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, 2017
	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 incorporation or organization)	(I.R.S. Employer Identification Number)
300 Peach Street, P.O. Box 7000,
El Dorado, Arkansas	71731-7000
(Address of principal executive offices)	(Zip Code)

(870) 862-6411

(Registrant’s telephone number, including area code)

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

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

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

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

Emerging growth company [  ]

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company [  ]

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

[  ]

Number of shares of Common Stock, $1.00 par value, outstanding at October 31, 2017 was 172,572,873.

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	23
Item 3.  Quantitative and Qualitative Disclosures About Market Risk	36
Item 4.  Controls and Procedures	36
Part II – Other Information	36
Item 1.  Legal Proceedings	36
Item 1A.  Risk Factors	36
Item 6.  Exhibits	36
Signature	37

1

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,
	2017		2016
ASSETS
Current assets
Cash and cash equivalents	$	997,207		872,797
Canadian government securities with maturities greater than 90 days at    the date of acquisition		–		111,542
Accounts receivable, less allowance for doubtful accounts of $1,605 in     2017 and 2016		267,209		357,099
Inventories, at lower of cost or market		120,066		127,071
Prepaid expenses		39,427		63,604
Assets held for sale		23,248		27,070
Total current assets		1,447,157		1,559,183
Property, plant and equipment, at cost less accumulated depreciation,    depletion and amortization of $12,027,902 in 2017 and $12,607,815 in 2016		8,283,738		8,316,188
Deferred income taxes		406,703		365,935
Deferred charges and other assets		55,161		54,554
Total assets	$	10,192,759		10,295,860
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	9,781		569,817
Accounts payable		584,025		784,975
Income taxes payable		57,687		13,920
Other taxes payable		30,160		28,167
Other accrued liabilities		146,607		102,777
Liabilities associated with assets held for sale		3,270		2,776
Total current liabilities		831,530		1,502,432
Long-term debt, including capital lease obligation		2,908,285		2,422,750
Deferred income taxes		108,756		69,081
Asset retirement obligations		747,602		681,528
Deferred credits and other liabilities		616,452		617,490
Liabilities associated with assets held for sale		–		85,900
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 2017 and 2016		195,056		195,056
Capital in excess of par value		910,936		916,799
Retained earnings		5,575,175		5,729,596
Accumulated other comprehensive loss		(425,504)		(628,212)
Treasury stock		(1,275,529)		(1,296,560)
Total stockholders’ equity		4,980,134		4,916,679
Total liabilities and stockholders’ equity	$	10,192,759		10,295,860

See Notes to Consolidated Financial Statements, page 7.

The Exhibit Index is on page 38.

2

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,
	2017		2016*	2017	2016*
Revenues
Sales and other operating revenues	$	498,202	486,276	1,552,473	1,326,587
Gain (loss) on sale of assets		117	(730)	130,765	3,101
Total revenues		498,319	485,546	1,683,238	1,329,688
Costs and expenses
Lease operating expenses		112,751	119,663	346,072	435,296
Severance and ad valorem taxes		10,816	9,592	32,771	35,668
Exploration expenses		28,492	19,866	77,356	83,910
Selling and general expenses		56,672	55,523	168,259	196,143
Depreciation, depletion and amortization		243,636	255,900	714,782	797,288
Accretion of asset retirement obligations		10,654	11,043	31,638	35,514
Impairment of assets		–	–	–	95,088
Other expense (benefit)		2,454	6,486	10,988	(1,446)
Total costs and expenses		465,475	478,073	1,381,866	1,677,461
Operating income (loss) from continuing operations		32,844	7,473	301,372	(347,773)
Other income (loss)
Interest and other income (loss)		(47,721)	14,987	(93,524)	38,602
Interest expense, net		(48,681)	(39,219)	(138,423)	(103,889)
Total other loss		(96,402)	(24,232)	(231,947)	(65,287)
Income (loss) from continuing operations before income taxes		(63,558)	(16,759)	69,425	(413,060)
Income tax expense (benefit)		2,760	(2,176)	95,602	(201,897)
Loss from continuing operations		(66,318)	(14,583)	(26,177)	(211,163)
Income (loss) from discontinued operations,     net of income taxes		425	(1,593)	1,177	(885)
NET LOSS	$	(65,893)	(16,176)	(25,000)	(212,048)
INCOME (LOSS) PER COMMON SHARE – BASIC
Continuing operations	$	(0.38)	(0.08)	(0.15)	(1.23)
Discontinued operations		-	(0.01)	0.01	(0.01)
Net loss	$	(0.38)	(0.09)	(0.14)	(1.24)
INCOME (LOSS) PER COMMON SHARE – DILUTED
Continuing operations	$	(0.38)	(0.08)	(0.15)	(1.23)
Discontinued operations		-	(0.01)	0.01	(0.01)
Net loss	$	(0.38)	(0.09)	(0.14)	(1.24)
Cash dividends per Common share		0.25	0.25	0.75	0.95
Average Common shares outstanding (thousands)
Basic		172,573	172,199	172,509	172,165
Diluted		172,573	172,199	172,509	172,165

See Notes to Consolidated Financial Statements, page 7.

*Reclassified to conform to current presentation (see Note A).

3

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,
	2017		2016	2017	2016
Net loss	$	(65,893)	(16,176)	(25,000)	(212,048)
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation		101,210	(37,369)	194,094	124,522
Retirement and postretirement benefit plans		2,396	2,515	7,169	7,544
Deferred loss on interest rate hedges reclassified to interest   expense		482	482	1,445	1,445
Other comprehensive income (loss)		104,088	(34,372)	202,708	133,511
COMPREHENSIVE INCOME (LOSS)	$	38,195	(50,548)	177,708	(78,537)

See Notes to Consolidated Financial Statements, page 7.

4

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)

(Thousands of dollars)

	Nine Months Ended
	September 30,
	2017		2016
Operating Activities
Net loss	$	(25,000)	(212,048)
Adjustments to reconcile net loss to net cash provided by continuing operations    activities:
(Income) loss from discontinued operations		(1,177)	885
Depreciation, depletion and amortization		714,782	797,288
Impairment of assets		–	95,088
Amortization of deferred major repair costs		–	3,794
Dry hole costs (credits)		(1,139)	15,226
Amortization of undeveloped leases		40,859	35,828
Accretion of asset retirement obligations		31,638	35,514
Deferred and noncurrent income tax benefits		(3,567)	(345,157)
Pretax gains from disposition of assets		(130,765)	(3,101)
Net (increase) decrease in noncash operating working capital		1,070	(152,618)	1
Other operating activities, net		192,867	9,651
Net cash provided by continuing operations activities		819,568	280,350
Investing Activities
Property additions and dry hole costs		(706,417)	(781,668)	2
Proceeds from sales of property, plant and equipment		69,146	1,154,623
Purchases of investment securities3		(212,661)	(651,218)
Proceeds from maturity of investment securities3		320,828	712,863
Other investing activities, net		–	(7,229)
Net cash (required) provided by investing activities		(529,104)	427,371
Financing Activities
Borrowings of debt, net of issuance costs		541,772	541,444
Repayments of debt		(550,000)	(600,000)
Capital lease obligation payments		(14,687)	(7,808)
Withholding tax on stock-based incentive awards		(7,151)	(1,138)
Issue cost of debt facility		–	(13,971)
Cash dividends paid		(129,421)	(163,586)
Other financing activities, net		–	(20)
Net cash required by financing activities		(159,487)	(245,079)
Cash Flows from Discontinued Operations
Operating activities		12,134	2,830
Changes in cash included in current assets held for sale		(12,904)	(2,830)
Net change in cash and cash equivalents of discontinued operations		(770)	–
Effect of exchange rate changes on cash and cash equivalents		(5,797)	7,268
Net increase in cash and cash equivalents		124,410	469,910
Cash and cash equivalents at beginning of period		872,797	283,183
Cash and cash equivalents at end of period	$	997,207	753,093

12016 balance includes payments for deepwater rig contract exit of $266.6 million.

2Includes costs of $206.7 million associated with acquisition of Kaybob Duvernay and Placid Montney.

3Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

See Notes to Consolidated Financial Statements, page 7.

5

Murphy Oil Corporation and Consolidated Subsidiaries

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (unaudited)

(Thousands of dollars)

	Nine Months Ended
	September 30,
	2017		2016
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, 2017 and 2016.
Balance at beginning of period		195,056		195,056
Exercise of stock options		–		–
Balance at end of period		195,056		195,056
Capital in Excess of Par Value
Balance at beginning of period		916,799		910,074
Restricted stock transactions and other		(26,553)		(10,078)
Stock-based compensation		20,767		21,918
Other		(77)		(239)
Balance at end of period		910,936		921,675
Retained Earnings
Balance at beginning of period		5,729,596		6,212,201
Net loss for the period		(25,000)		(212,048)
Cash dividends		(129,421)		(163,586)
Balance at end of period		5,575,175		5,836,567
Accumulated Other Comprehensive Loss
Balance at beginning of period		(628,212)		(704,542)
Foreign currency translation gain, net of income taxes		194,094		124,522
Retirement and postretirement benefit plans, net of income taxes		7,169		7,544
Deferred loss on interest rate hedges reclassified to interest expense,    net of income taxes		1,445		1,445
Balance at end of period		(425,504)		(571,031)
Treasury Stock
Balance at beginning of period		(1,296,560)		(1,306,061)
Sale of stock under employee stock purchase plan		145		389
Awarded restricted stock, net of forfeitures		20,886		8,993
Balance at end of period – 22,482,851 shares of Common Stock in    2017 and 22,855,649 shares of Common Stock in 2016, at cost		(1,275,529)		(1,296,679)
Total Stockholders’ Equity	$	4,980,134		5,085,588

See Notes to Consolidated Financial Statements, page 7.

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.

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, 2017 and December 31, 2016, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2017 and 2016, 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 2016 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report.  Financial results for the three-month and nine-month periods ended September 30, 2017 are not necessarily indicative of future results.

Beginning in the period ended September 30, 2017, certain reclassifications in presentation have been made to the Consolidated Statements of Operations.  The Company now presents a separate “Operating income (loss) from continuing operations” subtotal on the Consolidated Statements of Operations.  Additionally, “Interest and other income (loss),” which includes foreign exchange gains and losses, has been reclassified from a component of total revenues and is now presented below Operating income (loss) from continuing operations. “Interest expense” and “Capitalized interest” have also been combined into the “Interest expense, net” line item and is now presented below Operating income (loss) from continuing operations.  Previously reported periods have been changed to conform to the current period presentation.  These reclassifications did not impact previously reported Income (loss) from continuing operations before income taxes, Loss from continuing operations, or Net Loss.

Note B – Property, Plant and Equipment

Exploratory Wells

Under Financial Accounting Standards Board (FASB) guidance 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, 2017, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $178.4 million.  The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2017 and 2016.

(Thousands of dollars)	2017		2016
Beginning balance at January 1	$	148,500	130,514
Additions pending the determination of proved reserves		51,614	847
Reclassifications to proved properties based on the determination of proved reserves		(13,370)	–
Capitalized exploratory well costs charged to expense		(8,360)	–
Other adjustments		–	(3,205)
Balance at September 30	$	178,384	128,156

The capitalized well costs charged to expense during the first nine months of 2017 included the Marakas-01 well in Block SK314A, offshore Malaysia in which development of the well could not be justified due to noncommercial hydrocarbon quantities found and change in development plan due to commodity prices.

6

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,
	2017				2016
(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	$	41,609	3	2	$	10,563	2	2
One to two years		8,430	2	2		53,101	3	3
Two to three years		43,197	1	1		31,627	2	–
Three years or more		85,148	7	1		32,865	4	–
	$	178,384	13	6	$	128,156	11	5

Of the $136.8 million of exploratory well costs capitalized more than one year at September 30, 2017, $70.4 million is in Brunei, $43.2 million is in Vietnam and $23.2 million is in Malaysia.  In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. 

Divestments

In January 2017, a Canadian subsidiary of the Company completed its disposition of the Seal field in Western Canada.  Total cash consideration to Murphy upon closing of the transaction was approximately $49.0 million.  Additionally, the buyer assumed the asset retirement obligation of approximately $85.9 million.  A $132.4 million pretax gain was reported in the first quarter of 2017 related to the sale.  Also, in 2017, a U.S. subsidiary of the Company completed its disposition of certain non-core properties in the Eagle Ford Shale area.  Total cash consideration to Murphy upon closing of the transaction was approximately $19.4 million.  There wereno gains or losses recorded related to these sales.  

During the second quarter 2016, a Canadian subsidiary of the Company completed the sale of its five percent, non-operated working interest in Syncrude Canada Ltd. (“Syncrude”) asset to Suncor Energy Inc. (“Suncor”).  The Company received net cash proceeds of $739.1 million and recorded an after-tax gain of $71.7 million in the nine-month period ended September 30, 2016 associated with the Syncrude divestiture.

During the second quarter 2016, a Canadian subsidiary of the Company completed a divestiture of natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia.  A gain on sale of approximately $187.0 million was deferred and is being recognized over the next 19 years in the Canadian operating segment.  The Company amortized approximately $5.3million and $3.4 million of the deferred gain during the nine-month periods ended September 30, 2017 and 2016, respectively.  The remaining deferred gain of $185.0 million was included as a component of deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of September 30, 2017.

Acquisitions

During the second quarter 2016, a Canadian subsidiary acquired a 70 percent operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30 percent non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved.  Under the terms of the joint venture, the total consideration amounts to approximately $375.0 million of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, and an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property.  As of September 30, 2017, $32.0 million of the carried interest had been paid.  The carry is to be paid over a period of up to five years from 2016.

7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Impairments

Declines in future oil and gas prices in early 2016 led to impairments in certain of the Company’s producing properties and the nine-month period in 2016 included pretax non-cash impairment charges of $95.1 million to reduce the carrying values to their estimated fair values for the Terra Nova field offshore Canada and the Western Canada onshore heavy oil producing properties at Seal.  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. See also Note J.

Other

The Company has an interest in the Kakap field in Block K Malaysia.  The Kakap field is operated by another company and was jointly developed with the Gumusut field owned by others.  As required by the agreements governing the field, a redetermination (unitization) review was required in 2016.  In the fourth quarter 2016, the Company recorded $39.1 million in redetermination expense related to an expected reduction in the Company’s working interest covering the period from inception through year-end 2016 at Kakap.  In February 2017, PETRONAS officially approved the redetermination that reduced the Company’s working interest from 8.6% to approximately 6.7% effective April 1, 2017.  The Company partially settled $21.8 million of the redetermination expense in cash in the second quarter of 2017.  The Company currently expects to settle the remainder of the redetermination costs in future periods.  It is possible that the final adjustment amount could be different than the current estimate.  Due to the change in working interest, the future payments under a capital lease of a floating, production and storage facility in the Kakap field are lower and the Company reduced the total debt recorded on the Consolidated Balance Sheet in the second quarter 2017 by approximately $56.7 million, with a similar reduction to Property, plant and equipment.

Note C – Discontinued Operations and Assets Held for Sale

The Company has accounted for its former U.K. and U.S. refining and marketing operations as discontinued operations for all periods presented.  The results of operations associated with discontinued operations for the three-month and nine-month periods ended September 30, 2017 and 2016 were as follows:

	Three Months			Nine Months
	Ended September 30,			Ended September 30,
(Thousands of dollars)		2017	2016	2017	2016
Revenues (costs)	$	598	5	853	1,454
Income (loss) before income taxes		425	(1,593)	1,177	(885)
Income tax benefit		–	–	–	–
Income (loss) from discontinued operations	$	425	(1,593)	1,177	(885)

Certain reclassifications have been made to 2016 Revenues to align with current period presentation (see Note A).

The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations and Seal operations in Canada reflected as held for sale on the company’s Consolidated Balance Sheets at September 30, 2017 and December 31, 2016.

		September 30,	December 31,
(Thousands of dollars)		2017	2016
Current assets
Cash	$	17,030	4,126
Accounts receivable		6,218	22,944
Total current assets held for sale	$	23,248	27,070
Current liabilities
Accounts payable	$	605	270
Refinery decommissioning cost		2,665	2,506
Total current liabilities associated with assets held for sale	$	3,270	2,776
Non-current liabilities
Asset retirement obligation - Seal asset	$	–	85,900

Note C – Discontinued Operations and Assets Held for Sale (Contd.)

The asset retirement obligation at December 31, 2016 relates to well and facility abandonment obligations at the Seal field in Canada which were assumed by the purchasing company upon the sale in January 2017. 

Note D – Financing Arrangements and Debt

At September 30, 2017, the Company has a $1.1 billion senior unsecured guaranteed credit facility (2016 facility) with a major banking consortium, which expires in August 2019.  At September 30, 2017, the Company had no outstanding borrowings under the 2016 facility, however, there were $84.8 million of outstanding letters of credit, which reduce the borrowing capacity of the 2016 facility.  Advances under the 2016 facility will accrue interest based, at the Company’s option, on either the London Interbank Offered rate plus an applicable margin (Eurodollar rate) or the alternate base rate (as defined in the 2016 facility agreement) plus an applicable margin.  Had there been any amounts borrowed under the 2016 facility at September 30, 2017, the applicable base interest rate would have been 4.50%.  At September 30, 2017, the Company was in compliance with all covenants related to the 2016 facility.

The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2018.

In August 2017, the Company sold $550 million of new notes that bear interest at the rate of 5.75% and mature on August 15, 2025.  The Company incurred transaction costs of $8.2 million on the issue of these new notes.  The new notes pay interest semi-annually on February 15 and August 15 of each year.  The initial interest payment will be paid on February 15, 2018.  The proceeds of the $550 million notes were used to redeem the Company’s 2.50%notes in September 2017. The 2.50% notes had an original maturity of December 2017.

In August 2016, the Company reduced its then existing $2.0 billion unsecured revolving credit facility (2011 facility) to $630 million (facility has since expired) and entered into a separate $1.2 billion senior unsecured guaranteed credit facility (2016 facility, subsequently reduced to $1.1 billion),  with a major banking consortium that expires in August 2019.  The Company incurred transaction costs of approximately $14.0 million to place the 2016 facility which were included in financing activities in the Consolidated Statement of Cash Flows.  Also in August 2016, the Company sold $550 million of notes that bear interest at the rate of 6.875% and mature on August 15, 2024.  The proceeds of the $550 million notes were used for general corporate purposes.

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 March 2029.  Current maturities of long-term debt and long-term debt on the Consolidated Balance Sheet included $9.8 million and $136.5 million, respectively, associated with this lease at September 30, 2017.

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note E – Other Financial Information

Additional disclosures regarding cash flow activities are provided below.

	Nine Months Ended September 30,
(Thousands of dollars)	2017		2016
Net (increase) decrease in operating working capital other than    cash and cash equivalents:
Decrease in accounts receivable	$	90,614	75,841
Decrease (increase) in inventories		5,869	(15,768)
Decrease in prepaid expenses		25,285	122,399
Decrease in other		–	720
Decrease in accounts payable and accrued liabilities		(115,977)	(376,310)	*
(Decrease) increase in current income tax liabilities		(4,721)	40,500
Net (increase) decrease in noncash operating working capital	$	1,070	(152,618)
Supplementary disclosures:
Cash income taxes paid, net of refunds	$	25,118	(3,911)
Interest paid, net of amounts capitalized of $3,338 in 2017   and $3,318 in 2016		95,899	52,287
Non-cash investing activities:
Asset retirement costs capitalized	$	38,992	13,959
Decrease in capital expenditure accrual		42,403	179,203

*2016 balance included payments for deepwater rig contract exit of $266.6 million.

9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note F – Employee and Retiree Benefit Plans

The Company has defined benefit pension plans that are principally noncontributory and cover most North American full-time employees.  All pension plans are funded except for the U.S. nonqualified supplemental 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.  The health care benefits are contributory; the life insurance benefits are noncontributory.

The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 2017 and 2016.

	Three Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2017	2016	2017		2016
Service cost	$	2,037	2,610		427		674
Interest cost		7,261	5,913		966		1,109
Expected return on plan assets		(8,070)	(6,626)		–		–
Amortization of prior service cost (credit)		259	323		(18)		(21)
Amortization of transitional asset		–	–		–		2
Recognized actuarial loss		3,610	3,617		–		38
Net periodic benefit expense	$	5,097	5,837		1,375		1,802
	Nine Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2017	2016	2017		2016
Service cost	$	6,099	8,533		1,276		2,022
Interest cost		20,267	20,386		2,899		3,324
Expected return on plan assets		(21,730)	(21,709)		–		–
Amortization of prior service cost (credit)		767	963		(55)		(62)
Amortization of transitional asset		–	–		–		4
Recognized actuarial loss		10,673	10,864		–		113
Curtailments		–	822		–		(19)
Net periodic benefit expense	$	16,076	19,859		4,120		5,382

Curtailment expense for the nine months ended September 30, 2016, shown in the table above, relates to restructuring activities in the U.S. undertaken by the Company in the first quarter of 2016.

During the nine-month period ended September 30, 2017, the Company made contributions of $24.0 million to its defined benefit pension and postretirement benefit plans.  Remaining required funding in 2017 for the Company’s defined benefit pension and postretirement plans is anticipated to be $6.8million. 

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note G – Incentive Plans

The costs resulting from all share-based and cash-based incentive plans payment transactions are recognized as an expense in the Consolidated Statements of Operations 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 certain other 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 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; allowed shares not granted in an earlier year may be granted in future years.  The Company also has a 2013 Stock Plan for Non-Employee Directors (Director Plan) that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.

The Company had an Employee Stock Purchase Plan (ESPP) that permitted the issuance of Company shares during 2016 and the first six months of 2017.  The ESPP terminated on June 30, 2017 and was not renewed by the Company.

In February 2017, the Committee granted stock options for 599,000 shares at an exercise price of $28.505 per share.  The Black-Scholes valuation for these awards was $7.96 per option.  The Committee also granted 556,000 performance-based

RSU and 282,000 time-based RSU in February 2017.  The fair value of the performance-based RSU, using a Monte Carlo valuation model, ranged from $24.10 to $28.28 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 $28.505 per share.  Additionally, the Committee granted 329,400 SAR and 154,150 units of cash-settled RSU (RSUC) to certain employees.  The SAR and RSUC 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 RSUC was equivalent to equity-settled restricted stock units granted.  Also in February, the Committee granted 83,220 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 was $28.84 per unit on date of grant.

For all periods presented, the Company had no stock options exercised.

Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:

	Nine Months Ended
	September 30,
(Thousands of dollars)		2017	2016
Compensation charged against income (loss) before tax benefit	$	28,264	35,948
Related income tax benefit recognized in income		8,695	11,796

11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note H – Earnings per Share

Net 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, 2017 and 2016.  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)	2017	2016	2017	2016
Basic method	172,572,873	172,199,350	172,509,418	172,164,683
Dilutive stock options and restricted stock units*	–	–	–	–
Diluted method	172,572,873	172,199,350	172,509,418	172,164,683

     *Due to net losses recognized by the Company for all periods presented, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive.

	Three Months Ended				Nine Months Ended
		September 30,			September 30,
		2017	2016		2017		2016
Antidilutive stock options excluded from diluted shares		5,257,718		5,884,201		5,578,495		5,822,036
Weighted average price of these options	$	46.46	$	49.00	$	46.86	$	49.82

Note I – Income Taxes

The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) before income tax expense.  For the three-month and nine-month periods ended September 30, 2017 and 2016, the Company’s effective income tax rates were as follows:

	2017	2016
Three months ended September 30	(4.3%)	13.0%
Nine months ended September 30	137.7%	48.9%

The effective tax rates for most periods where earnings are generated, 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.  Conversely, the effective tax rates for most periods where losses are incurred generally are lower than U.S. statutory tax rate of 35% due to similar reasons. 

The effective tax rate for the three-month period ended September 30, 2017 was below the U.S. statutory tax rate of 35% primarily due to the tax effect of expenses in foreign jurisdictions not fully deductible from losses at the U.S. statutory tax rate, an estimated U.S. tax charge for undistributed foreign earnings and Canadian foreign exchange losses not fully deductible at 35%.  These impacts were partially offset by the U.S. tax benefit recognized from the reversal of an uncertain tax position for federal tax years 2011-2013.

The effective tax rate for the nine-month period ended September 30, 2017 was above the U.S. statutory tax rate of 35% primarily due to an estimated U.S. tax charge for undistributed foreign earnings and Canadian foreign exchange losses.  These impacts were partially offset by the U.S. tax benefit recognized from the reversal of an uncertain tax position for federal tax years 2011-2013 and other items.  During the first nine-months of 2017, the Company determined that prospective earnings from its Malaysian and Canadian subsidiaries will not be considered reinvested into local operations.  Due to this change in assertion, the Company recorded a deferred tax charge of $65.2 million in the nine-month period 2017 associated with the estimated tax consequence of the future repatriation of these subsidiaries earnings during the first nine months 2017.  This decision provides greater financial flexibility as it considers future domestic investment opportunities.  The Company expects to incur further tax charges in the fourth quarter 2017 for additional 2017 foreign earnings as they arise. 

Note I – Income Taxes (Contd.)

The effective tax rate for the three-month period ended September 30, 2016 was less than the U.S. statutory tax rate primarily due to expenses in foreign jurisdictions for which no tax benefits were recognized.  The effective tax rate for the nine-month period ended September 30, 2016 was above the U.S. statutory tax rate primarily due to deferred tax benefits recognized related to the Canadian asset dispositions and income tax benefits on investments in foreign areas. 

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, 2017, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows:United States – 2014; Canada – 2012; Malaysia – 2010; and United Kingdom – 2015.

Note J – 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 gain or loss associated with recording the fair value of these contracts was deferred in Accumulated Other Comprehensive Loss until the anticipated transactions occur.  This deferred cost is being reclassified to Interest expense, net in the Consolidated Statements of Operations over the period until the associated notes mature in 2022.

Commodity Purchase Price Risks

The Company is subject to commodity price risk related to crude oil it produces and sells.  During the first nine months 2017 and 2016, the Company had West Texas Intermediate (WTI) crude oil swap financial contracts to economically hedge a portion of its United States production.  Under these contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract prices.  At September 30, 2017, the Company had 22,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during the remainder of 2017 at an average price of $50.41 and 6,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2018 at an average price of $51.83.  At September 30, 2017, the fair value of WTI contracts of $3.2 million was included in Accounts Payable.  The impact of marking to market these commodity derivative contracts increased the loss before income taxes by $3.2 million for the nine-month period ended September 30, 2017.

At September 30, 2016, the Company had 25,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2016.  At September 30, 2016, the fair value of WTI contracts of $0.2 million was included in Accounts Receivable.  The impact of marking to market these 2016 commodity derivative contracts decreased the loss before income taxes by $3.9 million for the nine-month period ended September 30, 2016.

12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange short-term derivatives outstanding at September 30, 2017.

At September 30, 2016, short-term derivative instruments were outstanding in Canada for approximately $25.2 million, to manage the currency risks of certain U.S. dollar accounts receivable associated with sale of Canadian crude oil.  The fair values of open foreign currency derivative contracts were assets of $0.1 million at September 30, 2016.

At September 30, 2017 and December 31, 2016, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

	September 30, 2017			December 31, 2016
(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 payable	$	(3,226)	Accounts payable	$	(48,864)
Foreign exchange	Accounts receivable		–	Accounts payable		(73)

For the three-month and nine-month periods ended September 30, 2017 and 2016, 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		2017	2016	2017	2016
Commodity	Sales and other operating revenues	$	(13,573)	11,871	50,365	(22,678)
Foreign exchange	Interest and other income (loss)		–	143	73	26,929
		$	(13,573)	12,014	50,438	4,251

Interest Rate Risks

Under hedge accounting rules, the Company deferred the net cost associated with derivative contracts purchased to manage interest rate risk associated with 10-year notes sold in May 2012 to match the payment of interest on these notes through 2022.  During each of the nine-month periods ended September 30, 2017 and 2016, $2.2 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations.  The remaining loss deferred on these matured contracts at September 30, 2017 was $8.9 million, which is recorded, net of income taxes of $4.8 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet.  The Company expects to charge approximately $0.7 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remaining three months of 2017.

13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

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, 2017 and December 31, 2016 are presented in the following table.

	September 30, 2017					December 31, 2016
(Thousands of dollars)	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Liabilities:
Nonqualified employee         savings plans	$	15,161	–	–	15,161	13,904	–	–	13,904
Commodity derivative contracts		–	3,226	–	3,226	–	48,864	–	48,864
Foreign currency exchange         derivative contracts		–	–	–	–	–	73	–	73
	$	15,161	3,226	–	18,387	13,904	48,937	–	62,841

The fair value of WTI crude oil derivative contracts in 2017 and 2016 was based on active market quotes for WTI crude oil.  The fair value of foreign exchange derivative contracts in each year 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, while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and other income.  The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds.  The fair value of this liability was based on quoted prices for these equity securities and mutual funds.  The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and general expenses in the Consolidated Statements of 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, 2017 and December 31, 2016.

14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

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

Fair Values – Nonrecurring

As a result of the fall in forward commodity prices during the first nine-month period ended September 30, 2016, the Company recognized approximately $95.1 million in pretax non-cash impairment charges related to producing properties.  The fair value information associated with these impaired properties is presented in the following table.

	Nine-months ended September 30, 2016
						Total
					Net Book	Pretax
					Value	(Noncash)
	Fair Value				Prior to	Impairment
		Level 1	Level 2	Level 3	Impairment	Expense
(Thousands of dollars)
Assets:
Impaired proved properties
Canada	$	–	–	71,967	167,055	95,088

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.

Note K – Accumulated Other Comprehensive Loss

The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at December 31, 2016 and September 30, 2017 and the changes during the nine-month period ended September 30, 2017 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)	Adjustments		Hedges		Total
Balance at December 31, 2016	$	(446,555)	(171,305)		(10,352)		(628,212)
2017 components of other comprehensive income (loss):
Before reclassifications to income		194,094	3		–		194,097
Reclassifications to income		–	7,166	1	1,445	2	8,611
Net other comprehensive income		194,094	7,169		1,445		202,708
Balance at September 30, 2017	$	(252,461)	(164,136)		(8,907)		(425,504)

1Reclassifications before taxes of $11,039 for the nine-month period ended September 30, 2017 are included in the computation of net periodic benefit expense.  See Note G for additional information.  Related income taxes of $3,873 for the nine-month period ended September 30, 2017 are included in Income tax expense.

2Reclassifications before taxes of $2,222 for the nine-month period ended September 30, 2017 are included in Interest expense, net.  Related income taxes of $777 for the nine-month period ended September 30, 2017 are included in Income tax expense.

Note L – 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, tax rate changes and retroactive tax claims; royalty and revenue sharing changes; 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.  Governmental actions are often motivated by political considerations, 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.

15

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note L – Environmental and Other Contingencies (Contd.)

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

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by priorowners 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 has not retained any environmental exposure associated with Murphy’s former U.S. marketing operations.  The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.

During 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 were notified.  Based on the assessments done, the Company recorded $43.9 million in Other expense during 2015 associated with the estimated costs of remediating the site.  As of September 30, 2017, the Company has a remaining accrued liability of $5.8 million associated with this event.  During the first nine months of 2017, the Company’s Canadian subsidiary paid approximately $130 thousand as the complete and final resolution of administrative penalties assessed by the Alberta Energy Regulator regarding this matter.  Further refinements in the estimated total cost to remediate the site are anticipated in future periods including possible 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 liability recorded.  The Company retained the responsibility for this remediation upon sale of the Seal field in the first quarter of 2017.

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 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.

Note M – Commitments

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2017 to 2020 natural gas sales volumes in Western Canada.  During the period from October to December 2017 the natural gas sales contracts call for deliveries of 124 million cubic feet per day at Cdn $2.97 per MCF.  During the period from January 2018 through December 2020 the natural gas sales contracts call for deliveries of 59 million cubic feet per day at Cdn $2.81 per MCF.  During the period from November 2017 through March 2018 the natural gas sales contracts call for deliveries of 20 million cubic feet per day at US $3.51 per MCF.

These natural gas contracts have been accounted for as normal sales for accounting purposes.

16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note N – Business Segments

Information about business segments and geographic operations is reported in the following tables.  For geographic purposes, revenues are attributed to the country in which the sale occurs.  Corporate, including interest income, miscellaneous gains and losses (including foreign exchange gains and losses), interest expense and unallocated overhead, is shown in the tables to reconcile the business segments to consolidated totals. Certain reclassifications have been made to 2016 Corporate External Revenue to align with current period presentation (see Note A).

				Three Months Ended		Three Months Ended
	Total Assets			September 30, 2017		September 30, 2016
	at September 30,			External	Income	External	Income
(Millions of dollars)	2017			Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States	$	5,439.1		195.9	(19.9)	201.8	(27.1)
Canada		1,711.1		81.9	(3.2)	80.9	(4.8)
Malaysia		1,755.3		220.5	67.7	202.7	65.0
Other		139.9		–	(11.0)	0.2	(8.1)
Total exploration and production		9,045.4		498.3	33.6	485.6	25.0
Corporate		1,124.2		–	(99.9)	(0.1)	(39.6)
Assets/revenue/loss from continuing operations		10,169.6		498.3	(66.3)	485.5	(14.6)
Discontinued operations, net of tax		23.2		–	0.4	–	(1.6)
Total	$	10,192.8		498.3	(65.9)	485.5	(16.2)
				Nine Months Ended		Nine Months Ended
				September 30, 2017		September 30, 2016
				External	Income	External	Income
(Millions of dollars)				Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States			$	696.7	11.0	520.2	(158.5)
Canada				388.1	102.6	264.4	(36.9)
Malaysia				594.4	173.9	541.4	135.1
Other				–	(10.9)	0.2	(39.2)
Total exploration and production				1,679.2	276.6	1,326.2	(99.5)
Corporate				4.0	(302.8)	3.5	(111.7)
Revenue/loss from continuing operations				1,683.2	(26.2)	1,329.7	(211.2)
Discontinued operations, net of tax				–	1.2	–	(0.8)
Total			$	1,683.2	(25.0)	1,329.7	(212.0)

*Additional details about results of oil and gas operations are presented in the tables on pages 29 and 30.

Note O – New Accounting Principles Adopted

Business Combinations

In January 2017, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) to clarify the definition of a business to assist entities in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses.  The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs.  The update is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The prospective approachis required for adoption and early adoption is permitted for transactions not previously reported in issued financial statements.  The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures.

17

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note O – New Accounting Principles Adopted(Contd.)

Compensation – Stock Compensation

In March 2016, the FASB issued an ASU intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification within the statement of cash flows.  The amendments in this ASU were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods.  The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures as there were no exercises of Company options during the period.

Note P – Recent Accounting Pronouncements

Compensation – Stock Compensation

In May 2017, FASB issued an ASU which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting.  The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period.  Early adoption is permitted.  The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.

Compensation – Retirement Benefits

In March 2017, the FASB issued an ASU requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component and outside a subtotal of income from operations, if presented.  The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization.  The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period.  Application is retrospective for the presentation of the components of these benefit costs and prospective for the capitalization of only service costs.  Early adoption is permitted.  The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.

Revenue from Contracts with Customers

In May 2014, the FASB issued an ASU to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance.  The codification was amended through additional ASU’s and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services.  Additional disclosures will be required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers.  The Company is required to adopt the new standard in the first quarter of 2018 using either the modified retrospective or cumulative effect transition method.  The Company has performed a review of contracts in each of its revenue streams and is developing accounting policies and applicable disclosures to address the provisions of the ASU.  While the Company does not currently expect net earnings to be materially impacted, the Company is analyzing whether total revenues and expenses will be significantly impacted.  The Company continues to evaluate the impact of this and other provisions of these ASU’s on its accounting policies, internal controls, and consolidated financial statements and related disclosures, and has not finalized any estimates of the potential impacts.  The Company will adopt the new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings as necessary.

Leases

In February 2016, FASB issued an ASU to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.  The main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP.  The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods.  Early adoption is permitted for all entities.  The Company anticipates adopting this guidance in the first quarter of 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements.

18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Contd.)

Note P – Recent Accounting Pronouncements  (Contd.)

Statement of Cash Flows

In August 2016, the FASB issued an ASU to reduce diversity in practice in how certain transactions are classified in the statement of cash flows.  The amendment provides guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees.  The ASU is effective for annual and interim periods beginning after December 15, 2017.  The Company is currently assessing the potential impact of this ASU on its consolidated financial statements.

Overall Review

During the three-month and nine-month periods ended September 30, 2017, worldwide benchmark oil and natural gas prices were above average comparable benchmark prices during 2016.  Although prices were above 2016 levels, unrealized losses from foreign exchange movements along with higher tax expense on earnings of foreign subsidiaries more than offset this increase in revenue in the third quarter.

For the three months ended September 30, 2017, the Company produced 154 thousand barrels of oil equivalent per day.  There was no production in the 2017 quarter from Canadian synthetic and heavy oil assets due to the 2016 and 2017 divestures of Syncrude and Seal assets, respectively.  The Company invested $287 million in capital expenditure in the third quarter of 2017 primarily in the United States and Canada.  The Company reported a net loss of $65.9 million, for the three months ended September 30, 2017, which included a foreign exchange after-tax loss of $43.9 million, principally on intercompany loans in the quarter and an after-tax loss of $11.8 million in the third quarter relating to crude oil derivative contracts.

For the nine-month period ended September 30, 2017, the Company reported  a net loss of $25.0 million, which included an after-tax gain of $96.0 million on the sale of the Seal heavy oil property in Canada.  The Company produced 162 thousand barrels of oil equivalent per day for the nine-month 2017 period and invested $702 million in capital expenditures, principally in the United States and Canada.  The Company incurred a non-cash deferred tax expense in the first nine months of 2017 of $65.2 million on earnings of foreign subsidiaries, the majority of which was recorded in first quarter of 2017 and recorded a foreign exchange after-tax loss of $86.6 million, principally on intercompany loans in the first nine months of 2017.  Further detail and discussion is provided in the narrative below.

Results of Operations

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

	Income (Loss)
	Three Months Ended			Nine Months Ended
	September 30,			September 30,
(Millions of dollars)	2017		2016	2017		2016
Exploration and production	$	33.6	25.0		276.6		(99.5)
Corporate and other		(99.9)	(39.6)		(302.8)		(111.7)
Loss from continuing operations		(66.3)	(14.6)		(26.2)		(211.2)
Discontinued operations		0.4	(1.6)		1.2		(0.8)
Net loss	$	(65.9)	(16.2)		(25.0)		(212.0)

Third quarter 2017 vs. 2016

For the third quarter of 2017, Murphy’s net loss was $65.9 million ($0.38 per diluted share) compared to net loss of $16.2 million ($0.09 per diluted share) in the third quarter of 2016.  Loss from continuing operations fell lower from a loss of $14.6 million ($0.08 per diluted share) in the 2016 quarter to a loss of $66.3 million ($0.38 per diluted share) in the 2017 period.  The Company’s exploration and production (E&P) continuing operations earned $33.6 million in the 2017 quarter compared to earnings of $25.0 million in the 2016 quarter.  The E&P results in the 2017 quarter were favorably impacted by higher revenues due to higher realized oil and natural gas sales prices, lower lease operating expenses, lower depreciation expense and lower dry hole costs, partially offset by lower volume sold, higher selling and general expenses and higher deferred tax expense on earnings of foreign subsidiaries.  The corporate function had after-tax costs of $99.9 million in the 2017 third quarter compared to after-tax costs of $39.6 million in the 2016 period with the unfavorable variance in the current period due to losses from foreign exchange effects in the 2017 period versus gains in the same period of 2016, higher net interest expense and deferred tax charges in 2017 on undistributed earnings of certain foreign subsidiaries, offset in part by lower administrative costs in the current quarter.  Thethird quarter of 2017 included gains from discontinued operations of $0.4 million ($0.00 per diluted share) compared to losses from discontinued operations of $1.6 million ($0.01 per diluted share) in the third quarter of 2016.

Nine months 2017 vs. 2016

For the first nine months of 2017, Murphy’s net loss was $25.0 million ($0.14 per diluted share) compared to a net loss of $212.0 million ($1.24 per diluted share) for the same period in 2016.  Loss from continuing operations improved from a loss of $211.2 million ($1.23 per diluted share) in the first nine months of 2016 to a loss of $26.2 million ($0.15 per diluted share) in 2017.  In the first nine months of 2017, the Company’s E&P continuing operations earned $276.6 million compared to a loss of $99.5 million in the same period of 2016.  The results for the first nine months of 2017 were favorably impacted

19

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

Results of Operations (Contd.)

Nine months 2017 vs. 2016 (contd.)

by higher revenues due to higher realized oil and natural gas sales prices, gain on sale of the Seal property in Western Canada, lower lease operating expenses, lower depreciation expense, non-recurring impairment expense in 2016, lower selling and general expenses, lower dry hole costs and higher tax benefits on investments in foreign areas, partially offset by higher non-cash deferred tax expense on earnings of foreign subsidiaries, higher other expense related primarily to rig demobilization in Malaysia and lower oil and natural gas volume sold.  The corporate function had after-tax costs of $302.8 million in the first nine months of 2017 compared to after-tax costs of $111.7 million in the 2016 period with the unfavorable variance in the current period due to losses from foreign exchange effects in the 2017 period versus gains in the same period of 2016, higher net interest expense and non-cash deferred tax charges in 2017 on undistributed earnings of certain foreign subsidiaries, offset in part by lower administrative costs.  Income from discontinued operations was $1.2 million ($0.01 per diluted share) in the first nine months of 2017 compared to a  loss of $0.8 million ($0.01 per diluted share) in the 2016 period.

Exploration and Production

Results of E&P continuing operations are presented by geographic segment below.

		Income (Loss)
	Three Months Ended			Nine Months Ended
	September 30,			September 30,
(Millions of dollars)	2017		2016	2017	2016
Exploration and production
United States	$	(19.9)	(27.1)	11.0	(158.5)
Canada		(3.2)	(4.8)	102.6	(36.9)
Malaysia		67.7	65.0	173.9	135.1
Other International		(11.0)	(8.1)	(10.9)	(39.2)
Total	$	33.6	25.0	276.6	(99.5)

Third quarter 2017 vs. 2016

United States E&P operations reported a net loss of $19.9 million in the third quarter of 2017 compared to a net loss of $27.1 million in the 2016 quarter.  Results improved $7.2 million in the 2017 quarter compared to the 2016 period.  Higher oil and natural gas realized sales prices more than offset impacts of lower volumes sold.  Lease operating expenses decreased due to lower costs in Eagle Ford Shale compared to the same quarter in 2016 with most of the reduction due to the Company’s continuous focus on improving its cost structure.  Depreciation expense decreased in 2017 compared to 2016 due primarily to lower volume sold in both Eagle Ford Shale and Gulf of Mexico and lower average unit rates in the Gulf of Mexico in the 2017 period.  Amortization of undeveloped leases were higher in the 2017 quarter due to costs related to certain offshore leases expiring in 2017 and 2018.  Revenue in the U.S. decreased by $5.9 million in the period as the U.S. segment recorded $18.1 million unrealized losses on open crude oil contracts in 2017 versus losses of $1.3 million in the 2016 period.  This was offset in part by higher oil and gas sales revenue.  Selling and general expenses increased in the third quarter of 2017 primarily due to higher allocated benefit costs in the current period versus 2016.

Canadian E&P operations reported a net loss of $3.2 million in the third quarter 2017 compared to a loss of $4.8 million in the 2016 quarter.  Canadian results of operations improved $1.6 million in the 2017 quarter compared to the 2016 period due to higher average sales prices received in 2017 for both oil and natural gas and lower lease operating expenses, partially offset by non-recurring 2016 income tax benefits associated with divestiture of Montney midstream assets in 2016 and a gain on sale of its synthetic operations completed in the third quarter 2016.  Natural gas sales volumes increased in 2017 due to new production in the Kaybob Duvernay and Placid Montney areas of Western Canada.

Malaysia E&P operations reported earnings of $67.7 million in the third quarter of 2017 and compared to earnings of $65.0 million in the comparable 2016 period.  Results were favorable to 2016 in Malaysia as higher average oil and natural gas prices realized, were mostly offset by lower natural gas volume sold, higher lease operating expense, higher depreciation expense, higher administrative expense and higher income tax expense.  Crude oil and natural gas sales volumes in Malaysia were lower in the 2017 quarter versus 2016, primarily due to a maintenance shutdown in Sarawak in 2017.  Depreciation expense was higher in 2017 compared to the 2016 quarter primarily due to higher unit rates in Block K and Sarawak partly offset by lower volumes sold in Block K and Sarawak.

20

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Third quarter 2017 vs. 2016 (Contd.)

Other international E&P operations reported a loss from continuing operations of $11.0 million in the third quarter of 2017 compared to a loss of $8.1 million in the 2016 quarter.  The results were $2.9 million lower in the 2017 period versus 2016 primarily related to higher exploration expenses and lower income tax benefits on investments in foreign areas, partially offset by lower selling and general expenses resulting from restructuring activity in 2016.

Total hydrocarbon production averaged 153,842 barrels of oil equivalent per day in the 2017 third quarter, which represented a 9% decrease from the 169,844 barrels of oil equivalents per day produced in the 2016 quarter.  When the Seal asset sold in 2017 is excluded, the Company’s worldwide production decreased 8% in 2017 compared to 2016. 

Average crude oil and condensate production was 84,230 barrels per day in the third quarter of 2017 compared to 96,476 barrels per day in the third quarter of 2016.  Crude oil production in the Eagle Ford Shale area of South Texas in the 2017 quarter was essentially flat to the same quarter in 2016.  Crude oil production in the Gulf of Mexico was lower in the 2017 quarter due to well decline and unplanned downtime.  Heavy oil production from the Seal area in Western Canada was divested in mid-January 2017.  Onshore oil production in Canada improved in the 2017 quarter in the Company’s Kaybob Duvernay and Placid Montney areas acquired in the third quarter of 2016.  Oil production offshore Eastern Canada was lower during 2017 primarily due to unplanned downtime at both Hibernia and Terra Nova fields.  Lower oil production in 2017 in Malaysia was primarily attributable to less net oil volumes produced in Block K due to lower working interest in the Kakap field subsequent to the redetermination of working interest.  On a worldwide basis, the Company's crude oil and condensate prices averaged $49.82 per barrel in the third quarter 2017 compared to $44.64 per barrel in the 2016 period, an increase of 12% quarter to quarter. 

Total production of natural gas liquids (NGL) was 9,128 barrels per day in the 2017 third quarter compared to 9,703 barrels per day in the same 2016 period.  The decrease in NGL production was primarily associated with lower natural gas liquids volumes in the U.S, offset by higher volumes in Canada.  The average sales price for U.S. NGL was $18.02 per barrel in the 2017 quarter compared to $11.38 per barrel in 2016.  Average NGL prices in Malaysia in the third quarter of 2017 and 2016 were $49.66 per barrel and $45.12 per barrel, respectively.

Natural gas sales volumes averaged 363 million cubic feet per day in the third quarter 2017 compared to 382 million cubic feet per day in 2016.  Natural gas sales volumes increased in North America for the 2017 period due primarily to new volumes in the Kaybob Duvernay and Placid Montney areas of Western Canada acquired in the third quarter of 2016, and growth in the Tupper Montney business, offset in part by lower volumes produced in both offshore Gulf of Mexico and in Eagle Ford Shale.  Natural gas production volumes in Malaysia decreased in the 2017 period due to lower demand and planned downtime at Sarawak in the current period.  North American natural gas sales prices averaged $1.93 per thousand cubic feet (MCF) in the 2017 quarter, 2% below the $1.96 per MCF average in the same quarter of 2016.  The average realized price for natural gas produced in the 2017 quarter at fields offshore Sarawak was $3.60 per MCF, compared to a price of $3.01 per MCF in the 2016 quarter.

Nine months 2017 vs. 2016

United States E&P operations reported earnings of $11.0 million in the first nine months of 2017 compared to a loss of $158.5 million in the 2016 period, an improvement of $169.5 million in 2017 compared to the 2016 period.  Revenue in the U.S. was $176.5 million in the period as oil and natural gas realized sales prices and unrealized gains on crude oil derivative contracts more than offset lower sales volume.  Lease operating expenses decreased by $33.9 million primarily due to lower costs in Eagle Ford Shale and Gulf of Mexico mainly related to cost structure improvements coupled with lower variable costs based on volumes produced.  Depreciation expense decreased $54.2 million in 2017 compared to 2016 due to lower unit rates in the Gulf of Mexico in the 2017 period and lower U.S. volume sold.  Exploration expenses were $6.6 million higher in the 2017 period primarily related to higher undeveloped lease amortization expense compared to the same period of 2016.  Income taxes increased by $87.7 million in the 2017 period due to improvements in net income.

21

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

Results of Operations (Contd.)

Exploration and Production (Contd.)

Nine months 2017 vs. 2016 (Contd.)

Canadian E&P operations reported earnings of $102.6 million in the first nine months of 2017 compared to a loss of $36.9 million in the 2016 period.  Results for conventional operations improved by $187.2 million in 2017 due to a gain of $132.4 million on the sale of Seal heavy oil assets in 2017, lower impairment expense of $95.1 million in 2017 and higher average realized sales prices for crude oil and natural gas, partially offset by lower oil volume sold (from the sale of Seal and Syncrude assets in quarter 1 2017 and quarter 2 2016, respectively), higher lease operating expense for conventional operations and non-recurring income tax benefits recognized on the sale of certain Montney midstream assets in 2016.

Malaysia E&P operations reported earnings of $173.9 million in the first nine months of 2017 compared to earnings of $135.1 million during the same period in 2016.  Results improved $38.8 million in 2017 in Malaysia primarily due to higher revenue of $53.0 million driven by higher commodity prices received and higher natural gas volume sold in Sarawak, partially offset by lower oil volume sold (from Block K due to normal field decline).  Depreciation expense was $10.1 million lower in 2017 compared to the same period in 2016 primarily due to lower unit rates in Sarawak and lower oil volume sold, partly offset by higher natural gas volume sold in Sarawak and higher unit rates at Block K.

Other international E&P operations reported a loss of $10.9 million in the first nine months of 2017 compared to a loss of $39.2 million in the 2016 period.  The 2017 period included lower dry hole costs of $10.4 million, with the higher 2016 costs primarily associated with unsuccessful drilling in Block 11-2/11 in Vietnam.  The 2017 period also included income tax benefits on investments in foreign areas of $32.9 million.  Other exploration expenses were $5.9 million higher in the current year, mostly attributable to costs in Mexico, Australia and Brazil.  Other expenses were $8.8 million higher in the 2017 period primarily related to no repeat of a credit from an adjustment of previously recorded exit costs in 2016 in the Republic of Congo.

Total worldwide production averaged 161,917 barrels of oil equivalent per day during the nine months ended September 30, 2017, a 9% decrease from 178,319 barrels of oil equivalent produced in the same period in 2016.  When Seal and Syncrude are excluded, the Company’s worldwide production decreased by 4%.  Crude oil and condensate production in the first nine months of 2017 averaged 89,580 barrels per day compared to 106,279 barrels per day in 2016.  Crude oil production decreased at Eagle Ford Shale in 2017 due to production decline associated with significantly less drilling in response to lower prices and phasing of capital expenditures into late 2017.  Heavy oil production declined in 2017 in the Seal area of Western Canada primarily due to divestment of the asset in January 2017.  Synthetic oil production in Canada also was nil in 2017 due to the Company’s divestiture of Syncrude Canada Ltd. in the second quarter of 2016.  Lower oil production in 2017 in Block K Malaysia was primarily attributable to lower working interest in Kakap field subsequent to the redetermination of working interest.  For the first nine months of 2017, the Company’s sales price for crude oil and condensate averaged $49.41 per barrel, up from $40.67 per barrel in 2016. 

Total production of NGLs was 9,140 barrels per day in the 2017 period compared to 9,275 barrels per day in 2016. The sales price for U.S. NGLs averaged $16.33 per barrel in 2017 compared to $10.31 per barrel in 2016. 

Natural gas sales volumes increased from 377 million cubic feet per day in 2016 to 379 million cubic feet per day in 2017. Natural gas sales volume increased, primarily due to less unplanned downtime in 2017 in Sarawak.  North American natural gas volumeswere flat as improvement in Canada due to the 2017 volumes from Kaybob Duvernay and Placid Montney fields were offset in part by lower U.S. volume due to natural field decline.  The average sales price for North American natural gas in the first nine months of 2017 was $2.08 per MCF, up from $1.58 per MCF realized in 2016.  Natural gas production at fields offshore Sarawak was sold at an average realized price of $3.50 per MCF in 2017 compared to $3.25 per MCF in 2016. 

Additional details about results of oil and gas operations are presented in the tables on pages 29 and 30.

22

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, 2017 and 2016 follow.

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2017	2016	2017	2016
Net crude oil and condensate produced – barrels per day	84,230	96,476	89,580	106,279
United States – Eagle Ford Shale	33,070	33,307	33,281	36,790
– Gulf of Mexico and other	10,240	11,722	11,309	12,791
Canada – onshore	3,240	1,288	2,729	791
– offshore	6,225	9,400	8,100	8,483
– heavy1	–	2,678	201	2,732
– synthetic1	–	–	–	6,194
Malaysia – Sarawak	11,508	12,889	12,727	13,288
– Block K	19,947	25,192	21,233	25,210
Net crude oil and condensate sold – barrels per day	92,033	97,542	89,597	104,525
United States – Eagle Ford Shale	33,070	33,307	33,281	36,790
– Gulf of Mexico and other	10,240	11,722	11,309	12,791
Canada – onshore	3,240	1,288	2,729	791
– offshore	6,533	9,027	7,812	8,576
– heavy1	–	2,678	201	2,732
– synthetic1	–	–	–	6,194
Malaysia – Sarawak	13,083	12,641	13,350	12,024
– Block K	25,867	26,879	20,915	24,627
Net natural gas liquids produced – barrels per day	9,128	9,703	9,140	9,275
United States – Eagle Ford Shale	6,669	6,940	6,812	6,972
– Gulf of Mexico and other	910	1,502	967	1,399
Canada	510	307	410	162
Malaysia – Sarawak	1,039	954	951	742
Net natural gas liquids sold – barrels per day	9,213	8,770	9,165	9,289
United States – Eagle Ford Shale	6,669	6,940	6,812	6,972
– Gulf of Mexico	910	1,502	967	1,399
Canada	510	307	410	162
Malaysia – Sarawak	1,124	21	976	756
Net natural gas sold – thousands of cubic feet per day	362,901	381,988	379,182	376,592
United States – Eagle Ford Shale	29,476	34,900	32,862	36,430
– Gulf of Mexico and other	11,232	16,873	11,654	19,012
Canada	223,032	204,816	220,121	206,458
Malaysia – Sarawak	90,181	115,535	106,481	103,327
– Block K	8,980	9,864	8,064	11,365
Total net hydrocarbons produced – equivalent barrels per day2	153,842	169,844	161,917	178,319
Total net hydrocarbons sold – equivalent barrels per day2	161,730	169,977	161,959	176,579

1The Company sold the Seal area heavy oil field in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016.

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

23

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,
	2017		2016	2017	2016
Weighted average sales prices
Crude oil and condensate – dollars per barrel
United States – Eagle Ford Shale	$	48.49	44.59	48.42	40.65
– Gulf of Mexico		47.82	43.93	47.48	40.53
Canada1    – onshore		43.15	36.36	43.64	41.04
– offshore		51.26	45.87	50.35	40.15
– heavy2		–	19.50	25.12	14.20
– synthetic2		–	–	–	35.59
Malaysia – Sarawak3		52.62	47.05	52.07	43.62
– Block K3		51.36	46.24	50.95	43.70
Natural gas liquids – dollars per barrel
United States – Eagle Ford Shale	$	17.89	10.89	16.12	10.06
– Gulf of Mexico		19.00	13.65	17.84	11.60
Canada1		22.77	39.23	22.48	41.04
Malaysia – Sarawak3		49.66	45.12	49.94	37.50
Natural gas – dollars per thousand cubic feet
United States – Eagle Ford Shale	$	2.44	2.24	2.53	1.69
– Gulf of Mexico		2.49	2.35	2.56	1.81
Canada1		1.84	1.88	1.99	1.58
Malaysia – Sarawak3		3.60	3.01	3.50	3.25
– Block K		0.25	0.23	0.24	0.24

1U.S. dollar equivalent.

2The Company sold the Seal area heavy oil field in January 2017 and its 5% non-operated interest in Syncrude Canada Ltd. in June 2016.

3Prices are net of payments under the terms of the respective production sharing contracts.

24

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, 2017 AND 2016

	United
(Millions of dollars)	States		Canada	Malaysia	Other	Total
Three Months Ended September 30, 2017
Oil and gas sales and other operating revenues	$	195.9	81.9	220.5	–	498.3
Lease operating expenses		43.5	28.7	40.6	–	112.8
Severance and ad valorem taxes		10.5	0.3	–	–	10.8
Depreciation, depletion and amortization		128.4	45.9	63.7	1.0	239.0
Accretion of asset retirement obligations		4.3	2.0	4.4	–	10.7
Exploration expenses
Dry holes		(0.6)	–	(2.5)	–	(3.1)
Geological and geophysical		0.1	–	–	1.5	1.6
Other		1.5	0.2	–	7.7	9.4
		1.0	0.2	(2.5)	9.2	7.9
Undeveloped lease amortization		20.4	0.2	–	–	20.6
Total exploration expenses		21.4	0.4	(2.5)	9.2	28.5
Selling and general expenses		16.6	6.9	4.8	5.1	33.4
Other expenses		0.8	0.5	1.2	–	2.5
Results of operations before taxes		(29.6)	(2.8)	108.3	(15.3)	60.6
Income tax provisions (benefits)		(9.7)	0.4	40.6	(4.3)	27.0
Results of operations (excluding corporate    overhead and interest)	$	(19.9)	(3.2)	67.7	(11.0)	33.6
Three Months Ended September 30, 2016
Oil and gas sales and other operating revenues	$	201.8	80.9	202.7	0.2	485.6
Lease operating expenses		59.6	30.7	29.4	–	119.7
Severance and ad valorem taxes		8.5	1.1	–	–	9.6
Depreciation, depletion and amortization		141.1	46.5	62.0	1.5	251.1
Accretion of asset retirement obligations		4.2	2.8	4.0	–	11.0
Exploration expenses
Dry holes		0.8	–	0.4	(0.2)	1.0
Geological and geophysical		(0.1)	–	0.1	0.5	0.5
Other		2.5	–	–	5.5	8.0
		3.2	–	0.5	5.8	9.5
Undeveloped lease amortization		9.3	1.1	–	–	10.4
Total exploration expenses		12.5	1.1	0.5	5.8	19.9
Selling and general expenses		14.7	5.2	0.2	7.4	27.5
Other expenses		1.0	–	5.4	0.1	6.5
Results of operations before taxes		(39.8)	(6.5)	101.2	(14.6)	40.3
Income tax provisions (benefits)		(12.7)	(1.7)	36.2	(6.5)	15.3
Results of operations (excluding corporate    overhead and interest)	$	(27.1)	(4.8)	65.0	(8.1)	25.0

25

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, 2017 AND 2016

			Canada
	United		Conven-
(Millions of dollars)	States		tional	Synthetic*	Malaysia	Other	Total
Nine Months Ended September 30, 2017
Oil and gas sales and other operating revenues	$	696.7	388.1	–	594.4	–	1,679.2
Lease operating expenses		135.7	76.8	–	133.6	–	346.1
Severance and ad valorem taxes		31.6	1.2	–	–	–	32.8
Depreciation, depletion and amortization		402.3	136.6	–	160.0	2.9	701.8
Accretion of asset retirement obligations		12.8	5.9	–	12.9	–	31.6
Exploration expenses
Dry holes		(1.9)	–	–	0.8	–	(1.1)
Geological and geophysical		1.0	0.1	–	–	6.0	7.1
Other		5.5	0.3	–	–	24.8	30.6
		4.6	0.4	–	0.8	30.8	36.6
Undeveloped lease amortization		39.4	1.4	–	–	–	40.8
Total exploration expenses		44.0	1.8	–	0.8	30.8	77.4
Selling and general expenses		48.7	21.2	–	10.5	15.0	95.4
Other expenses		1.5	0.4	–	9.1	–	11.0
Results of operations before taxes		20.1	144.2	–	267.5	(48.7)	383.1
Income tax provisions (benefits)		9.1	41.6	–	93.6	(37.8)	106.5
Results of operations (excluding corporate    overhead and interest)	$	11.0	102.6	–	173.9	(10.9)	276.6
Nine Months Ended September 30, 2016
Oil and gas sales and other operating revenues	$	520.2	200.2	64.2	541.4	0.2	1,326.2
Lease operating expenses		169.6	73.3	69.9	122.5	–	435.3
Severance and ad valorem taxes		30.0	3.2	2.5	–	–	35.7
Depreciation, depletion and amortization		456.5	137.5	16.5	170.0	4.6	785.1
Accretion of asset retirement obligations		12.8	8.2	2.4	12.1	–	35.5
Impairment of assets		–	95.1	–	–	–	95.1
Exploration expenses
Dry holes		0.4	–	–	4.5	10.4	15.3
Geological and geophysical		0.6	2.9	–	0.6	4.8	8.9
Other		4.5	0.5	–	–	18.9	23.9
		5.5	3.4	–	5.1	34.1	48.1
Undeveloped lease amortization		31.9	3.4	–	–	0.5	35.8
Total exploration expenses		37.4	6.8	–	5.1	34.6	83.9
Selling and general expenses		49.9	20.9	0.5	8.6	26.6	106.5
Other expenses (benefits)		1.1	–	–	6.3	(8.8)	(1.4)
Results of operations before taxes		(237.1)	(144.8)	(27.6)	216.8	(56.8)	(249.5)
Income tax provisions (benefits)		(78.6)	(60.2)	(75.3)	81.7	(17.6)	(150.0)
Results of operations (excluding corporate    overhead and interest)	$	(158.5)	(84.6)	47.7	135.1	(39.2)	(99.5)

*The Company sold its 5% non-operated interest in Syncrude Canada Ltd. on June 23, 2016.

26

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 cost of $99.9 million in the 2017 third quarter compared to $39.6 million in the same 2016 quarter.  The $60.3 million increased cost in the 2017 period is primarily due to after-tax foreign currency exchange losses of $43.9 millionin the 2017 period versus gains in the 2016 period, higher net interest expense of $9.5 million in 2017 and deferred tax charges on undistributed earnings of certain foreign subsidiaries of $4.7 million in 2017, partially offset by lower administrative costs in the current quarter.  Net interest costs increased in the 2017 period primarily due to accelerated interest payment upon the early repayment of the December 2017 notes, additional interest on $550 million notes issued in August 2017 (2025 maturity) and an increase of 1.00% on the coupon rates on $950 million of the Company’s outstanding notes effective September 1, 2016 following a downgrade by Moody’s Investor Services in February 2016.  Selling and general expenses decreased $4.7 million in the third quarter of 2017 primarily related to restructuring activity that occurred in 2016 and continual monitoring of the cost structure.

During the first nine months of 2017, Corporate activities had a net cost of $302.8 million compared to $111.7 million for the same period of 2016.  The $191.1 million increased cost in the 2017 period compared to the 2016 period was primarily due to after-tax losses fromforeign currency exchange of $86.6 millionin the 2017 period versus gains in the 2016 period, deferred tax charges in 2017 on undistributed earnings of certain foreign subsidiaries of $65.2 million and higher net interest expense of $34.5 million in 2017 due to additional interest on the $550 million notes issued in August 2017 and an increase of 1.00% on the coupon rates on $950 million of the Company’s notes.  These were partially offset by lower administrative costs in 2017.  During the first nine months of 2017, the Company’s determined that prospective earnings from its Malaysian and Canadian subsidiaries will not be considered reinvested into local operations.  Due to this change in assertion, the Company recorded a deferred tax charge of $65.2 million in the first nine month of 2017 associated with the estimated tax consequence of the future repatriation of these subsidiaries’ nine-month 2017 earnings.  This decision provides greater financial flexibility as it considers future domestic investment opportunities.  The Company expects to incur further tax charges in the fourth quarter 2017 for additional 2017 foreign earnings as they arise.

Discontinued Operations

The Company has presented its former U.K. and U.S. refining and marketing operations as discontinued operations in its consolidated financial statements.  The after-tax results of these operations for the three-month and nine-month periods ended September 30, 2017 and 2016 are reflected in the following table.

		Three Months Ended		Nine Months Ended
		September 30,		September 30,
(Millions of dollars)		2017	2016	2017	2016
U.S. refining and marketing	$	(0.7)	–	(0.7)	–
U.K. refining and marketing		1.1	(1.0)	1.9	(1.1)
U.K. exploration and production		–	(0.6)	–	0.3
Income (loss) from discontinued operations	$	0.4	(1.6)	1.2	(0.8)

Financial Condition

Net cash provided by continuing operating activities was $819.6 million for the first nine months of 2017 compared to $280.3 million during the same period in 2016.  The improvement in cash provided by continuing operations activities in 2017 was primarily attributable to higher realized sales prices for the Company’s oil and gas production, lower lease operating and administrative expenses, and rig cancellation payments in 2016 which are discussed below, partially offset by lower volume sold in the current year and higher interest costs.  Changes in operating working capital from continuing operations increased cash by $1.1 million during the first nine months of 2017, compared to a use of cash of $152.6 million in 2016.  The use of cash in 2016 included $266.6 million associated with pay-off of cancelled deepwater rig contracts that were previously charged to expense in 2015.  Proceeds from sales of property and equipment generated cash of $69.1 million in 2017 primarily relating to proceeds from the sale of the Seal field in Western Canada and the sale of certain areas of Eagle Ford Shale in South Texas, while the 2016 period generated cash of $1,154.6 million mainly related to the sale of Syncrude Canada Limited and certain midstream assets in the Tupper area of Western Canada.  Other significant sources of cash included $320.8 million in the 2017 period and $712.9 million in 2016 from maturity of Canadian government securities that had maturity dates greater than 90 days at acquisition.

27

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

Financial Condition (Contd.)

Cash used for property additions and dry holes, which includes amounts expensed, were $706.4 million and $781.7 million in the nine-month period ended September 30, 2017 and 2016, respectively.Total cash dividends to shareholders amounted to $129.4 million for the nine-months ended September 30, 2017 compared to $163.6 million in the same period of 2016 as the Company lowered the dividend from $1.40 per share to $1.00 per share effective in the third quarter 2016.  The purchase of Canadian government securities with maturity dates greater than 90 days at acquisition used cash of $212.7 million in the 2017 period and $651.2 million in the 2016 period.  The proceeds of the $550 million notes issued in August 2017, were used to redeem the Company’s $550 million 2.50% notes in September 2017.  The 2.50% notes had a maturity date of December 2017 and were retired early.The Company repaid debt in the amount of $600.0 million in the nine-month period of 2016 using proceeds from the sale of assets.

Total accrual basis capital expenditures were as follows:

	Nine Months Ended
	September 30,
(Millions of dollars)	2017		2016
Capital Expenditures
Exploration and production	$	694.7		614.6
Corporate		6.9		20.7
Total capital expenditures	$	701.6		635.3

The increase in capital expenditures in the exploration and production business in 2017 compared to 2016 was primarily attributable to higher developmental drilling activities in Eagle Ford Shale and Kaybob Duvernay and Placid Montney assets, partially offset by 2016 acquisition costs in the Kaybob Duvernay and liquids rich Placid Montney properties in Canada and lower spending in Malaysia.

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)	2017		2016
Property additions and dry hole costs per cash flow statements	$	706.4		781.7
Geophysical and other exploration expenses		37.7		32.8
Capital expenditure accrual changes and other		(42.5)		(179.2)
Total capital expenditures	$	701.6		635.3

Working capital (total current assets less total current liabilities) at September 30, 2017 was $615.6 million, $558.8 million more than December 31, 2016, with the increase primarily attributable to the Company redeeming the $550 million in 2.50% notes in September 2017, higher cash balances and lower accounts payable.

At September 30, 2017, long-term debt of $2,908.3 million had increased by $485.5 million compared to December 31, 2016.  A summary of capital employed at September 30, 2017 and December 31, 2016 follows.

	September 30, 2017				December 31, 2016
(Millions of dollars)	Amount		%		Amount		%
Capital employed
Long-term debt	$	2,908.3	36.9	%	$	2,422.8	33.0	%
Stockholders' equity		4,980.1	63.1	%		4,916.7	67.0	%
Total capital employed	$	7,888.4	100.0	%	$	7,339.5	100.0	%

Cash and invested cash are maintained in several operating locations outside the United States.  At September 30, 2017, Cash and cash equivalents held outside the U.S. included U.S. dollar equivalents of approximately $495.5 million in Canada and $261.6 million in Malaysia.  In addition, $17.0 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, 2017.  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 incentivize 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

Financial Condition (Contd.)

any cash repatriated to the United States through a dividend tothe U.S. parent.  See the “Corporate” section on page 31 of this Form 10-Q report regarding theCompany’s change in assertion for indefinite reinvestment on prospective earnings from its Malaysian and Canadian subsidiaries.

Accounting and Other Matters

Business Combinations

In January 2017, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) to clarify the definition of a business to assist entities in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses.  The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs.  The update is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The prospective approachis required for adoption and early adoption is permitted for transactions not previously reported in issued financial statements.  The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures.

Compensation – Stock Compensation

In March 2016, the FASB issued an ASU intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification within the statement of cash flows.  The amendments in this ASU were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods.  The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures as there were no exercises of Company options during the period.

In May 2017, FASB issued an ASU which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting.  The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period.  Early adoption is permitted.  The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.

Compensation – Retirement Benefits

In March 2017, the FASB issued an ASU requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component and outside a subtotal of income from operations, if presented.  The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization.  The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period.  Application is retrospective for the presentation of the components of these benefit costs and prospective for the capitalization of only service costs.  Early adoption is permitted.  The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.

Revenue from Contracts with Customers

In May 2014, the FASB issued an ASU to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance.  The codification was amended through additional ASU’s and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services.  Additional disclosures will be required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers.  The Company is required to adopt the new standard in the first quarter of 2018 using either the modified retrospective or cumulative effect transition method.  The Company has performed a review of contracts in each of its revenue streams and is developing accounting policies and applicable disclosures to address the provisions of the ASU.  While the Company does not currently expect net earnings to be materially impacted, the Company is analyzing whether total revenues and expenses will be significantly impacted.  The Company continues to evaluate the impact of this and other provisions of these ASU’s on its accounting policies, internal controls, and consolidated financial statements and related disclosures, and has not finalized any estimates of the potential impacts.  The Company will adopt the new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings as necessary.

Accounting and Other Matters(Contd.)

Leases

In February 2016, FASB issued an ASU to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.  The main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP.  The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods.  Early adoption is permitted for all entities.  The Company anticipates adopting this guidance in the first quarter of 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements.

Statement of Cash Flows

In August 2016, the FASB issued an ASU to reduce diversity in practice in how certain transactions are classified in the statement of cash flows.  The amendment provides guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees.  The ASU is effective for annual and interim periods beginning after December 15, 2017.  The Company is currently assessing the potential impact of this ASU on its consolidated financial statements.

Outlook

Average worldwide crude oil prices in October 2017 have slightly improved from the average prices during the third quarter of 2017.  North American natural gas prices decreased slightly in October from the 2017 third quarter.  The Company expects its total oil and natural gas production to average 170,000 – 172,000 barrels of oil equivalent per day in the fourth quarter 2017.  The Company currently anticipates total capital expenditures for the full year 2017 to be approximately $940 million.

The Company will primarily fund its remaining capital program in 2017 using operating cash flow, but will supplement funding where necessary using borrowings under available credit facilities.  If oil and/or natural gas prices weaken, actual cash flow generated from operations could be reduced such that capital spending reductions are required and/or additional borrowings might be required during the remainder of year to maintain funding of the Company’s ongoing development projects. 

As of November 1, 2017, 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. 2017		22,000 bbls/d	$50.41 per bbl.
U.S. Oil	West Texas Intermediate	Jan. –  Dec. 2018		7,000 bbls/d	$51.92 per bbl.
Natural Gas	TCPL–NOVA System	Jul. – Dec. 2017		124 mmcf/d	C$2.97 per mcf
Natural Gas	TCPL–NOVA System	Jan. – Dec. 2018		59 mmcf/d	C$2.81 per mcf
Natural Gas	Alberta Alliance	Nov. 2017 – Mar. 2018		20 mmcf/d	US$3.51 per mcf	*

*Title transfer at Alberta Alliance pipeline.  Sale price fixed and transported to Chicago Gate.

28

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

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 2016 Annual Report on Form 10-K on file with the U.S. Securities and

Exchange Commission and page 36 of this Form 10-Q report.  Murphy undertakes no duty to publicly update or revise any forward-looking statements.

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 J 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, 2017 covering certain future U.S. crude oil sales volumes in 2017.  A 10% increase in the respective benchmark price of these commodities would have decreased the recorded net receivable associated with these derivative contracts by approximately $21.9 million, while a 10% decrease would have increased the recorded net receivable by a similar amount.

There were no derivative foreign exchange contracts in place at September 30, 2017.

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.

During the quarter ended September 30, 2017, there were no other changes in the Company's internal control over financial reporting 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 2016 Form 10-K filed on February 24, 2017.  The Company has not identified any additional risk factors not previously disclosed in its 2016 Form 10-K report.

ITEM 6. EXHIBITS

The Exhibit Index on page 38 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.

MURPHYOILCORPORATION
(Registrant)
By	/s/ CHRISTOPHER D. HULSE
	Christopher D. Hulse,   Vice President and Controller
	(Chief Accounting Officer and Duly Authorized Officer)

November 1, 2017

(Date)

EXHIBIT INDEX

Exhibit
No.
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.

29

EX-31.1

EXHIBIT 31.1

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Roger W. Jenkins certify that:

1. I have reviewed this quarterly report on Form 10-Q of Murphy Oil Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controls over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date:  November 1, 2017

By		/s/ Roger W. Jenkins
	Roger W. Jenkins
	Principal Executive Officer

Ex. 31-1

EX-31.2

EXHIBIT 31.2

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John W. Eckart, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Murphy Oil Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controls over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting.

Date:  November 1, 2017

By		/s/ John W. Eckart
	John W. Eckart
	Principal Financial Officer

Ex. 31-2

EX-32

EXHIBIT 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Murphy Oil Corporation (the “Company”) on Form 10-Q for the period endedSeptember 30, 2017as filed with the Securities and Exchange Commission on the date hereof (the “Report”), we, Roger W. Jenkinsand John W. Eckart,  Principal Executive Officer and PrincipalFinancial Officer, respectively,of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to our knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:  November 1, 2017

By		/s/  Roger W. Jenkins
	Roger W. Jenkins
	Principal Executive Officer

By		/s/  John W. Eckart
	John W. Eckart
	Principal Financial Officer

Ex. 32-1

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Oct. 31, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Trading Symbol	mur
Entity Registrant Name	MURPHY OIL CORP /DE
Entity Central Index Key	0000717423
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		172,572,873

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Current assets
Cash and equivalents	$ 997,207	$ 872,797
Canadian government securities with maturities greater than 90 days at the date of acquisition		111,542
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2017 and 2016	267,209	357,099
Inventories, at lower of cost or market	120,066	127,071
Prepaid expenses	39,427	63,604
Assets held for sale	23,248	27,070
Total current assets	1,447,157	1,559,183
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,027,902 in 2017 and $12,607,815 in 2016	8,283,738	8,316,188
Deferred income taxes	406,703	365,935
Deferred charges and other assets	55,161	54,554
Total assets	10,192,759	10,295,860
Current liabilities
Current maturities of long-term debt	9,781	569,817
Accounts payable	584,025	784,975
Income taxes payable	57,687	13,920
Other taxes payable	30,160	28,167
Other accrued liabilities	146,607	102,777
Liabilities associated with assets held for sale	3,270	2,776
Total current liabilities	831,530	1,502,432
Long-term debt, including capital lease obligation	2,908,285	2,422,750
Deferred income taxes	108,756	69,081
Asset retirement obligations	747,602	681,528
Deferred credits and other liabilities	616,452	617,490
Liabilities associated with assets held for sale		85,900
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 2017 and 2016	195,056	195,056
Capital in excess of par value	910,936	916,799
Retained earnings	5,575,175	5,729,596
Accumulated other comprehensive loss	(425,504)	(628,212)
Treasury stock	(1,275,529)	(1,296,560)
Total stockholders' equity	4,980,134	4,916,679
Total liabilities and stockholders' equity	$ 10,192,759	$ 10,295,860

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Accounts receivable, allowance for doubtful accounts	$ 1,605	$ 1,605
Property, plant and equipment, accumulated depreciation, depletion and amortization	$ 12,027,902	$ 12,607,815
Cumulative Preferred Stock, par value (per share)	$ 100	$ 100
Cumulative Preferred Stock, authorized shares	400,000	400,000
Cumulative Preferred Stock, shares issued	0	0
Common Stock, par value (per share)	$ 1.00	$ 1.00
Common Stock, authorized shares	450,000,000	450,000,000
Common Stock, shares issued	195,055,724	195,055,724
Minimum [Member]
Maturity of Canadian government securities	90 days	90 days

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CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues
Sales and other operating revenues	$ 498,202	$ 486,276	$ 1,552,473	$ 1,326,587
Gain (loss) on sale of assets	117	(730)	130,765	3,101
Total revenues	498,319	485,546	1,683,238	1,329,688
Costs and expenses
Lease operating expenses	112,751	119,663	346,072	435,296
Severance and ad valorem taxes	10,816	9,592	32,771	35,668
Exploration expenses	28,492	19,866	77,356	83,910
Selling and general expenses	56,672	55,523	168,259	196,143
Depreciation, depletion and amortization	243,636	255,900	714,782	797,288
Accretion of asset retirement obligations	10,654	11,043	31,638	35,514
Impairment of assets				95,088
Other expense (benefit)	2,454	6,486	10,988	(1,446)
Total costs and expenses	465,475	478,073	1,381,866	1,677,461
Operating income (loss) from continuing operations	32,844	7,473	301,372	(347,773)
Other income (loss)
Interest and other income (loss)	(47,721)	14,987	(93,524)	38,602
Interest expense, net	(48,681)	(39,219)	(138,423)	(103,889)
Total other loss	(96,402)	(24,232)	(231,947)	(65,287)
Income (loss) from continuing operations before income taxes	(63,558)	(16,759)	69,425	(413,060)
Income tax expense (benefit)	2,760	(2,176)	95,602	(201,897)
Loss from continuing operations	(66,318)	(14,583)	(26,177)	(211,163)
Income (loss) from discontinued operations, net of income taxes	425	(1,593)	1,177	(885)
NET LOSS	$ (65,893)	$ (16,176)	$ (25,000)	$ (212,048)
INCOME (LOSS) PER COMMON SHARE - BASIC
Continuing operations	$ (0.38)	$ (0.08)	$ (0.15)	$ (1.23)
Discontinued operations		(0.01)	0.01	(0.01)
Net loss	(0.38)	(0.09)	(0.14)	(1.24)
INCOME (LOSS) PER COMMON SHARE - DILUTED
Continuing operations	(0.38)	(0.08)	(0.15)	(1.23)
Discontinued operations		(0.01)	0.01	(0.01)
Net loss	(0.38)	(0.09)	(0.14)	(1.24)
Cash dividends per Common share	$ 0.25	$ 0.25	$ 0.75	$ 0.95
Average Common shares outstanding
Basic	172,572,873	172,199,350	172,509,418	172,164,683
Diluted	172,572,873	172,199,350	172,509,418	172,164,683

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
Net loss	$ (65,893)	$ (16,176)	$ (25,000)	$ (212,048)
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation	101,210	(37,369)	194,094	124,522
Retirement and postretirement benefit plans	2,396	2,515	7,169	7,544
Deferred loss on interest rate hedges reclassified to interest expense	482	482	1,445	1,445
Other comprehensive income (loss)	104,088	(34,372)	202,708	133,511
COMPREHENSIVE INCOME (LOSS)	$ 38,195	$ (50,548)	$ 177,708	$ (78,537)

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016
Operating Activities
Net loss		$ (25,000)	$ (212,048)
Adjustments to reconcile net loss to net cash provided by continuing operations activities:
(Income) loss from discontinued operations		(1,177)	885
Depreciation, depletion and amortization		714,782	797,288
Impairment of assets			95,088
Amortization of deferred major repair costs			3,794
Dry hole costs (credits)		(1,139)	15,226
Amortization of undeveloped leases		40,859	35,828
Accretion of asset retirement obligations		31,638	35,514
Deferred and noncurrent income tax benefit		(3,567)	(345,157)
Pretax gains from disposition of assets		(130,765)	(3,101)
Net (increase) decrease in noncash operating working capital		1,070	(152,618)	[1]
Other operating activities, net		192,867	9,651
Net cash provided by continuing operations activities		819,568	280,350
Investing Activities
Property additions and dry hole costs		(706,417)	(781,668)	[2]
Proceeds from sales of property, plant and equipment		69,146	1,154,623
Purchases of investment securities	[3]	(212,661)	(651,218)
Proceeds from maturity of investment securities	[3]	320,828	712,863
Other investing activities, net			(7,229)
Net cash (required) provided by investing activities		(529,104)	427,371
Financing Activities
Borrowings of debt		541,772	541,444
Repayments of debt		(550,000)	(600,000)
Capital lease obligation payments		(14,687)	(7,808)
Withholding tax on stock-based incentive awards		(7,151)	(1,138)
Issue cost of debt facility			(13,971)
Cash dividends paid		(129,421)	(163,586)
Other financing activities, net			(20)
Net cash required by financing activities		(159,487)	(245,079)
Cash Flows from Discontinued Operations
Operating activities		12,134	2,830
Changes in cash included in current assets held for sale		(12,904)	(2,830)
Net change in cash and cash equivalents of discontinued operations		(770)
Effect of exchange rate changes on cash and cash equivalents		(5,797)	7,268
Net increase in cash and cash equivalents		124,410	469,910
Cash and cash equivalents at beginning of period		872,797	283,183
Cash and cash equivalents at end of period		$ 997,207	$ 753,093

[1] 2016 balance includes payments for deepwater rig contract exit of $266.6 million.

[2] Includes costs of $206.7 million associated with acquisition of Kaybob Duvernay and Placid Montney.

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

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CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) - USD ($) $ in Millions	3 Months Ended	9 Months Ended		12 Months Ended
	Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Payments for deepwater rig exit costs			$ 266.6
Cost of acquired assets, cash paid	$ 206.7
Minimum [Member]
Maturity of Canadian government securities		90 days	90 days	90 days

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Cumulative Preferred Stock [Member]	Common Stock [Member]	Capital In Excess Of Par Value [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Treasury Stock [Member]	Total
Balance at beginning of year at Dec. 31, 2015		$ 195,056	$ 910,074	$ 6,212,201	$ (704,542)	$ (1,306,061)
Foreign currency translation gain, net of income taxes					124,522		$ 124,522
Net loss for the period				(212,048)			(212,048)
Restricted stock transactions and other			(10,078)
Cash dividends				(163,586)
Retirement and postretirement benefit plans, net of income taxes					7,544		7,544
Sale of stock under employee stock purchase plan						389
Stock-based compensation			21,918
Other			(239)
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes					1,445		1,445
Awarded restricted stock, net of forfeitures						8,993
Balance at end of year at Sep. 30, 2016		195,056	921,675	5,836,567	(571,031)	(1,296,679)	5,085,588
Balance at beginning of year at Dec. 31, 2016		195,056	916,799	5,729,596	(628,212)	(1,296,560)	4,916,679
Foreign currency translation gain, net of income taxes					194,094		194,094
Net loss for the period				(25,000)			(25,000)
Restricted stock transactions and other			(26,553)
Cash dividends				(129,421)
Retirement and postretirement benefit plans, net of income taxes					7,169		7,169
Sale of stock under employee stock purchase plan						145
Stock-based compensation			20,767
Other			(77)
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes					1,445		1,445
Awarded restricted stock, net of forfeitures						20,886
Balance at end of year at Sep. 30, 2017		$ 195,056	$ 910,936	$ 5,575,175	$ (425,504)	$ (1,275,529)	$ 4,980,134

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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	Sep. 30, 2017	Sep. 30, 2016
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY [Abstract]
Cumulative Preferred Stock, par value (per share)	$ 100	$ 100
Cumulative Preferred Stock, authorized shares	400,000	400,000
Cumulative Preferred Stock, shares issued	0	0
Common Stock, par value (per share)	$ 1.00	$ 1.00
Common Stock, authorized shares	450,000,000	450,000,000
Common Stock, shares issued	195,055,724	195,055,724
Treasury stock, shares	22,482,851	22,855,649

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Nature of Business and Interim Financial Statements

9 Months Ended

Sep. 30, 2017

Nature of Business and Interim Financial Statements [Abstract]

Nature of Business and Interim Financial Statements

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.

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, 2017 and December 31, 2016, and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2017 and 2016, 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 2016 Form 10-K report, as certain notes and other pertinent information have been abbreviated or omitted in this report.  Financial results for the three-month and nine-month periods ended September 30, 2017 are not necessarily indicative of future results.

Beginning in the period ended September 30, 2017, certain reclassifications in presentation have been made to the Consolidated Statements of Operations.  The Company now presents a separate “Operating income (loss) from continuing operations” subtotal on the Consolidated Statements of Operations.  Additionally, “Interest and other income (loss),” which includes foreign exchange gains and losses, has been reclassified from a component of total revenues and is now presented below Operating income (loss) from continuing operations. “Interest expense” and “Capitalized interest” have also been combined into the “Interest expense, net” line item and is now presented below Operating income (loss) from continuing operations.  Previously reported periods have been changed to conform to the current period presentation.  These reclassifications did not impact previously reported Income (loss) from continuing operations before income taxes, Loss from continuing operations, or Net Loss.

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Property, Plant and Equipment

9 Months Ended

Sep. 30, 2017

Property, Plant And Equipment [Abstract]

Property, Plant and Equipment

Note B – Property, Plant and Equipment

Exploratory Wells

Under Financial Accounting Standards Board (FASB) guidance 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, 2017, the Company had total capitalized exploratory well costs pending the determination of proved reserves of $178.4 million.  The following table reflects the net changes in capitalized exploratory well costs during the nine-month periods ended September 30, 2017 and 2016.

(Thousands of dollars)	2017		2016
Beginning balance at January 1	$	148,500	130,514
Additions pending the determination of proved reserves		51,614	847
Reclassifications to proved properties based on the determination of proved reserves		(13,370)	–
Capitalized exploratory well costs charged to expense		(8,360)	–
Other adjustments		–	(3,205)
Balance at September 30	$	178,384	128,156

The capitalized well costs charged to expense during the first nine months of 2017 included the Marakas-01 well in Block SK314A, offshore Malaysia in which development of the well could not be justified due to noncommercial hydrocarbon quantities found and change in development plan due to commodity prices.

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,
	2017				2016
(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	$	41,609	3	2	$	10,563	2	2
One to two years		8,430	2	2		53,101	3	3
Two to three years		43,197	1	1		31,627	2	–
Three years or more		85,148	7	1		32,865	4	–
	$	178,384	13	6	$	128,156	11	5

Of the $136.8 million of exploratory well costs capitalized more than one year at September 30, 2017, $70.4 million is in Brunei, $43.2 million is in Vietnam and $23.2 million is in Malaysia.  In all geographical areas, either further appraisal or development drilling is planned and/or development studies/plans are in various stages of completion. 

Divestments

In January 2017, a Canadian subsidiary of the Company completed its disposition of the Seal field in Western Canada.  Total cash consideration to Murphy upon closing of the transaction was approximately $49.0 million.  Additionally, the buyer assumed the asset retirement obligation of approximately $85.9 million.  A $132.4 million pretax gain was reported in the first quarter of 2017 related to the sale.  Also, in 2017, a U.S. subsidiary of the Company completed its disposition of certain non-core properties in the Eagle Ford Shale area.  Total cash consideration to Murphy upon closing of the transaction was approximately $19.4 million.  There wereno gains or losses recorded related to these sales.  

During the second quarter 2016, a Canadian subsidiary of the Company completed the sale of its five percent, non-operated working interest in Syncrude Canada Ltd. (“Syncrude”) asset to Suncor Energy Inc. (“Suncor”).  The Company received net cash proceeds of $739.1 million and recorded an after-tax gain of $71.7 million in the nine-month period ended September 30, 2016 associated with the Syncrude divestiture.

During the second quarter 2016, a Canadian subsidiary of the Company completed a divestiture of natural gas processing and sales pipeline assets that support Murphy’s Montney natural gas fields in the Tupper area of northeastern British Columbia.  A gain on sale of approximately $187.0 million was deferred and is being recognized over the next 19 years in the Canadian operating segment.  The Company amortized approximately $5.3million and $3.4 million of the deferred gain during the nine-month periods ended September 30, 2017 and 2016, respectively.  The remaining deferred gain of $185.0 million was included as a component of deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of September 30, 2017.

Acquisitions

During the second quarter 2016, a Canadian subsidiary acquired a 70 percent operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30 percent non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved.  Under the terms of the joint venture, the total consideration amounts to approximately $375.0 million of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, and an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property.  As of September 30, 2017, $32.0 million of the carried interest had been paid.  The carry is to be paid over a period of up to five years from 2016.

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

Impairments

Declines in future oil and gas prices in early 2016 led to impairments in certain of the Company’s producing properties and the nine-month period in 2016 included pretax non-cash impairment charges of $95.1 million to reduce the carrying values to their estimated fair values for the Terra Nova field offshore Canada and the Western Canada onshore heavy oil producing properties at Seal.  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. See also Note J.

Other

The Company has an interest in the Kakap field in Block K Malaysia.  The Kakap field is operated by another company and was jointly developed with the Gumusut field owned by others.  As required by the agreements governing the field, a redetermination (unitization) review was required in 2016.  In the fourth quarter 2016, the Company recorded $39.1 million in redetermination expense related to an expected reduction in the Company’s working interest covering the period from inception through year-end 2016 at Kakap.  In February 2017, PETRONAS officially approved the redetermination that reduced the Company’s working interest from 8.6% to approximately 6.7% effective April 1, 2017.  The Company partially settled $21.8 million of the redetermination expense in cash in the second quarter of 2017.  The Company currently expects to settle the remainder of the redetermination costs in future periods.  It is possible that the final adjustment amount could be different than the current estimate.  Due to the change in working interest, the future payments under a capital lease of a floating, production and storage facility in the Kakap field are lower and the Company reduced the total debt recorded on the Consolidated Balance Sheet in the second quarter 2017 by approximately $56.7 million, with a similar reduction to Property, plant and equipment.

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Discontinued Operations and Assets Held for Sale

9 Months Ended

Sep. 30, 2017

Discontinued Operations and Assets Held for Sale [Abstract]

Discontinued Operations and Assets Held for Sale

Note C – Discontinued Operations and Assets Held for Sale

The Company has accounted for its former U.K. and U.S. refining and marketing operations as discontinued operations for all periods presented.  The results of operations associated with discontinued operations for the three-month and nine-month periods ended September 30, 2017 and 2016 were as follows:

	Three Months			Nine Months
	Ended September 30,			Ended September 30,
(Thousands of dollars)		2017	2016	2017	2016
Revenues (costs)	$	598	5	853	1,454
Income (loss) before income taxes		425	(1,593)	1,177	(885)
Income tax benefit		–	–	–	–
Income (loss) from discontinued operations	$	425	(1,593)	1,177	(885)

Certain reclassifications have been made to 2016 Revenues to align with current period presentation (see Note A).

The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations and Seal operations in Canada reflected as held for sale on the company’s Consolidated Balance Sheets at September 30, 2017 and December 31, 2016.

		September 30,	December 31,
(Thousands of dollars)		2017	2016
Current assets
Cash	$	17,030	4,126
Accounts receivable		6,218	22,944
Total current assets held for sale	$	23,248	27,070
Current liabilities
Accounts payable	$	605	270
Refinery decommissioning cost		2,665	2,506
Total current liabilities associated with assets held for sale	$	3,270	2,776
Non-current liabilities
Asset retirement obligation - Seal asset	$	–	85,900

Note C – Discontinued Operations and Assets Held for Sale (Contd.)

The asset retirement obligation at December 31, 2016 relates to well and facility abandonment obligations at the Seal field in Canada which were assumed by the purchasing company upon the sale in January 2017. 

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Financing Arrangements and Debt

9 Months Ended

Sep. 30, 2017

Financing Arrangements and Debt [Abstract]

Financing Arrangements and Debt

Note D – Financing Arrangements and Debt

At September 30, 2017, the Company has a $1.1 billion senior unsecured guaranteed credit facility (2016 facility) with a major banking consortium, which expires in August 2019.  At September 30, 2017, the Company had no outstanding borrowings under the 2016 facility, however, there were $84.8 million of outstanding letters of credit, which reduce the borrowing capacity of the 2016 facility.  Advances under the 2016 facility will accrue interest based, at the Company’s option, on either the London Interbank Offered rate plus an applicable margin (Eurodollar rate) or the alternate base rate (as defined in the 2016 facility agreement) plus an applicable margin.  Had there been any amounts borrowed under the 2016 facility at September 30, 2017, the applicable base interest rate would have been 4.50%.  At September 30, 2017, the Company was in compliance with all covenants related to the 2016 facility.

The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2018.

In August 2017, the Company sold $550 million of new notes that bear interest at the rate of 5.75% and mature on August 15, 2025.  The Company incurred transaction costs of $8.2 million on the issue of these new notes.  The new notes pay interest semi-annually on February 15 and August 15 of each year.  The initial interest payment will be paid on February 15, 2018.  The proceeds of the $550 million notes were used to redeem the Company’s 2.50%notes in September 2017. The 2.50% notes had an original maturity of December 2017.

In August 2016, the Company reduced its then existing $2.0 billion unsecured revolving credit facility (2011 facility) to $630 million (facility has since expired) and entered into a separate $1.2 billion senior unsecured guaranteed credit facility (2016 facility, subsequently reduced to $1.1 billion),  with a major banking consortium that expires in August 2019.  The Company incurred transaction costs of approximately $14.0 million to place the 2016 facility which were included in financing activities in the Consolidated Statement of Cash Flows.  Also in August 2016, the Company sold $550 million of notes that bear interest at the rate of 6.875% and mature on August 15, 2024.  The proceeds of the $550 million notes were used for general corporate purposes.

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 March 2029.  Current maturities of long-term debt and long-term debt on the Consolidated Balance Sheet included  $9.8 million and $136.5 million, respectively, associated with this lease at September 30, 2017.

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Other Financial Information

9 Months Ended

Sep. 30, 2017

Other Financial Information [Abstract]

Other Financial Information

Note E – Other Financial Information

Additional disclosures regarding cash flow activities are provided below.

	Nine Months Ended September 30,
(Thousands of dollars)	2017		2016
Net (increase) decrease in operating working capital other than    cash and cash equivalents:
Decrease in accounts receivable	$	90,614	75,841
Decrease (increase) in inventories		5,869	(15,768)
Decrease in prepaid expenses		25,285	122,399
Decrease in other		–	720
Decrease in accounts payable and accrued liabilities		(115,977)	(376,310)	*
(Decrease) increase in current income tax liabilities		(4,721)	40,500
Net (increase) decrease in noncash operating working capital	$	1,070	(152,618)
Supplementary disclosures:
Cash income taxes paid, net of refunds	$	25,118	(3,911)
Interest paid, net of amounts capitalized of $3,338 in 2017   and $3,318 in 2016		95,899	52,287
Non-cash investing activities:
Asset retirement costs capitalized	$	38,992	13,959
Decrease in capital expenditure accrual		42,403	179,203

*2016 balance included payments for deepwater rig contract exit of $266.6 million.

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Employee and Retiree Benefit Plans

9 Months Ended

Sep. 30, 2017

Employee and Retiree Benefit Plans [Abstract]

Employee and Retiree Benefit Plans

Note F – Employee and Retiree Benefit Plans

The Company has defined benefit pension plans that are principally noncontributory and cover most North American full-time employees.  All pension plans are funded except for the U.S. nonqualified supplemental 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.  The health care benefits are contributory; the life insurance benefits are noncontributory.

The table that follows provides the components of net periodic benefit expense for the three-month and nine-month periods ended September 30, 2017 and 2016.

	Three Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2017	2016	2017		2016
Service cost	$	2,037	2,610		427		674
Interest cost		7,261	5,913		966		1,109
Expected return on plan assets		(8,070)	(6,626)		–		–
Amortization of prior service cost (credit)		259	323		(18)		(21)
Amortization of transitional asset		–	–		–		2
Recognized actuarial loss		3,610	3,617		–		38
Net periodic benefit expense	$	5,097	5,837		1,375		1,802
	Nine Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2017	2016	2017		2016
Service cost	$	6,099	8,533		1,276		2,022
Interest cost		20,267	20,386		2,899		3,324
Expected return on plan assets		(21,730)	(21,709)		–		–
Amortization of prior service cost (credit)		767	963		(55)		(62)
Amortization of transitional asset		–	–		–		4
Recognized actuarial loss		10,673	10,864		–		113
Curtailments		–	822		–		(19)
Net periodic benefit expense	$	16,076	19,859		4,120		5,382

Curtailment expense for the nine months ended September 30, 2016, shown in the table above, relates to restructuring activities in the U.S. undertaken by the Company in the first quarter of 2016.

During the nine-month period ended September 30, 2017, the Company made contributions of $24.0 million to its defined benefit pension and postretirement benefit plans.  Remaining required funding in 2017 for the Company’s defined benefit pension and postretirement plans is anticipated to be $6.8million. 

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Incentive Plans

9 Months Ended

Sep. 30, 2017

Incentive Plans [Abstract]

Incentive Plans

Note G – Incentive Plans

The costs resulting from all share-based and cash-based incentive plans payment transactions are recognized as an expense in the Consolidated Statements of Operations 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 certain other 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 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; allowed shares not granted in an earlier year may be granted in future years.  The Company also has a 2013 Stock Plan for Non-Employee Directors (Director Plan) that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.

The Company had an Employee Stock Purchase Plan (ESPP) that permitted the issuance of Company shares during 2016 and the first six months of 2017.  The ESPP terminated on June 30, 2017 and was not renewed by the Company.

In February 2017, the Committee granted stock options for 599,000 shares at an exercise price of $28.505 per share.  The Black-Scholes valuation for these awards was $7.96 per option.  The Committee also granted 556,000 performance-based

RSU and 282,000 time-based RSU in February 2017.  The fair value of the performance-based RSU, using a Monte Carlo valuation model, ranged from $24.10 to $28.28 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 $28.505 per share.  Additionally, the Committee granted 329,400 SAR and 154,150 units of cash-settled RSU (RSUC) to certain employees.  The SAR and RSUC 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 RSUC was equivalent to equity-settled restricted stock units granted.  Also in February, the Committee granted 83,220 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 was $28.84 per unit on date of grant.

For all periods presented, the Company had no stock options exercised.

Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:

	Nine Months Ended
	September 30,
(Thousands of dollars)		2017	2016
Compensation charged against income (loss) before tax benefit	$	28,264	35,948
Related income tax benefit recognized in income		8,695	11,796

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Earnings per Share

9 Months Ended

Sep. 30, 2017

Earnings per Share [Abstract]

Earnings per Share

Note H – Earnings per Share

Net 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, 2017 and 2016.  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)	2017	2016	2017	2016
Basic method	172,572,873	172,199,350	172,509,418	172,164,683
Dilutive stock options and restricted stock units*	–	–	–	–
Diluted method	172,572,873	172,199,350	172,509,418	172,164,683

     *Due to net losses recognized by the Company for all periods presented, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive.

	Three Months Ended				Nine Months Ended
		September 30,			September 30,
		2017	2016		2017		2016
Antidilutive stock options excluded from diluted shares		5,257,718		5,884,201		5,578,495		5,822,036
Weighted average price of these options	$	46.46	$	49.00	$	46.86	$	49.82

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Income Taxes

9 Months Ended

Sep. 30, 2017

Income Taxes [Abstract]

Income Taxes

Note I – Income Taxes

The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income (loss) before income tax expense.  For the three-month and nine-month periods ended September 30, 2017 and 2016, the Company’s effective income tax rates were as follows:

	2017	2016
Three months ended September 30	(4.3%)	13.0%
Nine months ended September 30	137.7%	48.9%

The effective tax rates for most periods where earnings are generated, 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.  Conversely, the effective tax rates for most periods where losses are incurred generally are lower than U.S. statutory tax rate of 35% due to similar reasons. 

The effective tax rate for the three-month period ended September 30, 2017 was below the U.S. statutory tax rate of 35% primarily due to the tax effect of expenses in foreign jurisdictions not fully deductible from losses at the U.S. statutory tax rate, an estimated U.S. tax charge for undistributed foreign earnings and Canadian foreign exchange losses not fully deductible at 35%.  These impacts were partially offset by the U.S. tax benefit recognized from the reversal of an uncertain tax position for federal tax years 2011-2013.

The effective tax rate for the nine-month period ended September 30, 2017 was above the U.S. statutory tax rate of 35% primarily due to an estimated U.S. tax charge for undistributed foreign earnings and Canadian foreign exchange losses.  These impacts were partially offset by the U.S. tax benefit recognized from the reversal of an uncertain tax position for federal tax years 2011-2013 and other items.  During the first nine-months of 2017, the Company determined that prospective earnings from its Malaysian and Canadian subsidiaries will not be considered reinvested into local operations.  Due to this change in assertion, the Company recorded a deferred tax charge of $65.2 million in the nine-month period 2017 associated with the estimated tax consequence of the future repatriation of these subsidiaries earnings during the first nine months 2017.  This decision provides greater financial flexibility as it considers future domestic investment opportunities.  The Company expects to incur further tax charges in the fourth quarter 2017 for additional 2017 foreign earnings as they arise. 

Note I – Income Taxes (Contd.)

The effective tax rate for the three-month period ended September 30, 2016 was less than the U.S. statutory tax rate primarily due to expenses in foreign jurisdictions for which no tax benefits were recognized.  The effective tax rate for the nine-month period ended September 30, 2016 was above the U.S. statutory tax rate primarily due to deferred tax benefits recognized related to the Canadian asset dispositions and income tax benefits on investments in foreign areas. 

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, 2017, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows:United States – 2014; Canada – 2012; Malaysia – 2010; and United Kingdom – 2015.

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Financial Instruments and Risk Management

9 Months Ended

Sep. 30, 2017

Financial Instruments and Risk Management [Abstract]

Financial Instruments and Risk Management

Note J – 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 gain or loss associated with recording the fair value of these contracts was deferred in Accumulated Other Comprehensive Loss until the anticipated transactions occur.  This deferred cost is being reclassified to Interest expense, net in the Consolidated Statements of Operations over the period until the associated notes mature in 2022.

Commodity Purchase Price Risks

The Company is subject to commodity price risk related to crude oil it produces and sells.  During the first nine months 2017 and 2016, the Company had West Texas Intermediate (WTI) crude oil swap financial contracts to economically hedge a portion of its United States production.  Under these contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract prices.  At September 30, 2017, the Company had 22,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during the remainder of 2017 at an average price of $50.41 and 6,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2018 at an average price of $51.83.  At September 30, 2017, the fair value of WTI contracts of $3.2 million was included in Accounts Payable.  The impact of marking to market these commodity derivative contracts increased the loss before income taxes by $3.2 million for the nine-month period ended September 30, 2017.

At September 30, 2016, the Company had 25,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2016.  At September 30, 2016, the fair value of WTI contracts of $0.2 million was included in Accounts Receivable.  The impact of marking to market these 2016 commodity derivative contracts decreased the loss before income taxes by $3.9 million for the nine-month period ended September 30, 2016.

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

Foreign Currency Exchange Risks

The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. The Company had no foreign currency exchange short-term derivatives outstanding at September 30, 2017.

At September 30, 2016, short-term derivative instruments were outstanding in Canada for approximately $25.2 million, to manage the currency risks of certain U.S. dollar accounts receivable associated with sale of Canadian crude oil.  The fair values of open foreign currency derivative contracts were assets of $0.1 million at September 30, 2016.

At September 30, 2017 and December 31, 2016, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

	September 30, 2017			December 31, 2016
(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 payable	$	(3,226)	Accounts payable	$	(48,864)
Foreign exchange	Accounts receivable		–	Accounts payable		(73)

For the three-month and nine-month periods ended September 30, 2017 and 2016, 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		2017	2016	2017	2016
Commodity	Sales and other operating revenues	$	(13,573)	11,871	50,365	(22,678)
Foreign exchange	Interest and other income (loss)		–	143	73	26,929
		$	(13,573)	12,014	50,438	4,251

Interest Rate Risks

Under hedge accounting rules, the Company deferred the net cost associated with derivative contracts purchased to manage interest rate risk associated with 10-year notes sold in May 2012 to match the payment of interest on these notes through 2022.  During each of the nine-month periods ended September 30, 2017 and 2016, $2.2 million of the deferred loss on the interest rate swaps was charged to Interest expense in the Consolidated Statement of Operations.  The remaining loss deferred on these matured contracts at September 30, 2017 was $8.9 million, which is recorded, net of income taxes of $4.8 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet.  The Company expects to charge approximately $0.7 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remaining three months of 2017.

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

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, 2017 and December 31, 2016 are presented in the following table.

	September 30, 2017					December 31, 2016
(Thousands of dollars)	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Liabilities:
Nonqualified employee         savings plans	$	15,161	–	–	15,161	13,904	–	–	13,904
Commodity derivative contracts		–	3,226	–	3,226	–	48,864	–	48,864
Foreign currency exchange         derivative contracts		–	–	–	–	–	73	–	73
	$	15,161	3,226	–	18,387	13,904	48,937	–	62,841

The fair value of WTI crude oil derivative contracts in 2017 and 2016 was based on active market quotes for WTI crude oil.  The fair value of foreign exchange derivative contracts in each year 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, while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and other income.  The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds.  The fair value of this liability was based on quoted prices for these equity securities and mutual funds.  The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and general expenses in the Consolidated Statements of 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, 2017 and December 31, 2016.

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

Fair Values – Nonrecurring

As a result of the fall in forward commodity prices during the first nine-month period ended September 30, 2016, the Company recognized approximately $95.1 million in pretax non-cash impairment charges related to producing properties.  The fair value information associated with these impaired properties is presented in the following table.

	Nine-months ended September 30, 2016
						Total
					Net Book	Pretax
					Value	(Noncash)
	Fair Value				Prior to	Impairment
		Level 1	Level 2	Level 3	Impairment	Expense
(Thousands of dollars)
Assets:
Impaired proved properties
Canada	$	–	–	71,967	167,055	95,088

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.

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Accumulated Other Comprehensive Loss

9 Months Ended

Sep. 30, 2017

Accumulated Other Comprehensive Loss [Abstract]

Accumulated Other Comprehensive Loss

Note K – Accumulated Other Comprehensive Loss

The components of Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets at December 31, 2016 and September 30, 2017 and the changes during the nine-month period ended September 30, 2017 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)	Adjustments		Hedges		Total
Balance at December 31, 2016	$	(446,555)	(171,305)		(10,352)		(628,212)
2017 components of other comprehensive income (loss):
Before reclassifications to income		194,094	3		–		194,097
Reclassifications to income		–	7,166	1	1,445	2	8,611
Net other comprehensive income		194,094	7,169		1,445		202,708
Balance at September 30, 2017	$	(252,461)	(164,136)		(8,907)		(425,504)

1Reclassifications before taxes of $11,039 for the nine-month period ended September 30, 2017 are included in the computation of net periodic benefit expense.  See Note G for additional information.  Related income taxes of $3,873 for the nine-month period ended September 30, 2017 are included in Income tax expense.

2Reclassifications before taxes of $2,222 for the nine-month period ended September 30, 2017 are included in Interest expense, net.  Related income taxes of $777 for the nine-month period ended September 30, 2017 are included in Income tax expense.

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Environmental and Other Contingencies

9 Months Ended

Sep. 30, 2017

Environmental and Other Contingencies [Abstract]

Environmental and Other Contingencies

Note L – 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, tax rate changes and retroactive tax claims; royalty and revenue sharing changes; 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.  Governmental actions are often motivated by political considerations, 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.

Note L – Environmental and Other Contingencies (Contd.)

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

The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by priorowners 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 has not retained any environmental exposure associated with Murphy’s former U.S. marketing operations.  The Company believes costs related to these sites will not have a material adverse effect on Murphy’s net income, financial condition or liquidity in a future period.

During 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 were notified.  Based on the assessments done, the Company recorded $43.9 million in Other expense during 2015 associated with the estimated costs of remediating the site.  As of September 30, 2017, the Company has a remaining accrued liability of $5.8 million associated with this event.  During the first nine months of 2017, the Company’s Canadian subsidiary paid approximately $130 thousand as the complete and final resolution of administrative penalties assessed by the Alberta Energy Regulator regarding this matter.  Further refinements in the estimated total cost to remediate the site are anticipated in future periods including possible 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 liability recorded.  The Company retained the responsibility for this remediation upon sale of the Seal field in the first quarter of 2017.

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 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.

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Commitments

9 Months Ended

Sep. 30, 2017

Commitments [Abstract]

Commitments

Note M – Commitments

The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2017 to 2020 natural gas sales volumes in Western Canada.  During the period from October to December 2017 the natural gas sales contracts call for deliveries of 124 million cubic feet per day at Cdn $2.97 per MCF.  During the period from January 2018 through December 2020 the natural gas sales contracts call for deliveries of 59 million cubic feet per day at Cdn $2.81 per MCF.  During the period from November 2017 through March 2018 the natural gas sales contracts call for deliveries of 20 million cubic feet per day at US $3.51 per MCF.

These natural gas contracts have been accounted for as normal sales for accounting purposes.

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Business Segments

9 Months Ended

Sep. 30, 2017

Business Segments [Abstract]

Business Segments

Note N – Business Segments

Information about business segments and geographic operations is reported in the following tables.  For geographic purposes, revenues are attributed to the country in which the sale occurs.  Corporate, including interest income, miscellaneous gains and losses (including foreign exchange gains and losses), interest expense and unallocated overhead, is shown in the tables to reconcile the business segments to consolidated totals. Certain reclassifications have been made to 2016 Corporate External Revenue to align with current period presentation (see Note A).

				Three Months Ended		Three Months Ended
	Total Assets			September 30, 2017		September 30, 2016
	at September 30,			External	Income	External	Income
(Millions of dollars)	2017			Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States	$	5,439.1		195.9	(19.9)	201.8	(27.1)
Canada		1,711.1		81.9	(3.2)	80.9	(4.8)
Malaysia		1,755.3		220.5	67.7	202.7	65.0
Other		139.9		–	(11.0)	0.2	(8.1)
Total exploration and production		9,045.4		498.3	33.6	485.6	25.0
Corporate		1,124.2		–	(99.9)	(0.1)	(39.6)
Assets/revenue/loss from continuing operations		10,169.6		498.3	(66.3)	485.5	(14.6)
Discontinued operations, net of tax		23.2		–	0.4	–	(1.6)
Total	$	10,192.8		498.3	(65.9)	485.5	(16.2)
				Nine Months Ended		Nine Months Ended
				September 30, 2017		September 30, 2016
				External	Income	External	Income
(Millions of dollars)				Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States			$	696.7	11.0	520.2	(158.5)
Canada				388.1	102.6	264.4	(36.9)
Malaysia				594.4	173.9	541.4	135.1
Other				–	(10.9)	0.2	(39.2)
Total exploration and production				1,679.2	276.6	1,326.2	(99.5)
Corporate				4.0	(302.8)	3.5	(111.7)
Revenue/loss from continuing operations				1,683.2	(26.2)	1,329.7	(211.2)
Discontinued operations, net of tax				–	1.2	–	(0.8)
Total			$	1,683.2	(25.0)	1,329.7	(212.0)

*Additional details about results of oil and gas operations are presented in the tables on pages 29 and 30.

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New Accounting Principles Adopted

9 Months Ended

Sep. 30, 2017

New Accounting Principles Adopted and Recent Accounting Pronouncements [Abstract]

New Accounting Principles

Note O – New Accounting Principles Adopted

Business Combinations

In January 2017, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) to clarify the definition of a business to assist entities in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses.  The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs.  The update is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The prospective approachis required for adoption and early adoption is permitted for transactions not previously reported in issued financial statements.  The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures.

Note O – New Accounting Principles Adopted(Contd.)

Compensation – Stock Compensation

In March 2016, the FASB issued an ASU intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification within the statement of cash flows.  The amendments in this ASU were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods.  The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures as there were no exercises of Company options during the period.

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Recent Accounting Pronouncements

9 Months Ended

Sep. 30, 2017

New Accounting Principles Adopted and Recent Accounting Pronouncements [Abstract]

Recent Accounting Pronouncements

Note P – Recent Accounting Pronouncements

Compensation – Stock Compensation

In May 2017, FASB issued an ASU which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting.  The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period.  Early adoption is permitted.  The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.

Compensation – Retirement Benefits

In March 2017, the FASB issued an ASU requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component and outside a subtotal of income from operations, if presented.  The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization.  The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period.  Application is retrospective for the presentation of the components of these benefit costs and prospective for the capitalization of only service costs.  Early adoption is permitted.  The Company does not believe the application of this accounting standard will have a material impact on its consolidated financial statements.

Revenue from Contracts with Customers

In May 2014, the FASB issued an ASU to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance.  The codification was amended through additional ASU’s and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services.  Additional disclosures will be required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers.  The Company is required to adopt the new standard in the first quarter of 2018 using either the modified retrospective or cumulative effect transition method.  The Company has performed a review of contracts in each of its revenue streams and is developing accounting policies and applicable disclosures to address the provisions of the ASU.  While the Company does not currently expect net earnings to be materially impacted, the Company is analyzing whether total revenues and expenses will be significantly impacted.  The Company continues to evaluate the impact of this and other provisions of these ASU’s on its accounting policies, internal controls, and consolidated financial statements and related disclosures, and has not finalized any estimates of the potential impacts.  The Company will adopt the new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to retained earnings as necessary.

Leases

In February 2016, FASB issued an ASU to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements.  The main difference between previous Generally Accepted Accounting Principles (GAAP) and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP.  The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods.  Early adoption is permitted for all entities.  The Company anticipates adopting this guidance in the first quarter of 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements.

Note P – Recent Accounting Pronouncements  (Contd.)

Statement of Cash Flows

In August 2016, the FASB issued an ASU to reduce diversity in practice in how certain transactions are classified in the statement of cash flows.  The amendment provides guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees.  The ASU is effective for annual and interim periods beginning after December 15, 2017.  The Company is currently assessing the potential impact of this ASU on its consolidated financial statements.

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Nature of Business and Interim Financial Statements (Policies)

9 Months Ended

Sep. 30, 2017

Nature of Business and Interim Financial Statements [Abstract]

Nature of Business

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.

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Property, Plant and Equipment (Tables)

9 Months Ended

Sep. 30, 2017

Property, Plant And Equipment [Abstract]

Net Changes in Capitalized Exploratory Well Costs

(Thousands of dollars)	2017		2016
Beginning balance at January 1	$	148,500	130,514
Additions pending the determination of proved reserves		51,614	847
Reclassifications to proved properties based on the determination of proved reserves		(13,370)	–
Capitalized exploratory well costs charged to expense		(8,360)	–
Other adjustments		–	(3,205)
Balance at September 30	$	178,384	128,156

Aging of Capitalized Exploratory Well Costs

		September 30,
	2017				2016
(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	$	41,609	3	2	$	10,563	2	2
One to two years		8,430	2	2		53,101	3	3
Two to three years		43,197	1	1		31,627	2	–
Three years or more		85,148	7	1		32,865	4	–
	$	178,384	13	6	$	128,156	11	5

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Discontinued Operations and Assets Held for Sale (Tables)

9 Months Ended

Sep. 30, 2017

Discontinued Operations and Assets Held for Sale [Abstract]

Results of Operations Associated with Discontinued Operations

	Three Months			Nine Months
	Ended September 30,			Ended September 30,
(Thousands of dollars)		2017	2016	2017	2016
Revenues (costs)	$	598	5	853	1,454
Income (loss) before income taxes		425	(1,593)	1,177	(885)
Income tax benefit		–	–	–	–
Income (loss) from discontinued operations	$	425	(1,593)	1,177	(885)

Major Categories of Assets and Liabilities Reflected as Held for Sale

		September 30,	December 31,
(Thousands of dollars)		2017	2016
Current assets
Cash	$	17,030	4,126
Accounts receivable		6,218	22,944
Total current assets held for sale	$	23,248	27,070
Current liabilities
Accounts payable	$	605	270
Refinery decommissioning cost		2,665	2,506
Total current liabilities associated with assets held for sale	$	3,270	2,776
Non-current liabilities
Asset retirement obligation - Seal asset	$	–	85,900

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Other Financial Information (Tables)

9 Months Ended

Sep. 30, 2017

Other Financial Information [Abstract]

Noncash Operating Working Capital (Increase) Decrease

	Nine Months Ended September 30,
(Thousands of dollars)	2017		2016
Net (increase) decrease in operating working capital other than    cash and cash equivalents:
Decrease in accounts receivable	$	90,614	75,841
Decrease (increase) in inventories		5,869	(15,768)
Decrease in prepaid expenses		25,285	122,399
Decrease in other		–	720
Decrease in accounts payable and accrued liabilities		(115,977)	(376,310)	*
(Decrease) increase in current income tax liabilities		(4,721)	40,500
Net (increase) decrease in noncash operating working capital	$	1,070	(152,618)
Supplementary disclosures:
Cash income taxes paid, net of refunds	$	25,118	(3,911)
Interest paid, net of amounts capitalized of $3,338 in 2017   and $3,318 in 2016		95,899	52,287
Non-cash investing activities:
Asset retirement costs capitalized	$	38,992	13,959
Decrease in capital expenditure accrual		42,403	179,203

*2016 balance included payments for deepwater rig contract exit of $266.6 million.

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Employee and Retiree Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2017

Employee and Retiree Benefit Plans [Abstract]

Components of Net Periodic Benefit Expense

	Three Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2017	2016	2017		2016
Service cost	$	2,037	2,610		427		674
Interest cost		7,261	5,913		966		1,109
Expected return on plan assets		(8,070)	(6,626)		–		–
Amortization of prior service cost (credit)		259	323		(18)		(21)
Amortization of transitional asset		–	–		–		2
Recognized actuarial loss		3,610	3,617		–		38
Net periodic benefit expense	$	5,097	5,837		1,375		1,802
	Nine Months Ended September 30,
	Pension Benefits			Other Postretirement Benefits
(Thousands of dollars)		2017	2016	2017		2016
Service cost	$	6,099	8,533		1,276		2,022
Interest cost		20,267	20,386		2,899		3,324
Expected return on plan assets		(21,730)	(21,709)		–		–
Amortization of prior service cost (credit)		767	963		(55)		(62)
Amortization of transitional asset		–	–		–		4
Recognized actuarial loss		10,673	10,864		–		113
Curtailments		–	822		–		(19)
Net periodic benefit expense	$	16,076	19,859		4,120		5,382

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Incentive Plans (Tables)

9 Months Ended

Sep. 30, 2017

Incentive Plans [Abstract]

Share-Based Plans, Amounts Recognized

	Nine Months Ended
	September 30,
(Thousands of dollars)		2017	2016
Compensation charged against income (loss) before tax benefit	$	28,264	35,948
Related income tax benefit recognized in income		8,695	11,796

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Earnings per Share (Tables)

9 Months Ended

Sep. 30, 2017

Earnings per Share [Abstract]

Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
(Weighted-average shares)	2017	2016	2017	2016
Basic method	172,572,873	172,199,350	172,509,418	172,164,683
Dilutive stock options and restricted stock units*	–	–	–	–
Diluted method	172,572,873	172,199,350	172,509,418	172,164,683

     *Due to net losses recognized by the Company for all periods presented, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive.

Anti Dilutive Securities Not Included in Computation of Diluted EPS

	Three Months Ended				Nine Months Ended
		September 30,			September 30,
		2017	2016		2017		2016
Antidilutive stock options excluded from diluted shares		5,257,718		5,884,201		5,578,495		5,822,036
Weighted average price of these options	$	46.46	$	49.00	$	46.86	$	49.82

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Income Taxes (Tables)

9 Months Ended

Sep. 30, 2017

Income Taxes [Abstract]

Effective Income Tax Rates

	2017	2016
Three months ended September 30	(4.3%)	13.0%
Nine months ended September 30	137.7%	48.9%

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Financial Instruments and Risk Management (Tables)

9 Months Ended

Sep. 30, 2017

Financial Instruments and Risk Management [Abstract]

Fair Value of Derivative Instruments Not Designated as Hedging Instruments

	September 30, 2017			December 31, 2016
(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 payable	$	(3,226)	Accounts payable	$	(48,864)
Foreign exchange	Accounts receivable		–	Accounts payable		(73)

Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments

			Gain (Loss)
		Three Months Ended			Nine Months Ended
(Thousands of dollars)		September 30,			September 30,
Type of Derivative Contract	Statement of Operations Location		2017	2016	2017	2016
Commodity	Sales and other operating revenues	$	(13,573)	11,871	50,365	(22,678)
Foreign exchange	Interest and other income (loss)		–	143	73	26,929
		$	(13,573)	12,014	50,438	4,251

Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis

	September 30, 2017					December 31, 2016
(Thousands of dollars)	Level 1		Level 2	Level 3	Total	Level 1	Level 2	Level 3	Total
Liabilities:
Nonqualified employee         savings plans	$	15,161	–	–	15,161	13,904	–	–	13,904
Commodity derivative contracts		–	3,226	–	3,226	–	48,864	–	48,864
Foreign currency exchange         derivative contracts		–	–	–	–	–	73	–	73
	$	15,161	3,226	–	18,387	13,904	48,937	–	62,841

Nonrecurring Fair Value Measurements

	Nine-months ended September 30, 2016
						Total
					Net Book	Pretax
					Value	(Noncash)
	Fair Value				Prior to	Impairment
		Level 1	Level 2	Level 3	Impairment	Expense
(Thousands of dollars)
Assets:
Impaired proved properties
Canada	$	–	–	71,967	167,055	95,088

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Accumulated Other Comprehensive Loss (Tables)

9 Months Ended

Sep. 30, 2017

Accumulated Other Comprehensive Loss [Abstract]

Components of Accumulated Other Comprehensive Loss

					Deferred
					Loss on
		Foreign	Retirement and		Interest
		Currency	Postretirement		Rate
		Translation	Benefit Plan		Derivative
(Thousands of dollars)		Gains (Losses)	Adjustments		Hedges		Total
Balance at December 31, 2016	$	(446,555)	(171,305)		(10,352)		(628,212)
2017 components of other comprehensive income (loss):
Before reclassifications to income		194,094	3		–		194,097
Reclassifications to income		–	7,166	1	1,445	2	8,611
Net other comprehensive income		194,094	7,169		1,445		202,708
Balance at September 30, 2017	$	(252,461)	(164,136)		(8,907)		(425,504)

1Reclassifications before taxes of $11,039 for the nine-month period ended September 30, 2017 are included in the computation of net periodic benefit expense.  See Note G for additional information.  Related income taxes of $3,873 for the nine-month period ended September 30, 2017 are included in Income tax expense.

2Reclassifications before taxes of $2,222 for the nine-month period ended September 30, 2017 are included in Interest expense, net.  Related income taxes of $777 for the nine-month period ended September 30, 2017 are included in Income tax expense.

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Business Segments (Tables)

9 Months Ended

Sep. 30, 2017

Business Segments [Abstract]

Segment Information

				Three Months Ended		Three Months Ended
	Total Assets			September 30, 2017		September 30, 2016
	at September 30,			External	Income	External	Income
(Millions of dollars)	2017			Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States	$	5,439.1		195.9	(19.9)	201.8	(27.1)
Canada		1,711.1		81.9	(3.2)	80.9	(4.8)
Malaysia		1,755.3		220.5	67.7	202.7	65.0
Other		139.9		–	(11.0)	0.2	(8.1)
Total exploration and production		9,045.4		498.3	33.6	485.6	25.0
Corporate		1,124.2		–	(99.9)	(0.1)	(39.6)
Assets/revenue/loss from continuing operations		10,169.6		498.3	(66.3)	485.5	(14.6)
Discontinued operations, net of tax		23.2		–	0.4	–	(1.6)
Total	$	10,192.8		498.3	(65.9)	485.5	(16.2)
				Nine Months Ended		Nine Months Ended
				September 30, 2017		September 30, 2016
				External	Income	External	Income
(Millions of dollars)				Revenues	(Loss)	Revenues	(Loss)
Exploration and production*
United States			$	696.7	11.0	520.2	(158.5)
Canada				388.1	102.6	264.4	(36.9)
Malaysia				594.4	173.9	541.4	135.1
Other				–	(10.9)	0.2	(39.2)
Total exploration and production				1,679.2	276.6	1,326.2	(99.5)
Corporate				4.0	(302.8)	3.5	(111.7)
Revenue/loss from continuing operations				1,683.2	(26.2)	1,329.7	(211.2)
Discontinued operations, net of tax				–	1.2	–	(0.8)
Total			$	1,683.2	(25.0)	1,329.7	(212.0)

*Additional details about results of oil and gas operations are presented in the tables on pages 29 and 30.

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Property, Plant and Equipment (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended					9 Months Ended
	Jan. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Apr. 01, 2017	Dec. 31, 2015
Property Plant And Equipment [Line Items]
Total capitalized exploratory well costs		$ 178,384		$ 148,500	$ 128,156		$ 178,384	$ 128,156		$ 130,514
Exploratory well costs capitalized more than one year		136,800					136,800
Proceeds from sales of property, plant and equipment							69,146	1,154,623
Gain (loss) on sale of assets		117			$ (730)		$ 130,765	3,101
Impairment of assets								95,088
Cost of acquired assets, cash paid						$ 206,700
Athabasca Oil Corporation [Member]
Property Plant And Equipment [Line Items]
Cost of acquired assets, carried interest						$ 168,000
Cost of acquired assets, interest carry period							5 years
Western Canada [Member]
Property Plant And Equipment [Line Items]
Proceeds from sales of property, plant and equipment	$ 49,000
Asset retirement obligation settled	$ 85,900
Gain (loss) on sale of assets			$ 132,400
Syncrude [Member]
Property Plant And Equipment [Line Items]
Gain (loss) on sale of assets								71,700
Percentage of interest in oil and gas property sold during period						5.00%
Eagle Ford Shale [Member]
Property Plant And Equipment [Line Items]
Proceeds from sales of property, plant and equipment							$ 19,400
Gain (loss) on sale of assets							0
Montney Natural Gas Fields [Member]
Property Plant And Equipment [Line Items]
Deferred gain on sale of property		185,000				$ 187,000	185,000
Amortization of deferred gain on sale of property							$ 5,300	$ 3,400
Deferred gain, period of recognition							19 years
Murphy Oil Corp [Member] | Syncrude [Member]
Property Plant And Equipment [Line Items]
Proceeds from sales of property, plant and equipment						739,100
Canadian Subsidiary [Member] | Athabasca Oil Corporation [Member]
Property Plant And Equipment [Line Items]
Cost of acquired assets						$ 375,000
Brunei [Member]
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year		70,400					$ 70,400
Vietnam [Member]
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year		43,200					43,200
Malaysia [Member]
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year		23,200					23,200
Redetermination expense				$ 39,100
Reduction in capital lease obligations		56,700					$ 56,700
Kaybob Duvernay Lands, Alberta [Member]
Property Plant And Equipment [Line Items]
Redetermination expense paid		$ 21,800
Interest in assets acquired						70.00%
Working interest			8.60%						6.70%
Montney Lands, Alberta [Member]
Property Plant And Equipment [Line Items]
Interest in assets acquired						30.00%

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Property, Plant And Equipment (Net Changes in Capitalized Exploratory Well Costs) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Property, Plant And Equipment [Abstract]
Beginning balance at January 1	$ 148,500	$ 130,514
Additions pending the determination of proved reserves	51,614	847
Reclassifications to proved properties based on the determination of proved reserves	(13,370)
Capitalized exploratory well costs charged to expense	(8,360)
Other adjustments		(3,205)
Balance at September 30	$ 178,384	$ 128,156

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Property, Plant And Equipment (Aging of Capitalized Exploratory Well Costs) (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2017 USD ($) item	Sep. 30, 2016 USD ($) item	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 178,384	$ 128,156	$ 148,500	$ 130,514
No. of Wells	13	11
No. of Projects	6	5
Zero to One Year [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 41,609	$ 10,563
No. of Wells	3	2
No. of Projects	2	2
One to Two Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 8,430	$ 53,101
No. of Wells	2	3
No. of Projects	2	3
Two to Three Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 43,197	$ 31,627
No. of Wells	1	2
No. of Projects	1
Three Years or More [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 85,148	$ 32,865
No. of Wells	7	4
No. of Projects	1

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Discontinued Operations and Assets Held for Sale (Results of Operations Associated with Discontinued Operations) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Discontinued Operations and Assets Held for Sale [Abstract]
Revenues (costs)	$ 598	$ 5	$ 853	$ 1,454
Income (loss) before income taxes	425	(1,593)	1,177	(885)
Income (loss) from discontinued operations	$ 425	$ (1,593)	$ 1,177	$ (885)

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Discontinued Operations and Assets Held for Sale (Major Categories of Assets and Liabilities Reflected as Held for Sale) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable	$ 267,209	$ 357,099
Total current assets held for sale	23,248	27,070
Accounts payable	584,025	784,975
Total current liabilities associated with assets held for sale	3,270	2,776
Asset retirement obligation - Seal asset	747,602	681,528
Total non-current liabilities associated with assets held for sale		85,900
UK Refining And Marketing Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash	17,030	4,126
Accounts receivable	6,218	22,944
Total current assets held for sale	23,248	27,070
Accounts payable	605	270
Refinery decommissioning cost	2,665	2,506
Total current liabilities associated with assets held for sale	$ 3,270	2,776
Asset retirement obligation - Seal asset		$ 85,900

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Financing Arrangements and Debt (Narrative) (Details) - USD ($)	9 Months Ended
	Sep. 30, 2017	Aug. 31, 2017	Aug. 31, 2016
Line of Credit Facility [Line Items]
Capital Lease Duration	25 years
Capital lease payment duration	15 years
Capital lease expiration date	Mar. 31, 2029
Capital lease obligations, current	$ 9,800,000
Capital lease obligations, noncurrent	$ 136,500,000
5.75% Notes, Due August 15, 2025 [Member]
Line of Credit Facility [Line Items]
Face amount of notes		$ 550,000,000
Notes payable, stated interest rate		5.75%
Maturity date	Aug. 15, 2025
Transaction costs		$ 8,200,000
2.50% Notes, Due December 2017 [Member]
Line of Credit Facility [Line Items]
Notes payable, stated interest rate		2.50%
6.875 Notes, Due August 15, 2024 [Member]
Line of Credit Facility [Line Items]
Face amount of notes			$ 550,000,000
Notes payable, stated interest rate			6.875%
Maturity date	Aug. 15, 2024
2016 Senior Unsecured Guaranteed Credity Facility [Member]
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity	$ 1,100,000,000		$ 1,200,000,000
Credit facility, expiration date	Aug. 01, 2019
Amount outstanding	$ 0
Transaction costs			14,000,000
2016 Senior Unsecured Guaranteed Credity Facility [Member] | Eurodollar [Member]
Line of Credit Facility [Line Items]
Interest rate	4.50%
2016 Senior Unsecured Guaranteed Credity Facility [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Amount outstanding	$ 84,800,000
2011 Unscured Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity	$ 630,000,000		$ 2,000,000,000

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Other Financial Information (Noncash Opearting Working Capital Increase (Decrease)) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Other Financial Information [Abstract]
Decrease in accounts receivable	$ 90,614	$ 75,841
Decrease (increase) in inventories	5,869	(15,768)
Decrease in prepaid expenses	25,285	122,399
Decrease in other		720
Decrease in accounts payable and accrued liabilities	(115,977)	(376,310)	[1]
(Decrease) increase in current income tax liabilities	(4,721)	40,500
Net (increase) decrease in noncash operating working capital	1,070	(152,618)	[1]
Cash income taxes paid, net of refunds	25,118	(3,911)
Interest paid, net of amounts capitalized of $3,338 in 2017 and $3,318 in 2016	95,899	52,287
Asset retirement costs capitalized	38,992	13,959
Decrease in capital expenditure accrual	42,403	179,203
Payments for deepwater rig exit costs		266,600
Interest paid, amounts capitalized	$ 3,338	$ 3,318

[1] 2016 balance includes payments for deepwater rig contract exit of $266.6 million.

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Employee and Retiree Benefit Plans (Narrative) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($)
Employee and Retiree Benefit Plans [Abstract]
Contributions to benefit plans	$ 24.0
Expected benefit plan contributions to be made during the year	$ 6.8

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Employee and Retiree Benefit Plans (Components of Net Periodic Benefit Expense) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 2,037	$ 2,610	$ 6,099	$ 8,533
Interest cost	7,261	5,913	20,267	20,386
Expected return on plan assets	(8,070)	(6,626)	(21,730)	(21,709)
Amortization of prior service cost (credit)	259	323	767	963
Recognized actuarial loss	3,610	3,617	10,673	10,864
Curtailments				822
Net periodic benefit expense	5,097	5,837	16,076	19,859
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	427	674	1,276	2,022
Interest cost	966	1,109	2,899	3,324
Amortization of prior service cost (credit)	(18)	(21)	(55)	(62)
Amortization of transitional asset		2		4
Recognized actuarial loss		38		113
Curtailments				(19)
Net periodic benefit expense	$ 1,375	$ 1,802	$ 4,120	$ 5,382

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Incentive Plans (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	1 Months Ended	9 Months Ended
	Feb. 28, 2017	Sep. 30, 2017	Sep. 30, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock options exercised		0	0
Related income tax benefit recognized in income		$ 8,695	$ 11,796
2012 Long-Term Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Long term plan expiration year		2022
Maximum number of shares available for issuance		8,700,000
Maximum number of shares available for issuance, annual rate		1.00%
Stock Options [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Options granted	599,000
Exercise price of options granted	$ 28.505
Granted stock options, valuation per option	$ 7.96
Stock-based compensation, fair value assumption model		Black-Scholes valuation model
Performance Based Restricted Share Awards [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	556,000
Stock-based compensation, fair value assumption model		Monte Carlo valuation model
Performance Based Restricted Share Awards [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per share at grant date	$ 24.10
Performance Based Restricted Share Awards [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per share at grant date	$ 28.28
Time Based Restricted Stock Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	282,000
Fair value per share at grant date	$ 28.505
Time Based Restricted Stock Units [Member] | Non-Employee Director Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	83,220
Vesting scheme		These shares vest on the third anniversary of the date of grant.
Time Based Restricted Stock Units [Member] | Non-Employee Director Plan [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per share at grant date	$ 28.84
SAR [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	329,400
Cash-Settled RSU (RSU-C) [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted	154,150

XML

Incentive Plans (Share-Based Plans, Amounts Recognized) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Incentive Plans [Abstract]
Compensation charged against income (loss) before tax benefit	$ 28,264	$ 35,948
Related income tax benefit recognized in income	$ 8,695	$ 11,796

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Earnings per Share (Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share) (Details) - shares		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Earnings per Share [Abstract]
Basic method		172,572,873	172,199,350	172,509,418	172,164,683
Dilutive stock options and restricted stock units	[1]	0	0	0	0
Diluted method		172,572,873	172,199,350	172,509,418	172,164,683

[1] Due to net losses recognized by the Company for all periods presented, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been anti-dilutive.

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Earnings per Share (Anti Dilutive Securities Not Included in Computation of Diluted EPS) (Details) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Earnings per Share [Abstract]
Antidilutive stock options excluded from diluted shares (in shares)	5,257,718	5,884,201	5,578,495	5,822,036
Weighted average price of these options (per share)	$ 46.46	$ 49.00	$ 46.86	$ 49.82

XML

Income Taxes (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Tax Examination [Line Items]
Deferred tax expense, undistributed foreign earnings			$ 65.2
U.S. statutory rate	35.00%	35.00%	35.00%	35.00%
United States [Member]
Income Tax Examination [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions			2014
Canada [Member]
Income Tax Examination [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions			2012
Malaysia [Member]
Income Tax Examination [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions			2010
United Kingdom [Member]
Income Tax Examination [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions			2015

XML

Income Taxes (Effective Income Tax Rates) (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Taxes [Abstract]
Effective income tax rate	(4.30%)	13.00%	137.70%	48.90%

XML

Financial Instruments and Risk Management (Narrative) (Details) bbl / d in Thousands, $ in Thousands	3 Months Ended	9 Months Ended		12 Months Ended
	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($) bbl / d contract item $ / bbl	Sep. 30, 2016 USD ($) bbl / d	Dec. 31, 2018 bbl / d $ / bbl	Dec. 31, 2016 item
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of open contracts | contract		0
Impairment of assets			$ 95,088
Amount of loss reclassified to interest expense		$ 2,200	$ 2,200
Derivative loss		$ 2,222
Number of offsetting positions | item		0			0
Scenario, Forecast [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative loss	$ 700
Commodity Derivative Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Daily production commitment (barrels per day) | bbl / d		22	25
Average price | $ / bbl		50.41
Fair value of derivative contract liability		$ 3,200
Fair value of derivative contract asset			$ 200
Increase (decrease) of income before taxes due to the impact of marking to market of derivative contracts		(3,200)	3,900
Commodity Derivative Contracts [Member] | Scenario, Forecast [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Daily production commitment (barrels per day) | bbl / d				6
Average price | $ / bbl				51.83
Foreign Exchange Derivative Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair value of foreign derivative contracts			100
Foreign Exchange Derivative Contracts [Member] | Currency, U.S. Dollar [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Short-term derivative instruments			$ 25,200
Interest Rate Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss deferred for fair value of interest rate derivative contracts, net of tax		8,900
Income taxes on deferred loss on fair value of interest rate derivative contracts		$ 4,800

XML

Financial Instruments and Risk Management (Fair Value of Derivative Instruments Not Designated as Hedging Instruments) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016	Sep. 30, 2016
Commodity Derivative Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives			$ 200
Foreign Exchange Derivative Contracts [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives			$ (100)
Nondesignated [Member] | Commodity Derivative Contracts [Member] | Accounts Payable [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ (3,226)	$ (48,864)
Nondesignated [Member] | Foreign Exchange Derivative Contracts [Member] | Accounts Payable [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives		$ (73)

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Financial Instruments and Risk Management (Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments) (Details) - Nondesignated [Member] - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ (13,573)	$ 12,014	$ 50,438	$ 4,251
Commodity Derivative Contracts [Member] | Sales And Other Operating Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ (13,573)	11,871	50,365	(22,678)
Foreign Exchange Derivative Contracts [Member] | Interest And Other Income (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)		$ 143	$ 73	$ 26,929

XML

Financial Instruments and Risk Management (Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016	Sep. 30, 2016
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	$ 18,387	$ 62,841
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	15,161	13,904
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	3,226	48,937
Non-Qualified Employee Savings Plans [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	15,161	13,904
Non-Qualified Employee Savings Plans [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	15,161	13,904
Commodity Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Asset Derivatives			$ 200
Commodity Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	3,226	48,864
Commodity Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	$ 3,226	48,864
Foreign Exchange Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives			$ 100
Foreign Exchange Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives		73
Foreign Exchange Derivative Contracts [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives		$ 73

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Financial Instruments and Risk Management (Nonrecurring Fair Value Measurements) (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2016 USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Pretax (Noncash) Impairment Expense	$ 95,088
Canada [Member] | Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Book Value Prior to Impairment	167,055
Total Pretax (Noncash) Impairment Expense	95,088
Canada [Member] | Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets: Impaired proved properties	$ 71,967

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Accumulated Other Comprehensive Loss (Components of Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance				$ (628,212)
Before reclassifications to income				194,097
Reclassifications to income				8,611
Net other comprehensive income		$ 104,088	$ (34,372)	202,708	$ 133,511
Ending Balance		(425,504)		(425,504)
Reclassifications before taxes, included in net periodic benefit expense				11,039
Reclassifications income tax, included in net periodic benefit expense				3,873
Reclassifications before taxes, included in interest expense				2,222
Reclassifications income tax, included in interest expense				777
Foreign Currency Translation Gains (Losses) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance				(446,555)
Before reclassifications to income				194,094
Net other comprehensive income				194,094
Ending Balance		(252,461)		(252,461)
Retirement and Postretirement Benefit Plan Adjustments [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance				(171,305)
Before reclassifications to income				3
Reclassifications to income	[1]			7,166
Net other comprehensive income				7,169
Ending Balance		(164,136)		(164,136)
Deferred Loss On Interest Rate Derivative Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance				(10,352)
Reclassifications to income	[2]			1,445
Net other comprehensive income				1,445
Ending Balance		$ (8,907)		$ (8,907)

[1] Reclassifications before taxes of $11,039 for the nine-month period ended September 30, 2017 are included in the computation of net periodic benefit expense. See Note G for additional information. Related income taxes of $3,873 for the nine-month period ended September 30, 2017 are included in Income tax expense.

[2] Reclassifications before taxes of $2,222 for the nine-month period ended September 30, 2017 are included in Interest expense, net. Related income taxes of $777 for the nine-month period ended September 30, 2017 are included in Income tax expense.

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Environmental and Other Contingencies (Narrative) (Details) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2015
Contingencies Disclosure [Line Items]
Remediation costs		$ 43,900,000
Remediation accrual	$ 5,800,000
Canada [Member]
Contingencies Disclosure [Line Items]
Payments for environmental liabilities	$ 130,000

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Commitments (Narrative) (Details) - Natural Gas [Member]	Sep. 30, 2017 MMcf / D MMcf / d $ / Mcf CAD / Mcf
October to December 2017 [Member]
Commitments and Contingencies Disclosure [Line Items]
Notional amount, per day | MMcf / d	124
Swap price (per share) | CAD / Mcf	2.97
January 2018 to December 2020 [Member]
Commitments and Contingencies Disclosure [Line Items]
Notional amount, per day | MMcf / D	59
Swap price (per share) | CAD / Mcf	2.81
November 2017 to March 2018 [Member]
Commitments and Contingencies Disclosure [Line Items]
Notional amount, per day | MMcf / d	20
Swap price (per share) | $ / Mcf	3.51

XML

Business Segments (Segment Information) (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Segment Reporting Information [Line Items]
Total Assets		$ 10,192,759		$ 10,192,759		$ 10,295,860
External Revenues		498,319	$ 485,546	1,683,238	$ 1,329,688
Net income (loss)		(65,893)	(16,176)	(25,000)	(212,048)
Continuing Operations [Member]
Segment Reporting Information [Line Items]
Total Assets		10,169,600		10,169,600
External Revenues		498,300	485,500	1,683,200	1,329,700
Net income (loss)		(66,300)	(14,600)	(26,200)	(211,200)
Discontinued Operations [Member]
Segment Reporting Information [Line Items]
Total Assets		23,200		23,200
Net income (loss)		400	(1,600)	1,200	(800)
Corporate [Member]
Segment Reporting Information [Line Items]
Total Assets		1,124,200		1,124,200
External Revenues			(100)	4,000	3,500
Net income (loss)		(99,900)	(39,600)	(302,800)	(111,700)
Exploration and production [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total Assets	[1]	9,045,400		9,045,400
External Revenues	[1]	498,300	485,600	1,679,200	1,326,200
Net income (loss)	[1]	33,600	25,000	276,600	(99,500)
Exploration and production [Member] | Operating Segments [Member] | United States [Member]
Segment Reporting Information [Line Items]
Total Assets	[1]	5,439,100		5,439,100
External Revenues	[1]	195,900	201,800	696,700	520,200
Net income (loss)	[1]	(19,900)	(27,100)	11,000	(158,500)
Exploration and production [Member] | Operating Segments [Member] | Canada [Member]
Segment Reporting Information [Line Items]
Total Assets	[1]	1,711,100		1,711,100
External Revenues	[1]	81,900	80,900	388,100	264,400
Net income (loss)	[1]	(3,200)	(4,800)	102,600	(36,900)
Exploration and production [Member] | Operating Segments [Member] | Malaysia [Member]
Segment Reporting Information [Line Items]
Total Assets	[1]	1,755,300		1,755,300
External Revenues	[1]	220,500	202,700	594,400	541,400
Net income (loss)	[1]	67,700	65,000	173,900	135,100
Exploration and production [Member] | Operating Segments [Member] | Other Regions [Member]
Segment Reporting Information [Line Items]
Total Assets	[1]	139,900		139,900
External Revenues	[1]		200		200
Net income (loss)	[1]	$ (11,000)	$ (8,100)	$ (10,900)	$ (39,200)

[1] Additional details about results of oil and gas operations are presented in the tables on pages 29 and 30.