387		3,979
Special termination benefits		8,606	–		–		–
Curtailments		306	–		–		–
Net periodic benefit expense	$	25,995	16,639		4,387		3,979

Termination and curtailment expenses shown in the table above relate to restructuring activities in the U.S. undertaken by the Company in the second quarter 2015.

During the six -month period ended June 3 0 , 2015 , the Company made contributions of $ 30.1 million to its defined benefit pension and postretirement benefit plans. Remaining required funding in 201 5 for the Company’s defined benefit pension and postretirement plans is anticipated to be $ 6.1 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 20 12 Annual Incentive Plan (20 12 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 20 12 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 20 12 Long-Term Incentive Plan (20 12 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 (RSU) , performance units, performance shares, dividend equivalents and other stock-based incentives. The 20 12 Long-Term Plan expires in 20 22 . A total of 8 ,700,000 shares are issuable during the life of the 20 12 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.

In February 2015, the Committee granted stock options for 991,000 shares at an exercise price of either $49.65 or $51.63 per share. The Black-Scholes valuation for these awards was $10.97 per option. The Committee also granted 455,000 performance-based RSU and 233,400 time-based RSU in February. The fair value of the performance-based RSU, using a Monte Carlo valuation model , ranged from $44.03 to $48.12 per unit. The fair value of time-based RSU was estimated based on the fair market value of the Company’s stock on the date of grant, which was $49.65 per share. Additionally, the Committee granted 847,400 SAR and 616,790 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. Also in February, the Committee granted 48,665 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 estimated fair value of these awards ranged between $49.09 and $50.90 per unit on date of grant.

Beginning January 1, 2014, a ll stock option exercises are non-cash transactions for the Company. The employee will receive net shares, after applicable statutory with holding taxes, upon each exercise. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $ 3 . 1 million for the six -month period ended June 3 0 , 2014 . No income tax benefit was realized from option exercises for the six -month period ended June 3 0 , 2015.

Amounts recognized in the financial statements with respect to share-based plans are a s follows:



	Six Months Ended
	June 30,
(Thousands of dollars)	2015		2014
Compensation charged against income before tax benefit	$	31,230		32,142
Related income tax benefit recognized in income		9,691		9,978

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note I – Earnings per Share

Net income (loss) was used as the numerator in computing both basic and diluted income per Common share for the

three-month and six-month periods ended June 3 0 , 2015 and 2014. The following table reconciles the weighted-average shares outstandin g used for these computations.



	Three Months Ended		Six Months Ended
	June 30,		June 30,
(Weighted-average shares)	2015	2014	2015	2014
Basic method	174,488,842	178,500,440	176,343,309	180,003,605
Dilutive stock options and restricted stock units*	–	1,544,580	–	1,324,309
Diluted method	174,488,842	180,045,020	176,343,309	181,327,914

* Due to a net loss recognized by the Company for the three-month and six-month periods ended June 30, 2015, no unvested stock awards were included in computing earnings per share because the effect was anti-dilutive.

The following table reflects certain options to purchase shares of common stock that were outstanding during the 201 5 and 201 4 periods but were not included in the computation of diluted earnings per share because the incremental shares from assumed conversion were antidilutive.



	Three Months Ended				Six Months Ended
		June 30,			June 30,
		2015	2014		2015		2014
Antidilutive stock options excluded from diluted shares		5,988,668		1,161,442		5,767,975		1,810,012
Weighted average price of these options	$	53.12	$	60.02	$	53.31	$	58.90

Note J – Income Taxes

The Company’s effective income tax rate generally exceeds the statutory U.S. tax rate of 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 201 5 and 201 4 , the Company’s effective income tax rates were as follows:



	2015		2014
Three months ended June 30	19.2	%	53.2	%
Six months ended June 30	62.5	%	51.2	%

The effective tax rates for most periods generally exceed the U.S. statutory tax rate of 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 effective tax rate for the three month period ended June 30, 2015 was less than the U.S. statutory tax rate primarily due to a deferred tax expense associated with the increase in the statutory tax rate in Alberta. The effective tax rate for the six -month period ended June 3 0 , 2015 was above the U.S. statutory tax rate primarily due to a deferred tax benefit associated with the sale of Malaysian assets partially offset by other expenses in foreign jurisdictions for which no tax benefit s were recognized and the increase in statutory rate in Alberta . The effective tax rate for the three and six -month period s ended June 3 0 , 2014 was above the U.S. statutory tax rate , primarily due to other expenses in certain foreign jurisdictions for which no tax benefits were re cognized .

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 June 3 0 , 2015 , the earliest years remaining open for audit and/or settlement in our major taxin g jurisdictions are as follows: United States – 201 1 ; Canada – 2008 ; Malaysia – 2007 ; and United Kingdom – 2012 .

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note K – Financial Instruments and Risk Management

Murphy often uses 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, such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Income. Certain interest rate derivative contracts were accounted for as hedges and the net payment upon settlement recording the fair value of these contracts was deferred in Accumulated Other Comprehensive Income (Loss). This deferred cost is being reclassified to Interest Expense in the Consolidated Statements of Income over the period until the associated notes mature in 2022.

Commodity Purchase Price Risks

The Company is subject to commodity price risk related to crude oil, natural gas liquids and natural gas it produces and sells. The Company had open derivative contracts at June 30 , 2015 and 2014. The impact from marking t o market these c ommodity derivative contracts in creased revenue by $ 7.4 million for the six -month period ended June 3 0 , 201 5 but reduced revenue by $36.9 million for the same period in 2014 . O pen West Texas Intermediate contracts for each period were as follows:



	Volumes
	(barrels per day)	Swap Prices
At June 30, 2015
July - September 2015	15,000	$62.84 per barrel
October - December 2015	15,000	$63.30 per barrel

At June 30, 2014
July - September 2014	26,000	$94.89 per barrel
October - December 2014	16,000	$92.33 per barrel

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. Short-term derivative instrument contracts totaling $ 8 . 0 million and $ 33 .0 million U.S. dollars were also outstanding at June 3 0 , 2015 and 2014, 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 $ 11 thousand and $0. 7 million for the six-month periods ended June 30, 2015 and 2014, respectively.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

At June 3 0 , 2015 and December 31, 2014, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.



	June 30, 2015			December 31, 2014
(Thousands of dollars)	Asset (Liability) Derivatives			Asset (Liability) Derivatives
Type of Derivative Contract	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Commodity	Accounts receivable	$	7,419	Accounts receivable	$	23,168
Foreign exchange	Accounts payable		(11)	Accounts payable		(25)

For the three-month and six-month periods ended June 3 0 , 2015 and 2014, 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			Six Months Ended
(Thousands of dollars)	Statement of Income	June 30,			June 30,
Type of Derivative Contract	Location		2015	2014	2015	2014
Commodity	Sales and other operating revenues	$	7,419	(36,041)	7,419	(54,455)
Foreign exchange	Interest and other income		(49)	1,464	14	4,900
		$	7,370	(34,577)	7,433	(49,555)

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 the net cost associated with these contracts to match the payment of interest on these notes through 2022. During each of the six -month periods ended June 3 0 , 2015 and 2014, $ 1.5 million of the deferred cost on the interest rate swaps was charged to income as a component of Interest Expense. The remaining cost deferred on these matured contracts at June 3 0 , 2015 was $ 13 . 2 million, which is recorded, net of income taxes of $ 7 . 1 million, in Accumulated Other Comprehensive Loss in the Consolidated Balance Sheet. The Company expects to charge approximately $ 1 . 5 million of this deferred cost to income in the form of interest expense during the remaining six months of 2015.

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 June 3 0 , 2015 and December 31, 2014 are presented in the following table.



	June 30, 2015					December 31, 2014
(Thousands of dollars)	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Assets:
Commodity derivative contracts		–	7,419	–	7,419	–	23,168	–	23,168
	$	–	7,419	–	7,419	–	23,168	–	23,168

Liabilities:
Nonqualified employee savings plans	$	(15,032)	–	–	(15,032)	(14,408)	–	–	(14,408)
Foreign currency exchange derivative contracts		–	(11)	–	(11)	–	(25)	–	(25)
	$	(15,032)	(11)	–	(15,043)	(14,408)	(25)	–	(14,433)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

The fair value of WTI crude oil derivative contracts was determined based on active market quotes for WTI crude oil at the balance sheet date. 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 June 3 0 , 2015 and December 31, 2014.

Note L – Accumulated Other Comprehensive Loss

The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at December 31, 201 4 and June 3 0 , 2015 and the changes during the six -month period ended June 3 0 , 2015 are presented net of taxes in the following table.



						Deferred
						Loss on
		Foreign		Retirement and		Interest
		Currency		Postretirement		Rate
		Translation		Benefit Plan		Derivative
(Thousands of dollars)		Gains (Losses) 1		Adjustments 1		Hedges 1		Total 1
Balance at December 31, 2014	$	33,701		(189,752)		(14,204)		(170,255)
Components of other comprehensive income (loss):
Before reclassifications to income		(308,359)		423		–		(307,936)
Reclassifications to income		41,745	2	5,566	3	963	4	48,274
Net other comprehensive income (loss)		(266,614)		5,989		963		(259,662)
Balance at June 30, 2015	$	(232,913)		(183,763)		(13,241)		(429,917)

1 All amounts are presented net of income taxes.

2 Reclassifications for the six-month period ended June 30, 2015 are included in discontinued operations and primarily relate to financial adjustments recognized upon selling all operational assets in the U.K.

3 Reclassifications before taxes of $ 8,522 for the six -month period ended June 30 , 2015 are included in the computation of net periodic benefit expense. See Note G for additional information. Related income taxes of $ 2,956 for the six -month period ended June 30 , 2015 are included in Income tax expense.

4 Reclassifications before taxes of $ 1,482 for the six -month period ended June 3 0 , 2015 are included in Interest expense. Related income taxes of $ 519 for the six -month period ended June 30 , 2015 are included in Income tax expense.

Note M – Environmental and Other Contingencies

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note M – Environmental and Other Contingencies (Contd.)

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

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup and the Company is investigating the extent of any such liability and the availability of applicable defenses. 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.

During the first quarter 2015, the Company’s subsidiary in Canada identified a leak or leaks at an infield condensate transfer pipeline at the Seal field in a remote area of Alberta. The pipeline was immediately shut down and the Company’s emergency response plan was activated. In cooperation with local governmental regulators, and with the assistance of qualified consultants, an invest igation and remediation plan continues and the Company’s insurers were previously notified. The Company has not yet established a complete estimate of the costs to remediate the site. T he Company recorded $43.9 million in other expense during the first quarter 2015 associated with the estimated costs of remediating the site. Further refinements in the estimated total cost to remediate the site are anticipated in future periods, including possible fines from regulators and insurance recoveries. It is possible that the ultimate net remediation costs to the Company associated with the condensate leak or leaks will exceed the amount of expense recorded through June 30, 2015.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

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

Note N – Commitments

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2015 and 2016 natural gas sales volumes in Western Canada. The natural gas sales contracts call for deliveries in the second half of 2015 and for the full year of 2016 of approximately 65 million cubic feet per day and 5 9 million cubic feet per day, respectively, at prices that average Cdn $4.13 and Cdn $ 3.19 per MCF in the respective period . These natural gas contracts have been accounted for as normal sales for accounting purposes.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note O – New Accounting Principles

In April 2015, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) that simplifies the presentation of debt issuance costs. The ASU requires that the cost of issuing debt be presented on the balance sheet as a direct reduction from the associated debt liability. These costs have historically been recorded as an asset, rather than a direct reduction of debt. This ASU does not affect the results of operations, as costs of debt issuance will continue to be amortized to interest expense. The Company is required to adopt the ASU effective in the first quarter of 2016, but early adoption is permitted. The Company adopted this ASU early, effective with the first quarter of 2015. This change in accounting principle is preferable due to allowing debt issuance costs and debt issuance discounts to be presented similarly in the Balance Sheet as reductions to recorded debt balances. A retrospective change to the December 31, 2014 Balance Sheet as previously presented is required due to the adoption. The retrospective adjustment to the December 31, 2014 Balance Sheet is shown below:



	As Previously
	Reported		Adjustment	December 31, 2014
(Thousands of dollars)	December 31, 2014		Effect	As Adjusted
Deferred charges and other assets	$	81,151	(18,569)	62,582
Long-term debt		(2,536,238)	18,569	(2,517,669)

Note P – Business Segments



			Three Months Ended		Three Months Ended
			June 30, 2015		June 30, 2014
	Total Assets
	at June 30,		External	Income	External	Income
(Millions of dollars)	2015		Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States	$	6,015.0	339.8	(16.5)	507.3	101.7
Canada		3,477.0	152.9	(32.2)	262.8	52.9
Malaysia		3,838.9	244.5	27.6	583.0	172.3
Other		114.8	–	(30.1)	(0.2)	(126.1)
Total exploration and production		13,445.7	737.2	(51.2)	1,352.9	200.8
Corporate		1,424.5	1.1	(37.8)	(3.9)	(58.1)
Assets/revenue/income from continuing operations		14,870.2	738.3	(89.0)	1,349.0	142.7
Discontinued operations, net of tax		279.8	–	15.2	–	(13.3)
Total	$	15,150.0	738.3	(73.8)	1,349.0	129.4



	Six Months Ended			Six Months Ended
	June 30, 2015			June 30, 2014
	External		Income	External	Income
(Millions of dollars)	Revenues		(Loss)	Revenues	(Loss)
Exploration and production*
United States	$	619.9	(110.4)	992.8	204.8
Canada		305.2	(70.7)	560.5	120.5
Malaysia		690.2	250.7	1,075.8	334.6
Other		–	(102.1)	(0.2)	(248.5)
Total exploration and production		1,615.3	(32.5)	2,628.9	411.4
Corporate		44.7	(53.0)	6.5	(99.4)
Revenue/income from continuing operations		1,660.0	(85.5)	2,635.4	312.0
Discontinued operations, net of tax		–	(2.8)	–	(27.3)
Total	$	1,660.0	(88.3)	2,635.4	284.7

*Additional details about results of oil and gas operations are presented in the table on page s 25 and 26 .

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

Overall Review

During the second quarter 2015, worldwide benchmark oil and natural gas prices continued to be significantly below average comparable benchmark prices during the second quarter 2014. T hese lower oil and natural gas prices have led the Company to incur losses from operations in 2015. Although the Company is aggressively attacking its overall cost structure, a continuation of very low commodity prices would continue to lead to adverse affects on the Company’s income and cash flow .

Results of Operations

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



	Income (Loss)
	Three Months Ended			Six Months Ended
	June 30,			June 30,
(Millions of dollars)	2015		2014	2015		2014
Exploration and production	$	(51.2)	200.8		(32.5)		411.4
Corporate and other		(37.8)	(58.1)		(53.0)		(99.4)
Income (loss) from continuing operations		(89.0)	142.7		(85.5)		312.0
Discontinued operations		15.2	(13.3)		(2.8)		(27.3)
Net income (loss)	$	(73.8)	129.4		(88.3)		284.7

Murphy’s net loss in t he second quarter of 2015 was $73.8 million ($0.42 per diluted share) compared to net income of $129.4 million ($0.72 per diluted share) in the second quarter of 2014. Income (loss) from continuing operations decreased from a profit of $142.7 million ($0.7 9 per diluted share) in the 2014 quarter to a loss of $ 89.0 million ($0. 51 per diluted share) in 2015. In the 2015 second quarter, the Company’s exploration and productio n continuing operations incurred a loss of $70 .5 million compared to earnings of $200.8 million in the 2014 quarter. Loss in the 2015 quarter was unfavorably impacted by significantly lower realized oil and natural gas sales prices offset in part by lower exploration expense and lower supply costs . The corporate function had after-tax costs of $ 37.8 million in the 2015 second quarter compared to after-tax costs of $58.1 million in the 2014 period with the favorable variance in the current period mostly due to foreign exchange effects and higher income tax benefits . The 2015 second quarter included income from discontinued operations of $ 15.2 million ($0. 09 per diluted share) compared to a loss of $13.3 million ($0. 07 per diluted share) in the 2014 period . The 2015 quarter included an adjustment to the impairment previously recognized as a result of the final sale of the U.K. downstream assets . Discontinued operations primarily relate to refining and marketing operations in the U.K. sold at the end of the second quarter 2015.

For the first six months of 2015, net loss totaled $88.3 million ($0. 5 0 per diluted share) compared to net income of $284.7 million ($1.57 per diluted share) for the same period in 2014. Continuing operations had a loss of $ 85.5 million ($0. 48 per diluted share) in the first six months of 2015, down from income of $312 .0 million ($1.72 per diluted share) for the 2014 period. In the first half of 2015, the Company’s exploration and production operati ons incurred a loss of $ 32 . 5 million compared to earnings of $411.4 million in the same period of 2014. Exploration and production earnings in 2015 were below the 2014 period primarily due to significantly lower oil pri ces realized and lower oil volumes sold coupled with higher depreciation expense , partially offset by lower operating expenses , exploration expenses and selling and general expenses coupled with t he gain on the second phase of its sale of assets in Malaysia. Corporate after-tax costs were $ 53.0 million in the 2015 period compared to after-tax costs of $99.4 million in the 2014 period as the current period had a favorable variance for the effects of foreign currency exchange partially offset by higher administrative and interest expenses. Net loss in the first half of 2015 included a loss from discontinued operations of $ 2.8 million ($0. 0 2 per diluted share) compared to a loss of $27.3 million ($0.15 per diluted share) in the 2014 period. Discontinued operations primarily relate to refining and marketing operations in the U.K. sold at the end of the second quarter 2015.

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

Results of Operations (Contd.)

Exploration and Production

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



		Income (Loss)
	Three Months Ended			Six Months Ended
	June 30,			June 30,
(Millions of dollars)	2015		2014	2015	2014
Exploration and production
United States	$	(16.5)	101.7	(110.4)	204.8
Canada		(32.2)	52.9	(70.7)	120.5
Malaysia		27.6	172.3	250.7	334.6
Other International		(30.1)	(126.1)	(102.1)	(248.5)
Total	$	(51.2)	200.8	(32.5)	411.4

Second quarter 2015 vs. 2014

United States exploration and production operations reported a loss of $16 .5 million in the second quarter of 2015 compared to a profit of $101.7 million in the 2014 quarter. Earnings were $1 18 .2 million lower in the 2015 quarter compared to the same period in 2014 as lower realized oil and natural gas sales prices and higher exploration expenses were partially offset by increased sales volumes. Revenue in the U.S. fell $167.5 million in the second quarter 2015 primarily due to lower oil and natural gas realized sales prices . H owever, produced and sold volumes for oil and natural gas w ere higher in 2015 at both Eagle Ford Shale in South Texas and in the Gulf of Mexico. Severance and ad valorem taxes in the 2015 quarter were $10.4 million lower than the 2014 period primarily due to weaker average commodity prices . Depreciation expense increased $8.1 million in 2015 compared to 2014 due to both higher production in the Eagle Ford Shale area and from the Dalmatian field in the Gulf of Mexico. E xploration expenses were up $21.0 million in the second quarter of 2015 primarily related to unsuccessful exploratory drilling at the Sea Eagle prospect in the Gulf of Mexico.

Operations in Canada had losses of $32.2 million in the second quarter 2015 compared to earnings of $52.9 million in the 2014 quarter. Canadian earnings were $85.1 million lower in the 2015 quarter and included losses for both conventional oil and natural gas operations and synthetic oil operations. Results for conventional operations were $61.3 million lower in 2015 mostly due to lower average realized sales prices for crude oil and natural gas, lower oil volume sold, and higher deferred income tax expense related to a 2% increase in the statutory tax rate in Alberta. These decreases in income were partially offset by higher natural gas volumes produced and lower operating expenses. Oil production for conventional operations was lower in Canada in the 2015 period compared to 2014 primarily due to lower volumes for both the Seal heavy oil area and offshore East Coast properties. Natural gas sales volumes increased in 2015 due to higher production in the Tupper area of Western Canada as a result of second half 2014 drilling activities . Lease operating expenses associated with conventional operations were $7.0 million lower in the 2015 quarter due primarily to a weaker Canadian dollar exchange rate. Synthetic operations results were lower by $23.8 million in the second quarter of 2015 due to lower oil production and price , plus the aforementioned increase in Alberta statutory tax rate . Lease operating expenses associated with synthetic operations were $17.3 million lower in the 2015 quarter due to lower maintenance costs, lower fuel costs and a weaker Canadian dollar exchange rate.

Malaysia operations reported earnings of $27.6 million in the 2015 quarter compared to earnings of $172.3 million during the same period in 2014. Earnings were down $144.7 million in 2015 in Malaysia primarily due to both lower volume s sold and lower realized sales prices for oil and natural gas, partially offset by lower lease operating expenses , lower depreciation expense and a positive adjustment to the gain on sale of 30% interest associated with a post - closing settlement . Crude oil and natural gas sales volumes in Malaysia were lower in the 2015 quarter, primarily due to impacts from the sale of 30% of the Company’s total interest and lower entitlements . Lease operating expenses decreased in the 2015 period by $31.0 million primarily due to the sale mentioned above, less maintenance costs and lower volume sold compared to 2014. Depreciation expense was $60.3 million lower in 2015 compared to the 2014 quarter primarily due to lower oil and natural gas volumes sold .

Other international operations reported a loss of $30.1 million in the second quarter of 2015 compared to a loss of $126.1 million in the 2014 quarter. The $96.0 million improvement in the 2015 perio d was primarily related to less dry hole costs and lower geological and geophysical costs .

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Second quarter 2015 vs. 2014 (Contd.)

Total hydrocarbon production averaged 201,952 barrels of oil equivalent per day in the 2015 second quarter, which represented a 3.9 % decrease from the 210,191 barrel s of oil equivalents per day produced in the 2014 quarter. Average crude oil and condensate production was 121,262 barrels per day in the second quarter of 2015 compared to 130,750 barrels per day in the second quarter of 2014. Crude oil production increased in the Eagle Ford Shale area of South Texas in 2015 where an ongoing development program continues. Crude oil production in the Gulf of Mexico was higher in the 2015 quarter due to production at the Dalmatian field with wells that came onstream mid-year 2014. Heavy oil production from the Seal area in Western Canada was lower in 2015 primarily due to volumes shut-in associated with a leak or leaks at an infield condensate transfer pipeline and natural decline. Oil production offshore Eastern Canada was lower during 2015 primarily due to downtime for a turnaround at the Terra Nova facilities. Lower oil production in 2015 in Malaysia was primarily attributable to less net oil volumes produced primarily due to impacts from the sale of 30% of the Company’s total interest . On a worldwide basis, the Company's crude oil and condensate prices averaged $56.49 per barrel in the second quarter 2015 compared to $93.56 per barrel in the 2014 period, a decline of 40% quarter to quarter. Total production of natural gas liquids (NGL) was 9,779 barrels per day in the 2015 second quarter compared to 8,583 barrels per day in the same 2014 period. The increase in NGL production was primarily associated with the ongoing drilling program in the Eagle Ford Shale and the start-up of the Dalmatian field in the Gulf of Mexico mid-year 2014. The average sales price for U.S. NGL was $12.64 per barrel in the 2015 quarter compared to $29.32 per barrel in 2014. Natural gas sales volumes averaged 42 5 million cubic feet per day in the second quarter 2015 and 2014. Natural gas sales volumes increased in North America for 2015 due to ongoing development drilling in the Eagle Ford Shale in South Texas and second half 2014 drilling in the Tupper area of W estern Canada and production from the Dalmatian field in the Gulf of Mexico, which started in April 2014. The increase in natural gas sales volumes in 2015 was somewhat offset by lower volumes in Malaysia due primarily to both lower entitlement percentages and sale of 30% of its total interests. North American natural gas sales prices averaged $2.42 per thousand cubic fe et (MCF) in the 2015 quarter, 40 % below the $4.03 per MCF average in the same quarter of 2014. The average realized price for natural gas produced in the 2015 quarter at fields offshore Sarawak was $3.82 per MCF, compared to a price of $5.32 per MCF in the 2014 quarter and decreased both due to lower sales prices received offset in part by lower levels of revenue sharing with the local government in the 2015 period .

Six Months 2015 vs. 2014

U.S. E& P operations incurred a loss of $110.4 million for the six months ended June 30, 2015 compared to income of $204.8 million in the 2014 period. The 2015 income reduction of $3 15.2 million was primarily caused by lower realized sales prices for oil and natural gas partially offset by higher production volume . Income was also unfavorably impacted by higher exploration, lease operating and depreciation exp ense s , which increased by $5 8 .2 million, $22.3 million and $44.8 million, respectively, in the current year. Dry hole costs were higher in 2015 due to costs of two unsuccessful exploration well s in the Gulf of Mexico in the first half of the year . Lease operating and d epreciation expense were higher primarily due to increased production volumes at both Eagle Ford Shale and Gulf of Mexico.

Canadian operations had a loss of $70.7 million in the first half of 2015 compared to income of $120.5 million a year ago and was adversely impacted by $23.8 million in the 2015 period due to a 2% increase in the statutory tax rate in Alberta . Operating results for conventional operations declined by $136.9 million in the 2015 period while synthetic operation’s operating results declined by $54.3 million compared to the same period in 2014. Sales revenue within conventional operations declined for 2015 by $ 154.6 million compared to 2014, primarily due to lower realized oil and natural gas prices and lower sales volumes. Lease operating and depreciation expenses for conventional operations were lower by $22.2 million and $10.7 million, respectively, in 2015 mostly related to lower oil sales volumes and weaker Canadian dollar exchange rate in the current year. Other expenses increased by $43.8 million due to an environmental remediation provision associated with the condensate leak or le a ks in the transfer pipeline at the Seal heavy oil area. Synthetic operating results were lower by $54.3 million in first half of 2015 due to weaker realized oil prices and lower production volumes . Lease operating expenses associated with synthetic operations were reduced by $37.1 million in 2015 due to lower maintenance costs and weaker Canadian dollar exchange rates.

M alaysia operations earned $250.7 million in the first half of 2015 compared to earnings of $334.6 million in the 2014 pe riod. Earnings were down $83.9 million in 2015 primarily due to lower realized sales prices for oil and natural gas coupled with lower volumes sold , partially offset by a $218.8 million after-tax gain on sale of a 10% interest in Malaysian assets and lower lease operating expenses. Lease operating expense in 2015 was lower than in 2014 by $51.2 million primarily due to lower volume sold, lower maintenance costs and no repeat of 2014 start-up costs for Siakap North, offshore Sabah.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Six Months 2015 vs. 2014 (Contd.)

Other international operations reported a loss of $102.1 million in the first six months of 2015 compared to a loss of $248.5 million in the 2014 period. The 2015 period included lower dry hole costs of $85.7 million, with the higher 2014 costs primarily associated with unsuccessful wildcat drilling offshore Cameroon. The current period included lower geological and geophysical expense of $36.5 million, principally for seismic data acquired in 2014 in Namibia. Other exploration expenses were $13.5 million lower in the current year, mostly attributable to an expense incurred in connection with relinquishing the exploration license on the South Barito block onshore Indonesia in 2014 .

Total worldwide production averaged 211,699 barrels of oil equivalent per day during the six months ended June 30, 2015, an increase from 207,329 barrels of oil equivalent produced in the same period in 2014. Crude oil, condensate and gas liquids production in the first half of 2015 averaged 130,778 barrels per day compared to 131,159 barrels per day a year ago. Higher oil production in the Eagle Ford Shale, where additional wells have been brought on production as part of a significant ongoing development drilling and completion program, essentially offset oil production declines in certain other areas. Heavy oil production in Canada declined in 2015 in the Seal area of Western Canada primarily due to wells shut in related to the condensate leak or leaks and natural well decline . Oil production offshore Eastern Canada was lower in 2015 due to less production at Terra Nova field primarily due to planned maintenance in 2015 . Synthetic oil production in Canada also was lower in 2015 due to impacts of maintenance work and higher Canadian royalty rates. Lower oil production in 2015 in Malaysia was primarily attributable to impacts from the sale of 30% of the Company’s total interest . For the first six months of 2015, the Company’s sales price for crude oil and condensate averaged $51.26 per barrel, down from $95.57 per barrel in 2014. The sales price for U.S. natural gas liquids averaged $12.77 per barrel in 2015 compared to $31.59 per barrel in 2014. Natural gas sales volumes increased from 413 million cubic feet per day in 2014 to 425 million cubic feet per day in 2015, with the increase due to higher gas production volumes in the Dalmatian field in the Gulf of Mexico, Eagle Ford Shale area of South Texas, and Tupper area in Western Canada. The average sales price for North American natural gas in the first six months of 2015 was $2. 44 per MCF, down from $4.08 per MCF realized in 2014. Natural gas production at fields offshore Sarawak was sold at an average realized price of $4.53 per MCF in 2015 compared to $5.87 per MCF in 2014. The Sarawak gas price was lower in 2015 primarily due to lower average selling price s offset in part by lower levels of revenue sharing with the local government during the current year.

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

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Selected operating statistics for the th ree-month and six-month periods ended June 30 , 2015 and 2014 follow.



	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2015	2014	2015	2014
Net crude oil and condensate produced – barrels per day	121,262	130,750	130,778	131,159
United States – Eagle Ford Shale	46,948	42,382	48,483	41,573
– Gulf of Mexico and other	12,263	11,561	12,519	11,605
Canada – light	91	48	110	38
– heavy	6,343	7,533	6,276	7,763
– offshore	6,043	7,991	7,702	8,416
– synthetic	9,129	9,576	11,394	11,624
Malaysia 1 – Sarawak	14,167	17,876	15,951	18,528
– Block K	26,278	33,783	28,343	31,612

Net crude oil and condensate sold – barrels per day	114,178	137,852	131,706	132,639
United States – Eagle Ford Shale	46,948	42,382	48,483	41,573
– Gulf of Mexico and other	12,263	11,561	12,519	11,605
Canada – light	91	48	110	38
– heavy	6,343	7,533	6,276	7,763
– offshore	6,907	8,887	8,065	9,374
– synthetic	9,129	9,576	11,394	11,624
Malaysia 1 – Sarawak	12,966	19,617	17,066	20,081
– Block K	19,531	38,248	27,793	30,581

Net natural gas liquids produced – barrels per day	9,779	8,583	10,094	7,389
United States – Eagle Ford Shale	7,579	5,383	7,517	4,844
– Gulf of Mexico and other	1,636	2,399	1,895	1,747
Canada	5	24	14	23
Malaysia 1 – Sarawak	559	777	668	775
Net natural gas liquids sold – barrels per day	9,611	7,886	9,794	7,174
United States – Eagle Ford Shale	7,579	5,383	7,517	4,844
– Gulf of Mexico and other	1,636	2,399	1,895	1,747
Canada	5	24	14	23
Malaysia 1 – Sarawak	391	80	368	560
Net natural gas sold – thousands of cubic feet per day	425,463	425,148	424,961	412,686
United States – Eagle Ford Shale	37,790	30,295	39,030	28,895
– Gulf of Mexico and other	54,093	51,311	55,563	42,543
Canada	195,159	134,828	193,133	141,360
Malaysia 1 – Sarawak	110,816	161,343	111,431	161,501
– Block K	27,605	47,371	25,804	38,387
Total net hydrocarbons produced – equivalent barrels per day 2	201,952	210,191	211,699	207,329
Total net hydrocarbons sold – equivalent barrels per day 2	194,700	216,596	212,327	208,594

1 The Company sold 20% interest in Malaysia properties on December 18, 2014 and sold an additional 10% interest on January 29, 2015. This table includes volumes for these sold interests through the date of disposition.

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

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

Results of Operations (Contd.)

Exploration and Production (Contd.)



	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2015		2014	2015	2014
Weighted average sales prices
Crude oil and condensate – dollars per barrel
United States – Eagle Ford Shale	$	55.66	95.88	49.55	96.65
– Gulf of Mexico and other		59.14	101.88	52.52	101.06
Canada 1 – light		51.90	97.69	46.16	96.31
– heavy		33.85	61.34	27.02	56.21
– offshore		60.35	109.42	55.51	108.42
– synthetic		60.88	102.77	51.27	98.42
Malaysia – Sarawak 2		57.91	88.17	52.87	95.32
– Block K 2		59.81	91.61	56.96	97.16
Natural gas liquids – dollars per barrel
United States – Eagle Ford Shale	$	12.15	27.70	12.22	30.36
– Gulf of Mexico and other		14.32	32.69	14.50	34.67
Canada 1		21.62	96.63	22.31	82.65
Malaysia – Sarawak 2		47.59	78.46	58.08	86.60
Natural gas – dollars per thousand cubic feet
United States – Eagle Ford Shale	$	2.23	4.30	2.39	4.43
– Gulf of Mexico and other		2.37	4.46	2.48	4.68
Canada 1		2.47	3.80	2.44	3.83
Malaysia – Sarawak 2		3.82	5.32	4.53	5.87
– Block K		0.23	0.23	0.24	0.24

1 U.S. dollar equivalent.

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

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

OIL AND GAS OPERATING RESULTS – THREE MONTHS ENDED JUNE 3 0 , 2015 AND 2014



			Canada
	United		Conven-
(Millions of dollars)	States		tional	Synthetic	Malaysia	Other	Total
Three Months Ended June 30, 2015
Oil and gas sales and other operating revenues	$	339.8	102.2	50.7	244.5	–	737.2
Lease operating expenses		78.6	32.7	43.5	72.7	–	227.5
Severance and ad valorem taxes		16.1	1.3	1.7	–	–	19.1
Depreciation, depletion and amortization		196.7	59.4	11.6	132.1	1.6	401.4
Accretion of asset retirement obligations		4.9	1.7	1.4	3.7	–	11.7
Exploration expenses
Dry holes		17.7	–	–	–	2.7	20.4
Geological and geophysical		3.6	–	–	1.3	1.8	6.7
Other		3.1	0.2	–	–	10.4	13.7
		24.4	0.2	–	1.3	14.9	40.8
Undeveloped lease amortization		19.7	4.2	–	–	0.3	24.2
Total exploration expenses		44.1	4.4	–	1.3	15.2	65.0
Selling and general expenses		22.9	6.5	0.2	0.5	14.4	44.5
Other expenses		1.8	(0.1)	–	–	12.1	13.8
Results of operations before taxes		(25.3)	(3.7)	(7.7)	34.2	(43.3)	(45.8)
Income tax provisions (benefits)		(8.8)	13.8	7.0	6.6	(13.2)	5.4
Results of operations (excluding corporate overhead and interest)	$	(16.5)	(17.5)	(14.7)	27.6	(30.1)	(51.2)


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		81.6	39.7	60.8	103.7	–	285.8
Severance and ad valorem taxes		26.5	1.2	1.2	—	–	28.9
Depreciation, depletion and amortization		188.6	62.4	12.3	192.4	1.2	456.9
Accretion of asset retirement obligations		4.3	1.6	2.3	4.2	–	12.4
Exploration expenses
Dry holes		0.7	–	–	–	39.2	39.9
Geological and geophysical		1.3	0.1	–	–	37.9	39.3
Other		2.4	0.2	–	–	28.1	30.7
		4.4	0.3	–	–	105.2	109.9
Undeveloped lease amortization		18.7	5.0	–	–	1.2	24.9
Total exploration expenses		23.1	5.3	–	–	106.4	134.8
Selling and general expenses		24.6	7.2	0.2	5.0	19.0	56.0
Other expenses		0.5	–	–	–	(0.7)	(0.2)
Results of operations before taxes		158.1	56.3	12.3	277.7	(126.1)	378.3
Income tax provisions		56.4	12.5	3.2	105.4	–	177.5
Results of operations (excluding corporate overhead and interest)	$	101.7	43.8	9.1	172.3	(126.1)	200.8

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

OIL AND GAS OPERATING RESULTS – SIX MONTHS ENDED JUNE 3 0 , 2015 AND 2014



			Canada
	United		Conven-
(Millions of dollars)	States		tional	Synthetic	Malaysia	Other	Total
Six Months Ended June 30, 2015
Oil and gas sales and other operating revenues	$	619.9	199.3	105.9	690.2	–	1,615.3
Lease operating expenses		180.4	58.3	87.4	133.8	–	459.9
Severance and ad valorem taxes		34.4	2.7	2.8	–	–	39.9
Depreciation, depletion and amortization		401.5	119.5	25.4	330.7	3.1	880.2
Accretion of asset retirement obligations		9.7	3.4	2.8	7.6	–	23.5
Exploration expenses
Dry holes		64.4	–	–	–	34.6	99.0
Geological and geophysical		5.3	–	–	1.3	16.9	23.5
Other		4.8	0.4	–		20.2	25.4
		74.5	0.4	–	1.3	71.7	147.9
Undeveloped lease amortization		36.5	8.4	–	–	0.9	45.8
Total exploration expenses		111.0	8.8	–	1.3	72.6	193.7
Selling and general expenses		45.3	13.3	0.4	1.2	29.1	89.3
Other expenses		7.5	43.9	–	–	12.1	63.5
Results of operations before taxes		(169.9)	(50.6)	(12.9)	215.6	(116.9)	(134.7)
Income tax provisions (benefits)		(59.5)	1.5	5.7	(35.1)	(14.8)	(102.2)
Results of operations (excluding corporate overhead and interest)	$	(110.4)	(52.1)	(18.6)	250.7	(102.1)	(32.5)


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

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 fu nctions, had a net cost of $ 37.8 million in the 2015 second quarter compared to a net cost of $ 58.1 million in the same 2014 quarter. Net cost s in the current year 2015 were $ 20.3 million lower than the prior-year quarter due to favorable impacts from foreign currency exchange and higher income tax benefits . Net after-tax gains of $ 1.3 million occurred in 2015 on transactions denominated in foreign currencies, while the 2014 quarter had net after-tax losses of $ 7.2 million.

For the first six months of 2015, corporate activit ies reflected net costs of $ 53.0 million compared to net costs of $99.4 million a year ago. S ix-month corporate costs in 2015 were favorable to 2014 by $ 46.4 million mostly due to favorable impacts from foreign currency exchange. Total after-tax gains associated with foreign currency transactions were $35.1 million in the 2015 period compared to after-tax losses of $4.1 million in the first six months of 2014.

Discontinued Operations

The Company has presented refining and marketing operations in the U.K. as discontinued operations in its consolidated financial statements. In June 2015, the Company completed an agreement to sell the remaining U.K. downstream assets.

The after-tax results of these operations for the three-month and six-month periods ended June 3 0 , 2015 and 2014 are reflected in the following table.




		Three Months Ended		Six Months Ended
		June 30,		June 30,
(Millions of dollars)		2015	2014	2015	2014
U.K. refining and marketing	$	15.4	(13.2)	(2.6)	(27.0)
U.K. exploration and production		(0.2)	(0.1)	(0.2)	(0.3)
Income (loss) from discontinued operations	$	15.2	(13.3)	(2.8)	(27.3)

Financial Condition

Net cash provided by continuing operating activities was $ 7 15.2 million for the first six months of 201 5 compared to $ 1,45 5.2 million during the same period in 201 4 . The decline in cash provided by operating activities in 2015 was primarily attributable to significantly lower realized sales prices for the Company’s oil and gas production during the current year. Changes in operating working capital other than cash and cash equivalents from continuin g operations generated cash of $107.2 million during the first six months of 201 5 , compared to $ 48. 5 million in 201 4 . Proceeds from sales of property and equipment generated cash of $423.1 million in 2015 compared to $3.1 million in 2014 with t he 2015 amount primarily relat ing to proceeds received upon sale of a 10% interest in Malaysian assets. Other significant sources of cash included $ 663.3 million in the 201 5 period and $ 320.3 million in 201 4 from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition. The Company borrowed $ 823 .0 million and $ 85 0 .0 million in the six-month periods of 201 5 and 201 4 , respectively, to fund capital development activities and repurchase Company stock. Net of repayments, in 2015 the Company added net borrowings of $373 .0 million under various credit facilities.

The most significant use of cash in both periods was for property additions and dry holes for continuing operations, which including amounts expensed, were $ 1,433.6 million and $ 1 , 840 . 5 million in the six-month periods ended June 30, 201 5 and 201 4 , respectively. Total cash dividends to shareholders amounted to $ 124.6 million in 201 5 and $ 112.1 million in 201 4 . The Company expended $ 250 .0 million to acquire 5,236,709 shares of Common stock through share repurchases during the first six months of 201 5 . In July 2015, the Company received additional shares of 730,604 upon conclusion of the accelerated share repurchase agreement. In the first six months of 201 4 , the Company spent $ 375 .0 million to repurchase c ommon shares. Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $ 629.8 million in the 201 5 period and $ 372.9 million in the 201 4 period. The Company used $450.0 million of cash in the 2015 period to repay current maturities of long-term debt.

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

Financial Condition (Contd.)

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



	Six Months Ended
	June 30,
(Millions of dollars)	2015		2014
Capital Expenditures – Continuing operations
Exploration and production	$	1,119.5		1,853.1
Corporate		25.6		3.2
Total capital expenditures	$	1,145.1		1,856.3

The reduction in capital expenditures in the exploration and production business in 2015 compared to 2014 was primarily attributable to lower development spending in the Eagle Ford Shale area in the United States and offshore Malaysia and lower spending on exploration drilling primarily in Cameroon .

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



	Six Months Ended
	June 30,
(Millions of dollars)	2015		2014
Property additions and dry hole costs per cash flow statements	$	1,433.6		1,840.5
Geophysical and other exploration expenses		48.9		107.7
Capital expenditure accrual changes and other		(337.4)		(91.9)
Total capital expenditures	$	1,145.1		1,856.3

Working capital (total current assets less total current liabilities) at June 3 0 , 2015 was $ 692.6 million, $ 561.4 million more than December 31, 2014, with the increase attributable to lower accounts payable for other operating activities and proceeds received from the sale of 10% interest in Malaysia in the first quarter 2015, partially offset by lower accounts receivable balances due to significant decline s in realized sales prices and lower invested cash balances held by the Company’s Canadian operations.

At June 3 0 , 2015, long-term debt of $ 3,264.9 million had increased by $ 747.2 million compared to December 31, 2014. A summary of capital employed at June 30 , 2015 and December 31, 2014 follows.



	June 30, 2015				December 31, 2014
(Millions of dollars)	Amount		%		Amount		%
Capital employed
Long-term debt	$	3,264.9	29.3	%	$	2,517.7	22.7	%
Stockholders' equity		7,866.0	70.7			8,573.4	77.3
Total capital employed	$	11,130.9	100.0	%	$	11,091.1	100.0	%

Cash and invested cash are maintained in several operating locations outside the United States. At June 30, 201 5 , cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included U.S. dollar equivalents of approximately $ 458.4 million in Canada and $ 811.0 million in Malaysia . In addition $111.3 million of cash was held in the United Kingdom, but was reflected in current Assets Held for Sale on the Company’s Consolidated Balance Sheet at June 30, 2015. 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 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.)

Financial Condition (Contd.)

On August 6, 2014, the Company announced that its Board of Directors had approved a share buyback program of up to $500 million of the Company’s shares of Common stock over the next year. On May 20, 2015 , the Company entered into a variable term, capped accelerated share repurchase transaction (ASR) with Wells Fargo Bank to repurchase an aggregate of $250 million of the Company’s common stock. As of Jun e 30, 2015, 5,236,709 shares of Common stock have been acquired under this repurchase agreement. In July, a further 730,604 shares were received upon final settlement of the ASR.

Accounting and Other Matters

In April 2015, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) that simplifies the presentation of debt issuance costs. The ASU requires that the cost of issuing debt be presented on the balance sheet as a direct reduction from the associated debt liability. These costs have historically been recorded as an asset, rather than a direct reduction of debt. This ASU does not affect the results of operations, as costs of debt issuance will continue to be amortized to interest expense. The Company is required to adopt the ASU effective in the first quarter of 2016, but early adoption is permitted. The Company adopted this ASU early, effective with the first quarter of 2015. This change in accounting principle is preferable due to allowing debt issuance costs and debt issuance discounts to be presented similarly in the Balance Sheet as reductions to recorded debt balances. A retrospective change to the December 31, 2014 Balance Sheet as presented in the Company’s 2014 Form 10-K is required due to the adoption. See Note O for further discussion of the retrospective adjustment.

During the first quarter 2015, the Company’s subsidiary in Canada identified a leak or leaks at an infield condensate transfer pipeline at the Seal field in a remote area of Alberta. Additional information associated with the leak or leaks are addressed in Note M to the Consolidated Financial Statements beginning on page 16 of this Form 10-Q. Based on information currently available to the Company, the changes in the recognized estimated remediation costs at the site are not expected to have a material adverse effect on the Company’s future net income, cash flows or liquidity.

Outlook

Average worldwide crude oil prices in July 2015 were lower than the average price during the second quarter of 2015, as a strengthening U . S . dollar, combined with the expectation of additional Iranian barrels coming to market subsequent to an agreement to withdraw sanctions on that count ry and a weakness in Chin ese demand. North American natural gas prices, however, have strengthened in July 2015 as power generation demand has increased in the U.S. due to warmer than normal temperatures across the Southeast, Northeast and Texas. The Company expects its total oil and natural gas production to average 200 ,000 barrels of oil equivalent per day in the third quarter 2015. The Company currently anticipates total capital expenditures for the full year 2015 to be approximately $ 2.3 billion.

The Company will primarily fund its capital program in 2015 using operating cash flow, but will supplement funding where necessary using borrowings under available credit facilities. The Company’s 201 5 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 further , 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.

The significant reduction in the sales prices of crude oil has caused the Company to reduce capital expenditures, including development drilling and completion operations in North America. The lower level of capital expenditures, if it continues, could lead to reductions in production levels in future periods. A continuation of very low oil and/or gas prices or further deterioration therein , could lead to negative future effects on the Company, which could include reductions in proved reserves, impairment charges, the necessity for cost containment measures, higher debt levels, and a reconsideration of the level of dividends on its common stock.

On June 30, 2015, the Company completed the sale of its former U.K. downstream assets. The Company retained an obligation to oversee the demolition of the former refinery site, for which the Company has entered into a contract with a third party to complete. The other primary obligation associated with this former business involves the defined benefit pension plan covering former employees, which will be ultimately settled over future periods. The settlement of these and other matters could lead to future financial accounting losses for the Company.

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

The Company has completed the sale of 30% of its working interest in most of its oil and gas properties in Malaysia as the final 10% sale was completed in January 2015. The total sale price of $2.0 billion for the 30% interest is subject to normal closing costs and settlement adjustments, which are scheduled to be completed in the third quarter 2015 . The final settlement with purchaser could lead to adjustments to the recorded gain and net cash proceeds .

Through June 30 , 2015, 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 follows:



	Contract or		Average
Commodities	Location	Dates	Volumes per Day		Average Prices
Canadian Natural Gas	TCPL–NOVA System	July – Dec. 2015		65 mmcf/d	C$4.13 per mcf
		Jan. – Dec. 2016		59 mmcf/d	C$3.19 per mcf
U.S. Oil	West Texas Intermediate	July – Dec. 2015		15,000 bbls/d	$63.07 per bbl.

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 Murphy’s exploration programs, the Company’s ability to maintain production rates and replace reserves, customer demand for Murphy’s products, adverse foreign exchange movements, political and regulatory instability, adverse developments in the U.S. or global capital markets, credit markets or economies generally and uncontrollable natural hazards. For further discussion of risk factors, see Murphy’s 2014 Annual Report on Form 10-K on file with the U.S. Securities and Exchange Commission. Murphy undertakes no duty to publicly update or revise any forward-looking statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note K to this Form 10-Q report, Murphy makes use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

There were commodity derivative contracts in place at June 30, 201 5 covering certain future U.S. crude oil sales volumes in 201 5 . A 10% increase in the respective benchmark price of these commodities would have de cr eased the recorded net asset associated with these derivative contracts by approximately $ 16.7 million, while a 10% decrease would have increased the recorded net asset by a similar amount.

There were derivative foreign exchange contracts in place at June 30, 201 5 to hedge the value of the U.S. dollar against the Canadian dollar for certain U.S. dollar receivables to be collected in July 2015 . A 10% strengthening of the U.S. dollar against the Canadian dollar would have increased the recorded net liability associated with these contracts by approximately $ 0.7 million, while a 10% weakening of the U.S. dollar would have reduced the recorded net liability by approximately $ 0.9 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 June 30, 201 5 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

The Company’s operations in the oil and gas business naturally lead to various risks and uncertainties. These risk factors are discussed in Item 1A. Risk Factors in its 201 4 Form 10-K filed on February 2 7, 2015. The Company has not identified any additional risk factors not previously disclosed in its 2014 Form 10-K report.

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

Murphy Oil Corporation

Issuer Purchases of Equity Securities



				Total
				Number	Approximate
				of Shares	Dollar Value
				Purchased	of Shares that
				as Part of	May Yet Be
	Total	Average		Publicly	Purchased
	Number of	Price		Announced	Under the
	Shares	Paid per		Plans or	Plans or
Period	Purchased	Share		Programs	Programs
April 1, 2015 to April 30, 2015	–	$	–	–	$	500,000,000
May 1, 2015 to May 31, 2015	5,236,709		–	5,236,709		250,000,000
June 1, 2015 to June 30, 2015	–		–	–		250,000,000
Total April 1, 2015 to June 30, 2015	5,236,709			5,236,709		250,000,000

1 On May 20, 201 5 , the Company announced that it had entered into a $ 250 million variable term, capped accelerated share repurchase agreement (ASR) with a major financial institution. 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. In May, the Company received the minimum number of shares under the tran saction, which totaled 5,236,709 shares. The ASR was completed in July 2015 and the Compa ny received an additional 730,604 shares upon completion of the ASR. This brought the total number of shares acquired under th is ASR transaction to 5,967,313 , with the average purchase price equal to $ 41.89 per share.

ITEM 6. EXHIBITS

The Exhibit Index on page 34 of this Form 10-Q report lists the exhibits that are hereby filed or incorporated by reference.

SIGNATURE

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

MURPHY OIL CORPORATION

(Registrant)

By /s/ KEITH CALDWELL

Keith Caldwell , Senior Vice President

and Controller (Chief Accounting Officer

and Duly Authorized Officer)

August 5 , 2015

(Date)

EXHIBIT INDEX



Exhibit
No.

12		Computation of Ratio of Earnings to Fixed Charges

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

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

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

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.

TABLE OF CONTENTS

Part I Item 1. Financial Statements Item 2. Management's Discussion and Analysis Of Financial Condition and Results Of Operations Item 2. Management S Discussion and Analysis (contd.)Item 3. Quantitative and Item 4. Controls and Procedures Part II Other Item 1. Legal Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 6. Exhibits

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MUR 10-Q Quarter ended June 30, 2015