MURPHY OIL CORP - Quarter Report: 2015 September (Form 10-Q)



UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark one)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934

For the quarterly period ended September 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 September 30, 2015 was 172,024,733

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 (Loss)		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		31
Item 6. Exhibits		31
Signature		32

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED BALANCE SHEETS (unaudited)

(Thousands of dollars)



	September 30,		December 31,
	2015		2014*
ASSETS
Current assets
Cash and cash equivalents	$	878,667		1,193,308
Canadian government securities with maturities greater than 90 days at the date of acquisition		415,097		461,313
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2015 and $1,609 in 2014		432,791		873,277
Inventories, at lower of cost or market
Crude oil		53,170		51,757
Materials and supplies		127,426		190,976
Prepaid expenses		157,455		77,281
Deferred income taxes		48,781		55,107
Assets held for sale		52,416		376,130
Total current assets		2,165,803		3,279,149
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $11,617,367 in 2015 and $9,503,524 in 2014		10,168,750		13,331,047
Deferred charges and other assets		293,409		62,582
Assets held for sale		–		50,960
Total assets	$	12,627,962		16,723,738
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	12,173		465,388
Accounts payable and accrued liabilities		1,621,415		2,471,897
Income taxes payable		7,588		59,054
Liabilities associated with assets held for sale		10,059		151,548
Total current liabilities		1,651,235		3,147,887
Long-term debt, including capital lease obligation		3,327,689		2,517,669
Deferred income taxes		306,379		1,193,864
Asset retirement obligations		885,984		841,526
Deferred credits and other liabilities		428,221		441,048
Liabilities associated with assets held for sale		–		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		902,241		906,741
Retained earnings		6,859,542		8,728,032
Accumulated other comprehensive loss		(621,759)		(170,255)
Treasury stock, 23,030,991 shares of Common Stock in 2015 and 17,540,636 shares of Common Stock in 2014, at cost		(1,306,626)		(1,086,124)
Total stockholders’ equity		6,028,454		8,573,434
Total liabilities and stockholders’ equity	$	12,627,962		16,723,738

*Reclassified to conform to current presentation.

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page 33.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS (unaudited)

(Thousands of dollars, except per share amounts)



		Three Months Ended		Nine Months Ended
	September 30,			September 30,
	2015		2014	2015	2014
REVENUES
Sales and other operating revenues	$	665,589	1,431,007	2,133,360	4,070,120
Gain (loss) on sale of assets		60	(133)	154,183	(5,130)
Interest and other income		49,300	2,163	87,443	3,468
Total revenues		714,949	1,433,037	2,374,986	4,068,458
COSTS AND EXPENSES
Lease operating expenses		183,826	265,518	643,736	813,638
Severance and ad valorem taxes		14,265	28,574	54,099	83,793
Exploration expenses, including undeveloped lease amortization		58,149	117,433	251,842	390,711
Selling and general expenses		71,791	82,960	237,934	269,986
Depreciation, depletion and amortization		433,706	499,151	1,318,123	1,354,393
Impairment of assets		2,300,974	–	2,300,974	–
Accretion of asset retirement obligations		11,918	12,600	35,437	36,992
Interest expense		32,009	34,970	91,945	101,625
Interest capitalized		(1,864)	(5,323)	(5,072)	(19,244)
Other expense		18,192	662	81,804	1,297
Total costs and expenses		3,122,966	1,036,545	5,010,822	3,033,191
Income (loss) from continuing operations before income taxes		(2,408,017)	396,492	(2,635,836)	1,035,267
Income tax expense (benefit)		(820,935)	125,435	(963,298)	452,255
Income (loss) from continuing operations		(1,587,082)	271,057	(1,672,538)	583,012
Loss from discontinued operations, net of taxes		(8,344)	(25,350)	(11,163)	(52,639)
NET INCOME (LOSS)	$	(1,595,426)	245,707	(1,683,701)	530,373
PER COMMON SHARE – BASIC
Income (loss) from continuing operations	$	(9.22)	1.52	(9.55)	3.25
Loss from discontinued operations		(0.04)	(0.14)	(0.07)	(0.29)
Net income (loss)	$	(9.26)	1.38	(9.62)	2.96
PER COMMON SHARE – DILUTED
Income (loss) from continuing operations	$	(9.22)	1.51	(9.55)	3.23
Loss from discontinued operations		(0.04)	(0.14)	(0.07)	(0.29)
Net income (loss)	$	(9.26)	1.37	(9.62)	2.94
Average Common shares outstanding
Basic		172,205,433	177,535,503	175,047,295	179,259,573
Diluted		172,205,433	178,856,078	175,047,295	180,578,085

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (unaudited)

(Thousands of dollars)



	Three Months Ended			Nine Months Ended
	September 30,			September 30,
	2015		2014	2015	2014

Net income (loss)	$	(1,595,426)	245,707	(1,683,701)	530,373
Other comprehensive income (loss), net of tax
Net loss from foreign currency translation		(195,440)	(192,329)	(462,054)	(195,374)
Retirement and postretirement benefit plans		3,116	1,505	9,105	3,996
Deferred loss on interest rate hedges reclassified to interest expense		482	484	1,445	1,450
Other comprehensive loss		(191,842)	(190,340)	(451,504)	(189,928)
COMPREHENSIVE INCOME (LOSS)	$	(1,787,268)	55,367	(2,135,205)	340,445

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)



	Nine Months Ended
	September 30,
	2015		2014
OPERATING ACTIVITIES
Net income (loss)	$	(1,683,701)	530,373
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities:
Loss from discontinued operations		11,163	52,639
Depreciation, depletion and amortization		1,318,123	1,354,393
Impairment of assets		2,300,974	–
Amortization of deferred major repair costs		5,450	6,390
Dry hole costs		120,459	203,607
Amortization of undeveloped leases		62,331	55,745
Accretion of asset retirement obligations		35,437	36,992
Deferred and noncurrent income tax charges (benefits)		(975,120)	64,557
Pretax (gains) losses from disposition of assets		(154,183)	5,130
Net decrease in noncash operating working capital		97,026	6,940
Other operating activities, net		(41,431)	17,531
Net cash provided by continuing operations activities		1,096,528	2,334,297
INVESTING ACTIVITIES
Property additions and dry hole costs		(1,975,069)	(2,806,705)
Proceeds from sales of property, plant and equipment		423,842	3,138
Purchase of investment securities*		(865,251)	(672,689)
Proceeds from maturity of investment securities*		852,394	587,341
Other investing activities, net		(19,538)	(19,233)
Net cash required by investing activities		(1,583,622)	(2,908,148)
FINANCING ACTIVITIES
Borrowings of debt		885,000	1,050,000
Repayments of debt		(450,000)	–
Capital lease obligation payments		(7,156)	–
Purchase of treasury stock		(250,000)	(375,000)
Withholding tax on stock-based incentive awards		(8,976)	(6,786)
Cash dividends paid		(184,789)	(174,248)
Other financing activities, net		(153)	(1,384)
Net cash provided (required) by financing activities		(16,074)	492,582
CASH FLOWS FROM DISCONTINUED OPERATIONS
Operating activities		(4,866)	(83,974)
Investing activities		5,343	(12,101)
Changes in cash included in current assets held for sale		179,774	103,694
Net increase in cash and cash equivalents of discontinued operations		180,251	7,619
Effect of exchange rate changes on cash and cash equivalents		8,276	(2,484)
Net decrease in cash and cash equivalents		(314,641)	(76,134)
Cash and cash equivalents at January 1		1,193,308	750,155
Cash and cash equivalents at September 30	$	878,667	674,021

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

See Notes to Consolidated Financial Statements, page 7.

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)




	Nine Months Ended
	September 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 shares at September 30, 2015 and 195,036,689 shares at September 30, 2014
Balance at beginning of period		195,040		194,920
Exercise of stock options		16		117
Balance at end of period		195,056		195,037
Capital in Excess of Par Value
Balance at beginning of period		906,741		902,633
Exercise of stock options, including income tax benefits		(73)		(11,354)
Restricted stock transactions and other		(38,260)		(27,977)
Stock-based compensation		33,925		33,291
Other		(92)		(26)
Balance at end of period		902,241		896,567
Retained Earnings
Balance at beginning of period		8,728,032		8,058,792
Net income (loss) for the period		(1,683,701)		530,373
Cash dividends		(184,789)		(174,248)
Balance at end of period		6,859,542		8,414,917
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		(170,255)		172,119
Foreign currency translation loss, net of income taxes		(462,054)		(195,374)
Retirement and postretirement benefit plans, net of income taxes		9,105		3,996
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes		1,445		1,450
Balance at end of period		(621,759)		(17,809)
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		322		345
Awarded restricted stock, net of forfeitures		29,176		21,185
Balance at end of period		(1,306,626)		(1,086,204)
Total Stockholders’ Equity	$	6,028,454		8,402,508

See Notes to Consolidated Financial Statements, page 7.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note A – 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 September 30, 2015 and December 31, 2014, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2015 and 2014, 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 2014 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report. Financial results for the nine-month period ended September 30, 2015 are not necessarily indicative of future results.

Note B – Property, Plant and Equipment

During the third quarter 2015, declines in future oil and gas prices provided indications of possible impairments in certain of the Company’s producing properties. As a result of management’s assessments, during the third quarter of 2015, the Company recognized a pretax noncash impairment charge of approximately $2,301.0 million to reduce the carrying value of certain producing properties in the Gulf of Mexico, Western Canada and Malaysia to their estimated fair value. The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs, and a discount rate believed to be consistent with those used by principal market participants in the applicable region. The following table reflects the recognized impairments for the three-month and nine-month periods of 2015.



	Three Months and Nine Months Ended
	September 30, 2015
(Thousands of dollars)		Impairment Expense	Net of Taxes
Gulf of Mexico	$	144,800	94,120
Western Canada – Heavy Oil		683,574	495,591
Malaysia		1,472,600	946,773
	$	2,300,974	1,536,484

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 September 30, 2015, the Company had total capitalized exploratory well costs pending the determination of proved reserves of 209.7 million. The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2015 and 2014.



(Thousands of dollars)	2015		2014
Beginning balance at January 1	$	120,455	393,030
Additions pending the determination of proved reserves		89,197	13,595
Balance at September 30	$	209,652	406,625

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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.



		September 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	$	52,249	5	3	$	32,192	2	1
One to two years		32,192	2	1		36,676	2	1
Two to three years		27,842	2	–		51,898	6	–
Three years or more		97,369	4	2		285,859	22	7
	$	209,652	13	6	$	406,625	32	9

Of the $157.4 million of exploratory well costs capitalized more than one year at September 30, 2015, $91.5 million is in the U.S. and $65.9 million is in Brunei. In both geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion.

During 2015, the Company completed the second phase of the sale of 30% of its oil and gas assets in Malaysia and received net cash proceeds of $417.2 million. The Company recorded an after-tax gain of $218.8 million on the sale of the final 10% portion of the total 30% sold. Combined net cash proceeds received to date from the 30% sale totaled $1.87 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 crude oil and finished products in prior periods was 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 all inventories reported under the LIFO method were included in the sale. At December 31, 2014, 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 were included in Current assets held for sale on the Consolidated Balance Sheet as of December 31, 2014.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note D – Discontinued Operations

The Company has accounted for its U.K. refining and marketing operations as discontinued operations for all periods presented. The Company completed its agreement to sell the remaining U.K. downstream assets at the end of the second quarter of 2015. The 2015 nine-month period includes an adjustment to the impairment recognized as a result of the

final sale of the U.K. downstream assets. There were no adjustments to impairment in the three month period ended September 30, 2015.

The results of operations associated with these discontinued operations for the three-month and nine-month periods ended September 30, 2015 and 2014 were as follows:




	Three Months			Nine Months
	Ended September 30,			Ended September 30,
(Thousands of dollars)		2015	2014	2015	2014
Revenues	$	(1,342)	509,037	381,154	2,752,557

Loss before income taxes	$	(8,366)	(27,163)	(8,029)	(61,396)
Income tax (benefit) expense		(22)	(1,813)	3,134	(8,757)
Loss from discontinued operations	$	(8,344)	(25,350)	(11,163)	(52,639)

The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheets at September 30, 2015 and December 31, 2014.



	September 30,		December 31,
(Thousands of dollars)	2015		2014
Current assets
Cash	$	20,738	200,512
Accounts receivable		12,067	97,568
Inventories		313	42,161
Other		19,298	35,889
Total current assets held for sale	$	52,416	376,130
Non-current assets
Property, plant and equipment, net	$	–	50,947
Other		–	13
Total non-current assets held for sale	$	–	50,960
Current liabilities
Accounts payable	$	2,895	59,023
Other accrued taxes payable		428	40,653
Accrued compensation and severance		3,715	30,872
Refinery decommissioning cost		3,021	21,000
Total current liabilities associated with assets held for sale	$	10,059	151,548
Non-current liabilities
Deferred income taxes payable	$	–	3,873
Deferred credits and other liabilities		–	4,437
Total non-current liabilities associated with assets held for sale	$	–	8,310

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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 September 30, 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 $157.2 million at September 30, 2015. These uncommitted facilities may be withdrawn by the various banks at any time. On October 16, 2015, the Company renewed its 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 2018.

The 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 $12.2 million and $213.0 million, respectively, associated with this lease at September 30, 2015.

Note F – Cash Flow Disclosures

Additional disclosures regarding cash flow activities are provided below.



	Nine Months
		Ended September 30,
(Thousands of dollars)	2015		2014
Net decrease in operating working capital other than cash and cash equivalents:
Decrease in accounts receivable	$	389,413	29,586
Increase in inventories		(16,607)	(3,326)
Increase in prepaid expenses		(87,051)	(2,235)
Decrease in deferred income tax assets		4,863	1,290
Increase (decrease) in accounts payable and accrued liabilities		(134,458)	59,369
Decrease in current income tax liabilities		(59,134)	(77,744)
Total	$	97,026	6,940
Supplementary disclosures (including discontinued operations):
Cash income taxes paid, net of refunds	$	111,897	438,309
Interest paid, net of amounts capitalized		60,766	44,657

Non-cash investing activities, related to continuing operations:
Asset retirement costs capitalized	$	55,258	15,509
Decrease in capital expenditure accrual		374,720	106,031

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.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 2015 and 2014.



	Three Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2015	2014	2015		2014
Service cost	$	5,898	6,208		826		672
Interest cost		8,972	8,239		1,192		1,278
Expected return on plan assets		(10,471)	(8,506)		–		–
Amortization of prior service cost		187	227		(21)		(20)
Amortization of transitional asset		402	208		2		1
Recognized actuarial loss		3,885	1,735		193		59
Net periodic benefit expense	$	8,873	8,111		2,192		1,990

	Nine Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2015	2014	2015		2014
Service cost	$	15,751	19,048		2,482		2,016
Interest cost		24,893	24,707		3,576		3,833
Expected return on plan assets		(27,882)	(25,514)		–		–
Amortization of prior service cost		580	680		(62)		(61)
Amortization of transitional asset		947	628		5		4
Recognized actuarial loss		11,667	5,201		578		177
		25,956	24,750		6,579		5,969
Special termination benefits		8,606	–		–		–
Curtailments		306	–		–		–
Net periodic benefit expense	$	34,868	24,750		6,579		5,969

Termination and curtailment expenses for the nine months ended September 30, shown in the table above relate to restructuring activities in the U.S. undertaken by the Company in the second quarter 2015.

During the nine-month period ended September 30, 2015, the Company made contributions of $33.8 million to its defined benefit pension and postretirement benefit plans. Remaining required funding in 2015 for the Company’s defined benefit pension and postretirement plans is anticipated to be $2.4 million.

Note H – Incentive Plans

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

The 2012 Annual Incentive Plan (2012 Annual Plan) authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and other key employees. Cash awards under the 2012 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. The 2012 Long-Term Incentive Plan (2012 Long-Term Plan) authorizes the Committee to make grants of the Company’s Common Stock and other stock-based incentives to employees. These grants may be in the form of stock options (nonqualified or incentive), stock appreciation rights (SAR), restricted stock, restricted stock units (RSU), performance units, performance shares, dividend equivalents and other stock-based incentives. The 2012 Long-Term Plan expires in 2022. A total of 8,700,000 shares are issuable during the life of the 2012 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding. The Company has an Employee Stock Purchase Plan that permits the issuance of up to 980,000 shares through September 30, 2017. The Company also has a Stock Plan for Non-Employee Directors that permits the issuance of restricted stock and stock options or a combination thereof to the Company’s Directors.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Incentive Plans (Contd.)

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, all stock option exercises are non-cash transactions for the Company. The employee will receive net shares, after applicable statutory withholding taxes, upon each exercise. The actual income tax benefit realized for the tax deductions from option exercises of the share-based payment arrangements totaled $3.8 million for the nine-month period ended September 30, 2014. No income tax benefit was realized from option exercises for the nine-month period ended September 30, 2015.

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



	Nine Months Ended
	September 30,
(Thousands of dollars)		2015	2014
Compensation charged against income before tax benefit	$	30,722	45,373
Related income tax benefit recognized in income		9,046	14,036

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 nine-month periods ended September 30, 2015 and 2014. The following table reconciles the

weighted-average shares outstanding used for these computations.



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
(Weighted-average shares)	2015	2014	2015	2014
Basic method	172,205,433	177,535,503	175,047,295	179,259,573
Dilutive stock options and restricted stock units*	–	1,320,575	–	1,318,512
Diluted method	172,205,433	178,856,078	175,047,295	180,578,085

*Due to a net loss recognized by the Company for the three-month and nine-month periods ended September 30, 2015,

no unvested stock awards were included in the computation of diluted earnings per share because the effect would have

been anti-dilutive.

The following table reflects certain options to purchase shares of common stock that were outstanding during the 2015 and 2014 periods but were not included in the computation of diluted earnings per share because the incremental shares from the assumed conversion were antidilutive.



	Three Months Ended				Nine Months Ended
		September 30,			September 30,
		2015	2014		2015		2014
Antidilutive stock options excluded from diluted shares		5,807,453		1,998,009		5,770,731		1,855,667
Weighted average price of these options	$	53.13		58.53		53.25		58.80

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note J – Income Taxes

The Company’s effective income tax rate often 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 nine-month periods in 2015 and 2014, the Company’s effective income tax rates were as follows:



	2015	2014
Three months ended September 30	34.1%	31.6%
Nine months ended September 30	36.6%	43.7%

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

nine-month period ended September 30, 2015 was above the U.S. statutory tax rate primarily due to a deferred tax benefit associated with the sale of Malaysian assets. The effective tax rate for the nine-month period ended September 30, 2014 was above the U.S. statutory tax rate, primarily due to other expenses in certain foreign jurisdictions for which no tax benefits were recognized.

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 September 30, 2015, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows:

United States – 2011; Canada – 2008; Malaysia – 2008; and United Kingdom – 2012.

During the third quarter of 2015, the Company received approval from the Malaysia Ministry of Finance granting “marginal” field status to three of its fields in its two shallow-water blocks, SK 309 and SK 311, offshore Sarawak. A “marginal” field is a field with a Field Development Plan which shows potential crude oil reserves not exceeding 30 million stock tank barrels or natural gas reserves not exceeding 500 billion standard cubic feet. Incentives include a reduced tax rate from the current 38% statutory rate to 25% on taxable income in the fields, accelerated capital allowance claims on capital spending and export duty exemption on crude oil sales. The benefits of the reduced statutory tax rate may be carried back to the earliest date of production from the impacted field from 2013 forward. As a result of this reduced tax rate, the Company

recorded total income tax benefits of approximately $21.8 million in the three-month and nine-month periods ended September 30, 2015.

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 Operations. 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 Loss. This deferred cost is being reclassified to Interest Expense in the Consolidated Statements of Operations over the period until the associated notes mature in 2022.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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 September 30, 2015 and 2014. The impact from marking to market these commodity derivative contracts improved loss before income taxes by $24.2 million for the nine-month period ended September 30, 2015 and decreased income before income taxes by $17.2 million for the nine-month period ended September 30, 2014.

Open West Texas Intermediate (WTI) contracts for each period were as follows:



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

At September 30, 2014
October – December 2014	22,000	$ 93.26	per barrel

Subsequent to September 30, 2015, the Company added 20,000 barrels per day in WTI contracts for all of 2016 at an average price of $52.01 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 $6.2 million and $15.0 million U.S. dollars were outstanding at September 30, 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 improved income (loss) before income taxes by $22 thousand and $0.2 million for the nine-month periods ended September 30, 2015 and 2014, respectively.

At September 30, 2015 and December 31, 2014, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.



	September 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	$	31,999	Accounts receivable	$	23,168
Foreign exchange	Accounts receivable		22	Accounts payable		(25)

For the three-month and nine-month periods ended September 30, 2015 and 2014, the gains and losses recognized in the Consolidated Statements of Operations for derivative instruments not designated as hedging instruments are presented in the following table.



			Gain (Loss)
		Three Months Ended			Nine Months Ended
(Thousands of dollars)		September 30,			September 30,
Type of Derivative Contract	Statement of Operations Location		2015	2014	2015	2014
Commodity	Sales and other operating revenues	$	39,392	37,305	46,811	(17,150)
Foreign exchange	Interest and other income		33	(838)	47	4,062
		$	39,425	36,467	46,858	(13,088)

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 nine-month periods ended September 30, 2015 and 2014, $2.2 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 September 30, 2015 was $12.8 million, which is recorded, net of income taxes of $6.9 million, in Accumulated Other Comprehensive Loss in the Consolidated Balance Sheet. The Company expects to charge approximately $0.7 million of this deferred cost to income in the form of interest expense during the remaining three months of 2015.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Fair Values – Nonrecurring

As a result of significantly lower commodity prices during the third quarter of 2015, the Company recognized approximately $2,301.0 million in pretax noncash impairment charges related to producing properties. The fair value information associated with these impaired properties is presented in the following table.


	September 30, 2015
						Total
					Net Book	Pretax
					Value	(Noncash)
	Fair Value				Prior to	Impairment
		Level 1	Level 2	Level 3	Impairment	Loss
(Thousands of dollars)
Assets:
Impaired proved properties
Gulf of Mexico	$	–	–	216,602	361,402	144,800
Western Canada		–	–	23,526	707,100	683,574
Malaysia		–	–	1,208,900	2,681,500	1,472,600
	$	–	–	1,449,028	3,750,002	2,300,974

The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs, and a discount rate believed to be consistent with those used by principal market participants in the applicable region.

Fair Values – Recurring

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 September 30, 2015 and December 31, 2014 are presented in the following table.

September 30, 2015

December 31, 2014

(Thousands of dollars)

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total

Assets:

Foreign currency exchange
derivative contracts

–

Commodity derivative
contracts

–

31,999

–

31,999

–

23,168

–

23,168

–

32,021

–

32,021

–

23,168

–

23,168

Liabilities:

Nonqualified employee
savings plans

12,195

–

12,195

14,408

–

14,408

Foreign currency exchange
derivative contracts

–

12,195

–

12,195

14,408

–

14,433

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 Operations 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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

in the fair value of the nonqualified employee savings plan is recorded in Selling and General Expenses in the Consolidated Statements of Operations.

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 September 30, 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, 2014 and September 30, 2015 and the changes during the nine-month period ended September 30, 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		Adjustments1		Hedges1		Total1
Balance at December 31, 2014	$	33,701		(189,752)		(14,204)		(170,255)
Components of other comprehensive income (loss):
Before reclassifications to income		(503,799)		767		–		(503,032)
Reclassifications to income		41,745	2	8,338	3	1,445	4	51,528
Net other comprehensive income (loss)		(462,054)		9,105		1,445		(451,504)
Balance at September 30, 2015	$	(428,353)		(180,647)		(12,759)		(621,759)

1All amounts are presented net of income taxes.

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

3Reclassifications before taxes of $12,768 for the nine-month period ended September 30, 2015 are included in the computation of net periodic benefit expense. See Note G for additional information. Related income taxes of $4,430 for the nine-month period ended September 30, 2015 are included in Income tax expense.

4Reclassifications before taxes of $2,222 for the nine-month period ended September 30, 2015 are included in Interest expense. Related income taxes of $777 for the nine-month period ended September 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.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note M – Environmental and Other Contingencies (Contd.)

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 investigation and remediation plan is progressing as planned and the Company’s insurers have been notified. The Company has not yet established a complete estimate of the costs to remediate the site. Based on the assessments done to date, the 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 September 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 2015 and 2016 of approximately 65 million cubic feet per day at Cdn $4.13 per MCF and 59 million cubic feet per day at Cdn $3.19 per MCF, respectively. These natural gas contracts have been accounted for as normal sales for accounting purposes.

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 has elected to adopt 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)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Business Segments



				Three Months Ended		Three Months Ended
	Total Assets			September 30, 2015		September 30, 2014
	at September 30,			External	Income	External	Income
(Millions of dollars)	2015			Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States	$	5,935.2		335.1	(107.8)	667.6	130.5
Canada		2,540.5		123.2	(507.0)	246.9	40.4
Malaysia		2,527.8		207.3	(952.7)	516.4	148.0
Other		155.3		–	(28.6)	–	(7.5)
Total exploration and production		11,158.8		665.6	(1,596.1)	1,430.9	311.4
Corporate		1,416.8		49.3	9.0	2.1	(40.4)
Assets/revenue/income (loss) from continuing operations		12,575.6		714.9	(1,587.1)	1,433.0	271.0
Discontinued operations, net of tax		52.4		–	(8.3)	–	(25.3)
Total	$	12,628.0		714.9	(1,595.4)	1,433.0	245.7


				Nine Months Ended		Nine Months Ended
				September 30, 2015		September 30, 2014
				External	Income	External	Income
(Millions of dollars)				Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States			$	955.0	(218.1)	1,660.4	335.3
Canada				428.4	(577.8)	807.4	160.9
Malaysia				897.6	(701.9)	1,592.2	482.6
Other				–	(130.7)	(0.2)	(256.0)
Total exploration and production				2,281.0	(1,628.5)	4,059.8	722.8
Corporate				94.0	(44.0)	8.6	(139.8)
Revenue/income (loss) from continuing operations				2,375.0	(1,672.5)	4,068.4	583.0
Discontinued operations, net of tax				–	(11.2)	–	(52.6)
Total			$	2,375.0	(1,683.7)	4,068.4	530.4

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

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

Overall Review

During the third quarter 2015, worldwide benchmark oil and natural gas prices continued to be significantly below average comparable benchmark prices during the third quarter 2014. These lower oil and natural gas prices have led the Company to incur losses from operations in 2015 and due to decline of future oil prices from previous quarter-end levels resulted in the Company recognizing significant noncash impairment expenses totaling $2,301.0 million before tax and $1,536.5 million after-tax for producing heavy oil properties in Western Canada and producing offshore properties in Malaysia and the Gulf of Mexico. Although the Company is aggressively attacking its overall cost structure, a continuation of very low commodity prices would continue to lead to adverse effects 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			Nine Months Ended
	September 30,			September 30,
(Millions of dollars)	2015		2014	2015		2014
Exploration and production	$	(1,596.1)	311.4		(1,628.5)		722.8
Corporate and other		9.0	(40.4)		(44.0)		(139.8)
Income (loss) from continuing operations		(1,587.1)	271.0		(1,672.5)		583.0
Discontinued operations		(8.3)	(25.3)		(11.2)		(52.6)
Net income (loss)	$	(1,595.4)	245.7		(1,683.7)		530.4

Murphy’s net loss in the third quarter of 2015 was $1,595.4 million ($9.26 per diluted share) compared to net income of $245.7 million ($1.37 per diluted share) in the third quarter of 2014. Income (loss) from continuing operations decreased from a profit of $271.0 million ($1.51 per diluted share) in the 2014 quarter to a loss of $1,587.1 million ($9.22 per diluted share) in 2015. In the 2015 third quarter, the Company’s exploration and production continuing operations incurred a loss of $1,596.1 million compared to earnings of $311.4 million in the 2014 quarter. The net loss in the 2015 quarter was unfavorably impacted by impairments and lower revenues due to significantly lower realized oil and natural gas sales prices, offset in part by lower exploration costs, depreciation expense and lease operating expenses. The corporate function had after-tax income of $9.0 million in the 2015 third quarter compared to after-tax costs of $40.4 million in the 2014 period with the favorable variance in the current period mostly due to foreign exchange effects and lower administrative costs. The 2015 third quarter included a loss from discontinued operations of $8.3 million ($0.04 per diluted share) compared to a loss of $25.3 million ($0.14 per diluted share) in the 2014 period. Discontinued operations primarily consist of costs relating to winding down of refining and marketing operations in the U.K., the final components of which were sold at the end of the second quarter 2015.

For the first nine months of 2015, net loss totaled $1,683.7 million ($9.62 per diluted share) compared to net income of $530.4 million ($2.94 per diluted share) for the same period in 2014. Continuing operations had a loss of $1,672.5 million ($9.55 per diluted share) in the first nine months of 2015, down from income of $583.0 million ($3.23 per diluted share) for the 2014 period. In the first nine months of 2015, the Company’s exploration and production operations incurred a loss of $1,628.5 million compared to earnings of $722.8 million in the same period of 2014. Exploration and production earnings in 2015 were below the 2014 period primarily due to impairment charges coupled with significantly lower oil prices realized and lower oil volumes sold, partially offset by lower operating expenses, lower depreciation expense, lower exploration expenses and lower selling and general expenses coupled with the gain on the second phase of its sale of assets in Malaysia. Corporate after-tax costs were $44.0 million in the first nine months of 2015 compared to after-tax costs of $139.8 million in 2014 as the current period had a favorable variance for the effects of foreign currency exchange, lower administrative cost, and increased tax benefits partially offset by higher net interest expense. Net loss in the first nine months of 2015 included a loss from discontinued operations of $11.2 million ($0.07 per diluted share) compared to a loss of $52.6 million ($0.29 per diluted share) in the 2014 period.

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			Nine Months Ended
	September 30,			September 30,
(Millions of dollars)	2015		2014	2015	2014
Exploration and production
United States	$	(107.8)	130.5	(218.1)	335.3
Canada		(507.0)	40.4	(577.8)	160.9
Malaysia		(952.7)	148.0	(701.9)	482.6
Other International		(28.6)	(7.5)	(130.7)	(256.0)
Total	$	(1,596.1)	311.4	(1,628.5)	722.8

Third quarter 2015 vs. 2014

United States exploration and production operations reported a loss of $107.8 million in the third quarter of 2015 compared to a profit of $130.5 million in the 2014 quarter. Results were $238.3 million lower in the 2015 quarter compared to the same period in 2014 due to asset impairments primarily caused by low oil prices and lower realized oil and natural gas sales prices, partially offset by increased oil sales volumes. Revenue in the U.S. fell $332.5 million in the third quarter 2015 primarily due to lower oil and natural gas realized sales prices. However, produced oil volumes were higher in 2015 at both Eagle Ford Shale in South Texas and in the Gulf of Mexico. Lease operating expenses decreased by $17.1 million due to lower costs in Eagle Ford Shale and lower repair costs offshore Gulf of Mexico compared to same quarter 2014. Severance and ad valorem taxes in the 2015 quarter were $13.2 million lower than the 2014 period primarily due to weaker average commodity prices. Depreciation expense decreased $13.7 million in 2015 compared to 2014 due to lower unit rates in the 2015 period. Impairment expense was $144.8 million in 2015 due to write down of certain producing properties in the Gulf of Mexico. Exploration expenses were down $64.1 million in the third quarter of 2015 primarily related to lower dry hole costs.

Operations in Canada had losses of $507.0 million in the third quarter 2015 compared to earnings of $40.4 million in the 2014 quarter. Canadian results of operations were $547.4 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 $525.6 million lower in 2015 due to impairment expense, lower average realized sales prices for crude oil and natural gas and lower oil volume sold. These 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 $20.0 million lower in the 2015 quarter due to weaker Canadian dollar exchange rates and lower repair costs. Impairment expense was $683.6 million in 2015 due to a write down of heavy oil properties at Seal in Western Canada. Synthetic operations results were lower by $21.8 million in the third quarter of 2015 due to lower oil production and lower sales price. Lease operating expenses associated with synthetic operations were $18.3 million lower in the 2015 quarter due to lower maintenance costs, lower fuel costs and a weaker Canadian dollar exchange rate.

Malaysia operations reported losses of $952.7 million in the 2015 quarter compared to earnings of $148.0 million during the same period in 2014. Results were down $1,100.7 million in 2015 in Malaysia due to impairment expense, lower volumes sold and lower realized sales prices for oil and natural gas, partially offset by lower lease operating expenses and lower depreciation expense. 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 $26.3 million due to the sale mentioned above, less maintenance costs and lower volume sold compared to 2014. Depreciation expense was $41.5 million lower in 2015 compared to the 2014 quarter primarily due to lower oil and natural gas volumes sold. Impairment expense was $1,472.6 million in 2015 due to write downs of certain offshore producing properties. Other expenses increased by $17.3 million in the 2015 period primarily due to write down of certain material and supply inventory to fair market value.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Third quarter 2015 vs. 2014 (Contd.)

Other international operations reported a loss of $28.6 million in the third quarter of 2015 compared to a loss of $7.5 million in the 2014 quarter. The $21.1 million decrease in the 2015 period was primarily related to income tax benefits recognized in the 2014 quarter related to exiting the Central Dohuk block in the Kurdistan region of Iraq.

Total hydrocarbon production averaged 207,586 barrels of oil equivalent per day in the 2015 third quarter, which represented a 9.7% decrease from the 229,759 barrels of oil equivalents per day produced in the 2014 quarter. The Company sold 30% of its interests in Malaysia in late 2014 and early 2015. On a pro-forma basis, assuming the sale of 30% of the Company’s interest in Malaysia properties occurred at the beginning of 2014, total hydrocarbon production in the 2015 third quarter increased approximately 2% compared to the 2014 period as adjusted for the sale. Average crude oil and condensate production was 125,170 barrels per day in the third quarter of 2015 compared to 144,934 barrels per day in the third 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 added production from the Medusa field’s subsea expansion project completed in June 2015. Heavy oil production from the Seal area in Western Canada was lower in 2015 primarily due to volumes shut-in associated with uneconomic wells and environmental monitoring together with natural decline. Oil production offshore Eastern Canada was lower during 2015 primarily due to downtime for a turnaround at the Hibernia facilities. Lower oil production in 2015 in Malaysia was primarily attributable to less net oil volumes produced due to the sale of 30% of the Company’s total interest in late 2014 and early 2015. On a worldwide basis, the Company's crude oil and condensate prices averaged $46.20 per barrel in the third quarter 2015 compared to $89.36 per barrel in the 2014 period, a decline of 48% quarter to quarter. Total production of natural gas liquids (NGL) was 11,093 barrels per day in the 2015 third quarter compared to 10,923 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. The average sales price for U.S. NGL was $10.25 per barrel in the 2015 quarter compared to $27.89 per barrel in 2014. Natural gas sales volumes averaged 428 million cubic feet per day in the third quarter 2015 compared to 443 million cubic feet per day in 2014. Natural gas sales volumes increased in North America for 2015 due to growth of associated gas production caused by ongoing development drilling in our predominately oil-based Eagle Ford Shale in South Texas and second half 2014 drilling in the Tupper area of Western Canada, somewhat offset by lower production volumes in the Gulf of Mexico. The increase in natural gas sales volumes in 2015 was somewhat offset by lower volumes in Malaysia due to both lower entitlement percentages and the sale of 30% of the Company’s total interests. North American natural gas sales prices averaged $2.42 per thousand cubic feet (MCF) in the 2015 quarter, 33% below the $3.63 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 $3.75 per MCF, compared to a price of $5.11 per MCF in the 2014 quarter and decreased due to lower sales prices received offset in part by lower levels of revenue sharing with the local government in the 2015 period.

Nine months 2015 vs. 2014

U.S. E&P operations incurred a loss of $218.1 million for the nine months ended September 30, 2015 compared to income of $335.3 million in the 2014 period. The 2015 income reduction of $553.4 million was primarily caused by impairment expense and lower realized sales prices for oil and natural gas, partially offset by higher production volume. Depreciation expense increased by $31.2 million in 2015 primarily due to increased production volumes at both Eagle Ford Shale and Gulf of Mexico. Severance and ad valorem tax expense in the first nine months of 2015 was $29.2 million lower than the 2014 period primarily due to weaker average commodity prices. Impairment expense was $144.8 million in 2015 due to a write down of certain producing properties in the Gulf of Mexico.

Canadian operations had a loss of $577.8 million in the first nine months of 2015 compared to income of $160.9 million a year ago. Operating results for conventional operations declined by $662.5 million in the 2015 period while synthetic operation’s operating results declined by $76.2 million compared to the same period in 2014. Sales revenue within conventional operations declined for 2015 by $228.3 million compared to 2014, primarily due to lower realized oil and natural gas prices and lower oil sales volumes. Lease operating and depreciation expenses for conventional operations were lower by $42.2 million and $21.1 million, respectively, in 2015 mostly related to lower oil sales volumes and weaker Canadian dollar exchange rate in the current year. Impairment expense of $683.6 million in 2015 was due to a write down of heavy oil properties at Seal in Western Canada. Other expenses increased by $43.9 million due to an environmental remediation provision associated with the condensate leak or leaks in the transfer pipeline at the Seal heavy oil area. Synthetic operating results were lower by $76.2 million in the first nine months of 2015 due to weaker realized oil prices and lower production volumes. Lease operating expenses associated with synthetic operations were reduced by $55.4 million in 2015 due to lower maintenance costs and weaker Canadian dollar exchange rates.

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Nine months 2015 vs. 2014 (Contd.)

Malaysia operations had a loss of $701.9 million in the first nine months of 2015 compared to earnings of $482.6 million in the 2014 period. Earnings were down $1,184.5 million in 2015 primarily due to impairment expense and lower realized sales prices for oil and natural gas and 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 $77.5 million primarily due to lower volume sold, lower maintenance costs and no repeat of 2014 start-up costs for Siakap North, offshore Sabah. Depreciation expense in 2015 was $46.0 million less than 2014 due to lower volumes sold. Impairment expense was $1,472.6 million due to write down of certain offshore producing properties. Other expense increased by $17.3 million in the 2015 period primarily due to write down of certain material and supply inventory to fair market value.

Other international operations reported a loss of $130.7 million in the first nine months of 2015 compared to a loss of $256.0 million in the 2014 period. The 2015 period included lower dry hole costs of $98.3 million, with the higher 2014 costs primarily associated with unsuccessful wildcat drilling offshore Cameroon. The current period included lower geological and geophysical expense of $33.1 million, principally for seismic data acquired in 2014 in Namibia. Other exploration expenses were $11.2 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 210,313 barrels of oil equivalent per day during the nine months ended September 30, 2015, a decrease from 214,888 barrels of oil equivalent produced in the same period in 2014. On a pro-forma basis, assuming the sale of 30% of the Company’s interest in Malaysia properties occurred at the beginning of 2014, total hydrocarbon production for the nine month period ended September 30, 2015 increased 11% compared to the 2014 period as adjusted for the sale. Crude oil, condensate and gas liquids production in the nine months of 2015 averaged 128,888 barrels per day compared to 135,801 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 an 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 uneconomic conditions together with natural well decline. Oil production offshore Eastern Canada was lower in 2015 due to less production at Hibernia field primarily due to planned maintenance in 2015. Synthetic oil production in Canada also was lower in 2015 due to impacts of unplanned outages 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 nine months of 2015, the Company’s sales price for crude oil and condensate averaged $49.58 per barrel, down from $93.49 per barrel in 2014. The sales price for U.S. natural gas liquids averaged $11.90 per barrel in 2015 compared to $29.92 per barrel in 2014. Natural gas sales volumes increased from 423 million cubic feet per day in 2014 to 426 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 nearly offset by declines in Malaysia due primarily to sale of 30% of the Company’s total interests. The average sales price for North American natural gas in the first nine months of 2015 was $2.44 per MCF, down from $3.92 per MCF realized in 2014. Natural gas production at fields offshore Sarawak was sold at an average realized price of $4.31 per MCF in 2015 compared to $5.67 per MCF in 2014. The Sarawak gas price was weaker in 2015 primarily due to lower average selling prices 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 three-month and nine-month periods ended September 30, 2015 and 2014 follow.



	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2015	2014	2015	2014
Net crude oil and condensate produced – barrels per day	125,170	144,934	128,888	135,801
United States – Eagle Ford Shale	48,304	47,745	48,423	43,653
– Gulf of Mexico and other	16,992	16,534	14,027	13,266
Canada – light	91	38	104	38
– heavy	4,975	6,784	5,837	7,433
– offshore	6,846	7,823	7,413	8,216
– synthetic	10,907	11,200	11,230	11,481
Malaysia1 – Sarawak	15,194	21,679	15,696	19,590
– Block K	21,861	33,131	26,158	32,124
Net crude oil and condensate sold – barrels per day	124,549	142,440	129,294	135,942
United States – Eagle Ford Shale	48,304	47,745	48,423	43,653
– Gulf of Mexico and other	16,992	16,534	14,027	13,266
Canada – light	91	38	104	38
– heavy	4,975	6,784	5,837	7,433
– offshore	5,611	7,092	7,238	8,605
– synthetic	10,907	11,200	11,230	11,481
Malaysia1 – Sarawak	18,493	23,660	17,546	21,287
– Block K	19,176	29,387	24,889	30,179
Net natural gas liquids produced – barrels per day	11,093	10,923	10,431	8,580
United States – Eagle Ford Shale	8,192	6,521	7,744	5,409
– Gulf of Mexico and other	2,264	3,412	2,020	2,308
Canada	1	23	9	23
Malaysia1 – Sarawak	636	967	658	840
Net natural gas liquids sold – barrels per day	11,789	11,480	10,466	8,625
United States – Eagle Ford Shale	8,192	6,521	7,744	5,409
– Gulf of Mexico	2,264	3,412	2,020	2,308
Canada	1	23	9	23
Malaysia1 – Sarawak	1,332	1,524	693	885
Net natural gas sold – thousands of cubic feet per day	427,937	443,413	425,964	423,041
United States – Eagle Ford Shale	39,543	37,782	39,203	31,890
– Gulf of Mexico and other	47,987	67,137	53,010	50,831
Canada	196,111	151,784	194,136	144,873
Malaysia1 – Sarawak	128,963	174,958	117,339	166,036
– Block K	15,333	11,752	22,276	29,411
Total net hydrocarbons produced – equivalent barrels per day2	207,586	229,759	210,313	214,888
Total net hydrocarbons sold – equivalent barrels per day2	207,661	227,822	210,754	215,074

1 The Company sold 20% of its 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. Total production volumes

during the three-month and nine-month periods in 2014 for the 30% volumes sold were approximately 26,000 and 25,500 barrels

of oil equivalent per day, respectively.

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			Nine Months Ended
	September 30,			September 30,
	2015		2014	2015	2014
Weighted average sales prices
Crude oil and condensate – dollars per barrel
United States – Eagle Ford Shale	$	48.70	93.56	49.27	95.50
– Gulf of Mexico and other		44.94	97.03	49.45	99.36
Canada1 – light		37.70	85.92	43.41	93.17
– heavy		20.28	57.86	25.09	56.69
– offshore		48.09	97.63	53.77	105.41
– synthetic		46.53	93.55	49.72	96.83
Malaysia – Sarawak2		46.38	80.55	50.27	89.57
– Block K2		46.88	89.00	54.24	95.18

Natural gas liquids – dollars per barrel
United States – Eagle Ford Shale	$	10.26	26.55	11.52	28.77
– Gulf of Mexico and other		10.25	30.45	13.13	32.60
Canada1		–	64.95	22.31	75.96
Malaysia – Sarawak2		54.27	68.48	55.23	75.68

Natural gas – dollars per thousand cubic feet
United States – Eagle Ford Shale	$	2.39	3.76	2.39	4.17
– Gulf of Mexico and other		2.46	3.60	2.47	4.20
Canada1		2.42	3.61	2.44	3.76
Malaysia – Sarawak2		3.75	5.11	4.31	5.67
– Block K		0.24	0.24	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 SEPTEMBER 30, 2015 AND 2014



			Canada
	United		Conven-
(Millions of dollars)	States		tional	Synthetic	Malaysia	Other	Total
Three Months Ended September 30, 2015
Oil and gas sales and other operating revenues	$	335.1	76.4	46.8	207.3	–	665.6
Lease operating expenses		66.9	22.6	37.3	57.0	–	183.8
Severance and ad valorem taxes		12.1	0.9	1.3	–	–	14.3
Depreciation, depletion and amortization		220.8	51.6	12.1	144.2	1.6	430.3
Accretion of asset retirement obligations		5.2	1.6	1.3	3.8	–	11.9
Impairment of assets		144.8	683.6	–	1,472.6	–	2,301.0
Exploration expenses
Dry holes		10.2	–	–	14.1	(2.9)	21.4
Geological and geophysical		2.5	–	–	–	4.8	7.3
Other		1.8	0.1	–	–	11.0	12.9
		14.5	0.1	–	14.1	12.9	41.6
Undeveloped lease amortization		12.0	3.9	–	–	0.6	16.5
Total exploration expenses		26.5	4.0	–	14.1	13.5	58.1
Selling and general expenses		22.9	5.1	0.2	3.3	15.2	46.7
Other expenses		0.9	–	–	17.3	–	18.2
Results of operations before taxes		(165.0)	(693.0)	(5.4)	(1,505.0)	(30.3)	(2,398.7)
Income tax benefits		(57.2)	(190.2)	(1.2)	(552.3)	(1.7)	(802.6)
Results of operations (excluding corporate overhead and interest)	$	(107.8)	(502.8)	(4.2)	(952.7)	(28.6)	(1,596.1)


Three Months Ended September 30, 2014
Oil and gas sales and other operating revenues	$	667.6	150.1	96.8	516.4	–	1,430.9
Lease operating expenses		84.0	42.6	55.6	83.3	–	265.5
Severance and ad valorem taxes		25.3	1.9	1.4	–	–	28.6
Depreciation, depletion and amortization		234.5	61.9	13.4	185.7	1.3	496.8
Accretion of asset retirement obligations		4.5	1.5	2.4	4.2	–	12.6
Exploration expenses
Dry holes		66.0	–	–	–	9.8	75.8
Geological and geophysical		3.9	0.1	–	0.5	1.4	5.9
Other		8.9	0.3	–	–	8.6	17.8
		78.8	0.4	–	0.5	19.8	99.5
Undeveloped lease amortization		11.8	4.9	–	–	1.2	17.9
Total exploration expenses		90.6	5.3	–	0.5	21.0	117.4
Selling and general expenses		24.2	6.3	0.3	3.4	19.5	53.7
Other expenses		0.7	–	–	–	–	0.7
Results of operations before taxes		203.8	30.6	23.7	239.3	(41.8)	455.6
Income tax provisions (benefits)		73.3	7.8	6.1	91.3	(34.3)	144.2
Results of operations (excluding corporate overhead and interest)	$	130.5	22.8	17.6	148.0	(7.5)	311.4

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

OIL AND GAS OPERATING RESULTS – NINE MONTHS ENDED SEPTEMBER 30, 2015 AND 2014




			Canada
	United		Conven-
(Millions of dollars)	States		tional	Synthetic	Malaysia	Other	Total
Nine Months Ended September 30, 2015
Oil and gas sales and other operating revenues	$	955.0	275.7	152.7	897.6	–	2,281.0
Lease operating expenses		247.3	80.9	124.7	190.8	–	643.7
Severance and ad valorem taxes		46.5	3.5	4.1	–	–	54.1
Depreciation, depletion and amortization		622.4	171.0	37.4	475.1	4.7	1,310.6
Accretion of asset retirement obligations		14.9	5.0	4.1	11.4	–	35.4
Impairment of assets		144.8	683.6	–	1,472.6	–	2,301.0
Exploration expenses
Dry holes		74.5	–	–	14.1	31.8	120.4
Geological and geophysical		7.8	–	–	1.2	21.7	30.7
Other		6.7	0.5	–	–	31.1	38.3
		89.0	0.5	–	15.3	84.6	189.4
Undeveloped lease amortization		48.5	12.4	–	–	1.5	62.4
Total exploration expenses		137.5	12.9	–	15.3	86.1	251.8
Selling and general expenses		68.2	18.4	0.7	4.5	44.3	136.1
Other expenses		8.4	44.0	–	17.3	12.1	81.8
Results of operations before taxes		(335.0)	(743.6)	(18.3)	(1,289.4)	(147.2)	(2,533.5)
Income tax provisions (benefits)		(116.9)	(188.7)	4.6	(587.5)	(16.5)	(905.0)
Results of operations (excluding corporate overhead and interest)	$	(218.1)	(554.9)	(22.9)	(701.9)	(130.7)	(1,628.5)


Nine Months Ended September 30, 2014
Oil and gas sales and other operating revenues	$	1,660.4	504.0	303.4	1,592.2	(0.2)	4,059.8
Lease operating expenses		242.1	123.1	180.1	268.3	–	813.6
Severance and ad valorem taxes		75.7	4.4	3.7	–	–	83.8
Depreciation, depletion and amortization		591.2	192.1	39.8	521.1	3.6	1,347.8
Accretion of asset retirement obligations		12.9	4.6	7.0	12.5	–	37.0
Exploration expenses							–
Dry holes		73.5	–	–	–	130.1	203.6
Geological and geophysical		19.7	0.3	–	0.5	54.8	75.3
Other		13.0	0.8	–	–	42.3	56.1
		106.2	1.1	–	0.5	227.2	335.0
Undeveloped lease amortization		37.2	14.8	–	–	3.7	55.7
Total exploration expenses		143.4	15.9	–	0.5	230.9	390.7
Selling and general expenses		71.8	21.4	0.8	11.8	55.6	161.4
Other expenses		1.2	0.1	–	–	–	1.3
Results of operations before taxes		522.1	142.4	72.0	778.0	(290.3)	1,224.2
Income tax provisions (benefits)		186.8	34.8	18.7	295.4	(34.3)	501.4
Results of operations (excluding corporate overhead and interest)	$	335.3	107.6	53.3	482.6	(256.0)	722.8

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

Results of Operations (Contd.)

Corporate

Corporate activities, which include interest income and expense, foreign exchange effects, and corporate overhead not allocated to operating functions, had net income of $9.0 million in the 2015 third quarter compared to a net cost of $40.4 million in the same 2014 quarter. The $49.4 million after-tax improvement in the quarter is primarily due to favorable impacts from foreign currency exchange and lower administrative costs. An after-tax gain of $47.8 million occurred in 2015 on transactions denominated in foreign currencies, while the 2014 quarter had an after-tax gain of $3.1 million.

For the nine months of 2015, corporate activities reflected net costs of $44.0 million compared to net costs of $139.8 million a year ago. Nine-month corporate costs in 2015 were favorable to 2014 by $95.8 million mostly due to favorable impacts from foreign currency exchange, lower administrative costs and increased tax benefits offset in part by higher net interest expense. Total after-tax gains associated with transactions denominated in foreign currencies were $82.3 million in the 2015 period compared to an after-tax loss of $1.0 million in the first nine 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 nine-month periods ended September 30, 2015 and 2014 are reflected in the following table.




		Three Months Ended		Nine Months Ended
		September 30,		September 30,
(Millions of dollars)		2015	2014	2015	2014
U.K. refining and marketing	$	(8.3)	(25.4)	(11.0)	(52.4)
U.K. exploration and production		–	0.1	(0.2)	(0.2)
Loss from discontinued operations	$	(8.3)	(25.3)	(11.2)	(52.6)

Financial Condition

Net cash provided by continuing operating activities was $1,096.5 million for the first nine months of 2015 compared to $2,334.3 million during the same period in 2014. The decline in cash provided by continuing operations 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 continuing operations generated cash of $97.0 million during the first nine months of 2015, compared to $6.9 million in 2014. Proceeds from sales of property and equipment generated cash of $423.8 million in 2015 compared to $3.1 million in 2014 with the 2015 amount primarily relating to proceeds received upon sale of a 10% interest in Malaysian assets. Other significant sources of cash included $852.4 million in the 2015 period and $587.3 million in 2014 from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition. The Company had net borrowings of $885.0 million and $1,050.0 million in the nine-month periods of 2015 and 2014, respectively, to fund capital development activities and repurchase Company stock.

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

Financial Condition (Contd.)

The most significant use of cash in both years was for property additions and dry holes for continuing operations, which including amounts expensed, were $1,975.1 million and $2,806.7 million in the nine-month periods ended September 2015 and 2014, respectively. Total cash dividends to shareholders amounted to $184.8 million in 2015 and $174.2 million in 2014. The Company expended $250.0 million to acquire 5,967,313 shares of Common stock through share repurchases during the first nine months of 2015. In the first nine months of 2014, the Company spent $375.0 million to repurchase Common shares. Also, the purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $865.3 million in the 2015 period and $672.7 million in the 2014 period. The Company used $450.0 million of cash in the 2015 period to repay current maturities of long-term debt.

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



	Nine Months Ended
	September 30,
(Millions of dollars)	2015		2014
Capital Expenditures – Continuing operations
Exploration and production	$	1,631.5		2,828.0
Corporate		37.5		5.6
Total capital expenditures	$	1,669.0		2,833.6

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 in other international operations.

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



	Nine Months Ended
	September 30,
(Millions of dollars)	2015		2014
Property additions and dry hole costs per cash flow statements	$	1,975.1		2,806.7
Geophysical and other exploration expenses		69.0		131.4
Capital expenditure accrual changes and other		(375.1)		(104.5)
Total capital expenditures	$	1,669.0		2,833.6

Working capital (total current assets less total current liabilities) at September 30, 2015 was $514.6 million, $383.3 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 in realized sales prices and lower invested cash balances held by the Company’s Canadian operations.

At September 30, 2015, long-term debt of $3,327.7 million had increased by $810.0 million compared to December 31, 2014. A summary of capital employed at September 30, 2015 and December 31, 2014 follows.



	September 30, 2015				December 31, 2014
(Millions of dollars)	Amount		%		Amount		%
Capital employed
Long-term debt	$	3,327.7	35.6	%	$	2,517.7	22.7	%
Stockholders' equity		6,028.5	64.4			8,573.4	77.3
Total capital employed	$	9,356.2	100.0	%	$	11,091.1	100.0	%

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

Financial Condition (Contd.)

Cash and invested cash are maintained in several operating locations outside the United States. At September 30, 2015, cash, cash equivalents and cash temporarily invested in Canadian government securities held outside the U.S. included U.S. dollar equivalents of approximately $475.4 million in Canada and $787.3 million in Malaysia. In addition $20.7 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 September 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 are permitted 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.

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 a major financial institution to repurchase an aggregate of $250 million of the Company’s Common stock. The Company completed the ASR on July 7, 2015. A total of 5,967,313 shares of Common stock were acquired under this repurchase agreement. The remaining Board authorization to repurchase the remaining $250 million expired in August 2015 and was not renewed.

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 has elected to adopt 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. 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 is addressed in Note M to the Consolidated Financial Statements on page 17 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 October 2015 were similar to the average prices during the third quarter of 2015. While prices have recovered from their August 2015 lows, downward pressures include continued slowing Asian demand growth and record high domestic crude stocks. North American natural gas prices have weakened in October 2015 as inventory levels continued to increase due to high production levels and lower seasonal demand. The Company expects its total oil and natural gas production to average 199,000 barrels of oil equivalent per day in the fourth 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 supplements funding where necessary using borrowings under available credit facilities. The Company’s 2015 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 Company currently projects that its capital spending program in 2016 will be well below 2015 levels. The reduced level of capital expenditures, if it continues, could lead to lower 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, additional impairment charges, the necessity for further cost containment measures, higher debt levels, and a reconsideration of the level of dividends on its Common stock.

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

Outlook (Contd.)

The Company has two deepwater drilling rigs under contract and in use in the Gulf of Mexico. These contracts expire in February and November 2016. The Company is evaluating its options as to these rig contracts in the face of low oil and gas prices, an expected reduction in the Company’s overall 2016 capital spending program and uncertainty about whether working interest partners will agree to participate in further Gulf drilling opportunities in 2016. Options being considered over the remaining months of the contracts include cancellation of the contracts, assignment of the rig time to a third party at a day rate below the Company’s committed day rate, and normal drilling operations. The Company currently estimates that the remaining day rate commitments following completion of present drilling operations could be up to $277 million. Depending on the final determination of rig use, the Company could incur pretax costs of up to $277 million under those contracts during a period that ranges from as early as the fourth quarter of 2015 through the fourth quarter of 2016.

As of October 28, 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
U.S. Oil	West Texas Intermediate	Oct. – Dec. 2015		15,000 bbls/d	$63.30 per bbl.
		Jan. – Dec. 2016		20,000 bbls/d	$52.01 per bbl.

Canadian Natural Gas	TCPL–NOVA System	Oct. – Dec. 2015		65 mmcf/d	C$4.13 per mcf
		Jan. – Dec. 2016		59 mmcf/d	C$3.19 per mcf

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 and page 31 of this Form 10-Q report. 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 transactions in place at September 30, 2015 covering certain future U.S. crude oil sales volumes in 2015. A 10% increase in the respective benchmark price of these commodities would have decreased the recorded net asset associated with these derivative contracts by approximately $6.3 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 September 30, 2015 to hedge the value of the U.S. dollar against the Canadian dollar for certain U.S. dollar receivables to be collected in October 2015. A 10% strengthening of the U.S. dollar against the Canadian dollar would have decreased the recorded net asset associated with these contracts by approximately $0.6 million, while a 10% weakening of the U.S. dollar would have increased the recorded net asset by approximately $0.6 million. Changes in the fair value of these derivative contracts generally offset the financial statement impact of an equivalent volume of foreign currency exposures associated with other assets and/or liabilities.

ITEM 4. CONTROLS AND PROCEDURES

Under the direction of its principal executive officer and principal financial officer, controls and procedures have been established by the Company to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on the Company’s evaluation as of the end of the period covered by the filing of this Quarterly Report on Form 10-Q, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There have been no changes in the Company’s internal control over financial reporting during the quarter ended September 30, 2015 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 2014 Form 10-K filed on February 27, 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
July 1, 2015 to July 31, 2015	–	$	–	–	$	250,000,000
August 1, 2015 to August 31, 2015	730,604		–	730,604		–
September 1, 2015 to September 30, 2015	–		–	–		–
Total July 1, 2015 to September 30, 2015	730,604			730,604		–

On May 20, 2015 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 transaction, which totaled 5,236,709 shares. The ASR was completed in July 2015 and the Company received an additional 730,604 shares upon completion of the ASR. This brought the total number of shares acquired under this 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 33 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)

November 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.