Murphy Oil (MUR) 10-Q 9 Aug 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Jul. 31, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
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		173,047,246

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 901,308	$ 964,988
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2018 and 2017	258,366	243,472
Inventories, at lower of cost or market	91,376	105,127
Prepaid expenses	42,638	35,087
Assets held for sale	21,667	22,929
Total current assets	1,315,355	1,371,603
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,625,179 in 2018 and $12,280,741 in 2017	8,208,142	8,220,031
Deferred income taxes	370,641	211,543
Deferred charges and other assets	51,311	57,765
Total assets	9,945,449	9,860,942
Current liabilities
Current maturities of long-term debt	9,674	9,902
Accounts payable	632,072	595,916
Income taxes payable	91,072	44,604
Other taxes payable	18,683	23,574
Other accrued liabilities	148,910	156,681
Liabilities associated with assets held for sale	3,146	3,530
Total current liabilities	903,557	834,207
Long-term debt, including capital lease obligation	2,897,345	2,906,520
Deferred income taxes	127,350	159,098
Asset retirement obligations	693,300	709,299
Deferred credits and other liabilities	652,259	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	898,126	917,665
Retained earnings	5,402,732	5,245,242
Accumulated other comprehensive loss	(575,123)	(462,243)
Treasury stock	(1,249,162)	(1,275,529)
Total stockholders' equity	4,671,638	4,620,191
Total liabilities and stockholders' equity	$ 9,945,449	$ 9,860,942

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	Jun. 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	$ 12,625,179	$ 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			6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	[1]	Jun. 30, 2018	Jun. 30, 2017	[1]
Revenues
Revenue from sales to customers	$ 655,150	$ 477,560		$ 1,262,104	$ 986,595
(Loss) gain on crude contracts	(37,624)	26,861		(67,126)	63,938
Gain on sale of assets and other income	668	3,858		8,821	134,386
Total revenues	618,194	508,279		1,203,799	1,184,919
Costs and expenses
Lease operating expenses	136,589	111,179		273,085	233,321
Severance and ad valorem taxes	12,876	10,742		25,033	21,955
Exploration expenses, including undeveloped lease amortization	19,145	20,201		48,073	48,864
Selling and general expenses	57,800	52,809		109,217	102,774
Depreciation, depletion and amortization	237,997	234,992		468,730	471,146
Accretion of asset retirement obligations	11,028	10,428		20,942	20,984
Other expense (benefit)	659	6,377		(10,389)	8,534
Total costs and expenses	476,094	446,728		934,691	907,578
Operating income from continuing operations	142,100	61,551		269,108	277,341
Other income (loss)
Interest and other income (loss)	(15,051)	(38,305)		33	(54,616)
Interest expense, net	(44,723)	(45,145)		(89,772)	(89,742)
Total other loss	(59,774)	(83,450)		(89,739)	(144,358)
Income (loss) from continuing operations before income taxes	82,326	(21,899)		179,369	132,983
Income tax expense (benefit)	36,410	(4,545)		(35,237)	92,842
Income (loss) from continuing operations	45,916	(17,354)		214,606	40,141
Income (loss) from discontinued operations, net of income taxes	(398)	(217)		(835)	752
NET INCOME (LOSS)	$ 45,518	$ (17,571)		$ 213,771	$ 40,893
INCOME (LOSS) PER COMMON SHARE - BASIC
Continuing operations	$ 0.26	$ (0.10)		$ 1.25	$ 0.23
Discontinued operations				(0.01)	0.01
Net Income (Loss)	0.26	(0.10)		1.24	0.24
INCOME (LOSS) PER COMMON SHARE - DILUTED
Continuing operations	0.26	(0.10)		1.23	0.23
Discontinued operations				(0.01)	0.01
Net Income (Loss)	0.26	(0.10)		1.22	0.24
Cash dividends per Common share	$ 0.25	$ 0.25		$ 0.50	$ 0.50
Average Common shares outstanding
Basic	173,042,626	172,557,978		172,907,537	172,482,223
Diluted	173,982,620	172,557,978		174,927,062	173,016,664
[1]	Reclassified to conform to current presentation (see Notes A and B).

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended			6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017		Jun. 30, 2018	Jun. 30, 2017
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME [Abstract]
Net income	$ 45,518	$ (17,571)	[1]	$ 213,771	$ 40,893	[1]
Other comprehensive income (loss), net of tax
Net (loss) gain from foreign currency translation	(34,910)	70,220		(87,185)	92,884
Retirement and postretirement benefit plans	3,938	2,386		7,108	4,773
Deferred loss on interest rate hedges reclassified to interest expense	586	481		1,171	963
Reclassification of certain tax effects to retained earnings				(30,237)
Other				(3,737)
Other comprehensive (loss) income	(30,386)	73,087		(112,880)	98,620
COMPREHENSIVE INCOME	$ 15,132	$ 55,516		$ 100,891	$ 139,513
[1]	Reclassified to conform to current presentation (see Notes A and B).

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands		3 Months Ended			6 Months Ended			12 Months Ended
		Jun. 30, 2018	Jun. 30, 2017		Jun. 30, 2018	Jun. 30, 2017		Dec. 31, 2017	Dec. 31, 2016
Operating Activities
Net income		$ 45,518	$ (17,571)	[1]	$ 213,771	$ 40,893	[1]
Adjustments to reconcile net income to net cash provided by continuing operations activities:
Loss (Income) from discontinued operations		398	217	[1]	835	(752)	[1]
Depreciation, depletion and amortization		237,997	234,992	[1]	468,730	471,146	[1]
Dry hole costs (credits)					(11)	1,904
Amortization of undeveloped leases					22,774	20,306
Accretion of asset retirement obligations		11,028	10,428	[1]	20,942	20,984	[1]
Deferred income tax (benefit) charge					(156,489)	33,130
Pretax (gain) loss from disposition of assets		(220)	1,333		118	(130,648)
Net decrease in noncash operating working capital					85,440	42,581
Other operating activities, net					(31,564)	91,918
Net cash provided by continuing operations activities					624,546	591,462
Investing Activities
Property additions and dry hole costs					(615,144)	(431,654)
Proceeds from sales of property, plant and equipment					623	64,303
Purchases of investment securities	[2]					(212,661)
Proceeds from maturity of investment securities	[2]					284,193
Net cash required by investing activities					(614,521)	(295,819)
Financing Activities
Capital lease obligation payments					(4,648)	(11,983)
Withholding tax on stock-based incentive awards					(6,922)	(7,081)
Cash dividends paid					(86,517)	(86,278)
Net cash provided by financing activities					(98,087)	(105,342)
Effect of exchange rate changes on cash and cash equivalents					24,382	(4,611)
Net increase (decrease) in cash and cash equivalents								$ (63,680)	$ 185,690
Cash and cash equivalents at beginning of period					964,988	872,797		872,797
Cash and cash equivalents at end of period		$ 901,308	$ 1,058,487		$ 901,308	$ 1,058,487		$ 964,988	$ 872,797
[1]	Reclassified to conform to current presentation (see Notes A and B).
[2]	Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

CONSOLIDATED STATEMENTS OF CAS7

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical)	6 Months Ended
	Jun. 30, 2018	Jun. 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					92,884		$ 92,884
Net income for the period				40,893			40,893	[1]
Restricted stock transactions and other			(26,483)
Cash dividends				(86,278)
Retirement and postretirement benefit plans, net of income taxes					4,773		4,773
Sale of stock under employee stock purchase plan						145
Stock-based compensation			13,302
Other			(76)
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes					963		963
Awarded restricted stock, net of forfeitures						20,886
Balance at end of period at Jun. 30, 2017		195,056	903,542	5,684,211	(529,592)	(1,275,529)	4,977,688
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					(87,185)		(87,185)
Net income for the period				213,771			213,771
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				(86,518)
Retirement and postretirement benefit plans, net of income taxes					7,108		7,108
Stock-based compensation			13,402
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes					1,171		1,171
Awarded restricted stock, net of forfeitures						26,367
Balance at end of period at Jun. 30, 2018		$ 195,065	$ 898,126	$ 5,402,732	$ (575,123)	$ (1,249,162)	$ 4,671,638
[1]	Reclassified to conform to current presentation (see Notes A and B).

CONSOLIDATED STATEMENTS OF STO9

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	Jun. 30, 2018	Jun. 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	6 Months Ended
	Jun. 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 produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide. INTERIM FINANCIAL STATEMENTS – In the opinion of Murphy's management, the unaudited financial statements presented herein include all accruals necessary to present fairly the Company's financial position at June 30, 2018 and December 31, 2017 , and the results of operations, cash flows and changes in stockholders’ equity for the interim periods ended June 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 six-month period ended June 30, 2018 are not necessarily indicative of future results. Beginning in the period ended September 30, 2017, certain reclassifications in presentation have been made to the Consolidated Statements of Operations. The Company now presents a separate “Operating income (loss) from continuing operations” subtotal on the Consolidated Statements of Operations. Additionally, “Interest and other income (loss),” which includes foreign exchange gains and losses, has been reclassified from a component of total revenues and is now presented below Operating income (loss) from continuing operations. “Interest expense” and “Capitalized interest” have also been combined into the “Interest expense, net” line item and is now presented below “Operating income (loss) from continuing operations.” Previously reported periods have been reclassified to conform to the current period presentation. These reclassifications did not impact previously reported Income from continuing operations before income taxes, Income from continuing operations, or Net income. 

New Accounting Principles and R

New Accounting Principles and Recent Accounting Pronouncements	6 Months Ended
	Jun. 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 occured 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.   Note B – New Accounting Principles and Recent Accounting Pronouncements ( Contd .) Accounting Principles Adopted (Cont.) 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. 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 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. 

Revenue from Contracts with Cus

Revenue from Contracts with Customers	6 Months Ended
	Jun. 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 Company 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 . Nature of Goods and Services The Company explores for and produces crude oil, natural gas and natural gas liquids (collectively oil and gas) worldwide. The Company’s revenue from sales of oil and gas production activities are 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. Note C – Revenue from Contracts with Customers (Contd.) 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 areas except for the unitized Kakap-Gumusut 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 June 30, 2018 and 2017, the Company recognized $655.2 million and $477.6 million, respectively, from contracts with customers for the sales of oil, natural gas liquids and natural gas. For the six months ended June 30, 2018 and 2017, the Company recognized $1,262.1 million and $986.6 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 Six Months Ended  June 30, June 30,  (Thousands of dollars) 2018 2017 2018 2017  Net crude oil and condensate revenue  United States – Onshore $ 198,823 143,684 381,472 293,671  – Offshore 94,393 47,669 165,922 101,481  Canada – Onshore 28,425 11,658 49,719 20,778  – Offshore 48,316 38,863 102,631 75,877  Malaysia – Sarawak 85,596 59,758 162,902 125,542  – Block K 101,609 76,741 196,181 164,572  Total crude oil and condensate revenue 557,162 378,373 1,058,827 781,921   Net natural gas liquids revenue  United States – Onshore 13,236 9,077 25,370 18,724  – Offshore 2,920 1,209 4,559 3,125  Canada – Onshore 3,448 881 6,916 1,313  Malaysia – Sarawak 4,002 3,358 10,193 8,541  Total natural gas liquids revenue 23,606 14,525 47,038 31,703   Net natural gas revenue  United States – Onshore 6,291 8,006 13,062 15,041  – Offshore 2,826 2,718 5,762 5,381  Canada – Onshore 28,089 37,951 67,683 77,798  Malaysia – Sarawak 36,997 35,829 69,380 74,418  – Block K 179 158 352 333  Total natural gas revenue 74,382 84,662 156,239 172,971  Total revenue from contracts with customers 655,150 477,560 1,262,104 986,595   Gain (loss) on crude contracts (37,624) 26,861 (67,126) 63,938  Other operating income (loss) 448 5,191 8,939 3,738  Gain (loss) on sale of assets 220 (1,333) (118) 130,648  Total revenue $ 618,194 508,279 1,203,799 1,184,919  Contract Balances and Asset Recognition As of June 30, 2018, and December 31, 2017, receivables from contracts with customers, net of royalties and associated payables, on the balance sheet, were $190.7 million and $203.4 million, respectively. Payment terms for Murphy’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 June 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 Murphy’s 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 June 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 June 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	6 Months Ended
	Jun. 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 June 30, 2018 , the Company had total capitalized exploratory well costs pending the determination of proved reserves of $ 206.4 million. The following table reflects the net changes in capitalized exploratory well costs during the six -month periods ended June 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 30,731 48,764  Reclassifications to proved properties based on the determination of proved reserves – (13,370)  Capitalized exploratory well costs charged to expense – (8,360)  Balance at June 30 $ 206,371 175,534 There were no capitalized well costs charged to expense during the first six months of 2018. The capitalized well costs charged to expense during the first six 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.     June 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 $ 34,779 2 2 $ 57,900 3 3  One to two years 35,934 2 1 53,023 3 3  Two to three years 50,272 2 2 – – –  Three years or more 85,386 7 1 64,611 6 –  $ 206,371 13 6 $ 175,534 12 6  Of the $171.6 million of exploratory well costs capitalized more than one year at June 30, 2018, $70.4 million is in Brunei, $52.6 million is in Vietnam, $27.8 million is in the U.S. and $20.8 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 was approximately $19.6 million. There were no gains or losses recorded related to these non-core Eagle Ford Shale sales. 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 $3.8 million and $3.4 million of the deferred gain during the first six months of 2018 and 2017, respectively. The remaining deferred gain of $170.2 million was included as a component of Deferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of June 30, 2018 . Note D – Property, Plant and Equipment (Contd.) Acquisitions In 2016, a Canadian subsidiary of Murphy Oil acquired a 70% operated working interest (WI) of Athabasca Oil Corporation’s (Athabasca) production, acreage, infrastructure and facilities in the Kaybob Duvernay lands, and a 30% non-operated WI of Athabasca’s production, acreage, infrastructure and facilities in the liquids rich Placid Montney lands in Alberta, the majority of which was unproved. Under the terms of the joint venture, the total consideration amounts to approximately $375.0 million of which Murphy paid $206.7 million in cash at closing, subject to normal closing adjustments, and an additional $168.0 million in the form of a carried interest on the Kaybob Duvernay property. As of June 30, 2018 , $75.4 million of the carried interest had been paid. The carry is to be paid over a period up to 2021. 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 June 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 expense of $15.0 million ( $9.3 million after tax) related to Company’s revised working interest. The remaining redetermination liability of $15.0 million was included as a component of Other current liabilities in the Company’s Consolidated Balance Sheet as of June 30, 2018 .

Discontinued Operations and Ass

Discontinued Operations and Assets Held for Sale	6 Months Ended
	Jun. 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 six-month periods ended June 30, 2018 and 2017 were as follows:    Three Months Six Months  Ended June 30, Ended June 30,  (Thousands of dollars) 2018 2017 2018 2017  Revenues $ 6 126 6 256  Income (loss) before income taxes (398) (217) (835) 752  Income tax benefit – – – –  Income (loss) from discontinued operations $ (398) (217) (835) 752  The following table presents the carrying value of the major categories of assets and liabilities of U.K. refining and marketing operations reflected as held for sale on the Company’s Consolidated Balance Sheets at June 30, 2018 and December 31, 2017 .    June 30, December 31,  (Thousands of dollars) 2018 2017  Current assets  Cash $ 14,609 16,631  Accounts receivable 7,058 6,298  Total current assets held for sale $ 21,667 22,929  Current liabilities  Accounts payable $ 488 837  Refinery decommissioning cost 2,658 2,693  Total current liabilities associated with assets held for sale $ 3,146 3,530 

Financing Arrangements and Debt

Financing Arrangements and Debt	6 Months Ended
	Jun. 30, 2018
Financing Arrangements and Debt [Abstract]
Financing Arrangements and Debt	Note F – Financing Arrangements and Debt At June 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 June 30, 2018 , the Company had no outstanding borrowings under the 2016 facility, however, there were $27.9 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 June 30, 2018, the applicable base interest rate would have been 5.5375% . At June 30, 2018 , the Company was in compliance with all covenants related to the 2016 facility. The Company also has a shelf registration statement on file with the U.S. Securities and Exchange Commission that permits the offer and sale of debt and/or equity securities through October 2018. The Company expects to renew the shelf registration in the second half of 2018. The Company and its partners are parties to a 25 -year lease of production equipment at the Kakap field offshore Malaysia. The lease has been accounted for as a capital lease, and payments under the agreement are to be made over a 15 -year period through March 2029 . Current maturities of long-term debt and long-term debt on the Consolidated Balance Sheet include d $9.7 million and $122.9 million, respectively, associated with this lease at June 30, 2018 .

Other Financial Information

Other Financial Information	6 Months Ended
	Jun. 30, 2018
Other Financial Information [Abstract]
Other Financial Information	 Note G – Other Financial Information Additional disclosures regarding cash flow activities are provided below.    Six Months Ended June 30,  (Thousands of dollars) 2018 2017  Net (increase) decrease in operating working capital other than cash and cash equivalents:  (Increase) decrease in accounts receivable $ (15,528) 125,283  Decrease in inventories 16,929 5,918  (Increase) decrease in prepaid expenses (7,890) 9,206  Increase (decrease) in accounts payable and accrued liabilities 49,311 (136,500)  Increase in income taxes payable 42,618 38,674  Net decrease in noncash operating working capital $ 85,440 42,581  Supplementary disclosures:  Cash income taxes paid, net of refunds $ 36,618 9,448  Interest paid, net of amounts capitalized of $2,377 in 2018 and $2,449 in 2017 79,279 72,136   Non-cash investing activities:  Asset retirement costs capitalized $ 1,608 797  Decrease in capital expenditure accrual 39,322 43,370  

Employee and Retiree Benefit Pl

Employee and Retiree Benefit Plans	6 Months Ended
	Jun. 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 six-month periods ended June 30, 2018 and 2017 .      Three Months Ended June 30,  Pension Benefits Other Postretirement Benefits  (Thousands of dollars) 2018 2017 2018 2017  Service cost $ 2,254 2,030 493 424  Interest cost 6,707 6,287 874 967  Expected return on plan assets (7,453) (6,475) – –  Amortization of prior service cost (credit) 256 254 (9) (19)  Recognized actuarial loss 5,181 3,509 – –  Net periodic benefit expense $ 6,945 5,605 1,358 1,372   Six Months Ended June 30,  Pension Benefits Other Postretirement Benefits  (Thousands of dollars) 2018 2017 2018 2017  Service cost $ 4,509 4,062 987 849  Interest cost 13,444 13,006 1,748 1,933  Expected return on plan assets (14,959) (13,660) – –  Amortization of prior service cost (credit) 513 508 (19) (37)  Recognized actuarial loss 10,396 7,063 – –  Net periodic benefit expense $ 13,903 10,979 2,716 2,745 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. During the six-month period ended June 30, 2018 , the Company made contributions of $13.2 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 $16.5 million.

Incentive Plans

Incentive Plans	6 Months Ended
	Jun. 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. No furt her awards will be granted under the 2012 Long-T erm Plan . The Company had an Employee Stock Purchase Plan (ESPP) that permitted the issuance of Company shares during the first six months of 2017. The ESPP terminated on June 30, 2017 and was not renewed by the Company. 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 six-month period ended June 30, 2018. Amounts recognized in the financial statements with respect to share-based plans are shown in the following table:      Six Months Ended  June 30,  (Thousands of dollars) 2018 2017  Compensation charged against income before tax benefit $ 18,970 16,722  Related income tax benefit recognized in income 2,463 5,425 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	6 Months Ended
	Jun. 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 share for the three-month and six-month periods ended June 30, 2018 and 2017. The following table reconciles the weighted-average shares outstanding used for these computations.     Three Months Ended Six Months Ended  June 30, June 30,  (Weighted-average shares) 2018 2017 2018 2017  Basic method 173,042,626 172,557,978 172,907,537 172,482,223  Dilutive stock options and restricted stock units 939,994 – 1 2,019,525 534,441  Diluted method 173,982,620 172,557,978 174,927,062 173,016,664 1 Due to a net loss in the three-month period ended June 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 Six Months Ended  June 30, June 30,  2018 2017 2018 2017  Antidilutive stock options excluded from diluted shares 3,396,951 5,578,634 3,622,106 4,903,084  Weighted average price of these options $ 50.22 $ 46.64 $ 50.56 $ 52.01  

Income Taxes

Income Taxes	6 Months Ended
	Jun. 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 taxes. For the three-month and six-month periods ended June 30, 2018 and 2017, the Company’s effective income tax rates were as follows:   2018 2017  Three months ended June 30 44.2% 20.7%  Six months ended June 30 (19.6)% 69.8% 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 and other expenses in certain foreign jurisdictions, for which no income tax benefits are available or are not presently being recorded due to a lack of reasonable certainty of adequate future revenue against which to utilize these expenses as deductions. Conversely, the effective tax rates for most periods where losses are incurred generally are lower than U.S. statutory tax rate of 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 the Section 965(n) election. This guidance resolved the ambiguity and allowed the Company to preserve the 2017 tax net operating loss as a carryforward by allowing the crediting of 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 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 June 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 June 30, 2017 was below the U.S. statutory tax rate primarily due to a tax benefit related to certain foreign investments, partially offset by income tax expense related to undistributed foreign earnings. The effective tax rate for the six-month period ended June 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. These impacts were partially 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 six-month period ended June 30, 2017 was above the U.S. statutory tax rate due to the Company recording a deferred tax charge of $60.4 million associated with the estimated tax consequence of future repatriation of foreign earnings not considered reinvested into local operations. The Company’s tax returns in multiple jurisdictions are subject to audit by taxing authorities. These audits often take years to complete and settle. Although the Company believes that recorded liabilities for unsettled issues are adequate, additional gains or losses could occur in future years from resolution of outstanding unsettled matters. As of June 30, 2018, the earliest years remaining open for audit and/or settlement in our major taxing jurisdictions are as follows: United States – 2014 ; Canada – 2012 ; Malaysia – 20 11 ; and United Kingdom – 2016 .

Financial Instruments and Risk

Financial Instruments and Risk Management	6 Months Ended
	Jun. 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 and sells. During the first half 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 June 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 June 30, 2017, the Company had 22,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 2017. 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 June 30, 2018 and 2017. At June 30, 2018 and December 31, 2017, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.      June 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 $ (68,882) Accounts payable $ (39,093)   Note L – Financial Instruments and Risk Management (Contd.) For the three-month and six-month periods ended June 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 Six Months Ended  (Thousands of dollars) June 30, June 30,  Type of Derivative Contract Statement of Operations Location 2018 2017 2018 2017  Commodity Gain (loss) on crude contracts $ (37,624) 26,861 (67,126) 63,938  Foreign exchange Interest and other income (loss) – (152) – 73  $ (37,624) 26,709 (67,126) 64,011 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 six-month periods ended June 30, 2018 and 2017, $1.5 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 June 30, 2018 was $9.1 million, which is recorded, net of income taxes of $2.4 million, in Accumulated other comprehensive loss in the Consolidated Balance Sheet. The Company expects to charge approximately $1.5 million of this deferred loss to Interest expense, net in the Consolidated Statement of Operations during the remaining six 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 June 30, 2018 and December 31, 2017 are presented in the following table.     June 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 $ 16,577 – – 16,577 16,158 – – 16,158  Commodity derivative contracts – 68,882 – 68,882 – 39,093 – 39,093  $ 16,577 68,882 – 85,459 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 June 30, 2018 and December 31, 2017.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Loss	6 Months Ended
	Jun. 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 Sheets at December 31, 2017 and June 30, 2018 and the changes during the six-month period ended June 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 (87,185) (32,159) (1,815) (121,159)  Reclassifications to income – 7,108 1 1,171 2 8,279  Net other comprehensive loss (87,185) (25,051) (644) (112,880)  Balance at June 30, 2018 $ (362,015) (204,038) (9,070) (575,123) 1 Reclassifications before taxes of $8,851 are included in the computation of net periodic benefit expense for the six-month period ended June 30, 2018. See Note H for additional information. Related income taxes of $1,743 are included in Income tax expense (benefit) for the six-month period ended June 30, 2018. 2 Reclassifications before taxes of $1,482 are included in Interest expense, net, for the six-month period ended June 30, 2018. Related income taxes of $311 are included in Income tax expense (benefit) for the six-month period ended June 30, 2018. See Note L for additional information.

Environmental and Other Conting

Environmental and Other Contingencies	6 Months Ended
	Jun. 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. The Company currently owns or leases, and has in the past owned or leased, properties at which hazardous substances have been or are being handled. Although the Company has used operating and disposal practices that were standard in the industry at the time, hazardous substances may have been disposed of or released on or under the properties owned or leased by the Company or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes were not under Murphy’s control. Under existing laws the Company could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Certain of these historical properties are in various stages of negotiation, investigation, and/or cleanup and the Company is investigating the extent of any such liability and the availability of applicable defenses. The Company has retained certain liabilities related to environmental matters at formerly owned U.S. refineries that were sold in 2011. The Company also obtained insurance covering certain levels of environmental exposures related to past operations of these refineries. The Company 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 $41.5 million from inception to June 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 June 30, 2018, the Company has a remaining accrued liability of $6.3 million associated with this event. In the first quarter of 2018, the Company received $15.0 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	6 Months Ended
	Jun. 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 Canada. During the period from July 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	6 Months Ended
	Jun. 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 June 30, 2018 June 30, 2017  at June 30, External Income External Income  (Millions of dollars) 2018 Revenues (Loss) Revenues (Loss)  Exploration and production 1  United States $ 4,799.1 318.8 72.6 212.5 (9.6)  Canada 1,745.6 108.4 9.7 88.2 5.2  Malaysia 1,621.7 228.6 83.9 176.5 47.7  Other 160.0 – (15.0) – 7.2  Total exploration and production 8,326.4 655.8 151.2 477.2 50.5  Corporate 3 1,597.3 (37.6) (105.3) 31.1 (67.9)  Assets/revenue/income from continuing operations 9,923.7 618.2 45.9 508.3 (17.4)  Discontinued operations, net of tax 21.7 – (0.4) – (0.2)  Total $ 9,945.4 618.2 45.5 508.3 (17.6)   Six Months Ended Six Months Ended  June 30, 2018 June 30, 2017  External Income External Income  (Millions of dollars) Revenues (Loss) Revenues (Loss)  Exploration and production 1  United States $ 596.9 108.7 436.7 (10.6)  Canada 2 226.7 34.3 306.1 105.8  Malaysia 439.5 154.3 373.9 106.3  Other – (30.5) – 0.1  Total exploration and production 1,263.1 266.8 1,116.7 201.6  Corporate 3 (59.3) (52.2) 68.2 (161.5)  Revenue/loss from continuing operations 1,203.8 214.6 1,184.9 40.1  Discontinued operations, net of tax – (0.8) – 0.8  Total $ 1,203.8 213.8 1,184.9 40.9 1 Additional details about results of oil and gas operations are presented in the tables on page s 1 and 30 . 2 Revenue for the six months ended June 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.

Nature of Business and Interi26

Nature of Business and Interim Financial Statements (Policies)	6 Months Ended
	Jun. 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 produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide.

Revenue from Contracts with C27

Revenue from Contracts with Customers (Policies)	6 Months Ended
	Jun. 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 Company 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 C28

Revenue from Contracts with Customers (Tables)	6 Months Ended
	Jun. 30, 2018
Revenue from Contracts with Customers [Abstract]
Disaggregation of Revenue	  Three Months Ended Six Months Ended  June 30, June 30,  (Thousands of dollars) 2018 2017 2018 2017  Net crude oil and condensate revenue  United States – Onshore $ 198,823 143,684 381,472 293,671  – Offshore 94,393 47,669 165,922 101,481  Canada – Onshore 28,425 11,658 49,719 20,778  – Offshore 48,316 38,863 102,631 75,877  Malaysia – Sarawak 85,596 59,758 162,902 125,542  – Block K 101,609 76,741 196,181 164,572  Total crude oil and condensate revenue 557,162 378,373 1,058,827 781,921   Net natural gas liquids revenue  United States – Onshore 13,236 9,077 25,370 18,724  – Offshore 2,920 1,209 4,559 3,125  Canada – Onshore 3,448 881 6,916 1,313  Malaysia – Sarawak 4,002 3,358 10,193 8,541  Total natural gas liquids revenue 23,606 14,525 47,038 31,703   Net natural gas revenue  United States – Onshore 6,291 8,006 13,062 15,041  – Offshore 2,826 2,718 5,762 5,381  Canada – Onshore 28,089 37,951 67,683 77,798  Malaysia – Sarawak 36,997 35,829 69,380 74,418  – Block K 179 158 352 333  Total natural gas revenue 74,382 84,662 156,239 172,971  Total revenue from contracts with customers 655,150 477,560 1,262,104 986,595   Gain (loss) on crude contracts (37,624) 26,861 (67,126) 63,938  Other operating income (loss) 448 5,191 8,939 3,738  Gain (loss) on sale of assets 220 (1,333) (118) 130,648  Total revenue $ 618,194 508,279 1,203,799 1,184,919 
Current Long-Term Contracts Outstanding	  Current Long-Term Contracts Outstanding at June 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)	6 Months Ended
	Jun. 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 30,731 48,764  Reclassifications to proved properties based on the determination of proved reserves – (13,370)  Capitalized exploratory well costs charged to expense – (8,360)  Balance at June 30 $ 206,371 175,534 
Aging of Capitalized Exploratory Well Costs	   June 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 $ 34,779 2 2 $ 57,900 3 3  One to two years 35,934 2 1 53,023 3 3  Two to three years 50,272 2 2 – – –  Three years or more 85,386 7 1 64,611 6 –  $ 206,371 13 6 $ 175,534 12 6 

Discontinued Operations and A30

Discontinued Operations and Assets Held for Sale (Tables)	6 Months Ended
	Jun. 30, 2018
Discontinued Operations and Assets Held for Sale [Abstract]
Results of Operations Associated with Discontinued Operations	  Three Months Six Months  Ended June 30, Ended June 30,  (Thousands of dollars) 2018 2017 2018 2017  Revenues $ 6 126 6 256  Income (loss) before income taxes (398) (217) (835) 752  Income tax benefit – – – –  Income (loss) from discontinued operations $ (398) (217) (835) 752 
Major Categories of Assets and Liabilities Reflected as Held for Sale	   June 30, December 31,  (Thousands of dollars) 2018 2017  Current assets  Cash $ 14,609 16,631  Accounts receivable 7,058 6,298  Total current assets held for sale $ 21,667 22,929  Current liabilities  Accounts payable $ 488 837  Refinery decommissioning cost 2,658 2,693  Total current liabilities associated with assets held for sale $ 3,146 3,530 

Other Financial Information (Ta

Other Financial Information (Tables)	6 Months Ended
	Jun. 30, 2018
Other Financial Information [Abstract]
Noncash Operating Working Capital (Increase) Decrease	  Six Months Ended June 30,  (Thousands of dollars) 2018 2017  Net (increase) decrease in operating working capital other than cash and cash equivalents:  (Increase) decrease in accounts receivable $ (15,528) 125,283  Decrease in inventories 16,929 5,918  (Increase) decrease in prepaid expenses (7,890) 9,206  Increase (decrease) in accounts payable and accrued liabilities 49,311 (136,500)  Increase in income taxes payable 42,618 38,674  Net decrease in noncash operating working capital $ 85,440 42,581  Supplementary disclosures:  Cash income taxes paid, net of refunds $ 36,618 9,448  Interest paid, net of amounts capitalized of $2,377 in 2018 and $2,449 in 2017 79,279 72,136   Non-cash investing activities:  Asset retirement costs capitalized $ 1,608 797  Decrease in capital expenditure accrual 39,322 43,370 

Employee and Retiree Benefit 32

Employee and Retiree Benefit Plans (Tables)	6 Months Ended
	Jun. 30, 2018
Employee and Retiree Benefit Plans [Abstract]
Components of Net Periodic Benefit Expense	   Three Months Ended June 30,  Pension Benefits Other Postretirement Benefits  (Thousands of dollars) 2018 2017 2018 2017  Service cost $ 2,254 2,030 493 424  Interest cost 6,707 6,287 874 967  Expected return on plan assets (7,453) (6,475) – –  Amortization of prior service cost (credit) 256 254 (9) (19)  Recognized actuarial loss 5,181 3,509 – –  Net periodic benefit expense $ 6,945 5,605 1,358 1,372   Six Months Ended June 30,  Pension Benefits Other Postretirement Benefits  (Thousands of dollars) 2018 2017 2018 2017  Service cost $ 4,509 4,062 987 849  Interest cost 13,444 13,006 1,748 1,933  Expected return on plan assets (14,959) (13,660) – –  Amortization of prior service cost (credit) 513 508 (19) (37)  Recognized actuarial loss 10,396 7,063 – –  Net periodic benefit expense $ 13,903 10,979 2,716 2,745 

Incentive Plans (Tables)

Incentive Plans (Tables)	6 Months Ended
	Jun. 30, 2018
Incentive Plans [Abstract]
Share-Based Plans, Amounts Recognized	   Six Months Ended  June 30,  (Thousands of dollars) 2018 2017  Compensation charged against income before tax benefit $ 18,970 16,722  Related income tax benefit recognized in income 2,463 5,425 

Earnings per Share (Tables)

Earnings per Share (Tables)	6 Months Ended
	Jun. 30, 2018
Earnings per Share [Abstract]
Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share	   Three Months Ended Six Months Ended  June 30, June 30,  (Weighted-average shares) 2018 2017 2018 2017  Basic method 173,042,626 172,557,978 172,907,537 172,482,223  Dilutive stock options and restricted stock units 939,994 – 1 2,019,525 534,441  Diluted method 173,982,620 172,557,978 174,927,062 173,016,664 1 Due to a net loss in the three-month period ended June 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 Six Months Ended  June 30, June 30,  2018 2017 2018 2017  Antidilutive stock options excluded from diluted shares 3,396,951 5,578,634 3,622,106 4,903,084  Weighted average price of these options $ 50.22 $ 46.64 $ 50.56 $ 52.01 

Income Taxes (Tables)

Income Taxes (Tables)	6 Months Ended
	Jun. 30, 2018
Income Taxes [Abstract]
Effective Income Tax Rates	  2018 2017  Three months ended June 30 44.2% 20.7%  Six months ended June 30 (19.6)% 69.8% 

Financial Instruments and Ris36

Financial Instruments and Risk Management (Tables)	6 Months Ended
	Jun. 30, 2018
Financial Instruments and Risk Management [Abstract]
Fair Value of Derivative Instruments Not Designated as Hedging Instruments	   June 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 $ (68,882) Accounts payable $ (39,093) 
Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments	   Gain (Loss)  Three Months Ended Six Months Ended  (Thousands of dollars) June 30, June 30,  Type of Derivative Contract Statement of Operations Location 2018 2017 2018 2017  Commodity Gain (loss) on crude contracts $ (37,624) 26,861 (67,126) 63,938  Foreign exchange Interest and other income (loss) – (152) – 73  $ (37,624) 26,709 (67,126) 64,011 
Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis	   June 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 $ 16,577 – – 16,577 16,158 – – 16,158  Commodity derivative contracts – 68,882 – 68,882 – 39,093 – 39,093  $ 16,577 68,882 – 85,459 16,158 39,093 – 55,251 

Accumulated Other Comprehensi37

Accumulated Other Comprehensive Loss (Tables)	6 Months Ended
	Jun. 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 (87,185) (32,159) (1,815) (121,159)  Reclassifications to income – 7,108 1 1,171 2 8,279  Net other comprehensive loss (87,185) (25,051) (644) (112,880)  Balance at June 30, 2018 $ (362,015) (204,038) (9,070) (575,123) 1 Reclassifications before taxes of $8,851 are included in the computation of net periodic benefit expense for the six-month period ended June 30, 2018. See Note H for additional information. Related income taxes of $1,743 are included in Income tax expense (benefit) for the six-month period ended June 30, 2018. 2 Reclassifications before taxes of $1,482 are included in Interest expense, net, for the six-month period ended June 30, 2018. Related income taxes of $311 are included in Income tax expense (benefit) for the six-month period ended June 30, 2018. See Note L for additional information.

Business Segments (Tables)

Business Segments (Tables)	6 Months Ended
	Jun. 30, 2018
Business Segments [Abstract]
Segment Information	  Three Months Ended Three Months Ended  Total Assets June 30, 2018 June 30, 2017  at June 30, External Income External Income  (Millions of dollars) 2018 Revenues (Loss) Revenues (Loss)  Exploration and production 1  United States $ 4,799.1 318.8 72.6 212.5 (9.6)  Canada 1,745.6 108.4 9.7 88.2 5.2  Malaysia 1,621.7 228.6 83.9 176.5 47.7  Other 160.0 – (15.0) – 7.2  Total exploration and production 8,326.4 655.8 151.2 477.2 50.5  Corporate 3 1,597.3 (37.6) (105.3) 31.1 (67.9)  Assets/revenue/income from continuing operations 9,923.7 618.2 45.9 508.3 (17.4)  Discontinued operations, net of tax 21.7 – (0.4) – (0.2)  Total $ 9,945.4 618.2 45.5 508.3 (17.6)   Six Months Ended Six Months Ended  June 30, 2018 June 30, 2017  External Income External Income  (Millions of dollars) Revenues (Loss) Revenues (Loss)  Exploration and production 1  United States $ 596.9 108.7 436.7 (10.6)  Canada 2 226.7 34.3 306.1 105.8  Malaysia 439.5 154.3 373.9 106.3  Other – (30.5) – 0.1  Total exploration and production 1,263.1 266.8 1,116.7 201.6  Corporate 3 (59.3) (52.2) 68.2 (161.5)  Revenue/loss from continuing operations 1,203.8 214.6 1,184.9 40.1  Discontinued operations, net of tax – (0.8) – 0.8  Total $ 1,203.8 213.8 1,184.9 40.9 1 Additional details about results of oil and gas operations are presented in the tables on page s 1 and 30 . 2 Revenue for the six months ended June 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 and39

New Accounting Principles and Recent Accounting Pronouncements (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Mar. 31, 2018	Jun. 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 C40

Revenue from Contracts with Customers (Narrative) (Details)	6 Months Ended
	Jun. 30, 2018USD ($)contractitemsegmentagreement	Jun. 30, 2017USD ($)	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	$ 190,700,000		$ 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 C41

Revenue from Contracts with Customers (Disaggregation of Revenue) (Details) - USD ($) $ in Thousands	3 Months Ended			6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017		Jun. 30, 2018	Jun. 30, 2017
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 655,150	$ 477,560	[1]	$ 1,262,104	$ 986,595	[1]
(Loss) gain on crude contracts	(37,624)	26,861	[1]	(67,126)	63,938	[1]
Other operating income (loss)	448	5,191		8,939	3,738
Gain (loss) on sale of assets	220	(1,333)		(118)	130,648
Total revenues	618,194	508,279	[1]	1,203,799	1,184,919	[1]
Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	557,162	378,373		1,058,827	781,921
Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	23,606	14,525		47,038	31,703
Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	74,382	84,662		156,239	172,971
United States Onshore [Member] | Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	198,823	143,684		381,472	293,671
United States Onshore [Member] | Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	13,236	9,077		25,370	18,724
United States Onshore [Member] | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	6,291	8,006		13,062	15,041
United States Offshore [Member] | Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	94,393	47,669		165,922	101,481
United States Offshore [Member] | Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,920	1,209		4,559	3,125
United States Offshore [Member] | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,826	2,718		5,762	5,381
Canada Onshore [Member] | Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	28,425	11,658		49,719	20,778
Canada Onshore [Member] | Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	3,448	881		6,916	1,313
Canada Onshore [Member] | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	28,089	37,951		67,683	77,798
Canada Offshore [Member] | Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	48,316	38,863		102,631	75,877
Malaysia - Sarawak [Member] | Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	85,596	59,758		162,902	125,542
Malaysia - Sarawak [Member] | Natural Gas Liquids [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	4,002	3,358		10,193	8,541
Malaysia - Sarawak [Member] | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	36,997	35,829		69,380	74,418
Malaysia - Block K [Member] | Crude Oil And Condensate [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	101,609	76,741		196,181	164,572
Malaysia - Block K [Member] | Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 179	$ 158		$ 352	$ 333
[1]	Reclassified to conform to current presentation (see Notes A and B).

Revenue from Contracts with C42

Revenue from Contracts with Customers (Current and Long-Term Contracts Outstanding) (Details)	Jun. 30, 2018MMcf / dBoe / d$ / Mcf
Alberta AECO Fixed Price [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 Fixed Price [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 Equipment43

Property, Plant and Equipment (Narrative) (Details) - USD ($)	1 Months Ended	3 Months Ended			6 Months Ended		12 Months Ended
	Jan. 31, 2017	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Apr. 01, 2017
Property Plant And Equipment [Line Items]
Total capitalized exploratory well costs		$ 206,371,000	$ 175,640,000	$ 175,534,000	$ 206,371,000	$ 175,534,000	$ 175,640,000	$ 148,500,000
Capitalized well costs charged to expense					0	8,360,000
Exploratory well costs capitalized more than one year		171,600,000			171,600,000
Proceeds from sales of property, plant and equipment					623,000	64,303,000
Gain (loss) on sale of assets		220,000		$ (1,333,000)	(118,000)	130,648,000
Athabasca Oil Corporation [Member]
Property Plant And Equipment [Line Items]
Cost of acquired assets, cash paid								206,700,000
Cost of acquired assets, carried interest								168,000,000
Carried interest paid		75,400,000			75,400,000
Canadian Subsidiary [Member] | Athabasca Oil Corporation [Member]
Property Plant And Equipment [Line Items]
Cost of acquired assets								375,000,000
Western Canada [Member]
Property Plant And Equipment [Line Items]
Proceeds from sales of property, plant and equipment	$ 48,800,000
Asset retirement obligation settled	$ 85,900,000
Gain (loss) on sale of assets						132,400,000	132,400,000
Eagle Ford Shale [Member]
Property Plant And Equipment [Line Items]
Proceeds from sales of property, plant and equipment							19,600,000
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								414,100,000
Deferred gain on sale of property		170,200,000			$ 170,200,000			$ 187,000,000
Deferred gain, period of recognition					18 years
Amortization of deferred gain					$ 3,800,000	$ 3,400,000
Brunei [Member]
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year		70,400,000			70,400,000
Vietnam [Member]
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year		52,600,000			52,600,000
United States [Member]
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year		27,800,000			27,800,000
Malaysia [Member]
Property Plant And Equipment [Line Items]
Exploratory well costs capitalized more than one year		$ 20,800,000			$ 20,800,000
Kaybob Duvernay Lands, Alberta [Member]
Property Plant And Equipment [Line Items]
Interest in assets acquired								70.00%
Placid Montney Lands, Alberta [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								$ 39,100,000
Redetermination expense, net of tax								$ 24,100,000
Redetermination liability		$ 17,300,000			$ 17,300,000
Unitization Framework Agreement [Member] | Kakap Field Block K Malaysia [Member]
Property Plant And Equipment [Line Items]
Redetermination expense			15,000,000
Redetermination expense, net of tax			$ 9,300,000
Redetermination liability		$ 15,000,000			$ 15,000,000

Property, Plant And Equipment44

Property, Plant And Equipment (Net Changes in Capitalized Exploratory Well Costs) (Details) - USD ($)	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Property, Plant And Equipment [Abstract]
Beginning balance at January 1	$ 175,640,000	$ 148,500,000
Additions pending the determination of proved reserves	30,731,000	48,764,000
Reclassifications to proved properties based on the determination of proved reserves		(13,370,000)
Capitalized exploratory well costs charged to expense	0	(8,360,000)
Ending balance at June 30	$ 206,371,000	$ 175,534,000

Property, Plant And Equipment45

Property, Plant And Equipment (Aging of Capitalized Exploratory Well Costs) (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2018USD ($)item	Jun. 30, 2017USD ($)item	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 206,371	$ 175,534	$ 175,640	$ 148,500
No. of Wells	13	12
No. of Projects	6	6
Zero to One Year [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 34,779	$ 57,900
No. of Wells	2	3
No. of Projects	2	3
One to Two Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 35,934	$ 53,023
No. of Wells	2	3
No. of Projects	1	3
Two to Three Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 50,272
No. of Wells	2
No. of Projects	2
Three Years or More [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 85,386	$ 64,611
No. of Wells	7	6
No. of Projects	1

Discontinued Operations and A46

Discontinued Operations and Assets Held for Sale (Results of Operations Associated with Discontinued Operations) (Details) - USD ($) $ in Thousands	3 Months Ended			6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017		Jun. 30, 2018	Jun. 30, 2017
Discontinued Operations and Assets Held for Sale [Abstract]
Revenues	$ 6	$ 126		$ 6	$ 256
Income (loss) before income taxes	(398)	(217)		(835)	752
Income tax benefit
Income (loss) from discontinued operations	$ (398)	$ (217)	[1]	$ (835)	$ 752	[1]
[1]	Reclassified to conform to current presentation (see Notes A and B).

Discontinued Operations and A47

Discontinued Operations and Assets Held for Sale (Major Categories of Assets and Liabilities Reflected as Held for Sale) (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable	$ 258,366	$ 243,472
Total current assets held for sale	21,667	22,929
Accounts payable	632,072	595,916
Total current liabilities associated with assets held for sale	3,146	3,530
UK Refining And Marketing Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash	14,609	16,631
Accounts receivable	7,058	6,298
Total current assets held for sale	21,667	22,929
Accounts payable	488	837
Refinery decommissioning cost	2,658	2,693
Total current liabilities associated with assets held for sale	$ 3,146	$ 3,530

Financing Arrangements and De48

Financing Arrangements and Debt (Narrative) (Details)	6 Months Ended
	Jun. 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	$ 9,700,000
Capital lease obligations, noncurrent	122,900,000
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	5.5375%
2016 Senior Unsecured Guaranteed Credity Facility [Member] | Letter of Credit [Member]
Line of Credit Facility [Line Items]
Amount outstanding	$ 27,900,000

Other Financial Information (No

Other Financial Information (Noncash Opearting Working Capital (Increase) Decrease) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Other Financial Information [Abstract]
(Increase) decrease in accounts receivable	$ (15,528)	$ 125,283
Decrease in inventories	16,929	5,918
(Increase) decrease in prepaid expenses	(7,890)	9,206
Increase (decrease) in accounts payable and accrued liabilities	49,311	(136,500)
Increase in income taxes payable	42,618	38,674
Net decrease in noncash operating working capital	85,440	42,581
Cash income taxes paid, net of refunds	36,618	9,448
Interest paid, net of amounts capitalized of $2,377 in 2018 and $2,449 in 2017	79,279	72,136
Asset retirement costs capitalized	1,608	797
Decrease in capital expenditure accrual	39,322	43,370
Interest paid, amounts capitalized	$ 2,377	$ 2,449

Employee and Retiree Benefit 50

Employee and Retiree Benefit Plans (Narrative) (Details) $ in Millions	6 Months Ended
	Jun. 30, 2018USD ($)
Employee and Retiree Benefit Plans [Abstract]
Contributions to benefit plans	$ 13.2
Expected benefit plan contributions to be made during the year	$ 16.5

Employee and Retiree Benefit 51

Employee and Retiree Benefit Plans (Components of Net Periodic Benefit Expense) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		9 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Sep. 30, 2017	Sep. 30, 2016
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 2,254	$ 2,030	$ 4,509	$ 4,062
Interest cost	6,707	6,287			$ 13,444	$ 13,006
Expected return on plan assets	(7,453)	(6,475)			(14,959)	(13,660)
Amortization of prior service cost (credit)	256	254			513	508
Recognized actuarial loss	5,181	3,509			10,396	7,063
Net periodic benefit expense	6,945	5,605			13,903	10,979
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	493	424	$ 987	$ 849
Interest cost	874	967			1,748	1,933
Amortization of prior service cost (credit)	(9)	(19)			(19)	(37)
Net periodic benefit expense	$ 1,358	$ 1,372			$ 2,716	$ 2,745

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	Jun. 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	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Incentive Plans [Abstract]
Compensation charged against income before tax benefit	$ 18,970	$ 16,722
Related income tax benefit recognized in income	$ 2,463	$ 5,425

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			6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017		Jun. 30, 2018	Jun. 30, 2017
Earnings per Share [Abstract]
Basic method	173,042,626	172,557,978	[1]	172,907,537	172,482,223	[1]
Dilutive stock options and restricted stock units	939,994	0	[2]	2,019,525	534,441
Diluted method	173,982,620	172,557,978	[1]	174,927,062	173,016,664	[1]
[1]	Reclassified to conform to current presentation (see Notes A and B).
[2]	Due to a net loss in the three-month period ended June 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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Earnings per Share [Abstract]
Antidilutive stock options excluded from diluted shares (in shares)	3,396,951	5,578,634	3,622,106	4,903,084
Weighted average price of these options (per share)	$ 50.22	$ 46.64	$ 50.56	$ 52.01

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2018	Jun. 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		2,014
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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Income Taxes [Abstract]
Effective income tax rate	44.20%	20.70%	(19.60%)	69.80%

Financial Instruments and Ris58

Financial Instruments and Risk Management (Narrative) (Details) bbl / d in Thousands, $ in Millions	6 Months Ended
	Dec. 31, 2018USD ($)	Jun. 30, 2018USD ($)bbl / dcontractitem$ / bbl	Jun. 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		$ 1.5	$ 1.5
Number of offsetting positions | item		0		0
Scenario, Forecast [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative loss	$ 1.5
Commodity Derivative Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Daily production commitment (barrels per day) | bbl / d		21	22
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		$ 9.1
Income taxes on deferred loss on fair value of interest rate derivative contracts		$ 2.4
Notes Due 2022 [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Debt instrument term		10 years

Financial Instruments and Ris59

Financial Instruments and Risk Management (Fair Value of Derivative Instruments Not Designated as Hedging Instruments) (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Nondesignated [Member] | Commodity Derivative Contracts [Member] | Accounts Payable [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ (68,882)	$ (39,093)

Financial Instruments and Ris60

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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ (37,624)	$ 26,709	$ (67,126)	$ 64,011
Commodity Derivative Contracts [Member] | Gain (Loss) on Crude Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ (37,624)	26,861	$ (67,126)	63,938
Foreign Exchange Derivative Contracts [Member] | Interest And Other Income (Loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)		$ (152)		$ 73

Financial Instruments and Ris61

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	Jun. 30, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	$ 85,459	$ 55,251
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	16,577	16,158
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	68,882	39,093
Non-Qualified Employee Savings Plans [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	16,577	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	16,577	16,158
Commodity Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	68,882	39,093
Commodity Derivative Contracts [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liability Derivatives	$ 68,882	$ 39,093

Accumulated Other Comprehensi62

Accumulated Other Comprehensive Loss (Components of Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance				$ (462,243)
Before reclassifications to income and retained earnings				(121,159)
Reclassifications to income				8,279
Net other comprehensive income		$ (30,386)	$ 73,087	(112,880)	$ 98,620
Ending Balance		(575,123)		(575,123)
Reclassifications before taxes, included in net periodic benefit expense				8,851
Reclassifications, income tax expense				1,743
Reclassifications income tax, included in interest expense				311
Foreign Currency Translation Gains (Losses) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance				(274,830)
Before reclassifications to income and retained earnings				(87,185)
Net other comprehensive income				(87,185)
Ending Balance		(362,015)		(362,015)
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]			7,108
Net other comprehensive income				(25,051)
Ending Balance		(204,038)		(204,038)
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]			1,171
Net other comprehensive income				(644)
Ending Balance		$ (9,070)		$ (9,070)
[1]	Reclassifications before taxes of $8,851 are included in the computation of net periodic benefit expense for the six-month period ended June 30, 2018. See Note H for additional information. Related income taxes of $1,743 are included in Income tax expense (benefit) for the six-month period ended June 30, 2018.
[2]	Reclassifications before taxes of $1,482 are included in Interest expense, net, for the six-month period ended June 30, 2018. Related income taxes of $311 are included in Income tax expense (benefit) for the six-month period ended June 30, 2018. See Note L for additional information.

Environmental and Other Conti63

Environmental and Other Contingencies (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended	42 Months Ended
	Mar. 31, 2018	Dec. 31, 2015	Jun. 30, 2018
Environmental and Other Contingencies [Abstract]
Remediation costs	$ 3.8	$ 43.9
Payments for environmental liabilities			$ 41.5
Remediation accrual			$ 6.3
Proceeds from insurance settlement	$ 15

Commitments (Narrative) (Detail

Commitments (Narrative) (Details) - Natural Gas Per Thousand Cubic Feet [Member] - July 2018 to December 2020 [Member]	Jun. 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			6 Months Ended			9 Months Ended		12 Months Ended
		Jun. 30, 2018	Jun. 30, 2017		Jun. 30, 2018	Jun. 30, 2017		Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2017
Segment Reporting Information [Line Items]
Total Assets		$ 9,945,449			$ 9,945,449					$ 9,860,942
External Revenues		618,194	$ 508,279	[1]	1,203,799	$ 1,184,919	[1]
Net income (loss)		45,518	(17,571)	[1]	213,771	40,893	[1]
Gain (loss) on sale of assets		220	(1,333)		(118)	130,648
Continuing Operations [Member]
Segment Reporting Information [Line Items]
Total Assets		9,923,700			9,923,700
External Revenues		618,200	508,300					$ 1,203,800	$ 1,184,900
Net income (loss)		45,900	(17,400)					214,600	40,100
Discontinued Operations [Member]
Segment Reporting Information [Line Items]
Total Assets		21,700			21,700
Net income (loss)		(400)	(200)					(800)	800
Corporate [Member]
Segment Reporting Information [Line Items]
Total Assets	[2]	1,597,300			1,597,300
External Revenues	[2]	(37,600)	31,100					(59,300)	68,200
Net income (loss)	[2]	(105,300)	(67,900)					(52,200)	(161,500)
Exploration And Production Segment [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Total Assets	[3]	8,326,400			8,326,400
External Revenues	[3]	655,800	477,200					1,263,100	1,116,700
Net income (loss)	[3]	151,200	50,500					266,800	201,600
Exploration And Production Segment [Member] | Operating Segments [Member] | United States [Member]
Segment Reporting Information [Line Items]
Total Assets	[3]	4,799,100			4,799,100
External Revenues	[3]	318,800	212,500					596,900	436,700
Net income (loss)	[3]	72,600	(9,600)					108,700	(10,600)
Exploration And Production Segment [Member] | Operating Segments [Member] | Canada [Member]
Segment Reporting Information [Line Items]
Total Assets	[3],[4]	1,745,600			1,745,600
External Revenues	[3],[4]	108,400	88,200					226,700	306,100
Net income (loss)	[3],[4]	9,700	5,200					34,300	105,800
Exploration And Production Segment [Member] | Operating Segments [Member] | Malaysia [Member]
Segment Reporting Information [Line Items]
Total Assets	[3]	1,621,700			1,621,700
External Revenues	[3]	228,600	176,500					439,500	373,900
Net income (loss)	[3]	83,900	47,700					154,300	106,300
Exploration And Production Segment [Member] | Operating Segments [Member] | Other Regions [Member]
Segment Reporting Information [Line Items]
Total Assets	[3]	160,000			$ 160,000
Net income (loss)	[3]	$ (15,000)	$ 7,200					$ (30,500)	$ 100
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 Notes A and 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 1 and 30.
[4]	Revenue for the six months ended June 30, 2017 includes a pretax gain of $132.4 million related to the sale of Seal heavy oil assets in Canada.