Murphy Oil (MUR) 10-Q 8 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 31, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Trading Symbol	mur
Entity Registrant Name	MURPHY OIL CORP /DE
Entity Central Index Key	717,423
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		173,056,234

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 947,732	$ 964,988
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2018 and 2017	274,193	243,472
Inventories, at lower of cost or market	94,615	105,127
Prepaid expenses	43,606	35,087
Assets held for sale	21,140	22,929
Total current assets	1,381,286	1,371,603
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,916,002 in 2018 and $12,280,741 in 2017	8,244,167	8,220,031
Deferred income taxes	346,455	211,543
Deferred charges and other assets	54,712	57,765
Total assets	10,026,620	9,860,942
Current liabilities
Current maturities of long-term debt	10,454	9,902
Accounts payable	622,577	595,916
Income taxes payable	53,676	44,604
Other taxes payable	19,939	23,574
Other accrued liabilities	166,066	156,681
Liabilities associated with assets held for sale	2,802	3,530
Total current liabilities	875,514	834,207
Long-term debt, including capital lease obligation	2,903,899	2,906,520
Deferred income taxes	130,369	159,098
Asset retirement obligations	700,055	709,299
Deferred credits and other liabilities	649,855	631,627
Stockholders' equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,065,341 shares in 2018 and 195,055,724 in 2017	195,065	195,056
Capital in excess of par value	905,379	917,665
Retained earnings	5,453,414	5,245,242
Accumulated other comprehensive loss	(537,768)	(462,243)
Treasury stock	(1,249,162)	(1,275,529)
Total stockholders' equity	4,766,928	4,620,191
Total liabilities and stockholders' equity	$ 10,026,620	$ 9,860,942

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
CONSOLIDATED BALANCE SHEETS [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 1,605	$ 1,605
Property, plant and equipment, accumulated depreciation, depletion and amortization	$ 12,916,002	$ 12,280,741
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	$ 1
Common Stock, authorized shares	450,000,000	450,000,000
Common Stock, shares issued	195,065,341	195,055,724

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	3 Months Ended			9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	[1]	Sep. 30, 2018	Sep. 30, 2017	[1]
Revenues
Revenue from sales to customers	$ 659,806	$ 511,192		$ 1,921,910	$ 1,498,093
Gain (loss) on crude contracts	(2,223)	(13,573)		(69,349)	50,365
Gain on sale of assets and other income	17,214	700		26,035	134,780
Total revenues	674,797	498,319		1,878,596	1,683,238
Costs and expenses
Lease operating expenses	133,141	112,751		406,226	346,072
Severance and ad valorem taxes	15,067	10,816		40,100	32,771
Exploration expenses, including undeveloped lease amortization	21,838	28,492		69,911	77,356
Selling and general expenses	64,107	51,374		173,324	155,438
Depreciation, depletion and amortization	241,833	243,636		710,563	714,782
Accretion of asset retirement obligations	11,099	10,654		32,041	31,638
Redetermination expense	11,332			11,332
Other expense (benefit)	(34,387)	2,454		(44,776)	10,988
Total costs and expenses	464,030	460,177		1,398,721	1,369,045
Operating income from continuing operations	210,767	38,142		479,875	314,193
Other income (loss)
Interest and other income (loss)	(19,478)	(53,019)		(19,445)	(106,345)
Interest expense, net	(44,492)	(48,681)		(134,264)	(138,423)
Total other loss	(63,970)	(101,700)		(153,709)	(244,768)
Income (loss) from continuing operations before income taxes	146,797	(63,558)		326,166	69,425
Income tax expense (benefit)	51,038	2,760		15,801	95,602
Income (loss) from continuing operations	95,759	(66,318)		310,365	(26,177)
Income (loss) from discontinued operations, net of income taxes	(1,815)	425		(2,650)	1,177
NET INCOME (LOSS)	$ 93,944	$ (65,893)		$ 307,715	$ (25,000)
INCOME (LOSS) PER COMMON SHARE - BASIC
Continuing operations	$ 0.55	$ (0.38)		$ 1.79	$ (0.15)
Discontinued operations	(0.01)			(0.01)	0.01
Net Income (Loss)	0.54	(0.38)		1.78	(0.14)
INCOME (LOSS) PER COMMON SHARE - DILUTED
Continuing operations	0.55	(0.38)		1.78	(0.15)
Discontinued operations	(0.01)			(0.01)	0.01
Net Income (Loss)	0.54	(0.38)		1.77	(0.14)
Cash dividends per Common share	$ 0.25	$ 0.25		$ 0.75	$ 0.75
Average Common shares outstanding
Basic	173,047,246	172,572,873		172,949,450	172,509,418
Diluted	174,175,267	172,572,873		174,201,760	172,509,418
[1]	Reclassified to conform to current presentation (see Note B).

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended			9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017		Sep. 30, 2018	Sep. 30, 2017
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract]
Net income (loss)	$ 93,944	$ (65,893)	[1]	$ 307,715	$ (25,000)	[1]
Other comprehensive income (loss), net of tax
Net (loss) gain from foreign currency translation	33,380	101,210		(53,805)	194,094
Retirement and postretirement benefit plans	3,390	2,396		10,498	7,169
Deferred loss on interest rate hedges reclassified to interest expense	585	482		1,756	1,445
Reclassification of certain tax effects to retained earnings				(30,237)
Other				(3,737)
Other comprehensive (loss) income	37,355	104,088		(75,525)	202,708
COMPREHENSIVE INCOME	$ 131,299	$ 38,195		$ 232,190	$ 177,708
[1]	Reclassified to conform to current presentation (see Note B).

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands		3 Months Ended			9 Months Ended			12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017		Sep. 30, 2018	Sep. 30, 2017		Dec. 31, 2017	Dec. 31, 2016
Operating Activities
Net income (loss)		$ 93,944	$ (65,893)	[1]	$ 307,715	$ (25,000)	[1]
Adjustments to reconcile net income (loss) to net cash provided by continuing operations activities:
Loss (Income) from discontinued operations		1,815	(425)	[1]	2,650	(1,177)	[1]
Depreciation, depletion and amortization		241,833	243,636	[1]	710,563	714,782	[1]
Dry hole costs (credits)					4,526	(1,139)
Amortization of undeveloped leases					31,544	40,859
Accretion of asset retirement obligations		11,099	10,654	[1]	32,041	31,638	[1]
Deferred income tax benefit					(138,755)	(3,567)
Pretax gain from sale of assets		(124)	(117)		(6)	(130,765)
Net (increase) decrease in noncash operating working capital					(2,550)	1,070
Other operating activities, net					49,217	192,097
Net cash provided by continuing operations activities					996,945	818,798
Investing Activities
Property additions and dry hole costs					(858,356)	(706,417)
Proceeds from sales of property, plant and equipment					1,128	69,146
Purchases of investment securities	[2]					(212,661)
Proceeds from maturity of investment securities	[2]					320,828
Net cash required by investing activities					(857,228)	(529,104)
Financing Activities
Borrowings of debt, net of issuance costs						541,772
Repayments of debt						(550,000)
Capital lease obligation payments					(7,164)	(14,687)
Withholding tax on stock-based incentive awards					(6,922)	(7,151)
Cash dividends paid					(129,780)	(129,421)
Net cash required by financing activities					(143,866)	(159,487)
Effect of exchange rate changes on cash and cash equivalents					(13,107)	(5,797)
Net increase (decrease) in cash and cash equivalents								$ (17,256)	$ 124,410
Cash and cash equivalents at beginning of period					964,988	872,797		872,797
Cash and cash equivalents at end of period		$ 947,732	$ 997,207		$ 947,732	$ 997,207		$ 964,988	$ 872,797
[1]	Reclassified to conform to current presentation (see Note B).
[2]	Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

CONSOLIDATED STATEMENTS OF CA_2

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Minimum [Member]
Maturity of Canadian government securities	90 days	90 days

CONSOLIDATED STATEMENTS OF STOC

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, 2016		$ 195,056	$ 916,799	$ 5,729,596	$ (628,212)	$ (1,296,560)
Foreign currency translation (loss) gain, net of income taxes					194,094		$ 194,094
Net income (loss) for the period				(25,000)			(25,000)	[1]
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 period at Sep. 30, 2017		195,056	910,936	5,575,175	(425,504)	(1,275,529)	4,980,134
Balance at beginning of year at Dec. 31, 2017		195,056	917,665	5,245,242	(462,243)	(1,275,529)	4,620,191
Exercise of stock options, inlcuding income tax benefits		9	(175)
Foreign currency translation (loss) gain, net of income taxes					(53,805)		(53,805)
Net income (loss) for the period				307,715			307,715
Reclassification of certain tax effects from accumulated other comprehensive loss to retained earnings				30,237	(30,237)		(30,237)
Other					(3,737)		(3,737)
Restricted stock transactions and other			(32,766)
Cash dividends				(129,780)
Retirement and postretirement benefit plans, net of income taxes					10,498		10,498
Stock-based compensation			20,655
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes					1,756		1,756
Awarded restricted stock, net of forfeitures						26,367
Balance at end of period at Sep. 30, 2018		$ 195,065	$ 905,379	$ 5,453,414	$ (537,768)	$ (1,249,162)	$ 4,766,928
[1]	Reclassified to conform to current presentation (see Note B).

CONSOLIDATED STATEMENTS OF ST_2

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	Sep. 30, 2018	Sep. 30, 2017
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	$ 1
Common Stock, authorized shares	450,000,000	450,000,000
Common Stock, shares issued	195,065,341	195,055,724
Treasury stock, shares	22,018,095	22,482,581

Nature of Business and Interim

Nature of Business and Interim Financial Statements	9 Months Ended
	Sep. 30, 2018
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 primarily produces oil and natural gas in the United States, Canada and Malaysia and undertakes oil and natural gas exploration activities in select basins around the globe . 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, 2018 and December 31, 2017 , and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended September 30, 2018 and 2017 , 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 2017 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 period s ended September 30, 2018 are not necessarily indicative of future results. 

New Accounting Principles and R

New Accounting Principles and Recent Accounting Pronouncements	9 Months Ended
	Sep. 30, 2018
New Accounting Principles and Recent Accounting Pronouncements [Abstract]
New Accounting Principles and Recent Accounting Pronouncements	Note B – New Accounting Principles and Recent Accounting Pronouncements Accounting Principles Adopted Revenue from Contracts with Customers. In May 2014, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU), which established a comprehensive model of accounting for revenue arising from contracts with customers that superseded most revenue recognition requirements and industry-specific guidance. Under the new standard, the Company recognizes revenue when it transfers control of the commodity to customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for the commodity. Additional disclosures are required to describe the nature, amount, timing and uncertainly of revenue and cash flows from contracts with customers. The Company adopted the new standard in the first quarter of 2018 using the modified retrospective method. The Company performed a review of contracts in each of its revenue streams and implemented accounting policies and internal controls to address the requirements of the ASU. Prior to January 1, 2018, the Company followed the sales method of revenue recognition under Accounting Standards Codification (ASC) Topic 605 and recorded revenue when deliveries occur r ed, and legal ownership of the commodity transferred to the customer. There was no adjustment to the opening balance of stockholders’ equity as at January 1, 2018, resulting from application of the new ASU promulgated in ASC Topic 606 using the modified retrospective method. The comparative information has not been adjusted and continues to be reported under ASC Topic 605 – Revenue Recognition. See also Note C for further discussion of Revenue Recognition. 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 amendments in this ASU were effective for annual and interim periods beginning after December 15, 2017. The Company adopted this guidance in the first quarter of 2018 and it did not 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 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 and interim periods beginning after December 15, 2017. The Company adopted the standard in the first quarter of 2018 and it did not have a material impact on its consolidated financial statements.   Note B – New Accounting Principles and Recent Accounting Pronouncements (Contd.) Accounting Principles Adopted (Cont.) Compensation – Stock Compensation. In May 2017, the 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. The Company adopted this accounting standard in the first quarter of 2018 and it did not have a material impact on its consolidated financial statements. Statement of Operations – Reporting Comprehensive Income . In February 2018, the FASB issued an ASU, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. The Company elected to early adopt this accounting standard during the first quarter of 2018 and recorded discrete adjustments from accumulated other comprehensive income to retained earnings of $28.4 million related to retirement and postretirement obligations and $1.8 million related to deferred loss on interest rate derivative hedges. The adoption of this ASU will have no future impact. Recent Accounting Pronouncements Leases . In February 2016, the 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 assessing internal processes and analyzing its portfolio of contracts to assess the impact future adoption of this ASU will have on its consolidated financial statements . Compensation – Stock Compensation. In June 2018, the FASB issued an ASU which supersedes existing guidance for equity-based payments to nonemployees and expands the scope of guidance for stock compensation to include all share-based payment arrangements related to the acquisition of goods and services from both nonemployees and employees. As a result, the same guidance that provides for employee share-based payments, including most of its requirements related to classification and measurement, applies to nonemployee share-based payment arrangements. The ASU 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. The Company anticipates adopting this guidance for the first quarter of 2019 and does not expect it to have a material impact on its consolidated financial statements. Fair Value Measurement. In August 2018, the FASB issued an ASU which modifies disclosure requirements related to fair value measurement. The amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Implementation on a prospective or retrospective basis varies by specific disclosure requirement. Early adoption is permitted. The standard also allows for early adoption of any removed or modified disclosures upon issuance of this ASU while delaying adoption of the additional disclosures until their effective date. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements. Compensation-Retirement Benefit s-Defined Benefit Plans-General. In August 2018, the FASB issued an ASU that modifies the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. For public companies, the amendments in this ASU are effective for fiscal years beginning after December 15, 2020, with early adoption permitted, and is to be applied on a retrospective basis to all periods presented. The Company is currently assessing the potential impact of this ASU to its consolidated financial statements. 

Revenue from Contracts with Cus

Revenue from Contracts with Customers	9 Months Ended
	Sep. 30, 2018
Revenue from Contracts with Customers [Abstract]
Revenue from Contracts with Customers	Note C – Revenue from Contracts with Customers Significant Accounting Policy Revenue is recognized when the Company satisfies a performance obligation by transferring control over a commodity to a customer; the amount of revenue recognized reflects the consideration expected in exchange for those commodities. The Company measures revenue based on consideration specified in a contract and excludes taxes and other amounts collected on behalf of third parties. Revenue is presented as the Company ’s share net of certain costs associated with generation of Revenue. Examples of costs that reduce revenue include transportation, gathering, compression, and processing fees in U.S. and Canada, as well as certain required payments associated with production sharing contracts (PSCs) and export taxes in Malaysia . Note C – Revenue from Contracts with Customers (Contd.) Nature of Goods and Services The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and gas) in select basins around the globe . The Company’s revenue from sales of oil and gas production activities are primarily subdivided into three key geographic segments: the U.S., Canada, and Malaysia. Additionally, revenue from sales to customers is generated from three primary revenue streams: crude oil and condensate, natural gas liquids, and natural gas. For operated oil and gas production where the non-operated working interest owner does not take-in-kind its proportionate interest in the produced commodity, the Company acts as an agent for the working interest owner and recognizes revenue only for its own share of the commingled production. U.S.- In the United States, the Company primarily produces oil and gas from fields in the Eagle Ford Shale area of South Texas and in the Gulf of Mexico. Revenue is generally recognized when oil and gas are transferred to the customer at the delivery point. Revenue recognized is largely index based with price adjustments for floating market differentials. Canada- Primarily all long-term contracts in Canada, except for certain natural gas physical forward sales fixed-price contracts, are floating commodity index priced. For the Onshore business in Canada, the recorded revenue is net of transportation and any gain or loss on spot purchases made to meet committed volumes on sales contracts for the month. For the Offshore business in Canada, contracts are based on index prices and revenue is recognized at the time of vessel load based on the volumes on the bill of lading and point of custody transfer. Malaysia- In Malaysia, the Company has interests in nine separate PSCs. The Company serves as the operator of all these area s except for the unitized Gumusut -Kakap field. Crude oil contracts in Malaysia share similar features of largely fixed cargo quantities, variable index-based pricing, and potential discounts at the point of meeting the performance obligation when the vessel is loaded. Malaysia also has three long term Gas Sales Agreements (GSA) with terms until the end of the field life, economic life, or PSC term. Disaggregation of Revenue The Company reviews performance based on three key geographical segments and between onshore and offshore sources of Revenue within these geographies. For the three months ended September 30, 2018 and 2017, the Company recognized $ 659.8 million and $ 511.2 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. For the nine months ended September 30, 2018 and 2017, the Company recognized $1,921.9 million and $1,498.1 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. Note C – Revenue from Contracts with Customers (Contd.)      Three Months Ended Nine Months Ended  September 30, September 30,  (Thousands of dollars) 2018 2017 2018 2017  Net crude oil and condensate revenue  United States – Onshore $ 224,714 143,527 606,186 437,504  – Offshore 93,206 43,658 259,128 145,139  Canada – Onshore 32,818 12,351 82,537 33,129  – Offshore 34,789 31,639 137,420 107,516  Malaysia – Sarawak 55,592 63,558 218,494 189,100  – Block K 102,149 122,460 298,330 287,032  Other 3,156 – 3,156 –  Total crude oil and condensate revenue 546,424 417,193 1,605,251 1,199,420   Net natural gas liquids revenue  United States – Onshore 16,993 11,114 42,363 29,838  – Offshore 3,438 1,679 7,998 4,804  Canada – Onshore 4,137 1,323 11,053 2,636  Malaysia – Sarawak 4,960 4,985 15,153 13,526  Total natural gas liquids revenue 29,528 19,101 76,567 50,804   Net natural gas revenue  United States – Onshore 6,872 6,031 19,934 21,072  – Offshore 3,306 2,541 9,068 7,922  Canada – Onshore 35,373 36,974 103,055 114,772  Malaysia – Sarawak 38,236 29,166 107,616 103,584  – Block K 67 186 419 519  Total natural gas revenue 83,854 74,898 240,092 247,869  Total revenue from contracts with customers 659,806 511,192 1,921,910 1,498,093   Gain (loss) on crude contracts (2,223) (13,573) (69,349) 50,365  Other operating income 17,090 583 26,029 4,015  Gain on sale of assets 124 117 6 130,765  Total revenue $ 674,797 498,319 1,878,596 1,683,238  Contract Balances and Asset Recognition As of September 30, 2018, and December 31, 2017, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet, were $187.3 million and $203.4 million, respectively. Payment terms for the Company’s sales vary across contracts and geographical regions, with the majority of the cash receipts required within 30 days of billing. Based on historical collections and ability of customers to pay, the Company did not recognize any impairment losses on receivables or contract assets arising from customer contracts during the reporting periods. The Company has not entered into any upstream oil and gas sale contracts that have financing components as at September 30, 2018. The Company does not employ sales incentive strategies such as commissions or bonuses for obtaining sales contracts. For the periods presented, the Company did not identify any assets to be recognized associated with the costs to obtain a contract with a customer.      Note C – Revenue from Contracts with Customers (Contd.) Performance Obligations The Company recognizes oil and gas revenue when it satisfies a performance obligation by transferring control over a commodity to a customer. Judgment is required to determine whether some customers simultaneously receive and consume the benefit of commodities. As a result of this assessment for the Company, each unit of measure of the specified commodity is considered to represent a distinct performance obligation that is satisfied at a point in time upon the transfer of control of the commodity. For contracts with market or index-based pricing, which represent the majority of sales contracts, the Company has elected the allocation exception and allocates the variable consideration to each single performance obligation in the contract. As a result, there is no price allocation to unsatisfied remaining performance obligations for delivery of commodity product in subsequent periods. The Company has entered into several long-term, fixed-price contracts in Canada. The underlying reason for entering a fixed price contract is generally unrelated to anticipated future prices or other observable data and serves a particular purpose in the company’s long-term strategy. The contractually stated price for each unit of commodity transferred under these contracts represents the stand-alone selling price of the commodity. As at September 30, 2018, the Company had the following sales contracts in place which are expected to generate revenue from sales to customers for a period of 12 months or more starting at the inception of the contract:     Current Long-Term Contracts Outstanding at September 30, 2018  Location Commodity End Date Description Approximate Volumes  U.S. Onshore Oil Q2 2019 Fixed quantity delivery in Eagle Ford 4,000 BOE/Day  U.S. Onshore Oil Q3 2019 Fixed quantity delivery in Eagle Ford 2,000 BOE/Day  U.S. Onshore Oil Q4 2021 Fixed quantity delivery in Eagle Ford 2018: 19,000 BOE/Day 2019-2021: 13,000 BOE/Day  U.S. Onshore Gas and NGL Q2 2026 Deliveries from dedicated acreage in Eagle Ford As produced  Canada Onshore Gas Q4 2020 Contracts to sell natural gas at Alberta AECO Cdn dollar 2.81/MCF 59 MMCF/Day  Canada Onshore Gas Q4 2020 Contracts to sell natural gas at USD Index pricing 60 MMCF/Day  Canada Onshore Gas Q4 2024 Contracts to sell natural gas at USD Index pricing 30 MMCF/Day  Canada Onshore Gas Q4 2026 Contracts to sell natural gas at USD Index pricing 38 MMCF/Day  

Property, Plant and Equipment

Property, Plant and Equipment	9 Months Ended
	Sep. 30, 2018
Property, Plant And Equipment [Abstract]
Property, Plant and Equipment	 Note D – Property, Plant and Equipment Exploratory Wells Under 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, 2018 , the Company had total capitalized exploratory well costs pending the determination of proved reserves of $ 2 10.8 million. The following table reflects the net changes in capitalized exploratory well costs during the nine -month periods ended September 30, 2018 and 2017 .     (Thousands of dollars) 2018 2017  Beginning balance at January 1 $ 175,640 148,500  Additions pending the determination of proved reserves 41,940 51,614  Reclassifications to proved properties based on the determination of proved reserves (2,214) (13,370)  Capitalized exploratory well costs charged to expense (4,521) (8,360)  Balance at September 30 $ 210,845 178,384 The capitalized well costs charged to expense during the first nine months of 2018 included the Julong East well in Block CA-1, offshore Brunei in which further development of the well has not been sanctioned by the operator and the contract term for development sanctions has now been reached. This well was originally drilled in 2012. 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. 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,  2018 2017  (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 $ 46,813 1 1 $ 41,609 3 2  One to two years 41,051 3 2 8,430 2 2  Two to three years 5,208 1 1 43,197 1 1  Three years or more 117,773 5 2 85,148 7 1  $ 210,845 10 6 $ 178,384 13 6 Of th e $164.0 million of exploratory well costs capitalized more than one year at September 30, 2018, $55.9 million is in Brunei, $59.8 million is in Vietnam, $27.4 million is in the U.S. and $20.9 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 $48.8 million. Additionally, the buyer assumed the asset retirement obligation of approximately $85.9 million. A $132.4 million pretax gain was reported in the 2017 period 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 s were approximately $19.6 million. There were no gains or losses recorded related to these non-core Eagle Ford Shale sales. Note D – Property, Plant and Equipment (Contd.) In 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. Total cash consideration received upon closing was $414.1 million. A gain on sale of approximately $187.0 million was deferred and is being recognized over approximately the next 18 years in the Canadian operating segment. The Company amortized approximately $5.7 million and $5.3 million of the deferred gain during the first nine months of 2018 and 2017, respectively. The remaining deferred gain of $171. 3 million was included as a component of Deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of September 30 , 2018 . A cquisitions In 2016, a Canadian subsidiary of Murphy Oil acquired a 70% operated working interest (WI) in Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30% non-operated WI in 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, 2018 , $93.1 million of the carried interest had been paid. The carry is to be paid over a period through 20 19 . Other In 2006, the Kakap field in Block K was unitized with the Gumusut field in an adjacent block under a Unitization and Unit Operating Agreement (UUOA) between the operators. The Gumusut-Kakap Unit is operated by another company. In the fourth quarter 2016, the operators completed the first redetermination process for a revision to the blocks’ tract participation interest, and the operator of the unitized field sought the approval of Petronas to effect the change in 2017. In 2016, the Company recorded an estimated redetermination expense of $39.1 million ( $24.1 million after tax) related to an expected revision in the Company’s working interest covering the period from inception through year-end 2016 at Kakap. In February 2017, the Company received Petronas’ official approval to the redetermination change that reduced the Company’s working interest in oil operations to 6.67% effective at April 1, 2017. Working interest redeterminations are required at different points within the life of the unitized field. Following a partial payment, the remaining redetermination liability of $17.3 million was included as a component of Other current liabilities in the Company’s Consolidated Balance Sheet as of September 30, 2018. Following a further Unitization Framework Agreement (UFA) between the governments of Brunei and Malaysia, the Company now has a 6.37% interest in the Kakap field in Block K Malaysia. The UFA unitized the Gumusut - Kakap (GK) and Geronggong/Jagus East fields effective November 23, 2017. In the fourth quarter 2017, the Company recorded an estimated redetermination liability of $15.0 million related to Company’s revised working interest , which was i ncluded as a component of Other current liabilities in the Company’s Consolidated Balance Sheet as of September 30, 2018 .

Discontinued Operations and Ass

Discontinued Operations and Assets Held for Sale	9 Months Ended
	Sep. 30, 2018
Discontinued Operations and Assets Held for Sale [Abstract]
Discontinued Operations and Assets Held for Sale	Note E – 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, 2018 and 2017 were as follows:    Three Months Ended Nine Months Ended  September 30, September 30,  (Thousands of dollars) 2018 2017 2018 2017  Revenues $ – 598 6 853  Income (loss) before income taxes (1,815) 425 (2,650) 1,177  Income tax benefit – – – –  Income (loss) from discontinued operations $ (1,815) 425 (2,650) 1,177  Note E – Discontinued Operations and Assets Held for Sale (Contd.) The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheets at September 30, 2018 and December 31, 2017 .    September 30, December 31,  (Thousands of dollars) 2018 2017  Current assets  Cash $ 17,409 16,631  Accounts receivable 3,731 6,298  Total current assets held for sale $ 21,140 22,929  Current liabilities  Accounts payable $ 143 837  Refinery decommissioning cost 2,659 2,693  Total current liabilities associated with assets held for sale $ 2,802 3,530  

Financing Arrangements and Debt

Financing Arrangements and Debt	9 Months Ended
	Sep. 30, 2018
Financing Arrangements and Debt [Abstract]
Financing Arrangements and Debt	Note F – Financing Arrangements and Debt At September 30, 2018 , the Company had a $1.1 billion senior unsecured guaranteed credit facility (2016 facility) with a major banking consortium, which expires in August 2021 . At September 30, 2018 , the Company had no outstanding borrowings under the 2016 facility, however, there were $28.0 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, 2018, the applicable base interest rate would have been 5.0625% . At September 30, 2018 , the Company was in compliance with all covenants related to the 2016 facility. The Company and its partners are parties to a 25 -year lease of production equipment at the Kak ap 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 include d $10.5 million and $128.5 million, respectively, associated with this lease at September 30, 2018 .

Other Financial Information

Other Financial Information	9 Months Ended
	Sep. 30, 2018
Other Financial Information [Abstract]
Other Financial Information	Note G – Other Financial Information Additional disclosures regarding cash flow activities are provided below.    Nine Months Ended September 30,  (Thousands of dollars) 2018 2017  Net (increase) decrease in operating working capital other than cash and cash equivalents:  (Increase) decrease in accounts receivable $ (31,178) 90,614  Decrease in inventories 16,732 5,869  (Increase) decrease in prepaid expenses (8,695) 25,285  Increase (decrease) in accounts payable and accrued liabilities 17,946 (115,977)  Increase(decrease) in income taxes payable 2,645 (4,721)  Net (increase) decrease in noncash operating working capital $ (2,550) 1,070  Supplementary disclosures:  Cash income taxes paid, net of refunds $ 77,508 25,118  Interest paid, net of amounts capitalized of $3,719 in 2018 and $3,338 in 2017 115,009 95,899   Non-cash investing activities:  Asset retirement costs capitalized $ 2,907 38,992  (Increase) decrease in capital expenditure accrual (751) 42,403  

Employee and Retiree Benefit Pl

Employee and Retiree Benefit Plans	9 Months Ended
	Sep. 30, 2018
Employee and Retiree Benefit Plans [Abstract]
Employee and Retiree Benefit Plans	Note H – 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 S eptember 30, 2018 and 2017 .      Three Months Ended September 30,  Pension Benefits Other Postretirement Benefits  (Thousands of dollars) 2018 2017 2018 2017  Service cost $ 2,252 2,037 492 427  Interest cost 6,716 7,261 874 966  Expected return on plan assets (7,476) (8,070) – –  Amortization of prior service cost (credit) 254 259 (10) (18)  Recognized actuarial loss 5,197 3,610 – –  Net periodic benefit expense $ 6,943 5,097 1,356 1,375   Nine Months Ended September 30,  Pension Benefits Other Postretirement Benefits  (Thousands of dollars) 2018 2017 2018 2017  Service cost $ 6,761 6,099 1,479 1,276  Interest cost 20,160 20,267 2,622 2,899  Expected return on plan assets (22,435) (21,730) – –  Amortization of prior service cost (credit) 767 767 (29) (55)  Recognized actuarial loss 15,593 10,673 – –  Net periodic benefit expense $ 20,846 16,076 4,072 4,120 The components of net periodic benefit expense other than the service cost component are included in the line item “Interest and other income (loss)” in Consolidated Statements of Operations. Du ring the nine -month period ended September 30, 2018 , the Company made contributions of $22.2 million to its defined benefit pension and postretirement benefit plans. Remaining funding in 2018 for the Company’s defined benefit pension and postretirement plans is anticipated to be $7.6 million.

Incentive Plans

Incentive Plans	9 Months Ended
	Sep. 30, 2018
Incentive Plans [Abstract]
Incentive Plans	Note I – 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 2017 Annual Incentive Plan (2017 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 2017 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 ha d a 2013 Stock Plan for Non-Employee Directors (Director Plan) that permit ted the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors. This plan expired in May 2018. At the Annual Shareholder Meeting held in May 2018, shareholders approved the 2018 Stock Plan for Non-Employee Directors and the 2018 Long-Term Incentive Plan. Following this approval, no furt her awards will be granted under the 2012 Long-T erm Plan . In the first quarter of 2018, the Committee granted 905,500 performance-based RSUs and 736,000 time-based RSUs to certain employees. The fair value of the performance-based RSUs, using a Monte Carlo valuation model , ranged from $28.27 to $30.56 per unit. The fair value of the time-based RSUs was estimated based on the fair market value of the Company’s stock on the date of grant. The fair value of the time-based RSUs granted February 6, 2018 was $28.42 per unit, the fair value of the time-based RSUs granted February 20, 2018 was $26.56 per unit, and the fair value of the time-based RSUs granted March 1, 2018 was $25.69 per unit. Additionally, on February 6, 2018 the Committee granted 715,100 cash-settled RSUs (RSUC) to certain employees, and on March 9, 2018 granted 29,000 RSUCs to certain employees. The 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 the RSUCs was equivalent to the equity-settled restricted stock units granted. Also in February, the Committee granted 77,803 shares of time-based RSUs to the Company’s Directors under the Non-Employee Director Plan. These units are scheduled to vest on the third anniversary of the date of grant. The estimated fair value of these awards was $28.28 per unit on date of grant. All stock option exercises are non-cash transactions for the Company. The employee receives net shares, after applicable withholding taxes, upon each stock option exercise. The actual income tax benefit realized from the tax deductions related to stock option exercises of the share-based payment arrangements were immaterial for the nine-month period ended September 30, 2018. 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) 2018 2017  Compensation charged against income before tax benefit $ 36,348 28,264  Related income tax benefit recognized in income 5,532 8,695 Certain incentive compensation granted to the Company’s named executive officers, to the extent their total compensation exceeds $1.0 million per executive per year, is not eligible for a U.S. income tax deduction under the Tax Cuts and Jobs Act (2017 Tax Act). 

Earnings per Share

Earnings per Share	9 Months Ended
	Sep. 30, 2018
Earnings per Share [Abstract]
Earnings per Share	Note J – Earnings per Share Net income was used as the numerator in computing both basic and diluted income per Common s hare for the three-month and nine -month periods ended September 30, 2018 and 2017. 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) 2018 2017 2018 2017  Basic method 173,047,246 172,572,873 172,949,450 172,509,418  Dilutive stock options and restricted stock units 1,128,021 – 1 1,252,310 – 1  Diluted method 174,175,267 172,572,873 174,201,760 172,509,418 1 Due to a net loss in the three-month and nine-month period s ended September 30, 2017, no unvested stock awards were included in the computation of diluted earnings per shares because the effect would have been anti-dilutive.  The following table reflects certain options to purchase shares of common stock that were outstanding during the periods presented but were not included in the computation of diluted shares above because the incremental shares from assumed conversion were antidilutive.    Three Months Ended Nine Months Ended  September 30, September 30,  2018 2017 2018 2017  Antidilutive stock options excluded from diluted shares 2,870,549 5,257,718 3,544,087 5,578,495  Weighted average price of these options $ 54.06 $ 46.46 $ 50.49 $ 46.86  

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2018
Income Taxes [Abstract]
Income Taxes	Note K – Income Taxes The Company’s effective income tax rate is calculated as the amount of income tax expense (benefit) divided by income from continuing operations before income t axes. For the three-month and nine- month periods ended September 30, 2018 and 2017, the Company’s effective income tax rates were as follows:   2018 2017  Three months ended September 30 34.8% (4.3%)  Nine months ended September 30 4.8% 137.7% The effective tax rates for most periods where earnings are generated, generally exceed the U.S. statutory tax rate ( 21% in 2018, 35% in 2017) 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 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 21% due to similar reasons. Due to uncertainty related to language in Section 965(n) of the 2017 Tax Act, and specifically whether current operating losses from 2017 were required to be applied to offset a company’s deemed taxable repatriation of foreign earnings under the 2017 Tax Act, the Company’s provisional tax expense recorded in the Company’s December 31, 2017 financial statements reflected use of all the estimated 2017 tax operating loss against the deemed repatriation. This resulted in no loss carryover of 2017 tax operating losses from 2017 into 2018 , and foreign tax credits of $228.2 million were fully provided for in the Company’s December 31, 2017 financial statements. On April 2, 2018, the Internal Revenue Service issued new guidance related to Section 965(n). This guidance resolved an ambiguity related to an election which allowed the Company to preserve the 2017 tax net operating loss as a carryforward which resulted in utilizing the previously unused foreign tax credits against all but $36 million of current income tax on the deemed repatriation of foreign earnings. The preservation of the tax loss carryforward reduced the deferred tax expense for the first quarter of 2018 and year to date by $156 million and resulted in a $36 million charge to taxes payable relating to the deemed inclusion. The Company anticipates paying this $36 million tax payable over eight years as permitted by the 2017 Tax Act. Note K – Income Taxes (Contd.) The effective tax rate for the three-month period ended September 30, 2018 was above the U.S. statutory tax rate of 21% primarily due to higher tax rates in certain foreign tax jurisdictions combined with expenses in foreign jurisdictions not fully deductible from income at the U.S. statutory rate. The effective tax rate for the three-month period ended September 30, 2017 was below the U.S. statutory tax rate primarily due to the tax effect of expenses in foreign jurisdiction s not being 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%. The 2017 period income before tax was a loss. The effective tax rate for the nine -month period ended September 30, 2018 was below the U.S. statutory tax rate of 21% primarily due to the discrete tax effect of the new guidance relating to Section 965(n), offset by higher tax rates in certain foreign tax jurisdictions and expenses in foreign jurisdictions not fully deductible from income at the U.S. statutory tax rate . The effective tax rate for the nine-month period ended September 30, 2017 was above the U.S. statutory tax rate primarily due to an estimated U.S. tax charge recognized for undistributed foreign earnings and Canadian foreign exchange losses not fully deductible at the statutory rate. 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 and recorded a deferred tax charge of $65.2 million associated with the estimated tax consequence of future repatriation of Malaysian and Canadian earnings that were deemed no longer indefinitely invested. The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take multiple 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, 2018, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2015 ; Canada – 2012 ; Malaysia – 20 11 ; and United Kingdom – 2016 .

Financial Instruments and Risk

Financial Instruments and Risk Management	9 Months Ended
	Sep. 30, 2018
Financial Instruments and Risk Management [Abstract]
Financial Instruments and Risk Management	 Note L – 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 reports gains and losses on derivative instruments in the Corporate segment. 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 Price Risks The Company is subject to commodity price risk related to crude oil it produces a nd sells. During the first nine months of 2018 and 2017, 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, 2018, the Company had 21,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during the remainder of 2018 at an average price of $54.88 . At September 30, 2017, the Company had 22,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2017 and 6,000 barrels per days in WTI crude oil swap financial contracts maturing ratably during 2018. 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, 2018 and 2017. At September 30, 2018 and December 31, 2017, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.      September 30, 2018 December 31, 2017  (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 $ (44,601) Accounts payable $ (39,093) Note L – Financial Instruments and Risk Management (Contd.) For the three-month and nine -month periods ended September 30, 2018 and 2017, 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 2018 2017 2018 2017  Commodity Gain (loss) on crude contracts $ (2,223) (13,573) (69,349) 50,365  Foreign exchange Interest and other income (loss) – – – 73  $ (2,223) (13,573) (69,349) 50,438 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, 2018 and 2017, $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 (net of tax) deferred on these matured contracts at September 30, 2018 was $8.5 million , which is recorded, net of income taxes of $2.3 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 Ope rations during the remaining three months of 2018. 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, 2018 and December 31, 2017 are presented in the following table.     September 30, 2018 December 31, 2017  (Thousands of dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total  Liabilities:  Nonqualified employee savings plans $ 15,957 – – 15,957 16,158 – – 16,158  Commodity derivative contracts – 44,601 – 44,601 – 39,093 – 39,093  $ 15,957 44,601 – 60,558 16,158 39,093 – 55,251 The fair value of WTI crude oil derivative contracts in 2018 and 2017 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 Gain (loss) on crude contracts 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, 2018 and December 31, 2017.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Loss	9 Months Ended
	Sep. 30, 2018
Accumulated Other Comprehensive Loss [Abstract]
Accumulated Other Comprehensive Loss	   Note M – Accumulated Other Comprehensive Loss The components of Accumulated other comprehensive loss on the Consolidated Balance Shee ts at December 31, 2017 and September 30, 2018 and the changes during the nine -month period ended September 30, 2018 are presented net of taxes in the following table.    Deferred  Retirement Loss on  Foreign and Interest  Currency Postretirement Rate  Translation Benefit Plan Derivative  (Thousands of dollars) Gains (Losses) Adjustments Hedges Total  Balance at December 31, 2017 $ (274,830) (178,987) (8,426) (462,243)  2018 components of other comprehensive income (loss):  Before reclassifications to income and retained earnings (53,805) (32,159) (1,815) (87,779)  Reclassifications to income – 10,498 1 1,756 2 12,254  Net other comprehensive loss (53,805) (21,661) (59) (75,525)  Balance at September 30, 2018 $ (328,635) (200,648) (8,485) (537,768) 1 Reclassifications before taxes of $13,111 are included in the computation of net per iodic benefit expense for the nine-month period ended September 30, 2018. See Note H for additional information. Related income taxes of $2,613 are included in Income t ax expense (benefit) for the nine-month period ended September 30, 2018. 2 Reclassifications before taxes of $2,222 are included in Interest expense, net, for the nine-month period ended September 30, 2018. Related income taxes of $466 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2018. See Note L for additional information.

Environmental and Other Conting

Environmental and Other Contingencies	9 Months Ended
	Sep. 30, 2018
Environmental and Other Contingencies [Abstract]
Environmental and Other Contingencies	Note N – 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 legislation changes, including 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 and may be taken without full consideration of their consequences or may be taken in response to actions of other governments. It is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company. Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations dealing with the environment. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hazardous substances into the environment could, to the extent such event is not insured, subject the Company to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for any personal injury and property damage that might result. Note N – Environmental and Other Contingencies (Contd.) The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance c overing 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. In early 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 and a further $3.8 million in the first quarter of 2018 associated with the estimated costs of remediating the site. The Company has spent $43.1 million from inception to September 30, 2018. Further refinements in the estimated total cost to remediate the site are anticipated in future periods. 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. As of September 30, 2018, the Company has a remaining accrued liability of $4.7 million associated with this event. In the first nine months of 2018, the Company received $25.0 million in respect to an insurance claim regarding this matter and the outcome of further insurance claims by the Company is pending. 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. 

Commitments

Commitments	9 Months Ended
	Sep. 30, 2018
Commitments [Abstract]
Commitments	Note O – Commitments The Company has entered into forward sales contracts to mitigate the price risk for a portion of its 2018 to 2020 natural gas sales volumes in Western Cana da. During the period from October 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. These natural gas contracts have been accounted for as normal sales for accounting purposes.

Business Segments

Business Segments	9 Months Ended
	Sep. 30, 2018
Business Segments [Abstract]
Business Segments	 Note P – 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, other gains and losses (including foreign exchange gains/losses and realized/unrealized gains/losses on crude oil contracts), interest expense and unallocated overhead, is shown in the tables to reconcile the business segments to consolidated totals. Certain reclassifications have been made to 2017 Exploration and production and Corporate External Revenues and Income (Loss) to align with current period presentation.    Three Months Ended Three Months Ended  Total Assets September 30, 2018 September 30, 2017  at September 30, External Income External Income  (Millions of dollars) 2018 Revenues (Loss) Revenues (Loss)  Exploration and production 1  United States $ 4,772.2 348.7 91.6 209.4 (11.2)  Canada 1,790.3 107.1 12.5 81.9 (3.2)  Malaysia 1,604.7 201.2 54.1 220.5 67.7  Other 183.4 19.9 1.3 – (11.0)  Total exploration and production 8,350.6 676.9 159.5 511.8 42.3  Corporate 3 1,654.9 (2.1) (63.8) (13.5) (108.6)  Assets/revenue/income from continuing operations 10,005.5 674.8 95.7 498.3 (66.3)  Discontinued operations, net of tax 21.1 – (1.8) – 0.4  Total $ 10,026.6 674.8 93.9 498.3 (65.9)   Nine Months Ended Nine Months Ended  September 30, 2018 September 30, 2017  External Income External Income  (Millions of dollars) Revenues (Loss) Revenues (Loss)  Exploration and production 1  United States $ 945.6 200.3 646.3 (21.8)  Canada 2 333.8 46.7 388.1 102.6  Malaysia 640.7 208.4 594.4 173.9  Other 19.9 (28.8) – (10.9)  Total exploration and production 1,940.0 426.6 1,628.8 243.8  Corporate 3 (61.4) (116.2) 54.4 (270.0)  Revenue/loss from continuing operations 1,878.6 310.4 1,683.2 (26.2)  Discontinued operations, net of tax – (2.7) – 1.2  Total $ 1,878.6 307.7 1,683.2 (25.0) 1 Additional details about results of oil and gas operations are presented in the tables on page s 30 and 31 . 2 Revenue for the nine months ended September 30, 2017 includes a pretax gain of $132.4 million related to the sale of Seal heavy oil assets in Canada. 3 In 2018, the Company reported realized and unrealized gains and losses on crude oil contracts in the Corporate segment (previously reported in the Exploration and production business) to reflect how segments are currently evaluated, how resources are allocated and how risk is managed by the Company. The 2017 amounts have been reclassified to reflect comparable disclosure.

Subsequent Event

Subsequent Event	9 Months Ended
	Sep. 30, 2018
Subsequent Event [Abstract]
Subsequent Event	 Note Q – Subsequent Event On October 10, 2018, the Company announced that its wholly owned subsidiary, Murphy Exploration & Production Company – USA, had entered into a definitive agreement to form a new joint venture company with Petrobras America Inc. (PAI), a subsidiary of Petrobras. The joint venture company will be comprised of Gulf of Mexico producing assets from Murphy and PAI with Murphy overseeing the operations. The transaction will have an effective date of October 1, 2018 and is expected to close by year-end 2018. Both companies will contribute all their current producing Gulf of Mexico assets to the joint venture, which will be owned 80 percent by Murphy and 20 percent by PAI. The transaction excludes exploration blocks from both companies, with the exception of PAI’s blocks that hold deep exploration rights. Murphy will pay cash consideration of $900 million to PAI, subject to normal closing adjustments. Additionally, PAI will earn an additional contingent consideration up to $150 million if certain price and production thresholds are exceeded beginning in 2019 through 2025. Also, Murphy will carry $50 million of PAI costs in the St. Malo Field if certain enhanced oil recovery projects are undertaken. Upon closing, Murphy expects to fund the transaction through a combination of cash-on-hand and the Company’s 2016 facility (See Note F). In conjunction with the joint venture, on October 10, 2018, the company entered into an amendment of its existing Credit Agreement. The amendment, once effective will provide selected covenant relief and add financial flexibility. The amended credit facility will be effective upon the closing of the joint venture transaction. The key terms of the amendment include eliminating the “collateral trigger event” clause (springing collateral, and “minimum domestic liquidity requirements” as defined in the Credit Agreement) and allows Company to execute the transaction, including contributing assets to the joint venture company.  

Nature of Business and Interi_2

Nature of Business and Interim Financial Statements (Policies)	9 Months Ended
	Sep. 30, 2018
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 primarily produces oil and natural gas in the United States, Canada and Malaysia and undertakes oil and natural gas exploration activities in select basins around the globe .

Revenue from Contracts with C_2

Revenue from Contracts with Customers (Policies)	9 Months Ended
	Sep. 30, 2018
Revenue from Contracts with Customers [Abstract]
Revenue Recognition	Revenue is recognized when the Company satisfies a performance obligation by transferring control over a commodity to a customer; the amount of revenue recognized reflects the consideration expected in exchange for those commodities. The Company measures revenue based on consideration specified in a contract and excludes taxes and other amounts collected on behalf of third parties. Revenue is presented as the Company ’s share net of certain costs associated with generation of Revenue. Examples of costs that reduce revenue include transportation, gathering, compression, and processing fees in U.S. and Canada, as well as certain required payments associated with production sharing contracts (PSCs) and export taxes in Malaysia .

Revenue from Contracts with C_3

Revenue from Contracts with Customers (Tables)	9 Months Ended
	Sep. 30, 2018
Revenue from Contracts with Customers [Abstract]
Disaggregation of Revenue	  Three Months Ended Nine Months Ended  September 30, September 30,  (Thousands of dollars) 2018 2017 2018 2017  Net crude oil and condensate revenue  United States – Onshore $ 224,714 143,527 606,186 437,504  – Offshore 93,206 43,658 259,128 145,139  Canada – Onshore 32,818 12,351 82,537 33,129  – Offshore 34,789 31,639 137,420 107,516  Malaysia – Sarawak 55,592 63,558 218,494 189,100  – Block K 102,149 122,460 298,330 287,032  Other 3,156 – 3,156 –  Total crude oil and condensate revenue 546,424 417,193 1,605,251 1,199,420   Net natural gas liquids revenue  United States – Onshore 16,993 11,114 42,363 29,838  – Offshore 3,438 1,679 7,998 4,804  Canada – Onshore 4,137 1,323 11,053 2,636  Malaysia – Sarawak 4,960 4,985 15,153 13,526  Total natural gas liquids revenue 29,528 19,101 76,567 50,804   Net natural gas revenue  United States – Onshore 6,872 6,031 19,934 21,072  – Offshore 3,306 2,541 9,068 7,922  Canada – Onshore 35,373 36,974 103,055 114,772  Malaysia – Sarawak 38,236 29,166 107,616 103,584  – Block K 67 186 419 519  Total natural gas revenue 83,854 74,898 240,092 247,869  Total revenue from contracts with customers 659,806 511,192 1,921,910 1,498,093   Gain (loss) on crude contracts (2,223) (13,573) (69,349) 50,365  Other operating income 17,090 583 26,029 4,015  Gain on sale of assets 124 117 6 130,765  Total revenue $ 674,797 498,319 1,878,596 1,683,238 
Current Long-Term Contracts Outstanding	  Current Long-Term Contracts Outstanding at September 30, 2018  Location Commodity End Date Description Approximate Volumes  U.S. Onshore Oil Q2 2019 Fixed quantity delivery in Eagle Ford 4,000 BOE/Day  U.S. Onshore Oil Q3 2019 Fixed quantity delivery in Eagle Ford 2,000 BOE/Day  U.S. Onshore Oil Q4 2021 Fixed quantity delivery in Eagle Ford 2018: 19,000 BOE/Day 2019-2021: 13,000 BOE/Day  U.S. Onshore Gas and NGL Q2 2026 Deliveries from dedicated acreage in Eagle Ford As produced  Canada Onshore Gas Q4 2020 Contracts to sell natural gas at Alberta AECO Cdn dollar 2.81/MCF 59 MMCF/Day  Canada Onshore Gas Q4 2020 Contracts to sell natural gas at USD Index pricing 60 MMCF/Day  Canada Onshore Gas Q4 2024 Contracts to sell natural gas at USD Index pricing 30 MMCF/Day  Canada Onshore Gas Q4 2026 Contracts to sell natural gas at USD Index pricing 38 MMCF/Day 

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	9 Months Ended
	Sep. 30, 2018
Property, Plant And Equipment [Abstract]
Net Changes in Capitalized Exploratory Well Costs	   (Thousands of dollars) 2018 2017  Beginning balance at January 1 $ 175,640 148,500  Additions pending the determination of proved reserves 41,940 51,614  Reclassifications to proved properties based on the determination of proved reserves (2,214) (13,370)  Capitalized exploratory well costs charged to expense (4,521) (8,360)  Balance at September 30 $ 210,845 178,384 
Aging of Capitalized Exploratory Well Costs	   September 30,  2018 2017  (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 $ 46,813 1 1 $ 41,609 3 2  One to two years 41,051 3 2 8,430 2 2  Two to three years 5,208 1 1 43,197 1 1  Three years or more 117,773 5 2 85,148 7 1  $ 210,845 10 6 $ 178,384 13 6 

Discontinued Operations and A_2

Discontinued Operations and Assets Held for Sale (Tables)	9 Months Ended
	Sep. 30, 2018
Discontinued Operations and Assets Held for Sale [Abstract]
Results of Operations Associated with Discontinued Operations	  Three Months Ended Nine Months Ended  September 30, September 30,  (Thousands of dollars) 2018 2017 2018 2017  Revenues $ – 598 6 853  Income (loss) before income taxes (1,815) 425 (2,650) 1,177  Income tax benefit – – – –  Income (loss) from discontinued operations $ (1,815) 425 (2,650) 1,177 
Major Categories of Assets and Liabilities Reflected as Held for Sale	   September 30, December 31,  (Thousands of dollars) 2018 2017  Current assets  Cash $ 17,409 16,631  Accounts receivable 3,731 6,298  Total current assets held for sale $ 21,140 22,929  Current liabilities  Accounts payable $ 143 837  Refinery decommissioning cost 2,659 2,693  Total current liabilities associated with assets held for sale $ 2,802 3,530 

Other Financial Information (Ta

Other Financial Information (Tables)	9 Months Ended
	Sep. 30, 2018
Other Financial Information [Abstract]
Noncash Operating Working Capital (Increase) Decrease	  Nine Months Ended September 30,  (Thousands of dollars) 2018 2017  Net (increase) decrease in operating working capital other than cash and cash equivalents:  (Increase) decrease in accounts receivable $ (31,178) 90,614  Decrease in inventories 16,732 5,869  (Increase) decrease in prepaid expenses (8,695) 25,285  Increase (decrease) in accounts payable and accrued liabilities 17,946 (115,977)  Increase(decrease) in income taxes payable 2,645 (4,721)  Net (increase) decrease in noncash operating working capital $ (2,550) 1,070  Supplementary disclosures:  Cash income taxes paid, net of refunds $ 77,508 25,118  Interest paid, net of amounts capitalized of $3,719 in 2018 and $3,338 in 2017 115,009 95,899   Non-cash investing activities:  Asset retirement costs capitalized $ 2,907 38,992  (Increase) decrease in capital expenditure accrual (751) 42,403 

Employee and Retiree Benefit _2

Employee and Retiree Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2018
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) 2018 2017 2018 2017  Service cost $ 2,252 2,037 492 427  Interest cost 6,716 7,261 874 966  Expected return on plan assets (7,476) (8,070) – –  Amortization of prior service cost (credit) 254 259 (10) (18)  Recognized actuarial loss 5,197 3,610 – –  Net periodic benefit expense $ 6,943 5,097 1,356 1,375   Nine Months Ended September 30,  Pension Benefits Other Postretirement Benefits  (Thousands of dollars) 2018 2017 2018 2017  Service cost $ 6,761 6,099 1,479 1,276  Interest cost 20,160 20,267 2,622 2,899  Expected return on plan assets (22,435) (21,730) – –  Amortization of prior service cost (credit) 767 767 (29) (55)  Recognized actuarial loss 15,593 10,673 – –  Net periodic benefit expense $ 20,846 16,076 4,072 4,120 

Incentive Plans (Tables)

Incentive Plans (Tables)	9 Months Ended
	Sep. 30, 2018
Incentive Plans [Abstract]
Share-Based Plans, Amounts Recognized	   Nine Months Ended  September 30,  (Thousands of dollars) 2018 2017  Compensation charged against income before tax benefit $ 36,348 28,264  Related income tax benefit recognized in income 5,532 8,695 

Earnings per Share (Tables)

Earnings per Share (Tables)	9 Months Ended
	Sep. 30, 2018
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) 2018 2017 2018 2017  Basic method 173,047,246 172,572,873 172,949,450 172,509,418  Dilutive stock options and restricted stock units 1,128,021 – 1 1,252,310 – 1  Diluted method 174,175,267 172,572,873 174,201,760 172,509,418 1 Due to a net loss in the three-month and nine-month period s ended September 30, 2017, no unvested stock awards were included in the computation of diluted earnings per shares 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,  2018 2017 2018 2017  Antidilutive stock options excluded from diluted shares 2,870,549 5,257,718 3,544,087 5,578,495  Weighted average price of these options $ 54.06 $ 46.46 $ 50.49 $ 46.86 

Income Taxes (Tables)

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2018
Income Taxes [Abstract]
Effective Income Tax Rates	  2018 2017  Three months ended September 30 34.8% (4.3%)  Nine months ended September 30 4.8% 137.7% 

Financial Instruments and Ris_2

Financial Instruments and Risk Management (Tables)	9 Months Ended
	Sep. 30, 2018
Financial Instruments and Risk Management [Abstract]
Fair Value of Derivative Instruments Not Designated as Hedging Instruments	   September 30, 2018 December 31, 2017  (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 $ (44,601) Accounts payable $ (39,093) 
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 2018 2017 2018 2017  Commodity Gain (loss) on crude contracts $ (2,223) (13,573) (69,349) 50,365  Foreign exchange Interest and other income (loss) – – – 73  $ (2,223) (13,573) (69,349) 50,438 
Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis	   September 30, 2018 December 31, 2017  (Thousands of dollars) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total  Liabilities:  Nonqualified employee savings plans $ 15,957 – – 15,957 16,158 – – 16,158  Commodity derivative contracts – 44,601 – 44,601 – 39,093 – 39,093  $ 15,957 44,601 – 60,558 16,158 39,093 – 55,251 

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Loss (Tables)	9 Months Ended
	Sep. 30, 2018
Accumulated Other Comprehensive Loss [Abstract]
Components of Accumulated Other Comprehensive Loss	   Deferred  Retirement Loss on  Foreign and Interest  Currency Postretirement Rate  Translation Benefit Plan Derivative  (Thousands of dollars) Gains (Losses) Adjustments Hedges Total  Balance at December 31, 2017 $ (274,830) (178,987) (8,426) (462,243)  2018 components of other comprehensive income (loss):  Before reclassifications to income and retained earnings (53,805) (32,159) (1,815) (87,779)  Reclassifications to income – 10,498 1 1,756 2 12,254  Net other comprehensive loss (53,805) (21,661) (59) (75,525)  Balance at September 30, 2018 $ (328,635) (200,648) (8,485) (537,768) 1 Reclassifications before taxes of $13,111 are included in the computation of net per iodic benefit expense for the nine-month period ended September 30, 2018. See Note H for additional information. Related income taxes of $2,613 are included in Income t ax expense (benefit) for the nine-month period ended September 30, 2018. 2 Reclassifications before taxes of $2,222 are included in Interest expense, net, for the nine-month period ended September 30, 2018. Related income taxes of $466 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2018. See Note L for additional information.

Business Segments (Tables)

Business Segments (Tables)	9 Months Ended
	Sep. 30, 2018
Business Segments [Abstract]
Segment Information	  Three Months Ended Three Months Ended  Total Assets September 30, 2018 September 30, 2017  at September 30, External Income External Income  (Millions of dollars) 2018 Revenues (Loss) Revenues (Loss)  Exploration and production 1  United States $ 4,772.2 348.7 91.6 209.4 (11.2)  Canada 1,790.3 107.1 12.5 81.9 (3.2)  Malaysia 1,604.7 201.2 54.1 220.5 67.7  Other 183.4 19.9 1.3 – (11.0)  Total exploration and production 8,350.6 676.9 159.5 511.8 42.3  Corporate 3 1,654.9 (2.1) (63.8) (13.5) (108.6)  Assets/revenue/income from continuing operations 10,005.5 674.8 95.7 498.3 (66.3)  Discontinued operations, net of tax 21.1 – (1.8) – 0.4  Total $ 10,026.6 674.8 93.9 498.3 (65.9)   Nine Months Ended Nine Months Ended  September 30, 2018 September 30, 2017  External Income External Income  (Millions of dollars) Revenues (Loss) Revenues (Loss)  Exploration and production 1  United States $ 945.6 200.3 646.3 (21.8)  Canada 2 333.8 46.7 388.1 102.6  Malaysia 640.7 208.4 594.4 173.9  Other 19.9 (28.8) – (10.9)  Total exploration and production 1,940.0 426.6 1,628.8 243.8  Corporate 3 (61.4) (116.2) 54.4 (270.0)  Revenue/loss from continuing operations 1,878.6 310.4 1,683.2 (26.2)  Discontinued operations, net of tax – (2.7) – 1.2  Total $ 1,878.6 307.7 1,683.2 (25.0) 1 Additional details about results of oil and gas operations are presented in the tables on page s 30 and 31 . 2 Revenue for the nine months ended September 30, 2017 includes a pretax gain of $132.4 million related to the sale of Seal heavy oil assets in Canada. 3 In 2018, the Company reported realized and unrealized gains and losses on crude oil contracts in the Corporate segment (previously reported in the Exploration and production business) to reflect how segments are currently evaluated, how resources are allocated and how risk is managed by the Company. The 2017 amounts have been reclassified to reflect comparable disclosure.

New Accounting Principles and_2

New Accounting Principles and Recent Accounting Pronouncements (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Mar. 31, 2018	Sep. 30, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of certain tax effects from accumulated other comprehensive loss to retained earnings		$ (30,237)
Accounting Standards Update 2018-02 [Member] | Retirement and Postretirement Benefit Plan Adjustments [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of certain tax effects from accumulated other comprehensive loss to retained earnings	$ 28,400
Accounting Standards Update 2018-02 [Member] | Deferred Loss On Interest Rate Derivative Hedges [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of certain tax effects from accumulated other comprehensive loss to retained earnings	$ 1,800

Revenue from Contracts with C_4

Revenue from Contracts with Customers (Narrative) (Details)	9 Months Ended
	Sep. 30, 2018USD ($)contractitemsegmentagreement	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)
Disaggregation of Revenue [Line Items]
Number of geographic segments | segment	3
Number of revenue streams | item	3
Receivables from contracts with customers	$ 187,300,000		$ 203,400,000
Impairment losses on receivables or contract assets	0	$ 0
Revenue, remaining performance obligation	$ 0
Malaysia [Member]
Disaggregation of Revenue [Line Items]
Number of production sharing contracts | contract	9
Number of gas sale agreements | agreement	3

Revenue from Contracts with C_5

Revenue from Contracts with Customers (Disaggregation of Revenue) (Details) - USD ($) $ in Thousands	3 Months Ended			9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017		Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 659,806	$ 511,192	[1]	$ 1,921,910	$ 1,498,093	[1]
Gain (loss) on crude contracts	(2,223)	(13,573)	[1]	(69,349)	50,365	[1]
Other operating income	17,090	583		26,029	4,015
Gain on sale of assets	124	117		6	130,765
Total revenues	674,797	498,319	[1]	1,878,596	1,683,238	[1]
Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	546,424	417,193		1,605,251	1,199,420
Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	29,528	19,101		76,567	50,804
Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	83,854	74,898		240,092	247,869
United States Onshore [Member] | Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	224,714	143,527		606,186	437,504
United States Onshore [Member] | Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	16,993	11,114		42,363	29,838
United States Onshore [Member] | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	6,872	6,031		19,934	21,072
United States Offshore [Member] | Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	93,206	43,658		259,128	145,139
United States Offshore [Member] | Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3,438	1,679		7,998	4,804
United States Offshore [Member] | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3,306	2,541		9,068	7,922
Canada Onshore [Member] | Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	32,818	12,351		82,537	33,129
Canada Onshore [Member] | Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4,137	1,323		11,053	2,636
Canada Onshore [Member] | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	35,373	36,974		103,055	114,772
Canada Offshore [Member] | Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	34,789	31,639		137,420	107,516
Malaysia - Sarawak [Member] | Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	55,592	63,558		218,494	189,100
Malaysia - Sarawak [Member] | Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4,960	4,985		15,153	13,526
Malaysia - Sarawak [Member] | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	38,236	29,166		107,616	103,584
Malaysia - Block K [Member] | Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	102,149	122,460		298,330	287,032
Malaysia - Block K [Member] | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	67	$ 186		419	$ 519
Other Locations [Member] | Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 3,156			$ 3,156
[1]	Reclassified to conform to current presentation (see Note B).

Revenue from Contracts with C_6

Revenue from Contracts with Customers (Current Long-Term Contracts Outstanding) (Details)	Sep. 30, 2018MMcf / dBoe / d$ / Mcf
Alberta AECO [Member]
Disaggregation of Revenue [Line Items]
Fixed price (Cdn/MCF) | $ / Mcf	2.81
End Date, Q2, 2019 [Member] | United States [Member]
Disaggregation of Revenue [Line Items]
Approximate Net Volumes | Boe / d	4,000
End Date, Q3, 2019 [Member] | United States [Member]
Disaggregation of Revenue [Line Items]
Approximate Net Volumes | Boe / d	2,000
End Date, Q4, 2021, 2018 Deliveries [Member] | United States [Member]
Disaggregation of Revenue [Line Items]
Approximate Net Volumes | Boe / d	19,000
End Date, Q4, 2021, 2019-2021 Deliveries [Member] | United States [Member]
Disaggregation of Revenue [Line Items]
Approximate Net Volumes | Boe / d	13,000
End Date, Q4, 2020 [Member] | Canada [Member] | Alberta AECO [Member]
Disaggregation of Revenue [Line Items]
Approximate Net Volumes | MMcf / d	59
End Date, Q4, 2020 [Member] | Canada [Member] | USD Index Pricing [Member]
Disaggregation of Revenue [Line Items]
Approximate Net Volumes | MMcf / d	60
End Date, Q4, 2024 [Member] | Canada [Member] | USD Index Pricing [Member]
Disaggregation of Revenue [Line Items]
Approximate Net Volumes | MMcf / d	30
End Date, Q4, 2026 [Member] | Canada [Member] | USD Index Pricing [Member]
Disaggregation of Revenue [Line Items]
Approximate Net Volumes | MMcf / d	38

Property, Plant and Equipment_2

Property, Plant and Equipment (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended			9 Months Ended		12 Months Ended
	Jan. 31, 2017	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Apr. 01, 2017
Property Plant And Equipment [Line Items]
Total capitalized exploratory well costs		$ 210,845	$ 175,640	$ 178,384	$ 210,845	$ 178,384	$ 175,640	$ 148,500
Exploratory well costs capitalized more than one year		164,000			164,000
Proceeds from sales of property, plant and equipment					1,128	69,146
Gain (loss) on sale of assets		124		$ 117	6	130,765
Redetermination expense		11,332			11,332
Canadian Subsidiary [Member] | Athabasca Oil Corporation [Member]
Property Plant And Equipment [Line Items]
Cost of acquired assets								375,000
Cost of acquired assets, cash paid								206,700
Cost of acquired assets, carried interest								168,000
Carried interest paid		93,100			93,100
Western Canada [Member]
Property Plant And Equipment [Line Items]
Proceeds from sales of property, plant and equipment	$ 48,800
Asset retirement obligation settled	$ 85,900
Gain (loss) on sale of assets						132,400	132,400
Eagle Ford Shale [Member]
Property Plant And Equipment [Line Items]
Proceeds from sales of property, plant and equipment							19,600
Gain (loss) on sale of assets							$ 0
Montney Natural Gas Fields [Member]
Property Plant And Equipment [Line Items]
Proceeds from sales of property, plant and equipment								414,100
Deferred gain on sale of property		171,000			$ 171,000			$ 187,000
Deferred gain, period of recognition					18 years
Amortization of deferred gain					$ 5,700	$ 5,300
Brunei [Member]
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year		55,900			55,900
Vietnam [Member]
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year		59,800			59,800
United States [Member]
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year		27,400			27,400
Malaysia [Member]
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year		$ 20,900			$ 20,900
Kaybob Duvernay Lands, Alberta [Member] | Canadian Subsidiary [Member]
Property Plant And Equipment [Line Items]
Interest in assets acquired								70.00%
Placid Montney Lands, Alberta [Member] | Canadian Subsidiary [Member]
Property Plant And Equipment [Line Items]
Interest in assets acquired								30.00%
Kakap Field Block K Malaysia [Member]
Property Plant And Equipment [Line Items]
Working interest		6.37%			6.37%				6.67%
Unitization and Unit Operating Agreement [Member] | Kakap Field Block K Malaysia [Member]
Property Plant And Equipment [Line Items]
Redetermination expense								$ 39,100
Redetermination expense, net of tax								$ 24,100
Redetermination liability		$ 17,300			$ 17,300
Unitization Framework Agreement [Member] | Kakap Field Block K Malaysia [Member]
Property Plant And Equipment [Line Items]
Redetermination expense			$ 15,000

Property, Plant And Equipment_3

Property, Plant And Equipment (Net Changes in Capitalized Exploratory Well Costs) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Property, Plant And Equipment [Abstract]
Beginning balance at January 1	$ 175,640	$ 148,500
Additions pending the determination of proved reserves	41,940	51,614
Reclassifications to proved properties based on the determination of proved reserves	(2,214)	(13,370)
Capitalized exploratory well costs charged to expense	(4,521)	(8,360)
Ending balance at September 30	$ 210,845	$ 178,384

Property, Plant And Equipment_4

Property, Plant And Equipment (Aging of Capitalized Exploratory Well Costs) (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2018USD ($)item	Sep. 30, 2017USD ($)item	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 210,845	$ 178,384	$ 175,640	$ 148,500
No. of Wells	10	13
No. of Projects	6	6
Zero to One Year [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 46,813	$ 41,609
No. of Wells	1	3
No. of Projects	1	2
One to Two Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 41,051	$ 8,430
No. of Wells	3	2
No. of Projects	2	2
Two to Three Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 5,208	$ 43,197
No. of Wells	1	1
No. of Projects	1	1
Three Years or More [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 117,773	$ 85,148
No. of Wells	5	7
No. of Projects	2	1

Discontinued Operations and A_3

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, 2018	Sep. 30, 2017		Sep. 30, 2018	Sep. 30, 2017
Discontinued Operations and Assets Held for Sale [Abstract]
Revenues		$ 598		$ 6	$ 853
Income (loss) before income taxes	$ (1,815)	425		(2,650)	1,177
Income tax benefit
Income (loss) from discontinued operations	$ (1,815)	$ 425	[1]	$ (2,650)	$ 1,177	[1]
[1]	Reclassified to conform to current presentation (see Note B).

Discontinued Operations and A_4

Discontinued Operations and Assets Held for Sale (Major Categories of Assets and Liabilities Reflected as Held for Sale) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable	$ 274,193	$ 243,472
Total current assets held for sale	21,140	22,929
Accounts payable	622,577	595,916
Total current liabilities associated with assets held for sale	2,802	3,530
UK Refining And Marketing Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash	17,409	16,631
Accounts receivable	3,731	6,298
Total current assets held for sale	21,140	22,929
Accounts payable	143	837
Refinery decommissioning cost	2,659	2,693
Total current liabilities associated with assets held for sale	$ 2,802	$ 3,530

Financing Arrangements and De_2

Financing Arrangements and Debt (Narrative) (Details)	9 Months Ended
	Sep. 30, 2018USD ($)
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	$ 10,500,000
Capital lease obligations, noncurrent	128,500,000
2016 Senior Unsecured Guaranteed Credity Facility [Member]
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity	$ 1,100,000,000
Credit facility, expiration date	Aug. 1, 2021
Amount outstanding	$ 0
2016 Senior Unsecured Guaranteed Credity Facility [Member] | Eurodollar [Member]
Line of Credit Facility [Line Items]
Interest rate	5.0625%
2016 Senior Unsecured Guaranteed Credity Facility [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Amount outstanding	$ 28,000,000

Other Financial Information (No

Other Financial Information (Noncash Opearting Working Capital (Increase) Decrease) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Other Financial Information [Abstract]
(Increase) decrease in accounts receivable	$ (31,178)	$ 90,614
Decrease in inventories	16,732	5,869
(Increase) decrease in prepaid expenses	(8,695)	25,285
Increase (decrease) in accounts payable and accrued liabilities	17,946	(115,977)
Increase (decrease) in income taxes payable	2,645	(4,721)
Net (increase) decrease in noncash operating working capital	(2,550)	1,070
Cash income taxes paid, net of refunds	77,508	25,118
Interest paid, net of amounts capitalized of $3,719 in 2018 and $3,338 in 2017	115,009	95,899
Asset retirement costs capitalized	2,907	38,992
(Increase) decrease in capital expenditure accrual	(751)	42,403
Interest paid, amounts capitalized	$ 3,719	$ 3,338

Employee and Retiree Benefit _3

Employee and Retiree Benefit Plans (Narrative) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)
Employee and Retiree Benefit Plans [Abstract]
Contributions to benefit plans	$ 22.2
Expected benefit plan contributions to be made during the year	$ 7.6

Employee and Retiree Benefit _4

Employee and Retiree Benefit Plans (Components of Net Periodic Benefit Expense) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 2,252	$ 2,037	$ 6,761	$ 6,099
Interest cost	6,716	7,261	20,160	20,267
Expected return on plan assets	(7,476)	(8,070)	(22,435)	(21,730)
Amortization of prior service cost (credit)	254	259	767	767
Recognized actuarial loss	5,197	3,610	15,593	10,673
Net periodic benefit expense	6,943	5,097	20,846	16,076
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	492	427	1,479	1,276
Interest cost	874	966	2,622	2,899
Amortization of prior service cost (credit)	(10)	(18)	(29)	(55)
Net periodic benefit expense	$ 1,356	$ 1,375	$ 4,072	$ 4,120

Incentive Plans (Narrative) (De

Incentive Plans (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	Mar. 09, 2018	Mar. 01, 2018	Feb. 20, 2018	Feb. 06, 2018	Feb. 28, 2018	Mar. 31, 2018	Sep. 30, 2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Threshold of deductible compensation for executive officers							$ 1
2012 Long-Term Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Long term plan expiration year							2,022
Maximum number of shares available for issuance							8,700,000
Maximum number of shares available for issuance, annual rate							1.00%
Performance-Based RSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grants in period						905,500
Stock-based compensation, fair value assumption model							Monte Carlo valuation model
Performance-Based RSUs [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per share at grant date						$ 28.27
Performance-Based RSUs [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per share at grant date						$ 30.56
Time-Based RSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grants in period						736,000
Fair value per share at grant date		$ 25.69	$ 26.56	$ 28.42
Time-Based RSUs [Member] | Director [Member] | Non-Employee Director Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grants in period					77,803
Fair value per share at grant date					$ 28.28
Vesting scheme							These units are scheduled to vest on the third anniversary of the date of grant.
Cash-Settled RSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grants in period	29,000			715,100

Incentive Plans (Share-Based Pl

Incentive Plans (Share-Based Plans, Amounts Recognized) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Incentive Plans [Abstract]
Compensation charged against income before tax benefit	$ 36,348	$ 28,264
Related income tax benefit recognized in income	$ 5,532	$ 8,695

Earnings per Share (Weighted-Av

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, 2018	Sep. 30, 2017		Sep. 30, 2018	Sep. 30, 2017
Earnings per Share [Abstract]
Basic method	173,047,246	172,572,873	[1]	172,949,450	172,509,418	[1]
Dilutive stock options and restricted stock units	1,128,021	0	[2]	1,252,310	0	[2]
Diluted method	174,175,267	172,572,873	[1]	174,201,760	172,509,418	[1]
[1]	Reclassified to conform to current presentation (see Note B).
[2]	Due to a net loss in the three-month and nine-month periods ended September 30, 2017, no unvested stock awards were included in the computation of diluted earnings per shares because the effect would have been anti-dilutive.

Earnings per Share (Anti Diluti

Earnings per Share (Anti Dilutive Securities Not Included in Computation of Diluted EPS) (Details) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Earnings per Share [Abstract]
Antidilutive stock options excluded from diluted shares (in shares)	2,870,549	5,257,718	3,544,087	5,578,495
Weighted average price of these options (per share)	$ 54.06	$ 46.46	$ 50.49	$ 46.86

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Income Tax Disclosure [Line Items]
U.S. statutory rate		21.00%	35.00%
Operating loss carryforwards		$ 0	$ 0
Valuation allowance		228,200,000
Repatriation tax payable		$ 36,000,000
Decrease in income tax expense	$ 156,000,000
Repatriation tax payment period		8 years
United States [Member]
Income Tax Disclosure [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions		2,015
Canada [Member]
Income Tax Disclosure [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions		2,012
Malaysia [Member]
Income Tax Disclosure [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions		2,011
United Kingdom [Member]
Income Tax Disclosure [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions		2,016
Scenario, Adjustment [Member]
Income Tax Disclosure [Line Items]
Deferred tax liabilities	$ (36,000,000)

Income Taxes (Effective Income

Income Taxes (Effective Income Tax Rates) (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Taxes [Abstract]
Effective income tax rate	34.80%	(4.30%)	4.80%	137.70%

Financial Instruments and Ris_3

Financial Instruments and Risk Management (Narrative) (Details) $ in Millions	3 Months Ended	9 Months Ended
	Dec. 31, 2018USD ($)	Sep. 30, 2018USD ($)bbl / dcontractitem$ / bbl	Sep. 30, 2017USD ($)bbl / dcontract	Dec. 31, 2017item
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of foreign currency derivatives | contract		0	0
Amount of loss reclassified to interest expense		$ 2.2	$ 2.2
Number of offsetting positions | item		0		0
Scenario, Forecast [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative loss	$ 0.7
Commodity Derivative Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Daily production commitment (barrels per day) | bbl / d		21,000
Average price | $ / bbl		54.88
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		$ 8.5
Income taxes on deferred loss on fair value of interest rate derivative contracts		$ 2.3
Contracts Maturing In 2017 [Member] | Commodity Derivative Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Daily production commitment (barrels per day) | bbl / d			22,000
Contracts Maturing In 2018 [Member] | Commodity Derivative Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Daily production commitment (barrels per day) | bbl / d			6,000
Notes Due 2022 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Debt instrument term		10 years

Financial Instruments and Ris_4

Financial Instruments and Risk Management (Fair Value of Derivative Instruments Not Designated as Hedging Instruments) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Nondesignated [Member] | Commodity Derivative Contracts [Member] | Accounts Payable [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ (44,601)	$ (39,093)

Financial Instruments and Ris_5

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, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ (2,223)	$ (13,573)	$ (69,349)	$ 50,438
Commodity Derivative Contracts [Member] | Gain (Loss) on Crude Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ (2,223)	$ (13,573)	$ (69,349)	50,365
Foreign Exchange Derivative Contracts [Member] | Interest And Other Income (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)				$ 73

Financial Instruments and Ris_6

Financial Instruments and Risk Management (Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis) (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	$ 60,558	$ 55,251
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	15,957	16,158
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	44,601	39,093
Non-Qualified Employee Savings Plans [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	15,957	16,158
Non-Qualified Employee Savings Plans [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	15,957	16,158
Commodity Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	44,601	39,093
Commodity Derivative Contracts [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	$ 44,601	$ 39,093

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Loss (Components of Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance				$ (462,243)
Before reclassifications to income and retained earnings				(87,779)
Reclassifications to income				12,254
Net other comprehensive income		$ 37,355	$ 104,088	(75,525)	$ 202,708
Ending Balance		(537,768)		(537,768)
Foreign Currency Translation Gains (Losses) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance				(274,830)
Before reclassifications to income and retained earnings				(53,805)
Net other comprehensive income				(53,805)
Ending Balance		(328,635)		(328,635)
Retirement and Postretirement Benefit Plan Adjustments [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance				(178,987)
Before reclassifications to income and retained earnings				(32,159)
Reclassifications to income	[1]			10,498
Net other comprehensive income				(21,661)
Ending Balance		(200,648)		(200,648)
Reclassifications before taxes, included in net periodic benefit expense				13,111
Reclassifications, income tax expense				2,613
Deferred Loss On Interest Rate Derivative Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance				(8,426)
Before reclassifications to income and retained earnings				(1,815)
Reclassifications to income	[2]			1,756
Net other comprehensive income				(59)
Ending Balance		$ (8,485)		(8,485)
Reclassifications before taxes, included in net periodic benefit expense				2,222
Reclassifications income tax, included in interest expense				$ 466
[1]	Reclassifications before taxes of $13,111 are included in the computation of net periodic benefit expense for the nine-month period ended September 30, 2018. See Note H for additional information. Related income taxes of $2,613 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2018.
[2]	Reclassifications before taxes of $2,222 are included in Interest expense, net, for the nine-month period ended September 30, 2018. Related income taxes of $466 are included in Income tax expense (benefit) for the nine-month period ended September 30, 2018. See Note L for additional information.

Environmental and Other Conti_2

Environmental and Other Contingencies (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended	45 Months Ended
	Mar. 31, 2018	Sep. 30, 2018	Dec. 31, 2015	Sep. 30, 2018
Environmental and Other Contingencies [Abstract]
Remediation costs	$ 3.8		$ 43.9
Payments for environmental liabilities				$ 43.1
Remediation accrual		$ 4.7		$ 4.7
Proceeds from insurance settlement		$ 25

Commitments (Narrative) (Detail

Commitments (Narrative) (Details) - Natural Gas Per Thousand Cubic Feet [Member] - July 2018 to December 2020 [Member]	Sep. 30, 2018MMcf / D$ / Mcf
Commitments and Contingencies Disclosure [Line Items]
Notional amount, per day | MMcf / D	59
Swap price (per share) | $ / Mcf	2.81

Business Segments (Segment Info

Business Segments (Segment Information) (Details) - USD ($) $ in Thousands		3 Months Ended			9 Months Ended			12 Months Ended
		Sep. 30, 2018	Sep. 30, 2017		Sep. 30, 2018	Sep. 30, 2017		Dec. 31, 2017
Segment Reporting Information [Line Items]
Total Assets		$ 10,026,620			$ 10,026,620			$ 9,860,942
External Revenues		674,797	$ 498,319	[1]	1,878,596	$ 1,683,238	[1]
Net income (loss)		93,944	(65,893)	[1]	307,715	(25,000)	[1]
Gain (loss) on sale of assets		124	117		6	130,765
Continuing Operations [Member]
Segment Reporting Information [Line Items]
Total Assets		10,005,500			10,005,500
External Revenues		674,800	498,300		1,878,600	1,683,200
Net income (loss)		95,700	(66,300)		310,400	(26,200)
Discontinued Operations [Member]
Segment Reporting Information [Line Items]
Total Assets		21,100			21,100
Net income (loss)		(1,800)	400		(2,700)	1,200
Corporate [Member]
Segment Reporting Information [Line Items]
Total Assets	[2]	1,654,900			1,654,900
External Revenues	[2]	(2,100)	(13,500)		(61,400)	54,400
Net income (loss)	[2]	(63,800)	(108,600)		(116,200)	(270,000)
Exploration And Production Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total Assets	[3]	8,350,600			8,350,600
External Revenues	[3]	676,900	511,800		1,940,000	1,628,800
Net income (loss)	[3]	159,500	42,300		426,600	243,800
Exploration And Production Segment [Member] | Operating Segments [Member] | United States [Member]
Segment Reporting Information [Line Items]
Total Assets	[3]	4,772,200			4,772,200
External Revenues	[3]	348,700	209,400		945,600	646,300
Net income (loss)	[3]	91,600	(11,200)		200,300	(21,800)
Exploration And Production Segment [Member] | Operating Segments [Member] | Canada [Member]
Segment Reporting Information [Line Items]
Total Assets	[3],[4]	1,790,300			1,790,300
External Revenues	[3],[4]	107,100	81,900		333,800	388,100
Net income (loss)	[3],[4]	12,500	(3,200)		46,700	102,600
Exploration And Production Segment [Member] | Operating Segments [Member] | Malaysia [Member]
Segment Reporting Information [Line Items]
Total Assets	[3]	1,604,700			1,604,700
External Revenues	[3]	201,200	220,500		640,700	594,400
Net income (loss)	[3]	54,100	67,700		208,400	173,900
Exploration And Production Segment [Member] | Operating Segments [Member] | Other Regions [Member]
Segment Reporting Information [Line Items]
Total Assets	[3]	183,400			183,400
External Revenues	[3]	19,900			19,900
Net income (loss)	[3]	$ 1,300	$ (11,000)		$ (28,800)	(10,900)
Western Canada [Member]
Segment Reporting Information [Line Items]
Gain (loss) on sale of assets						$ 132,400		$ 132,400
[1]	Reclassified to conform to current presentation (see Note B).
[2]	In 2018, the Company reported realized and unrealized gains and losses on crude oil contracts in the Corporate segment (previously reported in the Exploration and production business) to reflect how segments are currently evaluated, how resources are allocated and how risk is managed by the Company. The 2017 amounts have been reclassified to reflect comparable disclosure.
[3]	Additional details about results of oil and gas operations are presented in the tables on pages 30 and 31.
[4]	Revenue for the nine months ended September 30, 2017 includes a pretax gain of $132.4 million related to the sale of Seal heavy oil assets in Canada.

Subsequent Events (Details)

Subsequent Events (Details) - Scenario, Forecast [Member] $ in Millions	3 Months Ended
	Dec. 31, 2018USD ($)
Joint Venture With Petrobras [Member]
Subsequent Event [Line Items]
Cash consideration	$ 900
Joint Venture With Petrobras [Member] | Price And Production Threshholds [Member]
Subsequent Event [Line Items]
Contingent consideration, maximum	150
Joint Venture With Petrobras [Member] | Oil Recovery Projects [Member]
Subsequent Event [Line Items]
Contingent consideration, maximum	$ 50
Murphy Exploration And Production Company - USA [Member] | Joint Venture With Petrobras [Member] | Joint Venture With Petrobras [Member]
Subsequent Event [Line Items]
Parent ownership interest	80.00%
Petrobas America Inc [Member] | Joint Venture With Petrobras [Member]
Subsequent Event [Line Items]
Ownership interest	20.00%