Murphy Oil (MUR) 10-K 26 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Jan. 31, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
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 Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 4,189,400,296
Entity Common Stock, Shares Outstanding		172,572,873

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and equivalents		$ 964,988	$ 872,797
Canadian government securities with maturities greater than 90 days at the date of acquisition			111,542
Accounts receivable, less allowance for doubtful accounts of $1,605 in 2017 and 2016		243,472	357,099
Inventories, at lower of cost or market		105,127	127,071
Prepaid expenses		35,087	63,604
Assets held for sale		22,929	27,070
Total current assets		1,371,603	1,559,183
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $12,280,741 in 2017 and $12,607,815 in 2016		8,220,031	8,316,188
Deferred income taxes		211,543	365,935
Deferred charges and other assets		57,765	54,554
Total assets		9,860,942	10,295,860
Current liabilities
Current maturities of long-term debt		9,902	569,817
Accounts payable		595,916	784,975
Income taxes payable		44,604	13,920
Other taxes payable		23,574	28,167
Other accrued liabilities		156,681	102,777
Liabilities associated with assets held for sale		3,530	2,776
Total current liabilities		834,207	1,502,432
Long-term debt, including capital lease obligation		2,906,520	2,422,750
Deferred income taxes		159,098	69,081
Asset retirement obligations		709,299	681,528
Deferred credits and other liabilities		631,627	617,490
Liabilities associated with assets held for sale	[1]		85,900
Stockholders' equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,055,724 shares in 2017 and 2016		195,056	195,056
Capital in excess of par value		917,665	916,799
Retained earnings		5,245,242	5,729,596
Accumulated other comprehensive loss		(462,243)	(628,212)
Treasury stock		(1,275,529)	(1,296,560)
Total stockholders' equity		4,620,191	4,916,679
Total liabilities and stockholders' equity		$ 9,860,942	$ 10,295,860
[1]	Liabilities held for sale related to Seal properties in Canada which were sold in January 2017.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
CONSOLIDATED BALANCE SHEETS [Abstract]
Maturity of Canadian government securities	90 days	90 days
Accounts receivable, allowance for doubtful accounts	$ 1,605	$ 1,605
Property, plant and equipment, accumulated depreciation, depletion and amortization	$ 12,280,741	$ 12,607,815
Cumulative Preferred Stock, par value (per share)	$ 100	$ 100
Cumulative Preferred Stock, authorized shares	400,000	400,000
Cumulative Preferred Stock, shares issued	0	0
Common Stock, par value (per share)	$ 1	$ 1
Common Stock, authorized shares	450,000,000	450,000,000
Common Stock, shares issued	195,055,724	195,055,724

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Revenues
Sales and other operating revenues		$ 2,097,695,000		$ 1,809,575,000	[1]	$ 2,787,116,000	[1]
Gain on sale of assets		127,434,000		1,663,000	[1]	154,155,000	[1]
Total revenues		2,225,129,000		1,811,238,000	[1]	2,941,271,000	[1]
Costs and Expenses
Lease operating expenses		468,323,000		559,360,000	[1]	832,306,000	[1]
Severance and ad valorem taxes		43,618,000		43,826,000	[1]	65,794,000	[1]
Exploration expenses, inlcluding undeveloped lease amortization		122,834,000		101,861,000	[1]	470,924,000	[1]
Selling and general expenses		222,766,000		265,210,000	[1]	306,663,000	[1]
Depreciation, depletion and amortization		957,719,000		1,054,081,000	[1]	1,619,824,000	[1]
Impairment of assets		0		95,088,000	[1]	2,493,156,000	[1]
Redetermination expense		15,000,000	[2]	39,100,000	[1]
Accretion of asset retirement obligations		42,590,000		46,742,000	[1]	48,665,000	[1]
Other expense		30,706,000		13,806,000	[1]	360,635,000	[1]
Total costs and expenses		1,903,556,000		2,219,074,000	[1]	6,197,967,000	[1]
Operating income (loss) from continuing operations		321,573,000		(407,836,000)	[1]	(3,256,696,000)	[1]
Other income (loss)
Interest and other income (loss)		(67,988,000)		62,891,000	[1]	91,809,000	[1]
Interest expense, net		(181,783,000)		(148,170,000)	[1]	(117,375,000)	[1]
Total other loss		(249,771,000)		(85,279,000)	[1]	(25,566,000)	[1]
Income (loss) from continuing operations before income taxes		71,802,000		(493,115,000)	[1]	(3,282,262,000)	[1]
Income tax expense (benefit)		382,738,000		(219,172,000)	[1]	(1,026,490,000)	[1]
Loss from continuing operations		(310,936,000)		(273,943,000)	[1]	(2,255,772,000)	[1]
Loss from discontinued operations, net of income taxes		(853,000)		(2,027,000)	[1]	(15,061,000)	[1]
NET LOSS		$ (311,789,000)		$ (275,970,000)	[1]	$ (2,270,833,000)	[1]
LOSS PER COMMON SHARE - BASIC
Continuing operations		$ (1.81)		$ (1.59)	[1]	$ (12.94)	[1]
Discontinued operations	[1]			(0.01)		(0.09)
Net loss		(1.81)		(1.60)	[1]	(13.03)	[1]
LOSS PER COMMON SHARE - DILUTED
Continuing operations		(1.81)		(1.59)	[1]	(12.94)	[1]
Discontinued operations	[1]			(0.01)		(0.09)
Net loss		(1.81)		(1.60)	[1]	(13.03)	[1]
Cash dividends per Common share		$ 1		$ 1.20	[1]	$ 1.40	[1]
Average Common shares outstanding
Basic		172,524,061		172,173,012	[1]	174,351,227	[1]
Diluted		172,524,061		172,173,012	[1]	174,351,227	[1]
[1]	Reclassified to conform to current presentation (see Note A).
[2]	Results exclude corporate overhead, interest and discontinued operations.

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) [Abstract]
Net loss	$ (311,789)	$ (275,970)	[1]	$ (2,270,833)	[1]
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation	171,725	66,449		(546,705)
Retirement and postretirement benefit plans	(7,682)	7,955		10,492
Deferred loss on interest rate hedges reclassified to interest expense	1,926	1,926		1,926
Other comprehensive income (loss)	165,969	76,330		(534,287)
COMPREHENSIVE LOSS	$ (145,820)	$ (199,640)		$ (2,805,120)
[1]	Reclassified to conform to current presentation (see Note A).

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Operating Activities
Net loss		$ (311,789,000)	$ (275,970,000)	[1]	$ (2,270,833,000)	[1]
Adjustments to reconcile net loss to net cash provided by continuing operations activities:
Loss from discontinued operations		853,000	2,027,000	[1]	15,061,000	[1]
Depreciation, depletion and amortization		957,719,000	1,054,081,000	[1]	1,619,824,000	[1]
Impairment of assets		0	95,088,000	[1]	2,493,156,000	[1]
Amortization of deferred major repair costs			3,794,000		7,296,000
Dry hole costs (credits)		(4,163,000)	15,047,000		296,845,000
Amortization of undeveloped leases		61,776,000	43,417,000		75,312,000
Accretion of asset retirement obligations		42,590,000	46,742,000	[1]	48,665,000	[1]
Deferred income tax expense (benefit)		260,420,000	(387,843,000)		(978,030,000)
Pretax gains from disposition of assets		(127,434,000)	(1,663,000)	[1]	(154,155,000)	[1]
Net (increase) decrease in noncash operating working capital		136,414,000	(38,689,000)		35,064,000
Other operating activities, net		113,289,000	44,764,000		(4,836,000)
Net cash provided by continuing operations activities		1,129,675,000	600,795,000		1,183,369,000
Investing Activities
Property additions and dry hole costs		(1,009,667,000)	(926,948,000)		(2,549,736,000)
Proceeds from sales of property, plant and equipment		69,506,000	1,155,144,000		423,911,000
Purchases of investment securities	[2]	(212,661,000)	(695,879,000)		(911,787,000)
Proceeds from maturity of investment securities	[2]	320,828,000	761,000,000		1,129,139,000
Other investing activities, net			(7,230,000)		(13,648,000)
Net cash provided (required) by investing activities		(831,994,000)	286,087,000		(1,922,121,000)
Financing Activities
Borrowings of debt		541,597,000	541,444,000		600,000,000
Repayments of debt		(550,000,000)	(600,000,000)		(450,000,000)
Capital lease obligation payments		(17,133,000)	(10,447,000)		(10,434,000)
Purchase of treasury stock					(250,000,000)
Issue cost of debt facility			(14,085,000)
Cash dividends paid		(172,565,000)	(206,635,000)		(244,998,000)
Other financing activities, net		(7,116,000)	(1,158,000)		(9,129,000)
Net cash required by financing activities		(205,217,000)	(290,881,000)		(364,561,000)
Cash Flows from Discontinued Operations
Operating activities		10,905,000			(15,005,000)
Investing activities					5,314,000
Changes in cash included in current assets held for sale		(12,505,000)			192,585,000
Net increase (decrease) in cash and cash equivalents of discontinued operations		(1,600,000)			182,894,000
Effect of exchange rate changes on cash and cash equivalents		1,327,000	(6,387,000)		10,294,000
Net increase (decrease) in cash and cash equivalents		92,191,000	589,614,000		(910,125,000)
Cash and cash equivalents at beginning of period		872,797,000	283,183,000		1,193,308,000
Cash and cash equivalents at end of period		$ 964,988,000	$ 872,797,000		$ 283,183,000
[1]	Reclassified to conform to current presentation (see Note A).
[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)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CONSOLIDATED STATEMENTS OF CASH FLOWS [Abstract]
Maturity of Canadian government securities	90 days	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, 2014		$ 195,040	$ 906,741	$ 8,728,032	$ (170,255)	$ (1,086,124)
Exercise of stock options		16	(376)
Foreign currency translation gain (losses), net of income taxes					(546,705)		$ (546,705)
Purchase of treasury shares						(250,000)
Net loss for the year				(2,270,833)			(2,270,833)	[1]
Restricted stock transactions and other			(38,415)
Cash dividends - $1.00 per share in 2017, $1.20 per share in 2016 and $1.40 per share in 2015				(244,998)
Retirement and postretirement benefit plans, net of income taxes					10,492		10,492
Sale of stock under employee stock purchase plans						491
Stock-based compensation			42,322
Other			(198)
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes					1,926		1,926
Awarded restricted stock						29,572
Balance at end of year at Dec. 31, 2015		195,056	910,074	6,212,201	(704,542)	(1,306,061)	5,306,728
Exercise of stock options			(12,017)
Foreign currency translation gain (losses), net of income taxes					66,449		66,449
Net loss for the year				(275,970)			(275,970)	[1]
Restricted stock transactions and other			(10,078)
Cash dividends - $1.00 per share in 2017, $1.20 per share in 2016 and $1.40 per share in 2015				(206,635)
Retirement and postretirement benefit plans, net of income taxes					7,955		7,955
Sale of stock under employee stock purchase plans						509
Stock-based compensation			29,119
Other			(299)
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes					1,926		1,926
Awarded restricted stock						8,992
Balance at end of year at Dec. 31, 2016		195,056	916,799	5,729,596	(628,212)	(1,296,560)	4,916,679
Foreign currency translation gain (losses), net of income taxes					171,725		171,725
Net loss for the year				(311,789)			(311,789)
Restricted stock transactions and other			(26,553)
Cash dividends - $1.00 per share in 2017, $1.20 per share in 2016 and $1.40 per share in 2015				(172,565)
Retirement and postretirement benefit plans, net of income taxes					(7,682)		(7,682)
Sale of stock under employee stock purchase plans						146
Stock-based compensation			27,496
Other			(77)
Deferred loss on interest rate hedges reclassified to interest expense, net of income taxes					1,926		1,926
Awarded restricted stock						20,885
Balance at end of year at Dec. 31, 2017		$ 195,056	$ 917,665	$ 5,245,242	$ (462,243)	$ (1,275,529)	$ 4,620,191
[1]	Reclassified to conform to current presentation (see Note A).

CONSOLIDATED STATEMENTS OF STO9

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - $ / shares	3 Months Ended		12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY [Abstract]
Cumulative Preferred Stock, par value (per share)	$ 100	$ 100	$ 100	$ 100		$ 100
Cumulative Preferred Stock, authorized shares	400,000	400,000	400,000	400,000		400,000
Cumulative Preferred Stock, shares issued	0	0	0	0		0
Common Stock, par value (per share)	$ 1	$ 1	$ 1	$ 1		$ 1
Common Stock, authorized shares	450,000,000	450,000,000	450,000,000	450,000,000		450,000,000
Common Stock, shares issued	195,055,724	195,055,724	195,055,724	195,055,724		195,055,724
Cash dividends per Common share	$ 0.25	$ 0.25	$ 1	$ 1.20	[1]	$ 1.40	[1]
Treasury stock, shares	22,482,851	22,853,547	22,482,851	22,853,547		23,021,013
[1]	Reclassified to conform to current presentation (see Note A).

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Significant Accounting Policies [Abstract]
Significant Accounting Policies	Note A – Significant Accounting Policies  NATURE OF BUSINESS – Murphy Oil Corporation is an international oil and gas company that conducts its business through various operating subsidiaries. The Company produces oil and natural gas in the United States, Canada and Malaysia and conducts oil and natural gas exploration activities worldwide. The Company sold its interest in a Canadian synthetic oil operation in 2016 and its Canadian heavy oil assets in early 2017. In addition, Murphy Oil sold its downstream retail marketing assets in the United Kingdom in 2015. See Notes C and E for more information regarding the sale of these assets .  PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. Investments in affiliates in which the Company owns from 20% to 50% are accounted for by the equity method. Other investments are generally carried at cost. All significant intercompany accounts and transactions have been eliminated.  Beginning in 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 are 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 (loss) from continuing operations before income taxes, Loss from continuing operations, or Net Loss.  REVENUE RECOGNITION – Revenues from sales of crude oil, natural gas liquids and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer. Revenues from the production of oil and natural gas properties in which Murphy shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period. Natural gas imbalances occur when the Company’s actual gas sales volumes differ from its proportional share of production from the well. The company follows the sales method of accounting for these natural gas imbalances. The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2017 and 2016, the liabilities for natural gas balancing were immaterial. See Note B for further discussion on revenue recognition.  CASH EQUIVALENTS – Short-term investments, which include government securities and other instruments with government securities as collateral, that are highly liquid and have a maturity of three months or less from the date of purchase are classified as cash equivalents.  MARKETABLE SECURITIES – The Company classifies investments in marketable securities as available-for-sale or held-to-maturity. The Company does not have any investments classified as trading securities. Available-for-sale securities are carried at fair value with the unrealized gain or loss, net of tax, reported in other comprehensive loss. Held-to-maturity securities are recorded at amortized cost. Premiums and discounts are amortized or accreted into earnings over the life of the related available-for-sale or held-to-maturity security. Dividend and interest income is recognized when earned. Unrealized losses considered to be other than temporary are recognized currently in earnings. The cost of securities sold is based on the specific identification method. The fair value of investment securities is determined by available market prices. At December 31, 2016, the Company owned Canadian government securities with maturities greater than 90 days at date of acquisition that had a carrying value of $111.5 million. These securities are readily marketable and could be quickly converted to cash if needed to meet operating cash needs in Canada.  ACCOUNTS RECEIVABLE – At December 31, 2017 and 2016, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural gas. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses on these receivables. The Company reviews this allowance for adequacy at least quarterly and bases its assessment on a combination of current information about its customers and historical write-off experience. Any trade accounts receivable balances written off are charged against the allowance for doubtful accounts. The Company has not experienced any significant credit-related losses in the past three years. INVENTORIES – Amounts included in the Consolidated Balance Sheets include unsold crude oil production and materials and supplies associated with oil and gas production operations. Unsold crude oil production is carried in inventory at the lower of cost, generally applied on a first-in, first-out (FIFO) basis, or market, and includes costs incurred to bring the inventory to its existing condition. Materials and supplies inventories are valued at the lower of average cost or estimated value and generally consist of tubulars and other drilling equipment. PROPERTY, PLANT AND EQUIPMENT – The Company uses the successful efforts method to account for exploration and development expenditures. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Costs of undeveloped leases associated with unproved properties are expensed over the life of the leases. Exploratory well costs are capitalized pending determination about whether proved reserves have been found. In certain cases, a determination of whether a drilled exploratory well has found proved reserves cannot be made immediately. This is generally due to the need for a major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such a capital expenditure is usually dependent on whether further exploratory wells find a sufficient quantity of additional reserves. The Company continues to capitalize exploratory well costs in Property, Plant and Equipment 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. The Company reevaluates its capitalized drilling costs at least annually to ascertain whether drilling costs continue to qualify for ongoing capitalization. Other exploratory costs, including geological and geophysical costs, are charged to expense as incurred. Development costs, including unsuccessful development wells, are capitalized. Interest is capitalized on significant development projects that are expected to take one year or more to complete.  Oil and gas properties are evaluated by field for potential impairment. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets as applicable. An impairment is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to fair value. There was no impairment recorded in 2017. During 2016 and 2015, declines in future oil and gas prices provided indications of possible impairments in certain of the Company’s producing properties. As a result of management’s assessments during 2016, the Company recognized pretax noncash impairments charges of $95.1 million at its Terra Nova field offshore Canada and its Western Canada onshore heavy oil producing properties. In 2015, the Company recognized pretax noncash impairments charges of $2.5 billion to reduce the carrying value of certain producing properties in Malaysia, Western Canada and the Gulf of Mexico to their estimated fair value. See also Note E for further discussion of impairment charges.  The Company records a liability for asset retirement obligations (ARO) equal to the fair value of the estimated cost to retire an asset. The ARO liability is initially recorded in the period in which the obligation meets the definition of a liability, which is generally when a well is drilled or the asset is placed in service. The ARO liability is estimated by the Company’s engineers using existing regulatory requirements and anticipated future inflation rates. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is increased over time to reflect the change in its present value, and the capitalized cost is depreciated over the useful life of the related long-lived asset. The Company reevaluates the adequacy of its recorded ARO liability at least annually. Actual costs of asset retirements such as dismantling oil and gas production facilities and site restoration are charged against the related liability. Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company’s earnings.  Depreciation and depletion of producing oil and gas properties are recorded based on units of production. Unit rates are computed for unamortized exploration drilling and development costs using proved developed reserves; unit rates for unamortized leasehold costs and asset retirement costs are amortized over proved reserves. Proved reserves are estimated by the Company’s engineers and are subject to future revisions based on availability of additional information. Additionally, certain natural gas processing facilities and related equipment in Malaysia are being  depreciated on a straight-line basis over their estimated useful life ranging from 20 to 25 years. Gains and losses on asset disposals or retirements are included in net loss as a separate component of revenues. Turnarounds for coking units at Syncrude Canada Ltd. were scheduled at intervals of two to three years. Turnaround work associated with various other less significant units at Syncrude varied depending on operating requirements and events. Murphy defers turnaround costs incurred and amortizes such costs over the period until the next scheduled turnaround. This amortization is recorded in Lease operating expenses for Syncrude. All other maintenance and repairs are expensed as incurred. Renewals and betterments are capitalized. The Company sold its interest in Syncrude during 2016.  Capitalized Interest – Interest associated with borrowings from third parties is capitalized on significant oil and gas development projects when the expected development period extends for one year or more. Interest capitalized is credited in the Consolidated Statements of Operations and is added to the cost of the underlying asset for the development project in Property, plant and equipment in the Consolidated Balance Sheets. Capitalized interest is amortized over the useful life of the asset in the same manner as other development costs.  ENVIRONMENTAL LIABILITIES – A liability for environmental matters is established when it is probable that an environmental obligation exists and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Related expenditures are charged against the liability. Environmental remediation liabilities have not been discounted for the time value of future expected payments. Environmental expenditures that have future economic benefit are capitalized. INCOME TAXES – The Company accounts for income taxes using the asset and liability method. Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities based on differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse. The Company routinely assesses the realizability of deferred tax assets based on available evidence including assumptions of future taxable income, tax planning strategies and other pertinent factors. A deferred tax asset valuation allowance is recorded when evidence indicates that it is more likely than not that all or a portion of these deferred tax assets will not be realized in a future period. Prior to 2017, the Company did not provide U.S. deferred taxes for undistributed earnings of certain foreign subsidiaries when these earnings were considered indefinitely invested. On December 22, 2017 the Tax Cuts and Jobs Act (2017 Tax Act) was enacted which triggered the transitional tax on a deemed repatriation of all past foreign earnings (see Note I) and a provision for this impact has been recorded. Also, deferred tax liabilities are recorded for relevant withholding taxes when undistributed earnings of foreign subsidiaries are not considered indefinitely invested. Under present law, the Company would incur a 5% withholding tax on any earnings repatriated from Canada to the U.S. The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be realized, and then only for the largest amount that is greater than 50% l ikely of being realized. The Company includes potential penalties and interest for uncertain income tax positions in income tax expense. FOREIGN CURRENCY – Local currency is the functional currency used for recording operations in Canada and for former refining and marketing activities in the United Kingdom. The U.S. dollar is the functional currency used to record all other operations. Exchange gains or losses from transactions in a currency other than the functional currency are included in earnings. Gains or losses from translating foreign functional currencies into U.S. dollars are included in Accumulated Other Comprehensive Loss in Consolidated Statements of Stockholders’ Equity. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheets. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge for accounting purposes, and thenceforth, recognize changes in the fair value of the contract in earnings. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to  specific assets and liabilities or to specific firm commitments or forecasted transactions. The Company assesses at inception and on an ongoing basis whether a derivative instrument accounted for as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. The change in the fair value of a qualifying fair value hedge is recorded in earnings along with the gain or loss on the hedged item. The effective portion of the change in the fair value of a qualifying cash flow hedge is recorded in Accumulated other comprehensive loss in the Consolidated Balance Sheets until the hedged item is recognized currently in earnings. If a derivative instrument no longer qualifies as a cash flow hedge and the underlying forecasted transaction is no longer probable of occurring, hedge accounting is discontinued and the gain or loss recorded in Accumulated other comprehensive loss is recognized immediately in earnings.  Fair Value Measurements – The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. Fair value is determined using various techniques depending on the availability of observable inputs. Level 1 inputs include quoted prices in active markets for identical assets or liabilities. Level 2 inputs include observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants .  STOCK-BASED COMPENSATION Equity-Settled Awards – The fair value of awarded stock options, restricted stock units and other stock-based compensation that are settled with Company shares is determined based on a combination of management assumptions and the market value of the Company’s common stock. The Company uses the Black-Scholes option pricing model for computing the fair value of equity-settled stock options. The primary assumptions made by management include the expected life of the stock option award and the expected volatility of Murphy’s common stock price. The Company uses both historical data and current information to support its assumptions. Stock option expense is recognized on a straight-line basis over the respective vesting period of two or three years. The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock units that are equity settled and expense is recognized over the three -year vesting period. The fair value of time-lapse restricted stock units is determined based on the price of Company stock on the date of grant and expense is recognized over the vesting period. The Company estimates the number of stock options and performance-based restricted stock units that will not vest and adjusts its compensation expense accordingly. Differences between estimated and actual vested amounts are accounted for as an adjustment to expense when known.  Cash-Settled Awards – The Company accounts for stock appreciation rights (SAR), cash-settled restricted stock units (CRSU) and phantom stock units as liability awards. Expense associated with these awards are recognized over the vesting period based on the latest available estimate of the fair value of the awards, which is generally determined using a Black-Scholes method for SAR, a Monte Carlo method for performance-based CRSU, and the period-end price of the Company’s common stock for time-based CRSU and phantom units. When SAR are exercised and when CRSU and phantom units settle, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards .  PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS – The Company recognizes the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of its defined benefit and other postretirement benefit plans in the Consolidated Balance Sheets. Changes in the funded status which have not yet been recognized in the Consolidated Statement of Operations are recorded net of tax in Accumulated o ther c omprehensive l oss. The remaining amounts in Accumulated o ther c omprehensive l oss include net actuarial losses and prior service (cost) credit.  NET INCOME (LOSS) PER COMMON SHARE – Basic income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period plus the effects of all potentially dilutive common shares. Dilutive securities are not included in the computation of diluted income (loss) per share when a net loss occurs as the inclusion would have the effect of reducing the diluted loss per share.  USE OF ESTIMATES – In preparing the financial statements of the Company in conformity with U.S. generally accepted accounting principles (GAAP), 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 .

New Accounting Principles and R

New Accounting Principles and Recent Accounting Pronouncements	12 Months Ended
	Dec. 31, 2017
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  Compensation – Stock Compensation. In March 2016, the Financial Accounting Standards Board (FASB) issued an Accounting Standards Update (ASU) intended to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification within the statement of cash flows. The amendments in this ASU were effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures as there were no exercises of Company options during the period.  Business Combinations. In January 2017, the FASB issued an ASU to clarify the definition of a business to assist entities in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs. The update is effective for annual periods beginning after December 15, 2017, including interim periods within those periods. The prospective approach is required for adoption and early adoption is permitted for transactions not previously reported in issued financial statements. The Company adopted this guidance in 2017 and it did not have a material impact on its consolidated financial statements and footnote disclosures.   Recent Accounting Pronouncements  Revenue from Contracts with Customers. In May 2014, the FASB issued an ASU to establish a comprehensive new revenue recognition standard for contracts with customers that will supersede most current revenue recognition requirements and industry-specific guidance. The codification was amended through additional ASU’s and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers. The Company has performed a review of contracts in each of its revenue streams and has developed accounting policies to address the provisions of the ASU. As a result of this review, the Company’s gross revenues and expenses may be impacted based on the determination of whether it is acting as a principal or an agent in certain transactions. The Company adopted the new standard on January 1, 2018, using the modified retrospective method and does not currently expect net earnings, revenues or expenses to be materially impacted. The Company continues to evaluate the impact of this and other provisions of the ASU on related disclosures.  Leases. In February 2016, FASB issued an ASU to increase transparency and comparability among companies by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and this ASU is the recognition of right-of-use assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. The new standard is effective for financial statements issued for annual periods beginning after December 15, 2018 and interim periods within those annual periods. Early adoption is permitted for all entities. The Company anticipates adopting this guidance in the first quarter of 2019 and is currently analyzing its portfolio of contracts to assess the impact future adoption of this ASU may have on its consolidated financial statements.  Statement of Cash Flows. In August 2016, the FASB issued an ASU to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The amendment provides guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instrument with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees. The ASU is effective for annual and interim periods beginning after December 15, 2017. The Company anticipates adopting this guidance in the first quarter 2018 and does not believe the application of this ASU will have a material impact on its consolid ated financial statements and related footnote disclosures.  Compensation – Retirement Benefits. In March 2017, the FASB issued an ASU requiring that the service cost component of pension and postretirement benefit costs be presented in the same line item as other current employee compensation costs and other components of those benefit costs be presented separately from the service cost component and outside a subtotal of income from operations, if presented. The update also requires that only the service cost component of pension and postretirement benefit cost is eligible for capitalization. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. Application is retrospective for the presentation of the components of these benefit costs and prospective for the capitalization of only service costs. The Company anticipates adopting this guidance in the first quarter 2018 and does not believe the application of this ASU will have a material impact on its consolid ated financial statements and related footnote disclosures .  Compensation – Stock Compensation. In May 2017, FASB issued an ASU which amends the scope of modification accounting for share-based payment arrangements and provides guidance on the type of changes to the terms and conditions of share-based payment awards to which an entity would be required to apply modification accounting. The update is effective for annual periods beginning after December 15, 2017 and interim periods within the annual period. The Company anticipates adopting this guidance in the first quarter 2018 and does not believe the application of this ASU will have a material impact on its consolid ated financial statements and related footnote disclosures.

Discontinued Operations and Ass

Discontinued Operations and Assets Held for Sale	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Assets Held for Sale [Abstract]
Discontinued Operations and Assets Held for Sale	Note C – Discontinued Operations and Assets Held for Sale  The Company has accounted for its former U.K. and U.S. refining and marketing operations as discontinued operations for all periods presented.  The following table presents the carrying value of the major categories of assets and liabilities of U.K. discontinued refining and marketing operations and Seal operations in Canada reflected as held for sale on the Company’s Consolidated Balance Sheets at December 31, 2017 and 2016.    ( Thousands of dollars ) 2017 2016  Current assets  Cash $ 16,631 4,126  Accounts receivable 6,298 22,944  Other – –  Total current assets held for sale $ 22,929 27,070  Current liabilities  Accounts payable $ 837 270  Accrued compensation and severance – –  Refinery decommissioning cost 2,693 2,506  Total current liabilities associated with assets held for sale $ 3,530 2,776  Non-current liabilities  Asset retirement obligation – Seal asset $ – 85,900  The asset retirement obligation at December 31, 2016 relates to well and facility abandonment obligations at the Seal field in Canada which were assumed by the purchasing company upon the completion of the sale in January 2017 (see Note E) .  The results of operations associated with discontinued operations are presented in the following table.     ( Thousands of dollars ) 2017 2016 2015  Revenues $ 854 1,464 381,747  Loss from operations before income taxes $ (853) (2,027) (6,758)  Loss on sale before income taxes – – (4,990)  Total loss from discontinued operations before taxes (853) (2,027) (11,748)  Income tax expense – – 3,313  Loss from discontinued operations $ (853) (2,027) (15,061)     Certain reclassifications have been made to 2016 and 2015 Revenues to align with current period presentation (see Note A) .

Inventories

Inventories	12 Months Ended
	Dec. 31, 2017
Inventories [Abstract]
Inventories	Note D – Inventories  Inventories consisted of the following at December 31, 2017 and 2016.     December 31,  2017 2016  ( Thousands of dollars )  Unsold crude oil $ 20,153 17,146  Materials and supplies 84,974 109,925  $ 105,127 127,071  

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2017
Property, Plant And Equipment [Abstract]
Property, Plant and Equipment	Note E – Property, Plant and Equipment     December 31, 2017 December 31, 2016  ( Thousands of dollars ) Cost Net Cost Net  Exploration and production 1 $ 20,329,930 8,120,293 2 20,767,772 8,214,740 2  Corporate and other 170,842 99,738 156,231 101,448  $ 20,500,772 8,220,031 20,924,003 8,316,188  1 Includes unproved mineral rights as follows: $ 600,423 198,349 595,138 188,689 2. Includes $38,670 in 2017 and $48,053 in 2016 related to administrative assets and support equipment.  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 t he transaction was $48.8 million. Additionally, the buyer assumed the asset retirement obligation of approximately $85.9 million. A $129.0 million pretax gain was reported in 2017 related to the sale. Also, in 2017, a U.S. subsidiary of the Company completed its disposition of certain non-core properties in the Eagle Ford Shale area. Total cash consideration to Murphy upon closing of the transaction was approximately $19.6 million. There were no gains or losses recorded related to the non-core Eagle Ford Shale sales.  In 2016, a Canadian subsidiary of the Company completed the sale of its five percent, non-operated working interest in Syncrude Canada Ltd. (Syncrude) asset to Suncor Energy Inc. (Suncor). The Company received net cash proceeds of $739.1 million and recorded an after-tax gain of $71.7 million associated with the Syncrude divestiture.  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 $7.1 million and $5.1 million of the deferred gain during 2017 and 2016, respectively. The remaining deferred gain of $181.7 million was included as a component of D eferred credits and other liabilities in the Company’s Consolidated Balance Sheet as of December 31, 2017.  Acquisition  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 December 31, 2017, $44.8 million of the carried interest had been paid. The carry is to be paid over a period of up to five years from 2016.  Impairments  During 2016 and 2015, declines in future oil and gas prices led to impairments in certain of the Company’s producing properties. During 2016, the Company recorded pretax noncash impairment charges of $95.1 million to reduce the carrying values to their estimated fair values for the Terra Nova field offshore Canada and the Western Canada onshore heavy oil producing properties. In 2015, the Company recognized pretax noncash impairment charges of $2. 49 billion to reduce the carrying value of certain offshore producing and non-producing properties in the Gulf of Mexico, producing offshore properties in Malaysia and for Western Canada onshore heavy oil producing properties. The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs, and a discount rate believed to be consistent with those used by principal market participants in the applicable region. The following table reflects the recognized impairments for the three years ended December 31, 2017.      December 31,  ( Thousands of dollars ) 2017 2016 2015  Gulf of Mexico $ – – 328,982  Canada – 95,088 683,574  Malaysia – – 1,480,600  $ – 95,088 2,493,156  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 owners. The Gumusut-Kakap Unit is operated by another company. In the fourth quarter 2016, the owners 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 taxes) 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 further Unitization Framework Agreement (UFA) between the governments of Brunei and Malaysia, the Company now has a 6.35% interest in the Kakap field in Block K Malaysia as of December 31, 2017. 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.  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 December 31, 2017, 2016 and 2015, the Company had total capitalized drilling costs pending the determination of proved reserves of $175.6 million, $148.5 million and $130.5 million, respectively. The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2017.      ( Thousands of dollars ) 2017 2016 2015  Beginning balance at January 1 $ 148,500 130,514 120,455  Additions pending the determination of proved reserves 51,488 17,986 64,578  Reclassifications to proved properties based on the determination of proved reserves (15,988) – –  Capitalized exploratory well costs charged to expense (8,360) – (54,519)  Ending balance at December 31 $ 175,640 148,500 130,514  The capitalized well costs charged to expense in 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 capitalized well costs charged to expense in 2015 included one well in the Gulf of Mexico in which development of the well also could not be justified due to noncommercial hydrocarbon quantities found in the sidetrack and one project in the Gulf of Mexico deemed unlikely to be developed due to low commodity prices.  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 has been capitalized. The projects are aged based on the last well drilled in the project.     2017 2016 2015  ( Thousands of dollars ) Amount No. of Wells No. of Projects Amount No. of Wells No. of Projects Amount No. of Wells No. of Projects  Aging of capitalized well costs:  Zero to one year $ 41,480 3 2 $ 20,481 1 1 $ 66,032 7 6  One to two years 5,812 1 1 63,527 5 5 – – –  Two to three years 43,200 2 2 – – – 57,876 3 –  Three years or more 85,148 7 1 64,492 6 – 6,606 3 –  $ 175,640 13 6 $ 148,500 12 6 $ 130,514 13 6  Of the $134.1 million of exploratory well costs capitalized more than one year at December 31, 2017, $70.4 million is in Brunei, $43.2 million is in Vietnam and $20.5 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.

Financing Arrangements

Financing Arrangements	12 Months Ended
	Dec. 31, 2017
Financing Arrangements and Long-Term Debt [Abstract]
Financing Arrangements	 Note F – Financing Arrangements  At December 31, 2017, the Company has a $1.1 billion senior unsecured guaranteed credit facility (2016 facility) with a major banking consortium, which expires in August 2021 . At December 31, 2017, the Company had no outstanding borrowings under the 2016 facility; however, there were $90.7 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 December 31, 2017, the applicable base interest rate would have been 4.875% . At December 31, 2017, the Company was in compliance with all covenants related to the 2016 facility.  On November 17, 2017, the Company entered into the third amendment (Amendment No. 3) to the 2016 facility. Among other things, Amendment No. 3 extends the maturity date of the 2016 facility to August 17, 2021 , and reduces the facility fee on revolving commitments and the interest margin on revolving loans and increases the total leverage ratio under the financial covenants from < 3.75 :1.00 to < 4.00 :1.00.  In August 2017, the Company sold $550 million of new notes that bear interest at the rate of 5.75% and mature on August 15, 2025 . The Company incurred transaction costs of $8.4 million on the issuance of these new notes. The new notes pay interest semi-annually on February 15 and August 15 of each year. The initial interest payment was paid on February 15, 2018. The proceeds of the $550 million notes were used to redeem the Company’s 3.50% notes in September 2017. The 3.50% notes had an original maturity of December 2017.  In August 2016, the Company reduced its then existing $2.0 billion unsecured revolving credit facility (2011 facility) to $630 million (facility has since expired) and entered into a separate $1.2 billion senior unsecured guaranteed credit facility (2016 facility, subsequently reduced to $1.1 billion), with a major banking consortium that originally expired in August 2019, which was subsequently extended to 2021. The Company incurred transaction costs of approximately $14.0 million to place the 2016 facility which were included in financing activities in the Consolidated Statement of Cash Flows. Also in August 2016, the Company sold $550 million of notes that bear interest at the rate of 6.875% and mature on August 15, 2024 . The proceeds of the $550 million notes were used for general corporate purposes.  The Company 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 and its partners are parties to a 25 -year lease of production equipment at the Kakap field offshore Malaysia. The lease has been accounted for as a capital lease, and payments under the agreement are to be made over a 15 -year period through March 2029 . Current maturities of long-term debt and long-term debt on the Consolidated Balance Sheet included $9.9 million and $134.0 million, respectively, associated with this lease at December 31, 2017.

Long-term Debt

Long-term Debt	12 Months Ended
	Dec. 31, 2017
Financing Arrangements and Long-Term Debt [Abstract]
Long-term Debt	Note G – Long-term Debt    December 31,  (Thousands of dollars ) 2017 2016  Notes payable  3.50% notes, due December 2017 $ - 550,000  4.00% notes, due June 2022 500,000 500,000  4.45% notes, due December 2022 1 600,000 600,000  6.875% notes, due August 2024 550,000 550,000  5.75% notes, due August 2025 550,000 -  7.05% notes, due May 2029 250,000 250,000  5.875% notes, due December 2042 1 350,000 350,000  Total notes payable 2,800,000 2,800,000  Unamortized debt issuance cost and discount on notes payable (27,433) (23,835)  Total notes payable, net of unamortized discount 2,772,567 2,776,165  Capitalized lease obligation, due through March 2029 143,855 216,402  Total debt including current maturities 2,916,422 2,992,567  Current maturities (9,902) (569,817)  Total long-term debt $ 2,906,520 2,422,750  1 Due to a series of ratings changes by credit agencies, the paying interest rates on the notes due December 2022 and December 2042 decreased from 4.7% to 4.45% and 6.125% to 5.875%, respectively, at December 2017.  The amount of debt repayable over each of the next five years and thereafter are as follows: $9.9 million in 2018, $10.4 million in 2019, $11.0 million in 2020, $11.5 million in 2021, $1.11 b illion in 2022 and $1.77 billion thereafter.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligations [Abstract]
Asset Retirement Obligations	 Note H – Asset Retirement Obligations The asset retirement obligations liabilities (ARO) recognized by the Company at December 31, 2017 and 2016 are related to the estimated costs to dismantle and abandon its producing oil and gas properties and related equipment.  A reconciliation of the beginning and ending aggregate carrying amount of the asset retirement obligation for 2017 and 2016 is shown in the following table.      ( Thousands of dollars ) 2017 2016  Balance at beginning of year $ 781,057 825,312  Accretion expense 42,590 46,742  Liabilities incurred 52,331 13,690  Revisions of previous estimates (47,612) (4,511)  Liabilities settled (29,111) (20,589)  Liabilities assumed by purchaser of oil and gas assets (87,456) (91,883)  Changes due to translation of foreign currencies 10,340 12,296  Balance at end of year 722,139 781,057  Liabilities reported as held for sale at end of year 1 – (85,900)  Current portion of liability at end of year 2 (12,840) (13,629)  Noncurrent portion of liability at end of year $ 709,299 681,528  1 Liabilities held for sale related to Seal properties in Canada which were sold in January 2017. 2 Included in Other accrued liabilities on the Consolidated Balance Sheet.  The estimation of future ARO is based on a number of assumptions requiring professional judgment. The Company cannot predict the type of revisions to these assumptions that may be required in future periods due to the availability of additional information such as: prices for oil field services, technological changes, governmental requirements and other factors.  In 2017, revisions of previous estimates primarily reflect the impact of lower rig service rates in the U.S.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Taxes [Abstract]
Income Taxes	 Note I – Income Taxes  The components of income (loss) from continuing operations before income taxes for each of the three years presented and income tax expense (benefit) attributable thereto were as follows.      ( Thousands of dollars ) 2017 2016 2015  Income (loss) from continuing operations before income taxes  United States $ (299,349) (595,196) (1,259,268)  Foreign 371,151 102,081 (2,022,994)  Total $ 71,802 (493,115) (3,282,262)  Income tax expense (benefit)  Federal – Current $ – – (9,435)  – Deferred 156,065 (197,450) (241,127)  Total Federal 156,065 (197,450) (250,562)  State 4,230 13,984 (5,294)  Foreign – Current 122,318 146,861 (40,550)  – Deferred 100,125 (182,567) (730,084)  Total Foreign 222,443 (35,706) (770,634)  Total $ 382,738 (219,172) (1,026,490)  The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense.     ( Thousands of dollars ) 2017 2016 2015  Income tax expense (benefit) based on the U.S. statutory tax rate $ 25,131 (172,590) (1,148,792)  Revaluation of deferred tax (US tax reform) 118,004 – –  Deferred tax effect of deemed repatriation of foreign invested earnings (U.S. tax reform) 156,000 – –  Deferred tax effect on Canadian earnings no longer indefinitely invested 65,000 – –  Foreign income (loss) subject to foreign tax rates different than the U.S. statutory rate 12,658 8,582 49,739  State income taxes, net of federal benefit 2,438 9,090 (3,441)  U.S. tax benefit on certain foreign upstream investments (32,926) (21,336) (16,939)  Deferred tax on distribution of foreign earnings – – 188,461  Tax effects on sale of Canadian assets – (89,473) –  Tax effects on sale of Malaysian assets – 2,080 (122,559)  Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures 18,601 25,734 40,788  Other, net 17,832 18,741 (13,747)  Total $ 382,738 (219,172) (1,026,490)  The Tax Cuts and Jobs Act On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (2017 Tax Act). For the year ended December 31, 2017, the Company recorded a tax expense of $274.0 million directly related to the impacts of the 2017 Tax Act. The charge includes the impact of a deemed repatriation of foreign earnings and the re-measurement of deferred tax assets and liabilities. Separately, Murphy expects to receive cash refunds or credits of $29.7 million over the next four years relating to Alternative Minimum Tax credits generated in earlier years. Murphy continues to assess the impact of this legislation including, among other things, the carryforward of 2017 net operating losses, refinement of post-1986 accumulated foreign earnings and profits computations, the change to U.S. federal tax rates, the possible limitations on the deductibility of interest expense, the option for expensing of  capital expenditures, the migration from a worldwide system of taxation to a territorial system, and the use of new anti-base erosion provisions. The tax expense recorded in 2017 is a reasonable estimate based on published guidance available at this time and is considered provisional. The ultimate impact of the 2017 Tax Act may differ from these estimates due to changes in interpretations and assumptions made by the company, as well as additional regulatory guidance that may be issued. The Company’s statutory U.S. federal income tax rate will be 21% beginning in 2018, a decrease from the previous rate of 35 %.  As part of the transition of the U.S. tax system to a territorial system, the 2017 Tax Act provides that certain past accumulated undistributed foreign earnings are deemed repatriated. The territorial system is effective January 1, 2018. For financial statement reporting purposes, the Company believes the 2016 tax net operating loss can be carried forward into 2018 and later years to offset U.S. taxable income. The legislation is inconclusive regarding whether the estimated 2017 tax operating loss incurred by the Company prior to the 2017 Tax Act’s required deemed repatriation at December 31, 2017 may be excluded from the deemed repatriation tax computation (Internal Revenue Code Section 965(n)).  Based on interpretation and guidance at this time and uncertainty regarding whether the new Section 965(n) election applies to a 2017 loss, the Company’s tax provision reflects the estimated 2017 tax operating loss being applied fully against the deemed income inclusion. This results in the inability to carryforward the 2017 tax operating loss and the creation of unused foreign tax credit carryforwards with a limited ten-year life. A full valuation allowance has been provided against these unused foreign tax credits to be carried forward. If the Company had prepared the 2017 tax provision preserving the 2017 tax loss as a carryforward, the unused foreign tax credits would have been available to offset a large portion of the tax resulting from the deemed inclusion of foreign earnings, and the U.S. deferred tax charge would have been reduced by approximately $120.0 million with the $36 million residual balance reclassified from deferred tax to a deemed repatriation tax payable over eight years . In the event the Internal Revenue Service or other guidance subsequently determines that the 2017 tax operating loss can be preserved as a carryforward to subsequent years with a twenty-year life, the Company will adjust its financial statements in future periods.  An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 201 7 and 201 6 showing the tax effects of significant temporary differences follows.     ( Thousands of dollars ) 2017 2016  Deferred tax assets  Property and leasehold costs $ 488,584 572,481  Liabilities for dismantlements 98,444 170,946  Postretirement and other employee benefits 134,444 214,288  Alternative minimum tax 29,710 29,710  Foreign tax credit carryforwards 228,159 33,295  U. S. net operating loss 272,930 454,231  Other deferred tax assets 13,892 16,541  Total gross deferred tax assets 1,266,163 1,491,492  Less valuation allowance (476,256) (305,389)  Net deferred tax assets 789,907 1,186,103  Deferred tax liabilities  Deferred tax on undistributed foreign earnings (65,000) –  Accumulated depreciation, depletion and amortization (669,638) (867,343)  Other deferred tax liabilities (2,824) (21,908)  Total gross deferred tax liabilities (737,462) (889,251)  Net deferred tax assets $ 52,445 296,852  In management’s judgment, the net deferred tax assets in the preceding table are more likely than not to be realized based on the consideration of deferred tax liability reversals and future taxable income. The valuation allowance for  deferred tax assets relates primarily to tax assets arising in foreign tax jurisdictions and foreign tax credit carryforwards; in the judgment of management at the present time, these tax assets are more likely than not unexpected to be realized. The foreign tax credit carryforwards expire in 2018 through 2027 . The valuation allowance increased $170.9 million in 2017 primarily due to foreign tax credit carryforwards realized from the deemed repatriation of accumulated undistributed foreign earnings under the 2017 Tax Act. Subsequent reductions of the valuation allowance are expected to be reported as reductions of tax expense assuming no offsetting change in the deferred tax asset.  The Company has an estimated U.S. net operating loss of $1.29 billion at year-end 2017 with a corresponding deferred tax asset of $272.9 million. The Company believes the U.S. net operating loss being carried forward will be utilized in future periods prior to expiration in 2036 .  Under present law, if the Company repatriates earnings from Canada to the United States in the future, it would incur a 5% withholding tax on the amounts repatriated. A provision of $65.0 million is recorded in the Company’s financial statements for future repatriation of $1.3 billion of Canada’s past foreign earnings no longer de emed indefinitely reinvested.  Other Information  The Company currently expects in 2018 to repatriate cash to the U.S. of $700 million of Canada’s past earnings not indefinitely invested, which will lead to a tax withholding payment of $35.0 million (provided for as part of the $65.0 million for future repatriation). In December 2015, one of the Company’s foreign subsidiaries declared a $2.0 billion dividend payable to its parent. The dividend represented substantially all of the foreign subsidiary’s accumulated retained earnings under U.S. GAAP. The foreign subsidiary’s dividend was settled with an $800 million cash payment plus issuance of a $1.2 billion note payable to its U.S. parent that was settled in June 2016. The dividend was completed without a U.S. current tax impact due to the utilization of the 2015 U.S. tax net operating loss combined with the shareholder’s ability to use foreign tax credits that attached to the dividend. Based on the usage of the 2015 U.S. tax net operating loss, a noncash tax expense of $188.5 million was recorded in 2015, primarily associated with using a U.S. deferred tax asset that without the dividend would otherwise have carried forward to future years.  Uncertain Income Tax Positions The FASB’s rules for accounting for income tax uncertainties clarify the criteria for recognizing uncertain income tax benefits and require additional disclosures about uncertain tax positions. Under current rules the financial statement recognition of the benefit for a tax position is dependent upon the benefit being more likely than not to be sustainable upon examination. If this threshold is met, the tax benefit is then measured and recognized at the largest amount that is greater than 50% likely of being realized upon ultimate settlement. Liabilities associated with uncertain income tax positions are included in Deferred credits and other liabilities in the Consolidated Balance Sheets. A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the three years presented is shown in the following table.       ( Thousands of dollars ) 2017 2016 2015  Balance at January 1 $ 7,417 6,631 6,011  Additions for tax positions related to current year 769 756 821  Settlements due to lapse of time (4,834) – –  Foreign currency translation effect 85 30 (201)  Balance at December 31 $ 3,437 7,417 6,631  All additions or settlements to the above liability affect the Company’s effective income tax rate in the respective period of change. The Company accounts for any applicable interest and penalties on uncertain tax positions as a component of income tax expense. The Company also had other recorded liabilities as of December 31, 2017, 2016 and 2015 for interest and penalties of $0.1 million, $0.3 million and $0.2 million, respectively, associated with uncertain tax positions. Income tax expense for the years ended December 31, 2017, 2016 and 2015 included net benefits for interest and penalties of $0.2 million, $0.1 million and $0.1 million , respectively, associated with uncertain tax positions.   During the next twelve months, the Company currently expects to add between $1.0 million and $2.0 million to the liability for uncertain taxes for 2018 events. Although existing liabilities could be reduced by settlement with taxing authorities or lapse due to statute of limitations, the Company believes that the changes in its unrecognized tax benefits due to these events will not have a material impact on the Consolidated Statement of Operations during 2018.  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 December 31, 2017, the earliest years remaining open for audit and/or settlement in the Company’s major taxing jurisdictions are as follows: United States – 2014 ; Canada – 2012 ; Malaysia – 2011 ; and United Kingdom – 2016 .

Incentive Plans

Incentive Plans	12 Months Ended
	Dec. 31, 2017
Incentive Plans [Abstract]
Incentive Plans	 Note J – Incentive Plans  Murphy utilizes cash-based and/or share-based incentive plans to supplement normal salaries as compensation for executive management and certain employees. For share-based awards that qualify for equity accounting, costs are recognized as an expense in the Consolidated Statements of Operations using a grant date fair value-based measurement method over the periods that the awards vest. For share-based awards that are required to be accounted for under liability accounting rules, costs are recognized as expense using a fair value-based measurement method over the vesting period, but expense is adjusted as necessary through the date the award value is finally determined. Total expense for liability awards is ultimately adjusted to the final intrinsic value for the award.  At December 31, 2017 , the Company has incentive awards issued to employees under the 2012 Long-Term Incentive Plan (2012 Long-Term Plan) and the 2012 Annual Incentive Plan (2012 Annual Plan). The 2012 Annual Plan authorizes the Executive Compensation Committee (the Committee) to establish specific performance goals associated with annual cash awards that may be earned by officers, executives and certain other employees. Cash awards under the 2012 Annual Plan are determined based on the Company’s actual financial and operating results as measured against the performance goals established by the Committee. The 2012 Long-Term 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, performance units, performance shares, dividend equivalents and other stock-based incentives. The 2012 Long-Term Plan expires in 2022 . A total of 8.7 million 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. Based on awards made to date, approximately 2.6 million shares remained available for grant under the 2012 Long-Term Plan at December 31, 201 7 . The Company also has a 2013 Stock Plan for Non-Employee Directors (Director Plan) that permits the issuance of restricted stock, restricted stock units and stock options or a combination thereof to the Company’s Non-Employee Directors.  Amounts recognized in the financial statements with respect to share-based plans are shown in the following table :     ( Thousands of dollars ) 2017 2016 2015  Compensation charged against income (loss) before income tax benefit $ 40,365 46,300 44,021  Related income tax benefit recognized in income 5,017 15,244 13,583  As of December 31, 201 7 , there were $29.8 million in compensation costs to be expensed over approximately the next two years related to unvested share-based compensation arrangements granted by the Company. Employees receive net shares, after applicable statutory withholding taxes, upon each stock option exercise and restricted stock award . Total income tax benefits realized from tax deductions related to stock option exercises under share-based payment arrangements were immaterial for the year ended December 31, 201 5. There were no income tax benefits realized in either 2017 or 2016 due to no stock option exercises during th ose year s .  Share-Settled Awards  STOCK OPTIONS – The Committee fixes the option price of each option granted at no less than fair market value (FMV) on the date of the grant and fixes the option term at no more than seven years from such date. Each option granted to date under the 2012 Long-Term Plan and the 2007 Long-Term Plan has been nonqualified, with a term of seven years and an option price equal to FMV at date of grant. Under these plans, one-half of each grant is generally exercisable after two years and the remainder after three years. For stock options, the number of shares issued upon exercise is reduced for settlement of applicable statutory income tax withholdings owed by the grantee.  The fair value of each option award is estimated on the date of grant using the Black-Scholes pricing model based on the assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s stock and implied volatility on publicly traded at-the-money options on the Company’s stock. The Company estimates the expected term of the options granted based on historical option exercise patterns and considers certain groups of employees exhibiting different behavior. The risk-free interest rate for periods within the expected term of the option is based on the U.S. Treasury yield curve in effect at the time of grant.     2017 2016 2015   Fair value per option grant $7.96 $5.03 $10.97 – $11.08  Assumptions  Dividend yield 3.60% 4.00% 2.40% – 2.50 %  Expected volatility 41.00% 45.00% 29.00% – 30.00%  Risk-free interest rate 1.97% 1.32% 1.34% – 1.60%  Expected life 5.30 yrs. 5.20 yrs. 5.30 yrs.   Changes in stock options outstanding during the last three years are presented in the following table.      Number of Shares Average Exercise Price  Outstanding at December 31, 2014 5,602,250 $ 57.95  Granted at FMV 991,000 49.67  Exercised (32,349) 40.80  Forfeited (1,117,613) 31.99  Outstanding at December 31, 2015 5,443,288 52.93  Granted at FMV 862,000 17.57  Exercised – –  Forfeited (547,853) 44.23  Outstanding at December 31, 2016 5,757,435 48.46  Granted at FMV 603,000 28.51  Exercised – –  Forfeited (1,459,166) 49.34  Outstanding at December 31, 2017 4,901,269 45.74  Exercisable at December 31, 2014 3,030,105 $ 53.10  Exercisable at December 31, 2015 3,542,352 52.26  Exercisable at December 31, 2016 3,830,535 53.80  Exercisable at December 31, 2017 3,197,269 54.22   Additional information about stock options outstanding at December 31, 201 7 is shown below.      Options Outstanding Options Exercisable  Range of Exercise Prices per Option No. of Options Avg. Life Remaining in Years Aggregate Intrinsic Value No. of Options Avg. Life Remaining in Years Aggregate Intrinsic Value  $17.00 to $30.00 1,320,000 5.5 $ 11,652,680 – – $ –  $31.00 to $50.00 823,350 3.9 – 439,350 3.8 –  $51.00 to $65.00 2,757,919 1.6 – 2,757,919 1.6 –  4,901,269 3.0 $ 11,652,680 3,197,269 1.9 $ –  The total intrinsic value of options exercised during 201 5 was $0.2 million . There were no options exercised in both 2017 and 201 6 as all awards either had no intrinsic value or were not vested. Intrinsic value is the excess of the market price of stock at date of exercise over the exercise price received by the Company upon exercise. Aggregate intrinsic value is nil when the exercise price of the stock option exceeds the market price of the Company’s c ommon stock.  PERFORMANCE-BASED RESTRICTED STOCK UNITS – Performance-based restricted stock units (PRSUS) to be settled in Common shares were granted in each of the last three years under the 2012 Long-Term Plan. Each grant will vest if the Company achieves specific performance objectives at the end of the designated performance period. Additional shares may be awarded if performance objectives are exceeded. If performance goals are not met, PRSUS will not vest, but recognized compensation cost associated with the stock award would not be reversed. For past awards, the performance conditions were based on the Company’s total shareholder return over the performance period compared to an industry peer group of companies. During the performance period, PRSUS are subject to transfer restrictions and are subject to forfeiture if a grantee terminates for reasons other than retirement, disability or death. Termination for these three reasons will lead to a pro rata award of amounts earned. No dividends are paid or voting rights exist on awards of PRSUS prior to their settlement.   Changes in PRSUS outstanding for each of the last three years are presented in the following table.      ( Number of share units ) 2017 2016 2015  Outstanding at beginning of year 992,573 1,103,986 1,397,040  Granted 560,000 394,000 455,000  Awarded (272,725) (361,096) (521,800)  Forfeited (91,927) (144,317) (226,254)  Outstanding at end of year 1,187,921 992,573 1,103,986   The fair value of the equity-settled performance-based awards granted in each year was estimated on the date of grant using a Monte Carlo valuation model. Expected volatility was based on daily historical volatility of the Company’s stock price compared to a peer group average over a three-year period. The risk-free interest rate is based on the yield curve of three-year U.S. Treasury bonds and the stock beta was calculated using three years of historical averages of daily stock data for Murphy and the peer group. The assumptions used in the valuation of the performance awards granted in 201 7 , 201 6 and 201 5 are presented in the following table.     2017 2016 2015   Fair value per share at grant date $24.10 – $28.28 $12.21 – $16.34 $44.03 – $48.12  Assumptions  Expected volatility 47.00% 33.00% 26.00%  Risk-free interest rate 1.46% 0.93% 0.85%  Stock beta 1.058 0.863 0.813  Expected life 3.0 yrs. 3.0 yrs. 3.0 yrs.  TIME-LAPSE RESTRICTED STOCK UNITS – Time-lapsed restricted stock units (TRSUS) have been granted to the Company’s Non-Employee Directors under the Directors Plan and to certain employees under the 2012 Long-Term Plan. These awards vest on the third anniversary of the date of grant. The fair value of these awards was estimated based on the market value of the Company’s stock on the date of grant, which were $28.51 per share in 2017, $17.57 per share in 2016, and $49.67 per share in 2015.  Changes in TRSUS outstanding for each of the last three years are presented in the following table.      ( Number of share units ) 2017 2016 2015   Outstanding at beginning of year 923,282 477,244 321,789  Granted 419,720 503,555 282,065  Vested and issued (217,633) (32,092) (69,610)  Forfeited (89,389) (25,425) (57,000)  Outstanding at end of year 1,035,980 923,282 477,244   EMPLOYEE STOCK PURCHA SE PLAN (ESPP) – The Company had an ESPP under which the Company’s Common stock could have been purchased by eligible U.S. and Canadian employees. Each quarter, an eligible employee could have elect ed to withhold up to 10% of his or her salary to purchase shares of the Company’s stock at the end of the quarter at a price equal to 90% of the fair value of the stock as of the first day of the quarter. The ESPP terminated June 30, 2017. Employee stock purchases under the ESPP were 2,564 shares at an average price of $26.85 per share in 2017, 8,962 shares at an average price of $23.41 per share in 2016, and 8,387 shares at an average price of $34.93 per share in 2015. Compensation costs related to the ESPP were estimated based on the value of the 10% discount and the fair value of the option that provided for the refund of participant withholdings , and such expenses were immaterial for all periods presented. The fair value per share issued under the ESPP was approximately $5.34 , $2.94 , and $5.74 for the years ended December 31, 201 7 , 201 6 and 201 5 , respectively.   Cash-Settled Awards  The Company has granted stock-based incentive awards to be settled in cash to certain employees in the form of Stock Appreciation Rights (SAR), Performance-based restricted stock units (PRSUC), Time-based restricted stock units (TRSUC) and Phantom units.  SAR awards have terms similar to stock options . PRSUC terms are similar to other performance-based restricted stock awards . TRSUC are generally settled on the third anniversary of the date of grant. Phantom units generally settle three to five years from date of grant. Each award granted is settled, net of applicable income tax withholdings, in cash rather than with Common shares. Total expense recorded in the Consolidated Statements of Operations for all cash-settled stock-based awards was $12.9 million in 2017, $17.2 million in 2016 and $1.6 million in 2015.  The Committee also administers the Company’s incentive compensation plans, which provide for annual or periodic cash awards to officers, directors and certain other employees. These cash awards are generally determinable based on the Company achieving specific financial and/or operational objectives. Compensation expense of $30.5 million, $25.8 million and $26.4 million was recorded in 201 7 , 201 6 and 201 5 , respectively, for these plans.

Employee and Retiree Benefit Pl

Employee and Retiree Benefit Plans	12 Months Ended
	Dec. 31, 2017
Employee and Retiree Benefit Plans [Abstract]
Employee and Retiree Benefit Plans	Note K – Employee and Retiree Benefit Plans PENSION AND OTHER POSTRETIREMENT PLANS – The Company has defined benefit pension plans that are principally noncontributory and cover most full-time employees. All pension plans are funded except for the U.S. and Canadian nonqualified supplemental plans and the U.S. directors’ plan. All U.S. tax qualified plans meet the funding requirements of federal laws and regulations. Contributions to foreign plans are based on local laws and tax regulations. The Company also sponsors health care and life insurance benefit plans, which are not funded, that cover most retired U.S. employees. The health care benefits are contributory; the life insurance benefits are noncontributory.  Upon the disposal of Murphy’s former U.K. downstream assets, the Company retained all vested defined benefit pension obligations associated with former employees of this business. No additional benefits will accrue to these former U.K. employees under the Company’s retirement plan after the date of their separation from Murphy.  GAAP requires the Company to recognize the overfunded or underfunded status of its defined benefit plans as an asset or liability in its consolidated balance sheet and to recognize changes in that funded status between periods through accumulated other comprehensive loss.    The tables that follow provide a reconciliation of the changes in the plans’ benefit obligations and fair value of assets for the years ended December 31, 2017 and 2016 and a statement of the funded status as of December 31, 2017 and 2016.     Pension Benefits Other Postretirement Benefits  ( Thousands of dollars ) 2017 2016 2017 2016  Change in benefit obligation  Obligation at January 1 $ 815,593 794,589 106,679 115,222  Service cost 8,279 8,136 1,601 1,864  Interest cost 27,047 25,185 3,444 3,800  Participant contributions – – 2,075 1,278  Actuarial loss (gain) 60,855 58,236 (3,077) (10,627)  Medicare Part D subsidy – – 318 510  Exchange rate changes 18,751 (30,447) 46 20  Benefits paid (39,910) (40,928) (4,810) (5,369)  Curtailments – 822 – (19)  Other (8,683) – – –  Obligation at December 31 881,932 815,593 106,276 106,679  Change in plan assets  Fair value of plan assets at January 1 519,357 521,682 – –  Actual return on plan assets 50,079 61,860 – –  Employer contributions 24,918 8,186 2,417 3,581  Participant contributions – – 2,075 1,278  Medicare Part D subsidy – – 318 510  Exchange rate changes 18,064 (30,609) – –  Benefits paid (39,910) (40,928) (4,810) (5,369)  Other (8,683) (834) – –  Fair value of plan assets at December 31 563,825 519,357 – –  Funded status and amounts recognized in the Consolidated Balance Sheets at December 31  Deferred charges and other assets 5,905 7,591 – –  Other accrued liabilities (8,856) (8,184) (5,392) (5,267)  Deferred credits and other liabilities (315,156) (295,643) (100,884) (101,412)  Funded status and net plan liability recognized at December 31 $ (318,107) (296,236) (106,276) (106,679)   At December 31, 2017, amounts included in A ccumulated other comprehensive loss (AOCL) in the Consolidated Balance Sheets , before reduction for associated deferred income taxes, which have not been recognized in net periodic benefit expense are shown in the following table.     ( Thousands of dollars ) Pension Benefits Other Postretirement Benefits  Net actuarial loss $ (269,063) 221  Prior service (cost) credit (5,824) 38  $ (274,887) 259  Amounts included in AOCL at December 31, 2017 that are expected to be amortized into net periodic benefit expense during 2018 are shown in the following table.     ( Thousands of dollars ) Pension Benefits Other Postretirement Benefits  Net actuarial loss $ (15,890) –  Prior service (cost) credit (1,021) 38  $ (16,911) 38  The table that follows includes projected benefit obligations, accumulated benefit obligations and fair value of plan assets for plans where the accumulated benefit obligation exceeded the fair value of plan assets.     Projected Benefit Obligations Accumulated Benefit Obligations Fair Value of Plan Assets  ( Thousands of dollars ) 2017 2016 2017 2016 2017 2016  Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets $ 691,923 643,174 640,230 599,730 540,161 497,894  Unfunded nonqualified and directors' plans where accumulated benefit obligation exceeds fair value of plan assets 172,364 156,088 163,319 150,780 – –  Unfunded other postretirement plans 106,276 106,678 106,276 106,678 – –   The table that follows provides the components of net periodic benefit expense for each of the three years ended December 31, 2017.     Pension Benefits Other Postretirement Benefits  ( Thousands of dollars ) 2017 2016 2015 2017 2016 2015  Service cost $ 8,279 8,136 17,948 1,601 1,864 3,180  Interest cost 27,047 25,185 33,168 3,444 3,800 4,883  Expected return on plan assets (28,941) (28,154) (34,016) – – –  Amortization of prior service cost (credit) 1,026 1,204 1,560 (74) (75) (82)  Amortization of transitional (asset) liability – – (1) – – –  Recognized actuarial loss 16,691 16,165 15,147 – 5 992  24,102 22,536 33,806 4,971 5,594 8,973  Termination benefits expense – – 8,606 – – –  Curtailment expense – 822 306 – (19) –  Net periodic benefit expense $ 24,102 23,358 42,718 4,971 5,575 8,973  Termination and curtailment expenses in 2016 and 2015 were primarily related to plan amendments made upon early retirement of certain employees during 2016 and 2015.  The preceding tables in this note include the following amounts related to foreign benefit plans.     Pension Benefits Other Postretirement Benefits  ( Thousands of dollars ) 2017 2016 2017 2016  Benefit obligation at December 31 $ 222,483 206,502 791 615  Fair value of plan assets at December 31 212,535 197,575 – –  Net plan liabilities recognized 9,948 8,927 791 615  Net periodic benefit expense (benefit) 194 (2,244) 133 154  The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2017 and 2016 and net periodic benefit expense for 2017 and 2016.     Benefit Obligations Net Periodic Benefit Expense  Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits  December 31 December 31 Year Year  2017 2016 2017 2016 2017 2016 2017 2016  Discount rate 3.42% 3.94% 3.73% 4.41% 3.66% 3.84% 4.33% 4.24%  Expected return on plan assets 5.64% 5.62% – – 5.64% 5.62% – –  Rate of compensation increase 3.52% 3.52% – – 3.52% 3.52% – –   The discount rates used for determining the plan obligations and expense are based on the universe of high-quality corporate bonds that are available within each country. Cash flow analyses are performed in which a spot yield curve is used to discount projected benefit payment streams for the most significant plans. The discounted cash flows are used to determine an equivalent single rate which is the basis for selecting the discount rate within each country. Expected plan asset returns are based on long-term expectations for asset portfolios with similar investment mix characteristics. Expected compensation increases are based on anticipated future averages for the Company.  Benefit payments, reflecting expected future service as appropriate, which are expected to be paid in future years from the assets of the plans or by the Company are shown in the following table.     ( Thousands of dollars ) Pension Benefits Other Postretirement Benefits  2018 $ 39,929 6,259  2019 40,236 6,280  2020 41,220 6,357  2021 42,276 6,489  2022 43,554 6,560  2023-2027 227,039 33,971   For purposes of measuring postretirement benefit obligations at December 31, 2017, the future annual rates of increase in the cost of health care were assumed to be 6.7% for 2017 decreasing each year to an ultimate rate of 4.5% in 2038 and thereafter.  Assumed health care cost trend rates have a significant effect on the expense and obligation reported for the postretirement benefit plan. A 1% change in assumed health care cost trend rates would have the following effects.     ( Thousands of dollars ) 1% Increase 1% Decrease  Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2017 $ 919 (719)  Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2017 15,220 (12,277)  During 2017, the Company made contributions of $18.0 million to its domestic defined benefit pension plans, $6.9 million to its foreign defined benefit pension plans and $2.4 million to its domestic postretirement benefits plan. D uring 2018 , Company currently expects to make contributions of $24.4 million to its domestic defined benefit pension plans, $0.6 million to its foreign defined benefit pension plans and $5.4 million to its domestic postretirement benefits plan.   Plan Investments – Murphy Oil Corporation maintains an Investment Policy Statement (Statement) that establishes investment standards related to its funded domestic qualified retirement plan. The Statement specifies that all assets will be held in a Trust sponsored by the Company, which is administrated by a trustee appointed by the Investment Committee (Committee). Members of the Committee are appointed by the Chief Executive Officer of Murphy. The Committee hires Investment Managers to invest trust assets within the guidelines established by the Committee as allowed by the Statement. The investment goals call for a portfolio of assets consisting of equity, fixed income and cash equivalent securities. The primary consideration for investments is the preservation of capital, and investment growth should exceed the rate of inflation. The Committee has directed the asset investment advisors of its benefit plans to maintain a portfolio consisting of both equity and fixed income securities. The Company believes that over time a balanced to slightly heavier weighting of the portfolio in equity securities compared to fixed income securities represents the most appropriate long-term mix for future investment return on assets held by domestic plans. The parameters for asset allocation call for the following minimum and maximum percentages: equity securities of between 40% and 70% ; fixed income securities of between 30% and 60% ; long/short equity of between 0% and 15% ; and cash and equivalents of between 0% and 15% . The Committee is authorized to direct investments within these parameters. Equity investments may include common, preferred and convertible preferred stocks, emerging markets stocks and similar funds, and long/short equity funds. Long/short equity is a strategy invested in a portfolio of long stocks hedged with short sales of stocks and/or stock index options, with the combination of investment intended to produce equity-like returns with lower volatility over the long term. Generally, no more than 10% of an Investment Manager’s portfolio is to be held in equity securities of any one issuer, and equity securities should have a minimum market capitalization of $100 million. Equities held in the trust should be listed on the New York or American Stock Exchanges, principal U.S. regional exchanges, major foreign exchanges or quoted in significant over-the-counter markets. Equity or fixed income securities issued by the Company may not be held in the trust. Fixed income securities include maturities greater than one year to maturity. The fixed income portfolio should not exceed an average maturity of 11 years. The portfolio may include investment grade corporate bonds, issues of the U.S. government, its agencies and government sponsored entities, government agency issued collateralized mortgage backed securities, agency issued mortgage backed securities, municipal bonds, asset backed securities, commercial mortgage backed securities and international and emerging markets bond funds. The Committee routinely reviews the investment performance of Investment Managers.  For the U.K. retirement plan, trustees have been appointed by the wholly-owned subsidiary that sponsors the plan for U.K. employees. The trustees have hired a fiduciary investment manager to manage the assets of the plan within the parameters of the Statement of Investment Principles (Statement). The objective of investments is to earn a reasonable return within the allocation strategy permitted in the Statement while limiting the risk for the funded position of the plan. The Statement specifies a strategy with an allocation goal of 60% Delegated growth fund (DGF) equities and 40% Delegated liability fund (DLF). Also, the allocation goal includes interest rate hedge ratio and inflation rate hedge ratio of 100% . Hewitt Risk Management Services Limited (Manager) has discretion to vary the level of interest rate and inflation hedge ratios from the strategic levels. The DGF is diversified by style, strategy and asset class by investing with underlying funds that may include equity funds, fixed income funds, debt funds, currency funds, hedge funds, fund of hedge funds and other collective investment schemes covering a broad range of asset classes and strategies. The DLF aims to provide returns in line with the liabilities of typical pension schemes on an exposure basis in the relevant tenures and instruments (long/short, real/nominal). The DLF holds cash as collateral for the leveraged positions. Small working cash balances are permitted to facilitate daily management of payments and receipts within the plan. The trustee routinely review s the investment performance of the plan.  For the Canadian retirement plan, the wholly-owned subsidiary that sponsors the plan has a Statement of Investment Policies and Procedures (Policy) applicable to the plan assets. A pension committee appointed by the board of directors of the subsidiary oversees the plan, selects the investment advisors and routinely reviews performance of the asset portfolio. The Policy permits assets to be invested in various Canadian and foreign equity securities, various fixed income securities, real estate, natural resource properties or participation rights and cash. The objective for plan investments is to achieve a total rate of return equal to the long-term interest rate assumption used for the going-concern actuarial funding valuation. The normal allocation for 2017 includes total equity securities of 60% with a range of 55% to 65% of total assets. Fixed income securities have a normal allocation of 35% with a range of 30% to 40% . Cash will normally have an allocation of 5% with a range of 0% to 10% . The Policy calls for diversification norms within the investment portfolios of both equity securities and fixed income securities.  The weighted average asset allocation for the Company’s funded pension benefit plans at December 31, 201 7 and 201 6 are presented in the following table.     December 31,  2017 2016  Equity securities 60.3 % 58.4 %  Fixed income securities 37.2 39.0  Cash equivalents 2.5 2.6  100.0 % 100.0 %  The Company’s weighted average expected return on plan assets was 5.64% in 2017 and the return was determined based on an assessment of actual long-term historical returns and expected future returns for a portfolio with investment characteristics similar to that maintained by the plans. The 5.64% expected return was based on an expected average future equity securities return of 7.15% and a fixed income securities return of 4.26% and is net of average expected investment expenses of 0.60% . Over the last 10 years, the return on funded retirement plan assets has averaged 6.66% .  At December 31, 2017, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.     Fair Value Measurements Using  ( Thousands of dollars ) Fair Value at December 31, 2017 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3)  Domestic Plans  Equity securities:  U.S. core equity $ 67,343 67,343 – –  U.S. small/midcap 24,544 24,544 – –  Hedged funds and other alternative strategies 50,522 – 12,572 37,950  International commingled trust fund 83,960 – 83,960 –  Emerging market commingled equity fund 20,774 – 20,774 –  Fixed income securities:  U.S. fixed income 79,890 – 79,890 –  International commingled trust fund 13,122 – 13,122 –  Emerging market mutual fund 5,266 – 5,266 –  Cash and equivalents 5,871 5,871 – –  Total Domestic Plans 351,292 97,758 215,584 37,950  Foreign Plans  Equity securities funds 78,666 – 78,666 –  Fixed income securities funds 103,314 – 103,314 –  Diversified pooled fund 23,665 – 23,665 –  Cash and equivalents 6,888 – 6,888 –  Total Foreign Plans 212,533 – 212,533 –  Total $ 563,825 97,758 428,117 37,950  At December 31, 2016, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.     Fair Value Measurements Using  ( Thousands of dollars ) Fair Value at December 31, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3)  Domestic Plans  Equity securities:  U.S. core equity $ 61,554 61,554 – –  U.S. small/midcap 23,103 23,103 – –  Hedged funds and other alternative strategies 48,113 – 13,999 34,114  International commingled trust fund 67,451 – 67,451 –  Emerging market commingled equity fund 16,006 – 16,006 –  Fixed income securities:  U.S. fixed income 78,473 – 78,473 –  International commingled trust fund 13,486 – 13,486 –  Emerging market mutual fund 5,775 – 5,775 –  Cash and equivalents 7,821 7,821 – –  Total Domestic Plans 321,782 92,478 195,190 34,114  Foreign Plans  Equity securities funds 74,108 – 74,108 –  Fixed income securities funds 97,075 – 97,075 –  Diversified pooled fund 21,463 – 21,463 –  Cash and equivalents 4,929 – 4,929 –  Total Foreign Plans 197,575 – 197,575 –  Total $ 519,357 92,478 392,765 34,114  The definition of levels within the fair value hierarchy in the tables above is included in Note Q.  For domestic plans, U.S. core and small/midcap equity securities are valued based on daily market prices as quoted on national stock exchanges or in the over-the-counter market. Hedged funds and other alternative strategies funds consist of three investments. One of these investments is valued based on daily market prices as quoted on national stock exchanges, another investment is valued monthly based on net asset value and permits withdrawals semi-annually after a 90 -day notice, and the third investment is also valued monthly based on net asset values and has a two - year lock-up period and a 95 -day notice following the lock-up period. International equities held in a commingled trust are valued monthly based on prices as quoted on various international stock exchanges. The emerging market commingled equity fund is valued monthly based on net asset value. These commingled equity funds can be withdrawn monthly and have a 10 -day notice period. U.S. fixed income securities are valued daily based on bids for the same or similar securities or using net asset values. International fixed income securities held in a commingled trust are valued on a monthly basis using net asset values. The fixed income emerging market mutual fund is valued daily based on net asset value. For foreign plans, the equity securities funds are comprised of U.K. and foreign equity funds valued daily based on fund net asset values. Fixed income securities funds are U.K. securities valued daily at net asset values. The diversified pooled fund is valued daily at net asset value and contains a combination of Canadian and foreign equity securities, Canadian fixed income securities and cash.  The effects of fair value measurements using significant unobservable inputs on changes in Level 3 plan assets are outlined below:    ( Thousands of dollars ) Hedged Funds and Other Alternative Strategies  Total at December 31, 2015 $ 33,929  Actual return on plan assets:  Relating to assets held at the reporting date 185  Relating to assets sold during the period –  Purchases, sales and settlements –  Total at December 31, 2016 34,114  Actual return on plan assets:  Relating to assets held at the reporting date 3,836  Relating to assets sold during the period –  Purchases, sales and settlements –  Total at December 31, 2017 $ 37,950  THRIFT PLANS – Most full-time U.S. employees of the Company may participate in thrift or similar savings plans by allotting up to a specified percentage of their base pay. The Company matches contributions at a stated percentage of each employee’s allotment based on years of participation in the plans, with a maximum match of 6% . Amounts charged to expense for these plans were $7.8 million in 2017, $7.4 million in 2016 and $7.6 million in 2015.

Financial Instruments and Risk

Financial Instruments and Risk Management	12 Months Ended
	Dec. 31, 2017
Financial Instruments and Risk Management [Abstract]
Financial Instruments and Risk Management	Note L – Financial Instruments and Risk Management  DERIVATIVE INSTRUMENTS – Murphy often uses derivative instruments to manage certain risks related to commodity prices, foreign currency exchange rates and interest rates . The use of derivative instruments for risk management is covered by operating policies and is closely monitored by the Company’s senior management. The Company does not hold any derivatives for speculative purposes and it does not use derivatives with leveraged or complex features. Derivative instruments are traded primarily with creditworthy major financial institutions or over national exchanges such as the New York Mercantile Exchange (NYMEX). The Company has a risk management control system to monitor commodity price risks and any derivatives obtained to manage a portion of such risks. For accounting purposes, the Company has not designated commodity and foreign currency derivative contracts as hedges, and therefore, it recognizes all gains and losses on these derivative contracts in its Consolidated Statements of Operations. Certain interest rate derivative contracts were accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in AOCL until the anticipated transactions occur.  Commodity Purchase Price Risks  The Company is subject to commodity price risk related to crude oil it produces and sells. During the last three years , the Company had West Texas Intermediate (WTI) crude oil price 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 December 31, 201 7 , the Company had 21,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 201 8 at an average price of $54.88 . At December 31, 201 7 , the fair value of these WTI contracts of $39.1 million was included in A ccounts payable in the Consolidated Balance Sheet . The impact of marking to market these commodity derivative contracts reduced the income before income taxes by $34.0 million for the year ended December 31, 201 7 . During 2016, the Company had WTI crude oil price swap financial contracts to hedge a portion of its United States production for 2016 and 2017. At December 31, 2016, the Company had 22,000 barrels per day in WTI crude oil swap financial contracts maturing ratably during 201 7 . At December 31, 2016, the fair value of WTI contracts of $48.9 million wa s included in A ccounts payable in the Consolidated Balance Sheet . The impact of marking to market these commodity derivative contracts increased the loss before income taxes by $47.7 million for the year ended December 31, 201 6 .  Foreign Currency Exchange Risks  The Company is subject to foreign currency exchange risk associated with operations in countries outside the U.S. At December 31, 2016, short-term derivative instruments were outstanding in Canada for approximately $14.2 million to manage the currency risk of U.S. dollar accounts receivable balances associated with the sale of Canadian crude oil.  At December 31, 201 7 and 201 6 , the fair value of derivative instruments not designated as hedging instruments are presented in the following table. Also shown is the fair value of open foreign currency derivative contracts at December 31, 2016 .    December 31, 2017 December 31, 2016  ( Thousands of dollars ) Asset (Liability) Derivatives Asset (Liability) Derivatives  Type of Derivative Contract Balance Sheet Location Fair Value Balance Sheet Location Fair Value  Commodity Accounts payable $ (39,093) Accounts payable $ (48,864)  Foreign exchange – – Accounts payable $ (73)  For the years ended December 31, 201 7 and 201 6 , 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)  ( Thousands of dollars ) Year Ended December 31,  Type of Derivative Contract Statement of Operations Locations 2017 2016  Commodity Sales and other operating revenues $ 9,567 $ (63,412)  Foreign exchange Interest and other income (loss) – 26,714  $ 9,567 $ (36,698)  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 2012 to match the payment of interest on these notes through 2022. During each of the three years ended December 31, 201 7 , $3.0 million of the deferred loss on the interest rate swaps was charged to I nterest expense in the Consolidated Statements of Operations. The remaining loss (net of tax) deferred on these matured contracts at December 31, 201 7 was $8.4 million, which is recorded, net of income taxes of $4.5 million, in Accumulated o ther c omprehensive l oss in the Consolidated Balance Sheets. The Company expects to charge approximately $3.0 million of this deferred loss to Interest expense in the Consolidated Statements of Operations during 201 8 .  CREDIT RISKS – The Company’s primary credit risks are associated with trade accounts receivable, cash equivalents and derivative instruments. Trade receivables arise mainly from sales of oil and natural gas in the U.S., Canada and Malaysia, and cost sharing amounts of operating and capital costs billed to partners for oil and natural gas fields operated by Murphy. The credit history and financial condition of potential customers are reviewed before credit is extended, security is obtained when deemed appropriate based on a potential customer’s financial condition, and routine follow-up evaluations are made. The combination of these evaluations and the large number of customers tends to limit the risk of credit concentration to an acceptable level. Cash equivalents are placed with several major financial institutions, which limit the Company’s exposure to credit risk. The Company controls credit risk on derivatives through credit approvals and monitoring procedures and believes that such risks are minimal because counterparties to the majority of transactions are major financial institutions.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity and Common Stock Issued and Outstanding [Abstract]
Stockholders' Equity	 Note M – Stockholders’ Equity  Common stock acquired under prior share buyback programs are carried as Treasury s tock in the Consolidated Balance Sheets. There were no share repurchases during 2017 or 2016 and no open share buyback programs as of December 31, 2017 .  During 2015, the Company repurchased Common Stock under variable term, capped accelerated share repurchase transactions (ASR) as authorized by the Board of Directors. These share repurchases during 2015 were as follows:       2015  Purchase of Treasury Stock $ 250,000,000  Shares repurchased 5,967,313 

Earnings per Share

Earnings per Share	12 Months Ended
	Dec. 31, 2017
Earnings per Share [Abstract]
Earnings per Share	Note N – Earnings per Share  Net loss was used as the numerator in computing both basic and diluted income per Common share for each of the three years ended December 31, 2017 . The following table reconciles the weighted-average shares outstanding used for these computations.      ( Weighted-average shares ) 2017 2016 2015  Basic method 172,524,061 172,173,012 174,351,227  Dilutive stock options 1 – – –  Diluted method 172,524,061 172,173,012 174,351,227  1 Due to a net loss recognized by the Company for the years ended December 31, 2017, 2016 and 2015, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.  The following table reflects certain options to purchase shares of common stock that were outstanding during the three years ended December 31, 2017, but were not included in the computation of dilutive earnings per share because the incremental shares from the assumed conversion were antidilutive.     2017 2016 2015  Antidilutive stock options excluded from diluted shares 4,901,269 5,757,435 5,443,288  Weighted average price of these options $45.74 $48.46 $52.93  

Other Financial Information

Other Financial Information	12 Months Ended
	Dec. 31, 2017
Other Financial Information [Abstract]
Other Financial Information	 Note O – Other Financial Information  GAIN FROM FOREIGN CURRENCY TRANSACTIONS – Net gains (losses) from foreign currency transactions, including the effects of foreign currency contracts, included in the Consolidated Statements of Operations were $(75.4) million in 2017 , $59.7 million in 2016 and $87.9 million in 2015.  Noncash operating working capital (increased) decreased during each of the thr ee years ended December 31, 2017 as shown in the following table.      ( Thousands of dollars ) 2017 2016 2015  Accounts receivable $ 114,401 119,671 297,625  Inventories 26,883 (5,171) (15,340)  Prepaid expenses 29,570 149,946 (144,845)  Deferred income tax assets – – 3,924  Accounts payable and accrued liabilities (51,439) (328,078) (36,887)  Current income tax liabilities 16,999 24,943 (69,413)  Net (increase) decrease in noncash operating working capital $ 136,414 (38,689) 35,064  Supplementary disclosures (including discontinued operations):  Cash income taxes paid, net of refunds $ 68,076 6,707 118,667  Interest paid, net of amounts capitalized of $4,488 in 2017, $4,322 in 2016 and $7,290 in 2015 147,975 127,798 110,386   Noncash investing activities, related to continuing operations:  Asset retirement costs capitalized $ 8,509 13,690 76,775  Decrease in capital expenditure accrual 99,199 158,885 462,474     DEEPWATER RIG CONTRACT EXIT COSTS – At year-end 2015, the Company had two deepwater drilling rigs in the Gulf of Mexico under contract that were scheduled to expire in February and November 2016. In the face of low commodity prices, a significant reduction in the Company’s overall 2016 capital spending program and lack of interest by working interest partners and others to participate in drilling opportunities in 2016, the Company idled and stacked both rigs during the fourth quarter of 2015. The Company reported a pretax charge to Other expense in 2015 totaling $282.0 million that included both th e costs incurred in 2015 when the rigs were idle and stacked together with the remaining day rate commitments due under the contracts in 2016. The contract originally scheduled to expire in November 2016 was terminated by the Company. The Company paid approximately $266.7 million related to these contracts in 2016 and reported a pretax benefit to Other expense in 2017 and 2016 of $6.1 million and $4.3 million, respectively, for the final settlement of the contracts at less than the recorded costs. These amounts are included in Other expense in the Consolidated Statements of Operations.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Loss	12 Months Ended
	Dec. 31, 2017
Accumulated Other Comprehensive Loss [Abstract]
Accumulated Other Comprehensive Loss	 Note P – Accumulated Other Comprehensive Loss  The components of Accumulated other comprehensive l oss on the Consolidated Balance Sheets at December 31, 201 7 and December 31, 201 6 and the changes during 2017 and 201 6 are presented net of taxes in the following table.      ( Thousands of dollars ) Foreign Currency Translation Gains (Losses) Retirement and Postretirement Benefit Plan Adjustments Deferred Loss on Interest Rate Derivative Hedges Total  Balance at December 31, 2015 $ (513,004) (179,260) (12,278) (704,542)  2016 components of other comprehensive income (loss):  Before reclassifications to income 66,449 (3,763) – 62,686  Reclassifications to income – 11,718 1 1,926 2 13,644  Net other comprehensive income 66,449 7,955 1,926 76,330  Balance at December 31, 2016 (446,555) (171,305) (10,352) (628,212)  2017 components of other comprehensive income (loss):  Before reclassifications to income 171,725 (17,269) – 154,456  Reclassifications to income – 9,587 1 1,926 2 11,513  Net other comprehensive income (loss) 171,725 (7,682) 1,926 165,969  Balance at December 31, 2017 $ (274,830) (178,987) (8,426) (462,243)  1 Reclassifications before taxes of $14,821 and $18,036 are included in the computation of net periodic benefit expense in 201 7 and 2016, respectively. See Note K for additional information. Related income taxes of $5,234 and $6,318 are included in income tax expense in 201 7 and 2016, respectively. 2 Reclassifications before taxes of $2,963 are included in Interest expense in both 201 7 and 2016. Related income taxes of $1,037 are included in income tax expense in 201 7 and 2016. See Note L for additional information.

Assets and Liabilities Measured

Assets and Liabilities Measured at Fair Value	12 Months Ended
	Dec. 31, 2017
Assets and Liabilities Measured at Fair Value [Abstract]
Assets and Liabilities Measured at Fair Value	Note Q – Assets and Liabilities Measured at Fair Value   Fair Values – Recurring  The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet. 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 fair value measurements for these assets and liabilities at December 31, 201 7 and 201 6 are presented in the following table.      December 31, 2017 December 31, 2016  ( Thousands of dollars ) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total  Liabilities:  Nonqualified employee savings plans $ 16,158 – – 16,158 13,904 – – 13,904  Commodity derivative contracts – 39,093 – 39,093 – 48,864 – 48,864  Foreign currency exchange derivative contracts – – – – – 73 – 73  $ 16,158 39,093 – 55,251 13,904 48,937 – 62,841  The fair value of West Texas Intermediate (WTI) crude oil contracts in 201 7 and 201 6 was based on active market quotes for WTI crude oil. The fair value of foreign exchange derivative contracts in 2016 was based on market quotes for similar contracts at the balance sheet date. The income effect of changes in fair value of crude oil derivative contracts is recorded in Sales and other operating revenues in the Consolidated Statements of Operations, while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and other income. The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds. The fair value of this liability was based on quoted prices for these equity securities and mutual funds. The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and g eneral e xpenses 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 December 31, 201 7 and 201 6 .  The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 201 7 and 201 6 . The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties. The table excludes cash and cash equivalents, trade accounts receivable, trade accounts payable and accrued expenses, all of which had fair values approximating carrying amounts. The carrying value of Canadian government securities was determined based on cost plus earned interest. The fair value of current and long-term debt was estimated based on rates offered to the Company at that time for debt of the same maturities. The Company has off-balance sheet exposures relating to certain letters of credit. The fair value of these, which represents fees associated with obtaining the instruments, was nominal.    At December 31,  2017 2016  ( Thousands of dollars ) Carrying Amount Fair Value Carrying Amount Fair Value  Financial assets (liabilities):  Canadian government securities with maturities greater than 90 days at the date of acquisition $ - - 111,542 111,331  Current and long-term debt (2,916,422) (2,993,003) (2,992,567) (2,951,992)   Fair Values – Nonrecurring  As a result of significantly lower commodity prices during 2016, the Company recognized $95.1 million, respectively, in pretax noncash impairment charges related primarily to producing properties. The fair value information associated with these impaired properties is presented in the following table.     Year Ended December 31, 2016  Total  Net Book Pretax  Value (Noncash)  Fair Value Prior to Impairment  ( Thousands of dollars ) Level 1 Level 2 Level 3 Impairment Expense  Assets:  Impaired proved properties  Western Canada $ – – 71,967 167,055 95,088  $ – – 71,967 167,055 95,088  The fair values were determined by internal discounted cash flow models using estimates of future production, prices from futures exchanges, costs and a discount rate believed to be consistent with those used by principal market participants in the applicable region.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2017
Commitments [Abstract]
Commitments	 Note R – Commitments  The Company leases production and other facilities under operating leases. The most significant operating leases are associated with floating, production, storage and offloading facilities at the Kikeh oil field and a production facility at the West Patricia field. During each of the next five years, expected future net rental payments under all operating leases are approximately $73.7 million in 201 8 , $65.6 million in 201 9 , $62.4 million in 2020, $61.3 million in 202 1 and $27.8 million in 202 2 . Rental expense for noncancelable operating leases, including contingent payments when applicable, was $72.6 million in 201 7 , $77.5 million in 2016, and $111.4 million in 2015. A lease of production equipment at the Kakap field offshore Sabah, Malaysia has been accounted for as a capital lease and is included in long-term debt discussed in Note G.  The Company has entered into contracts to hire various drilling rigs and associated equipment for periods beyond December 31, 2017. These rigs will primarily be utilized for d rilling operations in onshore U.S. , Canada , Gulf of Mexico , and Vietnam . Future commitments under these contracts, all of which expire by 2020, total $66.6 million. Gulf of Mexico rig contracts are short term in nature and can be terminated within 30 days without cost. A portion of these costs are expected to be borne by other working interest owners as partners of the Company when the wells are drilled. These drilling costs are generally expected to be accounted for as capital expenditures as incurred during the contract periods.  The Company has operating, production handling and transportation service agreements for oil and/or natural gas operations in the U.S. and Western Canada. The U.S. transportation contracts require minimum monthly payments through 2024, while the Western Canada processing contracts call for minimum monthly payments through 2035. Future required minimum monthly payments for the next five years are $57.8 million in 2018, $63.8 million in 2019, $77.9 million in 2020, $91.9 million in 2021 and $78.5 million in 2022. Under certain circumstances, the Company is required to pay additional amounts depending on the actual hydrocarbon quantities processed under the agreement. Total costs incurred under these service arrangements were $53.8 million in 2017, $50.3 million in 2016, and $32.5 million in 2015.  Commitments for capital expenditures were approximately $432.3 million at December 31, 201 7 , including $197.3 million for field development and future work commitments in Malaysia, $129.4 million for development at Kaybob Duvernay in Canada, $31.8 million for work at Eagle Ford Shale, $31.3 million for exploration cost in Mexico, $24.0 million for costs to develop deepwater U.S. Gulf of Mexico fi elds, and $8.8 million and $6.3 million f or future work commitments in Vietnam and Brazil, respectively.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2017
Contingencies [Abstract]
Contingencies	Note S – 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 increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others. G overnmental 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 . I t 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.  ENVIRONMENTAL MATTERS – 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. Murphy USA Inc. has retained any environmental exposure associated with Murphy’s former U.S. marketing operations that were spun-off in August 2013. 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. The Company has not yet established a complete estimate of the costs to remediate the site. Based on the assessments done to date, the Company recorded $43.9 million in Other expense in the 2015 Consolidated Statements of Operations associated with the estimated costs of remediating the site. The Company has spent $39.7 million from inception to the end of 2017. Further refinements in the estimated total cost to remediate the site are anticipated in future periods including possible insurance recoveries. It is possible that the ultimate net remediation costs to the Company associated with the condensate leak or leaks will exceed the amount of liability recorded. 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.  LEGAL MATTERS – 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.

Common Stock Issued and Outstan

Common Stock Issued and Outstanding	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity and Common Stock Issued and Outstanding [Abstract]
Common Stock Issued and Outstanding	 Note T – Common Stock Issued and Outstanding  Activity in the number of shares of Common Stock issued and outstanding for the three years ended December 31, 2017 is shown below.     ( Number of shares outstanding ) 2017 2016 2015  Beginning of year 172,202,177 172,034,711 177,499,513  Stock options exercised 1 – – 15,575  Restricted stock awards 1 368,132 158,504 478,549  Employee stock purchase and thrift plans 2,564 8,962 8,387  Treasury shares purchased – – (5,967,313)  End of year 172,572,873 172,202,177 172,034,711  1 Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note J due to withholdings for statutory income taxes owed upon issuance of shares.

Business Segments

Business Segments	12 Months Ended
	Dec. 31, 2017
Business Segments [Abstract]
Business Segments	 Note U – Business Segments  Murphy’s reportable segments are organized into geographic areas of operations. The Company’s exploration and production activity is subdivided into segments for the United States, Canada, Malaysia and all other countries. Each of these segments derives revenues primarily from the sale of crude oil, condensate, natural gas liquids and/or natural gas. The Company’s management evaluates segment performance based on income (loss) from operations, excluding interest income and interest expense.  The Company has several customers that purchase a significant portion of its oil and natural gas production. During 201 7, 2016, and 2015 , sales to Phillips 66 and affiliated companies represented approximately 14% , 17% and 17% , respectively, of the Company’s total sales revenue. Due to the quantity of active oil and natural gas purchasers in the markets where it produces hydrocarbons, the Company does not foresee any difficulty with selling its hydrocarbon production at fair market prices.  The Company completed the sale of its U.K. downstream assets during 2015. For all years presented, assets and liabilities associated with U.K. refining and marketing operations were reported as held for sale in the Consolidated Balance Sheets. These operations have been reported as D iscontinued operations for all periods presented in these consolidated financial statements.  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 and other activities, including interest income, miscellaneous gains and losses (including foreign exchange gains and losses), interest expense and unallocated overhead, are shown in the tables to reconcile the business segments to consolidated totals. Certain reclassifications have been made to 2016 and 2015 Corporate Revenue from external customers to align with current period presentation (see Note A). As used in the table on the following page, c ertain l ong- l ived a ssets at December 31 exclude investments, noncurrent receivables, deferred tax assets, and goodwill and other intangible assets.    Segment Information Exploration and Production  ( Millions of dollars ) United States Canada 1 Malaysia Other Total E&P  Year ended December 31, 2017  Segment income (loss) $ (2.6) 112.5 224.2 (37.5) 296.6  Revenues from external customers 953.9 485.5 781.1 – 2,220.5 2  Interest income – – – – –  Interest expense, net of capitalization – – – – –  Income tax expense (benefit) 2.5 44.4 126.4 (36.2) 137.1  Significant noncash charges (credits)  Depreciation, depletion and amortization 546.1 185.4 204.6 3.8 939.9  Accretion of asset retirement obligations 17.4 7.9 17.3 – 42.6  Amortization of undeveloped leases 60.2 1.6 – – 61.8  Deferred and noncurrent income taxes 2.5 55.3 (3.7) (36.2) 17.9  Additions to property, plant, equipment 534.8 267.6 16.0 37.6 856.0  Total assets at year-end 5,186.2 1,725.8 1,670.1 154.2 8,736.3  Year ended December 31, 2016  Segment income (loss) $ (205.4) (35.9) 171.1 (54.7) (124.9)  Revenues from external customers 685.7 365.3 753.4 0.2 1,804.6  Interest income – – – – –  Interest expense, net of capitalization – – – – –  Income tax expense (benefit) (87.9) (134.3) 85.9 (18.8) (155.1)  Significant noncash charges (credits)  Depreciation, depletion and amortization 600.5 203.2 227.7 5.9 1,037.3  Accretion of asset retirement obligations 17.1 13.3 16.3 – 46.7  Amortization of undeveloped leases 38.4 4.5 – 0.5 43.4  Impairment of assets – 95.1 – – 95.1  Deferred and noncurrent income taxes (108.4) (175.8) (8.5) (18.3) (311.0)  Additions to property, plant, equipment 269.8 361.3 101.4 (1.3) 731.2  Total assets at year-end 5,419.0 1,559.5 2,024.7 115.7 9,118.9  Year ended December 31, 2015  Segment loss $ (615.7) (583.4) (653.2) (158.6) (2,010.9)  Revenues from external customers 1,253.6 549.7 1,131.4 – 2,934.7  Interest income – – – – –  Interest expense, net of capitalization – – – – –  Income tax expense (benefit) (337.0) (188.8) (567.9) (17.3) (1,111.0)  Significant noncash charges (credits)  Depreciation, depletion and amortization 794.9 261.9 544.9 6.2 1,607.9  Accretion of asset retirement obligations 20.2 12.6 15.9 – 48.7  Amortization of undeveloped leases 59.2 14.4 – 1.8 75.4  Impairment of assets 329.0 683.6 1,480.6 – 2,493.2  Deferred and noncurrent income taxes (187.7) (146.0) (579.2) (4.6) (917.5)  Additions to property, plant, equipment 1,263.1 184.9 244.4 39.2 1,731.6  Total assets at year-end 5,717.8 2,460.6 2,537.2 147.7 10,863.3  1 Includes Synthetic crude operations in 2016 and 2015. This business was sold in June 2016. 2 Includes a pretax gain of $129.0 million on sale of Seal area heavy oil field sold in January 2017.    Geographic Information Certain Long-Lived Assets at December 31  ( Millions of dollars ) United States Canada Malaysia United Kingdom Other Total  2017 $ 5,050.5 1,635.9 1,392.3 – 141.3 8,220.0  2016 5,121.6 1,451.4 1,637.0 – 106.2 8,316.2  2015 5,484.7 2,310.6 1,912.0 – 111.1 9,818.4      Segment Information — Continued  ( Millions of dollars ) Corporate and Other Discontinued Operations Consolidated Total  Year ended December 31, 2017  Segment income (loss) $ (607.5) (0.9) (311.8)  Revenues from external customers 4.6 – 2,225.1  Interest income 7.4 – 7.4  Interest expense, net of capitalization 181.8 – 181.8  Income tax expense (benefit) 245.6 – 382.7  Significant noncash charges (credits)  Depreciation, depletion and amortization 17.8 – 957.7  Accretion of asset retirement obligations – – 42.6  Amortization of undeveloped leases – – 61.8  Deferred and noncurrent income taxes 242.5 – 260.4  Additions to property, plant, equipment 14.8 – 870.8  Total assets at year-end 1,101.7 22.9 9,860.9  Year ended December 31, 2016  Segment income (loss) $ (149.1) (2.0) (276.0)  Revenues from external customers 6.6 – 1,811.2  Interest income 2.9 – 2.9  Interest expense, net of capitalization 148.2 – 148.2  Income tax expense (benefit) (64.1) – (219.2)  Significant noncash charges (credits)  Depreciation, depletion and amortization 16.8 – 1,054.1  Accretion of asset retirement obligations – – 46.7  Amortization of undeveloped leases – – 43.4  Impairment of assets – – 95.1  Deferred and noncurrent income taxes (76.8) – (387.8)  Additions to property, plant, equipment 21.9 – 753.1  Total assets at year-end 1,149.9 27.1 10,295.9   Year ended December 31, 2015  Segment loss $ (244.9) (15.0) (2,270.8)  Revenues from external customers 6.6 – 2,941.3  Interest income 4.0 – 4.0  Interest expense, net of capitalization 117.4 – 117.4  Income tax expense (benefit) 84.5 – (1,026.5)  Significant noncash charges (credits)  Depreciation, depletion and amortization 11.9 – 1,619.8  Accretion of asset retirement obligations – – 48.7  Amortization of undeveloped leases – – 75.4  Impairment of assets – – 2,493.2  Deferred and noncurrent income taxes (60.5) – (978.0)  Additions to property, plant, equipment 59.9 – 1,791.5  Total assets at year-end 592.2 38.3 11,493.8         Geographic Information Revenues from External Customers for the Year  ( Millions of dollars ) United States Canada Malaysia Other Total  2017 $ 958.3 485.7 781.1 – 2,225.1  2016 692.3 365.3 753.4 0.2 1,811.2  2015 1,260.2 549.7 1,131.4 – 2,941.3  

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information	12 Months Ended
	Dec. 31, 2017
Supplemental Oil and Gas Information [Abstract]
Supplemental Oil and Gas Information	 The following unaudited schedules are presented in accordance with required disclosures about Oil and Gas Producing Activities to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies. Additional background information concerning some of the schedules follows:  SCHEDULE 1 – SUMMARY OF PROVED CRUDE OIL AND SYNTHETIC OIL RESERVES SCHEDULE 2 – SUMMARY OF PROVED NATURAL GAS LIQUIDS RESERVES SCHEDULE 3 – SUMMARY OF PROVED NATURAL GAS RESERVES  Reserves of crude oil, synthetic oil, condensate, natural gas liquids and natural gas are estimated by the Company’s or independent engineers and are adjusted to reflect contractual arrangements and royalty rates in effect at the end of each year. Many assumptions and judgmental decisions are required to estimate reserves. Reported quantities are subject to future revisions, some of which may be substantial, as additional information becomes available from reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors.  Murphy’s estimations for proved reserves were generated through the integration of available geoscience, engineering , and economic data and commercially available technologies, to establish ‘reasonable certainty’ of economic productibility. As defined by the SEC, reasonable certainty of proved reserves describes a high degree of confidence that the quantities will be recovered. In estimating proved reserves, Murphy uses familiar industry-accepted methods for subsurface evaluations, including performance, volumetric and analogue - based studies. Where appropriate, Murphy includes reliable geologic and engineering technology to estimate proved reserves. Reliable geologic and engineering technology is a method or combination of methods that are field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. This integrated approach increases the quality of and confidence in Mur phy’s proved reserves estimates. The approach was utilized in certain undrilled acreage at distances greater than the directly offsetting development spacing areas and in certain reservoirs developed with the application of improved recovery techniques. Murphy utilized a combination of 3D seismic interpretation, core analysis, wellbore log measurements, well test data, histor ic production and pressure data and commercially available seismic processing and numerical reservoir simulation programs. Reservoir parameters from analogous reservoirs were used to strengthen the reserves estimates when available.  Prior to its disposition in 2016, Murphy included synthetic crude oil from its 5% interest in the Syncrude project in Alberta, Canada in its proved crude oil reserves. All synthetic oil volumes reported as proved reserves in Schedule 1 are the final synthetic crude oil product.  Production quantities shown are net volumes withdrawn from reservoirs. These may differ from sales quantities due to inventory changes, volumes consumed for fuel and/or shrinkage from extraction of natural gas liquids.  All crude oil and synthetic reserves, natural gas liquids reserves and natural gas reserves are from consolidated subsidiaries and proportionately consolidated joint ventures. The Company has no proved reserves attributable to investees accounted for by the equity method.  All proved reserves in Malaysia are associated with production sharing contracts for Blocks SK 309/311, K and H. Malaysia reserves include oil and gas to be received for both cost recovery and profit provisions under the contract. At December 31, 2017 , l iquids and natural gas proved reserves associated with the production sharing contracts in Malaysia totaled 52.2 million barrels and 491.3 billion cubic feet (BCF), respectively. A t December 31, 2017 , a pproximately 26.7 BCF of natural gas proved reserves in Malaysia relate to fields in Block K for which the Company expects to receive sale proceeds of approximately $0.24 pe r thousand cubic feet . Sales price for other natural gas produced in Malaysia is based on market-driven prices .  SCHEDULE 6 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES  GAAP requires calculation of future net cash flows using a 10% annual discount factor, an unweighted average of oil and natural gas prices in effect at the beginning of each month of the year, and year-end costs and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates. On December 22, 2017, the U.S. enacted into legislation the Tax Cuts and Jobs Act (2017 Tax Act); as a result the company’s statutory U.S. tax rate will be 21% beginning in 2018, a decrease from the previous rate of 35% .  The reported value of proved reserves is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs and governmental policies do not remain static; appropriate discount rates may vary; and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts.  Schedule 6 also presents the principal reasons for change in the standardized measure of discounted future net cash flows for each of the three years ended December 31, 2017. Schedule 1 – Summary of Proved Crude Oil and Synthetic Oil Reserves Based on Average Prices for 2014 – 2017     Crude & Synthetic Oil Crude Oil Synthetic Oil 1  ( Millions of barrels ) Total Total United States Canada Malaysia Canada  Proved developed and undeveloped crude oil / synthetic oil reserves:  December 31, 2014 441.8 336.2 204.9 37.4 93.9 105.6  Revisions of previous estimates 5.3 (8.2) (7.6) (4.8) 4.2 13.5  Improved recovery 2.4 2.4 – – 2.4 –  Extensions and discoveries 63.8 63.8 63.8 – – –  Sales of properties (11.0) (11.0) – – (11.0) –  Production (46.1) (41.8) (22.2) (4.7) (14.9) (4.3)  December 31, 2015 456.2 341.4 238.9 27.9 74.6 114.8  Revisions of previous estimates (5.8) (5.8) (10.9) 2.5 2.6 –  Extensions and discoveries 11.0 11.0 8.6 – 2.4 –  Purchases of properties 26.3 26.3 – 26.3 – –  Sales of properties (121.0) (7.8) (4.5) (3.3) – (113.2)  Production (37.7) (36.1) (17.7) (4.5) (13.9) (1.6)  December 31, 2016 329.0 329.0 214.4 48.9 65.7 (0.0)  Revisions of previous estimates (6.0) (6.0) (4.7) 2.3 (3.6) –  Improved recovery 2.0 2.0 – – 2.0 –  Extensions and discoveries 31.6 31.6 27.2 4.4 – –  Purchases of properties 4.7 4.7 4.7 – – –  Production (33.2) (33.2) (16.9) (4.1) (12.2) –  December 31, 2017 328.1 328.1 224.7 51.5 51.9 –  Proved developed crude oil/ synthetic oil reserves:  December 31, 2014 324.1 218.5 106.2 32.4 79.9 105.6  December 31, 2015 326.6 211.8 125.9 23.8 62.1 114.8  December 31, 2016 184.9 184.9 113.9 19.2 51.8 –  December 31, 2017 185.5 185.5 126.3 21.9 37.3 –  Proved undeveloped crude oil reserves:  December 31, 2014 117.7 117.7 98.7 5.0 14.0 –  December 31, 2015 129.6 129.6 113.0 4.1 12.5 –  December 31, 2016 144.1 144.1 100.5 29.7 13.9 –  December 31, 2017 142.6 142.6 98.4 29.6 14.6 –  1 All synthetic oil operations were sold in June 2016.  Schedule 1 – Summary of Proved Crude Oil and Synthetic Oil Reserves Based on Average Prices for 2014 – 2017 – Continued  2017 Comments for Proved Crude Oil Reserves Changes Revisions of previous estimate – The 2017 negative crude oil revision in the U.S. was primarily attributable to the removal of proved undeveloped locations within the 5 -year development window as capital was reallocated to higher performing drilling locations within the Company’s Eagle Ford Shale fields, partially offset by improved Eagle Ford Shale costs and performance results in the Gulf of Mexico. The positive Canadian oil reserves revisions in 2017 resulted from improved performance at Tupper Montney assets in Western Canada, and offshore Canada fields , Hibernia and Terra Nova. The negative revisions for crude oil reserves in Malaysia were principally attributable to the redetermination of Kakap participation that lowered the Company’s entitlement, and higher government entitlement under the terms of the respective production sharing contracts due to higher oil prices, offsetting positive performance revisions at the Company’s Sarawak projects.  Improved recovery – The 201 7 Malaysia crude oil proved reserve add ition was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields.  Extensions and discoveries – In 2017, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves, and in Canada for drilling activities in the Montney and Duvernay. Proved oil reserves were also added for drilling activities in the U.S. offshore.  Purchases of p roperties – In 2017, the Company acquire d greater working interests in two of its operated Gulf of Mexico fields. In U.S. onshore, the Company acquired acreage in the Permian area of west Texas. Additional Eagle Ford Shale acreage was acquired through joint venture agreement s with other operators within its core acreage position.  2016 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes Revisions of previous estimate – The 2016 negative crude oil revision in the U.S. was primarily attributable to impacts of lower price on Eagle Ford Shale volumes and reduced performance in a particular location, partially offset by improved Eagle Ford Shale costs and drilling results in the Gulf of Mexico. The positive Canadian oil reserves revisions in 2016 resulted from improved Kaybob Duvernay performance and an increase at Terra Nova due to development drilling. The positive revisions for crude oil reserves in Malaysia was attributable to improved performance and lower government entitlement under the terms of the respective production sharing contracts due to lower oil prices, which collectively more than offset a negative revision at Kikeh following updated decline curve analysis.  Extensions and discoveries – In 2016, proved oil reserves were added in the U.S. for drilling activities in the Eagle Ford Shale, and deeper oil-water contacts realized at a field in Malaysia.  Purchases of p roperties – In 2016, the Company’s Canadian subsidiary acquired working interests in the Kaybob Duvernay and liquids rich Placid Montney areas. The crude oil reserves are all associated with the Kaybob Duvernay area.  Sales of properties – In the U.S., proved oil reserves were reduced following the sale of certain non-core Eagle Ford Shale acreage. In Canada, the Company sold its interests in both a heavy oil field and a synthetic oil project.            2015 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes Revisions of previous estimate – The 2015 negative crude oil revision in the U.S. was primarily attributable to impacts of lower price on Eagle Ford Shale volumes, partially offset by improved Eagle Ford Shale performance, improved Eagle Ford Shale lifting costs, and drilling activity in the Gulf of Mexico. The negative Canadian conventional oil reserves revision in 2015 was result of lower heavy oil prices partially offset by increases at both Hibernia and Terra Nova due to development drilling and lower government royalty effects. The positive synthetic oil revision in the current period is due predominantly to lower government royalty effects due to lower oil prices. The positive revision for crude oil reserves in Malaysia was attributable to improved performance and lower government entitlement under the terms of the respective production sharing contracts due to lower oil prices.  Improved recovery – The 2015 Malaysia crude oil proved reserve add ition was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields.  Extensions and discoveries – In 2015, the U.S. added proved oil reserves primarily for planned drilling activities in the Eagle Ford Shale.  Sales of prope rties – The proved crude oil reserves reduction in Malaysia was associated with the 2015 sale of 10% of the Company’s oil and gas asset s in Malaysia .    Schedule 2 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices for 2014 – 2017       ( Millions of barrels ) Total United States Canada Malaysia  Proved developed and undeveloped NGL reserves:  December 31, 2014 30.6 29.1 0.7 0.8  Revisions of previous estimates 2.0 2.2 (0.3) 0.1  Extensions and discoveries 7.6 7.6 – –  Sales of properties (0.1) – – (0.1)  Production (3.7) (3.5) – (0.2)  December 31, 2015 36.4 35.4 0.4 0.6  Revisions of previous estimates 1.6 1.2 0.2 0.2  Extensions and discoveries 2.9 2.8 0.1 –  Purchases of properties 5.1 – 5.1 –  Production (3.5) (3.0) (0.2) (0.3)  December 31, 2016 42.5 36.4 5.6 0.5  Revisions of previous estimates 1.3 2.0 (0.6) (0.1)  Extensions and discoveries 7.8 7.0 0.8 –  Purchases of properties 0.5 0.5 – –  Production (3.2) (2.9) (0.2) (0.1)  December 31, 2017 48.9 43.0 5.6 0.3  Proved developed NGL reserves:  December 31, 2014 17.5 16.5 0.2 0.8  December 31, 2015 21.6 20.7 0.3 0.6  December 31, 2016 22.2 20.8 0.9 0.5  December 31, 2017 24.6 23.3 1.0 0.3  Proved undeveloped NGL reserves:  December 31, 2014 13.1 12.6 0.5 –  December 31, 2015 14.8 14.7 0.1 –  December 31, 2016 20.3 15.6 4.7 –  December 31, 2017 24.3 19.7 4.6 –   Schedule 2 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices for 2014 – 2017 – Continued  2017 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates – The positive 2017 NGL proved reserves revision in the U.S. was primarily in the Company’s Eagle Ford Shale fields based on an updated shrinkage ratio of liquids rich gas production combined with improved costs, offsetting removal of proved undeveloped locations from within the 5 -year development window as capital was reallocated to higher performing drilling locations within the Eagle Ford Shale.  Extensions and discoveries – Proved NGL reserves were added primarily from drilling activiti es in the Eagle Ford Shale area concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves.  Purchase of properties – In U.S., proved NGL reserves were added following the acquisition of acreage in both the Eagle Ford Shale and Permian areas, and increased working interest in two Gulf of Mexico fields.  2016 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates – The positive 2016 NGL proved reserves revision was primarily in the Eagle Ford Shale area based on an updated ratio of oil to gas production.  Extensions and discoveries – Proved NGL reserves were added primarily from drilling activities in the Eagle Ford Shale area.  Purchase of properties – In Canada, proved NGL reserves were added following the acquisition of acreage in both the Kabob Duvernay and liquids rich Placid Montney areas.  2015 Comments for Proved Natural Gas Liquids Reserves Changes Revisions of previous estimates – The positive 2015 NGL proved reserves revision in the U.S. was primarily in the Eagle Ford Shale area based on improved performance.  Extensions and discoveries – In 2015, the U.S. added NGL reserves primarily for additional drilling activities in the Eagle Ford Shale.  Sales of properties – The Company sold 10% of its oil and gas assets in Malaysia in January 2015.    Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 201 4 – 201 7     ( Billions of cubic feet ) Total United States Canada Malaysia  Proved developed and undeveloped natural gas reserves:  December 31, 2014 1,704.7 226.3 842.8 635.6  Revisions of previous estimates 53.5 (5.2) 18.9 39.8  Improved recovery 1.8 – – 1.8  Extensions and discoveries 162.9 43.2 119.7 –  Sales of properties (78.0) – – (78.0)  Production (156.1) (31.9) (71.8) (52.4)  December 31, 2015 1,688.8 232.4 909.6 546.8  Revisions of previous estimates 43.3 0.1 45.3 (2.1)  Extensions and discoveries 164.2 6.4 120.2 37.6  Purchases of properties 122.3 – 122.3 –  Sales of properties (2.2) (0.1) (2.1) –  Production (138.4) (19.4) (76.4) (42.6)  December 31, 2016 1,878.0 219.4 1,118.9 539.7  Revisions of previous estimates (5.4) (16.0) 19.4 (8.8)  Extensions and discoveries 190.6 32.2 156.7 1.7  Purchases of properties 4.0 4.0 – –  Production (140.1) (16.3) (82.6) (41.2)  December 31, 2017 1,927.1 223.3 1,212.4 491.4  Proved developed natural gas reserves:  December 31, 2014 812.1 145.6 467.4 199.1  December 31, 2015 783.5 148.3 453.5 181.7  December 31, 2016 818.1 138.7 498.9 180.5  December 31, 2017 819.3 127.7 547.0 144.6  Proved undeveloped natural gas reserves:  December 31, 2014 892.6 80.7 375.4 436.5  December 31, 2015 905.3 84.1 456.1 365.1  December 31, 2016 1,059.9 80.7 620.0 359.2  December 31, 2017 1,107.8 95.6 665.5 346.7   Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2014 – 2017 – Continued  2017 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates – In the U.S., the negative natural gas revision was primarily due to shutting in a gas well located in the Gulf of Mexico due to early water break through , and in the Company’s Eagle Ford Shale fields proved undeveloped locations were removed from within the 5 -year development window as capital was reallocated to higher performing drilling locations within the Eagle Ford Shale . The negative revision for natural gas reserves in Malaysia was primarily attributable to higher government entitlement under the terms of the respective production sharing contracts due to higher gas prices, offsetting positive performance revisions at the Company’s Sarawak projects. The 2017 positive natural gas revisions in Canada were attributable to updated well type curves and field performance at the Tupper Montney assets in Western Canada.  Extensions and discoveries – In 2017, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale concurrent with the reallocation of capital to higher performing drilling areas moving well locations within the 5-year development window for proved undeveloped reserves, and field development drilling in the Gulf of Mexico. Natural gas reserve add itions in Canada were attributable to developmental drilling activities in the Montney and Kaybob Duvernay areas in Western Canada. In Malaysia, proved natural gas reserves were added in Sarawak from field development activities.  Purchase of properties – In the U.S., proved natural gas reserves were added following the acquisition of acreage in both the Eagle Ford Shale and Permian areas, and increased working interest in two Gulf of Mexico fields.  2016 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates – The 2016 positive natural gas revisions in Canada were attributable to updated well type curves and field development techniques in both the Montney and Duvernay areas of Western Canada. The negative revision for natural gas reserves in Malaysia was primarily attributable to the removal of Sarawak area proved reserves resulting from the government’s decision to delay certain field development plans.  Extensions and discoveries – In 2016, the U.S. added natural gas reserves primarily for developmental drilling activities in the Eagle Ford Shale. Natural gas reserve add itions in Canada were attributable to developmental drilling activities in the Tupper area. In Malaysia, proved natural gas reserves were added in Block H as the Permai field was added to the field development plan.  Purchase of properties – In Canada, proved natural gas reserves were added following the acquisition of acreage in both the Kaybob Duvernay and liquids rich Placid Montney areas.  Sales of properties – Proved natural gas reserves were reduced following the sale of certain non-core Eagle Ford Shale acreage in the U.S. and the associated gas related to the sale of a heavy oil field in Canada.  2015 Comments for Proved Natural Gas Reserves Changes Revisions of previous estimates – The 2015 negative natural gas revision in the U.S. was primarily attributable to performance declines in certain fields in the Gulf of Mexico offset in part by the overall positive performance in the Eagle Ford Shale area. The positive revisions in Canada were attributable to updated well type curves and field development techniques in the Montney area of Western Canada. The positive revision for natural gas reserves in Malaysia was attributable to lower government entitlement under the terms of the respective production sharing contracts due to lower natural gas prices.  Improved recovery – The 2015 Malaysia natural gas proved reserve add ition was primarily due to favorable impacts for waterflood activity at certain Sarawak oil fields.  Extensions and discoveries – In 2015, the U.S. added natural gas reserves primarily for planned developmental drilling activities in the Eagle Ford Shale while the gas reserve add ition s in Canada were attributable to developmental drilling activities in the Tupper area.  Sales of properties – The Company sold 10% of its oil and gas assets in Malaysia in January 2015.  Schedule 4 – Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities     ( Millions of dollars ) United States Canada Malaysia Other Total  Year ended December 31, 2017  Property acquisition costs  Unproved $ 50.4 – – 13.0 63.4  Proved 7.7 – – – 7.7  Total acquisition costs 58.1 – – 13.0 71.1  Exploration costs 1 13.7 0.6 (8.9) 73.8 79.2  Development costs 1 508.4 273.8 35.7 1.1 819.0  Total costs incurred 580.2 274.4 26.8 87.9 969.3  Charged to expense  Dry hole expense (1.9) – 0.7 (3.0) (4.2)  Geophysical and other costs 9.7 0.5 1.7 53.3 65.2  Total charged to expense 7.8 0.5 2.4 50.3 61.0  Property additions $ 572.4 273.9 24.4 37.6 908.3  Year ended December 31, 2016  Property acquisition costs  Unproved $ 18.6 – – – 18.6  Proved – 206.7 – – 206.7  Total acquisition costs 18.6 206.7 – – 225.3  Exploration costs 1 18.5 3.6 6.0 42.0 70.1  Development costs 1 239.7 165.1 102.9 0.3 508.0  Total costs incurred 276.8 375.4 108.9 42.3 803.4  Charged to expense  Dry hole expense 0.4 – 4.5 10.2 15.1  Geophysical and other costs 5.7 3.6 0.7 33.4 43.4  Total charged to expense 6.1 3.6 5.2 43.6 58.5  Property additions $ 270.7 371.8 103.7 (1.3) 744.9  Year ended December 31, 2015  Property acquisition costs  Unproved $ 10.1 2.5 – – 12.6  Proved – – – – –  Total acquisition costs 10.1 2.5 – – – 12.6  Exploration costs 1 166.8 0.7 69.0 135.4 371.9  Development costs 1 1,375.1 231.5 210.0 2.8 1,819.4  Total costs incurred 1,552.0 234.7 279.0 138.2 2,203.9  Charged to expense  Dry hole expense 241.3 – 29.7 25.8 296.8  Geophysical and other costs 16.9 0.7 7.9 73.2 98.7  Total charged to expense 258.2 0.7 37.6 99.0 395.5  Property additions $ 1,293.8 234.0 241.4 39.2 1,808.4  1 Includes noncash asset retirement costs as follows:    2017  Exploration costs $ – – – – –  Development costs 37.6 6.3 8.4 – 52.3  $ 37.6 6.3 8.4 – 52.3  2016  Exploration costs $ – – – – –  Development costs 0.9 10.5 2.3 – 13.7  $ 0.9 10.5 2.3 – 13.7  2015  Exploration costs $ – – – – –  Development costs 30.7 49.1 (3.0) – 76.8  $ 30.7 49.1 (3.0) – 76.8    Schedule 5 – Results of Operations for Oil and Gas Producing Activities 1    Canada  United Conven-  ( Millions of dollars ) States tional Synthetic Malaysia Other Total  Year ended December 31, 2017  Revenues  Crude oil and natural gas liquids sales $ 913.3 203.7 – 639.9 – 1,756.9  Natural gas sales 37.9 155.1 – 138.2 – 331.2  Total oil and gas revenues 951.2 358.8 – 778.1 – 2,088.1  Other operating revenues 2.7 126.7 – 3.0 – 132.4  Total revenues 953.9 485.5 – 781.1 – 2,220.5  Costs and expenses  Lease operating expenses 198.5 101.1 – 168.8 – 468.4  Severance and ad valorem taxes 42.2 1.5 – – – 43.7  Exploration costs charged to expense 7.8 0.5 – 2.4 50.3 61.0  Undeveloped lease amortization 60.2 1.6 – – – 61.8  Depreciation, depletion and amortization 546.1 185.4 – 204.6 3.8 939.9  Accretion of asset retirement obligations 17.4 7.9 – 17.3 – 42.6  Redetermination expense – – – 15.0 – 15.0  Selling and general expenses 61.8 28.3 – 14.0 19.6 123.7  Other expenses 20.0 2.3 – 8.4 – 30.7  Total costs and expenses 954.0 328.6 – 430.5 73.7 1,786.8  Results of operations before taxes (0.1) 156.9 – 350.6 (73.7) 433.7  Income tax expense (benefit) 2.5 44.4 – 126.4 (36.2) 137.1  Results of operations $ (2.6) 112.5 – 224.2 (37.5) 296.6  Year ended December 31, 2016  Revenues  Crude oil and natural gas liquids sales $ 650.7 171.7 60.7 623.7 – 1,506.8  Natural gas sales 35.1 130.0 – 127.6 – 292.7  Total oil and gas revenues 685.8 301.7 60.7 751.3 – 1,799.5  Other operating revenues (0.1) (0.7) 3.6 2.1 0.2 5.1  Total revenues 685.7 301.0 64.3 753.4 0.2 1,804.6  Costs and expenses  Lease operating expenses 218.6 102.6 69.8 168.4 – 559.4  Severance and ad valorem taxes 37.0 4.3 2.5 – – 43.8  Exploration costs charged to expense 6.1 3.6 – 5.2 43.6 58.5  Undeveloped lease amortization 38.4 4.5 – – 0.5 43.4  Depreciation, depletion and amortization 600.5 186.7 16.5 227.7 5.9 1,037.3  Accretion of asset retirement obligations 17.1 10.9 2.4 16.3 – 46.7  Impairment of assets – 95.1 – – – 95.1  Redetermination expense – – – 39.1 – 39.1  Selling and general expenses 68.8 28.6 0.5 15.9 33.6 147.4  Other expenses (benefits) (7.5) 7.5 – 23.8 (9.9) 13.9  Total costs and expenses 979.0 443.8 91.7 496.4 73.7 2,084.6  Results of operations before taxes (293.3) (142.8) (27.4) 257.0 (73.5) (280.0)  Income tax expense (benefit) (87.9) (58.9) (75.4) 85.9 (18.8) (155.1)  Results of operations $ (205.4) (83.9) 48.0 171.1 (54.7) (124.9) 1 Results exclude corporate overhead, interest and discontinued operations.    Schedule 5 – Results of Operations for Oil and Gas Producing Activities 1 – Continued      Canada  United Conven-  ( Millions of dollars ) States tional Synthetic Malaysia Other Total  Year ended December 31, 2015  Revenues  Crude oil and natural gas liquids sales $ 1,176.9 181.0 203.0 790.6 – 2,351.5  Natural gas sales 70.4 167.7 – 185.4 – 423.5  Total oil and gas revenues 1,247.3 348.7 203.0 976.0 – 2,775.0  Other operating revenues 6.3 (2.4) 0.4 155.4 – 159.7  Total revenues 1,253.6 346.3 203.4 1,131.4 – 2,934.7  Costs and expenses  Lease operating expenses 312.0 102.4 166.0 251.9 – 832.3  Severance and ad valorem taxes 55.9 4.8 5.1 – – 65.8  Exploration costs charged to expense 258.2 0.7 – 37.6 99.0 395.5  Undeveloped lease amortization 59.2 14.4 – – 1.8 75.4  Depreciation, depletion and amortization 794.9 211.2 50.7 544.9 6.2 1,607.9  Accretion of asset retirement obligations 20.2 7.2 5.4 15.9 – 48.7  Impairment of assets 329.0 683.6 – 1,480.6 – 2,493.2  Selling and general expenses 88.2 25.5 1.0 5.7 56.8 177.2  Other expenses 288.7 43.9 – 15.9 12.1 360.6  Total costs and expenses 2,206.3 1,093.7 228.2 2,352.5 175.9 6,056.6  Results of operations before taxes (952.7) (747.4) (24.8) (1,221.1) (175.9) (3,121.9)  Income tax expense (benefit) (337.0) (191.2) 2.4 (567.9) (17.3) (1,111.0)  Results of operations $ (615.7) (556.2) (27.2) (653.2) (158.6) (2,010.9)  1 Results exclude corporate overhead, interest and discontinued operations.  Schedule 6 – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves     ( Millions of dollars ) United States Canada Malaysia Total  December 31, 2017  Future cash inflows $ 12,885.8 4,714.3 4,392.0 21,992.1  Future development costs (2,079.5) (1,081.7) (632.3) (3,793.5)  Future production costs (4,765.3) (2,507.4) (2,305.0) (9,577.7)  Future income taxes (893.7) (161.1) (232.2) (1,287.0)  Future net cash flows 5,147.3 964.1 1,222.5 7,333.9  10% annual discount for estimated timing of cash flows (2,698.2) (394.6) (318.2) (3,411.0)  Standardized measure of discounted future net cash flows $ 2,449.1 569.5 904.3 3,922.9  December 31, 2016  Future cash inflows $ 9,477.9 3,752.7 4,318.7 17,549.3  Future development costs (1,691.1) (1,143.6) (763.8) (3,598.5)  Future production costs (3,981.6) (2,329.7) (2,661.2) (8,972.5)  Future income taxes (118.9) (81.3) (73.3) (273.5)  Future net cash flows 3,686.3 198.1 820.4 4,704.8  10% annual discount for estimated timing of cash flows (1,799.5) (95.0) (230.3) (2,124.8)  Standardized measure of discounted future net cash flows $ 1,886.8 103.1 590.1 2,580.0  December 31, 2015  Future cash inflows $ 12,373.9 8,922.0 6,143.1 27,439.0  Future development costs (2,620.5) (1,145.4) (957.8) (4,723.7)  Future production costs (4,955.4) (5,892.7) (3,290.5) (14,138.6)  Future income taxes (339.7) (504.8) (216.2) (1,060.7)  Future net cash flows 4,458.3 1,379.1 1,678.6 7,516.0  10% annual discount for estimated timing of cash flows (2,430.0) (666.8) (560.1) (3,656.9)  Standardized measure of discounted future net cash flows $ 2,028.3 712.3 1,118.5 3,859.1   Schedule 6 – Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves – Continued  Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years sho wn.      ( Millions of dollars ) 2017 2016 2015  Net changes in prices and production costs $ 2,428.4 (1,476.1) (11,365.5)  Net changes in development costs (724.4) 544.9 591.4  Sales and transfers of oil and gas produced, net of production costs (1,576.0) (1,196.3) (1,876.9)  Net change due to extensions and discoveries 807.9 280.5 1,145.8  Net change due to purchases and sales of proved reserves 85.9 (583.4) (287.4)  Development costs incurred 802.7 479.6 1,725.4  Accretion of discount 270.9 428.1 1,289.5  Revisions of previous quantity estimates (109.5) (49.2) 163.3  Net change in income taxes (643.0) 292.8 2,568.3  Net increase (decrease) 1,342.9 (1,279.1) (6,046.1)  Standardized measure at January 1 2,580.0 3,859.1 9,905.2  Standardized measure at December 31 $ 3,922.9 2,580.0 3,859.1   Schedule 7 – Capitalized Costs Relating to Oil and Gas Producing Activities     ( Millions of dollars ) United States Canada Malaysia Other Total  December 31, 2017  Unproved oil and gas properties $ 360.9 286.8 20.5 162.1 830.3  Proved oil and gas properties 9,606.4 3,603.4 6,139.7 – 19,349.5  Gross capitalized costs 9,967.3 3,890.2 6,160.2 162.1 20,179.8  Accumulated depreciation, depletion and amortization  Unproved oil and gas properties (149.5) (230.7) – (21.8) (402.0)  Proved oil and gas properties (4,893.8) (2,027.9) (4,774.5) – (11,696.2)  Net capitalized costs $ 4,924.0 1,631.6 1,385.7 140.3 8,081.6  December 31, 2016  Unproved oil and gas properties $ 360.8 315.6 47.0 125.6 849.0  Proved oil and gas properties 9,384.6 4,241.6 6,147.8 – 19,774.0  Gross capitalized costs 9,745.4 4,557.2 6,194.8 125.6 20,623.0  Accumulated depreciation, depletion and amortization  Unproved oil and gas properties (151.2) (233.6) – (21.8) (406.6)  Proved oil and gas properties (4,605.9) (2,877.2) (4,566.6) – (12,049.7)  Net capitalized costs $ 4,988.3 1,446.4 1,628.2 103.8 8,166.7   Note: Unproved oil and gas properties above include costs and associated accumulated amortization of properties that do not have proved reserves; these costs include mineral interests, uncompleted exploratory wells, and exploratory wells capitalized pending further evaluation.

Supplemental Quarterly Informat

Supplemental Quarterly Information	12 Months Ended
	Dec. 31, 2017
Supplemental Quarterly Information [Abstract]
Supplemental Quaterly Information	     ( Millions of dollars except per share amounts ) First Quarter Second Quarter Third Quarter Fourth Quarter Year  Year ended December 31, 2017  Sales and other operating revenues $ 544.7 509.7 498.3 545.0 2,097.7  Income (loss) from continuing operations before income taxes 154.9 (21.9) (63.6) 2.4 71.8  Income (loss) from continuing operations 57.5 (17.3) (66.3) (284.8) (310.9)  Net income (loss) 58.5 (17.6) (65.9) (286.8) (311.8)  Income (loss) from continuing operations per Common share  Basic 0.33 (0.10) (0.38) (1.65) (1.81)  Diluted 0.33 (0.10) (0.38) (1.65) (1.81)  Net income (loss) per Common share  Basic 0.34 (0.10) (0.38) (1.66) (1.81)  Diluted 0.34 (0.10) (0.38) (1.66) (1.81)  Cash dividend per Common share 0.25 0.25 0.25 0.25 1.00  Market price of Common Stock 1  High 32.18 28.71 27.43 31.98 32.18  Low 25.76 24.06 22.63 25.02 22.63  Year ended December 31, 2016  Sales and other operating revenues $ 429.1 411.2 486.3 483.0 1,809.6  Loss from continuing operations before income taxes (265.0) (131.3) (16.7) (80.1) (493.1)  Income (loss) from continuing operations (199.5) 2.9 (14.6) (62.8) (274.0)  Net income (loss) (198.8) 2.9 (16.2) (63.9) (276.0)  Income from continuing operations per Common share  Basic (1.16) 0.02 (0.08) (0.36) (1.59)  Diluted (1.16) 0.02 (0.08) (0.36) (1.59)  Net income (loss) per Common share  Basic (1.16) 0.02 (0.08) (0.37) (1.60)  Diluted (1.16) 0.02 (0.08) (0.37) (1.60)  Cash dividend per Common share 0.35 0.35 0.25 0.25 1.20  Market price of Common Stock 1  High 26.69 36.24 32.66 34.30 36.24  Low 15.76 23.49 25.14 25.00 15.76  1 Prices are as quoted on the New York Stock Exchange.

Schedule II - Valuation Account

Schedule II - Valuation Accounts and Reserves	12 Months Ended
	Dec. 31, 2017
Schedule II - Valuation Accounts and Reserves [Abstract]
Schedule II - Valuation Accounts and Reserves	     ( Millions of dollars ) Balance at January 1 Charged to Expense Deductions Other 1 Balance at December 31  2017  Deducted from asset accounts:  Allowance for doubtful accounts $ 1.6 – – – 1.6  Deferred tax asset valuation allowance 305.4 18.6 – 152.3 476.3  2016  Deducted from asset accounts:  Allowance for doubtful accounts $ 1.6 – – – 1.6  Deferred tax asset valuation allowance 294.4 25.7 – (14.7) 305.4  2015  Deducted from asset accounts:  Allowance for doubtful accounts $ 1.6 – – – 1.6  Deferred tax asset valuation allowance 306.5 40.8 – (52.9) 294.4  1 Amount s in 2017 and 2016 for deferred tax asset valuations are primarily associated with an increase in foreign tax credit carryforwards. The a mount in 2015 for deferred tax asset valuation allowance is primarily associated with utilization of foreign tax credit carryforwards.

Significant Accounting Polici34

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Significant Accounting Policies [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. The Company sold its interest in a Canadian synthetic oil operation in 2016 and its Canadian heavy oil assets in early 2017. In addition, Murphy Oil sold its downstream retail marketing assets in the United Kingdom in 2015. See Notes C and E for more information regarding the sale of these assets
Principles of Consolidation	PRINCIPLES OF CONSOLIDATION – The consolidated financial statements include the accounts of Murphy Oil Corporation and all majority-owned subsidiaries. Undivided interests in oil and gas joint ventures are consolidated on a proportionate basis. Investments in affiliates in which the Company owns from 20% to 50% are accounted for by the equity method. Other investments are generally carried at cost. All significant intercompany accounts and transactions have been eliminated.  Beginning in 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 are 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 (loss) from continuing operations before income taxes, Loss from continuing operations, or Net Loss.
Revenue Recognition	REVENUE RECOGNITION – Revenues from sales of crude oil, natural gas liquids and natural gas are recorded when deliveries have occurred and legal ownership of the commodity transfers to the customer. Revenues from the production of oil and natural gas properties in which Murphy shares an undivided interest with other producers are recognized based on the actual volumes sold by the Company during the period. Natural gas imbalances occur when the Company’s actual gas sales volumes differ from its proportional share of production from the well. The company follows the sales method of accounting for these natural gas imbalances. The Company records a liability for gas imbalances when it has sold more than its working interest of gas production and the estimated remaining reserves make it doubtful that partners can recoup their share of production from the field. At December 31, 2017 and 2016, the liabilities for natural gas balancing were immaterial. See Note B for further discussion on revenue recognition. 
Cash Equivalents	CASH EQUIVALENTS – Short-term investments, which include government securities and other instruments with government securities as collateral, that are highly liquid and have a maturity of three months or less from the date of purchase are classified as cash equivalents.
Marketable Securities	MARKETABLE SECURITIES – The Company classifies investments in marketable securities as available-for-sale or held-to-maturity. The Company does not have any investments classified as trading securities. Available-for-sale securities are carried at fair value with the unrealized gain or loss, net of tax, reported in other comprehensive loss. Held-to-maturity securities are recorded at amortized cost. Premiums and discounts are amortized or accreted into earnings over the life of the related available-for-sale or held-to-maturity security. Dividend and interest income is recognized when earned. Unrealized losses considered to be other than temporary are recognized currently in earnings. The cost of securities sold is based on the specific identification method. The fair value of investment securities is determined by available market prices. At December 31, 2016, the Company owned Canadian government securities with maturities greater than 90 days at date of acquisition that had a carrying value of $111.5 million. These securities are readily marketable and could be quickly converted to cash if needed to meet operating cash needs in Canada.
Accounts Receivable	 ACCOUNTS RECEIVABLE – At December 31, 2017 and 2016, the Company’s accounts receivable primarily consisted of amounts owed to the Company by customers for sales of crude oil and natural gas. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses on these receivables. The Company reviews this allowance for adequacy at least quarterly and bases its assessment on a combination of current information about its customers and historical write-off experience. Any trade accounts receivable balances written off are charged against the allowance for doubtful accounts. The Company has not experienced any significant credit-related losses in the past three years.
Inventories	 INVENTORIES – Amounts included in the Consolidated Balance Sheets include unsold crude oil production and materials and supplies associated with oil and gas production operations. Unsold crude oil production is carried in inventory at the lower of cost, generally applied on a first-in, first-out (FIFO) basis, or market, and includes costs incurred to bring the inventory to its existing condition. Materials and supplies inventories are valued at the lower of average cost or estimated value and generally consist of tubulars and other drilling equipment.
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT – The Company uses the successful efforts method to account for exploration and development expenditures. Leasehold acquisition costs are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Costs of undeveloped leases associated with unproved properties are expensed over the life of the leases. Exploratory well costs are capitalized pending determination about whether proved reserves have been found. In certain cases, a determination of whether a drilled exploratory well has found proved reserves cannot be made immediately. This is generally due to the need for a major capital expenditure to produce and/or evacuate the hydrocarbon(s) found. The determination of whether to make such a capital expenditure is usually dependent on whether further exploratory wells find a sufficient quantity of additional reserves. The Company continues to capitalize exploratory well costs in Property, Plant and Equipment 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. The Company reevaluates its capitalized drilling costs at least annually to ascertain whether drilling costs continue to qualify for ongoing capitalization. Other exploratory costs, including geological and geophysical costs, are charged to expense as incurred. Development costs, including unsuccessful development wells, are capitalized. Interest is capitalized on significant development projects that are expected to take one year or more to complete.  Oil and gas properties are evaluated by field for potential impairment. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets as applicable. An impairment is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to fair value. There was no impairment recorded in 2017. During 2016 and 2015, declines in future oil and gas prices provided indications of possible impairments in certain of the Company’s producing properties. As a result of management’s assessments during 2016, the Company recognized pretax noncash impairments charges of $95.1 million at its Terra Nova field offshore Canada and its Western Canada onshore heavy oil producing properties. In 2015, the Company recognized pretax noncash impairments charges of $2.5 billion to reduce the carrying value of certain producing properties in Malaysia, Western Canada and the Gulf of Mexico to their estimated fair value. See also Note E for further discussion of impairment charges.  The Company records a liability for asset retirement obligations (ARO) equal to the fair value of the estimated cost to retire an asset. The ARO liability is initially recorded in the period in which the obligation meets the definition of a liability, which is generally when a well is drilled or the asset is placed in service. The ARO liability is estimated by the Company’s engineers using existing regulatory requirements and anticipated future inflation rates. When the liability is initially recorded, the Company increases the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is increased over time to reflect the change in its present value, and the capitalized cost is depreciated over the useful life of the related long-lived asset. The Company reevaluates the adequacy of its recorded ARO liability at least annually. Actual costs of asset retirements such as dismantling oil and gas production facilities and site restoration are charged against the related liability. Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability is recognized as a gain or loss in the Company’s earnings.  Depreciation and depletion of producing oil and gas properties are recorded based on units of production. Unit rates are computed for unamortized exploration drilling and development costs using proved developed reserves; unit rates for unamortized leasehold costs and asset retirement costs are amortized over proved reserves. Proved reserves are estimated by the Company’s engineers and are subject to future revisions based on availability of additional information. Additionally, certain natural gas processing facilities and related equipment in Malaysia are being  depreciated on a straight-line basis over their estimated useful life ranging from 20 to 25 years. Gains and losses on asset disposals or retirements are included in net loss as a separate component of revenues. Turnarounds for coking units at Syncrude Canada Ltd. were scheduled at intervals of two to three years. Turnaround work associated with various other less significant units at Syncrude varied depending on operating requirements and events. Murphy defers turnaround costs incurred and amortizes such costs over the period until the next scheduled turnaround. This amortization is recorded in Lease operating expenses for Syncrude. All other maintenance and repairs are expensed as incurred. Renewals and betterments are capitalized. The Company sold its interest in Syncrude during 2016.
Capitalized Interest	Capitalized Interest – Interest associated with borrowings from third parties is capitalized on significant oil and gas development projects when the expected development period extends for one year or more. Interest capitalized is credited in the Consolidated Statements of Operations and is added to the cost of the underlying asset for the development project in Property, plant and equipment in the Consolidated Balance Sheets. Capitalized interest is amortized over the useful life of the asset in the same manner as other development costs.
Environmental Liabilities	ENVIRONMENTAL LIABILITIES – A liability for environmental matters is established when it is probable that an environmental obligation exists and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Related expenditures are charged against the liability. Environmental remediation liabilities have not been discounted for the time value of future expected payments. Environmental expenditures that have future economic benefit are capitalized.
Income Taxes	INCOME TAXES – The Company accounts for income taxes using the asset and liability method. Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities based on differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities. Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse. The Company routinely assesses the realizability of deferred tax assets based on available evidence including assumptions of future taxable income, tax planning strategies and other pertinent factors. A deferred tax asset valuation allowance is recorded when evidence indicates that it is more likely than not that all or a portion of these deferred tax assets will not be realized in a future period. Prior to 2017, the Company did not provide U.S. deferred taxes for undistributed earnings of certain foreign subsidiaries when these earnings were considered indefinitely invested. On December 22, 2017 the Tax Cuts and Jobs Act (2017 Tax Act) was enacted which triggered the transitional tax on a deemed repatriation of all past foreign earnings (see Note I) and a provision for this impact has been recorded. Also, deferred tax liabilities are recorded for relevant withholding taxes when undistributed earnings of foreign subsidiaries are not considered indefinitely invested. Under present law, the Company would incur a 5% withholding tax on any earnings repatriated from Canada to the U.S. The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be realized, and then only for the largest amount that is greater than 50% l ikely of being realized. The Company includes potential penalties and interest for uncertain income tax positions in income tax expense.
Foreign Currency	FOREIGN CURRENCY – Local currency is the functional currency used for recording operations in Canada and for former refining and marketing activities in the United Kingdom. The U.S. dollar is the functional currency used to record all other operations. Exchange gains or losses from transactions in a currency other than the functional currency are included in earnings. Gains or losses from translating foreign functional currencies into U.S. dollars are included in Accumulated Other Comprehensive Loss in Consolidated Statements of Stockholders’ Equity.
Derivative Instruments and Hedging Activities	DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES – The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheets. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge for accounting purposes, and thenceforth, recognize changes in the fair value of the contract in earnings. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items as well as its objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to  specific assets and liabilities or to specific firm commitments or forecasted transactions. The Company assesses at inception and on an ongoing basis whether a derivative instrument accounted for as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. The change in the fair value of a qualifying fair value hedge is recorded in earnings along with the gain or loss on the hedged item. The effective portion of the change in the fair value of a qualifying cash flow hedge is recorded in Accumulated other comprehensive loss in the Consolidated Balance Sheets until the hedged item is recognized currently in earnings. If a derivative instrument no longer qualifies as a cash flow hedge and the underlying forecasted transaction is no longer probable of occurring, hedge accounting is discontinued and the gain or loss recorded in Accumulated other comprehensive loss is recognized immediately in earnings.
Fair Value Measurements	Fair Value Measurements – The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheets. Fair value is determined using various techniques depending on the availability of observable inputs. Level 1 inputs include quoted prices in active markets for identical assets or liabilities. Level 2 inputs include observable inputs other than quoted prices included within Level 1. Level 3 inputs are unobservable inputs which reflect assumptions about pricing by market participants
Stock-based Compensation	STOCK-BASED COMPENSATION Equity-Settled Awards – The fair value of awarded stock options, restricted stock units and other stock-based compensation that are settled with Company shares is determined based on a combination of management assumptions and the market value of the Company’s common stock. The Company uses the Black-Scholes option pricing model for computing the fair value of equity-settled stock options. The primary assumptions made by management include the expected life of the stock option award and the expected volatility of Murphy’s common stock price. The Company uses both historical data and current information to support its assumptions. Stock option expense is recognized on a straight-line basis over the respective vesting period of two or three years. The Company uses a Monte Carlo valuation model to determine the fair value of performance-based restricted stock units that are equity settled and expense is recognized over the three -year vesting period. The fair value of time-lapse restricted stock units is determined based on the price of Company stock on the date of grant and expense is recognized over the vesting period. The Company estimates the number of stock options and performance-based restricted stock units that will not vest and adjusts its compensation expense accordingly. Differences between estimated and actual vested amounts are accounted for as an adjustment to expense when known.  Cash-Settled Awards – The Company accounts for stock appreciation rights (SAR), cash-settled restricted stock units (CRSU) and phantom stock units as liability awards. Expense associated with these awards are recognized over the vesting period based on the latest available estimate of the fair value of the awards, which is generally determined using a Black-Scholes method for SAR, a Monte Carlo method for performance-based CRSU, and the period-end price of the Company’s common stock for time-based CRSU and phantom units. When SAR are exercised and when CRSU and phantom units settle, the Company adjusts previously recorded expense to the final amounts paid out in cash for these awards
Pension and Other Postretirement Benefit Plans	PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS – The Company recognizes the funded status (the difference between the fair value of plan assets and the projected benefit obligation) of its defined benefit and other postretirement benefit plans in the Consolidated Balance Sheets. Changes in the funded status which have not yet been recognized in the Consolidated Statement of Operations are recorded net of tax in Accumulated o ther c omprehensive l oss. The remaining amounts in Accumulated o ther c omprehensive l oss include net actuarial losses and prior service (cost) credit.
Net Income (Loss) Per Common Share	NET INCOME (LOSS) PER COMMON SHARE – Basic income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income (loss) per common share is computed by dividing net income (loss) for each reporting period by the weighted average number of common shares outstanding during the period plus the effects of all potentially dilutive common shares. Dilutive securities are not included in the computation of diluted income (loss) per share when a net loss occurs as the inclusion would have the effect of reducing the diluted loss per share.
Use of Estimates	USE OF ESTIMATES – In preparing the financial statements of the Company in conformity with U.S. generally accepted accounting principles (GAAP), 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

Discontinued Operations and A35

Discontinued Operations and Assets Held for Sale (Tables)	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Assets Held for Sale [Abstract]
Major Categories of Assets and Liabilities Reflected as Held for Sale	   ( Thousands of dollars ) 2017 2016  Current assets  Cash $ 16,631 4,126  Accounts receivable 6,298 22,944  Other – –  Total current assets held for sale $ 22,929 27,070  Current liabilities  Accounts payable $ 837 270  Accrued compensation and severance – –  Refinery decommissioning cost 2,693 2,506  Total current liabilities associated with assets held for sale $ 3,530 2,776  Non-current liabilities  Asset retirement obligation – Seal asset $ – 85,900 
Results of Operations Associated with Discontinued Operations	   ( Thousands of dollars ) 2017 2016 2015  Revenues $ 854 1,464 381,747  Loss from operations before income taxes $ (853) (2,027) (6,758)  Loss on sale before income taxes – – (4,990)  Total loss from discontinued operations before taxes (853) (2,027) (11,748)  Income tax expense – – 3,313  Loss from discontinued operations $ (853) (2,027) (15,061) 

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2017
Inventories [Abstract]
Schedule of Inventory	   December 31,  2017 2016  ( Thousands of dollars )  Unsold crude oil $ 20,153 17,146  Materials and supplies 84,974 109,925  $ 105,127 127,071 

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant And Equipment [Abstract]
Schedule of Property, Plant and Equipment	   December 31, 2017 December 31, 2016  ( Thousands of dollars ) Cost Net Cost Net  Exploration and production 1 $ 20,329,930 8,120,293 2 20,767,772 8,214,740 2  Corporate and other 170,842 99,738 156,231 101,448  $ 20,500,772 8,220,031 20,924,003 8,316,188  1 Includes unproved mineral rights as follows: $ 600,423 198,349 595,138 188,689 2. Includes $38,670 in 2017 and $48,053 in 2016 related to administrative assets and support equipment.
Schedule of Recognized Impairments	    December 31,  ( Thousands of dollars ) 2017 2016 2015  Gulf of Mexico $ – – 328,982  Canada – 95,088 683,574  Malaysia – – 1,480,600  $ – 95,088 2,493,156 
Net Changes in Capitalized Exploratory Well Costs	   ( Thousands of dollars ) 2017 2016 2015  Beginning balance at January 1 $ 148,500 130,514 120,455  Additions pending the determination of proved reserves 51,488 17,986 64,578  Reclassifications to proved properties based on the determination of proved reserves (15,988) – –  Capitalized exploratory well costs charged to expense (8,360) – (54,519)  Ending balance at December 31 $ 175,640 148,500 130,514 
Aging of Capitalized Exploratory Well Costs	   2017 2016 2015  ( Thousands of dollars ) Amount No. of Wells No. of Projects Amount No. of Wells No. of Projects Amount No. of Wells No. of Projects  Aging of capitalized well costs:  Zero to one year $ 41,480 3 2 $ 20,481 1 1 $ 66,032 7 6  One to two years 5,812 1 1 63,527 5 5 – – –  Two to three years 43,200 2 2 – – – 57,876 3 –  Three years or more 85,148 7 1 64,492 6 – 6,606 3 –  $ 175,640 13 6 $ 148,500 12 6 $ 130,514 13 6 

Long-term Debt (Tables)

Long-term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Financing Arrangements and Long-Term Debt [Abstract]
Schedule of Long-term Debt	   December 31,  (Thousands of dollars ) 2017 2016  Notes payable  3.50% notes, due December 2017 $ - 550,000  4.00% notes, due June 2022 500,000 500,000  4.45% notes, due December 2022 1 600,000 600,000  6.875% notes, due August 2024 550,000 550,000  5.75% notes, due August 2025 550,000 -  7.05% notes, due May 2029 250,000 250,000  5.875% notes, due December 2042 1 350,000 350,000  Total notes payable 2,800,000 2,800,000  Unamortized debt issuance cost and discount on notes payable (27,433) (23,835)  Total notes payable, net of unamortized discount 2,772,567 2,776,165  Capitalized lease obligation, due through March 2029 143,855 216,402  Total debt including current maturities 2,916,422 2,992,567  Current maturities (9,902) (569,817)  Total long-term debt $ 2,906,520 2,422,750  1 Due to a series of ratings changes by credit agencies, the paying interest rates on the notes due December 2022 and December 2042 decreased from 4.7% to 4.45% and 6.125% to 5.875%, respectively, at December 2017.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligations [Abstract]
Schedule of Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligations	   ( Thousands of dollars ) 2017 2016  Balance at beginning of year $ 781,057 825,312  Accretion expense 42,590 46,742  Liabilities incurred 52,331 13,690  Revisions of previous estimates (47,612) (4,511)  Liabilities settled (29,111) (20,589)  Liabilities assumed by purchaser of oil and gas assets (87,456) (91,883)  Changes due to translation of foreign currencies 10,340 12,296  Balance at end of year 722,139 781,057  Liabilities reported as held for sale at end of year 1 – (85,900)  Current portion of liability at end of year 2 (12,840) (13,629)  Noncurrent portion of liability at end of year $ 709,299 681,528  1 Liabilities held for sale related to Seal properties in Canada which were sold in January 2017. 2 Included in Other accrued liabilities on the Consolidated Balance Sheet. 

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Taxes [Abstract]
Components of Income (Loss) from Continuing Operations Before Income Taxes and Income Tax Expense	   ( Thousands of dollars ) 2017 2016 2015  Income (loss) from continuing operations before income taxes  United States $ (299,349) (595,196) (1,259,268)  Foreign 371,151 102,081 (2,022,994)  Total $ 71,802 (493,115) (3,282,262)  Income tax expense (benefit)  Federal – Current $ – – (9,435)  – Deferred 156,065 (197,450) (241,127)  Total Federal 156,065 (197,450) (250,562)  State 4,230 13,984 (5,294)  Foreign – Current 122,318 146,861 (40,550)  – Deferred 100,125 (182,567) (730,084)  Total Foreign 222,443 (35,706) (770,634)  Total $ 382,738 (219,172) (1,026,490) 
Effective Income Tax Rates	  ( Thousands of dollars ) 2017 2016 2015  Income tax expense (benefit) based on the U.S. statutory tax rate $ 25,131 (172,590) (1,148,792)  Revaluation of deferred tax (US tax reform) 118,004 – –  Deferred tax effect of deemed repatriation of foreign invested earnings (U.S. tax reform) 156,000 – –  Deferred tax effect on Canadian earnings no longer indefinitely invested 65,000 – –  Foreign income (loss) subject to foreign tax rates different than the U.S. statutory rate 12,658 8,582 49,739  State income taxes, net of federal benefit 2,438 9,090 (3,441)  U.S. tax benefit on certain foreign upstream investments (32,926) (21,336) (16,939)  Deferred tax on distribution of foreign earnings – – 188,461  Tax effects on sale of Canadian assets – (89,473) –  Tax effects on sale of Malaysian assets – 2,080 (122,559)  Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures 18,601 25,734 40,788  Other, net 17,832 18,741 (13,747)  Total $ 382,738 (219,172) (1,026,490) 
Analysis of Deferred Tax Assets and Deferred Tax Liabilities Showing Tax Effects of Significant Temporary Differences	   ( Thousands of dollars ) 2017 2016  Deferred tax assets  Property and leasehold costs $ 488,584 572,481  Liabilities for dismantlements 98,444 170,946  Postretirement and other employee benefits 134,444 214,288  Alternative minimum tax 29,710 29,710  Foreign tax credit carryforwards 228,159 33,295  U. S. net operating loss 272,930 454,231  Other deferred tax assets 13,892 16,541  Total gross deferred tax assets 1,266,163 1,491,492  Less valuation allowance (476,256) (305,389)  Net deferred tax assets 789,907 1,186,103  Deferred tax liabilities  Deferred tax on undistributed foreign earnings (65,000) –  Accumulated depreciation, depletion and amortization (669,638) (867,343)  Other deferred tax liabilities (2,824) (21,908)  Total gross deferred tax liabilities (737,462) (889,251)  Net deferred tax assets $ 52,445 296,852 
Reconciliation of Beginning and Ending Amount of Consolidated Liability for Unrecognized Income Tax Benefits	   ( Thousands of dollars ) 2017 2016 2015  Balance at January 1 $ 7,417 6,631 6,011  Additions for tax positions related to current year 769 756 821  Settlements due to lapse of time (4,834) – –  Foreign currency translation effect 85 30 (201)  Balance at December 31 $ 3,437 7,417 6,631 

Incentive Plans (Tables)

Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Incentive Plans [Abstract]
Share-Based Plans, Amounts Recognized	   ( Thousands of dollars ) 2017 2016 2015  Compensation charged against income (loss) before income tax benefit $ 40,365 46,300 44,021  Related income tax benefit recognized in income 5,017 15,244 13,583 
Fair Value of Option Award Estimated on Date of Grant using Black-Scholes Pricing Model	   2017 2016 2015   Fair value per option grant $7.96 $5.03 $10.97 – $11.08  Assumptions  Dividend yield 3.60% 4.00% 2.40% – 2.50 %  Expected volatility 41.00% 45.00% 29.00% – 30.00%  Risk-free interest rate 1.97% 1.32% 1.34% – 1.60%  Expected life 5.30 yrs. 5.20 yrs. 5.30 yrs. 
Changes in Stock Options Outstanding	   Number of Shares Average Exercise Price  Outstanding at December 31, 2014 5,602,250 $ 57.95  Granted at FMV 991,000 49.67  Exercised (32,349) 40.80  Forfeited (1,117,613) 31.99  Outstanding at December 31, 2015 5,443,288 52.93  Granted at FMV 862,000 17.57  Exercised – –  Forfeited (547,853) 44.23  Outstanding at December 31, 2016 5,757,435 48.46  Granted at FMV 603,000 28.51  Exercised – –  Forfeited (1,459,166) 49.34  Outstanding at December 31, 2017 4,901,269 45.74  Exercisable at December 31, 2014 3,030,105 $ 53.10  Exercisable at December 31, 2015 3,542,352 52.26  Exercisable at December 31, 2016 3,830,535 53.80  Exercisable at December 31, 2017 3,197,269 54.22 
Additional Information about Stock Options Outstanding	   Options Outstanding Options Exercisable  Range of Exercise Prices per Option No. of Options Avg. Life Remaining in Years Aggregate Intrinsic Value No. of Options Avg. Life Remaining in Years Aggregate Intrinsic Value  $17.00 to $30.00 1,320,000 5.5 $ 11,652,680 – – $ –  $31.00 to $50.00 823,350 3.9 – 439,350 3.8 –  $51.00 to $65.00 2,757,919 1.6 – 2,757,919 1.6 –  4,901,269 3.0 $ 11,652,680 3,197,269 1.9 $ – 
Changes in Performance-Based RSU Outstanding	   ( Number of share units ) 2017 2016 2015  Outstanding at beginning of year 992,573 1,103,986 1,397,040  Granted 560,000 394,000 455,000  Awarded (272,725) (361,096) (521,800)  Forfeited (91,927) (144,317) (226,254)  Outstanding at end of year 1,187,921 992,573 1,103,986 
Assumptions used in Valuation of Performance Awards Granted	   2017 2016 2015   Fair value per share at grant date $24.10 – $28.28 $12.21 – $16.34 $44.03 – $48.12  Assumptions  Expected volatility 47.00% 33.00% 26.00%  Risk-free interest rate 1.46% 0.93% 0.85%  Stock beta 1.058 0.863 0.813  Expected life 3.0 yrs. 3.0 yrs. 3.0 yrs. 
Changes in Time-Lapse Restricted Stock and Restricted Stock Units Outstanding	   ( Number of share units ) 2017 2016 2015   Outstanding at beginning of year 923,282 477,244 321,789  Granted 419,720 503,555 282,065  Vested and issued (217,633) (32,092) (69,610)  Forfeited (89,389) (25,425) (57,000)  Outstanding at end of year 1,035,980 923,282 477,244 

Employee and Retiree Benefit 42

Employee and Retiree Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status	   Pension Benefits Other Postretirement Benefits  ( Thousands of dollars ) 2017 2016 2017 2016  Change in benefit obligation  Obligation at January 1 $ 815,593 794,589 106,679 115,222  Service cost 8,279 8,136 1,601 1,864  Interest cost 27,047 25,185 3,444 3,800  Participant contributions – – 2,075 1,278  Actuarial loss (gain) 60,855 58,236 (3,077) (10,627)  Medicare Part D subsidy – – 318 510  Exchange rate changes 18,751 (30,447) 46 20  Benefits paid (39,910) (40,928) (4,810) (5,369)  Curtailments – 822 – (19)  Other (8,683) – – –  Obligation at December 31 881,932 815,593 106,276 106,679  Change in plan assets  Fair value of plan assets at January 1 519,357 521,682 – –  Actual return on plan assets 50,079 61,860 – –  Employer contributions 24,918 8,186 2,417 3,581  Participant contributions – – 2,075 1,278  Medicare Part D subsidy – – 318 510  Exchange rate changes 18,064 (30,609) – –  Benefits paid (39,910) (40,928) (4,810) (5,369)  Other (8,683) (834) – –  Fair value of plan assets at December 31 563,825 519,357 – –  Funded status and amounts recognized in the Consolidated Balance Sheets at December 31  Deferred charges and other assets 5,905 7,591 – –  Other accrued liabilities (8,856) (8,184) (5,392) (5,267)  Deferred credits and other liabilities (315,156) (295,643) (100,884) (101,412)  Funded status and net plan liability recognized at December 31 $ (318,107) (296,236) (106,276) (106,679) 
Amounts Included in Accumulated Other Comprehensive Income Not Recognized in Net Periodic Benefit Expense	   ( Thousands of dollars ) Pension Benefits Other Postretirement Benefits  Net actuarial loss $ (269,063) 221  Prior service (cost) credit (5,824) 38  $ (274,887) 259 
Amounts Included in Accumulated Other Comprehensive Income Expected to be Amortized into Net Periodic Benefit Expense	   ( Thousands of dollars ) Pension Benefits Other Postretirement Benefits  Net actuarial loss $ (15,890) –  Prior service (cost) credit (1,021) 38  $ (16,911) 38 
Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets	   Projected Benefit Obligations Accumulated Benefit Obligations Fair Value of Plan Assets  ( Thousands of dollars ) 2017 2016 2017 2016 2017 2016  Funded qualified plans where accumulated benefit obligation exceeds fair value of plan assets $ 691,923 643,174 640,230 599,730 540,161 497,894  Unfunded nonqualified and directors' plans where accumulated benefit obligation exceeds fair value of plan assets 172,364 156,088 163,319 150,780 – –  Unfunded other postretirement plans 106,276 106,678 106,276 106,678 – – 
Components of Net Periodic Benefit Expense	  Pension Benefits Other Postretirement Benefits  ( Thousands of dollars ) 2017 2016 2015 2017 2016 2015  Service cost $ 8,279 8,136 17,948 1,601 1,864 3,180  Interest cost 27,047 25,185 33,168 3,444 3,800 4,883  Expected return on plan assets (28,941) (28,154) (34,016) – – –  Amortization of prior service cost (credit) 1,026 1,204 1,560 (74) (75) (82)  Amortization of transitional (asset) liability – – (1) – – –  Recognized actuarial loss 16,691 16,165 15,147 – 5 992  24,102 22,536 33,806 4,971 5,594 8,973  Termination benefits expense – – 8,606 – – –  Curtailment expense – 822 306 – (19) –  Net periodic benefit expense $ 24,102 23,358 42,718 4,971 5,575 8,973 
Weighted-Average Assumptions used in Measurement of Benefit Obligations and Net Periodic Benefit Expense	   Benefit Obligations Net Periodic Benefit Expense  Pension Benefits Other Postretirement Benefits Pension Benefits Other Postretirement Benefits  December 31 December 31 Year Year  2017 2016 2017 2016 2017 2016 2017 2016  Discount rate 3.42% 3.94% 3.73% 4.41% 3.66% 3.84% 4.33% 4.24%  Expected return on plan assets 5.64% 5.62% – – 5.64% 5.62% – –  Rate of compensation increase 3.52% 3.52% – – 3.52% 3.52% – – 
Benefit Payments Reflecting Expected Future Service as Appropriate which are Expected to be Paid in Future Years from Assets of Plans or by Company	   ( Thousands of dollars ) Pension Benefits Other Postretirement Benefits  2018 $ 39,929 6,259  2019 40,236 6,280  2020 41,220 6,357  2021 42,276 6,489  2022 43,554 6,560  2023-2027 227,039 33,971  
One Percent Change in Assumed Health Care Cost Trend Rates	   ( Thousands of dollars ) 1% Increase 1% Decrease  Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2017 $ 919 (719)  Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2017 15,220 (12,277) 
Weighted Average Asset Allocation for Funded Pension Benefit Plans	   December 31,  2017 2016  Equity securities 60.3 % 58.4 %  Fixed income securities 37.2 39.0  Cash equivalents 2.5 2.6  100.0 % 100.0 % 
Fair Value Measurements of Retirement Plan Assets	At December 31, 2017, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.     Fair Value Measurements Using  ( Thousands of dollars ) Fair Value at December 31, 2017 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3)  Domestic Plans  Equity securities:  U.S. core equity $ 67,343 67,343 – –  U.S. small/midcap 24,544 24,544 – –  Hedged funds and other alternative strategies 50,522 – 12,572 37,950  International commingled trust fund 83,960 – 83,960 –  Emerging market commingled equity fund 20,774 – 20,774 –  Fixed income securities:  U.S. fixed income 79,890 – 79,890 –  International commingled trust fund 13,122 – 13,122 –  Emerging market mutual fund 5,266 – 5,266 –  Cash and equivalents 5,871 5,871 – –  Total Domestic Plans 351,292 97,758 215,584 37,950  Foreign Plans  Equity securities funds 78,666 – 78,666 –  Fixed income securities funds 103,314 – 103,314 –  Diversified pooled fund 23,665 – 23,665 –  Cash and equivalents 6,888 – 6,888 –  Total Foreign Plans 212,533 – 212,533 –  Total $ 563,825 97,758 428,117 37,950  At December 31, 2016, the fair value measurements of retirement plan assets within the fair value hierarchy are included in the table that follows.     Fair Value Measurements Using  ( Thousands of dollars ) Fair Value at December 31, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3)  Domestic Plans  Equity securities:  U.S. core equity $ 61,554 61,554 – –  U.S. small/midcap 23,103 23,103 – –  Hedged funds and other alternative strategies 48,113 – 13,999 34,114  International commingled trust fund 67,451 – 67,451 –  Emerging market commingled equity fund 16,006 – 16,006 –  Fixed income securities:  U.S. fixed income 78,473 – 78,473 –  International commingled trust fund 13,486 – 13,486 –  Emerging market mutual fund 5,775 – 5,775 –  Cash and equivalents 7,821 7,821 – –  Total Domestic Plans 321,782 92,478 195,190 34,114  Foreign Plans  Equity securities funds 74,108 – 74,108 –  Fixed income securities funds 97,075 – 97,075 –  Diversified pooled fund 21,463 – 21,463 –  Cash and equivalents 4,929 – 4,929 –  Total Foreign Plans 197,575 – 197,575 –  Total $ 519,357 92,478 392,765 34,114 
Effects of Fair Value Measurements Using Significant Unobservable Inputs on Changes in Level 3 Plan Assets	   ( Thousands of dollars ) Hedged Funds and Other Alternative Strategies  Total at December 31, 2015 $ 33,929  Actual return on plan assets:  Relating to assets held at the reporting date 185  Relating to assets sold during the period –  Purchases, sales and settlements –  Total at December 31, 2016 34,114  Actual return on plan assets:  Relating to assets held at the reporting date 3,836  Relating to assets sold during the period –  Purchases, sales and settlements –  Total at December 31, 2017 $ 37,950 
Foreign Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status	   Pension Benefits Other Postretirement Benefits  ( Thousands of dollars ) 2017 2016 2017 2016  Benefit obligation at December 31 $ 222,483 206,502 791 615  Fair value of plan assets at December 31 212,535 197,575 – –  Net plan liabilities recognized 9,948 8,927 791 615  Net periodic benefit expense (benefit) 194 (2,244) 133 154 

Financial Instruments and Ris43

Financial Instruments and Risk Management (Tables)	12 Months Ended
	Dec. 31, 2017
Financial Instruments and Risk Management [Abstract]
Fair Value of Derivative Instruments Not Designated as Hedging Instruments	   December 31, 2017 December 31, 2016  ( Thousands of dollars ) Asset (Liability) Derivatives Asset (Liability) Derivatives  Type of Derivative Contract Balance Sheet Location Fair Value Balance Sheet Location Fair Value  Commodity Accounts payable $ (39,093) Accounts payable $ (48,864)  Foreign exchange – – Accounts payable $ (73) 
Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments	   Gain (Loss)  ( Thousands of dollars ) Year Ended December 31,  Type of Derivative Contract Statement of Operations Locations 2017 2016  Commodity Sales and other operating revenues $ 9,567 $ (63,412)  Foreign exchange Interest and other income (loss) – 26,714  $ 9,567 $ (36,698) 

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity and Common Stock Issued and Outstanding [Abstract]
Summary of Shares Repurchased	    2015  Purchase of Treasury Stock $ 250,000,000  Shares repurchased 5,967,313 

Earnings per Share (Tables)

Earnings per Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings per Share [Abstract]
Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share	   ( Weighted-average shares ) 2017 2016 2015  Basic method 172,524,061 172,173,012 174,351,227  Dilutive stock options 1 – – –  Diluted method 172,524,061 172,173,012 174,351,227  1 Due to a net loss recognized by the Company for the years ended December 31, 2017, 2016 and 2015, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.
Anti Dilutive Securities Not Included in Computation of Diluted EPS	   2017 2016 2015  Antidilutive stock options excluded from diluted shares 4,901,269 5,757,435 5,443,288  Weighted average price of these options $45.74 $48.46 $52.93 

Other Financial Information (Ta

Other Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Other Financial Information [Abstract]
Schedule of Noncash Operating Working Capital (Increase) Decrease	   ( Thousands of dollars ) 2017 2016 2015  Accounts receivable $ 114,401 119,671 297,625  Inventories 26,883 (5,171) (15,340)  Prepaid expenses 29,570 149,946 (144,845)  Deferred income tax assets – – 3,924  Accounts payable and accrued liabilities (51,439) (328,078) (36,887)  Current income tax liabilities 16,999 24,943 (69,413)  Net (increase) decrease in noncash operating working capital $ 136,414 (38,689) 35,064  Supplementary disclosures (including discontinued operations):  Cash income taxes paid, net of refunds $ 68,076 6,707 118,667  Interest paid, net of amounts capitalized of $4,488 in 2017, $4,322 in 2016 and $7,290 in 2015 147,975 127,798 110,386   Noncash investing activities, related to continuing operations:  Asset retirement costs capitalized $ 8,509 13,690 76,775  Decrease in capital expenditure accrual 99,199 158,885 462,474 

Accumulated Other Comprehensi47

Accumulated Other Comprehensive Loss (Tables)	12 Months Ended
	Dec. 31, 2017
Accumulated Other Comprehensive Loss [Abstract]
Components of Accumulated Other Comprehensive Loss	   ( Thousands of dollars ) Foreign Currency Translation Gains (Losses) Retirement and Postretirement Benefit Plan Adjustments Deferred Loss on Interest Rate Derivative Hedges Total  Balance at December 31, 2015 $ (513,004) (179,260) (12,278) (704,542)  2016 components of other comprehensive income (loss):  Before reclassifications to income 66,449 (3,763) – 62,686  Reclassifications to income – 11,718 1 1,926 2 13,644  Net other comprehensive income 66,449 7,955 1,926 76,330  Balance at December 31, 2016 (446,555) (171,305) (10,352) (628,212)  2017 components of other comprehensive income (loss):  Before reclassifications to income 171,725 (17,269) – 154,456  Reclassifications to income – 9,587 1 1,926 2 11,513  Net other comprehensive income (loss) 171,725 (7,682) 1,926 165,969  Balance at December 31, 2017 $ (274,830) (178,987) (8,426) (462,243)  1 Reclassifications before taxes of $14,821 and $18,036 are included in the computation of net periodic benefit expense in 201 7 and 2016, respectively. See Note K for additional information. Related income taxes of $5,234 and $6,318 are included in income tax expense in 201 7 and 2016, respectively. 2 Reclassifications before taxes of $2,963 are included in Interest expense in both 201 7 and 2016. Related income taxes of $1,037 are included in income tax expense in 201 7 and 2016. See Note L for additional information.

Assets and Liabilities Measur48

Assets and Liabilities Measured at Fair Value (Tables)	12 Months Ended
	Dec. 31, 2017
Assets and Liabilities Measured at Fair Value [Abstract]
Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis	  December 31, 2017 December 31, 2016  ( Thousands of dollars ) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total  Liabilities:  Nonqualified employee savings plans $ 16,158 – – 16,158 13,904 – – 13,904  Commodity derivative contracts – 39,093 – 39,093 – 48,864 – 48,864  Foreign currency exchange derivative contracts – – – – – 73 – 73  $ 16,158 39,093 – 55,251 13,904 48,937 – 62,841 
Carrying Amounts and Estimated Fair Values of Financial Instruments	  At December 31,  2017 2016  ( Thousands of dollars ) Carrying Amount Fair Value Carrying Amount Fair Value  Financial assets (liabilities):  Canadian government securities with maturities greater than 90 days at the date of acquisition $ - - 111,542 111,331  Current and long-term debt (2,916,422) (2,993,003) (2,992,567) (2,951,992) 
Nonrecurring Fair Value Measurements	    Year Ended December 31, 2016  Total  Net Book Pretax  Value (Noncash)  Fair Value Prior to Impairment  ( Thousands of dollars ) Level 1 Level 2 Level 3 Impairment Expense  Assets:  Impaired proved properties  Western Canada $ – – 71,967 167,055 95,088  $ – – 71,967 167,055 95,088 

Common Stock Issued and Outst49

Common Stock Issued and Outstanding (Tables)	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity and Common Stock Issued and Outstanding [Abstract]
Activity in Number of Shares of Common Stock Issued and Outstanding	   ( Number of shares outstanding ) 2017 2016 2015  Beginning of year 172,202,177 172,034,711 177,499,513  Stock options exercised 1 – – 15,575  Restricted stock awards 1 368,132 158,504 478,549  Employee stock purchase and thrift plans 2,564 8,962 8,387  Treasury shares purchased – – (5,967,313)  End of year 172,572,873 172,202,177 172,034,711  1 Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note J due to withholdings for statutory income taxes owed upon issuance of shares.

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
	Dec. 31, 2017
Business Segments [Abstract]
Segment Information	  Segment Information Exploration and Production  ( Millions of dollars ) United States Canada 1 Malaysia Other Total E&P  Year ended December 31, 2017  Segment income (loss) $ (2.6) 112.5 224.2 (37.5) 296.6  Revenues from external customers 953.9 485.5 781.1 – 2,220.5 2  Interest income – – – – –  Interest expense, net of capitalization – – – – –  Income tax expense (benefit) 2.5 44.4 126.4 (36.2) 137.1  Significant noncash charges (credits)  Depreciation, depletion and amortization 546.1 185.4 204.6 3.8 939.9  Accretion of asset retirement obligations 17.4 7.9 17.3 – 42.6  Amortization of undeveloped leases 60.2 1.6 – – 61.8  Deferred and noncurrent income taxes 2.5 55.3 (3.7) (36.2) 17.9  Additions to property, plant, equipment 534.8 267.6 16.0 37.6 856.0  Total assets at year-end 5,186.2 1,725.8 1,670.1 154.2 8,736.3  Year ended December 31, 2016  Segment income (loss) $ (205.4) (35.9) 171.1 (54.7) (124.9)  Revenues from external customers 685.7 365.3 753.4 0.2 1,804.6  Interest income – – – – –  Interest expense, net of capitalization – – – – –  Income tax expense (benefit) (87.9) (134.3) 85.9 (18.8) (155.1)  Significant noncash charges (credits)  Depreciation, depletion and amortization 600.5 203.2 227.7 5.9 1,037.3  Accretion of asset retirement obligations 17.1 13.3 16.3 – 46.7  Amortization of undeveloped leases 38.4 4.5 – 0.5 43.4  Impairment of assets – 95.1 – – 95.1  Deferred and noncurrent income taxes (108.4) (175.8) (8.5) (18.3) (311.0)  Additions to property, plant, equipment 269.8 361.3 101.4 (1.3) 731.2  Total assets at year-end 5,419.0 1,559.5 2,024.7 115.7 9,118.9  Year ended December 31, 2015  Segment loss $ (615.7) (583.4) (653.2) (158.6) (2,010.9)  Revenues from external customers 1,253.6 549.7 1,131.4 – 2,934.7  Interest income – – – – –  Interest expense, net of capitalization – – – – –  Income tax expense (benefit) (337.0) (188.8) (567.9) (17.3) (1,111.0)  Significant noncash charges (credits)  Depreciation, depletion and amortization 794.9 261.9 544.9 6.2 1,607.9  Accretion of asset retirement obligations 20.2 12.6 15.9 – 48.7  Amortization of undeveloped leases 59.2 14.4 – 1.8 75.4  Impairment of assets 329.0 683.6 1,480.6 – 2,493.2  Deferred and noncurrent income taxes (187.7) (146.0) (579.2) (4.6) (917.5)  Additions to property, plant, equipment 1,263.1 184.9 244.4 39.2 1,731.6  Total assets at year-end 5,717.8 2,460.6 2,537.2 147.7 10,863.3  1 Includes Synthetic crude operations in 2016 and 2015. This business was sold in June 2016. 2 Includes a pretax gain of $129.0 million on sale of Seal area heavy oil field sold in January 2017.    Geographic Information Certain Long-Lived Assets at December 31  ( Millions of dollars ) United States Canada Malaysia United Kingdom Other Total  2017 $ 5,050.5 1,635.9 1,392.3 – 141.3 8,220.0  2016 5,121.6 1,451.4 1,637.0 – 106.2 8,316.2  2015 5,484.7 2,310.6 1,912.0 – 111.1 9,818.4      Segment Information — Continued  ( Millions of dollars ) Corporate and Other Discontinued Operations Consolidated Total  Year ended December 31, 2017  Segment income (loss) $ (607.5) (0.9) (311.8)  Revenues from external customers 4.6 – 2,225.1  Interest income 7.4 – 7.4  Interest expense, net of capitalization 181.8 – 181.8  Income tax expense (benefit) 245.6 – 382.7  Significant noncash charges (credits)  Depreciation, depletion and amortization 17.8 – 957.7  Accretion of asset retirement obligations – – 42.6  Amortization of undeveloped leases – – 61.8  Deferred and noncurrent income taxes 242.5 – 260.4  Additions to property, plant, equipment 14.8 – 870.8  Total assets at year-end 1,101.7 22.9 9,860.9  Year ended December 31, 2016  Segment income (loss) $ (149.1) (2.0) (276.0)  Revenues from external customers 6.6 – 1,811.2  Interest income 2.9 – 2.9  Interest expense, net of capitalization 148.2 – 148.2  Income tax expense (benefit) (64.1) – (219.2)  Significant noncash charges (credits)  Depreciation, depletion and amortization 16.8 – 1,054.1  Accretion of asset retirement obligations – – 46.7  Amortization of undeveloped leases – – 43.4  Impairment of assets – – 95.1  Deferred and noncurrent income taxes (76.8) – (387.8)  Additions to property, plant, equipment 21.9 – 753.1  Total assets at year-end 1,149.9 27.1 10,295.9   Year ended December 31, 2015  Segment loss $ (244.9) (15.0) (2,270.8)  Revenues from external customers 6.6 – 2,941.3  Interest income 4.0 – 4.0  Interest expense, net of capitalization 117.4 – 117.4  Income tax expense (benefit) 84.5 – (1,026.5)  Significant noncash charges (credits)  Depreciation, depletion and amortization 11.9 – 1,619.8  Accretion of asset retirement obligations – – 48.7  Amortization of undeveloped leases – – 75.4  Impairment of assets – – 2,493.2  Deferred and noncurrent income taxes (60.5) – (978.0)  Additions to property, plant, equipment 59.9 – 1,791.5  Total assets at year-end 592.2 38.3 11,493.8         Geographic Information Revenues from External Customers for the Year  ( Millions of dollars ) United States Canada Malaysia Other Total  2017 $ 958.3 485.7 781.1 – 2,225.1  2016 692.3 365.3 753.4 0.2 1,811.2  2015 1,260.2 549.7 1,131.4 – 2,941.3 

Supplemental Oil and Gas Info51

Supplemental Oil and Gas Information (Tables)	12 Months Ended
	Dec. 31, 2017
Reserve Quantities [Line Items]
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities	   ( Millions of dollars ) United States Canada Malaysia Other Total  Year ended December 31, 2017  Property acquisition costs  Unproved $ 50.4 – – 13.0 63.4  Proved 7.7 – – – 7.7  Total acquisition costs 58.1 – – 13.0 71.1  Exploration costs 1 13.7 0.6 (8.9) 73.8 79.2  Development costs 1 508.4 273.8 35.7 1.1 819.0  Total costs incurred 580.2 274.4 26.8 87.9 969.3  Charged to expense  Dry hole expense (1.9) – 0.7 (3.0) (4.2)  Geophysical and other costs 9.7 0.5 1.7 53.3 65.2  Total charged to expense 7.8 0.5 2.4 50.3 61.0  Property additions $ 572.4 273.9 24.4 37.6 908.3  Year ended December 31, 2016  Property acquisition costs  Unproved $ 18.6 – – – 18.6  Proved – 206.7 – – 206.7  Total acquisition costs 18.6 206.7 – – 225.3  Exploration costs 1 18.5 3.6 6.0 42.0 70.1  Development costs 1 239.7 165.1 102.9 0.3 508.0  Total costs incurred 276.8 375.4 108.9 42.3 803.4  Charged to expense  Dry hole expense 0.4 – 4.5 10.2 15.1  Geophysical and other costs 5.7 3.6 0.7 33.4 43.4  Total charged to expense 6.1 3.6 5.2 43.6 58.5  Property additions $ 270.7 371.8 103.7 (1.3) 744.9  Year ended December 31, 2015  Property acquisition costs  Unproved $ 10.1 2.5 – – 12.6  Proved – – – – –  Total acquisition costs 10.1 2.5 – – – 12.6  Exploration costs 1 166.8 0.7 69.0 135.4 371.9  Development costs 1 1,375.1 231.5 210.0 2.8 1,819.4  Total costs incurred 1,552.0 234.7 279.0 138.2 2,203.9  Charged to expense  Dry hole expense 241.3 – 29.7 25.8 296.8  Geophysical and other costs 16.9 0.7 7.9 73.2 98.7  Total charged to expense 258.2 0.7 37.6 99.0 395.5  Property additions $ 1,293.8 234.0 241.4 39.2 1,808.4  1 Includes noncash asset retirement costs as follows:    2017  Exploration costs $ – – – – –  Development costs 37.6 6.3 8.4 – 52.3  $ 37.6 6.3 8.4 – 52.3  2016  Exploration costs $ – – – – –  Development costs 0.9 10.5 2.3 – 13.7  $ 0.9 10.5 2.3 – 13.7  2015  Exploration costs $ – – – – –  Development costs 30.7 49.1 (3.0) – 76.8  $ 30.7 49.1 (3.0) – 76.8 
Results of Operations for Oil andGas Producing Activities	   Canada  United Conven-  ( Millions of dollars ) States tional Synthetic Malaysia Other Total  Year ended December 31, 2017  Revenues  Crude oil and natural gas liquids sales $ 913.3 203.7 – 639.9 – 1,756.9  Natural gas sales 37.9 155.1 – 138.2 – 331.2  Total oil and gas revenues 951.2 358.8 – 778.1 – 2,088.1  Other operating revenues 2.7 126.7 – 3.0 – 132.4  Total revenues 953.9 485.5 – 781.1 – 2,220.5  Costs and expenses  Lease operating expenses 198.5 101.1 – 168.8 – 468.4  Severance and ad valorem taxes 42.2 1.5 – – – 43.7  Exploration costs charged to expense 7.8 0.5 – 2.4 50.3 61.0  Undeveloped lease amortization 60.2 1.6 – – – 61.8  Depreciation, depletion and amortization 546.1 185.4 – 204.6 3.8 939.9  Accretion of asset retirement obligations 17.4 7.9 – 17.3 – 42.6  Redetermination expense – – – 15.0 – 15.0  Selling and general expenses 61.8 28.3 – 14.0 19.6 123.7  Other expenses 20.0 2.3 – 8.4 – 30.7  Total costs and expenses 954.0 328.6 – 430.5 73.7 1,786.8  Results of operations before taxes (0.1) 156.9 – 350.6 (73.7) 433.7  Income tax expense (benefit) 2.5 44.4 – 126.4 (36.2) 137.1  Results of operations $ (2.6) 112.5 – 224.2 (37.5) 296.6  Year ended December 31, 2016  Revenues  Crude oil and natural gas liquids sales $ 650.7 171.7 60.7 623.7 – 1,506.8  Natural gas sales 35.1 130.0 – 127.6 – 292.7  Total oil and gas revenues 685.8 301.7 60.7 751.3 – 1,799.5  Other operating revenues (0.1) (0.7) 3.6 2.1 0.2 5.1  Total revenues 685.7 301.0 64.3 753.4 0.2 1,804.6  Costs and expenses  Lease operating expenses 218.6 102.6 69.8 168.4 – 559.4  Severance and ad valorem taxes 37.0 4.3 2.5 – – 43.8  Exploration costs charged to expense 6.1 3.6 – 5.2 43.6 58.5  Undeveloped lease amortization 38.4 4.5 – – 0.5 43.4  Depreciation, depletion and amortization 600.5 186.7 16.5 227.7 5.9 1,037.3  Accretion of asset retirement obligations 17.1 10.9 2.4 16.3 – 46.7  Impairment of assets – 95.1 – – – 95.1  Redetermination expense – – – 39.1 – 39.1  Selling and general expenses 68.8 28.6 0.5 15.9 33.6 147.4  Other expenses (benefits) (7.5) 7.5 – 23.8 (9.9) 13.9  Total costs and expenses 979.0 443.8 91.7 496.4 73.7 2,084.6  Results of operations before taxes (293.3) (142.8) (27.4) 257.0 (73.5) (280.0)  Income tax expense (benefit) (87.9) (58.9) (75.4) 85.9 (18.8) (155.1)  Results of operations $ (205.4) (83.9) 48.0 171.1 (54.7) (124.9) 1 Results exclude corporate overhead, interest and discontinued operations.    Schedule 5 – Results of Operations for Oil and Gas Producing Activities 1 – Continued      Canada  United Conven-  ( Millions of dollars ) States tional Synthetic Malaysia Other Total  Year ended December 31, 2015  Revenues  Crude oil and natural gas liquids sales $ 1,176.9 181.0 203.0 790.6 – 2,351.5  Natural gas sales 70.4 167.7 – 185.4 – 423.5  Total oil and gas revenues 1,247.3 348.7 203.0 976.0 – 2,775.0  Other operating revenues 6.3 (2.4) 0.4 155.4 – 159.7  Total revenues 1,253.6 346.3 203.4 1,131.4 – 2,934.7  Costs and expenses  Lease operating expenses 312.0 102.4 166.0 251.9 – 832.3  Severance and ad valorem taxes 55.9 4.8 5.1 – – 65.8  Exploration costs charged to expense 258.2 0.7 – 37.6 99.0 395.5  Undeveloped lease amortization 59.2 14.4 – – 1.8 75.4  Depreciation, depletion and amortization 794.9 211.2 50.7 544.9 6.2 1,607.9  Accretion of asset retirement obligations 20.2 7.2 5.4 15.9 – 48.7  Impairment of assets 329.0 683.6 – 1,480.6 – 2,493.2  Selling and general expenses 88.2 25.5 1.0 5.7 56.8 177.2  Other expenses 288.7 43.9 – 15.9 12.1 360.6  Total costs and expenses 2,206.3 1,093.7 228.2 2,352.5 175.9 6,056.6  Results of operations before taxes (952.7) (747.4) (24.8) (1,221.1) (175.9) (3,121.9)  Income tax expense (benefit) (337.0) (191.2) 2.4 (567.9) (17.3) (1,111.0)  Results of operations $ (615.7) (556.2) (27.2) (653.2) (158.6) (2,010.9)  1 Results exclude corporate overhead, interest and discontinued operations.
Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves	   ( Millions of dollars ) United States Canada Malaysia Total  December 31, 2017  Future cash inflows $ 12,885.8 4,714.3 4,392.0 21,992.1  Future development costs (2,079.5) (1,081.7) (632.3) (3,793.5)  Future production costs (4,765.3) (2,507.4) (2,305.0) (9,577.7)  Future income taxes (893.7) (161.1) (232.2) (1,287.0)  Future net cash flows 5,147.3 964.1 1,222.5 7,333.9  10% annual discount for estimated timing of cash flows (2,698.2) (394.6) (318.2) (3,411.0)  Standardized measure of discounted future net cash flows $ 2,449.1 569.5 904.3 3,922.9  December 31, 2016  Future cash inflows $ 9,477.9 3,752.7 4,318.7 17,549.3  Future development costs (1,691.1) (1,143.6) (763.8) (3,598.5)  Future production costs (3,981.6) (2,329.7) (2,661.2) (8,972.5)  Future income taxes (118.9) (81.3) (73.3) (273.5)  Future net cash flows 3,686.3 198.1 820.4 4,704.8  10% annual discount for estimated timing of cash flows (1,799.5) (95.0) (230.3) (2,124.8)  Standardized measure of discounted future net cash flows $ 1,886.8 103.1 590.1 2,580.0  December 31, 2015  Future cash inflows $ 12,373.9 8,922.0 6,143.1 27,439.0  Future development costs (2,620.5) (1,145.4) (957.8) (4,723.7)  Future production costs (4,955.4) (5,892.7) (3,290.5) (14,138.6)  Future income taxes (339.7) (504.8) (216.2) (1,060.7)  Future net cash flows 4,458.3 1,379.1 1,678.6 7,516.0  10% annual discount for estimated timing of cash flows (2,430.0) (666.8) (560.1) (3,656.9)  Standardized measure of discounted future net cash flows $ 2,028.3 712.3 1,118.5 3,859.1 
Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows	   ( Millions of dollars ) 2017 2016 2015  Net changes in prices and production costs $ 2,428.4 (1,476.1) (11,365.5)  Net changes in development costs (724.4) 544.9 591.4  Sales and transfers of oil and gas produced, net of production costs (1,576.0) (1,196.3) (1,876.9)  Net change due to extensions and discoveries 807.9 280.5 1,145.8  Net change due to purchases and sales of proved reserves 85.9 (583.4) (287.4)  Development costs incurred 802.7 479.6 1,725.4  Accretion of discount 270.9 428.1 1,289.5  Revisions of previous quantity estimates (109.5) (49.2) 163.3  Net change in income taxes (643.0) 292.8 2,568.3  Net increase (decrease) 1,342.9 (1,279.1) (6,046.1)  Standardized measure at January 1 2,580.0 3,859.1 9,905.2  Standardized measure at December 31 $ 3,922.9 2,580.0 3,859.1 
Capitalized Costs Relating to Oil and Gas Producing Activities	   ( Millions of dollars ) United States Canada Malaysia Other Total  December 31, 2017  Unproved oil and gas properties $ 360.9 286.8 20.5 162.1 830.3  Proved oil and gas properties 9,606.4 3,603.4 6,139.7 – 19,349.5  Gross capitalized costs 9,967.3 3,890.2 6,160.2 162.1 20,179.8  Accumulated depreciation, depletion and amortization  Unproved oil and gas properties (149.5) (230.7) – (21.8) (402.0)  Proved oil and gas properties (4,893.8) (2,027.9) (4,774.5) – (11,696.2)  Net capitalized costs $ 4,924.0 1,631.6 1,385.7 140.3 8,081.6  December 31, 2016  Unproved oil and gas properties $ 360.8 315.6 47.0 125.6 849.0  Proved oil and gas properties 9,384.6 4,241.6 6,147.8 – 19,774.0  Gross capitalized costs 9,745.4 4,557.2 6,194.8 125.6 20,623.0  Accumulated depreciation, depletion and amortization  Unproved oil and gas properties (151.2) (233.6) – (21.8) (406.6)  Proved oil and gas properties (4,605.9) (2,877.2) (4,566.6) – (12,049.7)  Net capitalized costs $ 4,988.3 1,446.4 1,628.2 103.8 8,166.7 
Oil Reserves [Member]
Reserve Quantities [Line Items]
Summary of Proved Reserves Based on Average Prices	   Crude & Synthetic Oil Crude Oil Synthetic Oil 1  ( Millions of barrels ) Total Total United States Canada Malaysia Canada  Proved developed and undeveloped crude oil / synthetic oil reserves:  December 31, 2014 441.8 336.2 204.9 37.4 93.9 105.6  Revisions of previous estimates 5.3 (8.2) (7.6) (4.8) 4.2 13.5  Improved recovery 2.4 2.4 – – 2.4 –  Extensions and discoveries 63.8 63.8 63.8 – – –  Sales of properties (11.0) (11.0) – – (11.0) –  Production (46.1) (41.8) (22.2) (4.7) (14.9) (4.3)  December 31, 2015 456.2 341.4 238.9 27.9 74.6 114.8  Revisions of previous estimates (5.8) (5.8) (10.9) 2.5 2.6 –  Extensions and discoveries 11.0 11.0 8.6 – 2.4 –  Purchases of properties 26.3 26.3 – 26.3 – –  Sales of properties (121.0) (7.8) (4.5) (3.3) – (113.2)  Production (37.7) (36.1) (17.7) (4.5) (13.9) (1.6)  December 31, 2016 329.0 329.0 214.4 48.9 65.7 (0.0)  Revisions of previous estimates (6.0) (6.0) (4.7) 2.3 (3.6) –  Improved recovery 2.0 2.0 – – 2.0 –  Extensions and discoveries 31.6 31.6 27.2 4.4 – –  Purchases of properties 4.7 4.7 4.7 – – –  Production (33.2) (33.2) (16.9) (4.1) (12.2) –  December 31, 2017 328.1 328.1 224.7 51.5 51.9 –  Proved developed crude oil/ synthetic oil reserves:  December 31, 2014 324.1 218.5 106.2 32.4 79.9 105.6  December 31, 2015 326.6 211.8 125.9 23.8 62.1 114.8  December 31, 2016 184.9 184.9 113.9 19.2 51.8 –  December 31, 2017 185.5 185.5 126.3 21.9 37.3 –  Proved undeveloped crude oil reserves:  December 31, 2014 117.7 117.7 98.7 5.0 14.0 –  December 31, 2015 129.6 129.6 113.0 4.1 12.5 –  December 31, 2016 144.1 144.1 100.5 29.7 13.9 –  December 31, 2017 142.6 142.6 98.4 29.6 14.6 – 
Natural Gas Liquids Reserves [Member]
Reserve Quantities [Line Items]
Summary of Proved Reserves Based on Average Prices	    ( Millions of barrels ) Total United States Canada Malaysia  Proved developed and undeveloped NGL reserves:  December 31, 2014 30.6 29.1 0.7 0.8  Revisions of previous estimates 2.0 2.2 (0.3) 0.1  Extensions and discoveries 7.6 7.6 – –  Sales of properties (0.1) – – (0.1)  Production (3.7) (3.5) – (0.2)  December 31, 2015 36.4 35.4 0.4 0.6  Revisions of previous estimates 1.6 1.2 0.2 0.2  Extensions and discoveries 2.9 2.8 0.1 –  Purchases of properties 5.1 – 5.1 –  Production (3.5) (3.0) (0.2) (0.3)  December 31, 2016 42.5 36.4 5.6 0.5  Revisions of previous estimates 1.3 2.0 (0.6) (0.1)  Extensions and discoveries 7.8 7.0 0.8 –  Purchases of properties 0.5 0.5 – –  Production (3.2) (2.9) (0.2) (0.1)  December 31, 2017 48.9 43.0 5.6 0.3  Proved developed NGL reserves:  December 31, 2014 17.5 16.5 0.2 0.8  December 31, 2015 21.6 20.7 0.3 0.6  December 31, 2016 22.2 20.8 0.9 0.5  December 31, 2017 24.6 23.3 1.0 0.3  Proved undeveloped NGL reserves:  December 31, 2014 13.1 12.6 0.5 –  December 31, 2015 14.8 14.7 0.1 –  December 31, 2016 20.3 15.6 4.7 –  December 31, 2017 24.3 19.7 4.6 – 
Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Summary of Proved Reserves Based on Average Prices	   ( Billions of cubic feet ) Total United States Canada Malaysia  Proved developed and undeveloped natural gas reserves:  December 31, 2014 1,704.7 226.3 842.8 635.6  Revisions of previous estimates 53.5 (5.2) 18.9 39.8  Improved recovery 1.8 – – 1.8  Extensions and discoveries 162.9 43.2 119.7 –  Sales of properties (78.0) – – (78.0)  Production (156.1) (31.9) (71.8) (52.4)  December 31, 2015 1,688.8 232.4 909.6 546.8  Revisions of previous estimates 43.3 0.1 45.3 (2.1)  Extensions and discoveries 164.2 6.4 120.2 37.6  Purchases of properties 122.3 – 122.3 –  Sales of properties (2.2) (0.1) (2.1) –  Production (138.4) (19.4) (76.4) (42.6)  December 31, 2016 1,878.0 219.4 1,118.9 539.7  Revisions of previous estimates (5.4) (16.0) 19.4 (8.8)  Extensions and discoveries 190.6 32.2 156.7 1.7  Purchases of properties 4.0 4.0 – –  Production (140.1) (16.3) (82.6) (41.2)  December 31, 2017 1,927.1 223.3 1,212.4 491.4  Proved developed natural gas reserves:  December 31, 2014 812.1 145.6 467.4 199.1  December 31, 2015 783.5 148.3 453.5 181.7  December 31, 2016 818.1 138.7 498.9 180.5  December 31, 2017 819.3 127.7 547.0 144.6  Proved undeveloped natural gas reserves:  December 31, 2014 892.6 80.7 375.4 436.5  December 31, 2015 905.3 84.1 456.1 365.1  December 31, 2016 1,059.9 80.7 620.0 359.2  December 31, 2017 1,107.8 95.6 665.5 346.7 

Supplemental Quarterly Inform52

Supplemental Quarterly Information (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Quarterly Information [Abstract]
Schedule of Supplemental Quarterly Information	   ( Millions of dollars except per share amounts ) First Quarter Second Quarter Third Quarter Fourth Quarter Year  Year ended December 31, 2017  Sales and other operating revenues $ 544.7 509.7 498.3 545.0 2,097.7  Income (loss) from continuing operations before income taxes 154.9 (21.9) (63.6) 2.4 71.8  Income (loss) from continuing operations 57.5 (17.3) (66.3) (284.8) (310.9)  Net income (loss) 58.5 (17.6) (65.9) (286.8) (311.8)  Income (loss) from continuing operations per Common share  Basic 0.33 (0.10) (0.38) (1.65) (1.81)  Diluted 0.33 (0.10) (0.38) (1.65) (1.81)  Net income (loss) per Common share  Basic 0.34 (0.10) (0.38) (1.66) (1.81)  Diluted 0.34 (0.10) (0.38) (1.66) (1.81)  Cash dividend per Common share 0.25 0.25 0.25 0.25 1.00  Market price of Common Stock 1  High 32.18 28.71 27.43 31.98 32.18  Low 25.76 24.06 22.63 25.02 22.63  Year ended December 31, 2016  Sales and other operating revenues $ 429.1 411.2 486.3 483.0 1,809.6  Loss from continuing operations before income taxes (265.0) (131.3) (16.7) (80.1) (493.1)  Income (loss) from continuing operations (199.5) 2.9 (14.6) (62.8) (274.0)  Net income (loss) (198.8) 2.9 (16.2) (63.9) (276.0)  Income from continuing operations per Common share  Basic (1.16) 0.02 (0.08) (0.36) (1.59)  Diluted (1.16) 0.02 (0.08) (0.36) (1.59)  Net income (loss) per Common share  Basic (1.16) 0.02 (0.08) (0.37) (1.60)  Diluted (1.16) 0.02 (0.08) (0.37) (1.60)  Cash dividend per Common share 0.35 0.35 0.25 0.25 1.20  Market price of Common Stock 1  High 26.69 36.24 32.66 34.30 36.24  Low 15.76 23.49 25.14 25.00 15.76 

Significant Accounting Polici53

Significant Accounting Policies (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Significant Accounting Policies [Line Items]
Maturity of Canadian government securities	90 days	90 days		90 days
Canadian government securities with maturities greater than 90 days at the date of acquisition		$ 111,542,000
Impairment of assets	$ 0	95,088,000	[1]	$ 2,493,156,000	[1]
Withholding tax on amounts repatriated	5.00%
Stock Options [Member]
Significant Accounting Policies [Line Items]
Stock-based compensation, fair value assumption model	Black-Scholes option pricing model
Performance Based Restricted Stock [Member]
Significant Accounting Policies [Line Items]
Stock-based compensation, fair value assumption model	Monte Carlo valuation model
Stock-based compensation, vesting period	3 years
Minimum [Member]
Significant Accounting Policies [Line Items]
Equity method investment, ownership percentage	20.00%
Minimum [Member] | Stock Options [Member]
Significant Accounting Policies [Line Items]
Stock-based compensation, vesting period	2 years
Maximum [Member]
Significant Accounting Policies [Line Items]
Equity method investment, ownership percentage	50.00%
Maximum [Member] | Stock Options [Member]
Significant Accounting Policies [Line Items]
Stock-based compensation, vesting period	3 years
Syncrude [Member] | Minimum [Member]
Significant Accounting Policies [Line Items]
Turnarounds for major processing units	2 years
Syncrude [Member] | Maximum [Member]
Significant Accounting Policies [Line Items]
Turnarounds for major processing units	3 years
Natural Gas Processing Facilities [Member] | Minimum [Member]
Significant Accounting Policies [Line Items]
Depreciable lives, straight-line method	20 years
Natural Gas Processing Facilities [Member] | Maximum [Member]
Significant Accounting Policies [Line Items]
Depreciable lives, straight-line method	25 years
Canada [Member]
Significant Accounting Policies [Line Items]
Impairment of assets		$ 95,088,000		$ 683,574,000
[1]	Reclassified to conform to current presentation (see Note A).

Discontinued Operations and A54

Discontinued Operations and Assets Held for Sale (Major Categories of Assets and Liabilities Reflected as Held for Sale) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable	$ 243,472	$ 357,099
Total current assets held for sale	22,929	27,070
Accounts payable	595,916	784,975
Total current liabilities associated with assets held for sale	3,530	2,776
Asset retirement obligation - Seal asset	709,299	681,528
UK Refining And Marketing Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash	16,631	4,126
Accounts receivable	6,298	22,944
Total current assets held for sale	22,929	27,070
Accounts payable	837	270
Refinery decommissioning cost	2,693	2,506
Total current liabilities associated with assets held for sale	$ 3,530	2,776
Asset retirement obligation - Seal asset		$ 85,900

Discontinued Operations and A55

Discontinued Operations and Assets Held for Sale (Results of Operations Associated with Discontinued Operations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Discontinued Operations and Assets Held for Sale [Abstract]
Revenues	$ 854	$ 1,464		$ 381,747
Loss from operations before income taxes	(853)	(2,027)		(6,758)
Loss on sale before income taxes				(4,990)
Total loss from discontinued operations before taxes	(853)	(2,027)		(11,748)
Income tax expense				3,313
Loss from discontinued operations	$ (853)	$ (2,027)	[1]	$ (15,061)	[1]
[1]	Reclassified to conform to current presentation (see Note A).

Inventories (Schedule of Invent

Inventories (Schedule of Inventory) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Inventories [Abstract]
Unsold crude oil	$ 20,153	$ 17,146
Materials and supplies	84,974	109,925
Inventory, Net, Total	$ 105,127	$ 127,071

Property, Plant and Equipment57

Property, Plant and Equipment (Narrative) (Details) - USD ($)		1 Months Ended	3 Months Ended	12 Months Ended
		Jan. 31, 2017	Dec. 31, 2017	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015		Apr. 01, 2017	Dec. 31, 2014
Property Plant And Equipment [Line Items]
Proceeds from sales of property, plant and equipment				$ 69,506,000		$ 1,155,144,000		$ 423,911,000
Asset retirement obligation settled				29,111,000		20,589,000
Gain (loss) on sale of assets				127,434,000		1,663,000	[1]	154,155,000	[1]
Total capitalized exploratory well costs			$ 175,640,000	175,640,000		148,500,000		130,514,000			$ 120,455,000
Cost of acquired assets				71,100,000		225,300,000		12,600,000
Impairment of assets				0		95,088,000	[1]	2,493,156,000	[1]
Redetermination expense				15,000,000	[2]	39,100,000	[1]
Exploratory well costs capitalized more than one year			134,100,000	134,100,000
Athabasca Oil Corporation [Member]
Property Plant And Equipment [Line Items]
Cost of acquired assets, cash paid						206,700,000
Athabasca Oil Corporation [Member] | Canadian Subsidiary [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				129,000,000
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
Syncrude [Member]
Property Plant And Equipment [Line Items]
Proceeds from sales of property, plant and equipment						739,100,000
Gain (loss) on sale of assets						$ 71,700,000
Syncrude [Member] | Canadian Subsidiary [Member]
Property Plant And Equipment [Line Items]
Percentage of interest in oil and gas property sold during period						5.00%
Montney Natural Gas Fields [Member]
Property Plant And Equipment [Line Items]
Proceeds from sales of property, plant and equipment						$ 414,100,000
Gain (loss) on sale of assets				7,100,000		5,100,000
Deferred gain on sale of property			181,700,000	$ 181,700,000		187,000,000
Deferred gain, period of recognition				18 years
Kaybob Duvernay Lands, Alberta [Member] | Athabasca Oil Corporation [Member]
Property Plant And Equipment [Line Items]
Cost of acquired assets, carried interest						$ 168,000,000
Carried interest paid			$ 44,800,000	$ 44,800,000
Cost of acquired assets, interest carry period				5 years
Kaybob Duvernay Lands, Alberta [Member] | Athabasca Oil Corporation [Member] | Canadian Subsidiary [Member]
Property Plant And Equipment [Line Items]
Interest in assets acquired						70.00%
Placid Montney Lands, Alberta [Member] | Athabasca Oil Corporation [Member] | Canadian Subsidiary [Member]
Property Plant And Equipment [Line Items]
Interest in assets acquired						30.00%
Kakap Field Block K Malaysia [Member]
Property Plant And Equipment [Line Items]
Working interest			6.35%	6.35%						6.67%
Redetermination expense			$ 15,000,000			$ 39,100,000
Redetermination expense, net of tax			9,300,000			24,100,000
Malaysia [Member]
Property Plant And Equipment [Line Items]
Impairment of assets	[2]							$ 1,480,600,000
Redetermination expense	[2]			$ 15,000,000		$ 39,100,000
Exploratory well costs capitalized more than one year			20,500,000	20,500,000
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			$ 43,200,000	$ 43,200,000
[1]	Reclassified to conform to current presentation (see Note A).
[2]	Results exclude corporate overhead, interest and discontinued operations.

Property, Plant and Equipment58

Property, Plant and Equipment (Schedule of Property, Plant and Equipment) (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Property Plant And Equipment [Line Items]
Property, plant and equipment, Cost		$ 20,500,772	$ 20,924,003
Property, plant and equipment, Net		8,220,031	8,316,188
Exploration and Production [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, Cost	[1]	20,329,930	20,767,772
Property, plant and equipment, Net	[1],[2]	8,120,293	8,214,740
Corporate and Other [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, Cost		170,842	156,231
Property, plant and equipment, Net		99,738	101,448
Mineral Rights [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, Cost		600,423	595,138
Property, plant and equipment, Net		198,349	188,689
Administrative Assets and Support Equipment [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, Net		$ 38,670	$ 48,053
[1]	Includes mineral rights as follows: $600,423 198,349 595,138 188,689
[2]	Includes $38,670 in 2017 and $48,053 in 2016 related to administrative assets and support equipment.

Property, Plant and Equipment59

Property, Plant and Equipment (Schedule of Recognized Impairments) (Details) - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Property Plant And Equipment [Line Items]
Impairment Expense		$ 0	$ 95,088,000	[1]	$ 2,493,156,000	[1]
Gulf Of Mexico [Member]
Property Plant And Equipment [Line Items]
Impairment Expense					328,982,000
Canada [Member]
Property Plant And Equipment [Line Items]
Impairment Expense			95,088,000		683,574,000
Malaysia [Member]
Property Plant And Equipment [Line Items]
Impairment Expense	[2]				1,480,600,000
Conventional [Member] | Canada [Member]
Property Plant And Equipment [Line Items]
Impairment Expense	[2]		$ 95,100,000		$ 683,600,000
[1]	Reclassified to conform to current presentation (see Note A).
[2]	Results exclude corporate overhead, interest and discontinued operations.

Property, Plant And Equipment60

Property, Plant And Equipment (Net Changes in Capitalized Exploratory Well Costs) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant And Equipment [Abstract]
Beginning balance at January 1	$ 148,500	$ 130,514	$ 120,455
Additions pending the determination of proved reserves	51,488	17,986	64,578
Reclassifications to proved properties based on the determination of proved reserves	(15,988)
Capitalized exploratory well costs charged to expense	(8,360)		(54,519)
Ending balance at December 31	$ 175,640	$ 148,500	$ 130,514

Property, Plant And Equipment61

Property, Plant And Equipment (Aging of Capitalized Exploratory Well Costs) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)item	Dec. 31, 2016USD ($)item	Dec. 31, 2015USD ($)item	Dec. 31, 2014USD ($)
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 175,640	$ 148,500	$ 130,514	$ 120,455
No. of Wells	13	12	13
No. of Projects	6	6	6
Zero to One Year [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 41,480	$ 20,481	$ 66,032
No. of Wells	3	1	7
No. of Projects	2	1	6
One to Two Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 5,812	$ 63,527
No. of Wells	1	5
No. of Projects	1	5
Two to Three Years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 43,200		$ 57,876
No. of Wells	2		3
No. of Projects	2
Three Years or More [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount | $	$ 85,148	$ 64,492	$ 6,606
No. of Wells	7	6	3
No. of Projects	1

Financing Arrangements (Narrati

Financing Arrangements (Narrative) (Details) - USD ($)	Nov. 17, 2017	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Aug. 31, 2017	Aug. 31, 2016	Jul. 31, 2016
Line of Credit Facility [Line Items]
Repayments of debt				$ 550,000,000	$ 600,000,000	$ 450,000,000
Capital Lease Duration				25 years
Capital lease payment duration				15 years
Capital lease expiration date				Mar. 1, 2029
Capital lease obligations, current		$ 9,900,000		$ 9,900,000
Capital lease obligations, noncurrent		$ 134,000,000		$ 134,000,000
5.75% Notes, Due August 15, 2025 [Member]
Line of Credit Facility [Line Items]
Interest rate							5.75%
Face amount of notes							$ 550,000,000
Maturity date				Aug. 15, 2025
Transaction costs							$ 8,400,000
3.50% notes, due December 2017 [Member]
Line of Credit Facility [Line Items]
Interest rate		3.50%	3.50%	3.50%	3.50%
Repayments of debt			$ 550,000,000
6.875 Notes, Due August 15, 2024 [Member]
Line of Credit Facility [Line Items]
Interest rate								6.875%
Face amount of notes								$ 550,000,000
Maturity date				Aug. 15, 2024
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Amount outstanding		$ 90,700,000		$ 90,700,000
2016 Senior Unsecured Guaranteed Credity Facility [Member]
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity		1,100,000,000		$ 1,100,000,000				1,200,000,000
Credit facility, expiration date				Aug. 17, 2021
Amount outstanding		$ 0		$ 0
Leverage ratio	375.00%	400.00%
Interest rate				4.875%
Transaction costs								14,000,000
2011 Unscured Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity								$ 630,000,000	$ 2,000,000,000

Long term Debt (Narrative) (Det

Long term Debt (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Financing Arrangements and Long-Term Debt [Abstract]
Future maturities of long term debt in 2018	$ 9.9
Future maturities of long term debt in 2019	10.4
Future maturities of long term debt in 2020	11
Future maturities of long term debt in 2021	11.5
Future maturities of long term debt in 2022	1,110
Thereafter	$ 1,770
Capital lease duration	25 years

Long term Debt (Schedule of Lon

Long term Debt (Schedule of Long Term Debt) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017		Nov. 30, 2017	Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Notes payable		$ 2,800,000				$ 2,800,000
Unamortized discount on notes payable		(27,433)				(23,835)
Total notes payable, net of unamortized discount		2,772,567				2,776,165
Capitalized lease obligation, due through June 2029		143,855				216,402
Total debt including current maturities		2,916,422				2,992,567
Current maturities		(9,902)				(569,817)
Total long-term debt		$ 2,906,520				2,422,750
Capital lease expiration date		Mar. 1, 2029
3.50% notes, due December 2017 [Member]
Debt Instrument [Line Items]
Notes payable						$ 550,000
Interest rate		3.50%			3.50%	3.50%
Notes payable, due date		December 2,017
4.00% notes, due June 2022 [Member]
Debt Instrument [Line Items]
Notes payable		$ 500,000				$ 500,000
Interest rate		4.00%				4.00%
Notes payable, due date		June 2,022
4.45% notes, due December 2022 [Member]
Debt Instrument [Line Items]
Notes payable	[1]	$ 600,000				$ 600,000
Interest rate		4.45%	[1]	4.70%		4.45%	[1]
Notes payable, due date	[1]	December 2,022
6.875% notes, due August 15, 2024 [Member]
Debt Instrument [Line Items]
Notes payable		$ 550,000				$ 550,000
Interest rate		6.875%				6.875%
Notes payable, due date		August 2,024
5.75% notes, due August 2025 [Member]
Debt Instrument [Line Items]
Notes payable		$ 550,000
Interest rate		5.75%
Notes payable, due date		August 2,025
7.05% notes, due May 2029 [Member]
Debt Instrument [Line Items]
Notes payable		$ 250,000				$ 250,000
Interest rate		7.05%				7.05%
Notes payable, due date		May 2,029
5.875% notes, due December 2042 [Member]
Debt Instrument [Line Items]
Notes payable	[1]	$ 350,000				$ 350,000
Interest rate		5.875%	[1]	6.125%		5.875%	[1]
Notes payable, due date	[1]	December 2,042
[1]	Due to a series of ratings changes by credit agencies, the paying interest rates on the notes due December 2022 and December 2042 decreased from 4.7% to 4.45% and 6.125% to 5.875%, respectively, at December 2017.

Asset Retirement Obligations (S

Asset Retirement Obligations (Schedule of Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligations) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligations [Abstract]
Balance at beginning of year		$ 781,057	$ 825,312
Accretion expense		42,590	46,742	[1]	$ 48,665	[1]
Liabilities incurred		52,331	13,690
Revision of previous estimates		(47,612)	(4,511)
Liabilities settled		(29,111)	(20,589)
Liabilities assumed by purchaser of oil and gas assets		(87,456)	(91,883)
Changes due to translation of foreign currencies		10,340	12,296
Balance at end of year		$ 781,057	$ 825,312		$ 825,312		$ 722,139	$ 781,057
Liabilities reported as held for sale at end of year	[2]							(85,900)
Current portion of liability at end of year	[3]						(12,840)	(13,629)
Noncurrent portion of liability at end of year							$ 709,299	$ 681,528
[1]	Reclassified to conform to current presentation (see Note A).
[2]	Liabilities held for sale related to Seal properties in Canada which were sold in January 2017.
[3]	Included in Other accrued liabilities on the Consolidated Balance Sheet.

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Line Items]
Provisional tax expense			$ 274,000
Taxes receivable			$ 29,700
U.S. statutory rate			35.00%
Provisional excess foreign tax credits available			$ 120,000
Repatriation tax payable			$ 36,000
Repatriation tax payment period			8 years
Increase (decrease) in deferred tax asset valuation allowance			$ 170,900
Operating loss carryforwards			1,290,000
Deferred tax asset. operating loss carryforward			$ 272,930	$ 454,231
Operating loss carryforward, expiration date			Dec. 31, 2036
Withholding tax on amounts repatriated			5.00%
Deferred tax expense, undistributed foreign earnings			$ 65,000
Repatriated cash			1,300,000
Earnings expected to be repatriated in 2018			700,000
Estimated withholding tax payment, 2018			35,000
Non-cash income tax expense, operating loss carryforward used			188,500
Other recorded liabilities for interest and penalties	$ 200		100	300
Income tax expense (benefit) related to interest and penalties	(100)		$ (200)	$ (100)
Subsidiaries [Member]
Income Tax Disclosure [Line Items]
Dividend payable to parent company	2,000,000
Cash dividend paid to parent	800,000
Note payable, parent	1,200,000
Note payable	$ 1,200,000
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
Minimum [Member]
Income Tax Disclosure [Line Items]
Foreign tax credit carryforwards expiration year		2,018
Expected liability to be added for uncertain taxes during next twelve months			$ 1,000
Maximum [Member]
Income Tax Disclosure [Line Items]
Foreign tax credit carryforwards expiration year		2,027
Expected liability to be added for uncertain taxes during next twelve months			$ 2,000
Scenario, Plan [Member]
Income Tax Disclosure [Line Items]
U.S. statutory rate		21.00%

Income Taxes (Components of Inc

Income Taxes (Components of Income (Loss) from Continuing Operations Before Income Taxes and Income Tax Expense) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Income (loss) from continuing operations before income taxes
United States									$ (299,349)	$ (595,196)		$ (1,259,268)
Foreign									371,151	102,081		(2,022,994)
Income (loss) from continuing operations before income taxes	$ 2,400	$ (63,600)	$ (21,900)	$ 154,900	$ (80,100)	$ (16,700)	$ (131,300)	$ (265,000)	71,802	(493,115)	[1]	(3,282,262)	[1]
Income tax expense (benefit)
Federal - Current												(9,435)
Federal - Deferred									156,065	(197,450)		(241,127)
Total Federal income tax expense (benefit)									156,065	(197,450)		(250,562)
State									4,230	13,984		(5,294)
Foreign - Current									122,318	146,861		(40,550)
Foreign - Deferred									100,125	(182,567)		(730,084)
Total Foreign income tax expense (benefit)									222,443	(35,706)		(770,634)
Total income tax expense (benefit)									$ 382,738	$ (219,172)	[1]	$ (1,026,490)	[1]
[1]	Reclassified to conform to current presentation (see Note A).

Income Taxes (Effective Income

Income Taxes (Effective Income Tax Rates) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Income Tax Disclosure [Line Items]
Income tax expense (benefit) based on the U.S. statutory tax rate	$ 25,131	$ (172,590)		$ (1,148,792)
Revaluation of deferred tax (U.S. tax reform)	118,004
Deferred tax effect of deemed repatriation of foreign invested earnings (U.S. tax reform)	156,000
Deferred tax effect on Canadian earnings no longer indefinitely invested	65,000
Foreign income (loss) subject to foreign tax rates different than the U.S. statutory rate	12,658	8,582		49,739
State income taxes, net of federal benefit	2,438	9,090		(3,441)
U.S. tax benefit on certain foreign upstream investments	(32,926)	(21,336)		(16,939)
Deferred tax on distribution of foreign earnings				188,461
Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures	18,601	25,734		40,788
Other, net	17,832	18,741		(13,747)
Total income tax expense (benefit)	$ 382,738	(219,172)	[1]	(1,026,490)	[1]
Canada [Member]
Income Tax Disclosure [Line Items]
Tax effects on sale of assets		(89,473)
Malaysia [Member]
Income Tax Disclosure [Line Items]
Tax effects on sale of assets		$ 2,080		$ (122,559)
[1]	Reclassified to conform to current presentation (see Note A).

Income Taxes (Analysis of Defer

Income Taxes (Analysis of Deferred Tax Assets and Deferred Tax Liabilities Showing Tax Effects of Significant Temporary Differences) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Deferred tax assets
Property and leasehold costs	$ 488,584	$ 572,481
Liabilities for dismantlements	98,444	170,946
Postretirement and other employee benefits	134,444	214,288
Alternative minimum tax	29,710	29,710
Foreign tax credit carryforwards	228,159	33,295
U.S. net operating loss	272,930	454,231
Other deferred tax assets	13,892	16,541
Total gross deferred tax assets	1,266,163	1,491,492
Less valuation allowance	(476,256)	(305,389)
Net deferred tax assets	789,907	1,186,103
Deferred tax liabilities
Deferred tax on undistributed foreign earnings	(65,000)
Accumulated depreciation, depletion and amortization	(669,638)	(867,343)
Other deferred tax liabilities	(2,824)	(21,908)
Total gross deferred tax liabilities	(737,462)	(889,251)
Net deferred tax assets	$ 52,445	$ 296,852

Income Taxes (Reconciliation of

Income Taxes (Reconciliation of Beginning and Ending Amount of Consolidated Liability for Unrecognized Income Tax Benefits) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Taxes [Abstract]
Balance at January 1	$ 7,417	$ 6,631	$ 6,011
Additions for tax positions related to current year	769	756	821
Settlements due to lapse of time	(4,834)
Foreign currency translation effect	85	30	(201)
Balance at December 31	$ 3,437	$ 7,417	$ 6,631

Incentive Plans (Narrative) (De

Incentive Plans (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested share-based compensation arrangements, compensation costs to be expensed	$ 29,800,000
Unvested share-based compensation arrangements, number of years compensation costs to be expensed	2 years
Vesting scheme	Under these plans, one-half of each grant is generally exercisable after two years and the remainder after three years.
Total intrinsic value of options exercised	$ 0			$ 200,000
Stock options exercised		[1]	0	15,575	[1]
Related income tax benefit recognized in income	$ 5,017,000		$ 15,244,000	$ 13,583,000
Share based compensation settled in cash	12,900,000		17,200,000	1,600,000
Incentive compensation plan expense	$ 30,500,000		$ 25,800,000	$ 26,400,000
Share-based Compensation Award, Tranche One [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	2 years
Share-based Compensation Award, Tranche Two [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Option term	7 years
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%
Number of shares available	2,600,000
Employee Stock Purchase Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Salary that can be withheld by eligible employee for stock purchase	10.00%
Stock purchase price, percentage of the fair value of the stock	90.00%
Employee Stock purchase plan, termination date	The ESPP terminated June 30, 2017.
Employee stock purchases, shares	2,564		8,962	8,387
Employee stock purchases, price per share	$ 26.85		$ 23.41	$ 34.93
Compensation costs estimation	Compensation costs related to the ESPP were estimated based on the value of the 10% discount and the fair value of the option that provided for the refund of participant withholdings
Discount percentage	10.00%
Fair value per share issued under ESPP	$ 5.34		$ 2.94	$ 5.74
2012 Long-Term Plan and the 2007 Long-Term Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Option granted to date, term of years	7 years
2012 Long-Term Plan and the 2007 Long-Term Plan [Member] | Share-based Compensation Award, Tranche One [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting percentage	50.00%
Stock Options [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation, fair value assumption model	Black-Scholes option pricing model
Stock options exercised				32,349
Stock Options [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	2 years
Stock Options [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Employee Stock Options [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock options exercised	0		0
Related income tax benefit recognized in income	$ 0		$ 0
Time-Lapse Restricted Stock and Restricted Stock Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per share at grant date	$ 28.51		$ 17.57	$ 49.67
Performance Based Restricted Stock [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Stock-based compensation, fair value assumption model	Monte Carlo valuation model
Performance Based Restricted Stock [Member] | Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per share at grant date	$ 24.10		12.21	44.03
Performance Based Restricted Stock [Member] | Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per share at grant date	$ 28.28		$ 16.34	$ 48.12
[1]	Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note J due to withholdings for statutory income taxes owed upon issuance of shares.

Incentive Plans (Share-Based Pl

Incentive Plans (Share-Based Plans, Amounts Recognized) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Incentive Plans [Abstract]
Compensation charged against income (loss) before tax benefit	$ 40,365	$ 46,300	$ 44,021
Related income tax benefit recognized in income	$ 5,017	$ 15,244	$ 13,583

Incentive Plans (Fair Value of

Incentive Plans (Fair Value of Option Award Estimated on Date of Grant using Black-Scholes Pricing Model) (Details) - Stock Options [Member] - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per option grant	$ 7.96	$ 5.03
Assumptions
Dividend yield	3.60%	4.00%
Expected volatility	41.00%	45.00%
Risk-free interest rate	1.97%	1.32%
Expected life	5 years 3 months 18 days	5 years 2 months 12 days	5 years 3 months 18 days
Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per option grant			$ 10.97
Assumptions
Dividend yield			2.40%
Expected volatility			29.00%
Risk-free interest rate			1.34%
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per option grant			$ 11.08
Assumptions
Dividend yield			2.50%
Expected volatility			30.00%
Risk-free interest rate			1.60%

Incentive Plans (Changes in Sto

Incentive Plans (Changes in Stock Options Outstanding) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Number of Shares
Exercised		[1]	0	(15,575)	[1]
Outstanding at end of year	4,901,269
Exercisable at end of year	3,197,269
Stock Options [Member]
Number of Shares
Outstanding at beginning of year	5,757,435		5,443,288	5,602,250
Granted at FMV	603,000		862,000	991,000
Exercised				(32,349)
Forfeited	(1,459,166)		(547,853)	(1,117,613)
Outstanding at end of year	4,901,269		5,757,435	5,443,288
Exercisable at end of year	3,197,269		3,830,535	3,542,352		3,030,105
Average Exercise Price
Outstanding at beginning of year	$ 48.46		$ 52.93	$ 57.95
Granted at FMV	28.51		17.57	49.67
Exercised				40.80
Forfeited	49.34		44.23	31.99
Exercisable at end of year	54.22		53.80	52.26		$ 53.10
Outstanding at end of year	$ 45.74		$ 48.46	$ 52.93
[1]	Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note J due to withholdings for statutory income taxes owed upon issuance of shares.

Incentive Plans (Additional Inf

Incentive Plans (Additional Information about Stock Options Outstanding) (Details)	12 Months Ended
	Dec. 31, 2017USD ($)$ / sharesshares
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options Outstanding, No. of Options	4,901,269
Options Outstanding, Avg. Life Remaining in Years	3 years
Options Outstanding, Aggregate Intrinsic Value | $	$ 11,652,680
Options Exercisable, No. of Options	3,197,269
Options Exercisable, Avg. Life Remaining in Years	1 year 10 months 24 days
Range of Exercise Prices per Option, $17.00 to $30.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices per option, lower limit | $ / shares	$ 17
Range of exercise prices per option, upper limit | $ / shares	$ 30
Options Outstanding, No. of Options	1,320,000
Options Outstanding, Avg. Life Remaining in Years	5 years 6 months
Options Outstanding, Aggregate Intrinsic Value | $	$ 11,652,680
Options Exercisable, Avg. Life Remaining in Years	0 years
Range of Exercise Prices per Option, $31.00 to $50.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices per option, lower limit | $ / shares	$ 31
Range of exercise prices per option, upper limit | $ / shares	$ 50
Options Outstanding, No. of Options	823,350
Options Outstanding, Avg. Life Remaining in Years	3 years 10 months 24 days
Options Exercisable, No. of Options	439,350
Options Exercisable, Avg. Life Remaining in Years	3 years 9 months 18 days
Range of Exercise Prices per Option, $51.00 to $65.00 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices per option, lower limit | $ / shares	$ 51
Range of exercise prices per option, upper limit | $ / shares	$ 65
Options Outstanding, No. of Options	2,757,919
Options Outstanding, Avg. Life Remaining in Years	1 year 7 months 6 days
Options Exercisable, No. of Options	2,757,919
Options Exercisable, Avg. Life Remaining in Years	1 year 7 months 6 days

Incentive Plans (Changes in Per

Incentive Plans (Changes in Performance-Based RSU Outstanding) (Details) - Equity-Settled Restricted Stock Units [Member] - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at beginning of year	992,573	1,103,986	1,397,040
Granted	560,000	394,000	455,000
Awarded	(272,725)	(361,096)	(521,800)
Forfeited	(91,927)	(144,317)	(226,254)
Outstanding at end of year	1,187,921	992,573	1,103,986

Incentive Plans (Assumptions us

Incentive Plans (Assumptions used in Valuation Performance Awards Granted) (Details) - Performance Based Restricted Stock [Member]	12 Months Ended
	Dec. 31, 2017item$ / shares	Dec. 31, 2016item$ / shares	Dec. 31, 2015item$ / shares
Assumptions
Expected volatility	47.00%	33.00%	26.00%
Risk-free interest rate	1.46%	0.93%	0.85%
Stock beta | item	1.058	0.863	0.813
Expected life	3 years	3 years	3 years
Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per share at grant date	$ 24.10	$ 12.21	$ 44.03
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Fair value per share at grant date	$ 28.28	$ 16.34	$ 48.12

Incentive Plans (Changes in Tim

Incentive Plans (Changes in Time-Lapse Restricted Stock and Restricted Stock Units Outstanding) (Details) - Restricted Stock and Restricted Stock Units [Member] - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding at beginning of year	923,282	477,244	321,789
Granted	419,720	503,555	282,065
Vested and issued	(217,633)	(32,092)	(69,610)
Forfeited	(89,389)	(25,425)	(57,000)
Outstanding at end of year	1,035,980	923,282	477,244

Employee and Retiree Benefit 79

Employee and Retiree Benefit Plans (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended			120 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Future annual rate of increase in cost of health care for 2016 to measure postretirement benefit obligations	6.70%			6.70%
Ultimate rate of health care cost in 2028 and thereafter	4.50%			4.50%
Plan asset, maximum investment in any one issuer	10.00%			10.00%
Equity securities minimum market capitalization	$ 100,000			$ 100,000
Fixed income portfolio, maximum average maturity years	11 years
Weighted average expected return on plan asset	5.64%
Basis used to determine expected return on plan asset, average expected investment expenses	0.60%
Perentage return on plan assets				6.66%
Defined benefit plan, percentage of employer's matching contribution	6.00%
Thrift plan expense	$ 7,800	$ 7,400	$ 7,600
Investment 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Domestic plan, investment notice period	90 days
Investment 3 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Domestic plan, investment lock up period	2 years
Domestic plan, investment notice period	95 days
Defined Benefit Plan, Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted average expected return on plan asset	7.15%
Defined Benefit Plan, Equity Securities [Member] | Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	40.00%			40.00%
Defined Benefit Plan, Equity Securities [Member] | Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	70.00%			70.00%
Defined Benefit Plan, Fixed Income Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted average expected return on plan asset	4.26%
Defined Benefit Plan, Fixed Income Securities [Member] | Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	30.00%			30.00%
Defined Benefit Plan, Fixed Income Securities [Member] | Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	60.00%			60.00%
Defined Benefit Plan, Long/Short Equity [Member] | Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	0.00%			0.00%
Defined Benefit Plan, Long/Short Equity [Member] | Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	15.00%			15.00%
Defined Benefit Plan, Cash And Equivalents [Member] | Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	0.00%			0.00%
Defined Benefit Plan, Cash And Equivalents [Member] | Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	15.00%			15.00%
Defined Benefit Plan, Equity Securities, Emerging Market Commingled Equity Fund [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Domestic plan, investment notice period	10 days
Canada [Member] | Defined Benefit Plan, Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	60.00%			60.00%
Canada [Member] | Defined Benefit Plan, Equity Securities [Member] | Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	55.00%			55.00%
Canada [Member] | Defined Benefit Plan, Equity Securities [Member] | Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	65.00%			65.00%
Canada [Member] | Defined Benefit Plan, Fixed Income Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	35.00%			35.00%
Canada [Member] | Defined Benefit Plan, Fixed Income Securities [Member] | Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	30.00%			30.00%
Canada [Member] | Defined Benefit Plan, Fixed Income Securities [Member] | Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	40.00%			40.00%
Canada [Member] | Defined Benefit Plan, Cash [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	5.00%			5.00%
Canada [Member] | Defined Benefit Plan, Cash [Member] | Minimum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	0.00%			0.00%
Canada [Member] | Defined Benefit Plan, Cash [Member] | Maximum [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	10.00%			10.00%
United Kingdom [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target interest and inflation rate hedge ratio	100.00%
United Kingdom [Member] | Defined Benefit Plan, Equity Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	60.00%			60.00%
United Kingdom [Member] | Defined Benefit Plan, Fixed Income Securities [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target allocations of plan assets	40.00%			40.00%
Pension Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	$ 24,918	$ 8,186
Weighted average expected return on plan asset	5.64%	5.62%
Pension Benefits [Member] | United States [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	$ 18,000
Expected benefit plan contributions to be made during next year	24,400			$ 24,400
Pension Benefits [Member] | Foreign Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	6,900
Expected benefit plan contributions to be made during next year	600			600
Other Postretirement Benefits [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	2,417	$ 3,581
Other Postretirement Benefits [Member] | United States [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to benefit plans	2,400
Expected benefit plan contributions to be made during next year	$ 5,400			$ 5,400

Employee and Retiree Benefit 80

Employee and Retiree Benefit Plans (Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016
Change in plan assets
Total beginning balance	$ 519,357
Total ending balance	563,825	$ 519,357
Pension Benefits [Member]
Change in benefit obligation
Obligation at January 1	881,932	815,593	$ 794,589	$ 881,932	$ 815,593
Service cost	8,279	8,136	17,948
Interest cost	27,047	25,185	33,168
Participant contributions
Actuarial loss (gain)	60,855	58,236
Medicare Part D subsidy
Exchange rate changes	18,751	(30,447)
Benefits paid	39,910	40,928
Curtailments		822
Other	(8,683)
Obligation at December 31	881,932	815,593	794,589
Change in plan assets
Total beginning balance	519,357	521,682
Actual return on plan assets	50,079	61,860
Employer contributions	24,918	8,186
Participant contributions
Medicare Part D subsidy
Exchange rate changes	18,064	(30,609)
Benefits paid	(39,910)	(40,928)
Other				(8,683)	(834)
Total ending balance	563,825	519,357	521,682
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets				5,905	7,591
Other accrued liabilities				(8,856)	(8,184)
Deferred credits and other liabilities				(315,156)	(295,643)
Funded status and net plan liability recognized at December 31				(318,107)	(296,236)
Other Postretirement Benefits [Member]
Change in benefit obligation
Obligation at January 1	106,276	106,679	115,222	106,276	106,679
Service cost	1,601	1,864	3,180
Interest cost	3,444	3,800	4,883
Participant contributions	2,075	1,278
Actuarial loss (gain)	(3,077)	(10,627)
Medicare Part D subsidy	318	510
Exchange rate changes	46	20
Benefits paid	4,810	5,369
Curtailments		(19)
Other
Obligation at December 31	106,276	106,679	115,222
Change in plan assets
Total beginning balance
Actual return on plan assets
Employer contributions	2,417	3,581
Participant contributions	2,075	1,278
Medicare Part D subsidy	318	510
Exchange rate changes
Benefits paid	(4,810)	(5,369)
Other
Total ending balance
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets
Other accrued liabilities				(5,392)	(5,267)
Deferred credits and other liabilities				(100,884)	(101,412)
Funded status and net plan liability recognized at December 31				$ (106,276)	$ (106,679)

Employee and Retiree Benefit 81

Employee and Retiree Benefit Plans (Amounts Included in Accumulated Other Comprehensive Income Not Recognized in Net Periodic Benefit Expense) (Details) $ in Thousands	Dec. 31, 2017USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ (269,063)
Prior service (cost) credit	(5,824)
Amounts included in accumulated other comprehensive loss which have not been recognized in net periodic benefit expense	(274,887)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	221
Prior service (cost) credit	38
Amounts included in accumulated other comprehensive loss which have not been recognized in net periodic benefit expense	$ 259

Employee and Retiree Benefit 82

Employee and Retiree Benefit Plans (Amounts Included in Accumulated Other Comprehensive Income Expected to be Amortized into Net Periodic Benefit Expense) (Details) $ in Thousands	Dec. 31, 2017USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	$ (15,890)
Prior service (cost) credit	(1,021)
Amounts included in accumulated other comprehensive loss expected to be amortized into net periodic benefit expense	(16,911)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service (cost) credit	38
Amounts included in accumulated other comprehensive loss expected to be amortized into net periodic benefit expense	$ 38

Employee and Retiree Benefit 83

Employee and Retiree Benefit Plans (Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Funded Plan [Member] | Qualified Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	$ 691,923	$ 643,174
Accumulated Benefit Obligations	640,230	599,730
Fair Value of Plan Assets	540,161	497,894
Unfunded Plan [Member] | Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	106,276	106,678
Accumulated Benefit Obligations	106,276	106,678
Unfunded Plan [Member] | Nonqualified Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligations	172,364	156,088
Accumulated Benefit Obligations	$ 163,319	$ 150,780

Employee and Retiree Benefit 84

Employee and Retiree Benefit Plans (Components of Net Periodic Benefit Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 8,279	$ 8,136	$ 17,948
Interest cost	27,047	25,185	33,168
Expected return on plan assets	(28,941)	(28,154)	(34,016)
Amortization of prior service cost (credit)	1,026	1,204	1,560
Amortization of transitional (asset) liability			(1)
Recognized actuarial loss	16,691	16,165	15,147
Gross periodic benefit expense	24,102	22,536	33,806
Termination benefits expense			8,606
Curtailment expense		822	306
Net periodic benefit expense	24,102	23,358	42,718
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1,601	1,864	3,180
Interest cost	3,444	3,800	4,883
Amortization of prior service cost (credit)	(74)	(75)	(82)
Recognized actuarial loss		5	992
Gross periodic benefit expense	4,971	5,594	8,973
Curtailment expense		(19)
Net periodic benefit expense	$ 4,971	$ 5,575	$ 8,973

Employee and Retiree Benefit 85

Employee and Retiree Benefit Plans (Amount Related to Foreign Benefit Plans) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at December 31	$ 563,825	$ 519,357
Foreign Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at December 31	212,533	197,575
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	881,932	815,593	$ 794,589
Fair value of plan assets at December 31	563,825	519,357	521,682
Net plan liabilities recognized	(318,107)	(296,236)
Net periodic benefit expense (benefit)	24,102	23,358	42,718
Pension Benefits [Member] | Foreign Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	222,483	206,502
Fair value of plan assets at December 31	212,535	197,575
Net plan liabilities recognized	9,948	8,927
Net periodic benefit expense (benefit)	194	(2,244)
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	106,276	106,679	115,222
Fair value of plan assets at December 31
Net plan liabilities recognized	(106,276)	(106,679)
Net periodic benefit expense (benefit)	4,971	5,575	$ 8,973
Other Postretirement Benefits [Member] | Foreign Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation at December 31	791	615
Net plan liabilities recognized	791	615
Net periodic benefit expense (benefit)	$ 133	$ 154

Employee and Retiree Benefit 86

Employee and Retiree Benefit Plans (Weighted-Average Assumptions used in Measurement of Benefit Obligations and Net Periodic Benefit Expense) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligations, Expected return on plan assets	5.64%
Net Periodic Benefit Expense, Expected return on plan assets	5.64%
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligations, Discount rate	3.42%	3.94%
Benefit Obligations, Expected return on plan assets	5.64%	5.62%
Benefit Obligation, Rate of compensation increase	3.52%	3.52%
Net Periodic Benefit Expense, Discount rate	3.66%	3.84%
Net Periodic Benefit Expense, Expected return on plan assets	5.64%	5.62%
Net Periodic Benefit Expense, Rate of compensation increase	3.52%	3.52%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligations, Discount rate	3.73%	4.41%
Net Periodic Benefit Expense, Discount rate	4.33%	4.24%

Employee and Retiree Benefit 87

Employee and Retiree Benefit Plans (Benefit Payments, Reflected Expected Future Service as Appropriate which are Expected to be Paid in Future Years from Assets of Plans or by Company) (Details) $ in Thousands	Dec. 31, 2017USD ($)
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2,018	$ 39,929
2,019	40,236
2,020	41,220
2,021	42,276
2,022	43,554
2023-2027	227,039
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2,018	6,259
2,019	6,280
2,020	6,357
2,021	6,489
2,022	6,560
2023-2027	$ 33,971

Employee and Retiree Benefit 88

Employee and Retiree Benefit Plans (One Percent Change in Assumed Health Care Cost Trend Rates) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Employee and Retiree Benefit Plans [Abstract]
1% Increase, Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2017	$ 919
1% Increase, Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2017	15,220
1% Decrease, Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2017	(719)
1% Decrease, Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2017	$ (12,277)

Employee and Retiree Benefit 89

Employee and Retiree Benefit Plans (Weighted Average Asset Allocation for Funded Pension Benefit Plans) (Details)	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	100.00%	100.00%
Defined Benefit Plan, Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	60.30%	58.40%
Defined Benefit Plan, Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	37.20%	39.00%
Defined Benefit Plan, Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	2.50%	2.60%

Employee and Retiree Benefit 90

Employee and Retiree Benefit Plans (Fair Value Measurements of Retirement Plan Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	$ 563,825	$ 519,357
Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	97,758	92,478
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	428,117	392,765
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	37,950	34,114
United States [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	351,292	321,782
United States [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	97,758	92,478
United States [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	215,584	195,190
United States [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	37,950	34,114
United States [Member] | Defined Benefit Plan, Equity Securities, US Core [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	67,343	61,554
United States [Member] | Defined Benefit Plan, Equity Securities, US Core [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	67,343	61,554
United States [Member] | Defined Benefit Plan, Equity Securities, US Small/Midcap [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	24,544	23,103
United States [Member] | Defined Benefit Plan, Equity Securities, US Small/Midcap [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	24,544	23,103
United States [Member] | Defined Benefit Plan, Equity Securities, Hedged Funds And Other Alternative Strategies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	50,522	48,113
United States [Member] | Defined Benefit Plan, Equity Securities, Hedged Funds And Other Alternative Strategies [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	12,572	13,999
United States [Member] | Defined Benefit Plan, Equity Securities, Hedged Funds And Other Alternative Strategies [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	37,950	34,114
United States [Member] | Defined Benefit Plan, Equity Securities, International Commingled Trust Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	83,960	67,451
United States [Member] | Defined Benefit Plan, Equity Securities, International Commingled Trust Fund [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	83,960	67,451
United States [Member] | Defined Benefit Plan, Equity Securities, Emerging Market Commingled Equity Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	20,774	16,006
United States [Member] | Defined Benefit Plan, Equity Securities, Emerging Market Commingled Equity Fund [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	20,774	16,006
United States [Member] | Defined Benefit Plan, Fixed Income Securities, US Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	79,890	78,473
United States [Member] | Defined Benefit Plan, Fixed Income Securities, US Fixed Income [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	79,890	78,473
United States [Member] | Defined Benefit Plan, Fixed Income Securities, International Commingled Trust Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	13,122	13,486
United States [Member] | Defined Benefit Plan, Fixed Income Securities, International Commingled Trust Fund [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	13,122	13,486
United States [Member] | Defined Benefit Plan, Fixed Income Securities, Emerging Market Mutual Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	5,266	5,775
United States [Member] | Defined Benefit Plan, Fixed Income Securities, Emerging Market Mutual Fund [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	5,266	5,775
United States [Member] | Defined Benefit Plan, Cash And Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	5,871	7,821
United States [Member] | Defined Benefit Plan, Cash And Equivalents [Member] | Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	5,871	7,821
Foreign Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	212,533	197,575
Foreign Plans [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	212,533	197,575
Foreign Plans [Member] | Defined Benefit Plan, Cash And Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	6,888	4,929
Foreign Plans [Member] | Defined Benefit Plan, Cash And Equivalents [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	6,888	4,929
Foreign Plans [Member] | Defined Benefit Plan, Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	78,666	74,108
Foreign Plans [Member] | Defined Benefit Plan, Equity Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	78,666	74,108
Foreign Plans [Member] | Defined Benefit Plan, Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	103,314	97,075
Foreign Plans [Member] | Defined Benefit Plan, Fixed Income Securities [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	103,314	97,075
Foreign Plans [Member] | Defined Benefit Plan, Diversified Pooled Fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	23,665	21,463
Foreign Plans [Member] | Defined Benefit Plan, Diversified Pooled Fund [Member] | Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	$ 23,665	$ 21,463

Employee and Retiree Benefit 91

Employee and Retiree Benefit Plans (Effects of Fair Value Measurements Using Significant Unobservable Inputs on Changes in Level 3 Plan Assets) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Total beginning balance	$ 519,357
Total ending balance	563,825	$ 519,357
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total beginning balance	34,114
Total ending balance	37,950	34,114
Defined Benefit Plan, Hedged Funds And Other Alternative Strategies [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Total beginning balance	34,114	33,929
Relating to assets held at the reporting date	3,836	185
Relating to assets sold during the period
Purchases, sales and settlements
Total ending balance	$ 37,950	$ 34,114

Financial Instruments and Ris92

Financial Instruments and Risk Management (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018bbl / d$ / bbl	Dec. 31, 2017USD ($)bbl / d	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Amount of loss reclassified to interest expense		$ 2,963	$ 2,963	$ 3,000
Amount of loss expected to be reclassified to interest expense in the next 12 months		3,000
Loss deferred for fair value of interest rate derivative contracts, net of tax		8,400
Income taxes on deferred loss on fair value of interest rate derivative contracts		$ 4,500
Commodity Derivative Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Daily production commitment (barrels per day) | bbl / d		22,000
Fair value of derivative contract liability		$ 39,100	48,900
Increase (decrease) of income before taxes due to the impact of marking to market of derivative contracts		$ (34,000)	(47,700)
Commodity Derivative Contracts [Member] | Scenario, Forecast [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Daily production commitment (barrels per day) | bbl / d	21,000
Average price | $ / bbl	54.88
Foreign Exchange Derivative Contracts [Member] | Currency, U.S. Dollar [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Short-term derivative instruments			$ 14,200

Financial Instruments and Ris93

Financial Instruments and Risk Management (Fair Value of Derivative Instruments Not Designated as Hedging Instruments) (Details) - Nondesignated [Member] - Accounts Payable [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Commodity Derivative Contracts [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ (39,093)	$ (48,864)
Foreign Exchange Derivative Contracts [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives		$ (73)

Financial Instruments and Ris94

Financial Instruments and Risk Management (Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments) (Details) - Nondesignated [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ 9,567	$ (36,698)
Commodity Derivative Contracts [Member] | Sales And Other Operating Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ 9,567	(63,412)
Foreign Exchange Derivative Contracts [Member] | Interest And Other Income [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)		$ 26,714

Stockholders' Equity (Summary O

Stockholders' Equity (Summary Of Shares Repurchased) (Details)	12 Months Ended
	Dec. 31, 2017itemshares	Dec. 31, 2016shares	Dec. 31, 2015USD ($)shares
Stockholders' Equity and Common Stock Issued and Outstanding [Abstract]
Purchase of Treasury Stock | $			$ 250,000,000
Shares repurchased | shares	0	0	5,967,313
Number of open share buyback programs | item	0

Earnings per Share (Weighted-Av

Earnings per Share (Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share) (Details) - shares		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Earnings per Share [Abstract]
Basic method		172,524,061	172,173,012	[1]	174,351,227	[1]
Dilutive stock options	[2]
Diluted method		172,524,061	172,173,012	[1]	174,351,227	[1]
[1]	Reclassified to conform to current presentation (see Note A).
[2]	Due to a net loss recognized by the Company for the years ended December 31, 2017, 2016 and 2015, no unvested stock awards were included in the computation of diluted earnings per share because the effect would have been antidilutive.

Earnings per Share (Anti Diluti

Earnings per Share (Anti Dilutive Securities Not Included in Computation of Diluted EPS) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings per Share [Abstract]
Antidilutive stock options excluded from diluted shares (in shares)	4,901,269	5,757,435	5,443,288
Weighted average price of these options (per share)	$ 45.74	$ 48.46	$ 52.93

Other Financial Information (Na

Other Financial Information (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)item
Other Financial Information [Line Items]
Net gains (losses) from foreign currency transactions	$ (75.4)	$ 59.7	$ 87.9
Deepwater rig contract exit costs			$ 282
Payment of contract exit costs	266.7
Write down of accrued contract exit costs	$ 6.1	$ 4.3
Gulf Of Mexico [Member]
Other Financial Information [Line Items]
Number of deepwater drilling rigs | item			2

Other Financial Information (No

Other Financial Information (Noncash Opearting Working Capital Increase (Decrease)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Financial Information [Abstract]
Accounts receivable	$ 114,401	$ 119,671	$ 297,625
Inventories	26,883	(5,171)	(15,340)
Prepaid expenses	29,570	149,946	(144,845)
Deferred income tax assets			3,924
Accounts payable and accrued liabilities	(51,439)	(328,078)	(36,887)
Current income tax liabilities	16,999	24,943	(69,413)
Net (increase) decrease in noncash operating working capital	136,414	(38,689)	35,064
Cash income taxes paid, net of refunds	68,076	6,707	118,667
Interest paid, net of amounts capitalized	147,975	127,798	110,386
Asset retirement costs capitalized	8,509	13,690	76,775
Decrease in capital expenditure accrual	99,199	158,885	462,474
Interest paid, amounts capitalized	$ 4,488	$ 4,322	$ 7,290

Accumulated Other Comprehens100

Accumulated Other Comprehensive Loss (Components of Accumulated Other Comprehensive Loss) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		$ (628,212)	$ (704,542)
Before reclassifications to income		154,456	62,686
Reclassifications to income		11,513	13,644
Net other comprehensive income (loss)		165,969	76,330	$ (534,287)
Ending Balance		(462,243)	(628,212)	(704,542)
Reclassifications before taxes, included in net periodic benefit expense		18,036	14,821
Reclassifications, income tax expense		6,318	5,234
Amount of loss reclassified to interest expense		2,963	2,963	3,000
Reclassifications income tax, included in interest expense		1,037	1,037
Foreign Currency Translation Gains (Losses) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(446,555)	(513,004)
Before reclassifications to income		171,725	66,449
Reclassifications to income
Net other comprehensive income (loss)		171,725	66,449
Ending Balance		(274,830)	(446,555)	(513,004)
Retirement and Postretirement Benefit Plan Adjustments [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(171,305)	(179,260)
Before reclassifications to income		(17,269)	(3,763)
Reclassifications to income	[1]	9,587	11,718
Net other comprehensive income (loss)		(7,682)	7,955
Ending Balance		(178,987)	(171,305)	(179,260)
Deferred Loss On Interest Rate Derivative Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance		(10,352)	(12,278)
Before reclassifications to income
Reclassifications to income	[2]	1,926	1,926
Net other comprehensive income (loss)		1,926	1,926
Ending Balance		$ (8,426)	$ (10,352)	$ (12,278)
[1]	Reclassifications before taxes of $14,821 and $18,036 are included in the computation of net periodic benefit expense in 2017 and 2016, respectively. See Note K for additional information. Related income taxes of $5,234 and $6,318 are included in income tax expense in 2017 and 2016, respectively.
[2]	Reclassifications before taxes of $2,963 are included in Interest expense in both 2017 and 2016. Related income taxes of $1,037 are included in income tax expense in 2017 and 2016. See Note L for additional information.

Assets and Liabilities Measu101

Assets and Liabilities Measured at Fair Value (Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis) (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, Nonqualified employee savings plans	$ 16,158	$ 13,904
Liabilities, Commodity derivative contracts	39,093	48,864
Liabilities, Foreign currency exchange derivative contracts		73
Liabilities, Total	55,251	62,841
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, Nonqualified employee savings plans	16,158	13,904
Liabilities, Total	16,158	13,904
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, Commodity derivative contracts	39,093	48,864
Liabilities, Foreign currency exchange derivative contracts		73
Liabilities, Total	$ 39,093	$ 48,937

Assets and Liabilities Measu102

Assets and Liabilities Measured at Fair Value (Carrying Amounts and Estimated Fair Values of Financial Instruments) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Financial assets (liabilities), Carrying value
Canadian government securities with maturities greater than 90 days at the date of acquisition		$ 111,542
Current and long-term debt	$ (2,916,422)	(2,992,567)
Financial assets (liabilities), Fair value
Canadian government securities with maturities greater than 90 days at the date of acquisition		111,331
Current and long-term debt	$ (2,993,003)	$ (2,951,992)

Assets and Liabilities Measu103

Assets and Liabilities Measured at Fair Value (Nonrecurring Fair Value Measurements) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015	[1]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Book Value Prior to Impairment		$ 167,055,000
Total Pretax (Noncash) Impairment Expense	$ 0	95,088,000	[1]	$ 2,493,156,000
Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets: Impaired proved properties		71,967,000
Western Canada [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net Book Value Prior to Impairment		167,055,000
Total Pretax (Noncash) Impairment Expense		95,088,000
Western Canada [Member] | Level 3 [Member] | Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets: Impaired proved properties		$ 71,967,000
[1]	Reclassified to conform to current presentation (see Note A).

Commitments (Narrative) (Detail

Commitments (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Line Items]
Operating lease rental payments due in 2018	$ 73.7
Operating lease rental payments due in 2019	65.6
Operating lease rental payments due in 2020	62.4
Operating lease rental payments due in 2021	61.3
Operating lease rental payments due in 2022	27.8
Rental expenses for non-cancellable lease, including contingent payments	72.6	$ 77.5	$ 111.4
Commitments for capital expenditures	432.3
Malaysia [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	197.3
Kaybob Duvernay Lands, Alberta [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	129.4
Eagle Ford Shale [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	31.8
Mexico [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	31.3
Gulf Of Mexico [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	$ 24
Rig contract cancellation period	30 days
Vietnam [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	$ 8.8
Brunei [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	6.3
Drilling Rigs And Associated Equipment [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	66.6
Processing Production Handling and Transportation Services [Member]
Commitments and Contingencies Disclosure [Line Items]
Operating lease rental payments due in 2018	57.8
Operating lease rental payments due in 2019	63.8
Operating lease rental payments due in 2020	77.9
Operating lease rental payments due in 2021	91.9
Operating lease rental payments due in 2022	78.5
Processing and transportation charges	$ 53.8	$ 50.3	$ 32.5

Contingencies (Narrative) (Deta

Contingencies (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Scenario, Forecast [Member]
Contingencies Disclosure [Line Items]
Proceeds from insurance settlement	$ 15
Canada [Member]
Contingencies Disclosure [Line Items]
Remediation costs		$ 43.9
Payments for environmental liabilities		$ 39.7

Common Stock Issued and Outs106

Common Stock Issued and Outstanding (Activity in the Number of Common Stock Shares Issued and Outstanding) (Details) - shares		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016	Dec. 31, 2015
Stockholders' Equity and Common Stock Issued and Outstanding [Abstract]
At beginning of year		172,202,177		172,034,711	177,499,513
Stock options exercised			[1]	0	15,575	[1]
Restricted stock awards	[1]	368,132		158,504	478,549
Employee stock purchase and thrift plans		2,564		8,962	8,387
Treasury shares purchased					(5,967,313)
At end of year		172,572,873		172,202,177	172,034,711
[1]	Shares issued upon exercise of stock options and award of restricted stock are less than the amount reflected in Note J due to withholdings for statutory income taxes owed upon issuance of shares.

Business Segments (Narrative) (

Business Segments (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Sales Revenue [Member] | Phillips 66 and Affiliated Companies [Member]
Segment Reporting Information [Line Items]
Concentration risk	14.00%	17.00%	17.00%

Business Segments (Segment Info

Business Segments (Segment Information) (Details) - USD ($)		3 Months Ended								12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Revenues From External Customers And Long Lived Assets [Line Items]
Net income (loss)		$ (286,800,000)	$ (65,900,000)	$ (17,600,000)	$ 58,500,000	$ (63,900,000)	$ (16,200,000)	$ 2,900,000	$ (198,800,000)	$ (311,789,000)		$ (275,970,000)	[1]	$ (2,270,833,000)	[1]
Revenues from external customers										2,225,129,000		1,811,238,000	[1]	2,941,271,000	[1]
Interest expense, net of capitalization										181,783,000		148,170,000	[1]	117,375,000	[1]
Income tax expense (benefit)										382,738,000		(219,172,000)	[1]	(1,026,490,000)	[1]
Depreciation, depletion and amortization										957,719,000		1,054,081,000	[1]	1,619,824,000	[1]
Accretion of asset retirement obligations										42,590,000		46,742,000	[1]	48,665,000	[1]
Amortization of undeveloped leases										61,776,000		43,417,000		75,312,000
Impairment of assets										0		95,088,000	[1]	2,493,156,000	[1]
Total assets at year end		9,860,942,000				10,295,860,000				9,860,942,000		10,295,860,000
United States [Member]
Revenues From External Customers And Long Lived Assets [Line Items]
Revenues from external customers										958,300,000		692,300,000		1,260,200,000
Impairment of assets	[2]													329,000,000
Canada [Member]
Revenues From External Customers And Long Lived Assets [Line Items]
Revenues from external customers										485,700,000		365,300,000		549,700,000
Impairment of assets												95,088,000		683,574,000
Malaysia [Member]
Revenues From External Customers And Long Lived Assets [Line Items]
Revenues from external customers										781,100,000		753,400,000		1,131,400,000
Impairment of assets	[2]													1,480,600,000
Other [Member]
Revenues From External Customers And Long Lived Assets [Line Items]
Revenues from external customers												200,000
Discontinued Operations [Member]
Revenues From External Customers And Long Lived Assets [Line Items]
Net income (loss)										(900,000)		(2,000,000)		(15,000,000)
Total assets at year end		22,900,000				27,100,000				22,900,000		27,100,000		38,300,000
Operating Segments [Member]
Revenues From External Customers And Long Lived Assets [Line Items]
Net income (loss)										(311,800,000)		(276,000,000)		(2,270,800,000)
Revenues from external customers										2,225,100,000		1,811,200,000		2,941,300,000
Interest income										7,400,000		2,900,000		4,000,000
Interest expense, net of capitalization										181,800,000		148,200,000		117,400,000
Income tax expense (benefit)										382,700,000		(219,200,000)		(1,026,500,000)
Depreciation, depletion and amortization										957,700,000		1,054,100,000		1,619,800,000
Accretion of asset retirement obligations										42,600,000		46,700,000		48,700,000
Amortization of undeveloped leases										61,800,000		43,400,000		75,400,000
Impairment of assets												95,100,000		2,493,200,000
Deferred and noncurrent income taxes										260,400,000		(387,800,000)		(978,000,000)
Additions to property, plant, equipment										870,800,000		753,100,000		1,791,500,000
Total assets at year end		9,860,900,000				10,295,900,000				9,860,900,000		10,295,900,000		11,493,800,000
Exploration and production [Member]
Revenues From External Customers And Long Lived Assets [Line Items]
Net income (loss)										296,600,000		(124,900,000)		(2,010,900,000)
Revenues from external customers										2,220,500,000	[3]	1,804,600,000		2,934,700,000
Interest income
Interest expense, net of capitalization
Income tax expense (benefit)										137,100,000		(155,100,000)		(1,111,000,000)
Depreciation, depletion and amortization										939,900,000		1,037,300,000		1,607,900,000
Accretion of asset retirement obligations										42,600,000		46,700,000		48,700,000
Amortization of undeveloped leases										61,800,000		43,400,000		75,400,000
Impairment of assets												95,100,000		2,493,200,000
Deferred and noncurrent income taxes										17,900,000		(311,000,000)		(917,500,000)
Additions to property, plant, equipment										856,000,000		731,200,000		1,731,600,000
Total assets at year end		8,736,300,000				9,118,900,000				8,736,300,000		9,118,900,000		10,863,300,000
Exploration and production [Member] | United States [Member]
Revenues From External Customers And Long Lived Assets [Line Items]
Net income (loss)										(2,600,000)		(205,400,000)		(615,700,000)
Revenues from external customers										953,900,000	[3]	685,700,000		1,253,600,000
Interest income
Interest expense, net of capitalization
Income tax expense (benefit)										2,500,000		(87,900,000)		(337,000,000)
Depreciation, depletion and amortization										546,100,000		600,500,000		794,900,000
Accretion of asset retirement obligations										17,400,000		17,100,000		20,200,000
Amortization of undeveloped leases										60,200,000		38,400,000		59,200,000
Impairment of assets														329,000,000
Deferred and noncurrent income taxes										2,500,000		(108,400,000)		(187,700,000)
Additions to property, plant, equipment										534,800,000		269,800,000		1,263,100,000
Total assets at year end		5,186,200,000				5,419,000,000				5,186,200,000		5,419,000,000		5,717,800,000
Exploration and production [Member] | Canada [Member]
Revenues From External Customers And Long Lived Assets [Line Items]
Net income (loss)	[4]									112,500,000		(35,900,000)		(583,400,000)
Revenues from external customers	[4]									485,500,000	[3]	365,300,000		549,700,000
Interest income	[4]
Interest expense, net of capitalization	[4]
Income tax expense (benefit)	[4]									44,400,000		(134,300,000)		(188,800,000)
Depreciation, depletion and amortization	[4]									185,400,000		203,200,000		261,900,000
Accretion of asset retirement obligations	[4]									7,900,000		13,300,000		12,600,000
Amortization of undeveloped leases	[4]									1,600,000		4,500,000		14,400,000
Impairment of assets	[4]											95,100,000		683,600,000
Deferred and noncurrent income taxes	[4]									55,300,000		(175,800,000)		(146,000,000)
Additions to property, plant, equipment	[4]									267,600,000		361,300,000		184,900,000
Total assets at year end	[4]	1,725,800,000				1,559,500,000				1,725,800,000		1,559,500,000		2,460,600,000
Exploration and production [Member] | Malaysia [Member]
Revenues From External Customers And Long Lived Assets [Line Items]
Net income (loss)										224,200,000		171,100,000		(653,200,000)
Revenues from external customers										781,100,000	[3]	753,400,000		1,131,400,000
Interest income
Interest expense, net of capitalization
Income tax expense (benefit)										126,400,000		85,900,000		(567,900,000)
Depreciation, depletion and amortization										204,600,000		227,700,000		544,900,000
Accretion of asset retirement obligations										17,300,000		16,300,000		15,900,000
Impairment of assets														1,480,600,000
Deferred and noncurrent income taxes										(3,700,000)		(8,500,000)		(579,200,000)
Additions to property, plant, equipment										16,000,000		101,400,000		244,400,000
Total assets at year end		1,670,100,000				2,024,700,000				1,670,100,000		2,024,700,000		2,537,200,000
Exploration and production [Member] | Other [Member]
Revenues From External Customers And Long Lived Assets [Line Items]
Net income (loss)										(37,500,000)		(54,700,000)		(158,600,000)
Revenues from external customers												200,000
Interest income
Interest expense, net of capitalization
Income tax expense (benefit)										(36,200,000)		(18,800,000)		(17,300,000)
Depreciation, depletion and amortization										3,800,000		5,900,000		6,200,000
Amortization of undeveloped leases												500,000		1,800,000
Deferred and noncurrent income taxes										(36,200,000)		(18,300,000)		(4,600,000)
Additions to property, plant, equipment										37,600,000		(1,300,000)		39,200,000
Total assets at year end		154,200,000				115,700,000				154,200,000		115,700,000		147,700,000
Corporate and Other [Member]
Revenues From External Customers And Long Lived Assets [Line Items]
Net income (loss)										(607,500,000)		(149,100,000)		(244,900,000)
Revenues from external customers										4,600,000		6,600,000		6,600,000
Interest income										7,400,000		2,900,000		4,000,000
Interest expense, net of capitalization										181,800,000		148,200,000		117,400,000
Income tax expense (benefit)										245,600,000		(64,100,000)		84,500,000
Depreciation, depletion and amortization										17,800,000		16,800,000		11,900,000
Accretion of asset retirement obligations										0		0		0
Amortization of undeveloped leases										0		0		0
Impairment of assets												0		0
Deferred and noncurrent income taxes										242,500,000		(76,800,000)		(60,500,000)
Additions to property, plant, equipment										14,800,000		21,900,000		59,900,000
Total assets at year end		$ 1,101,700,000				$ 1,149,900,000				$ 1,101,700,000		$ 1,149,900,000		$ 592,200,000
[1]	Reclassified to conform to current presentation (see Note A).
[2]	Results exclude corporate overhead, interest and discontinued operations.
[3]	Includes a pretax gain of $129.0 million on sale of Seal area heavy oil field sold in January 2017.
[4]	Includes Synthetic crude operations in 2016 and 2015. This business was sold in June 2016.

Business Segments (Geographic I

Business Segments (Geographic Information on Certain Long-Lived Assets) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	$ 8,220	$ 8,316.2	$ 9,818.4
United States [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	5,050.5	5,121.6	5,484.7
Canada [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	1,635.9	1,451.4	2,310.6
Malaysia [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	1,392.3	1,637	1,912
Other [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	$ 141.3	$ 106.2	$ 111.1

Business Segments (Geographi110

Business Segments (Geographic Information on Revenues from External Customers) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Revenues from External Customers and Long-Lived Assets [Line Items]
External Revenues	$ 2,225,129	$ 1,811,238	[1]	$ 2,941,271	[1]
United States [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
External Revenues	958,300	692,300		1,260,200
Canada [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
External Revenues	485,700	365,300		549,700
Malaysia [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
External Revenues	$ 781,100	753,400		$ 1,131,400
Other [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
External Revenues		$ 200
[1]	Reclassified to conform to current presentation (see Note A).

Supplemental Oil and Gas Inf111

Supplemental Oil and Gas Information (Narrative) (Details) MMBbls in Millions

1 Months Ended

12 Months Ended

Jan. 31, 2015

Dec. 31, 2018

Dec. 31, 2017bbl

Dec. 31, 2017MMcf

Dec. 31, 2017ft³

Dec. 31, 2017MMBbls

Dec. 31, 2017$ / Mcf

Dec. 31, 2017

Dec. 31, 2016ft³MMBbls

Dec. 31, 2015ft³MMBbls

Dec. 31, 2014ft³MMBbls

Reserve Quantities [Line Items]

Proved reserves

328.1

329

456.2

441.8

Future net cash flows annual discount factor, percentage

10.00%

U.S. statutory rate

35.00%

Equity Method Investee [Member]

Reserve Quantities [Line Items]

Reserves attributable to investees accounted for my the equity method | bbl

0

Scenario, Plan [Member]

Reserve Quantities [Line Items]

U.S. statutory rate

21.00%

Oil Reserves [Member]

Reserve Quantities [Line Items]

Proved undeveloped reserve development window

5 years

Natural Gas Liquids Reserves [Member]

Reserve Quantities [Line Items]

Proved reserves

48.9

42.5

36.4

30.6

Proved undeveloped reserve development window

5 years

Natural Gas Reserves [Member]

Reserve Quantities [Line Items]

Proved reserves | ft³

1,927,100,000,000

1,878,000,000,000

1,688,800,000,000

1,704,700,000,000

Proved undeveloped reserve development window

5 years

Alberta, Canada [Member]

Reserve Quantities [Line Items]

Working interest

5.00%

Malaysia [Member] | Oil Reserves [Member]

Reserve Quantities [Line Items]

Proved reserves

52.2

Malaysia [Member] | Natural Gas Liquids Reserves [Member]

Reserve Quantities [Line Items]

Proved reserves

0.3

0.5

0.6

0.8

Malaysia [Member] | Natural Gas Reserves [Member]

Reserve Quantities [Line Items]

Proved reserves

491,300

491,400,000,000

539,700,000,000

546,800,000,000

635,600,000,000

Malaysia [Member] | Natural Gas Reserves [Member] | Held-for-sale [Member]

Reserve Quantities [Line Items]

Proved reserves | ft³

26,700

Expected sales proceeds | $ / Mcf

0.24

Canada [Member] | Natural Gas Liquids Reserves [Member]

Reserve Quantities [Line Items]

Proved reserves

5.6

5.6

0.4

0.7

Canada [Member] | Natural Gas Reserves [Member]

Reserve Quantities [Line Items]

Proved reserves | ft³

1,212,400,000,000

1,118,900,000,000

909,600,000,000

842,800,000,000

Canada [Member] | Synthetic Oil [Member]

Reserve Quantities [Line Items]

Proved reserves

[1]

0

114.8

105.6

Malaysia [Member]

Reserve Quantities [Line Items]

Percentage of interest in oil and gas property sold during period

10.00%

[1]

All synthetic oil operations were sold in June 2016.

Supplemental Oil and Gas Inf112

Supplemental Oil and Gas Information (Summary of Proved Reserves Based on Average Prices) (Details) MMBbls in Millions, ft³ in Billions		12 Months Ended
		Dec. 31, 2017MMcfft³MMBbls	Dec. 31, 2017ft³MMBbls	Dec. 31, 2017ft³MMBbls	Dec. 31, 2016ft³MMBbls	Dec. 31, 2015ft³MMBbls	Dec. 31, 2014ft³MMBbls
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance				329	456.2	441.8
Revisions of previous estimates				(6)	(5.8)	5.3
Improved recovery				2		2.4
Extensions and discoveries				31.6	11	63.8
Purchases of properties				4.7	26.3
Sales of properties					(121)	(11)
Production				(33.2)	(37.7)	(46.1)
Proved developed and undeveloped reserves, Ending Balance				328.1	329	456.2
Proved developed reserves		185.5	185.5	185.5	184.9	326.6	324.1
Proved undeveloped reserves		142.6	142.6	142.6	144.1	129.6	117.7
Crude Oil [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance				329	341.4	336.2
Revisions of previous estimates				(6)	(5.8)	(8.2)
Improved recovery				2		2.4
Extensions and discoveries				31.6	11	63.8
Purchases of properties				4.7	26.3
Sales of properties					(7.8)	(11)
Production				(33.2)	(36.1)	(41.8)
Proved developed and undeveloped reserves, Ending Balance				328.1	329	341.4
Proved developed reserves		185.5	185.5	185.5	184.9	211.8	218.5
Proved undeveloped reserves		142.6	142.6	142.6	144.1	129.6	117.7
Natural Gas Liquids Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance				42.5	36.4	30.6
Revisions of previous estimates				1.3	1.6	2
Extensions and discoveries				7.8	2.9	7.6
Purchases of properties				0.5	5.1
Sales of properties						(0.1)
Production				(3.2)	(3.5)	(3.7)
Proved developed and undeveloped reserves, Ending Balance				48.9	42.5	36.4
Proved developed reserves		24.6	24.6	24.6	22.2	21.6	17.5
Proved undeveloped reserves		24.3	24.3	24.3	20.3	14.8	13.1
Natural Gas Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance | ft³			1,878		1,688.8	1,704.7
Revisions of previous estimates | ft³			(5.4)		43.3	53.5
Improved recovery | ft³						1.8
Extensions and discoveries | ft³			190.6		164.2	162.9
Purchases of properties | ft³			4		122.3
Sales of properties | ft³					(2.2)	(78)
Production | ft³			(140.1)		(138.4)	(156.1)
Proved developed and undeveloped reserves, Ending Balance | ft³			1,927.1		1,878	1,688.8
Proved developed reserves | ft³		819.3	819.3	819.3	818.1	783.5	812.1
Proved undeveloped reserves | ft³		1,107.8	1,107.8	1,107.8	1,059.9	905.3	892.6
United States [Member] | Crude Oil [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance				214.4	238.9	204.9
Revisions of previous estimates				(4.7)	(10.9)	(7.6)
Extensions and discoveries				27.2	8.6	63.8
Purchases of properties				4.7
Sales of properties					(4.5)
Production				(16.9)	(17.7)	(22.2)
Proved developed and undeveloped reserves, Ending Balance				224.7	214.4	238.9
Proved developed reserves		126.3	126.3	126.3	113.9	125.9	106.2
Proved undeveloped reserves		98.4	98.4	98.4	100.5	113	98.7
United States [Member] | Natural Gas Liquids Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance				36.4	35.4	29.1
Revisions of previous estimates				2	1.2	2.2
Extensions and discoveries				7	2.8	7.6
Purchases of properties				0.5
Production				(2.9)	(3)	(3.5)
Proved developed and undeveloped reserves, Ending Balance				43	36.4	35.4
Proved developed reserves		23.3	23.3	23.3	20.8	20.7	16.5
Proved undeveloped reserves		19.7	19.7	19.7	15.6	14.7	12.6
United States [Member] | Natural Gas Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance | ft³			219.4		232.4	226.3
Revisions of previous estimates | ft³			(16)		0.1	(5.2)
Extensions and discoveries | ft³			32.2		6.4	43.2
Purchases of properties | ft³			4
Sales of properties | ft³					(0.1)
Production | ft³			(16.3)		(19.4)	(31.9)
Proved developed and undeveloped reserves, Ending Balance | ft³			223.3		219.4	232.4
Proved developed reserves | ft³		127.7	127.7	127.7	138.7	148.3	145.6
Proved undeveloped reserves | ft³		95.6	95.6	95.6	80.7	84.1	80.7
Canada [Member] | Crude Oil [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance				48.9	27.9	37.4
Revisions of previous estimates				2.3	2.5	(4.8)
Extensions and discoveries				4.4
Purchases of properties					26.3
Sales of properties					(3.3)
Production				(4.1)	(4.5)	(4.7)
Proved developed and undeveloped reserves, Ending Balance				51.5	48.9	27.9
Proved developed reserves		21.9	21.9	21.9	19.2	23.8	32.4
Proved undeveloped reserves		29.6	29.6	29.6	29.7	4.1	5
Canada [Member] | Synthetic Oil [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance	[1]			0	114.8	105.6
Revisions of previous estimates	[1]					13.5
Sales of properties	[1]				(113.2)
Production	[1]				(1.6)	(4.3)
Proved developed and undeveloped reserves, Ending Balance	[1]				0	114.8
Proved developed reserves	[1]					114.8	105.6
Canada [Member] | Natural Gas Liquids Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance				5.6	0.4	0.7
Revisions of previous estimates				(0.6)	0.2	(0.3)
Extensions and discoveries				0.8	0.1
Purchases of properties					5.1
Production				(0.2)	(0.2)
Proved developed and undeveloped reserves, Ending Balance				5.6	5.6	0.4
Proved developed reserves		1	1	1	0.9	0.3	0.2
Proved undeveloped reserves		4.6	4.6	4.6	4.7	0.1	0.5
Canada [Member] | Natural Gas Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance | ft³			1,118.9		909.6	842.8
Revisions of previous estimates | ft³			19.4		45.3	18.9
Extensions and discoveries | ft³			156.7		120.2	119.7
Purchases of properties | ft³					122.3
Sales of properties | ft³					(2.1)
Production | ft³			(82.6)		(76.4)	(71.8)
Proved developed and undeveloped reserves, Ending Balance | ft³			1,212.4		1,118.9	909.6
Proved developed reserves | ft³		547	547	547	498.9	453.5	467.4
Proved undeveloped reserves | ft³		665.5	665.5	665.5	620	456.1	375.4
Malaysia [Member] | Crude Oil [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance				65.7	74.6	93.9
Revisions of previous estimates				(3.6)	2.6	4.2
Improved recovery				2		2.4
Extensions and discoveries					2.4
Sales of properties						(11)
Production				(12.2)	(13.9)	(14.9)
Proved developed and undeveloped reserves, Ending Balance				51.9	65.7	74.6
Proved developed reserves		37.3	37.3	37.3	51.8	62.1	79.9
Proved undeveloped reserves		14.6	14.6	14.6	13.9	12.5	14
Malaysia [Member] | Oil Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Ending Balance				52.2
Malaysia [Member] | Natural Gas Liquids Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance				0.5	0.6	0.8
Revisions of previous estimates				(0.1)	0.2	0.1
Sales of properties						(0.1)
Production				(0.1)	(0.3)	(0.2)
Proved developed and undeveloped reserves, Ending Balance				0.3	0.5	0.6
Proved developed reserves		0.3	0.3	0.3	0.5	0.6	0.8
Malaysia [Member] | Natural Gas Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped crude oil/synthetic oil reserves, Beginning Balance | ft³			539.7		546.8	635.6
Revisions of previous estimates | ft³			(8.8)		(2.1)	39.8
Improved recovery | ft³						1.8
Extensions and discoveries | ft³			1.7		37.6
Sales of properties | ft³						(78)
Production | ft³			(41.2)		(42.6)	(52.4)
Proved developed and undeveloped reserves, Ending Balance		491,300	491.4		539.7	546.8
Proved developed reserves | ft³		144.6	144.6	144.6	180.5	181.7	199.1
Proved undeveloped reserves | ft³		346.7	346.7	346.7	359.2	365.1	436.5
[1]	All synthetic oil operations were sold in June 2016.

Supplemental Oil and Gas Inf113

Supplemental Oil and Gas Information (Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property acquisition costs
Unproved	$ 63.4	$ 18.6	$ 12.6
Proved	7.7	206.7
Total acquisition costs	71.1	225.3	12.6
Exploration costs	79.2	70.1	371.9
Development costs	819	508	1,819.4
Total costs incurred	969.3	803.4	2,203.9
Charged to expense
Dry hole expense	(4.2)	15.1	296.8
Geophysical and other costs	65.2	43.4	98.7
Total charged to expense	61	58.5	395.5
Property additions	908.3	744.9	1,808.4
United States [Member]
Property acquisition costs
Unproved	50.4	18.6	10.1
Proved	7.7
Total acquisition costs	58.1	18.6	10.1
Exploration costs	13.7	18.5	166.8
Development costs	508.4	239.7	1,375.1
Total costs incurred	580.2	276.8	1,552
Charged to expense
Dry hole expense	(1.9)	0.4	241.3
Geophysical and other costs	9.7	5.7	16.9
Total charged to expense	7.8	6.1	258.2
Property additions	572.4	270.7	1,293.8
Canada [Member]
Property acquisition costs
Unproved			2.5
Proved		206.7
Total acquisition costs		206.7	2.5
Exploration costs	0.6	3.6	0.7
Development costs	273.8	165.1	231.5
Total costs incurred	274.4	375.4	234.7
Charged to expense
Geophysical and other costs	0.5	3.6	0.7
Total charged to expense	0.5	3.6	0.7
Property additions	273.9	371.8	234
Malaysia [Member]
Property acquisition costs
Exploration costs	(8.9)	6	69
Development costs	35.7	102.9	210
Total costs incurred	26.8	108.9	279
Charged to expense
Dry hole expense	0.7	4.5	29.7
Geophysical and other costs	1.7	0.7	7.9
Total charged to expense	2.4	5.2	37.6
Property additions	24.4	103.7	241.4
Other Regions [Member]
Property acquisition costs
Unproved	13
Total acquisition costs	13
Exploration costs	73.8	42	135.4
Development costs	1.1	0.3	2.8
Total costs incurred	87.9	42.3	138.2
Charged to expense
Dry hole expense	(3)	10.2	25.8
Geophysical and other costs	53.3	33.4	73.2
Total charged to expense	50.3	43.6	99
Property additions	37.6	(1.3)	39.2
Asset Retirement Obligation Costs [Member]
Property acquisition costs
Development costs	52.3	13.7	76.8
Total costs incurred	52.3	13.7	76.8
Asset Retirement Obligation Costs [Member] | United States [Member]
Property acquisition costs
Development costs	37.6	0.9	30.7
Total costs incurred	37.6	0.9	30.7
Asset Retirement Obligation Costs [Member] | Canada [Member]
Property acquisition costs
Development costs	6.3	10.5	49.1
Total costs incurred	6.3	10.5	49.1
Asset Retirement Obligation Costs [Member] | Malaysia [Member]
Property acquisition costs
Development costs	8.4	2.3	(3)
Total costs incurred	$ 8.4	$ 2.3	$ (3)

Supplemental Oil and Gas Inf114

Supplemental Oil and Gas Information (Results of Operations for Oil andGas Producing Activities) (Details) - USD ($)		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Revenues
Revenues	[1]	$ 2,088,100,000		$ 1,799,500,000		$ 2,775,000,000
Other operating revenues	[1]	132,400,000		5,100,000		159,700,000
Total revenues	[1]	2,220,500,000		1,804,600,000		2,934,700,000
Costs and expenses
Lease operating expenses	[1]	468,400,000		559,400,000		832,300,000
Severance and ad valorem taxes	[1]	43,700,000		43,800,000		65,800,000
Exploration costs charged to expense	[1]	61,000,000		58,500,000		395,500,000
Undeveloped lease amortization	[1]	61,800,000		43,400,000		75,400,000
Depreciation, depletion and amortization	[1]	939,900,000		1,037,300,000		1,607,900,000
Accretion of asset retirement obligations	[1]	42,600,000		46,700,000		48,700,000
Impairment of assets		0		95,088,000	[2]	2,493,156,000	[2]
Redetermination expense		15,000,000	[1]	39,100,000	[2]
Deepwater rig contract exit costs						282,000,000
Selling and general expenses	[1]	123,700,000		147,400,000		177,200,000
Other expenses (benefits)	[1]	30,700,000		13,900,000		360,600,000
Total costs and expenses	[1]	1,786,800,000		2,084,600,000		6,056,600,000
Results of operations before taxes	[1]	433,700,000		(280,000,000)		(3,121,900,000)
Income tax expense (benefit)	[1]	137,100,000		(155,100,000)		(1,111,000,000)
Results of operations	[1]	296,600,000		(124,900,000)		(2,010,900,000)
Crude Oil and Natural Gas Liquids [Member]
Revenues
Revenues	[1]	1,756,900,000		1,506,800,000		2,351,500,000
Natural Gas [Member]
Revenues
Revenues	[1]	331,200,000		292,700,000		423,500,000
United States [Member]
Revenues
Revenues	[1]	951,200,000		685,800,000		1,247,300,000
Other operating revenues	[1]	2,700,000		(100,000)		6,300,000
Total revenues	[1]	953,900,000		685,700,000		1,253,600,000
Costs and expenses
Lease operating expenses	[1]	198,500,000		218,600,000		312,000,000
Severance and ad valorem taxes	[1]	42,200,000		37,000,000		55,900,000
Exploration costs charged to expense	[1]	7,800,000		6,100,000		258,200,000
Undeveloped lease amortization	[1]	60,200,000		38,400,000		59,200,000
Depreciation, depletion and amortization	[1]	546,100,000		600,500,000		794,900,000
Accretion of asset retirement obligations	[1]	17,400,000		17,100,000		20,200,000
Impairment of assets	[1]					329,000,000
Selling and general expenses	[1]	61,800,000		68,800,000		88,200,000
Other expenses (benefits)	[1]	20,000,000		(7,500,000)		288,700,000
Total costs and expenses	[1]	954,000,000		979,000,000		2,206,300,000
Results of operations before taxes	[1]	(100,000)		(293,300,000)		(952,700,000)
Income tax expense (benefit)	[1]	2,500,000		(87,900,000)		(337,000,000)
Results of operations	[1]	(2,600,000)		(205,400,000)		(615,700,000)
United States [Member] | Crude Oil and Natural Gas Liquids [Member]
Revenues
Revenues	[1]	913,300,000		650,700,000		1,176,900,000
United States [Member] | Natural Gas [Member]
Revenues
Revenues	[1]	37,900,000		35,100,000		70,400,000
Canada [Member]
Costs and expenses
Impairment of assets				95,088,000		683,574,000
Canada [Member] | Conventional [Member]
Revenues
Revenues	[1]	358,800,000		301,700,000		348,700,000
Other operating revenues	[1]	126,700,000		(700,000)		(2,400,000)
Total revenues	[1]	485,500,000		301,000,000		346,300,000
Costs and expenses
Lease operating expenses	[1]	101,100,000		102,600,000		102,400,000
Severance and ad valorem taxes	[1]	1,500,000		4,300,000		4,800,000
Exploration costs charged to expense	[1]	500,000		3,600,000		700,000
Undeveloped lease amortization	[1]	1,600,000		4,500,000		14,400,000
Depreciation, depletion and amortization	[1]	185,400,000		186,700,000		211,200,000
Accretion of asset retirement obligations	[1]	7,900,000		10,900,000		7,200,000
Impairment of assets	[1]			95,100,000		683,600,000
Selling and general expenses	[1]	28,300,000		28,600,000		25,500,000
Other expenses (benefits)	[1]	2,300,000		7,500,000		43,900,000
Total costs and expenses	[1]	328,600,000		443,800,000		1,093,700,000
Results of operations before taxes	[1]	156,900,000		(142,800,000)		(747,400,000)
Income tax expense (benefit)	[1]	44,400,000		(58,900,000)		(191,200,000)
Results of operations	[1]	112,500,000		(83,900,000)		(556,200,000)
Canada [Member] | Synthetic Oil [Member]
Revenues
Revenues	[1]			60,700,000		203,000,000
Other operating revenues	[1]			3,600,000		400,000
Total revenues	[1]			64,300,000		203,400,000
Costs and expenses
Lease operating expenses	[1]			69,800,000		166,000,000
Severance and ad valorem taxes	[1]			2,500,000		5,100,000
Depreciation, depletion and amortization	[1]			16,500,000		50,700,000
Accretion of asset retirement obligations	[1]			2,400,000		5,400,000
Selling and general expenses	[1]			500,000		1,000,000
Total costs and expenses	[1]			91,700,000		228,200,000
Results of operations before taxes	[1]			(27,400,000)		(24,800,000)
Income tax expense (benefit)	[1]			(75,400,000)		2,400,000
Results of operations	[1]			48,000,000		(27,200,000)
Canada [Member] | Crude Oil and Natural Gas Liquids [Member] | Conventional [Member]
Revenues
Revenues	[1]	203,700,000		171,700,000		181,000,000
Canada [Member] | Crude Oil and Natural Gas Liquids [Member] | Synthetic Oil [Member]
Revenues
Revenues	[1]			60,700,000		203,000,000
Canada [Member] | Natural Gas [Member] | Conventional [Member]
Revenues
Revenues	[1]	155,100,000		130,000,000		167,700,000
Malaysia [Member]
Revenues
Revenues	[1]	778,100,000		751,300,000		976,000,000
Other operating revenues	[1]	3,000,000		2,100,000		155,400,000
Total revenues	[1]	781,100,000		753,400,000		1,131,400,000
Costs and expenses
Lease operating expenses	[1]	168,800,000		168,400,000		251,900,000
Exploration costs charged to expense	[1]	2,400,000		5,200,000		37,600,000
Depreciation, depletion and amortization	[1]	204,600,000		227,700,000		544,900,000
Accretion of asset retirement obligations	[1]	17,300,000		16,300,000		15,900,000
Impairment of assets	[1]					1,480,600,000
Redetermination expense	[1]	15,000,000		39,100,000
Selling and general expenses	[1]	14,000,000		15,900,000		5,700,000
Other expenses (benefits)	[1]	8,400,000		23,800,000		15,900,000
Total costs and expenses	[1]	430,500,000		496,400,000		2,352,500,000
Results of operations before taxes	[1]	350,600,000		257,000,000		(1,221,100,000)
Income tax expense (benefit)	[1]	126,400,000		85,900,000		(567,900,000)
Results of operations	[1]	224,200,000		171,100,000		(653,200,000)
Malaysia [Member] | Crude Oil and Natural Gas Liquids [Member]
Revenues
Revenues	[1]	639,900,000		623,700,000		790,600,000
Malaysia [Member] | Natural Gas [Member]
Revenues
Revenues	[1]	138,200,000		127,600,000		185,400,000
Other Regions [Member]
Revenues
Other operating revenues	[1]			200,000
Total revenues	[1]			200,000
Costs and expenses
Exploration costs charged to expense	[1]	50,300,000		43,600,000		99,000,000
Undeveloped lease amortization	[1]			500,000		1,800,000
Depreciation, depletion and amortization	[1]	3,800,000		5,900,000		6,200,000
Selling and general expenses	[1]	19,600,000		33,600,000		56,800,000
Other expenses (benefits)	[1]			(9,900,000)		12,100,000
Total costs and expenses	[1]	73,700,000		73,700,000		175,900,000
Results of operations before taxes	[1]	(73,700,000)		(73,500,000)		(175,900,000)
Income tax expense (benefit)	[1]	(36,200,000)		(18,800,000)		(17,300,000)
Results of operations	[1]	$ (37,500,000)		$ (54,700,000)		$ (158,600,000)
[1]	Results exclude corporate overhead, interest and discontinued operations.
[2]	Reclassified to conform to current presentation (see Note A).

Supplemental Oil and Gas Inf115

Supplemental Oil and Gas Information (Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$ 21,992.1	$ 17,549.3	$ 27,439
Future development costs	(3,793.5)	(3,598.5)	(4,723.7)
Future production costs	(9,577.7)	(8,972.5)	(14,138.6)
Future income taxes	(1,287)	(273.5)	(1,060.7)
Future net cash flows	7,333.9	4,704.8	7,516
10% annual discount for estimated timing of cash flows	(3,411)	(2,124.8)	(3,656.9)
Standardized measure of discounted future net cash flows	3,922.9	2,580	3,859.1	$ 9,905.2
United States [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	12,885.8	9,477.9	12,373.9
Future development costs	(2,079.5)	(1,691.1)	(2,620.5)
Future production costs	(4,765.3)	(3,981.6)	(4,955.4)
Future income taxes	(893.7)	(118.9)	(339.7)
Future net cash flows	5,147.3	3,686.3	4,458.3
10% annual discount for estimated timing of cash flows	(2,698.2)	(1,799.5)	(2,430)
Standardized measure of discounted future net cash flows	2,449.1	1,886.8	2,028.3
Canada [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	4,714.3	3,752.7	8,922
Future development costs	(1,081.7)	(1,143.6)	(1,145.4)
Future production costs	(2,507.4)	(2,329.7)	(5,892.7)
Future income taxes	(161.1)	(81.3)	(504.8)
Future net cash flows	964.1	198.1	1,379.1
10% annual discount for estimated timing of cash flows	(394.6)	(95)	(666.8)
Standardized measure of discounted future net cash flows	569.5	103.1	712.3
Malaysia [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	4,392	4,318.7	6,143.1
Future development costs	(632.3)	(763.8)	(957.8)
Future production costs	(2,305)	(2,661.2)	(3,290.5)
Future income taxes	(232.2)	(73.3)	(216.2)
Future net cash flows	1,222.5	820.4	1,678.6
10% annual discount for estimated timing of cash flows	(318.2)	(230.3)	(560.1)
Standardized measure of discounted future net cash flows	$ 904.3	$ 590.1	$ 1,118.5

Supplemental Oil and Gas Inf116

Supplemental Oil and Gas Information (Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Oil and Gas Information [Abstract]
Net changes in prices and production costs	$ 2,428.4	$ (1,476.1)	$ (11,365.5)
Net changes in development costs	(724.4)	544.9	591.4
Sales and transfers of oil and gas produced, net of production costs	(1,576)	(1,196.3)	(1,876.9)
Net change due to extensions and discoveries	807.9	280.5	1,145.8
Net change due to purchases and sales of proved reserves	85.9	(583.4)	(287.4)
Development costs incurred	802.7	479.6	1,725.4
Accretion of discount	270.9	428.1	1,289.5
Revisions of previous quantity estimates	(109.5)	(49.2)	163.3
Net change in income taxes	(643)	292.8	2,568.3
Net increase (decrease)	1,342.9	(1,279.1)	(6,046.1)
Standardized measure	$ 3,922.9	$ 2,580	$ 3,859.1	$ 9,905.2

Supplemental Oil and Gas Inf117

Supplemental Oil and Gas Information (Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	$ 830.3	$ 849
Proved oil and gas properties	19,349.5	19,774
Gross capitalized costs	20,179.8	20,623
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	(402)	(406.6)
Proved oil and gas properties	(11,696.2)	(12,049.7)
Net capitalized costs	8,081.6	8,166.7
United States [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	360.9	360.8
Proved oil and gas properties	9,606.4	9,384.6
Gross capitalized costs	9,967.3	9,745.4
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	(149.5)	(151.2)
Proved oil and gas properties	(4,893.8)	(4,605.9)
Net capitalized costs	4,924	4,988.3
Canada [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	286.8	315.6
Proved oil and gas properties	3,603.4	4,241.6
Gross capitalized costs	3,890.2	4,557.2
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	(230.7)	(233.6)
Proved oil and gas properties	(2,027.9)	(2,877.2)
Net capitalized costs	1,631.6	1,446.4
Malaysia [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	20.5	47
Proved oil and gas properties	6,139.7	6,147.8
Gross capitalized costs	6,160.2	6,194.8
Accumulated depreciation, depletion and amortization
Proved oil and gas properties	(4,774.5)	(4,566.6)
Net capitalized costs	1,385.7	1,628.2
Other Regions [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	162.1	125.6
Gross capitalized costs	162.1	125.6
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	(21.8)	(21.8)
Net capitalized costs	$ 140.3	$ 103.8

Supplemental Quarterly Infomati

Supplemental Quarterly Infomation (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015	[1]
Supplemental Quarterly Information [Abstract]
Sales and other operating revenues		$ 545,000	$ 498,300	$ 509,700	$ 544,700	$ 483,000	$ 486,300	$ 411,200	$ 429,100	$ 2,097,695	$ 1,809,575	[1]	$ 2,787,116
Income (loss) from continuing operations before income taxes		2,400	(63,600)	(21,900)	154,900	(80,100)	(16,700)	(131,300)	(265,000)	71,802	(493,115)	[1]	(3,282,262)
Income (loss) from continuing operations		(284,800)	(66,300)	(17,300)	57,500	(62,800)	(14,600)	2,900	(199,500)	(310,936)	(273,943)	[1]	(2,255,772)
Net income (loss)		$ (286,800)	$ (65,900)	$ (17,600)	$ 58,500	$ (63,900)	$ (16,200)	$ 2,900	$ (198,800)	$ (311,789)	$ (275,970)	[1]	$ (2,270,833)
Income (loss) from continuing operations per Common share, Basic		$ (1.65)	$ (0.38)	$ (0.10)	$ 0.33	$ (0.36)	$ (0.08)	$ 0.02	$ (1.16)	$ (1.81)	$ (1.59)	[1]	$ (12.94)
Income (loss) from continuing operations per Common share, Diluted		(1.65)	(0.38)	(0.10)	0.33	(0.36)	(0.08)	0.02	(1.16)	(1.81)	(1.59)	[1]	(12.94)
Net income (loss) per Common share, Basic		(1.66)	(0.38)	(0.10)	0.34	(0.37)	(0.08)	0.02	(1.16)	(1.81)	(1.60)	[1]	(13.03)
Net income (loss) per Common share, Diluted		(1.66)	(0.38)	(0.10)	0.34	(0.37)	(0.08)	0.02	(1.16)	(1.81)	(1.60)	[1]	(13.03)
Cash dividend per Common share		0.25	0.25	0.25	0.25	0.25	0.25	0.35	0.35	1	1.20	[1]	$ 1.40
Market price of Common Stock, High	[2]	31.98	27.43	28.71	32.18	34.30	32.66	36.24	26.69	32.18	36.24
Market price of Common Stock, Low	[2]	$ 25.02	$ 22.63	$ 24.06	$ 25.76	$ 25	$ 25.14	$ 23.49	$ 15.76	$ 22.63	$ 15.76
[1]	Reclassified to conform to current presentation (see Note A).
[2]	Prices are as quoted on the New York Stock Exchange.

Schedule II - Valuation Acco119

Schedule II - Valuation Accounts and Reserves (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Allowance for doubtful accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at January 1		$ 1.6	$ 1.6	$ 1.6
Charged (Credited) to Expense
Deductions
Other	[1]
Balance at December 31		1.6	1.6	1.6
Deferred tax asset valuation allowance [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at January 1		305.4	294.4	306.5
Charged (Credited) to Expense		18.6	25.7	40.8
Deductions
Other	[1]	152.3	(14.7)	(52.9)
Balance at December 31		$ 476.3	$ 305.4	$ 294.4
[1]	Amounts in 2017 and 2016 for deferred tax asset valuations are primarily associated with an increase in foreign tax credit carryforwards. The amount in 2015 for deferred tax asset valuation allowance is primarily associated with utilization of foreign tax credit carryforwards.