Murphy Oil (MUR) 10-K 27 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Jan. 31, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	mur
Entity Registrant Name	MURPHY OIL CORP /DE
Entity Central Index Key	717423
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$11,804,954,783
Entity Common Stock, Shares Outstanding		177,501,534

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014		Dec. 31, 2013
Current assets
Cash and cash equivalents	$1,193,308,000		$750,155,000
Canadian government securities with maturities greater than 90 days at the date of acquisition	461,313,000		374,842,000
Accounts receivable, less allowance for doubtful accounts of $1,609 in both 2014 and 2013	873,277,000		999,872,000
Inventories, at lower of cost or market	242,733,000		294,195,000
Prepaid expenses	77,281,000		83,856,000
Deferred income taxes	55,107,000		61,991,000
Assets held for sale	376,130,000		943,732,000
Total current assets	3,279,149,000		3,508,643,000
Property, plant and equipment, at cost less accumulated depreciation, depletion and amortization of $9,503,524 in 2014 and $8,540,239 in 2013	13,331,047,000		13,481,055,000
Goodwill	0		40,259,000
Deferred charges and other assets	81,151,000		98,123,000
Assets held for sale	50,960,000		381,404,000
Total assets	16,742,307,000		17,509,484,000
Current liabilities
Current maturities of long-term debt	465,388,000		26,249,000
Accounts payable	2,275,830,000		2,158,485,000
Income taxes payable	59,054,000		222,930,000
Other taxes payable	52,457,000		33,969,000
Other accrued liabilities	143,610,000		143,258,000
Liabilities associated with assets held for sale	151,548,000		639,140,000
Total current liabilities	3,147,887,000		3,224,031,000
Long-term debt, including capital lease obligation	2,536,238,000		2,936,563,000
Deferred income taxes	1,193,864,000		1,466,100,000
Asset retirement obligations	841,526,000		852,488,000
Deferred credits and other liabilities	441,048,000		339,028,000
Liabilities associated with assets held for sale	8,310,000		95,544,000
Stockholders' equity
Cumulative Preferred Stock, par $100, authorized 400,000 shares, none issued
Common Stock, par $1.00, authorized 450,000,000 shares, issued 195,040,149 shares in 2014 and 194,920,155 shares in 2013	195,040,000		194,920,000
Capital in excess of par value	906,741,000		902,633,000
Retained earnings	8,728,032,000		8,058,792,000
Accumulated other comprehensive income (loss)	-170,255,000	[1]	172,119,000	[1]
Treasury stock	-1,086,124,000		-732,734,000
Total stockholders' equity	8,573,434,000		8,595,730,000
Total liabilities and stockholders' equity	$16,742,307,000		$17,509,484,000
[1]	All amounts are presented net of income taxes.

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Statement Of Financial Position [Abstract]
Maturity of Canadian government securities	90 days
Accounts receivable, allowance for doubtful accounts	$1,609	$1,609
Property, plant and equipment, accumulated depreciation, depletion and amortization	$9,503,524	$8,540,239
Cumulative Preferred Stock, par	$100	$100
Cumulative Preferred Stock, authorized	400,000	400,000
Cumulative Preferred Stock, issued	0	0
Common Stock, par	$1	$1
Common Stock, authorized	450,000,000	450,000,000
Common Stock, issued	195,040,149	194,920,155

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues
Sales and other operating revenues	$5,288,933	$5,312,686	$4,608,563
Gain (loss) on sale of assets	138,903	-87	66
Interest and other income	48,248	77,490	10,973
Total revenues	5,476,084	5,390,089	4,619,602
Costs and Expenses
Lease operating expenses	1,089,888	1,252,812	1,079,136
Severance and ad valorem taxes	107,215	87,331	35,612
Exploration expenses, including undeveloped lease amortization	513,600	502,215	380,924
Selling and general expenses	364,004	379,167	249,532
Depreciation, depletion and amortization	1,906,247	1,553,394	1,253,095
Impairment of assets	51,314	21,587	200,000	[1]
Accretion of asset retirement obligations	50,778	48,996	38,361
Interest expense	136,424	124,423	54,105
Interest capitalized	-20,605	-52,523	-39,173
Other expense	24,949
Total costs and expenses	4,223,814	3,917,402	3,251,592
Income from continuing operations before income taxes	1,252,270	1,472,687	1,368,010
Income tax expense	227,297	584,550	561,516
Income from continuing operations	1,024,973	888,137	806,494
Income (loss) from discontinued operations, net of income taxes	-119,362	235,336	164,382
Net Income	$905,611	$1,123,473	$970,876
Income per Common Share - Basic
Income from continuing operations	$5.73	$4.73	$4.16
Income (loss) from discontinued operations	($0.67)	$1.25	$0.85
Net income - Basic	$5.06	$5.98	$5.01
Income per Common Share - Diluted
Income from continuing operations	$5.69	$4.69	$4.14
Income (loss) from discontinued operations	($0.66)	$1.25	$0.85
Net income - Diluted	$5.03	$5.94	$4.99
Average Common shares outstanding
Average Common shares outstanding - Basic	178,852,942	187,921,062	193,902,335
Average Common shares outstanding - Diluted	180,070,984	189,271,398	194,668,737
[1]	Results exclude corporate overhead, interest and discontinued operations.

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Statement Of Income And Comprehensive Income [Abstract]
Net income	$905,611		$1,123,473		$970,876
Other comprehensive income (loss), net of tax
Net gain (loss) from foreign currency translation	-271,491		-308,300		117,331
Retirement and postretirement benefit plans	-72,796		69,583		-17,650
Deferred loss on interest rate hedges:
Increase in deferred loss associated with contract revaluation and settlement					-2,407
Amount of loss reclassified to interest expense in consolidated statement of income	1,913		1,935		1,207
Other comprehensive income (loss)	-342,374	[1]	-236,782	[1]	98,481
Comprehensive Income	$563,237		$886,691		$1,069,357
[1]	All amounts are presented net of income taxes.

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Operating Activities
Net income	$905,611		$1,123,473		$970,876
Adjustments to reconcile net income to net cash provided by operating activities:
Loss (income) from discontinued operations	119,362		-235,336		-164,382
Depreciation, depletion and amortization	1,906,247		1,553,394		1,253,095
Impairment of assets	51,314		21,587		200,000	[1]
Amortization of deferred major repair costs	8,345		8,464		7,065
Dry hole costs	269,986		262,876		181,924
Amortization of undeveloped leases	74,438		66,891		129,750
Accretion of asset retirement obligations	50,778		48,996		38,361
Deferred and noncurrent income tax charges (benefits)	-170,915		158,108		342,718
Pretax (gains) losses from disposition of assets	-138,903		87		-66
Net decrease (increase) in noncash operating working capital	-3,729		266,329		-168,180
Other operating activities, net	-23,895		-64,174		120,219
Net cash provided by continuing operations	3,048,639		3,210,695		2,911,380
Investing Activities
Property additions and dry hole costs	-3,679,464	[2]	-3,590,344	[2]	-3,541,724	[2]
Proceeds from sales of property, plant and equipment	1,467,046		1,650		99
Purchase of investment securities	-986,328	[3]	-923,497	[3]	-1,619,308	[3]
Proceeds from maturity of investment securities	899,857	[3]	664,258	[3]	2,035,798	[3]
Other investing activities - net	-18,929		291		253
Net cash required by investing activities	-2,317,818		-3,847,642		-3,124,882
Financing Activities
Borrowings of debt	100,000	[2]	350,000	[2]	1,995,467	[2]
Repayments of debt					-350,000
Repayment of capital lease obligation	-25,265
Purchase of treasury stock	-375,000		-500,000		-250,000
Proceeds from exercise of stock options and employee stock purchase plans	210		3,409		12,324
Withholding tax on stock-based incentive awards	-6,786		-16,727		-3,341
Cash dividends paid	-236,371		-235,108		-714,429
Separation of U.S. retail marketing business:
Cash distributed to Murphy Oil by Murphy USA			650,000
Cash held and retained by Murphy USA upon separation			-55,506
Other - net	-1,498		-2,473		-4,312
Net cash provided (required) by financing activities	-544,710		193,595		685,709
Cash Flows from Discontinued Operations
Operating activities	-39,563		427,792		144,901
Investing activities	199,541		116,463		-192,540
Changes in cash included in current assets held for sale	100,790		-301,302
Net increase (decrease) in cash and cash equivlents of discontinued operations	260,768		242,953		-47,639
Effect of exchange rate changes on cash and cash equivalents	-3,726		3,238		8,875
Net increase (decrease) in cash and cash equivalents	443,153		-197,161		433,443
Cash and cash equivalents at January 1	750,155		947,316		513,873
Cash and cash equivalents at December 31	$1,193,308		$750,155		$947,316
[1]	Results exclude corporate overhead, interest and discontinued operations.
[2]	Excludes non-cash asset and long-term obligation of $357,991 in 2013 associated with lease commencement for production equipment at the Kakap field offshore Malaysia.
[3]	Investments are Canadian government securities with maturities greater than 90 days at the date of acquisition.

CONSOLIDATED_STATEMENTS_OF_CAS1

CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Non-cash asset and long-term obligation	368,251
Minimum [Member]
Maturity of Canadian government securities	90 days
Malaysia [Member]
Non-cash asset and long-term obligation	357,991

CONSOLIDATED_STATEMENTS_OF_STO

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (USD $)	Cumulative Preferred Stock [Member]	Common Stock [Member]	Capital In Excess Of Par Value [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Stock [Member]	Total
In Thousands
Balance at beginning of year at Dec. 31, 2011		$193,909	$817,974	$7,460,942	$310,420	($4,848)
Exercise of stock options, including income tax benefits		483	12,717
Foreign currency translation gains (losses), net of income taxes					117,331		117,331
Purchase of treasury shares						-250,000
Net income for the year				970,876			970,876
Restricted stock transactions			-5,257
Retirement and postretirement benefit plans, net of income taxes					-17,650		17,650
Sale of stock under employee stock purchase plans			1,916			2,043
Cash dividends - $1.325 per share in 2014, $1.25 per share in 2013 and $3.675 per share in 2012				-714,429			-714,429
Stock-based compensation			46,584
Change in deferred loss on interest rate hedges, net of income taxes					-1,200
Awarded restricted stock		224
Balance at end of year at Dec. 31, 2012		194,616	873,934	7,717,389	408,901	-252,805	8,942,035
Exercise of stock options, including income tax benefits		304	563
Foreign currency translation gains (losses), net of income taxes					-308,300		-308,300
Purchase of treasury shares						-500,000
Net income for the year				1,123,473			1,123,473
Restricted stock transactions			-28,339
Retirement and postretirement benefit plans, net of income taxes					69,583		-69,583
Sale of stock under employee stock purchase plans			-147			1,015
Cash dividends - $1.325 per share in 2014, $1.25 per share in 2013 and $3.675 per share in 2012				-235,108			-235,108
Distribution of common stock of Murphy USA Inc. to shareholders				-546,962
Stock-based compensation			56,622
Change in deferred loss on interest rate hedges, net of income taxes					1,935
Awarded restricted stock						19,056
Balance at end of year at Dec. 31, 2013		194,920	902,633	8,058,792	172,119	-732,734	8,595,730
Exercise of stock options, including income tax benefits		120	-11,422
Foreign currency translation gains (losses), net of income taxes					-271,491		-271,491
Purchase of treasury shares						-375,000
Net income for the year				905,611			905,611
Restricted stock transactions			-27,920
Retirement and postretirement benefit plans, net of income taxes					-72,796		72,796
Sale of stock under employee stock purchase plans			-40			420
Cash dividends - $1.325 per share in 2014, $1.25 per share in 2013 and $3.675 per share in 2012				-236,371			-236,371
Stock-based compensation			43,490
Change in deferred loss on interest rate hedges, net of income taxes					1,913
Awarded restricted stock						21,190
Balance at end of year at Dec. 31, 2014		$195,040	$906,741	$8,728,032	($170,255)	($1,086,124)	$8,573,434

CONSOLIDATED_STATEMENTS_OF_STO1

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) (USD $)	3 Months Ended		12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement Of Stockholders Equity [Abstract]
Cumulative Preferred Stock, par	$100	$100	$100	$100	$100
Cumulative Preferred Stock, authorized	400,000	400,000	400,000	400,000	400,000
Cumulative Preferred Stock, issued	0	0	0	0	0
Common Stock, par	$1	$1	$1	$1	$1
Common Stock, authorized	450,000,000	450,000,000	450,000,000	450,000,000	450,000,000
Common Stock, issued	195,040,149	194,920,155	195,040,149	194,920,155	194,616,470
Cash dividends, per share	$0.35	$0.31	$1.32	$1.25	$3.67
Balance at end of year, shares of Common Stock	17,540,636	11,513,642	17,540,636	11,513,642	3,975,153

Significant_Accounting_Policie

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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 has an interest in a Canadian synthetic oil operation.  On August 30, 2013, the Company spun off Murphy USA Inc. (MUSA) to its shareholders.  MUSA formerly was the Company’s U.S. gasoline retail marketing operations.  MUSA is now a separate, publicly owned company traded on the New York Stock Exchange under the symbol “MUSA.”  In addition, Murphy Oil sold its United Kingdom retail marketing assets during 2014 and sold its U.K. oil and natural gas producing assets during 2013.  The Company is in the process of selling components of and decommissioning a crude oil refinery in the U.K. that was shutdown in May 2014.  It also is marketing for sale four U.K. petroleum product terminals as of December 31, 2014.  See Note C regarding more information regarding the spin-off and 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.
	REVENUE RECOGNITION – Revenues from sales of crude oil, natural gas liquids, natural gas and refined petroleum products 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 entitlement under existing working interests.  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, 2014 and 2013, the liabilities for natural gas balancing were immaterial.
	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 income.  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, 2014, the Company owned Canadian government securities with maturities greater than 90 days at date of acquisition that had a carrying value of $461,313,000.  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, 2014 and 2013, 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.
	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 is 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 and Canada are being depreciated on a straight-line basis over its estimated useful life ranging from 20 to 25 years.  Gains and losses on asset disposals or retirements are included in income as a separate component of revenues.
	Turnarounds for coking units at Syncrude Canada Ltd. are scheduled at intervals of two to three years.  Turnaround work associated with various other less significant units at Syncrude varies 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.
	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 Statement of Income and is added to the cost of the underlying asset for the development project in Property, Plant and Equipment in the Consolidated Balance Sheet.  Capitalized interest is amortized over the useful life of the asset in the same manner as other development costs.
	GOODWILL – Goodwill is recorded in an acquisition when the purchase price exceeds the fair value of net assets acquired.  All recorded goodwill arose from the purchase of an oil and natural gas company by Murphy’s wholly owned Canadian subsidiary in 2000.  Goodwill is not amortized, but is assessed annually for recoverability of the carrying value.  The Company assesses goodwill recoverability at each year-end by comparing the fair value of net assets for conventional oil and natural gas properties in Canada with the carrying value of these net assets including goodwill.  The fair value of the conventional oil and natural gas reporting unit is determined using the expected present value of future cash flows.  Based on its assessment of the fair value of its Canadian conventional oil and natural gas operations, the Company recorded an impairment charge of $37,047,000 in the fourth quarter 2014 and reduced the carrying amount to zero.
	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.  The Company does not provide U.S. deferred taxes for the portion of undistributed earnings of foreign subsidiaries when these earnings are considered indefinitely reinvested in the respective foreign operations.  The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be 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 Income (Loss) in 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 Sheet.  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 other comprehensive income 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 other comprehensive income is recognized immediately in earnings.
	Fair Value Measurements – The Company carries certain assets and liabilities at fair value in its Consolidated Balance Sheet.  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 prices.  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 three-year 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 Sheet.  Changes in the funded status which have not yet been recognized in the Statement of Income are recorded net of tax in Accumulated Other Comprehensive Income (Loss).  The remaining amounts in Accumulated Other Comprehensive Income (Loss) as of December 31, 2014 include net actuarial losses and prior service costs.
	NET INCOME PER COMMON SHARE – Basic income per common share is computed by dividing net income for each reporting period by the weighted average number of common shares outstanding during the period.  Diluted income per common share is computed by dividing net income 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.
	RECLASSIFICATIONS – The Consolidated Balance Sheet for 2013 has been reclassified to conform to the 2014 presentation within current liabilities.  The Consolidated Statements of Income for 2013 and 2012 have been reclassified to disclose separately Lease Operating Expenses and Severance and Ad valorem Taxes and to conform to 2014 presentation.  The Consolidated Statements of Cash Flows have been reclassified in 2013 and 2012 to conform to the 2014 presentation of all cash flow impacts of discontinued operations in a separate category in the statement below financing activities.
	USE OF ESTIMATES – In preparing the financial statements of the Company in conformity with U.S. generally accepted accounting principles, 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_

New Accounting Principles and Recent Accounting Pronouncements	12 Months Ended
	Dec. 31, 2014
New Accounting Principles and Recent Accounting Pronouncements [Abstract]
New Accounting Principles and Recent Accounting Pronouncements	Note B – New Accounting Principles and Recent Accounting Pronouncements
	The Company did not adopt any new accounting pronouncements in 2014 that had a significant effect on its consolidated financial statements.
	Recent Accounting Pronouncements
	Three new Accounting Standards Updates (ASU) were issued during 2014 by the Financial Accounting Standards Board (FASB) that must be adopted in the future.
	In August 2014, the FASB issued an ASU requiring, when applicable, disclosures regarding uncertainties about an entity’s ability to continue as a going concern.  During the preparation of quarterly and annual financial statements, management should evaluate whether conditions or events exist that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date the financial statements are issued.  If this evaluation indicates that it is probable that an entity will be unable to meet its obligations when they become due within one year of the financial statement issuance date, management must evaluate whether its mitigation plans will alleviate the substantial doubt of continuing as a going concern.  If substantial doubt exists, regardless of whether the mitigation plan alleviates the concern, additional disclosures are required in the financial statements addressing the conditions or events that raise substantial doubt, management’s evaluation of the significance of those conditions or events, and management’s mitigation plans.  This new guidance will become effective for the Company for all reporting periods beginning in 2016.  Early application is permitted.  Company management currently does not expect that this new guidance will have a significant effect on its consolidated financial statements when adopted.
	In May 2014, the FASB issued an ASU addressing recognition of revenue from contracts with customers.  When adopted, this guidance will supersede current revenue recognition rules currently followed by the Company.  The core principle of the new ASU is that an entity should recognize revenue to depict the transfer of promised goods or services to customers that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The ASU provides five steps for an entity to apply in recognizing revenue, including:  (1) identify the customer contract; (2) identify the contractual performance obligations; (3) determine the transaction price; (4) allocate the transaction price to the contractual performance obligations; and (5) recognize revenue when the performance obligation is satisfied.  The new ASU also requires additional disclosures regarding significant contracts with customers.  The new ASU will be effective for the Company on January 1, 2017, and early adoption is not permitted.  For transition purposes, the new ASU permits either (a) a retrospective application to all years presented, or (b) an alternative transition method whereby the new guidance is only applied to contracts not completed at the date of initial application.  The vast majority of the Company’s revenue is recognized when oil and natural gas produced by the Company is delivered and legal ownership of these products has transferred to the purchaser.  Based on the Company’s present understanding, the accounting for oil and gas sales revenue is not expected to be significantly altered by the new ASU.  The Company has not yet selected which transition method it will use.
	In April 2014, the FASB issued an ASU that will change the requirements for reporting discontinued operations after its adoption.  Under the new guidance, only disposals of components of an entity that represent a strategic shift that has or will have a major effect on an entity’s operations and financial results will be reported as discontinued operations in the financial statements.  Under prior guidance, a component of an entity that is a reportable segment, an operating segment, a reporting unit, a subsidiary, or an asset group that has been or will be eliminated from ongoing operations and for which the Company will not have any significant continuing involvement with the component after the disposal was generally reported as discontinued operations.  The FASB anticipates that fewer component disposals will be reported as discontinued operations under the new guidance.  The new guidance also requires expanded disclosures about discontinued operations.  The new guidance will be effective for the Company beginning in 2015.  The new guidance is not to be applied to a component that is classified as held for sale before the effective date of the guidance.

Discontinued_Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2014
Discontinued Operations [Abstract]
Discontinued Operations	Note C – Discontinued Operations
	Separation of U.S. Downstream Business
	On August 30, 2013, Murphy Oil Corporation (the “Company”) distributed 100% of the outstanding common stock of Murphy USA Inc. (“MUSA”) to its shareholders in a generally tax-free spin-off for U.S. federal income tax purposes.  After the close of the New York Stock Exchange on August 30, 2013, the Company’s shareholders of record as of 5:00 p.m. Eastern time on August 21, 2013 received one share of MUSA common stock for every four common shares of the Company held by such shareholders.  Prior to the separation, MUSA held all of the Company’s U.S. downstream operations, including retail gasoline stations and other marketing assets, plus two ethanol production facilities.  In connection with the separation, Murphy Oil USA, Inc., MUSA’s 100% owned primary operating subsidiary, distributed $650,000,000 to the Company in the form of a cash dividend.  The shares of MUSA common stock are traded on the New York Stock Exchange under the ticker symbol “MUSA.”  The Company has no continuing involvement with MUSA operations.  Accordingly, the operating results and the cash flows for these former U.S. downstream operations have been reported as discontinued operations for all periods presented in the consolidated financial statements.  These operations were formerly reported as the U.S. refining and marketing segment in prior years’ financial statements.
	In order to effect the separation and govern the Company’s relationship with MUSA after the separation, both parties entered into a series of agreements governing each party’s rights and obligations after the separation.  Among such agreements, the Separation and Distribution Agreement governs the separation of the U.S. downstream business, the transfer of assets, cross-indemnities between the Company and MUSA, handling of claims subject to indemnification and related matters, and other matters related to the Company’s relationship with MUSA.
	The Tax Matters Agreement governs the respective rights, responsibilities and obligations of the Company and MUSA with respect to taxes, tax attributes, tax returns, tax proceedings and certain other tax matters.  In addition, the Tax Matters Agreement imposes certain restrictions on MUSA and its subsidiaries (including restrictions on share issuances, business combinations, sales of assets and similar transactions) that are designed to preserve the tax-free status of the distribution.
	The Employee Matters Agreement governs the compensation and employee benefit obligations with respect to the current and former employees and non-employee directors of the Company and MUSA, and generally allocates liabilities and responsibilities relating to employee compensation, benefit plans and programs.  The Employee Matters Agreement provides that employees of MUSA will no longer participate in benefit plans sponsored or maintained by the Company.  In addition, the Employee Matters Agreement provides that each of the parties will be responsible for their respective current employees and compensation plans for such current employees, and that the Company will be responsible for liabilities relating to former employees who left prior to the separation.  The Employee Matters Agreement sets forth the general principles relating to employee matters and also addresses any special circumstances during the transition period.  The Employee Matters Agreement also provides that (i) the distribution does not constitute a change in control under existing plans, programs, agreements or arrangements, and (ii) the distribution and the assignment, transfer or continuation of the employment of employees with another entity will not constitute a severance event under the applicable plans, programs, agreements or arrangements.
	The Transition Service Agreement sets forth the terms on which the Company and MUSA will provide certain services or functions to the other party.  Transition services include administration, payroll, human resources, data processing, environmental health and safety, audit support, financial transaction support, and other support services, information technology systems and various other corporate services.  The agreement provides for the provision of specified services, generally for a period of up to 18 months, with a possible extension of six months (an aggregate of 24 months), on a full cost basis.
	Other Discontinued Operations
	The Company sold all of its U.K. oil and natural gas production assets during 2013, and recognized an after-tax gain of $216,147,000 on sale of these assets.  The results of these operations have been reported as discontinued operations for all periods presented in these consolidated financial statements.
	On September 30, 2014, the Company sold its U.K. retail marketing operations and associated inventories with total proceeds of $211,965,000.  The Company was unable to sell the Milford Haven, Wales, refinery after an extensive marketing effort proved unsuccessful.  The refinery ceased processing crude oil in May 2014, and the refinery portion of the Milford Haven facility is in the process of being decommissioned.  The Company is marketing for sale the products terminal portion of the Milford Haven facility along with three U.K. inland product terminals.  The Company has accounted for this U.K. downstream business as discontinued operations for all periods presented.
	The following table presents the carrying value of the major categories of assets and liabilities of discontinued operations associated with U.K. refining and marketing operations that are reflected on the Company’s consolidated balance sheets at December 31, 2014 and 2013:
	(Millions of dollars)	2014			2013
	Current assets
	Cash	$	200,512			301,302
	Accounts receivable		97,568			302,059
	Inventory		42,161			254,240
	Other		35,889			86,131
	Total current assets held for sale	$	376,130			943,732
	Non-current assets
	Property, plant and equipment, net	$	50,947			360,347
	Other		13			21,057
	Total non-current assets held for sale	$	50,960			381,404
	Current liabilities
	Accounts payable	$	59,023			484,082
	Other accrued taxes payable		40,653			130,028
	Accrued compensation and severance		30,872			17,020
	Refinery decommissioning cost		21,000			–
	Other		–			8,010
	Total current liabilities associated with	$	151,548			639,140
	assets held for sale
	Non-current liabilities
	Deferred income taxes payable	$	3,873			68,096
	Deferred credits and other liabilities		4,437			27,448
	Total non-current liabilities associated	$	8,310			95,544
	with assets held for sale
	In 2014 and 2013, the Company wrote down its net investment in the held for sale U.K. refining and marketing assets by $269,200,000 and $73,000,000, respectively.  The 2014 writedown was based on estimated salvage value of remaining refining and terminal assets as of the end of the year.  The 2013 write down was based on an assessment of the fair value of these assets based on the status of the ongoing sale process at that time.  The Company benefited in 2014 from a LIFO inventory liquidation credit of $209,600,000 and a gain on sale of the U.K. retail marketing assets of $101,700,000.  These charges and benefits have been included in the results of discontinued operations.
	Discontinued operations inventories accounted for under the LIFO method totaled $10,954,000 and $318,628,000 at December 31, 2014 and 2013, respectively, and these amounts were $44,881,000 and $268,608,000 less than such inventories would have been valued using the FIFO method.  These inventories are carried in Current Assets Held for Sale in the Consolidated Balance Sheets at December 31, 2014 and 2013.  In association with the shutdown of the Milford Haven, Wales, refinery in 2014, most crude oil inventories and a large portion of the refinery’s finished products were liquidated at market values.  This reduction in LIFO inventory reserve benefited discontinued operating results in 2014 as noted above.
	As of December 31, 2014, the Company has recorded an Asset Retirement Obligation (ARO) for its refining assets in the U.K. that are being decommissioned.  The ARO estimate for the U.K. assets is based on professional judgment associated with abandonment of major industrial assets, but is subject to change based on the availability of additional information in subsequent periods.  The ARO associated with the U.K. refinery abandonment of $21,000,000 is included in Other Current Liabilities Associated with Assets Held for Sale in the Consolidated Balance Sheet at December 31, 2014.
	At year-end 2012, the Company wrote down its net investment in the ethanol production facility in Hereford, Texas, taking an impairment charge of $60,988,000 in discontinued operations.  The write down was required based on expected weak ethanol production margins at the plant in future periods.  Fair value was determined using a discounted cash flow model for three years, plus an estimated terminal value based on a multiple of the last year’s cash flow.  Certain key assumptions used in the cash flow model included use of available futures prices for corn and ethanol products.  Additional key assumptions included estimated future ethanol and distillers grain production levels, estimated future operating expenses, and estimated sales prices for distillers grain.
	In July 2012, the United Kingdom enacted tax changes that limited tax relief on oil and gas decommissioning costs to 50%, a reduction from the 62% tax relief previously allowed for these costs.  This tax rate change led to a net reduction of income from discontinued operations of $5,523,000 in 2012.
	The results of operations associated with all discontinued operations are presented in the following table.
	(Thousands of dollars)	2014		2013		2012
	Revenues	$	2,786,394	17,586,236		24,156,748
	Income (loss) from operations before income taxes	$	-261,873	119,984		330,048
	Gain on sale before income taxes		101,684	130,991		–
	Total income (loss) from discontinued operations before taxes		-160,189	250,975		330,048
	Income tax expense (benefit)		-40,827	15,639		165,666
	Income (loss) from discontinued operations	$	-119,362	235,336		164,382

Inventories

Inventories	12 Months Ended
	Dec. 31, 2014
Inventories [Abstract]
Inventories	Note D – Inventories
	Inventories consisted of the following at December 31, 2014 and 2013.
		December 31,
		2014		2013
	(Thousands of dollars)
	Unsold crude oil	$	51,810	40,077
	Materials and supplies		190,923	254,118
		$	242,733	294,195

Property_Plant_and_Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2014
Property, Plant And Equipment [Abstract]
Property, Plant and Equipment	Note E – Property, Plant and Equipment
		31-Dec-14					31-Dec-13
	(Thousands of dollars)	Cost		Net			Cost		Net
	Exploration and production1	$	22,731,220	13,277,985	2		21,932,119		13,433,468	2
	Corporate and other		103,351	53,062			89,175		47,587
		$	22,834,571	13,331,047			22,021,294		13,481,055
	1  Includes mineral rights as follows:	$	924,253	410,482			1,007,920		489,578
	2  Includes $58,334 in 2014 and $48,691
	in 2013 related to administrative assets
	and support equipment.
	In December 2014, the Company sold 20% of its oil and gas assets in Malaysia and received net cash proceeds of $1,460,425,000.  The Company recorded an after-tax gain on this sale of $321,454,000 in 2014.
	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, 2014, 2013 and 2012, the Company had total capitalized drilling costs pending the determination of proved reserves of $120,455,000,  $393,030,000 and $445,697,000, respectively.  The following table reflects the net changes in capitalized exploratory well costs during the three-year period ended December 31, 2014.
	(Thousands of dollars)		2014	2013		2012
	Beginning balance at January 1	$	393,030	445,697		556,412
	Additions to capitalized exploratory well costs pending the		2,874	57,716		135,849
	determination of proved reserves
	Reclassifications to proved properties based on the		-91,236	-93,936		-165,377
	determination of proved reserves
	Reduction of capitalized exploratory well costs due to		-122,175	–		–
	partial asset sale in Malaysia
	Capitalized exploratory well costs charged to expense		-62,038	-16,447		-81,187
	Ending balance at December 31	$	120,455	393,030		445,697
	The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs has been capitalized since the completion of drilling.
		2014						2013					2012
	(Thousands of dollars)	Amount		No. of		No. of		Amount			No. of	No. of	Amount		No. of	No. of
				Wells		Projects					Wells	Projects			Wells	Projects
	Aging of capitalized
	well costs:
	Zero to one year	$	–	–		–		$	56,499		3	1	$	59,833	7	2
	One to two years		59,330	3		1			60,787		7	1		18,335	2	3
	Two to three years		6,606	3		–			–		–	–		83,314	9	4
	Three years or more		54,519	2		2			275,744		22	7		284,215	26	6
		$	120,455	8		3		$	393,030		32	9	$	445,697	44	15
	Of the $120,455,000 of exploratory well costs capitalized more than one year at December 31, 2014, $54,519,000 is in the U.S. and $65,936,000 is in Brunei.  In the U.S. further drilling is anticipated and development plans are being formulated.  In Brunei development options are under review for these multiple gas discoveries.  The capitalized well costs charged to expense in 2014 included four gas wells in Peninsula Malaysia and one well in the Gulf of Mexico.  The Company’s application to extend the gas holding period for the Malaysia wells was denied by the Malaysian government in 2014.  Development of the well in the Gulf of Mexico could not be justified due to the low prices for natural gas at year-end 2014.  The capitalized well costs charged to expense in 2013 included two wells offshore Sarawak Malaysia that were written off due to the Company’s decision not to move forward with development of the wells.  The capitalized well costs charged to expense in 2012 included a suspended well in the northern block of the Republic of the Congo that was written off following unsuccessful wildcat drilling in 2012 at a nearby prospect, two suspended wells offshore Sarawak Malaysia that were written off following a decision not to continue development of the wells, and a well drilled in the Gulf of Mexico in 2010 that the owners decided not to develop.
	At year-end 2014, the Company recorded an impairment writedown of property, plant and equipment in the amount of $14,267,000 related to one gas well in the Gulf of Mexico, and in 2013 an impairment writedown of $21,587,000 was recorded for properties in Western Canada.  At year-end 2012, Murphy determined that the Azurite field, offshore Republic of the Congo, was impaired due to removal of all proved oil reserves after an unsuccessful redrill of a key well in the field.  The impairment charge in 2012 totaled $200,000,000 and included a write-off of the remaining book value of the Azurite field plus other anticipated losses related to operations of the field.  Fair value was determined at these fields using a discounted cash flow model based on certain key assumptions, including future estimated net production levels, future estimated oil prices for the field based on year-end futures prices, and future estimated operating and capital expenditures.

Financing_Arrangements

Financing Arrangements	12 Months Ended
	Dec. 31, 2014
Long-term Debt [Abstract]
Financing Arrangements	Note F – Financing Arrangements
	At December 31, 2014, the Company had a $2.0 billion committed credit facility with a major banking consortium that expires in June 2017.  Borrowings under this facility bear interest at 1.25% above LIBOR based on the Company’s current credit rating as of December 31, 2014.  In addition, facility fees of 0.25% are charged on the full $2.0 billion commitment.  In May 2013, the Company increased the capacity of the committed credit facility from $1.5 billion to $2.0 billion and extended the maturity date by one year from June 2016 to June 2017.  At December 31, 2014, the Company had borrowings of $450,000,000 under this committed facility.  At December 31, 2014, the Company also had uncommitted credit lines that had estimated total borrowing capacity of approximately $435,000,000.  No borrowings were outstanding under these uncommitted credit lines at December 31, 2014.  If necessary, the Company could borrow funds under all or certain of these uncommitted lines with various financial institutions in future periods.  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 2015.

Longterm_Debt

Long-term Debt	12 Months Ended
	Dec. 31, 2014
Long-term Debt [Abstract]
Long-term Debt	Note G – Long-term Debt
		December 31,
	(Thousands of dollars)		2014	2013
	Notes payable
	2.50% notes, due 2017	$	550,000	550,000
	3.70% notes, due 2022		600,000	600,000
	4.00% notes, due 2022		500,000	500,000
	7.05% notes, due 2029		250,000	250,000
	5.125% notes, due 2042		350,000	350,000
	Notes payable to banks, 1.4375% at December 31, 2014		450,000	350,000
	Total notes payable		2,700,000	2,600,000
	Unamortized discount on notes payable		-4,953	-5,439
	Total notes payable, net of unamortized discount		2,695,047	2,594,561
	Capitalized lease obligation, due through June 2028		306,579	368,251
	Total debt including current maturities		3,001,626	2,962,812
	Current maturities		-465,388	-26,249
	Total long-term debt	$	2,536,238	2,936,563
	The amount of debt repayable over each of the next five years and thereafter are as follows:  $465,388,000 in 2015, $16,071,000 in 2016, $566,336,000 in 2017, $17,675,000 in 2018, $18,561,000 in 2019 and $1,917,595,000 thereafter.
	The capitalized lease obligation included in the above table is associated with production facilities at the Kakap field, offshore Sabah, Malaysia.  The facilities are utilized by the Company under a 25-year lease that extends through 2038.  Payments under this lease are owed through 2028.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013 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 2014 and 2013 is shown in the following table.
	(Thousands of dollars)	2014		2013
	Balance at beginning of year	$	880,003	751,583
	Accretion expense		50,778	48,996
	Liabilities incurred		70,568	172,048
	Revisions of previous estimates		8,278	-4,856
	Liabilities settled		-36,818	-51,647
	Liabilities assumed by purchaser of oil and gas assets		-69,416	–
	Liabilities assumed by Murphy USA Inc. upon separation		–	-15,401
	Changes due to translation of foreign currencies		-27,665	-20,720
	Balance at end of year		875,728	880,003
	Current portion of liability at end of year*		-34,202	-27,515
	Noncurrent portion of liability at end of year	$	841,526	852,488
	*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.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Taxes [Abstract]
Income Taxes	Note I – Income Taxes
	The components of income from continuing operations before income taxes for each of the three years ended December 31, 2014 and income tax expense attributable thereto were as follows.
	(Thousands of dollars)	2014		2013	2012
	Income (loss) from continuing operations before income taxes
	United States	$	179,484	-5,810	54,275
	Foreign		1,072,786	1,478,497	1,313,735
	Total	$	1,252,270	1,472,687	1,368,010
	Income tax expense (benefit)
	Federal – Current	$	25,151	-56,790	-256,931
	– Deferred		25,444	65,883	177,325
			50,595	9,093	-79,606
	State		8,840	7,141	8,104
	Foreign – Current		359,502	477,715	472,701
	– Deferred		-191,640	90,601	160,317
			167,862	568,316	633,018
	Total	$	227,297	584,550	561,516
	The following table reconciles income taxes based on the U.S. statutory tax rate to the Company’s income tax expense.
	(Thousands of dollars)	2014		2013	2012
	Income tax expense based on the U.S. statutory tax rate	$	438,295	515,440	478,804
	Foreign income subject to foreign tax rates different than		20,562	31,752	7,710
	the U.S. statutory rate
	State income taxes, net of federal benefit		5,746	4,642	5,268
	U.S. tax benefit on certain foreign upstream investments		-95,838	-133,526	-108,077
	Deferred tax benefit on sale of Malaysian assets		-176,661	–	–
	Increase in deferred tax asset valuation allowance related		37,712	129,588	87,558
	to other foreign exploration expenditures
	Impairment or abandonment of Azurite field with no tax benefit		–	35,475	70,000
	Other, net		-2,519	1,179	20,253
	Total	$	227,297	584,550	561,516
	An analysis of the Company’s deferred tax assets and deferred tax liabilities at December 31, 2014 and 2013 showing the tax effects of significant temporary differences follows.
	(Thousands of dollars)	2014		2013
	Deferred tax assets
	Property and leasehold costs	$	379,577	708,947
	Liabilities for dismantlements		85,544	79,111
	Postretirement and other employee benefits		208,600	175,446
	Alternative minimum tax		46,792	49,536
	Foreign tax credit carryforwards		44,061	19,896
	Other deferred tax assets		22,426	23,352
	Total gross deferred tax assets		787,000	1,056,288
	Less valuation allowance		-306,463	-633,735
	Net deferred tax assets		480,537	422,553
	Deferred tax liabilities
	Property, plant and equipment		-479,677	-747,561
	Accumulated depreciation, depletion and amortization		-1,123,864	-1,040,251
	Other deferred tax liabilities		-15,753	-38,849
	Total gross deferred tax liabilities		-1,619,294	-1,826,661
	Net deferred tax liabilities	$	-1,138,757	-1,404,108
	In management’s judgment, the net deferred tax assets in the preceding table will more likely than not be realized as reductions of future taxable income or by utilizing available tax planning strategies.  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 not likely to be realized.  The foreign tax credit carryforwards expire in 2015 through 2024.  The valuation allowance decreased $327,272,000 in 2014.  The deferred tax valuation allowance decreased by $65,384,000 in 2014 due to sanction of the Block H development plan, which allowed recognition of deferred tax benefits that were fully reserved in prior years.  Additionally, the decrease included realization of U.S. tax benefits related to certain foreign upstream investments where the Company has exited.  The remainder of the valuation allowance reduction offset changes in certain deferred tax assets.  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 not recognized a deferred tax liability for undistributed earnings of its Canadian, Malaysian and certain other foreign subsidiaries because such earnings are considered indefinitely reinvested in foreign countries.  As of December 31, 2014, undistributed earnings of the Company’s subsidiaries considered indefinitely reinvested were approximately $6,045,000,000.  The unrecognized deferred tax liability is dependent on many factors including withholding taxes under current tax treaties and foreign tax credits and is estimated to be approximately $684,000,000.  The Company does not consider undistributed earnings from certain other international operations to be indefinitely reinvested; however, any estimated tax liabilities upon repatriation of earnings from these international operations are expected to be offset with foreign tax credits.  Although the Company does not foresee repatriating earnings considered indefinitely reinvested, under present law, it would incur a 5% withholding tax on any monies repatriated from Canada to the United States.
	During 2014, the Company sold its U.K. retail marketing assets as well as 20% of its oil and gas assets in Malaysia.  Following these sales, the Company repatriated cash from the U.K. and Malaysia of $250,000,000 and $1,700,000,000, respectively.  Foreign tax credits were available to cover most of the U.S. income taxes associated with these repatriated funds.  The Company continues to assert that the previously generated earnings in Malaysia are indefinitely reinvested as of December 31, 2014.
	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 audit by the applicable taxing authority.  If this threshold is met, the tax benefit is then measured and recognized at the largest amount that is greater than 50 percent 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 Sheet.  A reconciliation of the beginning and ending amount of the consolidated liability for unrecognized income tax benefits during the three years ended December 31, 2014 is shown in the following table.
	(Thousands of dollars)	2014		2013	2012
	Balance at January 1	$	6,366	16,611	18,857
	Additions for tax positions related to current year		988	2,486	1,258
	Settlements due to lapse of time		-1,225	-12,731	-3,504
	Foreign currency translation effect		-118	–	–
	Balance at December 31	$	6,011	6,366	16,611
	All additions or reductions 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, 2014 and 2013 for interest and penalties of $142,000 and $146,000, respectively, associated with uncertain tax positions.  Income tax expense for the years ended December 31, 2014, 2013 and 2012 included net benefits for interest and penalties of $4,000,  $829,000 and $1,000, respectively, associated with uncertain tax positions.
	During the next twelve months, the Company currently expects to add between $1,000,000 and $2,000,000 to the liability for uncertain taxes for 2015 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 Income during 2015.
	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, 2014, the earliest years remaining open for audit and/or settlement in the Company’s major taxing jurisdictions are as follows:  United States – 2011; Canada – 2008; United Kingdom – 2012; and Malaysia – 2007.

Incentive_Plans

Incentive Plans	12 Months Ended
	Dec. 31, 2014
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 financial statements 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.
	In 2012, the Company’s shareholders approved replacement of the 2007 Annual Incentive Plan (2007 Annual Plan) and the 2007 Long-Term Incentive Plan (2007 Long-Term Plan) with the 2012 Annual Incentive Plan (2012 Annual Plan) and 2012 Long-Term Incentive Plan (2012 Long-Term Plan), respectively.  All awards to employees on or after May 9, 2012 have been made under the respective 2012 plans.
	The 2012 Annual Plan and the 2007 Annual Plan authorize 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 and 2007 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 and the 2007 Long-Term Plan authorize 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 8,700,000 shares are issuable during the life of the 2012 Long-Term Plan, with annual grants limited to 1% of Common shares outstanding; allowed shares not granted may be granted in future years.  Based on awards made to date, approximately 5,481,000 shares remained available for grant under the 2012 Long-Term Plan at December 31, 2014.  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)	2014			2013		2012
	Compensation charged against income before	$	53,157		66,976		46,694
	income tax benefit
	Related income tax benefit recognized in income		15,604		19,321		14,443
	As of December 31, 2014, there was $46,024,000 in compensation costs to be expensed over approximately the next two years related to unvested share-based compensation arrangements granted by the Company.  Beginning January 1, 2014, employees will receive net shares, after applicable statutory withholding taxes, upon each stock option exercise.  Cash received from options exercised under all share-based payment arrangements for the years ended December 31, 2013 and 2012 was $2,395,000 and $10,375,000, respectively.  Total income tax benefits realized from tax deductions related to stock option exercises under share-based payment arrangements were $5,364,000,  $7,435,000 and $5,920,000 for the years ended December 31, 2014, 2013 and 2012, respectively.
	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 the 2012 Long-Term Plan and the 2007 Long-Term Plan, 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.
		2014		2013		2012
	Fair value per option grant	$12.84		$15.81 – $20.62		$12.37 – $17.74
	Assumptions
	Dividend yield	2.00%		2.10% – 2.30%		1.80% – 2.27%
	Expected volatility	29.00%		34.00% – 36.00%		39.00% – 39.62%
	Risk-free interest rate	1.62%		0.96% – 2.00%		0.55% – 0.77%
	Expected life	5.35 yrs.		5.25 yrs. – 6.50 yrs.		4.00 yrs. – 5.20 yrs.
	Changes in stock options outstanding during the last three years are presented in the following table.
		Number of		Average
		Shares		Exercise
				Price
	Outstanding at December 31, 2011	5,434,228		$	55.17
	Granted at FMV	1,870,500			57.96
	Exercised	-823,855			38.37
	Forfeited	-573,514			60.43
	Outstanding at December 31, 2012	5,907,359			55.17
	Granted at FMV	1,320,176			55.26
	Exercised	-1,335,355			45.84
	Forfeited	-228,576			58.01
	Surrendered in connection with separation of Murphy USA Inc.	-272,936			55.99
	Murphy USA Inc. spin-off adjustment	615,917			52.09
	Outstanding at December 31, 2013	6,006,585			56.80
	Granted at FMV	772,900			55.82
	Exercised	-862,407			49.27
	Forfeited	-314,828			54.53
	Outstanding at December 31, 2014	5,602,250			57.95
	Exercisable at December 31, 2011	2,319,735		$	51.14
	Exercisable at December 31, 2012	2,474,636			54.43
	Exercisable at December 31, 2013	2,435,322			51.79
	Exercisable at December 31, 2014	3,030,105			53.10
	Additional information about stock options outstanding at December 31, 2014 is shown below.
			Options Outstanding						Options Exercisable
	Range of Exercise		No. of		Avg. Life		Aggregate		No. of	Avg. Life	Aggregate
	Prices per Option		Options		Remaining		Intrinsic		Options	Remaining	Intrinsic
					in Years		Value			in Years	Value
	$37.44 to $39.02		444,524		2.4		$	5,533,247	356,103	1.9	$	4,516,795
	$43.88 to $51.63		1,772,764		1.8			2,786,024	1,162,708	2.4		2,786,024
	$54.21 to $63.46		3,384,962		4			–	1,511,294	2.1		–
			5,602,250		3.6		$	8,319,271	3,030,105	2.4	$	7,302,819
	The total intrinsic value of options exercised during 2014, 2013 and 2012 was $12,003,000,  $25,284,000 and $17,197,000, respectively.  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 Common stock.
	In February 2013, the Committee reduced the exercise price of all outstanding stock options by $2.50 per share to reflect the impact of the special dividend of the same amount paid in December 2012.  The exercise prices in the preceding tables beginning in 2013 reflect this $2.50 reduction in exercise price approved in 2013.  The income statement effect of this reduced exercise price was an expense of $6,454,000 in 2013.
	In order to preserve the economic value of unexercised stock options following the spin-off of Murphy USA Inc. on August 30, 2013, the number of outstanding stock options was increased by 10.7% and the exercise price of stock options was reduced by 10.7%.  The number of options and the exercise prices in the preceding tables reflect these adjustments related to the MUSA spin-off.  There was no immediate impact on the expense for stock options recognized in 2013 related to this exercise price adjustment.
	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 or the 2007 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.
	Upon the separation of Murphy USA Inc. on August 30, 2013, adjustments to outstanding PRSUS were made to the number of units outstanding to preserve the economic value of these awards.
	Changes in PRSUS outstanding for each of the last three years are presented in the following table.
	(Number of share units)	2014		2013		2012
	Outstanding at beginning of year	1,560,292		1,426,238		1,174,492
	Granted	464,300		521,776		653,355
	Awarded	-473,186		-380,150		-260,175
	Forfeited	-154,366		-39,573		-141,434
	Surrendered in connection with	–		-116,568		–
separation of Murphy USA Inc.
Murphy USA Inc. spin-off adjustment	–		148,569		–
Outstanding at end of year	1,397,040		1,560,292		1,426,238
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 2014, 2013 and 2012 are presented in the following table.
	2014		2013		2012
Fair value per share at grant date	$33.90 – $51.30		$39.50 – $68.01		$54.90 – $63.64
Assumptions
Expected volatility	29.00%		31.00% – 32.00%		37.00%
Risk-free interest rate	0.65%		0.41% – 0.62%		0.30%
Stock beta	0.843		0.907 – 0.908		0.913
Expected life	3.0 yrs.		3.0 yrs.		3.0 yrs.
TIME-LAPSE RESTRICTED STOCK UNITS – Time-lapsed restricted stock units (TSUS) have been granted to the Company’s Non-Employee Directors under the Directors Plan and, beginning in 2014, 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 $55.20 to $60.85 per share in 2014,  $60.30 to $69.67 per share in 2013, and $59.33 per share in 2012.  To retain economic value at the time of spin-off of Murphy USA Inc., the number of TSUS was increased by 10.7% for each unit outstanding on August 30, 2013.
Changes in TSUS outstanding for each of the last three years are presented in the following table.
(Number of share units)	2014		2013		2012
Outstanding at beginning of year	112,881		98,477		116,724
Granted	278,892		38,184		42,256
Vested and issued	-54,884		-34,696		-44,980
Forfeited	-15,100		–		-15,523
Murphy USA Inc. spin-off adjustment	–		10,916		–
Outstanding at end of year	321,789		112,881		98,477
EMPLOYEE STOCK PURCHASE PLAN (ESPP) – The Company has an ESPP under which the Company’s Common stock can be purchased by eligible U.S. and Canadian employees.  Each quarter, an eligible employee may elect 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 will terminate on the earlier of the date that employees have purchased all 980,000 authorized shares or June 30, 2017.  Employee stock purchases under the ESPP were 6,739 shares at an average price of $56.22 per share in 2014, 16,020 shares at an average price of $54.14 per share in 2013 and 24,418 shares at an average price of $48.54 per share in 2012.  At December 31, 2014,  280,202 shares remained available for sale under the ESPP.  Compensation costs related to the ESPP are estimated based on the value of the 10% discount and the fair value of the option that provides for the refund of participant withholdings, and such expenses were $55,000 in 2014, $143,000 in 2013 and $272,000 in 2012.  The fair value per share issued under the ESPP was approximately $6.49,  $6.72 and $7.30 for the years ended December 31, 2014, 2013 and 2012, 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 and TRSUC and Phantom units are generally settled on the third anniversary of the 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 Income for all cash-settled stock-based awards was $9,667,000 in 2014, $9,436,000 in 2013 and $552,000 in 2012.
Upon the separation of Murphy USA Inc. on August 30, 2013, adjustments to outstanding PRSUC were made to the number of units outstanding to preserve the economic value of these awards.
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 $38,000,000,  $53,250,000 and $32,417,000 was recorded in 2014, 2013 and 2012, respectively, for these plans.

Employee_and_Retiree_Benefit_P

Employee and Retiree Benefit Plans	12 Months Ended
	Dec. 31, 2014
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.
	Effective with the spin-off of Murphy’s former U.S. retail marketing operation, Murphy USA Inc. (MUSA), on August 30, 2013, significant modifications were made to the U.S. defined benefit pension plan.  Certain Murphy employees’ benefits under the U.S. plan were frozen at that time.  No further benefit service will accrue for the affected employees, however, the plan will recognize future earnings after the spin-off.  In addition, all previously unvested benefits became fully vested at the spin-off date.  For those affected active employees of the Company, additional U.S. retirement plan benefits will accrue in future periods under a cash balance formula.  Additionally, new hires of Murphy after the MUSA spin-off are not eligible to participate in the Company’s postretirement health care and life insurance benefit plans.  Upon the spin-off of MUSA, Murphy retained all vested pension defined benefit and other postretirement benefit obligations associated with current and former employees of this separated business.  No additional benefit will accrue for any employees of MUSA under the Company’s retirement plans after the spin-off date.
	Generally accepted accounting principles require 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 comprehensive income.
	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, 2014 and 2013 and a statement of the funded status as of December 31, 2014 and 2013.
		Pension					Other
		Benefits					Postretirement
							Benefits
	(Thousands of dollars)	2014			2013		2014		2013
	Change in benefit obligation
	Obligation at January 1	$	707,254		721,531		107,001		124,134
	Service cost		22,470		26,346		2,459		4,566
	Interest cost		33,680		30,903		4,617		5,189
	Plan amendments		–		1,989		–		–
	Participant contributions		5		21		1,406		1,376
	Actuarial loss (gain)		122,824		-9,876		8,150		-8,324
	Medicare Part D subsidy		–		–		404		384
	Exchange rate changes		-14,614		1,852		-55		-36
	Benefits paid		-35,044		-38,745		-5,486		-5,211
	Special termination benefits		–		849		–		–
	Curtailments		-11,023		-26,463		–		-15,077
	Obligation assumed by MUSA at separation		–		-1,153		–		–
	Obligation at December 31		825,552		707,254		118,496		107,001
	Change in plan assets
	Fair value of plan assets at January 1		533,108		463,546		–		–
	Actual return on plan assets		31,340		61,932		–		–
	Employer contributions		47,279		46,726		3,676		3,451
	Participant contributions		5		21		1,406		1,376
	Medicare Part D subsidy		–		–		404		384
	Exchange rate changes		-13,284		1,594		–		–
	Benefits paid		-35,044		-38,745		-5,486		-5,211
	Other		-2,426		-1,966		–		–
	Fair value of plan assets at December 31		560,978		533,108		–		–
	Funded status and amounts recognized in the
	Consolidated Balance Sheets at December 31
	Deferred charges and other assets		7,899		10,254		–		–
	Other accrued liabilities		-5,996		-5,565		-5,515		-5,920
	Deferred credits and other liabilities		-252,237		-158,589		-112,981		-101,081
	Liabilities associated with assets held for sale		-14,240		-20,246		–		–
	Funded status and net plan liability recognized	$	-264,574		-174,146		-118,496		-107,001
	at December 31
	The significant actuarial loss in 2014 for pension benefits was primarily due to a combination of a lower discount rate and new actuarial mortality assumptions adopted by the Society of Actuaries in 2014.  The new mortality assumptions reflect the expectation of generally longer lives for U.S. participants based on the latest study by the Society of Actuaries.
	At December 31, 2014, amounts included in accumulated other comprehensive loss (AOCL), 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			Other
		Benefits			Postretirement
					Benefits
	Net actuarial loss	$	-256,821		-21,948
	Prior service (cost) credit		-2,456		289
		$	-259,277		-21,659
	Amounts included in AOCL at December 31, 2014 that are expected to be amortized into net periodic benefit expense during 2015 are shown in the following table.
	(Thousands of dollars)	Pension			Other
		Benefits			Postretirement
					Benefits
	Net actuarial loss	$	-16,706		-778
	Prior service (cost) credit		-854		82
		$	-17,560		-696
	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					Accumulated				Fair Value
		Benefit Obligations					Benefit Obligations				of Plan Assets
	(Thousands of dollars)	2014			2013		2014		2013		2014		2013
	Funded qualified plans where	$	658,618		571,217		597,918		520,610		533,165		502,308
	accumulated benefit obligation
	exceeds fair value of plan assets
	Unfunded nonqualified and directors'		147,018		115,492		127,200		102,198		–		–
plans where accumulated benefit
obligation exceeds fair value of
plan assets
Unfunded other postretirement plans		118,496		107,001		118,496		107,001		–		–
The table that follows provides the components of net periodic benefit expense for each of the three years ended December 31, 2014.
	Pension Benefits							Other
								Postretirement Benefits
(Thousands of dollars)		2014		2013		2012		2014		2013		2012
Service cost	$	22,470		26,346		23,500		2,459		4,566		3,958
Interest cost		33,680		30,903		29,869		4,617		5,189		5,174
Expected return on plan assets		-33,723		-28,974		-25,826		–		–		–
Amortization of prior service		899		1,006		1,254		-82		-143		-173
cost (credit)
Amortization of transitional		-480		-514		-529		–		8		8
(asset) liability
Recognized actuarial loss		9,471		17,338		16,389		5		1,484		1,317
		32,317		46,105		44,657		6,999		11,104		10,284
Termination benefits expense		–		849		6,177		–		–		–
Curtailment expense (benefit)		–		1,365		–		–		-442		–
Net periodic benefit expense	$	32,317		48,319		50,834		6,999		10,662		10,284
Termination and curtailment expenses in 2013 primarily related to plan amendments made at the time of separation of Murphy USA Inc.  The termination benefits expense in 2012 was primarily related to enhanced retirement benefits provided to a former executive officer.
The preceding tables in this note include the following amounts related to foreign benefit plans.
	Pension					Other
	Benefits					Postretirement
						Benefits
(Thousands of dollars)	2014			2013		2014		2013
Benefit obligation at December 31	$	222,497		211,799		648		541
Fair value of plan assets at December 31		202,305		188,575		–		–
Net plan liabilities recognized		20,192		23,224		648		541
Net periodic benefit expense		12,968		12,622		152		92
The following table provides the weighted-average assumptions used in the measurement of the Company’s benefit obligations at December 31, 2014 and 2013 and net periodic benefit expense for 2014 and 2013.
	Benefit Obligations								Net Periodic Benefit Expense
	Pension				Other				Pension				Other
	Benefits				Postretirement				Benefits				Postretirement
					Benefits								Benefits
	31-Dec				31-Dec				Year				Year
	2014		2013		2014		2013		2014		2013		2014	2013
Discount rate	3.94%		4.78%		4.12%		4.91%		4.56%		4.23%		4.91%	4.18%
Expected return on plan assets	6.11%		6.24%		–		–		6.11%		6.24%		–	–
Rate of compensation increase	3.69%		4.14%		–		–		3.69%		4.12%		–	–
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			Other
	Benefits			Postretirement
				Benefits
2015	$	33,516		6,349
2016		34,212		6,573
2017		35,144		6,730
2018		36,439		6,943
2019		37,671		7,225
2020-2024		208,294		40,535
For purposes of measuring postretirement benefit obligations at December 31, 2014, the future annual rates of increase in the cost of health care were assumed to be 7.2% for 2015 decreasing each year to an ultimate rate of 4.5% in 2028 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	$	1,190		-942
benefit expense for the year ended December 31, 2014
Effect on the health care component of the accumulated postretirement benefit		17,879		-14,456
obligation at December 31, 2014
During 2014, the Company made contributions of $27,948,000 to its domestic defined benefit pension plans, $19,331,000 to its foreign defined benefit pension plans, $3,641,000 to its domestic postretirement benefits plan and $35,000 to its foreign postretirement benefits plan.  The Company currently expects during 2015 to make contributions of $40,045,000 to its domestic defined benefit pension plans, $18,739,000 to its foreign defined benefit pension plans, $5,481,000 to its domestic postretirement benefits plan and $36,000 to its foreign postretirement benefits plan.
U.S. Health Care Reform – In March 2010, the United States Congress enacted a health care reform law.  Along with other provisions, the law (a) eliminated the tax free status of federal subsidies to companies with qualified retiree prescription drug plans that are actuarially equivalent to Medicare Part D plans beginning in 2013; (b) imposes a 40% excise tax on high-cost health plans as defined in the law beginning in 2018; (c) eliminated lifetime or annual coverage limits and required coverage for preventative health services beginning in September 2010; and (d) imposed a fee of $2 (subsequently adjusted for inflation) for each person covered by a health insurance policy beginning in September 2010.  The Company provides a health care benefit plan to eligible U.S. employees and most U.S. retired employees.  The law did not significantly affect the Company’s consolidated financial statements as of December 31, 2014, 2013 and 2012 and for the years then ended.  The Company continues
to evaluate the various components of the law as guidance is issued and cannot predict with certainty all the ways it may impact the Company.  However, based on information available to date, the Company currently believes that the health care reform law will not have a material effect on its financial condition, net income or cash flow in future periods.
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 Board of Directors.  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 an investment consultant to manage the assets of the plan within the parameters of the Investment Policy Implementation Document (Document).  The objective of investments is to earn a reasonable return within the allocation strategy permitted in the Document while limiting the risk for the funded position of the plan.  The Document specifies a strategy with an allocation goal of 60% equities and 40% bonds.  The Document allows for ranges of equity investments from 27% to 98%, fixed income securities may range from 25% to 60%, and cash can be held for up to 5% of investments.  Approximately one-half of the equity allocation is to be invested in U.K. securities and the remainder split between North American, European, Japanese and other Pacific Basin securities.  A minimum of 95% of the fixed income allocation is to be invested in U.K. securities with up to 5% in international or high yield bonds. Tolerance ranges are specified in the Document within the general equity/bond allocation guidelines.  Asset performance is compared to a benchmark return based on the allocation guidelines and is targeted to outperform the benchmark by 0.75% per annum over a rolling three-year period.  Small working cash balances are permitted to facilitate daily management of payments and receipts within the plan.  The trustees routinely review 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 includes total equity securities of 60% with a range of 40% to 75% of total assets.  Fixed income securities have a normal allocation of 35% with a range of 25% to 45%.  Cash will normally have an allocation of 5% with a range of 0% to 15%.  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, 2014 and 2013 are presented in the following table.
	December 31,
	2014			2013
Equity securities	66.6	%		68.4	%
Fixed income securities	32.5			30.7
Cash equivalents	0.9			0.9
	100.0	%		100.0	%
The Company’s weighted average expected return on plan assets was 6.11% in 2014 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 6.11% expected return was based on an expected average future equity securities return of 7.72% and a fixed income securities return of 4.04% and is net of average expected investment expenses of 0.53%.  Over the last 10 years, the return on funded retirement plan assets has averaged 6.93%.
At December 31, 2014, 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			Quoted Prices		Significant		Significant
	31-Dec-14			in Active Markets		Other Observable		Unobservable
				for Identical Assets		Inputs		Inputs
				(Level 1)		(Level 2)		(Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	67,863		67,863		–		–
U.S. small/midcap		33,709		33,709		–		–
Hedged funds and other		52,905		–		18,953		33,952
alternative strategies
International commingled		75,702		–		75,702		–
trust fund
Emerging market commingled		19,908		–		19,908		–
equity fund
Fixed income securities:
U.S. fixed income		80,577		–		80,577		–
International commingled		17,559		–		17,559		–
trust fund
Emerging market mutual fund		8,069		–		8,069		–
Cash and equivalents		2,381		2,381		–		–
Total Domestic Plans		358,673		103,953		220,768		33,952
Foreign Plans
Equity securities funds		106,694		–		106,694		–
Fixed income securities funds		66,435		–		66,435		–
Diversified pooled fund		27,813		–		27,813		–
Cash and equivalents		1,363		1,363		–		–
Total Foreign Plans		202,305		1,363		200,942		–
Total	$	560,978		105,316		421,710		33,952
At December 31, 2013, 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			Quoted Prices		Significant		Significant
	31-Dec-13			in Active Markets		Other Observable		Unobservable
				for Identical Assets		Inputs		Inputs
				(Level 1)		(Level 2)		(Level 3)
Domestic Plans
Equity securities:
U.S. core equity	$	89,255		89,255		–		–
U.S. small/midcap		37,149		37,149		–		–
Hedged funds and other		32,788		–		–		32,788
alternative strategies
International commingled		77,041		–		77,041		–
trust fund
Emerging market commingled		9,654		–		9,654		–
equity fund
Fixed income securities:
U.S. fixed income		72,240		–		72,240		–
International commingled		14,865		–		14,865		–
trust fund
Emerging market mutual fund		8,549		–		8,549		–
Cash and equivalents		2,992		2,992		–		–
Total Domestic Plans		344,533		129,396		182,349		32,788
Foreign Plans
Equity securities funds		99,085		–		99,085		–
Fixed income securities funds		57,030		–		57,030		–
Diversified pooled fund		30,800		–		30,800		–
Cash and equivalents		1,660		1,660		–		–
Total Foreign Plans		188,575		1,660		186,915		–
Total	$	533,108		131,056		369,264		32,788
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 three 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, 2012		$	14,654
Actual return on plan assets:
Relating to assets held at the reporting date			3,134
Relating to assets sold during the period			–
Purchases, sales and settlements			15,000
Total at December 31, 2013			32,788
Actual return on plan assets:
Relating to assets held at the reporting date			1,164
Relating to assets sold during the period			–
Purchases, sales and settlements			–
Total at December 31, 2014		$	33,952
THRIFT PLANS – Most full-time U.S. and U.K. 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 $10,229,000 in 2014, $13,839,000 in 2013 and $12,594,000 in 2012.

Financial_Instruments_and_Risk

Financial Instruments and Risk Management

12 Months Ended

Dec. 31, 2014

Financial Instruments and Risk Management [Abstract]

Financial Instruments and Risk Management

Note L – Financial Instruments and Risk Management

DERIVATIVE INSTRUMENTS – Murphy uses derivative instruments to manage certain risks related to commodity prices, interest rates and foreign currency exchange 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 Income.  Certain interest rate derivative contracts were accounted for as hedges and the gain or loss associated with recording the fair value of these contracts was deferred in Accumulated Other Comprehensive Income (Loss) 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 2014, the Company had West Texas Intermediate (WTI) crude oil price swap financial contracts to hedge a portion of its Eagle Ford Shale production for 2014.  Under these contracts, which matured monthly, the Company paid the average monthly price in effect and received the fixed contract prices.  At December 31, 2014, $23,168,000 is included in accounts receivable for final settlement of 2014 contracts.  There were no open WTI contracts at year-end 2014 with maturity dates in 2015 or thereafter.

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, 2014 and 2013, short-term derivative instruments were outstanding in Canada for approximately $21,000,000 and $32,300,000, respectively, to manage the currency risk of U.S. dollar accounts receivable balances associated with sale of Canadian crude oil in both years and a U.S. dollar intercompany accounts receivable balance at year-end 2013.  The fair values of open foreign currency derivative contracts were liabilities of  $25,000 at December 31, 2014 and $26,000 at December 31, 2013.

At December 31, 2014 and 2013, the fair value of derivative instruments not designated as hedging instruments are presented in the following table.

31-Dec-14

31-Dec-13

Asset Derivatives

Liability Derivatives

Asset Derivatives

Liability Derivatives

(Thousands of dollars)

Balance

Fair

Balance

Fair

Balance

Fair

Balance

Fair

Sheet

Value

Sheet

Value

Sheet

Value

Sheet

Value

Location

Location

Location

Location

Type of

Derivative Contract

Commodity

Accounts

$

–

–

Accounts

$

–

–

Receivable

23,168

Receivable

1,970

Foreign exchange

–

–

Accounts

$

–

–

Accounts

$

Payable

25

Payable

1,038

For the years ended December 31, 2014 and 2013, the gains and losses recognized in the Consolidated Statements of Income for derivative instruments not designated as hedging instruments are presented in the following table.

Year Ended December 31, 2014

Year Ended December 31, 2013

(Thousands of dollars)

Location of

Amount of

Location of

Amount of

Gain (Loss)

Gain (Loss)

Gain (Loss)

Gain (Loss)

Recognized

Recognized

Recognized

Recognized

in Income

in Income

in Income

in Income

on Derivative

on Derivative

on Derivative

on Derivative

Type of

Derivative Contract

Commodity

Sale and Other

$

17,887

Sale and Other

$

2,104

Operating Revenues

Operating Revenues

Commodity

–

–

Discontinued

-1,604

Operations

Foreign exchange

Interest and

4,226

Interest and

-5,162

Other Income

Other Income

$

22,113

$

-4,662

Interest Rate Risks – In 2011 the Company entered into a series of derivative contracts known as forward starting interest rate swaps to manage interest rate risk associated with $350,000,000 of notes that were sold in 2012.  These interest rate swaps matured in May 2012.  Under hedge accounting rules, the Company deferred a loss on these contracts to match the payment of interest on these notes through 2022.  During 2014, 2013 and 2012,  $2,963,000,  $2,963,000 and $1,852,000, respectively, of the deferred loss on the interest rate swaps was charged to interest expense in the Consolidated Statements of Income.  The remaining loss deferred on these matured contracts at December 31, 2014 was $21,852,000, which is recorded, net of income taxes of $7,648,000, in Accumulated Other Comprehensive Income (Loss) in the Consolidated Balance Sheet.  The Company expects to charge approximately $2,963,000 of this deferred loss to income in the form of interest expense during 2015.

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, 2014
Equity [Abstract]
Stockholders' Equity	Note M – Stockholders’ Equity
	On December 3, 2012, the Company paid a special dividend of $2.50 per outstanding Common share to shareholders of record on November 16, 2012.  This dividend totaled $486,141,000.
	In October 2012, the Company announced authorization of a share buyback program of up to $1.0 billion.  This share repurchase program was completed in early 2014.  In 2014, the Company announced two share buyback programs.  The first program announced on May 20, 2014 totaled $125 million and was completed in August 2014.  The second and larger program totaling up to $500 million was announced on August 6, 2014 and is still open.  No shares have been acquired through year-end 2014 under this $500 million program that expires in August 2015.  Future share repurchases could be carried out by utilization of a number of different methods, including but not limited to, open market purchases, accelerated share repurchases and negotiated block purchases, and some of the repurchases may be effected through Rule 10b5-1 plans.  The shares acquired under the various buyback programs are carried as Treasury Stock in the Consolidated Balance Sheet.

Earnings_per_Share

Earnings per Share	12 Months Ended
	Dec. 31, 2014
Earnings per Share [Abstract]
Earnings per Share	Note N – Earnings per Share
	The following table reconciles the weighted-average shares outstanding for computation of basic and diluted income per Common share for each of the three years ended December 31, 2014.  No difference existed between net income used in computing basic and diluted income per Common share for these years.
	(Weighted-average shares outstanding)	2014	2013	2012
	Basic method	178,852,942	187,921,062	193,902,335
	Dilutive stock options	1,218,042	1,350,336	766,402
	Diluted method	180,070,984	189,271,398	194,668,737
	The following table reflects certain options to purchase shares of common stock that were outstanding during the three years ended December 31, 2014, but were not included in the total of dilutive stock options above because the incremental shares from assumed conversion were antidilutive.
		2014	2013	2012
	Antidilutive stock options excluded from diluted shares	1,893,364	1,026,900	3,329,689
	Weighted average price of these options	$	$	$
		55.21	54.54	64.72

Other_Financial_Information

Other Financial Information	12 Months Ended
	Dec. 31, 2014
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Other Financial Information	Note O – Other Financial Information
	GAIN FROM FOREIGN CURRENCY TRANSACTIONS – Net gains from foreign currency transactions, including the effects of foreign currency contracts, included in the Consolidated Statements of Income were $40,596,000 in 2014, $73,732,000 in 2013 and $5,092,000 in 2012.
	CASH FLOW DISCLOSURES – Cash income taxes paid were $573,799,000,  $457,006,000 and $566,999,000 in 2014, 2013 and 2012, respectively.  Interest paid, net of amounts capitalized, was $114,232,000,  $60,501,000 and $9,501,000 in 2014, 2013 and 2012, respectively.
	Noncash operating working capital (increased) decreased during each of the three years ended December 31, 2014 as shown in the following table.
	(Thousands of dollars)	2014		2013	2012
	Accounts receivable	$	175,820	224,281	-382,137
	Inventories		25,697	14,166	-94,907
	Prepaid expenses		6,575	195,013	-245,881
	Deferred income tax assets		6,884	15,510	-7,218
	Accounts payable and accrued liabilities		-54,785	-176,543	534,353
	Current income tax liabilities		-163,920	-6,098	27,610
	Net (increase) decrease in noncash	$	-3,729	266,329	-168,180
	operating working capital

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss)	Note P – Accumulated Other Comprehensive Income (Loss)
	The components of Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheets at December 31, 2014 and December 31, 2013 and the changes during 2013 and 2014 are presented net of taxes in the following table.
	(Thousands of dollars)	Foreign			Retirement and		Deferred		Total1
		Currency			Postretirement		Loss on
		Translation			Benefit Plan		Interest
		Gains (Losses)1			Adjustments1		Rate
							Derivative
							Hedges1
	Balance at December 31, 2012	$	613,492		-186,539		-18,052		408,901
	2013 components of other comprehensive income (loss):
	Before reclassifications to income		-240,300		59,145		–		-181,155
	Reclassifications to income		-68,000	2	10,438	3	1,935	4	-55,627
	Net other comprehensive income (loss)		-308,300		69,583		1,935		-236,782
	Balance at December 31, 2013		305,192		-116,956		-16,117		172,119
	2014 components of other comprehensive income (loss):
	Before reclassifications to income		-271,491		-79,403		–		-350,894
	Reclassifications to income		–		6,607	3	1,913	4	8,520
	Net other comprehensive income (loss)		-271,491		-72,796		1,913		-342,374
	Balance at December 31, 2014	$	33,701		-189,752		-14,204		-170,255
		1		All amounts are presented net of income taxes.
		2		Reclassification is included in income from discontinued operations, net of income taxes.
		3		Reclassifications before taxes of $18,570 and $9,813 are included in the computation of net periodic benefit expense in 2013 and 2014, respectively.  Related income taxes of $8,132 and $3,206 are included in Income tax expense in 2013 and 2014, respectively.
		4		Reclassifications before taxes of $2,963 are included in Interest expense in both 2013 and 2014.  Related income taxes of $1,028 and $1,050 are included in Income tax expense in 2013 and 2014, respectively.

Assets_and_Liabilities_Measure

Assets and Liabilities Measured at Fair Value	12 Months Ended
	Dec. 31, 2014
Assets and Liabilities Measured at Fair Value [Abstract]
Assets and Liabilities Measured at Fair Value	Note Q – Assets and Liabilities Measured at Fair Value
	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, 2014 and 2013 are presented in the following table.
				Fair Value Measurements at Reporting Date Using
	(Thousands of dollars)	Fair Value at		Quoted Prices	Significant	Significant
		31-Dec-14		in Active Markets	Other Observable	Unobservable
				for Identical	Inputs	Inputs
				Assets (Liabilities)	(Level 2)	(Level 3)
				(Level 1)
	Assets
	Commodity derivative contracts	$	23,168	–	23,168	–
	Liabilities
	Nonqualified employee savings plan	$	-14,408	-14,408	–	–
	Foreign currency exchange		-25	–	-25	–
	derivative contracts
	Total	$	-14,433	-14,408	-25	–
				Fair Value Measurements at Reporting Date Using
	(Thousands of dollars)	Fair Value at		Quoted Prices	Significant	Significant
		31-Dec-13		in Active Markets	Other Observable	Unobservable
				for Identical	Inputs	Inputs
				Assets (Liabilities)	(Level 2)	(Level 3)
				(Level 1)
	Assets
	Commodity derivative contracts	$	1,970	–	1,970	–
	Liabilities
	Nonqualified employee savings plan	$	-13,267	-13,267	–	–
	Foreign currency exchange		-1,038	–	-1,038	–
	derivative contracts
	Total	$	-14,305	-13,267	-1,038	–
	The fair value of West Texas Intermediate (WTI) crude oil contracts in 2013 was based on active market quotes for WTI crude oil.  The fair value of foreign exchange derivative contracts in each year was based on market quotes for similar contracts at the balance sheet 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 Income, while the effects of changes in fair value of foreign exchange derivative contracts is recorded in Interest and Other Income.  The nonqualified employee savings plan is an unfunded savings plan through which participants seek a return via phantom investments in equity securities and/or mutual funds.  The fair value of this liability was based on quoted prices for these equity securities and mutual funds.  The income effect of changes in the fair value of the nonqualified employee savings plan is recorded in Selling and General Expenses.
	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, 2014 and 2013.
	The following table presents the carrying amounts and estimated fair values of financial instruments held by the Company at December 31, 2014 and 2013.  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 is 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,
		2014			2013
	(Thousands of dollars)	Carrying		Fair	Carrying	Fair
		Amount		Value	Amount	Value
	Financial assets (liabilities):
	Canadian government securities with maturities	$	461,313	462,056	374,842	375,623
	greater than 90 days at the date of acquisition
	Current and long-term debt		-3,001,626	-2,774,065	-2,962,812	-2,822,827

Commitments

Commitments	12 Months Ended
	Dec. 31, 2014
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 rental payments under all operating leases are approximately $108,717,000 in 2015, $71,573,000 in 2016, $51,744,000 in 2017, $45,669,000 in 2018 and $37,062,000 in 2019.  Rental expense for noncancellable operating leases, including contingent payments when applicable, was $144,981,000 in 2014, $192,482,000 in 2013 and $178,292,000 in 2012.  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, 2014.  These rigs will primarily be utilized for drilling operations in the Gulf of Mexico, onshore U.S. and Canada, and offshore Malaysia and Australia.  Future commitments under these contracts, all of which expire by 2017, total $559,272,000.  A significant 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.  These agreements require minimum monthly or annual payments for processing and/or transportation charges through 2024.  Future required minimum monthly payments for the next five years are $64,928,000 in 2015, $49,792,000 in 2016, $40,512,000 in 2017, $33,019,000 in 2018 and $16,763,000 in 2019.  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 $34,597,000 in 2014, $40,254,000 in 2013 and $19,733,000 in 2012.
	In 2006, the Company committed to fund an educational assistance program known as the “El Dorado Promise.”  Under this commitment, the Company will pay $5,000,000 per year for ten years through 2016 to provide scholarships for a specified amount of college expenses for eligible graduates of El Dorado High School in Arkansas.  The first nine payments have been made through January 2015.  The Company recorded a discounted liability of $38,700,000 in 2006 for this unconditional commitment.  The liability was discounted at the Company’s 10-year borrowing rate and the discounted liability increases for accretion monthly with a corresponding charge to Selling and General Expenses in the Consolidated Statement of Income.  Total accretion cost was $541,000 in 2014, $805,000 in 2013 and $1,063,000 in 2012.
	Commitments for capital expenditures were approximately $1,423,139,000 at December 31, 2014, including $416,892,000 for field development and future work commitments in Malaysia, $378,989,000 for work in the Eagle Ford Shale, $279,395,000 for costs to develop deepwater Gulf of Mexico fields, and $86,894,000,  $79,036,000, $52,400,000 and $43,764,000 for future work commitments in Namibia, Equatorial Guinea, Vietnam and Australia, respectively.

Environmental_and_Other_Contin

Environmental and Other Contingencies	12 Months Ended
	Dec. 31, 2014
Contingencies [Abstract]
Environmental and Other 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 increases and retroactive tax claims; royalty and revenue sharing increases; import and export controls; price controls; currency controls; allocation of supplies of crude oil and petroleum products and other goods; expropriation of property; restrictions and preferences affecting the issuance of oil and gas or mineral leases; restrictions on drilling and/or production; laws and regulations intended for the promotion of safety and the protection and/or remediation of the environment; governmental support for other forms of energy; and laws and regulations affecting the Company’s relationships with employees, suppliers, customers, stockholders and others.  Because governmental actions are often motivated by political considerations, may be taken without full
	consideration of their consequences, and may be taken in response to actions of other governments, it is not practical to attempt to predict the likelihood of such actions, the form the actions may take or the effect such actions may have on the Company.
	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 affect on Murphy’s net income, financial condition or liquidity in a future period.
	The U.S. Environmental Protection Agency (EPA) formerly considered the Company to be a Potentially Responsible Party (PRP) at one Superfund site.  Based on evidence provided by the Company, the EPA has determined that the Company is no longer considered a PRP at this site.  Accordingly, the Company has not recorded a liability for remedial costs at the Superfund site at December 31, 2014.  The potential total cost to all parties to perform necessary remedial work at the site may be substantial.  The Company believes that its share of the ultimate costs to remediate the Superfund site will be immaterial and will not have a material adverse effect on its net income, financial condition or liquidity in a future period.
	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_Outsta

Common Stock Issued and Outstanding	12 Months Ended
	Dec. 31, 2014
Equity [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, 2014 is shown below.
	(Number of shares outstanding)	2014	2013	2012
	At beginning of year	183,406,513	190,641,317	193,723,208
	Stock options exercised*	119,994	303,685	482,974
	Restricted stock awards*	339,985	300,910	224,296
	Employee stock purchase and thrift plans	6,739	16,020	78,389
	Treasury shares purchased	-6,373,718	-7,855,419	-3,867,550
	At end of year	177,499,513	183,406,513	190,641,317
	*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.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	Note U – Subsequent Events
	On January 29, 2015, the Company completed the sale of 10% of its various interests in oil and gas properties in Malaysia to Pertamina.  Upon closing, the Company received cash proceeds of $417,200,000.

Business_Segments

Business Segments	12 Months Ended
	Dec. 31, 2014
Business Segments [Abstract]
Business Segments	Note V – 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 and/or natural gas.  The Company’s management evaluates segment performance based on income from operations, excluding interest income and interest expense.  Intersegment transfers of crude oil, natural gas and petroleum products are at market prices and intersegment services are recorded at cost.
	The Company desires to sell its U.K. finished product terminal operations.  The Company carries the assets and liabilities of this business as held for sale at December 31, 2014.  The Company sold its retail marketing operations in the United Kingdom on September 30, 2014.  The Company was unable to sell its Milford Haven, Wales refinery and it is in the process of decommissioning the facility at year-end 2014.  At December 31, 2014 and 2013, assets and liabilities associated with U.K. refining and marketing operations were reported as held for sale in the consolidated balance sheet.  These operations have been reported as discontinued operations for all periods presented in these consolidated financial statements.
	The Company sold all of its oil and natural gas producing assets in the United Kingdom during the first half of 2013.  The Company also completed the separation of its U.S. retail marketing business on August 30, 2013.  Both of these operations have also been reported as discontinued operations for all periods presented in these consolidated financial statements.
	The Company has several customers that purchase a significant portion of its oil and natural gas production.  During 2014, sales to Shell Oil and affiliated companies and Phillips 66 and affiliated companies represented approximately 20% and 14%, respectively, of the Company’s total sales revenue.  During 2013, sales to Phillips 66 and affiliated companies and Shell Oil and its affiliates represented approximately 17%  and 14%, respectively, of the Company’s total sales revenue.  In 2012, Shell Oil, BP and Petronas represented approximately 17%,  13% and 12%, respectively, of consolidated sales.  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.
	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, interest expense and unallocated overhead, are shown in the tables to reconcile the business segments to consolidated totals.  As used in the table on the following page, Certain Long-Lived Assets 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		Canada	Malaysia	Other*	Total
		States					E&P
	Year ended December 31, 2014
	Segment income (loss)	$	387.1	156.5	896.2	-250	1,189.8
	Revenues from external customers		2,196.4	1,044.1	2,183.5	-1.3	5,422.7
	Interest income		–	–	–	–	–
	Interest expense, net of capitalization		–	–	–	–	–
	Income tax expense (benefit)		214.8	64.2	102.6	-95.9	285.7
	Significant noncash charges (credits)
	Depreciation, depletion and amortization		840.7	316.7	735.0	5.1	1,897.5
	Accretion of asset retirement obligations		17.5	15.2	18.1	–	50.8
	Amortization of undeveloped leases		50.1	19.4	–	4.9	74.4
	Impairment of assets		14.3	37.0	–	–	51.3
	Deferred and noncurrent income taxes		39.7	43.3	-235.1	–	-152.1
	Additions to property, plant, equipment		2,028.7	445.9	818.0	10.7	3,303.3
	Total assets at year-end		5,745.7	3,769.8	4,887.1	138.7	14,541.3
	Year ended December 31, 2013
	Segment income (loss)	$	435.4	180.8	786.4	-373.8	1,028.8
	Revenues from external customers		1,803.8	1,144.7	2,280.5	83.6	5,312.6
	Interest income		–	–	–	–	–
	Interest expense, net of capitalization		–	–	–	–	–
	Income tax expense (benefit)		241.6	57.8	477.7	-120.8	656.3
	Significant noncash charges (credits)
	Depreciation, depletion and amortization		576.3	374.6	588.2	4.5	1,543.6
	Accretion of asset retirement obligations		13.5	16.2	15.0	4.3	49.0
	Amortization of undeveloped leases		30.3	21.0	–	15.6	66.9
	Impairment of assets		–	21.6	–	–	21.6
	Deferred and noncurrent income taxes		99.6	26.1	48.1	–	173.8
	Additions to property, plant, equipment		1,785.9	334.5	1,323.4	64.8	3,508.6
	Total assets at year-end		4,530.0	4,087.8	6,121.0	180.4	14,919.2
	Year ended December 31, 2012
	Segment income (loss)	$	168.0	208.1	894.2	-365.3	905.0
	Revenues from external customers		1,038.0	1,084.3	2,428.1	57.7	4,608.1
	Interest income		–	–	–	–	–
	Interest expense, net of capitalization		–	–	–	–	–
	Income tax expense (benefit)		99.8	65.1	544.7	-104.6	605.0
	Significant noncash charges (credits)
	Depreciation, depletion and amortization		330.2	345.8	532.1	36.3	1,244.4
	Accretion of asset retirement obligations		11.4	13.6	12.5	0.9	38.4
	Amortization of undeveloped leases		71.6	29.3	–	28.9	129.8
	Impairment of assets		–	–	–	200.0	200.0
	Deferred and noncurrent income taxes		231.0	72.3	73.3	-1.5	375.1
	Additions to property, plant, equipment		1,615.9	887.2	1,426.7	4.0	3,933.8
	Total assets at year-end		3,625.9	4,477.7	4,811.5	187.8	13,102.9
	Geographic Information	Certain Long-Lived Assets at December 31
	(Millions of dollars)	United		Canada	Malaysia	United	Other*	Total
		States				Kingdom
	2014	$	5,419.5	3,574.6	4,258.8	0.4	78.1	13,331.4
	2013		4,267.9	3,834.9	5,301.7	0.4	76.6	13,481.5
	2012		4,177.4	4,190.5	4,101.2	703.2	45.1	13,217.4
	*Reclassified to conform to current presentation.
	Segment Information (Continued)
	(Millions of dollars)	Corporate		Discontinued	Consolidated
		and		Operations	Total
		Other
	Year ended December 31, 2014
	Segment income (loss)	$	-164.8	-119.4	905.6
Revenues from external customers		53.4	–	5,476.1
Interest income		7.7	–	7.7
Interest expense, net of capitalization		115.8	–	115.8
Income tax expense (benefit)		-58.4	–	227.3
Significant noncash charges (credits)
Depreciation, depletion and amortization		8.7	–	1,906.2
Accretion of asset retirement obligations		–	–	50.8
Amortization of undeveloped leases		–	–	74.4
Impairment of assets		–	–	51.3
Deferred and noncurrent income taxes		-18.8	–	-170.9
Additions to property, plant, equipment		14.5	–	3,317.8
Total assets at year-end		1,773.9	427.1	16,742.3
Year ended December 31, 2013
Segment income (loss)	$	-140.7	235.4	1,123.5
Revenues from external customers		77.5	–	5,390.1
Interest income		3.9	–	3.9
Interest expense, net of capitalization		71.9	–	71.9
Income tax expense (benefit)		-71.7	–	584.6
Significant noncash charges (credits)
Depreciation, depletion and amortization		9.8	–	1,553.4
Accretion of asset retirement obligations		–	–	49.0
Amortization of undeveloped leases		–	–	66.9
Impairment of assets		–	–	21.6
Deferred and noncurrent income taxes		-15.7	–	158.1
Additions to property, plant, equipment		15.5	8.1	3,532.2
Total assets at year-end		1,265.2	1,325.1	17,509.5
Year ended December 31, 2012
Segment income (loss)	$	-98.5	164.4	970.9
Revenues from external customers		11.5	–	4,619.6
Interest income		6.5	–	6.5
Interest expense, net of capitalization		14.9	–	14.9
Income tax expense (benefit)		-43.5	–	561.5
Significant noncash charges (credits)
Depreciation, depletion and amortization		8.7	–	1,253.1
Accretion of asset retirement obligations		–	–	38.4
Amortization of undeveloped leases		–	–	129.8
Impairment of assets		–	–	200.0
Deferred and noncurrent income taxes		-32.3	–	342.8
Additions to property, plant, equipment		8.2	191.8	4,133.8
Total assets at year-end		1,009.6	3,410.1	17,522.6
Geographic Information	Revenues from External Customers for the Year
(Millions of dollars)	United		Canada	Malaysia	Other	Total
	States
2014	$	2,201.5	1,052.4	2,233.0	-10.8	5,476.1
2013		1,798.5	1,150.2	2,337.5	103.9	5,390.1
2012		1,038.1	1,088.4	2,415.6	77.5	4,619.6

Supplemental_Oil_and_Gas_Infor

Supplemental Oil and Gas Information	12 Months Ended
	Dec. 31, 2014
Supplemental Oil and Gas Information [Abstract]
Supplemental Oil and Gas Information	MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES
	SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
	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 follows concerning five of the schedules.
	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 producibility.  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 Murphy’s proved reserves estimates, and 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, historic 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.
	Murphy includes synthetic crude oil from its 5% interest in the Syncrude project in Alberta, Canada in its proved crude oil reserves.  This operation involves a process of mining tar sands and converting the raw bitumen into a pipeline-quality crude.  The proved reserves associated with this project are estimated through a combination of core-hole drilling and realized process efficiencies.  The high-density core-hole drilling, at a spacing of less than 500 meters (proved area), provides engineering and geologic data needed to estimate the volumes of tar sand in place and its associated bitumen content.  The bitumen generally constitutes approximately 10% of the total bulk tar sand that is mined.  The bitumen extraction process is fairly efficient and removes about 90% of the bitumen that is contained within the tar sand.  The final step of the process converts the 8.4° API bitumen into 30°-34° API crude oil.  A catalytic cracking process is used to crack the long hydrocarbon chains into shorter ones yielding a final crude oil that can be shipped via pipelines.  The cracking process has an efficiency ranging from 85% to 90%.  Overall, it takes approximately two metric tons of oil sand to produce one barrel of synthetic crude oil.  All synthetic oil volumes reported as proved reserves in Schedule 1 are the final synthetic crude oil product.
	The Company has included a schedule of proved reserves of natural gas liquids (NGL) in this Form 10-K report.  In the prior year’s report, certain NGL proved reserves and associated changes were included in crude oil proved reserves.  Therefore, certain adjustments of crude oil proved reserves previously reported in the 2013 Form 10-K report have been made to separate the effects of NGL for prior-year activities.
	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 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.  Liquids and natural gas proved reserves associated with the production sharing contracts in Malaysia totaled 94.6 million barrels and 635.6 billion cubic feet, respectively, at December 31, 2014.  Approximately 54.7 billion cubic feet of natural gas proved reserves in Malaysia at December 31, 2014 relate to fields in Block K for which the Company expects to receive sale proceeds of approximately $0.24 per thousand cubic feet.
	SCHEDULE 5 – RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
	Results of operations from exploration and production activities by geographic area are reported as if these activities were not part of an operation that also refines crude oil and sells refined products.
	SCHEDULE 6 – STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
	Generally accepted accounting principles require 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.
	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, 2014.
	Schedule 1 – Summary of Proved Crude Oil and Synthetic Oil Reserves Based on Average Prices
	for 2011 – 2014
		Crude &		Crude Oil												Synthetic
		Synthetic														Oil
		Oil
	(Millions of barrels)	Total		Total		United		Canada		Malaysia		United		Other		Canada
						States						Kingdom
	Proved developed and
	undeveloped crude oil /
	synthetic oil reserves:
	31-Dec-11	349.7		220.2		55.3		36.6		104.4		21.6		2.3		129.5
	Revisions of previous estimates	2.3		7.6		13.0		-3.4		-0.7		0.3		-1.6		-5.3
	Improved recovery	7.2		7.2		–		–		7.2		–		–		–
	Extensions and discoveries	84.0		84.0		77.3		2.9		3.8		–		–		–
	Purchases of properties	12.5		12.5		6.5		6.0		–		–		–		–
	Production	-40.9		-35.8		-9.5		-5.3		-19		-1.3		-0.7		-5.1
	31-Dec-12	414.8		295.7		142.6		36.8		95.7		20.6		–		119.1
	Revisions of previous estimates	27.4		24.8		13.1		8.4		3.3		–		–		2.6
	Improved recovery	27.4		27.4		–		–		27.4		–		–		–
	Extensions and discoveries	69.6		69.6		52.4		0.2		17.0		–		–		–
	Purchases of properties	-20.4		-20.4		–		–		–		-20.4		–		–
	Production	-47.6		-42.9		-16.6		-6.7		-19.4		-0.2		–		-4.7
	31-Dec-13	471.2		354.2		191.5		38.7		124.0		0.0		–		117.0
	Revisions of previous estimates	-9.3		-2.3		-3.2		2.7		-1.8		–		–		-7
	Improved recovery	7.5		7.5		–		–		7.5		–		–		–
	Extensions and discoveries	42.6		42.6		32.7		2.4		7.5		–		–		–
	Purchases of properties	6.1		6.1		6.1		–		–		–		–		–
	Sales of properties	-24.3		-24.3		-0.3		-0.5		-23.5		–		–		–
	Production	-52		-47.6		-21.9		-5.9		-19.8		–		–		-4.4
	December 31, 2014	441.8		336.2		204.9		37.4		93.9		–		–		105.6
	Proved developed crude oil /
	synthetic oil reserves:
	December 31, 2011	238.5		118.0		20.8		32.6		57.2		5.1		2.3		120.5
	December 31, 2012	267.7		148.6		48.0		29.5		67.0		4.1		–		119.1
	December 31, 2013	289.9		172.9		75.8		31.6		65.5		–		–		117.0
	December 31, 2014	324.1		218.5		106.2		32.4		79.9		–		–		105.6
	Proved undeveloped crude
	oil / synthetic oil reserves:
	December 31, 2011	111.2		102.2		34.5		4.0		47.2		16.5		–		9.0
	December 31, 2012	147.1		147.1		94.6		7.3		28.7		16.5		–		–
	December 31, 2013	181.3		181.3		115.7		7.1		58.5		–		–		–
	December 31, 2014	117.7		117.7		98.7		5.0		14.0		–		–		–
	Note:All crude oil and synthetic reserves included in the table above are from consolidated subsidiaries and proportionately consolidated joint ventures.  The Company has no proved crude oil and synthetic oil reserves attributable to investees accounted for by the equity method.
	Schedule 1 – Summary of Proved Crude Oil and Synthetic Oil Reserves Based on Average Prices
	for 2011 – 2014 –  Continued
	2014 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes
Revisions of previous estimates – The 2014 negative crude oil revision in the U.S. was primarily attributed to a new downspacing drilling strategy at the Eagle Ford Shale, which recognizes incrementally greater reserves as an Extension for 2014.  The positive Canadian conventional oil reserves revision in 2014 was based on Hibernia well performance and stronger heavy oil prices during 2014.  The negative synthetic oil revision in 2014 was based on a review of the recoverable bitumen area coupled with the impact of a lower oil price.  The negative revision for crude oil reserves in Malaysia in 2014 was attributable to an updated decline curve analysis for the Kikeh field, partially offset by a benefit for performance associated with field ramp up at Kakap.
Improved recovery  – This 2014 Malaysia crude oil proved reserves add was associated with favorable impacts for waterflood activities at the Kikeh, Siakap North and Sarawak oil fields.
Extensions and discoveries – In 2014, the U.S. added proved oil reserves primarily for substantial drilling activities in the Eagle Ford Shale.  Canadian proved oil reserves adds in 2014 were associated with drilling activities in the Seal heavy oil area and at the Hibernia field.  The crude oil proved reserves adds in 2014 in Malaysia were mostly for drilling activities at the Siakap North and Sarawak oil fields.
Purchases of properties – The proved crude oil reserves adds in the U.S. were due to acquisition of an interest in the Kodiak field in the Gulf of Mexico.
Sales of properties  – The proved crude oil reserves reduction in Malaysia was associated with the late 2014 sale of 20% of the Company’s oil and gas assets.  A further 10% of Malaysia assets was sold in 2015 and the associated reserves reduction will be reflected in the 2015 reserves table.
2013 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes
Revisions of previous estimates – The positive revision for proved crude oil reserves in 2013 in the U.S. was attributable to better well performance in the Eagle Ford Shale area in South Texas, plus minor adds to several fields in the Gulf of Mexico.  The positive revision for conventional oil in Canada was caused by well performance at the Hibernia and Terra Nova fields.  Synthetic oil revisions were positive primarily due to revised cost recovery factors for bitumen extraction following renegotiated royalty terms with the government.  Positive revisions in Malaysia were primarily attributable to well performance at Kikeh.
Improved recovery – The positive effect from improved recovery in Malaysia was at the Kikeh field where waterflood has led to better than anticipated response in certain reservoirs.
Extensions and discoveries – The U.S. proved crude oil reserve additions were all in the Eagle Ford Shale where the Company has used reliable technology to add offset locations associated with well downspacing in certain areas.  Proved oil adds in Canada were associated with extensions at Seal.  Additions to oil reserves in Malaysia primarily related to four new oil fields offshore Sarawak which were put on production during the second half of 2013.
Sales of properties – The Company sold all its oil fields in the U.K. during the first half of 2013.
Schedule 1 – Summary of Proved Crude Oil and Synthetic Oil Reserves Based on Average Prices
for 2011 – 2014 –  Continued
2012 Comments for Proved Crude Oil and Synthetic Oil Reserves Changes
Revisions of previous estimates – A positive proved crude oil reserves revision in 2012 in the U.S. was due to improved well performance in the Eagle Ford Shale and at the Medusa field in the Gulf of Mexico.  Downward revisions for conventional oil in Canada related to a lower recovery assessment for certain heavy oil wells in the Seal area.  Negative proved oil revisions for synthetic oil in Canada related to an entitlement change based on recent spending projections that increased royalties estimated to be paid to the government.  Negative proved oil revisions in the Other category related to Republic of the Congo and arose due to a combination of poor well performance on existing wells, a well that went off production in 2012, and generally uneconomic remaining future production due to oil recovery projections.
Improved recovery – The improved recovery in 2012 in Malaysia was essentially caused by better waterflood response in certain Kikeh field reservoir sands.
Extensions and discoveries – The U.S. proved crude oil reserves added in 2012 were primarily in the Eagle Ford Shale and were based on use of reliable technology to recognize additional offset undeveloped locations with 80 acre downspacing in certain areas of the play.  The oil reserves added in Canada mostly related to additional development drilling off the East Coast at Hibernia and Terra Nova.  Malaysia reserves increases primarily arose due to development drilling at fields offshore Sarawak.
Purchases of properties – Proved crude oil reserves added from property acquisitions in 2012 were associated with interests added at the Front Runner and Thunder Hawk fields in the U.S. Gulf of Mexico and in the Seal heavy oil area of Western Canada.
Schedule 2 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices
for 2011 – 2014
(Millions of barrels)	Total		United		Canada		Malaysia
			States
Proved developed and undeveloped NGL reserves:
31-Dec-11	–		–		–		–
Revisions of previous estimates	0.3		–		–		0.3
Improved recovery	–		–		–		–
Extensions and discoveries	–		–		–		–
Production	-0.3		–		–		-0.3
31-Dec-12	–		–		–		–
Revisions of previous estimates	15.7		15.6		–		0.1
Improved recovery	–		–		–		–
Extensions and discoveries	10.0		8.7		0.1		1.2
Production	-1.3		-1.1		–		-0.2
31-Dec-13	24.4		23.2		0.1		1.1
Revisions of previous estimates	5.1		5.0		–		0.1
Improved recovery	–		–		–		–
Extensions and discoveries	4.7		4.0		0.6		0.1
Sales of properties	-0.2		–		–		-0.2
Production	-3.4		-3.1		–		-0.3
December 31, 2014	30.6		29.1		0.7		0.8
Proved developed NGL reserves:
December 31, 2011	–		–		–		–
December 31, 2012	–		–		–		–
December 31, 2013	14.2		13.1		–		1.1
December 31, 2014	17.5		16.5		0.2		0.8
Proved undeveloped NGL reserves:
December 31, 2011	–		–		–		–
December 31, 2012	–		–		–		–
December 31, 2013	10.2		10.1		0.1		–
December 31, 2014	13.1		12.6		0.5		–
Note:All NGL reserves included in the table above are from consolidated subsidiaries and proportionately consolidated joint ventures.  The Company has no proved NGL reserves attributable to investees accounted for by the equity method.
Schedule 2 – Summary of Proved Natural Gas Liquids (NGL) Reserves Based on Average Prices
for 2011 – 2014 – Continued
2014 Comments for Proved Natural Gas Liquids Reserves Changes
Revisions of previous estimates – The positive 2014 NGL proved reserves revision in the U.S. was primarily in the Eagle Ford Shale based on an overall review of oil and gas mix for this production area.
Extensions and discoveries  – The 2014 proved NGL reserves add in the U.S. was primarily attributable to drilling activities in the Eagle Ford Shale.  The proved reserves add for Canadian NGL in 2014 was primarily associated with the drilling program in the Tupper and Tupper West areas.
Sales of properties – The Company sold 20% of its oil and gas assets in Malaysia in late 2014.  A further 10% of oil and gas assets was sold in Malaysia in January 2015 and the associated reserves reduction will be reflected in the 2015 reserves table.
2013 Comments for Proved Natural Gas Liquids Reserves Changes
Revisions of previous estimates – The positive U.S. revision to NGL proved reserves in 2013 was primarily due to well productivity in the Eagle Ford Shale, plus initial recognition of proved reserves quantities for NGL.
Extensions and discoveries  – The NGL proved reserves add in 2013 in the U.S. was primarily attributable to development drilling in the Eagle Ford Shale.
Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2011 – 2014
(Billions of cubic feet)	Total		United		Canada		Malaysia		United
			States						Kingdom
Proved developed and undeveloped
natural gas reserves:
31-Dec-11	1,106.1		98.4		638.9		347.8		21.0
Revisions of previous estimates	20.2		16.5		-37.2		41.4		-0.5
Improved recovery	7.2		–		–		7.2		–
Extensions and discoveries	173.5		107.2		25.8		40.5		–
Purchases of properties	9.4		7.0		2.4		–		–
Production	-179.4		-19.4		-79.5		-79.3		-1.2
31-Dec-12	1,137.0		209.7		550.4		357.6		19.3
Revisions of previous estimates	33.7		-38.6		34.0		38.3		–
Improved recovery	3.2		–		–		3.2		–
Extensions and discoveries	153.4		33.3		42.5		77.6		–
Sales of properties	-19		–		–		–		-19
Production	-154.7		-19.4		-64.1		-70.9		-0.3
31-Dec-13	1,153.6		185.0		562.8		405.8		–
Revisions of previous estimates	167.2		47.7		105.6		13.9		–
Improved recovery	7.0		–		–		7.0		–
Extensions and discoveries	696.8		24.1		231.5		441.2		–
Purchases of properties	5.5		5.5		–		–		–
Sales of properties	-162.6		-3.7		–		-158.9		–
Production	-162.8		-32.3		-57.1		-73.4		–
December 31, 2014	1,704.7		226.3		842.8		635.6		–
Proved developed natural gas reserves:
December 31, 2011	711.6		58.2		427.1		210.5		15.8
December 31, 2012	706.0		78.8		415.8		197.3		14.1
December 31, 2013	786.2		112.6		384.0		289.6		–
December 31, 2014	812.1		145.6		467.4		199.1		–
Proved undeveloped natural gas reserves:
December 31, 2011	394.5		40.2		211.8		137.3		5.2
December 31, 2012	431.0		130.9		134.6		160.3		5.2
December 31, 2013	367.4		72.4		178.8		116.2		–
December 31, 2014	892.6		80.7		375.4		436.5		–
Note:All natural gas reserves included in the table above are from consolidated subsidiaries and proportionately consolidated joint ventures.  The Company has no proved natural gas reserves attributable to investees accounted for by the equity method.
2014 Comments for Proved Natural Gas Reserves Changes
Revisions of previous estimates  – The positive revision for U.S. proved reserves of natural gas in 2014 was primarily attributable to good well performance at the new Dalmatian field in the Gulf of Mexico, plus a reassessment of oil and gas production mix in the Eagle Ford Shale that increased natural gas and gas liquids reserves with a corresponding decline in crude oil proved reserves.  The positive revision associated with Canada natural gas proved reserves in 2014 was based on better performance in the Tupper and Tupper West areas following a change in the completion process.  The positive revision for proved natural gas reserves in Malaysia in 2014 was primarily due to well performance and a higher entitlement rate for fields offshore Sarawak.
Schedule 3 – Summary of Proved Natural Gas Reserves Based on Average Prices for 2011 – 2014 –  Continued
2014 Comments for Proved Natural Gas Reserves Changes – Continued
Extensions and discoveries – The proved reserves of natural gas added in the U.S. in 2014 was primarily associated with the development drilling program in the Eagle Ford Shale, while the add in Canada in 2014 was attributable to drilling in the Tupper and Tupper West areas in Western Canada.  The proved natural gas reserves added in Malaysia in 2014 was mostly associated with approval and sanction of the plan for a floating liquefied natural gas development in Block H, offshore Sabah, during the just completed year.
Purchases of properties –  The Company acquired an interest in the Kodiak field in the Gulf of Mexico in 2014, which added proved reserves of natural gas during the year.
Sales of properties  – The Company sold its interests in South Louisiana gas fields in 2014, plus it sold a 20% interest in oil and gas assets in Malaysia late in the year.  A further 10% of Malaysia assets was sold in 2015 and the associated reserves reduction will be reflected in the 2015 reserves table.
2013 Comments for Proved Natural Gas Reserves Changes
Revisions of previous estimates – The U.S. natural gas proved reserves revisions in 2013 were unfavorable due to converting gas liquids volumes within the gas stream to proved NGL reserves.  Positive revisions in Canada were mostly attributable to better well performance in the Tupper West area.  Malaysia had positive gas revisions principally due to better well performance at gas fields offshore Sarawak and positive revisions due to better overall well production at the Kikeh field.
Improved recovery – The reserves add in Malaysia was attributable to better waterflood response at the Kikeh field due to better overall well production.
Extensions and discoveries – U.S. proved reserves of gas had adds in the Eagle Ford Shale due to additional offsets based on use of reliable technology with narrower downspacing in certain areas.  The gas reserve adds in Canada were at the Tupper West and Tupper areas primarily caused by drilling activities and recognition of offset undeveloped locations.  Natural gas proved reserve were added in Malaysia primarily due to initial booking of reserves of associated gas at three oil fields offshore Sarawak.
Sales of properties – The Company sold all of its U.K. oil and gas fields in the first half of 2013.
2012 Comments for Proved Natural Gas Reserves Changes
Revisions of previous estimates – The positive proved natural gas reserves revisions in the U.S. during 2012 were primarily caused by better well performance for certain fields in the Gulf of Mexico and in the Eagle Ford Shale.  The negative revision in Canada was mostly attributable to weaker natural gas prices that unfavorably affected economical recovery at certain wells in the Montney formation in Western Canada.  A positive natural gas reserves revision in Malaysia was related to better well performance and favorable entitlement effects for gas operations offshore Sarawak.
Improved recovery – The improved recovery in 2012 in Malaysia was essentially caused by better waterflood response in certain Kikeh field reservoir sands.
Extensions and discoveries – U.S. natural gas proved reserves added were primarily in the Eagle Ford Shale due to recognition of additional offsets from expanded use of reliable technology with 80 acre downspacing in certain areas of the play, plus the initial booking of proved gas reserves for the Dalmatian field in the Gulf of Mexico.  Natural gas reserves added in Canada were primarily associated with drilling performed in the Tupper area.  Reserves added in Malaysia were principally associated with development drilling operations at Sarawak gas fields.
Purchases of properties – Natural gas reserves added in 2012 related to additional interests acquired during the year at the Front Runner and Thunder Hawk fields in the U.S. Gulf of Mexico and in the Seal area of Western Canada.
Schedule 4 – Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
(Millions of dollars)	United			Canada		Malaysia		United		Other2		Total
	States							Kingdom1
Year Ended December 31, 2014
Property acquisition costs
Unproved	$	92.9		–		–		–		–		92.9
Proved		7.4		–		–		–		–		7.4
Total acquisition costs		100.3		–		–		–		–		100.3
Exploration costs3		160.0		1.7		6.3		–		262.1		430.1
Development costs3		1,934.7		413.8		926.6		–		7.6		3,282.7
Total costs incurred		2,195.0		415.5		932.9		–		269.7		3,813.1
Charged to expense
Dry hole expense		92.1		–		47.4		–		130.5		270.0
Geophysical and other costs		37.7		1.7		1.3		–		128.5		169.2
Total charged to expense		129.8		1.7		48.7		–		259.0		439.2
Property additions	$	2,065.2		413.8		884.2		–		10.7		3,373.9
Year Ended December 31, 2013
Property acquisition costs
Unproved	$	32.4		–		–		–		3.2		35.6
Proved		13.2		–		–		–		–		13.2
Total acquisition costs		45.6		–		–		–		3.2		48.8
Exploration costs3		112.4		21.8		14.9		–		344.6		493.7
Development costs3		1,773.2		351.6		1,787.7	4	8.1		19.0		3,939.6
Total costs incurred		1,931.2		373.4		1,802.6		8.1		366.8		4,482.1
Charged to expense
Dry hole expense		46.1		32.1		20.7		–		164.0		262.9
Geophysical and other costs		29.1		0.7		4.6		–		138.0		172.4
Total charged to expense		75.2		32.8		25.3		–		302.0		435.3
Property additions	$	1,856.0		340.6		1,777.3		8.1		64.8		4,046.8
Year Ended December 31, 2012
Property acquisition costs
Unproved	$	107.7		14.6		–		–		10.2		132.5
Proved		69.1		242.4		–		–		–		311.5
Total acquisition costs		176.8		257.0		–		–		10.2		444.0
Exploration costs3		174.5		57.0		68.8		-1		148.7		448.0
Development costs3		1,352.7		664.5		1,433.7		46.6		24.2		3,521.7
Total costs incurred		1,704.0		978.5		1,502.5		45.6		183.1		4,413.7
Charged to expense
Dry hole expense		32.3		8.0		26.1		-0.8		115.5		181.1
Geophysical and other costs		19.6		2.5		1.1		-0.2		46.0		69.0
Total charged to expense		51.9		10.5		27.2		-1		161.5		250.1
Property additions	$	1,652.1		968.0		1,475.3		46.6		21.6		4,163.6
	1		The Company has accounted for U.K. operations as discontinued operations due to the sale of these operations in the first half of 2013.
	2		Due to the shutdown of production operations in Republic of the Congo, the Company now includes the result of these operations in the Other exploration and production segment in the above table.
	3		Includes non-cash asset retirement costs as follows:
2014
Exploration costs	$	–		–		–		–		–		–
Development costs		36.5		-32.1		66.2		–		–		70.6
	$	36.5		-32.1		66.2		–		–		70.6
2013
Exploration costs	$	–		0.2		–		–		–		0.2
Development costs		70.1		5.9		95.9		–		–		171.9
	$	70.1		6.1		95.9		–		–		172.1
2012
Exploration costs	$	-1.7		0.1		–		–		–		-1.6
Development costs		37.9		80.7		48.6		-11.5		17.6		173.3
	$	36.2		80.8		48.6		-11.5		17.6		171.7
	4		Includes property costs associated with non-cash capital lease of $358.0 million at the Kakap field.
Schedule 5 – Results of Operations for Oil and Gas Producing Activities1
				Canada
	United			Conven-
(Millions of dollars)	States			tional		Synthetic		Malaysia		Other2		Total
Year Ended December 31, 2014
Revenues												–
Crude oil and natural gas liquids sales	$	2,062.1		453.3		391.5		1,680.2		–		4,587.1
Natural gas sales		127.2		201.3		–		357.5		–		686.0
Total oil and gas revenues		2,189.3		654.6		391.5		2,037.7		–		5,273.1
Other operating revenues		7.1		-2.4		0.4		145.8		-1.3		149.6
Total revenues		2,196.4		652.2		391.9		2,183.5		-1.3		5,422.7
Costs and expenses
Lease operating expenses		345.5		160.3		233.8		350.3		–		1,089.9
Severance and ad valorem taxes		96.5		5.6		5.1		–		–		107.2
Exploration costs charged to expense		129.8		1.7		–		48.7		259.0		439.2
Undeveloped lease amortization		50.1		19.4		–		–		4.9		74.4
Depreciation, depletion and amortization		840.7		262.7		54.0		735.0		5.1		1,897.5
Accretion of asset retirement obligations		17.5		6.0		9.2		18.1		–		50.8
Impairment of assets		14.3		37.0		–		–		–		51.3
Selling and general expenses		95.2		26.7		0.9		15.7		73.5		212.0
Other expenses		4.9		1.0		–		16.9		2.1		24.9
Total costs and expenses		1,594.5		520.4		303.0		1,184.7		344.6		3,947.2
Results of operations before taxes		601.9		131.8		88.9		998.8		-345.9		1,475.5
Income tax expense (benefit)		214.8		42.4		21.8		102.6		-95.9		285.7
Results of operations	$	387.1		89.4		67.1		896.2		-250		1,189.8
Year Ended December 31, 2013
Revenues
Crude oil and natural gas liquids sales	$	1,724.7		507.2		441.0		1,875.0		83.6		4,631.5
Natural gas sales		72.7		198.1		–		404.0		–		674.8
Total oil and gas revenues		1,797.4		705.3		441.0		2,279.0		83.6		5,306.3
Other operating revenues		6.4		-1.9		0.3		1.5		–		6.3
Total revenues		1,803.8		703.4		441.3		2,280.5		83.6		5,312.6
Costs and expenses
Lease operating expenses		273.6		180.5		223.4		384.4		191.0		1,252.9
Severance and ad valorem taxes		77.5		5.0		4.8		–		–		87.3
Exploration costs charged to expense		75.2		32.8		–		25.3		302.0		435.3
Undeveloped lease amortization		30.3		21.0		–		–		15.6		66.9
Depreciation, depletion and amortization		576.3		319.2		55.4		588.2		4.5		1,543.6
Accretion of asset retirement obligations		13.5		5.9		10.3		15.0		4.3		49.0
Impairment of assets		–		21.6		–		–		–		21.6
Selling and general expenses		80.4		25.3		0.9		3.5		60.8		170.9
Total costs and expenses		1,126.8		611.3		294.8		1,016.4		578.2		3,627.5
Results of operations before taxes		677.0		92.1		146.5		1,264.1		-494.6		1,685.1
Income tax expense (benefit)		241.6		19.9		37.9		477.7		-120.8		656.3
Results of operations	$	435.4		72.2		108.6		786.4		-373.8		1,028.8
	1		Results exclude corporate overhead, interest and discontinued operations.
	2		Due to the shutdown of production operations in Republic of the Congo, the Company now includes the results of these operations in the Other exploration and production segment in the above tables.
Schedule 5 – Results of Operations for Oil and Gas Producing Activities1 – Continued
				Canada
	United			Conven-
(Millions of dollars)	States			tional		Synthetic		Malaysia		Other2		Total
Year Ended December 31, 2012
Revenues
Crude oil and natural gas liquids sales	$	976.1		411.7		463.1		1,946.0		57.6		3,854.5
Natural gas sales		54.2		209.8		–		481.1		–		745.1
Total oil and gas revenues		1,030.3		621.5		463.1		2,427.1		57.6		4,599.6
Other operating revenues		7.7		-0.9		0.6		1.0		0.1		8.5
Total revenues		1,038.0		620.6		463.7		2,428.1		57.7		4,608.1
Costs and expenses
Lease operating expenses		225.4		163.7		219.0		422.7		48.4		1,079.2
Severance and ad valorem taxes		27.0		3.5		5.1		–		–		35.6
Exploration costs charged to expense		51.9		10.5		–		27.2		161.5		251.1
Undeveloped lease amortization		71.6		29.3		–		–		28.9		129.8
Depreciation, depletion and amortization		330.2		290.5		55.3		532.1		36.3		1,244.4
Accretion of asset retirement obligations		11.4		5.1		8.5		12.5		0.9		38.4
Impairment of assets		–		–		–		–		200.0		200.0
Selling and general expenses		52.7		19.7		0.9		-5.3		51.6		119.6
Total costs and expenses		770.2		522.3		288.8		989.2		527.6		3,098.1
Results of operations before taxes		267.8		98.3		174.9		1,438.9		-469.9		1,510.0
Income tax expense (benefit)		99.8		25.1		40.0		544.7		-104.6		605.0
Results of operations	$	168.0		73.2		134.9		894.2		-365.3		905.0
	1		Results exclude corporate overhead, interest and discontinued operations.
	2		Due to the shutdown of production operations in Republic of the Congo, the Company now includes the results of these operations in the Other exploration and production segment in the above table.
Schedule 6 – Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves
(Millions of dollars)	United			Canada		Malaysia		United		Total
	States							Kingdom
31-Dec-14
Future cash inflows	$	20,767.4		16,257.0		11,909.7		–		48,934.1
Future development costs		-3,151.40		-1,810.50		-1,920.80		–		-6,882.70
Future production costs		-6,378.50		-7,770.20		-4,575.60		–		-18,724.30
Future income taxes		-2,930.10		-1,389.60		-1,249.90		–		-5,569.60
Future net cash flows		8,307.4		5,286.7		4,163.4		–		17,757.5
10% annual discount for estimated timing		-3,729.10		-2,595.30		-1,527.90		–		-7,852.30
of cash flows
Standardized measure of discounted	$	4,578.3		2,691.4		2,635.5		–		9,905.2
future net cash flows
31-Dec-13
Future cash inflows	$	20,638.6		16,112.9		13,399.0		–		50,150.5
Future development costs		-3,833.90		-1,882.30		-1,445.30		–		-7,161.50
Future production costs		-5,244.70		-7,073.00		-4,490.40		–		-16,808.10
Future income taxes		-3,368.30		-1,472.80		-1,855.10		–		-6,696.20
Future net cash flows		8,191.7		5,684.8		5,608.2		–		19,484.7
10% annual discount for estimated timing		-4,020.20		-2,999.10		-1,620.70		–		-8,640.00
of cash flows
Standardized measure of discounted	$	4,171.5		2,685.7		3,987.5		–		10,844.7
future net cash flows
31-Dec-12
Future cash inflows	$	15,547.5		15,511.6		10,354.9		2,395.2		43,809.2
Future development costs		-3,731.60		-1,815.20		-966.9		-273.2		-6,786.90
Future production costs		-3,466.60		-7,336.40		-3,143.40		-738.3		-14,684.70
Future income taxes		-2,527.60		-1,714.90		-1,675.90		-872.7		-6,791.10
Future net cash flows		5,821.7		4,645.1		4,568.7		511.0		15,546.5
10% annual discount for estimated timing		-2,862.10		-2,876.50		-1,322.90		-372.2		-7,433.70
of cash flows
Standardized measure of discounted	$	2,959.6		1,768.6		3,245.8		138.8		8,112.8
future net cash flows
Schedule 6 continues on Page F-65.
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 shown.
(Millions of dollars)		2014		2013		2012
Net changes in prices and production costs	$	-2,697.80		267.8		-2,461.10
Net changes in development costs		-2,317.30		-3,456.80		-3,860.10
Sales and transfers of oil and gas produced, net of production costs		-4,076.00		-3,972.40		-3,493.30
Net change due to extensions and discoveries		3,251.6		4,608.9		4,466.3
Net change due to purchases and sales of proved reserves		-1,041.00		-135.6		347.4
Development costs incurred		3,169.3		3,326.8		3,299.0
Accretion of discount		1,462.5		1,109.3		1,153.5
Revisions of previous quantity estimates		518.9		1,646.0		728.1
Net change in income taxes		790.3		-662.1		9.8
Net increase (decrease)		-939.5		2,731.9		189.6
Standardized measure at January 1		10,844.7		8,112.8		7,923.2
Standardized measure at December 31	$	9,905.2		10,844.7		8,112.8
Schedule 7 – Capitalized Costs Relating to Oil and Gas Producing Activities
(Millions of dollars)	United			Canada		Malaysia		Other*		Subtotal		Synthetic		Total
	States											Oil –
												Canada
31-Dec-14
Unproved oil and gas properties	$	634.9		424.1		–		168.1		1,227.1		–		1,227.1
Proved oil and gas properties		7,810.9		4,515.4		6,917.7		737.8		19,981.8		1,386.9		21,368.7
Gross capitalized costs		8,445.8		4,939.5		6,917.7		905.9		21,208.9		1,386.9		22,595.8
Accumulated depreciation,
depletion and amortization
Unproved oil and gas properties		-171.6		-245.6		–		-96.6		-513.8		–		-513.8
Proved oil and gas properties		-2,944.00		-2,082.10		-2,665.30		-737.8		-8,429.20		-433.1		-8,862.30
Net capitalized costs	$	5,330.2		2,611.8		4,252.4		71.5		12,265.9		953.8		13,219.7
31-Dec-13
Unproved oil and gas properties	$	723.6		475.9		233.5		165.0		1,598.0		–		1,598.0
Proved oil and gas properties		5,816.9		4,529.9		7,636.6		737.8		18,721.2		1,493.5		20,214.7
Gross capitalized costs		6,540.5		5,005.8		7,870.1		902.8		20,319.2		1,493.5		21,812.7
Accumulated depreciation,
depletion and amortization
Unproved oil and gas properties		-178.1		-248.5		–		-91.7		-518.3		–		-518.3
Proved oil and gas properties		-2,171.10		-2,006.80		-2,576.40		-737.8		-7,492.10		-417.6		-7,909.70
Net capitalized costs	$	4,191.3		2,750.5		5,293.7		73.3		12,308.8		1,075.9		13,384.7
*Due to the shutdown of production operations in Republic of the Congo, the Company now includes the results of these operations in the Other exploration and production segment in the above table.
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_Inofrma

Supplemental Quarterly Inofrmation	12 Months Ended
	Dec. 31, 2014
Supplemental Quarterly Information [Abstract]
Supplemental Quaterly Information
	(Millions of dollars except per share amounts)	First		Second	Third	Fourth	Year
		Quarter		Quarter	Quarter	Quarter
	Year Ended December 31, 2014
	Sales and other operating revenues	$	1,281.2	1,357.9	1,431.0	1,218.8	5,288.9
	Income from continuing operations before		334.2	304.6	396.5	217.0	1,252.3
	income taxes
	Income from continuing operations		169.3	142.7	271.0	442.0	1,025.0
	Net income		155.3	129.4	245.7	375.2	905.6
	Income from continuing operations per
	Common share
	Basic		0.94	0.80	1.52	2.49	5.73
	Diluted		0.93	0.79	1.51	2.48	5.69
	Net income per Common share
	Basic		0.86	0.72	1.38	2.11	5.06
	Diluted		0.85	0.72	1.37	2.10	5.03
	Cash dividend per Common share		0.3125	0.3125	0.35	0.35	1.325
	Market price of Common Stock*
	High		63.70	66.82	67.75	56.13	67.75
	Low		55.68	59.61	56.18	44.39	44.39
	Year Ended December 31, 2013
	Sales and other operating revenues	$	1,298.9	1,315.6	1,366.5	1,331.7	5,312.7
	Income from continuing operations before		360.0	454.2	463.7	194.8	1,472.7
	income taxes
	Income from continuing operations		182.7	259.9	265.0	180.5	888.1
	Net income		360.6	402.7	284.8	75.4	1,123.5
	Income from continuing operations per
	Common share
	Basic		0.96	1.38	1.42	0.98	4.73
	Diluted		0.95	1.37	1.41	0.96	4.69
	Net income per Common share
	Basic		1.89	2.13	1.52	0.41	5.98
	Diluted		1.88	2.12	1.51	0.40	5.94
	Cash dividend per Common share		0.3125	0.3125	0.3125	0.3125	1.25
	Market price of Common Stock*
	High		63.81	66.09	71.84	65.55	71.84
	Low		59.33	59.98	59.80	59.93	59.33
	*Prices are as quoted on the New York Stock Exchange.

Valuation_Accounts_and_Reserve

Valuation Accounts and Reserves	12 Months Ended
	Dec. 31, 2014
Valuation Accounts and Reserves [Abstract]
Valuation Accounts and Reserves
	(Millions of dollars)	Balance at		Charged	Deductions	Other*	Balance at
		1-Jan		(Credited)			31-Dec
				to Expense
	2014
	Deducted from asset accounts:
	Allowance for doubtful accounts	$	1.6	–	–	–	1.6
	Deferred tax asset valuation allowance		633.7	37.7	–	-364.9	306.5
	2013
	Deducted from asset accounts:
	Allowance for doubtful accounts	$	6.7	0.4	-0.4	-5.1	1.6
	Deferred tax asset valuation allowance		524.0	115.4	–	-5.7	633.7
	2012
	Deducted from asset accounts:
	Allowance for doubtful accounts	$	7.9	0.3	-1.5	–	6.7
	Deferred tax asset valuation allowance		445.8	78.2	–	–	524.0
	*Amount in 2014 for deferred tax asset valuation allowance is primarily associated with final abandonment of certain foreign investments in 2014, essentially offsetting changes in deferred tax assets.  Amounts in 2013 primarily arose due to separation of Murphy USA Inc. and presentation of U.K. downstream operations as assets held for sale.

Significant_Accounting_Policie1

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
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 has an interest in a Canadian synthetic oil operation.  On August 30, 2013, the Company spun off Murphy USA Inc. (MUSA) to its shareholders.  MUSA formerly was the Company’s U.S. gasoline retail marketing operations.  MUSA is now a separate, publicly owned company traded on the New York Stock Exchange under the symbol “MUSA.”  In addition, Murphy Oil sold its United Kingdom retail marketing assets during 2014 and sold its U.K. oil and natural gas producing assets during 2013.  The Company is in the process of selling components of and decommissioning a crude oil refinery in the U.K. that was shutdown in May 2014.  It also is marketing for sale four U.K. petroleum product terminals as of December 31, 2014.  See Note C regarding more information regarding the spin-off and 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.
Revenue Recognition	REVENUE RECOGNITION – Revenues from sales of crude oil, natural gas liquids, natural gas and refined petroleum products 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 entitlement under existing working interests.  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, 2014 and 2013, the liabilities for natural gas balancing were immaterial.
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 income.  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, 2014, the Company owned Canadian government securities with maturities greater than 90 days at date of acquisition that had a carrying value of $461,313,000.  These securities are readily marketable and could be quickly converted to cash if needed to meet operating cash needs in Canada.
Accounts Receivables	ACCOUNTS RECEIVABLE – At December 31, 2014 and 2013, 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.
	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 is 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 and Canada are being depreciated on a straight-line basis over its estimated useful life ranging from 20 to 25 years.  Gains and losses on asset disposals or retirements are included in income as a separate component of revenues.
	Turnarounds for coking units at Syncrude Canada Ltd. are scheduled at intervals of two to three years.  Turnaround work associated with various other less significant units at Syncrude varies 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.
Capitalization 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 Statement of Income and is added to the cost of the underlying asset for the development project in Property, Plant and Equipment in the Consolidated Balance Sheet.  Capitalized interest is amortized over the useful life of the asset in the same manner as other development costs.
Goodwill	GOODWILL – Goodwill is recorded in an acquisition when the purchase price exceeds the fair value of net assets acquired.  All recorded goodwill arose from the purchase of an oil and natural gas company by Murphy’s wholly owned Canadian subsidiary in 2000.  Goodwill is not amortized, but is assessed annually for recoverability of the carrying value.  The Company assesses goodwill recoverability at each year-end by comparing the fair value of net assets for conventional oil and natural gas properties in Canada with the carrying value of these net assets including goodwill.  The fair value of the conventional oil and natural gas reporting unit is determined using the expected present value of future cash flows.  Based on its assessment of the fair value of its Canadian conventional oil and natural gas operations, the Company recorded an impairment charge of $37,047,000 in the fourth quarter 2014 and reduced the carrying amount to zero.
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.  The Company does not provide U.S. deferred taxes for the portion of undistributed earnings of foreign subsidiaries when these earnings are considered indefinitely reinvested in the respective foreign operations.  The accounting rules for income tax uncertainties permit recognition of income tax benefits only when they are more likely than not to be 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 Income (Loss) in 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 Sheet.  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 other comprehensive income 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 other comprehensive income 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 Sheet.  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 prices.  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 three-year 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 Sheet.  Changes in the funded status which have not yet been recognized in the Statement of Income are recorded net of tax in Accumulated Other Comprehensive Income (Loss).  The remaining amounts in Accumulated Other Comprehensive Income (Loss) as of December 31, 2014 include net actuarial losses and prior service costs.
Net Income Per Common Share	NET INCOME PER COMMON SHARE – Basic income per common share is computed by dividing net income for each reporting period by the weighted average number of common shares outstanding during the period.  Diluted income per common share is computed by dividing net income 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.
Reclassifications	RECLASSIFICATIONS – The Consolidated Balance Sheet for 2013 has been reclassified to conform to the 2014 presentation within current liabilities.  The Consolidated Statements of Income for 2013 and 2012 have been reclassified to disclose separately Lease Operating Expenses and Severance and Ad valorem Taxes and to conform to 2014 presentation.  The Consolidated Statements of Cash Flows have been reclassified in 2013 and 2012 to conform to the 2014 presentation of all cash flow impacts of discontinued operations in a separate category in the statement below financing activities.
Use of Estimates	USE OF ESTIMATES – In preparing the financial statements of the Company in conformity with U.S. generally accepted accounting principles, 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_Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2014
Discontinued Operations [Abstract]
Major Categories of Assets and Liabilities Reflected as Held for Sale
	(Millions of dollars)	2014			2013
	Current assets
	Cash	$	200,512			301,302
	Accounts receivable		97,568			302,059
	Inventory		42,161			254,240
	Other		35,889			86,131
	Total current assets held for sale	$	376,130			943,732
	Non-current assets
	Property, plant and equipment, net	$	50,947			360,347
	Other		13			21,057
	Total non-current assets held for sale	$	50,960			381,404
	Current liabilities
	Accounts payable	$	59,023			484,082
	Other accrued taxes payable		40,653			130,028
	Accrued compensation and severance		30,872			17,020
	Refinery decommissioning cost		21,000			–
	Other		–			8,010
	Total current liabilities associated with	$	151,548			639,140
	assets held for sale
	Non-current liabilities
	Deferred income taxes payable	$	3,873			68,096
	Deferred credits and other liabilities		4,437			27,448
	Total non-current liabilities associated	$	8,310			95,544
	with assets held for sale
Results of Operations Associated with Discontinued Operations
	(Thousands of dollars)	2014		2013		2012
	Revenues	$	2,786,394	17,586,236		24,156,748
	Income (loss) from operations before income taxes	$	-261,873	119,984		330,048
	Gain on sale before income taxes		101,684	130,991		–
	Total income (loss) from discontinued operations before taxes		-160,189	250,975		330,048
	Income tax expense (benefit)		-40,827	15,639		165,666
	Income (loss) from discontinued operations	$	-119,362	235,336		164,382

Inventories_Tables

Inventories (Tables)	12 Months Ended
	Dec. 31, 2014
Inventories [Abstract]
Schedule of Inventory
		December 31,
		2014		2013
	(Thousands of dollars)
	Unsold crude oil	$	51,810	40,077
	Materials and supplies		190,923	254,118
		$	242,733	294,195

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant And Equipment [Abstract]
Property, Plant and Equipment
		31-Dec-14					31-Dec-13
	(Thousands of dollars)	Cost		Net			Cost		Net
	Exploration and production1	$	22,731,220	13,277,985	2		21,932,119		13,433,468	2
	Corporate and other		103,351	53,062			89,175		47,587
		$	22,834,571	13,331,047			22,021,294		13,481,055
	1  Includes mineral rights as follows:	$	924,253	410,482			1,007,920		489,578
	2  Includes $58,334 in 2014 and $48,691
	in 2013 related to administrative assets
	and support equipment.
Net Changes in Capitalized Exploratory Well Costs
	(Thousands of dollars)		2014	2013		2012
	Beginning balance at January 1	$	393,030	445,697		556,412
	Additions to capitalized exploratory well costs pending the		2,874	57,716		135,849
	determination of proved reserves
	Reclassifications to proved properties based on the		-91,236	-93,936		-165,377
	determination of proved reserves
	Reduction of capitalized exploratory well costs due to		-122,175	–		–
	partial asset sale in Malaysia
	Capitalized exploratory well costs charged to expense		-62,038	-16,447		-81,187
	Ending balance at December 31	$	120,455	393,030		445,697
Aging of Capitalized Exploratory Well Costs
		2014						2013					2012
	(Thousands of dollars)	Amount		No. of		No. of		Amount			No. of	No. of	Amount		No. of	No. of
				Wells		Projects					Wells	Projects			Wells	Projects
	Aging of capitalized
	well costs:
	Zero to one year	$	–	–		–		$	56,499		3	1	$	59,833	7	2
	One to two years		59,330	3		1			60,787		7	1		18,335	2	3
	Two to three years		6,606	3		–			–		–	–		83,314	9	4
	Three years or more		54,519	2		2			275,744		22	7		284,215	26	6
		$	120,455	8		3		$	393,030		32	9	$	445,697	44	15

Longterm_Debt_Tables

Long-term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Long-term Debt [Abstract]
Long-term Debt
		December 31,
	(Thousands of dollars)		2014	2013
	Notes payable
	2.50% notes, due 2017	$	550,000	550,000
	3.70% notes, due 2022		600,000	600,000
	4.00% notes, due 2022		500,000	500,000
	7.05% notes, due 2029		250,000	250,000
	5.125% notes, due 2042		350,000	350,000
	Notes payable to banks, 1.4375% at December 31, 2014		450,000	350,000
	Total notes payable		2,700,000	2,600,000
	Unamortized discount on notes payable		-4,953	-5,439
	Total notes payable, net of unamortized discount		2,695,047	2,594,561
	Capitalized lease obligation, due through June 2028		306,579	368,251
	Total debt including current maturities		3,001,626	2,962,812
	Current maturities		-465,388	-26,249
	Total long-term debt	$	2,536,238	2,936,563

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligations [Abstract]
Asset Retirement Obligation
	(Thousands of dollars)	2014		2013
	Balance at beginning of year	$	880,003	751,583
	Accretion expense		50,778	48,996
	Liabilities incurred		70,568	172,048
	Revisions of previous estimates		8,278	-4,856
	Liabilities settled		-36,818	-51,647
	Liabilities assumed by purchaser of oil and gas assets		-69,416	–
	Liabilities assumed by Murphy USA Inc. upon separation		–	-15,401
	Changes due to translation of foreign currencies		-27,665	-20,720
	Balance at end of year		875,728	880,003
	Current portion of liability at end of year*		-34,202	-27,515
	Noncurrent portion of liability at end of year	$	841,526	852,488
	*Included in Other Accrued Liabilities on the Consolidated Balance Sheet.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Taxes [Abstract]
Components of Income from Continuing Operations Before Income Taxes and Income Tax Expense
	(Thousands of dollars)	2014		2013	2012
	Income (loss) from continuing operations before income taxes
	United States	$	179,484	-5,810	54,275
	Foreign		1,072,786	1,478,497	1,313,735
	Total	$	1,252,270	1,472,687	1,368,010
	Income tax expense (benefit)
	Federal – Current	$	25,151	-56,790	-256,931
	– Deferred		25,444	65,883	177,325
			50,595	9,093	-79,606
	State		8,840	7,141	8,104
	Foreign – Current		359,502	477,715	472,701
	– Deferred		-191,640	90,601	160,317
			167,862	568,316	633,018
	Total	$	227,297	584,550	561,516
Reconciliation of Income Taxes Based on U.S. Statutory Tax Rate to Income Tax Expense
	(Thousands of dollars)	2014		2013	2012
	Income tax expense based on the U.S. statutory tax rate	$	438,295	515,440	478,804
	Foreign income subject to foreign tax rates different than		20,562	31,752	7,710
	the U.S. statutory rate
	State income taxes, net of federal benefit		5,746	4,642	5,268
	U.S. tax benefit on certain foreign upstream investments		-95,838	-133,526	-108,077
	Deferred tax benefit on sale of Malaysian assets		-176,661	–	–
	Increase in deferred tax asset valuation allowance related		37,712	129,588	87,558
	to other foreign exploration expenditures
	Impairment or abandonment of Azurite field with no tax benefit		–	35,475	70,000
	Other, net		-2,519	1,179	20,253
	Total	$	227,297	584,550	561,516
Analysis of Deferred Tax Assets and Deferred Tax Liabilities Showing Tax Effects of Significant Temporary Differences
	(Thousands of dollars)	2014		2013
	Deferred tax assets
	Property and leasehold costs	$	379,577	708,947
	Liabilities for dismantlements		85,544	79,111
	Postretirement and other employee benefits		208,600	175,446
	Alternative minimum tax		46,792	49,536
	Foreign tax credit carryforwards		44,061	19,896
	Other deferred tax assets		22,426	23,352
	Total gross deferred tax assets		787,000	1,056,288
	Less valuation allowance		-306,463	-633,735
	Net deferred tax assets		480,537	422,553
	Deferred tax liabilities
	Property, plant and equipment		-479,677	-747,561
	Accumulated depreciation, depletion and amortization		-1,123,864	-1,040,251
	Other deferred tax liabilities		-15,753	-38,849
	Total gross deferred tax liabilities		-1,619,294	-1,826,661
	Net deferred tax liabilities	$	-1,138,757	-1,404,108
Reconciliation of Beginning and Ending Amount of Consolidated Liability for Unrecognized Income Tax Benefits
	(Thousands of dollars)	2014		2013	2012
	Balance at January 1	$	6,366	16,611	18,857
	Additions for tax positions related to current year		988	2,486	1,258
	Settlements due to lapse of time		-1,225	-12,731	-3,504
	Foreign currency translation effect		-118	–	–
	Balance at December 31	$	6,011	6,366	16,611

Incentive_Plans_Tables

Incentive Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Incentive Plans [Abstract]
Share-Based Plans, Amounts Recognized
	(Thousands of dollars)	2014			2013		2012
	Compensation charged against income before	$	53,157		66,976		46,694
	income tax benefit
	Related income tax benefit recognized in income		15,604		19,321		14,443
Fair Value of Option Award Estimated on Date of Grant using Black-Scholes Pricing Model
		2014		2013		2012
	Fair value per option grant	$12.84		$15.81 – $20.62		$12.37 – $17.74
	Assumptions
	Dividend yield	2.00%		2.10% – 2.30%		1.80% – 2.27%
	Expected volatility	29.00%		34.00% – 36.00%		39.00% – 39.62%
	Risk-free interest rate	1.62%		0.96% – 2.00%		0.55% – 0.77%
	Expected life	5.35 yrs.		5.25 yrs. – 6.50 yrs.		4.00 yrs. – 5.20 yrs.
Changes in Stock Options Outstanding
		Number of		Average
		Shares		Exercise
				Price
	Outstanding at December 31, 2011	5,434,228		$	55.17
	Granted at FMV	1,870,500			57.96
	Exercised	-823,855			38.37
	Forfeited	-573,514			60.43
	Outstanding at December 31, 2012	5,907,359			55.17
	Granted at FMV	1,320,176			55.26
	Exercised	-1,335,355			45.84
	Forfeited	-228,576			58.01
	Surrendered in connection with separation of Murphy USA Inc.	-272,936			55.99
	Murphy USA Inc. spin-off adjustment	615,917			52.09
	Outstanding at December 31, 2013	6,006,585			56.80
	Granted at FMV	772,900			55.82
	Exercised	-862,407			49.27
	Forfeited	-314,828			54.53
	Outstanding at December 31, 2014	5,602,250			57.95
	Exercisable at December 31, 2011	2,319,735		$	51.14
	Exercisable at December 31, 2012	2,474,636			54.43
	Exercisable at December 31, 2013	2,435,322			51.79
	Exercisable at December 31, 2014	3,030,105			53.10
Additional Information about Stock Options Outstanding
			Options Outstanding						Options Exercisable
	Range of Exercise		No. of		Avg. Life		Aggregate		No. of	Avg. Life	Aggregate
	Prices per Option		Options		Remaining		Intrinsic		Options	Remaining	Intrinsic
					in Years		Value			in Years	Value
	$37.44 to $39.02		444,524		2.4		$	5,533,247	356,103	1.9	$	4,516,795
	$43.88 to $51.63		1,772,764		1.8			2,786,024	1,162,708	2.4		2,786,024
	$54.21 to $63.46		3,384,962		4			–	1,511,294	2.1		–
			5,602,250		3.6		$	8,319,271	3,030,105	2.4	$	7,302,819
Changes in Performance-Based RSU Outstanding
	(Number of share units)	2014		2013		2012
	Outstanding at beginning of year	1,560,292		1,426,238		1,174,492
	Granted	464,300		521,776		653,355
	Awarded	-473,186		-380,150		-260,175
	Forfeited	-154,366		-39,573		-141,434
	Surrendered in connection with	–		-116,568		–
	separation of Murphy USA Inc.
	Murphy USA Inc. spin-off adjustment	–		148,569		–
	Outstanding at end of year	1,397,040		1,560,292		1,426,238
Assumptions used in Valuation of Performance Awards Granted
		2014		2013		2012
	Fair value per share at grant date	$33.90 – $51.30		$39.50 – $68.01		$54.90 – $63.64
	Assumptions
	Expected volatility	29.00%		31.00% – 32.00%		37.00%
	Risk-free interest rate	0.65%		0.41% – 0.62%		0.30%
	Stock beta	0.843		0.907 – 0.908		0.913
	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)	2014		2013		2012
	Outstanding at beginning of year	112,881		98,477		116,724
	Granted	278,892		38,184		42,256
	Vested and issued	-54,884		-34,696		-44,980
	Forfeited	-15,100		–		-15,523
	Murphy USA Inc. spin-off adjustment	–		10,916		–
	Outstanding at end of year	321,789		112,881		98,477

Employee_and_Retiree_Benefit_P1

Employee and Retiree Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Pension And Other Postretirement Benefits Disclosure [Line Items]
Amounts Included in Accumulated Other Comprehensive Income Not Recognized in Net Periodic Benefit Expense
	(Thousands of dollars)	Pension			Other
		Benefits			Postretirement
					Benefits
	Net actuarial loss	$	-256,821		-21,948
	Prior service (cost) credit		-2,456		289
		$	-259,277		-21,659
Amounts Included in Accumulated Other Comprehensive Income Expected to be Amortization into Net Periodic Benefit Expense
	(Thousands of dollars)	Pension			Other
		Benefits			Postretirement
					Benefits
	Net actuarial loss	$	-16,706		-778
	Prior service (cost) credit		-854		82
		$	-17,560		-696
Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets for Plans where Accumulated Benefit Obligation Exceeded Fair Value of Plan Assets
		Projected					Accumulated				Fair Value
		Benefit Obligations					Benefit Obligations				of Plan Assets
	(Thousands of dollars)	2014			2013		2014		2013		2014		2013
	Funded qualified plans where	$	658,618		571,217		597,918		520,610		533,165		502,308
	accumulated benefit obligation
	exceeds fair value of plan assets
	Unfunded nonqualified and directors'		147,018		115,492		127,200		102,198		–		–
	plans where accumulated benefit
	obligation exceeds fair value of
	plan assets
	Unfunded other postretirement plans		118,496		107,001		118,496		107,001		–		–
Components of Net Periodic Benefit Expense
		Pension Benefits							Other
									Postretirement Benefits
	(Thousands of dollars)		2014		2013		2012		2014		2013		2012
	Service cost	$	22,470		26,346		23,500		2,459		4,566		3,958
	Interest cost		33,680		30,903		29,869		4,617		5,189		5,174
	Expected return on plan assets		-33,723		-28,974		-25,826		–		–		–
	Amortization of prior service		899		1,006		1,254		-82		-143		-173
	cost (credit)
	Amortization of transitional		-480		-514		-529		–		8		8
	(asset) liability
	Recognized actuarial loss		9,471		17,338		16,389		5		1,484		1,317
			32,317		46,105		44,657		6,999		11,104		10,284
	Termination benefits expense		–		849		6,177		–		–		–
	Curtailment expense (benefit)		–		1,365		–		–		-442		–
	Net periodic benefit expense	$	32,317		48,319		50,834		6,999		10,662		10,284
Weighted-Average Assumptions used in Measurement of Benefit Obligations and Net Periodic Benefit Expense
		Benefit Obligations								Net Periodic Benefit Expense
		Pension				Other				Pension				Other
		Benefits				Postretirement				Benefits				Postretirement
						Benefits								Benefits
		31-Dec				31-Dec				Year				Year
		2014		2013		2014		2013		2014		2013		2014	2013
	Discount rate	3.94%		4.78%		4.12%		4.91%		4.56%		4.23%		4.91%	4.18%
	Expected return on plan assets	6.11%		6.24%		–		–		6.11%		6.24%		–	–
	Rate of compensation increase	3.69%		4.14%		–		–		3.69%		4.12%		–	–
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			Other
		Benefits			Postretirement
					Benefits
	2015	$	33,516		6,349
	2016		34,212		6,573
	2017		35,144		6,730
	2018		36,439		6,943
	2019		37,671		7,225
	2020-2024		208,294		40,535
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	$	1,190		-942
	benefit expense for the year ended December 31, 2014
	Effect on the health care component of the accumulated postretirement benefit		17,879		-14,456
	obligation at December 31, 2014
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, 2012		$	14,654
	Actual return on plan assets:
	Relating to assets held at the reporting date			3,134
	Relating to assets sold during the period			–
	Purchases, sales and settlements			15,000
	Total at December 31, 2013			32,788
	Actual return on plan assets:
	Relating to assets held at the reporting date			1,164
	Relating to assets sold during the period			–
	Purchases, sales and settlements			–
	Total at December 31, 2014		$	33,952
Domestic Plans [Member]
Pension And Other Postretirement Benefits Disclosure [Line Items]
Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status
		Pension					Other
		Benefits					Postretirement
							Benefits
	(Thousands of dollars)	2014			2013		2014		2013
	Change in benefit obligation
	Obligation at January 1	$	707,254		721,531		107,001		124,134
	Service cost		22,470		26,346		2,459		4,566
	Interest cost		33,680		30,903		4,617		5,189
	Plan amendments		–		1,989		–		–
	Participant contributions		5		21		1,406		1,376
	Actuarial loss (gain)		122,824		-9,876		8,150		-8,324
	Medicare Part D subsidy		–		–		404		384
	Exchange rate changes		-14,614		1,852		-55		-36
	Benefits paid		-35,044		-38,745		-5,486		-5,211
	Special termination benefits		–		849		–		–
	Curtailments		-11,023		-26,463		–		-15,077
	Obligation assumed by MUSA at separation		–		-1,153		–		–
	Obligation at December 31		825,552		707,254		118,496		107,001
	Change in plan assets
	Fair value of plan assets at January 1		533,108		463,546		–		–
	Actual return on plan assets		31,340		61,932		–		–
	Employer contributions		47,279		46,726		3,676		3,451
	Participant contributions		5		21		1,406		1,376
	Medicare Part D subsidy		–		–		404		384
	Exchange rate changes		-13,284		1,594		–		–
	Benefits paid		-35,044		-38,745		-5,486		-5,211
	Other		-2,426		-1,966		–		–
	Fair value of plan assets at December 31		560,978		533,108		–		–
	Funded status and amounts recognized in the
	Consolidated Balance Sheets at December 31
	Deferred charges and other assets		7,899		10,254		–		–
	Other accrued liabilities		-5,996		-5,565		-5,515		-5,920
	Deferred credits and other liabilities		-252,237		-158,589		-112,981		-101,081
	Liabilities associated with assets held for sale		-14,240		-20,246		–		–
	Funded status and net plan liability recognized	$	-264,574		-174,146		-118,496		-107,001
	at December 31
Foreign Plans [Member]
Pension And Other Postretirement Benefits Disclosure [Line Items]
Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status
		Pension					Other
		Benefits					Postretirement
							Benefits
	(Thousands of dollars)	2014			2013		2014		2013
	Benefit obligation at December 31	$	222,497		211,799		648		541
	Fair value of plan assets at December 31		202,305		188,575		–		–
	Net plan liabilities recognized		20,192		23,224		648		541
	Net periodic benefit expense		12,968		12,622		152		92
Other Postretirement Benefits [Member]
Pension And Other Postretirement Benefits Disclosure [Line Items]
Asset Allocation for Benefit Plans	At December 31, 2014, 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			Quoted Prices		Significant		Significant
		31-Dec-14			in Active Markets		Other Observable		Unobservable
					for Identical Assets		Inputs		Inputs
					(Level 1)		(Level 2)		(Level 3)
	Domestic Plans
	Equity securities:
	U.S. core equity	$	67,863		67,863		–		–
	U.S. small/midcap		33,709		33,709		–		–
	Hedged funds and other		52,905		–		18,953		33,952
	alternative strategies
	International commingled		75,702		–		75,702		–
	trust fund
	Emerging market commingled		19,908		–		19,908		–
	equity fund
	Fixed income securities:
	U.S. fixed income		80,577		–		80,577		–
	International commingled		17,559		–		17,559		–
	trust fund
	Emerging market mutual fund		8,069		–		8,069		–
	Cash and equivalents		2,381		2,381		–		–
	Total Domestic Plans		358,673		103,953		220,768		33,952
	Foreign Plans
	Equity securities funds		106,694		–		106,694		–
	Fixed income securities funds		66,435		–		66,435		–
	Diversified pooled fund		27,813		–		27,813		–
	Cash and equivalents		1,363		1,363		–		–
	Total Foreign Plans		202,305		1,363		200,942		–
	Total	$	560,978		105,316		421,710		33,952
	At December 31, 2013, 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			Quoted Prices		Significant		Significant
		31-Dec-13			in Active Markets		Other Observable		Unobservable
					for Identical Assets		Inputs		Inputs
					(Level 1)		(Level 2)		(Level 3)
	Domestic Plans
	Equity securities:
	U.S. core equity	$	89,255		89,255		–		–
	U.S. small/midcap		37,149		37,149		–		–
	Hedged funds and other		32,788		–		–		32,788
	alternative strategies
	International commingled		77,041		–		77,041		–
	trust fund
	Emerging market commingled		9,654		–		9,654		–
	equity fund
	Fixed income securities:
	U.S. fixed income		72,240		–		72,240		–
	International commingled		14,865		–		14,865		–
	trust fund
	Emerging market mutual fund		8,549		–		8,549		–
	Cash and equivalents		2,992		2,992		–		–
	Total Domestic Plans		344,533		129,396		182,349		32,788
	Foreign Plans
	Equity securities funds		99,085		–		99,085		–
	Fixed income securities funds		57,030		–		57,030		–
	Diversified pooled fund		30,800		–		30,800		–
	Cash and equivalents		1,660		1,660		–		–
	Total Foreign Plans		188,575		1,660		186,915		–
	Total	$	533,108		131,056		369,264		32,788
Funded Defined Benefit Pension Plans [Member]
Pension And Other Postretirement Benefits Disclosure [Line Items]
Asset Allocation for Benefit Plans
		December 31,
		2014			2013
	Equity securities	66.6	%		68.4	%
	Fixed income securities	32.5			30.7
	Cash equivalents	0.9			0.9
		100.0	%		100.0	%

Financial_Instruments_and_Risk1

Financial Instruments and Risk Management (Tables)

12 Months Ended

Dec. 31, 2014

Financial Instruments and Risk Management [Abstract]

Fair Value of Derivative Instruments Not Designated as Hedging Instruments

31-Dec-14

31-Dec-13

Asset Derivatives

Liability Derivatives

Asset Derivatives

Liability Derivatives

(Thousands of dollars)

Balance

Fair

Balance

Fair

Balance

Fair

Balance

Fair

Sheet

Value

Sheet

Value

Sheet

Value

Sheet

Value

Location

Location

Location

Location

Type of

Derivative Contract

Commodity

Accounts

$

–

–

Accounts

$

–

–

Receivable

23,168

Receivable

1,970

Foreign exchange

–

–

Accounts

$

–

–

Accounts

$

Payable

25

Payable

1,038

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

Year Ended December 31, 2014

Year Ended December 31, 2013

(Thousands of dollars)

Location of

Amount of

Location of

Amount of

Gain (Loss)

Gain (Loss)

Gain (Loss)

Gain (Loss)

Recognized

Recognized

Recognized

Recognized

in Income

in Income

in Income

in Income

on Derivative

on Derivative

on Derivative

on Derivative

Type of

Derivative Contract

Commodity

Sale and Other

$

17,887

Sale and Other

$

2,104

Operating Revenues

Operating Revenues

Commodity

–

–

Discontinued

-1,604

Operations

Foreign exchange

Interest and

4,226

Interest and

-5,162

Other Income

Other Income

$

22,113

$

-4,662

Earnings_per_Share_Tables

Earnings per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings per Share [Abstract]
Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share
	(Weighted-average shares outstanding)	2014	2013	2012
	Basic method	178,852,942	187,921,062	193,902,335
	Dilutive stock options	1,218,042	1,350,336	766,402
	Diluted method	180,070,984	189,271,398	194,668,737
Anti Dilutive Securities Not Included in Computation of Diluted EPS
		2014	2013	2012
	Antidilutive stock options excluded from diluted shares	1,893,364	1,026,900	3,329,689
	Weighted average price of these options	$	$	$
		55.21	54.54	64.72

Other_Financial_Information_Ta

Other Financial Information (Tables)	12 Months Ended
	Dec. 31, 2014
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Noncash Operating Working Capital (Increased) Decreased
	(Thousands of dollars)	2014		2013	2012
	Accounts receivable	$	175,820	224,281	-382,137
	Inventories		25,697	14,166	-94,907
	Prepaid expenses		6,575	195,013	-245,881
	Deferred income tax assets		6,884	15,510	-7,218
	Accounts payable and accrued liabilities		-54,785	-176,543	534,353
	Current income tax liabilities		-163,920	-6,098	27,610
	Net (increase) decrease in noncash	$	-3,729	266,329	-168,180
	operating working capital

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Abstract]
Components of Accumulated Other Comprehensive Income
	(Thousands of dollars)	Foreign			Retirement and		Deferred		Total1
		Currency			Postretirement		Loss on
		Translation			Benefit Plan		Interest
		Gains (Losses)1			Adjustments1		Rate
							Derivative
							Hedges1
	Balance at December 31, 2012	$	613,492		-186,539		-18,052		408,901
	2013 components of other comprehensive income (loss):
	Before reclassifications to income		-240,300		59,145		–		-181,155
	Reclassifications to income		-68,000	2	10,438	3	1,935	4	-55,627
	Net other comprehensive income (loss)		-308,300		69,583		1,935		-236,782
	Balance at December 31, 2013		305,192		-116,956		-16,117		172,119
	2014 components of other comprehensive income (loss):
	Before reclassifications to income		-271,491		-79,403		–		-350,894
	Reclassifications to income		–		6,607	3	1,913	4	8,520
	Net other comprehensive income (loss)		-271,491		-72,796		1,913		-342,374
	Balance at December 31, 2014	$	33,701		-189,752		-14,204		-170,255
		1		All amounts are presented net of income taxes.
		2		Reclassification is included in income from discontinued operations, net of income taxes.
		3		Reclassifications before taxes of $18,570 and $9,813 are included in the computation of net periodic benefit expense in 2013 and 2014, respectively.  Related income taxes of $8,132 and $3,206 are included in Income tax expense in 2013 and 2014, respectively.
		4		Reclassifications before taxes of $2,963 are included in Interest expense in both 2013 and 2014.  Related income taxes of $1,028 and $1,050 are included in Income tax expense in 2013 and 2014, respectively.

Assets_and_Liabilities_Measure1

Assets and Liabilities Measured at Fair Value (Tables)	12 Months Ended
	Dec. 31, 2014
Assets and Liabilities Measured at Fair Value [Abstract]
Carrying Value of Assets and Liabilities Recorded at Fair Value on Recurring Basis
				Fair Value Measurements at Reporting Date Using
	(Thousands of dollars)	Fair Value at		Quoted Prices	Significant	Significant
		31-Dec-14		in Active Markets	Other Observable	Unobservable
				for Identical	Inputs	Inputs
				Assets (Liabilities)	(Level 2)	(Level 3)
				(Level 1)
	Assets
	Commodity derivative contracts	$	23,168	–	23,168	–
	Liabilities
	Nonqualified employee savings plan	$	-14,408	-14,408	–	–
	Foreign currency exchange		-25	–	-25	–
	derivative contracts
	Total	$	-14,433	-14,408	-25	–
				Fair Value Measurements at Reporting Date Using
	(Thousands of dollars)	Fair Value at		Quoted Prices	Significant	Significant
		31-Dec-13		in Active Markets	Other Observable	Unobservable
				for Identical	Inputs	Inputs
				Assets (Liabilities)	(Level 2)	(Level 3)
				(Level 1)
	Assets
	Commodity derivative contracts	$	1,970	–	1,970	–
	Liabilities
	Nonqualified employee savings plan	$	-13,267	-13,267	–	–
	Foreign currency exchange		-1,038	–	-1,038	–
	derivative contracts
	Total	$	-14,305	-13,267	-1,038	–
Carrying Amounts and Estimated Fair Values of Financial Instruments
		At December 31,
		2014			2013
	(Thousands of dollars)	Carrying		Fair	Carrying	Fair
		Amount		Value	Amount	Value
	Financial assets (liabilities):
	Canadian government securities with maturities	$	461,313	462,056	374,842	375,623
	greater than 90 days at the date of acquisition
	Current and long-term debt		-3,001,626	-2,774,065	-2,962,812	-2,822,827

Common_Stock_Issued_and_Outsta1

Common Stock Issued and Outstanding (Tables)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Activity in Number of Shares of Common Stock Issued and Outstanding
	(Number of shares outstanding)	2014	2013	2012
	At beginning of year	183,406,513	190,641,317	193,723,208
	Stock options exercised*	119,994	303,685	482,974
	Restricted stock awards*	339,985	300,910	224,296
	Employee stock purchase and thrift plans	6,739	16,020	78,389
	Treasury shares purchased	-6,373,718	-7,855,419	-3,867,550
	At end of year	177,499,513	183,406,513	190,641,317
	*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, 2014
Business Segments [Abstract]
Segment Information
	Segment Information	Exploration and Production
	(Millions of dollars)	United		Canada	Malaysia	Other*	Total
		States					E&P
	Year ended December 31, 2014
	Segment income (loss)	$	387.1	156.5	896.2	-250	1,189.8
	Revenues from external customers		2,196.4	1,044.1	2,183.5	-1.3	5,422.7
	Interest income		–	–	–	–	–
	Interest expense, net of capitalization		–	–	–	–	–
	Income tax expense (benefit)		214.8	64.2	102.6	-95.9	285.7
	Significant noncash charges (credits)
	Depreciation, depletion and amortization		840.7	316.7	735.0	5.1	1,897.5
	Accretion of asset retirement obligations		17.5	15.2	18.1	–	50.8
	Amortization of undeveloped leases		50.1	19.4	–	4.9	74.4
	Impairment of assets		14.3	37.0	–	–	51.3
	Deferred and noncurrent income taxes		39.7	43.3	-235.1	–	-152.1
	Additions to property, plant, equipment		2,028.7	445.9	818.0	10.7	3,303.3
	Total assets at year-end		5,745.7	3,769.8	4,887.1	138.7	14,541.3
	Year ended December 31, 2013
	Segment income (loss)	$	435.4	180.8	786.4	-373.8	1,028.8
	Revenues from external customers		1,803.8	1,144.7	2,280.5	83.6	5,312.6
	Interest income		–	–	–	–	–
	Interest expense, net of capitalization		–	–	–	–	–
	Income tax expense (benefit)		241.6	57.8	477.7	-120.8	656.3
	Significant noncash charges (credits)
	Depreciation, depletion and amortization		576.3	374.6	588.2	4.5	1,543.6
	Accretion of asset retirement obligations		13.5	16.2	15.0	4.3	49.0
	Amortization of undeveloped leases		30.3	21.0	–	15.6	66.9
	Impairment of assets		–	21.6	–	–	21.6
	Deferred and noncurrent income taxes		99.6	26.1	48.1	–	173.8
	Additions to property, plant, equipment		1,785.9	334.5	1,323.4	64.8	3,508.6
	Total assets at year-end		4,530.0	4,087.8	6,121.0	180.4	14,919.2
	Year ended December 31, 2012
	Segment income (loss)	$	168.0	208.1	894.2	-365.3	905.0
	Revenues from external customers		1,038.0	1,084.3	2,428.1	57.7	4,608.1
	Interest income		–	–	–	–	–
	Interest expense, net of capitalization		–	–	–	–	–
	Income tax expense (benefit)		99.8	65.1	544.7	-104.6	605.0
	Significant noncash charges (credits)
	Depreciation, depletion and amortization		330.2	345.8	532.1	36.3	1,244.4
	Accretion of asset retirement obligations		11.4	13.6	12.5	0.9	38.4
	Amortization of undeveloped leases		71.6	29.3	–	28.9	129.8
	Impairment of assets		–	–	–	200.0	200.0
	Deferred and noncurrent income taxes		231.0	72.3	73.3	-1.5	375.1
	Additions to property, plant, equipment		1,615.9	887.2	1,426.7	4.0	3,933.8
	Total assets at year-end		3,625.9	4,477.7	4,811.5	187.8	13,102.9
	Geographic Information	Certain Long-Lived Assets at December 31
	(Millions of dollars)	United		Canada	Malaysia	United	Other*	Total
		States				Kingdom
	2014	$	5,419.5	3,574.6	4,258.8	0.4	78.1	13,331.4
	2013		4,267.9	3,834.9	5,301.7	0.4	76.6	13,481.5
	2012		4,177.4	4,190.5	4,101.2	703.2	45.1	13,217.4
	*Reclassified to conform to current presentation.
	Segment Information (Continued)
	(Millions of dollars)	Corporate		Discontinued	Consolidated
		and		Operations	Total
		Other
	Year ended December 31, 2014
	Segment income (loss)	$	-164.8	-119.4	905.6
	Revenues from external customers		53.4	–	5,476.1
	Interest income		7.7	–	7.7
	Interest expense, net of capitalization		115.8	–	115.8
	Income tax expense (benefit)		-58.4	–	227.3
	Significant noncash charges (credits)
Depreciation, depletion and amortization		8.7	–	1,906.2
Accretion of asset retirement obligations		–	–	50.8
Amortization of undeveloped leases		–	–	74.4
Impairment of assets		–	–	51.3
Deferred and noncurrent income taxes		-18.8	–	-170.9
Additions to property, plant, equipment		14.5	–	3,317.8
Total assets at year-end		1,773.9	427.1	16,742.3
Year ended December 31, 2013
Segment income (loss)	$	-140.7	235.4	1,123.5
Revenues from external customers		77.5	–	5,390.1
Interest income		3.9	–	3.9
Interest expense, net of capitalization		71.9	–	71.9
Income tax expense (benefit)		-71.7	–	584.6
Significant noncash charges (credits)
Depreciation, depletion and amortization		9.8	–	1,553.4
Accretion of asset retirement obligations		–	–	49.0
Amortization of undeveloped leases		–	–	66.9
Impairment of assets		–	–	21.6
Deferred and noncurrent income taxes		-15.7	–	158.1
Additions to property, plant, equipment		15.5	8.1	3,532.2
Total assets at year-end		1,265.2	1,325.1	17,509.5
Year ended December 31, 2012
Segment income (loss)	$	-98.5	164.4	970.9
Revenues from external customers		11.5	–	4,619.6
Interest income		6.5	–	6.5
Interest expense, net of capitalization		14.9	–	14.9
Income tax expense (benefit)		-43.5	–	561.5
Significant noncash charges (credits)
Depreciation, depletion and amortization		8.7	–	1,253.1
Accretion of asset retirement obligations		–	–	38.4
Amortization of undeveloped leases		–	–	129.8
Impairment of assets		–	–	200.0
Deferred and noncurrent income taxes		-32.3	–	342.8
Additions to property, plant, equipment		8.2	191.8	4,133.8
Total assets at year-end		1,009.6	3,410.1	17,522.6
Geographic Information	Revenues from External Customers for the Year
(Millions of dollars)	United		Canada	Malaysia	Other	Total
	States
2014	$	2,201.5	1,052.4	2,233.0	-10.8	5,476.1
2013		1,798.5	1,150.2	2,337.5	103.9	5,390.1
2012		1,038.1	1,088.4	2,415.6	77.5	4,619.6

Supplemental_Oil_and_Gas_Infor1

Supplemental Oil and Gas Information (Tables)	12 Months Ended
	Dec. 31, 2014
Reserve Quantities [Line Items]
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities	(Millions of dollars)	United			Canada		Malaysia		United		Other2		Total
		States							Kingdom1
	Year Ended December 31, 2014
	Property acquisition costs
	Unproved	$	92.9		–		–		–		–		92.9
	Proved		7.4		–		–		–		–		7.4
	Total acquisition costs		100.3		–		–		–		–		100.3
	Exploration costs3		160.0		1.7		6.3		–		262.1		430.1
	Development costs3		1,934.7		413.8		926.6		–		7.6		3,282.7
	Total costs incurred		2,195.0		415.5		932.9		–		269.7		3,813.1
	Charged to expense
	Dry hole expense		92.1		–		47.4		–		130.5		270.0
	Geophysical and other costs		37.7		1.7		1.3		–		128.5		169.2
	Total charged to expense		129.8		1.7		48.7		–		259.0		439.2
	Property additions	$	2,065.2		413.8		884.2		–		10.7		3,373.9
	Year Ended December 31, 2013
	Property acquisition costs
	Unproved	$	32.4		–		–		–		3.2		35.6
	Proved		13.2		–		–		–		–		13.2
	Total acquisition costs		45.6		–		–		–		3.2		48.8
	Exploration costs3		112.4		21.8		14.9		–		344.6		493.7
	Development costs3		1,773.2		351.6		1,787.7	4	8.1		19.0		3,939.6
	Total costs incurred		1,931.2		373.4		1,802.6		8.1		366.8		4,482.1
	Charged to expense
	Dry hole expense		46.1		32.1		20.7		–		164.0		262.9
	Geophysical and other costs		29.1		0.7		4.6		–		138.0		172.4
	Total charged to expense		75.2		32.8		25.3		–		302.0		435.3
	Property additions	$	1,856.0		340.6		1,777.3		8.1		64.8		4,046.8
	Year Ended December 31, 2012
	Property acquisition costs
	Unproved	$	107.7		14.6		–		–		10.2		132.5
	Proved		69.1		242.4		–		–		–		311.5
	Total acquisition costs		176.8		257.0		–		–		10.2		444.0
	Exploration costs3		174.5		57.0		68.8		-1		148.7		448.0
	Development costs3		1,352.7		664.5		1,433.7		46.6		24.2		3,521.7
	Total costs incurred		1,704.0		978.5		1,502.5		45.6		183.1		4,413.7
	Charged to expense
	Dry hole expense		32.3		8.0		26.1		-0.8		115.5		181.1
	Geophysical and other costs		19.6		2.5		1.1		-0.2		46.0		69.0
	Total charged to expense		51.9		10.5		27.2		-1		161.5		250.1
	Property additions	$	1,652.1		968.0		1,475.3		46.6		21.6		4,163.6
		1		The Company has accounted for U.K. operations as discontinued operations due to the sale of these operations in the first half of 2013.
		2		Due to the shutdown of production operations in Republic of the Congo, the Company now includes the result of these operations in the Other exploration and production segment in the above table.
		3		Includes non-cash asset retirement costs as follows:
	2014
	Exploration costs	$	–		–		–		–		–		–
	Development costs		36.5		-32.1		66.2		–		–		70.6
		$	36.5		-32.1		66.2		–		–		70.6
	2013
	Exploration costs	$	–		0.2		–		–		–		0.2
	Development costs		70.1		5.9		95.9		–		–		171.9
		$	70.1		6.1		95.9		–		–		172.1
	2012
	Exploration costs	$	-1.7		0.1		–		–		–		-1.6
	Development costs		37.9		80.7		48.6		-11.5		17.6		173.3
		$	36.2		80.8		48.6		-11.5		17.6		171.7
		4		Includes property costs associated with non-cash capital lease of $358.0 million at the Kakap field.
Results of Operations for Oil andGas Producing Activities					Canada
		United			Conven-
	(Millions of dollars)	States			tional		Synthetic		Malaysia		Other2		Total
	Year Ended December 31, 2014
	Revenues												–
	Crude oil and natural gas liquids sales	$	2,062.1		453.3		391.5		1,680.2		–		4,587.1
	Natural gas sales		127.2		201.3		–		357.5		–		686.0
	Total oil and gas revenues		2,189.3		654.6		391.5		2,037.7		–		5,273.1
	Other operating revenues		7.1		-2.4		0.4		145.8		-1.3		149.6
	Total revenues		2,196.4		652.2		391.9		2,183.5		-1.3		5,422.7
	Costs and expenses
	Lease operating expenses		345.5		160.3		233.8		350.3		–		1,089.9
	Severance and ad valorem taxes		96.5		5.6		5.1		–		–		107.2
	Exploration costs charged to expense		129.8		1.7		–		48.7		259.0		439.2
	Undeveloped lease amortization		50.1		19.4		–		–		4.9		74.4
	Depreciation, depletion and amortization		840.7		262.7		54.0		735.0		5.1		1,897.5
	Accretion of asset retirement obligations		17.5		6.0		9.2		18.1		–		50.8
	Impairment of assets		14.3		37.0		–		–		–		51.3
	Selling and general expenses		95.2		26.7		0.9		15.7		73.5		212.0
	Other expenses		4.9		1.0		–		16.9		2.1		24.9
	Total costs and expenses		1,594.5		520.4		303.0		1,184.7		344.6		3,947.2
	Results of operations before taxes		601.9		131.8		88.9		998.8		-345.9		1,475.5
	Income tax expense (benefit)		214.8		42.4		21.8		102.6		-95.9		285.7
	Results of operations	$	387.1		89.4		67.1		896.2		-250		1,189.8
	Year Ended December 31, 2013
	Revenues
	Crude oil and natural gas liquids sales	$	1,724.7		507.2		441.0		1,875.0		83.6		4,631.5
	Natural gas sales		72.7		198.1		–		404.0		–		674.8
	Total oil and gas revenues		1,797.4		705.3		441.0		2,279.0		83.6		5,306.3
	Other operating revenues		6.4		-1.9		0.3		1.5		–		6.3
	Total revenues		1,803.8		703.4		441.3		2,280.5		83.6		5,312.6
	Costs and expenses
	Lease operating expenses		273.6		180.5		223.4		384.4		191.0		1,252.9
	Severance and ad valorem taxes		77.5		5.0		4.8		–		–		87.3
	Exploration costs charged to expense		75.2		32.8		–		25.3		302.0		435.3
	Undeveloped lease amortization		30.3		21.0		–		–		15.6		66.9
	Depreciation, depletion and amortization		576.3		319.2		55.4		588.2		4.5		1,543.6
	Accretion of asset retirement obligations		13.5		5.9		10.3		15.0		4.3		49.0
	Impairment of assets		–		21.6		–		–		–		21.6
	Selling and general expenses		80.4		25.3		0.9		3.5		60.8		170.9
	Total costs and expenses		1,126.8		611.3		294.8		1,016.4		578.2		3,627.5
	Results of operations before taxes		677.0		92.1		146.5		1,264.1		-494.6		1,685.1
	Income tax expense (benefit)		241.6		19.9		37.9		477.7		-120.8		656.3
	Results of operations	$	435.4		72.2		108.6		786.4		-373.8		1,028.8
		1		Results exclude corporate overhead, interest and discontinued operations.
		2		Due to the shutdown of production operations in Republic of the Congo, the Company now includes the results of these operations in the Other exploration and production segment in the above tables.
	Schedule 5 – Results of Operations for Oil and Gas Producing Activities1 – Continued
					Canada
		United			Conven-
	(Millions of dollars)	States			tional		Synthetic		Malaysia		Other2		Total
	Year Ended December 31, 2012
	Revenues
	Crude oil and natural gas liquids sales	$	976.1		411.7		463.1		1,946.0		57.6		3,854.5
	Natural gas sales		54.2		209.8		–		481.1		–		745.1
	Total oil and gas revenues		1,030.3		621.5		463.1		2,427.1		57.6		4,599.6
	Other operating revenues		7.7		-0.9		0.6		1.0		0.1		8.5
	Total revenues		1,038.0		620.6		463.7		2,428.1		57.7		4,608.1
	Costs and expenses
	Lease operating expenses		225.4		163.7		219.0		422.7		48.4		1,079.2
	Severance and ad valorem taxes		27.0		3.5		5.1		–		–		35.6
	Exploration costs charged to expense		51.9		10.5		–		27.2		161.5		251.1
	Undeveloped lease amortization		71.6		29.3		–		–		28.9		129.8
	Depreciation, depletion and amortization		330.2		290.5		55.3		532.1		36.3		1,244.4
	Accretion of asset retirement obligations		11.4		5.1		8.5		12.5		0.9		38.4
Impairment of assets		–		–		–		–		200.0		200.0
Selling and general expenses		52.7		19.7		0.9		-5.3		51.6		119.6
Total costs and expenses		770.2		522.3		288.8		989.2		527.6		3,098.1
Results of operations before taxes		267.8		98.3		174.9		1,438.9		-469.9		1,510.0
Income tax expense (benefit)		99.8		25.1		40.0		544.7		-104.6		605.0
Results of operations	$	168.0		73.2		134.9		894.2		-365.3		905.0
	1		Results exclude corporate overhead, interest and discontinued operations.
	2		Due to the shutdown of production operations in Republic of the Congo, the Company now includes the results of these operations in the Other exploration and production segment in the above table.
Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves
	(Millions of dollars)	United			Canada		Malaysia		United		Total
		States							Kingdom
	31-Dec-14
	Future cash inflows	$	20,767.4		16,257.0		11,909.7		–		48,934.1
	Future development costs		-3,151.40		-1,810.50		-1,920.80		–		-6,882.70
	Future production costs		-6,378.50		-7,770.20		-4,575.60		–		-18,724.30
	Future income taxes		-2,930.10		-1,389.60		-1,249.90		–		-5,569.60
	Future net cash flows		8,307.4		5,286.7		4,163.4		–		17,757.5
	10% annual discount for estimated timing		-3,729.10		-2,595.30		-1,527.90		–		-7,852.30
	of cash flows
	Standardized measure of discounted	$	4,578.3		2,691.4		2,635.5		–		9,905.2
	future net cash flows
	31-Dec-13
	Future cash inflows	$	20,638.6		16,112.9		13,399.0		–		50,150.5
	Future development costs		-3,833.90		-1,882.30		-1,445.30		–		-7,161.50
	Future production costs		-5,244.70		-7,073.00		-4,490.40		–		-16,808.10
	Future income taxes		-3,368.30		-1,472.80		-1,855.10		–		-6,696.20
	Future net cash flows		8,191.7		5,684.8		5,608.2		–		19,484.7
	10% annual discount for estimated timing		-4,020.20		-2,999.10		-1,620.70		–		-8,640.00
	of cash flows
	Standardized measure of discounted	$	4,171.5		2,685.7		3,987.5		–		10,844.7
	future net cash flows
	31-Dec-12
	Future cash inflows	$	15,547.5		15,511.6		10,354.9		2,395.2		43,809.2
	Future development costs		-3,731.60		-1,815.20		-966.9		-273.2		-6,786.90
	Future production costs		-3,466.60		-7,336.40		-3,143.40		-738.3		-14,684.70
	Future income taxes		-2,527.60		-1,714.90		-1,675.90		-872.7		-6,791.10
	Future net cash flows		5,821.7		4,645.1		4,568.7		511.0		15,546.5
	10% annual discount for estimated timing		-2,862.10		-2,876.50		-1,322.90		-372.2		-7,433.70
	of cash flows
	Standardized measure of discounted	$	2,959.6		1,768.6		3,245.8		138.8		8,112.8
	future net cash flows
Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows
	(Millions of dollars)		2014		2013		2012
	Net changes in prices and production costs	$	-2,697.80		267.8		-2,461.10
	Net changes in development costs		-2,317.30		-3,456.80		-3,860.10
	Sales and transfers of oil and gas produced, net of production costs		-4,076.00		-3,972.40		-3,493.30
	Net change due to extensions and discoveries		3,251.6		4,608.9		4,466.3
	Net change due to purchases and sales of proved reserves		-1,041.00		-135.6		347.4
	Development costs incurred		3,169.3		3,326.8		3,299.0
	Accretion of discount		1,462.5		1,109.3		1,153.5
	Revisions of previous quantity estimates		518.9		1,646.0		728.1
	Net change in income taxes		790.3		-662.1		9.8
	Net increase (decrease)		-939.5		2,731.9		189.6
	Standardized measure at January 1		10,844.7		8,112.8		7,923.2
	Standardized measure at December 31	$	9,905.2		10,844.7		8,112.8
Capitalized Costs Relating to Oil and Gas Producing Activities	(Millions of dollars)	United			Canada		Malaysia		Other*		Subtotal		Synthetic		Total
		States											Oil –
													Canada
	31-Dec-14
	Unproved oil and gas properties	$	634.9		424.1		–		168.1		1,227.1		–		1,227.1
	Proved oil and gas properties		7,810.9		4,515.4		6,917.7		737.8		19,981.8		1,386.9		21,368.7
	Gross capitalized costs		8,445.8		4,939.5		6,917.7		905.9		21,208.9		1,386.9		22,595.8
	Accumulated depreciation,
	depletion and amortization
	Unproved oil and gas properties		-171.6		-245.6		–		-96.6		-513.8		–		-513.8
	Proved oil and gas properties		-2,944.00		-2,082.10		-2,665.30		-737.8		-8,429.20		-433.1		-8,862.30
	Net capitalized costs	$	5,330.2		2,611.8		4,252.4		71.5		12,265.9		953.8		13,219.7
	31-Dec-13
	Unproved oil and gas properties	$	723.6		475.9		233.5		165.0		1,598.0		–		1,598.0
	Proved oil and gas properties		5,816.9		4,529.9		7,636.6		737.8		18,721.2		1,493.5		20,214.7
	Gross capitalized costs		6,540.5		5,005.8		7,870.1		902.8		20,319.2		1,493.5		21,812.7
	Accumulated depreciation,
	depletion and amortization
	Unproved oil and gas properties		-178.1		-248.5		–		-91.7		-518.3		–		-518.3
	Proved oil and gas properties		-2,171.10		-2,006.80		-2,576.40		-737.8		-7,492.10		-417.6		-7,909.70
	Net capitalized costs	$	4,191.3		2,750.5		5,293.7		73.3		12,308.8		1,075.9		13,384.7
	*Due to the shutdown of production operations in Republic of the Congo, the Company now includes the results of these operations in the Other exploration and production segment in the above table.
Oil Reserves [Member]
Reserve Quantities [Line Items]
Summary of Proved Reserves Based on Average Prices
		Crude &		Crude Oil												Synthetic
		Synthetic														Oil
		Oil
	(Millions of barrels)	Total		Total		United		Canada		Malaysia		United		Other		Canada
						States						Kingdom
	Proved developed and
	undeveloped crude oil /
	synthetic oil reserves:
	31-Dec-11	349.7		220.2		55.3		36.6		104.4		21.6		2.3		129.5
	Revisions of previous estimates	2.3		7.6		13.0		-3.4		-0.7		0.3		-1.6		-5.3
	Improved recovery	7.2		7.2		–		–		7.2		–		–		–
	Extensions and discoveries	84.0		84.0		77.3		2.9		3.8		–		–		–
	Purchases of properties	12.5		12.5		6.5		6.0		–		–		–		–
	Production	-40.9		-35.8		-9.5		-5.3		-19		-1.3		-0.7		-5.1
	31-Dec-12	414.8		295.7		142.6		36.8		95.7		20.6		–		119.1
	Revisions of previous estimates	27.4		24.8		13.1		8.4		3.3		–		–		2.6
	Improved recovery	27.4		27.4		–		–		27.4		–		–		–
	Extensions and discoveries	69.6		69.6		52.4		0.2		17.0		–		–		–
	Purchases of properties	-20.4		-20.4		–		–		–		-20.4		–		–
	Production	-47.6		-42.9		-16.6		-6.7		-19.4		-0.2		–		-4.7
	31-Dec-13	471.2		354.2		191.5		38.7		124.0		0.0		–		117.0
	Revisions of previous estimates	-9.3		-2.3		-3.2		2.7		-1.8		–		–		-7
	Improved recovery	7.5		7.5		–		–		7.5		–		–		–
	Extensions and discoveries	42.6		42.6		32.7		2.4		7.5		–		–		–
	Purchases of properties	6.1		6.1		6.1		–		–		–		–		–
	Sales of properties	-24.3		-24.3		-0.3		-0.5		-23.5		–		–		–
	Production	-52		-47.6		-21.9		-5.9		-19.8		–		–		-4.4
	December 31, 2014	441.8		336.2		204.9		37.4		93.9		–		–		105.6
	Proved developed crude oil /
	synthetic oil reserves:
	December 31, 2011	238.5		118.0		20.8		32.6		57.2		5.1		2.3		120.5
	December 31, 2012	267.7		148.6		48.0		29.5		67.0		4.1		–		119.1
	December 31, 2013	289.9		172.9		75.8		31.6		65.5		–		–		117.0
	December 31, 2014	324.1		218.5		106.2		32.4		79.9		–		–		105.6
	Proved undeveloped crude
	oil / synthetic oil reserves:
	December 31, 2011	111.2		102.2		34.5		4.0		47.2		16.5		–		9.0
	December 31, 2012	147.1		147.1		94.6		7.3		28.7		16.5		–		–
	December 31, 2013	181.3		181.3		115.7		7.1		58.5		–		–		–
	December 31, 2014	117.7		117.7		98.7		5.0		14.0		–		–		–
Natural Gas Liquids Reserves [Member]
Reserve Quantities [Line Items]
Summary of Proved Reserves Based on Average Prices
	(Millions of barrels)	Total		United		Canada		Malaysia
				States
	Proved developed and undeveloped NGL reserves:
	31-Dec-11	–		–		–		–
	Revisions of previous estimates	0.3		–		–		0.3
	Improved recovery	–		–		–		–
	Extensions and discoveries	–		–		–		–
	Production	-0.3		–		–		-0.3
	31-Dec-12	–		–		–		–
	Revisions of previous estimates	15.7		15.6		–		0.1
	Improved recovery	–		–		–		–
	Extensions and discoveries	10.0		8.7		0.1		1.2
	Production	-1.3		-1.1		–		-0.2
	31-Dec-13	24.4		23.2		0.1		1.1
	Revisions of previous estimates	5.1		5.0		–		0.1
	Improved recovery	–		–		–		–
	Extensions and discoveries	4.7		4.0		0.6		0.1
	Sales of properties	-0.2		–		–		-0.2
	Production	-3.4		-3.1		–		-0.3
	December 31, 2014	30.6		29.1		0.7		0.8
	Proved developed NGL reserves:
	December 31, 2011	–		–		–		–
	December 31, 2012	–		–		–		–
	December 31, 2013	14.2		13.1		–		1.1
	December 31, 2014	17.5		16.5		0.2		0.8
	Proved undeveloped NGL reserves:
	December 31, 2011	–		–		–		–
	December 31, 2012	–		–		–		–
	December 31, 2013	10.2		10.1		0.1		–
	December 31, 2014	13.1		12.6		0.5		–
Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Summary of Proved Reserves Based on Average Prices
	(Billions of cubic feet)	Total		United		Canada		Malaysia		United
				States						Kingdom
	Proved developed and undeveloped
	natural gas reserves:
	31-Dec-11	1,106.1		98.4		638.9		347.8		21.0
	Revisions of previous estimates	20.2		16.5		-37.2		41.4		-0.5
	Improved recovery	7.2		–		–		7.2		–
	Extensions and discoveries	173.5		107.2		25.8		40.5		–
	Purchases of properties	9.4		7.0		2.4		–		–
	Production	-179.4		-19.4		-79.5		-79.3		-1.2
	31-Dec-12	1,137.0		209.7		550.4		357.6		19.3
	Revisions of previous estimates	33.7		-38.6		34.0		38.3		–
	Improved recovery	3.2		–		–		3.2		–
	Extensions and discoveries	153.4		33.3		42.5		77.6		–
	Sales of properties	-19		–		–		–		-19
	Production	-154.7		-19.4		-64.1		-70.9		-0.3
	31-Dec-13	1,153.6		185.0		562.8		405.8		–
	Revisions of previous estimates	167.2		47.7		105.6		13.9		–
	Improved recovery	7.0		–		–		7.0		–
	Extensions and discoveries	696.8		24.1		231.5		441.2		–
	Purchases of properties	5.5		5.5		–		–		–
	Sales of properties	-162.6		-3.7		–		-158.9		–
	Production	-162.8		-32.3		-57.1		-73.4		–
	December 31, 2014	1,704.7		226.3		842.8		635.6		–
	Proved developed natural gas reserves:
	December 31, 2011	711.6		58.2		427.1		210.5		15.8
	December 31, 2012	706.0		78.8		415.8		197.3		14.1
	December 31, 2013	786.2		112.6		384.0		289.6		–
	December 31, 2014	812.1		145.6		467.4		199.1		–
	Proved undeveloped natural gas reserves:
	December 31, 2011	394.5		40.2		211.8		137.3		5.2
	December 31, 2012	431.0		130.9		134.6		160.3		5.2
	December 31, 2013	367.4		72.4		178.8		116.2		–
	December 31, 2014	892.6		80.7		375.4		436.5		–

Supplemental_Quarterly_Informa

Supplemental Quarterly Information (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Quarterly Information [Abstract]
Schedule of Supplemental Quarterly Information	(Millions of dollars except per share amounts)	First		Second	Third	Fourth	Year
		Quarter		Quarter	Quarter	Quarter
	Year Ended December 31, 2014
	Sales and other operating revenues	$	1,281.2	1,357.9	1,431.0	1,218.8	5,288.9
	Income from continuing operations before		334.2	304.6	396.5	217.0	1,252.3
	income taxes
	Income from continuing operations		169.3	142.7	271.0	442.0	1,025.0
	Net income		155.3	129.4	245.7	375.2	905.6
	Income from continuing operations per
	Common share
	Basic		0.94	0.80	1.52	2.49	5.73
	Diluted		0.93	0.79	1.51	2.48	5.69
	Net income per Common share
	Basic		0.86	0.72	1.38	2.11	5.06
	Diluted		0.85	0.72	1.37	2.10	5.03
	Cash dividend per Common share		0.3125	0.3125	0.35	0.35	1.325
	Market price of Common Stock*
	High		63.70	66.82	67.75	56.13	67.75
	Low		55.68	59.61	56.18	44.39	44.39
	Year Ended December 31, 2013
	Sales and other operating revenues	$	1,298.9	1,315.6	1,366.5	1,331.7	5,312.7
	Income from continuing operations before		360.0	454.2	463.7	194.8	1,472.7
	income taxes
	Income from continuing operations		182.7	259.9	265.0	180.5	888.1
	Net income		360.6	402.7	284.8	75.4	1,123.5
	Income from continuing operations per
	Common share
	Basic		0.96	1.38	1.42	0.98	4.73
	Diluted		0.95	1.37	1.41	0.96	4.69
	Net income per Common share
	Basic		1.89	2.13	1.52	0.41	5.98
	Diluted		1.88	2.12	1.51	0.40	5.94
	Cash dividend per Common share		0.3125	0.3125	0.3125	0.3125	1.25
	Market price of Common Stock*
	High		63.81	66.09	71.84	65.55	71.84
	Low		59.33	59.98	59.80	59.93	59.33
	*Prices are as quoted on the New York Stock Exchange.

Significant_Accounting_Policie2

Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended				3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2014
Significant Accounting Policies [Line Items]
Canadian government securities with maturities greater than 90 days at the date of acquisition	$461,313,000	$374,842,000			$461,313,000
Maturity of Canadian government securities	90 days
Impairment of assets	51,314,000	21,587,000	200,000,000	[1]
Goodwill	0	40,259,000			0
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%				20.00%
Maturity of Canadian government securities		90 days
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%				50.00%
Maximum [Member] | Stock Options [Member]
Significant Accounting Policies [Line Items]
Stock-based compensation, vesting period	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
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
Canada [Member]
Significant Accounting Policies [Line Items]
Impairment of assets					$37,047,000
[1]	Results exclude corporate overhead, interest and discontinued operations.

Discontinued_Operations_Narrat

Discontinued Operations (Narrative) (Details) (USD $)	0 Months Ended	1 Months Ended	12 Months Ended			0 Months Ended
	Aug. 30, 2013	Jul. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014	Jan. 29, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stock conversion ratio	0.25
Cash Dividends Paid to Parent Company				$650,000,000
Borrowed funds under credit facility			3,001,626,000	2,962,812,000
Provision Of Specified Service Periods			The agreement provides for the provision of specified services, generally for a period of up to 18 months, with a possible extension of six months (an aggregate of 24 months), on a full cost basis.
Asset Retirement Obligation			875,728,000	880,003,000	751,583,000
United Kingdom, corporation tax rate, tax relief on oil and gas decommissioning costs		62.00%			50.00%
United Kingdom, increase in tax expense of discontinued operations					5,523,000
Proceeds From Sale Of Productive Assets			1,467,046,000	1,650,000	99,000
Inventories accounted for under the LIFO method			10,954,000	318,628,000
Decrease amount of inventory that would have been valued using the FIFO method			44,881,000	268,608,000
U.K. refining and marketing assets [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset Retirement Obligation			21,000,000
Asset Impairment Charges			269,200,000	73,000,000
Effect of LIFO Inventory Liquidation on Income			209,600,000
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax			101,700,000
Ethanol Plant in Hereford, Texas [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset Impairment Charges					60,988,000
U.K. Oil and Gas Production [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
After tax gain on sale of oil and natural gas production				216,147,000
U.K. Retail Marketing Operation [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds From Sale Of Productive Assets						211,965,000
Subsequent Event [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds From Sale Of Productive Assets							417,200,000
Murphy USA Inc [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Common stock outstanding	100.00%
Percentage Of Ownership In Murphy USA Inc.	100.00%
Cash Dividends Paid to Parent Company	650,000,000

Discontinued_Operations_Major_

Discontinued Operations (Major Categories of Assets and Liabilities Reflected as Held for Sale) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable	$873,277	$999,872
Inventory	242,733	294,195
Total current assets held for sale	376,130	943,732
Property, plant and equipment, net	13,331,047	13,481,055
Other	81,151	98,123
Total non-current assets held for sale	50,960	381,404
Other accrued taxes payable	52,457	33,969
Total current liabilities associated with assets held for sale	151,548	639,140
Deferred income taxes payable	1,193,864	1,466,100
Deferred credits and other liabilities	441,048	339,028
Total non-current liabilities associated with assets held for sale	8,310	95,544
UK Refining And Marketing Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash	200,512	301,302
Accounts receivable	97,568	302,059
Inventory	42,161	254,240
Other	35,889	86,131
Total current assets held for sale	376,130	943,732
Property, plant and equipment, net	50,947	360,347
Other	13	21,057
Total non-current assets held for sale	50,960	381,404
Accounts payable	59,023	484,082
Other accrued taxes payable	40,653	130,028
Accrued compensation and severance	30,872	17,020
Refinery decommissioning cost	21,000
Other		8,010
Total current liabilities associated with assets held for sale	151,548	639,140
Deferred income taxes payable	3,873	68,096
Deferred credits and other liabilities	4,437	27,448
Total non-current liabilities associated with assets held for sale	$8,310	$95,544

Discontinued_Operations_Result

Discontinued Operations (Results of Operations Associated with Discontinued Operations) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discontinued Operations [Abstract]
Revenues	$2,786,394	$17,586,236	$24,156,748
Income (loss) from operations before income taxes	-261,873	119,984	330,048
Gain on sale before income taxes	101,684	130,991
Total income (loss) from discontinued operations before taxes	-160,189	250,975	330,048
Income tax expense (benefit)	-40,827	15,639	165,666
Income (loss) from discontinued operations	($119,362)	$235,336	$164,382

Inventories_Schedule_of_Crude_

Inventories (Schedule of Crude Oil and Blend Stocks Inventories) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Inventories [Abstract]
Unsold crude oil	$51,810	$40,077
Materials and supplies	190,923	254,118
Inventory, Net, Total	$242,733	$294,195

Property_Plant_and_Equipment_N

Property, Plant and Equipment (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Proceeds from sales of property, plant and equipment	$1,467,046,000	$1,650,000	$99,000
Gain (loss) on sale of assets	138,903,000	-87,000	66,000
Total capitalized exploratory well costs	120,455,000	393,030,000	445,697,000		556,412,000
Impairment of assets	51,314,000	21,587,000	200,000,000	[1]
Malaysia [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Percentage of interest in oil and gas property sold during period	20.00%
Proceeds from sales of property, plant and equipment	1,460,425,000
Gain (loss) on sale of assets	321,454,000
United States [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized more than one year	54,519,000
Brunei
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Exploratory well costs capitalized more than one year	65,936,000
Gulf of Mexico [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Impairment of assets	$14,267,000
[1]	Results exclude corporate overhead, interest and discontinued operations.

Property_Plant_and_Equipment_S

Property, Plant and Equipment (Schedule Cost and Net of Property, Plant and Equipment) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified
Property Plant And Equipment [Line Items]
Property, Plant and Equipment, Gross	$22,834,571		$22,021,294
Property, plant and equipment, net	13,331,047		13,481,055
Exploration and Production Equipment [Member]
Property Plant And Equipment [Line Items]
Property, Plant and Equipment, Gross	22,731,220	[1]	21,932,119	[1]
Property, plant and equipment, net	13,277,985	[1],[2]	13,433,468	[1],[2]
Corporate and Other [Member]
Property Plant And Equipment [Line Items]
Property, Plant and Equipment, Gross	103,351		89,175
Property, plant and equipment, net	53,062		47,587
Mineral Rights [Member]
Property Plant And Equipment [Line Items]
Property, Plant and Equipment, Gross	924,253		1,007,920
Property, plant and equipment, net	410,482		489,578
Administrative Assets And Support Equipment [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, net	$58,334		$48,691
[1]	Includes mineral rights as follows:$924,253410,4821,007,920489,578
[2]	Includes $58,334 in 2014 and $48,691 in 2013 related to administrative assets and support equipment.

Recovered_Sheet1

Property, Plant And Equipment (Net Changes in Capitalized Exploratory Well Costs) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant And Equipment [Abstract]
Beginning balance at January 1	$393,030,000	$445,697,000	$556,412,000
Additions pending the determination of proved reserves	2,874,000	57,716,000	135,849,000
Reclassifications to proved properties based on the determination of proved reserves	-91,236,000	-93,936,000	-165,377,000
Reduction of capitalized exploratory well costs due to partial asset sale	-122,175,000
Capitalized exploratory well costs charged to expense	-62,038,000	-16,447,000	-81,187,000
Ending balance at December 31	$120,455,000	$393,030,000	$445,697,000

Property_Plant_And_Equipment_A

Property, Plant And Equipment (Aging of Capitalized Exploratory Well Costs) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	item	item	item
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount	$120,455,000	$393,030,000	$445,697,000	$556,412,000
No. of Wells	8	32	44
No. of Projects	3	9	15
Zero to one year [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount		56,499,000	59,833,000
No. of Wells		3	7
No. of Projects		1	2
One to two years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount	59,330,000	60,787,000	18,335,000
No. of Wells	3	7	2
No. of Projects	1	1	3
Two to three years [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount	6,606,000		83,314,000
No. of Wells	3		9
No. of Projects			4
Three years or more [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amount	$54,519,000	$275,744,000	$284,215,000
No. of Wells	2	22	26
No. of Projects	2	7	6

Financing_Arrangements_and_Deb

Financing Arrangements and Debt (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	31-May-13
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity	$2,000,000,000	$1,500,000,000
Credit facility, maturity date	1-Jun-17
Credit facility interest rate above LIBOR	1.25%
Line of credit facility fee	0.25%
Committed Credit Facility [Member]
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity	2,000,000,000
Line of Credit Facility, Current Borrowing Capacity	450,000,000
Uncommitted Credit Facilities [Member]
Line of Credit Facility [Line Items]
Credit facility maximum borrowing capacity	435,000,000
Line of Credit Facility, Current Borrowing Capacity	$0

Long_term_Debt_Narrative_Detai

Long term Debt (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
Long-term Debt [Abstract]
Future maturities of long term debt in 2015	$465,388,000
Future maturities of long term debt in 2016	16,071,000
Future maturities of long term debt in 2017	566,336,000
Future maturities of long term debt in 2018	17,675,000
Future maturities of long term debt in 2019	18,561,000
Thereafter	$1,917,595,000
Term of capital lease	25 years
Lease expiration year	2038
Lease payment owed through year	2028

Long_term_Debt_Schedule_of_Lon

Long term Debt (Schedule of Long Term Debt) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Notes payable	$2,700,000	$2,600,000
Unamortized discount on notes payable	-4,953	-5,439
Total notes payable, net of unamortized discount	2,695,047	2,594,561
Capitalized lease obligation, due through June 2028	306,579	368,251
Total debt including current maturities	3,001,626	2,962,812
Current maturities	-465,388	-26,249
Total long-term debt	2,536,238	2,936,563
2.50% notes, due 2017 [Member]
Debt Instrument [Line Items]
Notes payable	550,000	550,000
Notes payable, stated interest rate	2.50%	2.50%
Notes payable, due date	2017	2017
3.70% notes, due 2022 [Member]
Debt Instrument [Line Items]
Notes payable	600,000	600,000
Notes payable, stated interest rate	3.70%	3.70%
Notes payable, due date	2022	2022
4.00% notes, due 2022 [Member]
Debt Instrument [Line Items]
Notes payable	500,000	500,000
Notes payable, stated interest rate	4.00%	4.00%
Notes payable, due date	2022	2022
7.05% notes, due 2029 [Member]
Debt Instrument [Line Items]
Notes payable	250,000	250,000
Notes payable, stated interest rate	7.05%	7.05%
Notes payable, due date	2029	2029
5.125% notes, due 2042 [Member]
Debt Instrument [Line Items]
Notes payable	350,000	350,000
Notes payable, stated interest rate	5.13%	5.13%
Notes payable, due date	2042	2042
Notes payable to banks, 1.4375% [Member]
Debt Instrument [Line Items]
Notes payable	$450,000	$350,000
Notes payable, stated interest rate	1.44%

Asset_Retirement_Obligations_S

Asset Retirement Obligations (Schedule of Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligation) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligations [Abstract]
Balance at beginning of year	$880,003	$751,583
Accretion of asset retirement obligations	50,778	48,996	38,361
Liabilities incurred	70,568	172,048
Revision of previous estimates	8,278	-4,856
Liabilities settled	-36,818	-51,647
Liabilities assumed by purchases of oil and gas assets	-69,416
Liabilities assumed by Murphy USA Inc. upon separation		-15,401
Changes due to translation of foreign currencies	-27,665	-20,720
Balance at end of year	$875,728	$880,003	$751,583

Asset_Retirement_Obligations_S1

Asset Retirement Obligations (Schedule of Reconciliation of Beginning and Ending Aggregate Carrying Amount of Asset Retirement Obligation Current and Noncurrent) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Asset Retirement Obligation [Abstract]
Balance at end of year	$875,728		$880,003		$751,583
Current portion of liability at end of year	-34,202	[1]	-27,515	[1]
Noncurrent portion of liability at end of year	$841,526		$852,488
[1]	Included in Other Accrued Liabilities on the Consolidated Balance Sheet.

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Examination [Line Items]
Income tax benefits attributable to employee stock option transactions	$5,364,000	$7,435,000	$5,920,000
Decrease in deferred tax asset valuation allowance	327,272,000
Undistributed earnings of subsidiaries considered indefinitely invested	6,045,000,000
Unrecognized deferred tax liability	684,000,000
Withholding tax on any monies repatriated from Canada to the U.S.	5.00%
Other recorded liabilities for interest and penalties	142,000	146,000
Income tax expense, (charges) net benefits for interest and penalties	4,000	829,000	1,000
Expected liability to be added for uncertain taxes during next twelve months	1,000,000
Expected liability to be added for uncertain taxes during next twelve months	2,000,000
United States [Member]
Income Tax Examination [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	2011
Canada [Member]
Income Tax Examination [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	2008
United Kingdom [Member]
Income Tax Examination [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	2012
Repatriated cash	250,000,000
Malaysia [Member]
Income Tax Examination [Line Items]
Earliest year remaining open for audit and/or settlement in major taxing jurisdictions	2007
Repatriated cash	1,700,000,000
Percentage of interest in oil and gas property sold during period	20.00%
Block H Development Plan [Member]
Income Tax Examination [Line Items]
Decrease in deferred tax asset valuation allowance	$65,384,000
Foreign Country [Member] | Minimum [Member]
Income Tax Examination [Line Items]
Foreign tax credit carryforwards expiration year	2015
Foreign Country [Member] | Maximum [Member]
Income Tax Examination [Line Items]
Foreign tax credit carryforwards expiration year	2024

Income_Taxes_Components_of_Inc

Income Taxes (Components of Income from Continuing Operations Before Income Taxes and Income Tax Expense) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income (loss) from continuing operations before income taxes
United States									$179,484	($5,810)	$54,275
Foreign									1,072,786	1,478,497	1,313,735
Income from continuing operations before income taxes	217,000	396,500	304,600	334,200	194,800	463,700	454,200	360,000	1,252,270	1,472,687	1,368,010
Income tax expense (benefit)
Federal - Current									25,151	-56,790	-256,931
Deferred									25,444	65,883	177,325
Total Federal Income Tax (benefit)									50,595	9,093	-79,606
State									8,840	7,141	8,104
Foreign - Current									359,502	477,715	472,701
- Deferred									-191,640	90,601	160,317
Total Foreign Income Tax									167,862	568,316	633,018
Income Tax Expense (Benefit), Total									$227,297	$584,550	$561,516

Income_Taxes_Reconciliation_of

Income Taxes (Reconciliation of Income Taxes Based on U.S. Statutory Tax Rate to Income Tax Expense) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Abstract]
Income tax expense based on the U.S. statutory tax rate	$438,295	$515,440	$478,804
Foreign income subject to foreign taxes at a rate different than the U.S. statutory rate	20,562	31,752	7,710
State income taxes, net of federal benefit	5,746	4,642	5,268
U.S. tax benefit on certain foreign upstream investments	-95,838	-133,526	-108,077
Deferred tax benefit on sale Malaysian assets	-176,661
Increase in deferred tax asset valuation allowance related to other foreign exploration expenditures	37,712	129,588	87,558
Impairment or abandonment of Azurite field with no tax benefit		35,475	70,000
Other, net	-2,519	1,179	20,253
Total	$227,297	$584,550	$561,516

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 $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Deferred tax assets
Property and leasehold costs	$379,577	$708,947
Liabilities for dismantlements	85,544	79,111
Postretirement and other employee benefits	208,600	175,446
Alternative minimum tax	46,792	49,536
Foreign tax credit carryforwards	44,061	19,896
Other deferred tax assets	22,426	23,352
Total gross deferred tax assets	787,000	1,056,288
Less valuation allowance	-306,463	-633,735
Net deferred tax assets	480,537	422,553
Deferred tax liabilities
Property, plant and equipment	-479,677	-747,561
Accumulated depreciation, depletion and amortization	-1,123,864	-1,040,251
Other deferred tax liabilities	-15,753	-38,849
Total gross deferred tax liabilities	-1,619,294	-1,826,661
Net deferred tax liabilities	($1,138,757)	($1,404,108)

Income_Taxes_Reconciliation_of1

Income Taxes (Reconciliation of Beginning and Ending Amount of Consolidated Liability for Unrecognized Income Tax Benefits) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Abstract]
Balance at January 1	$6,366	$16,611	$18,857
Additions for tax positions related to current year	988	2,486	1,258
Settlements due to lapse of time	-1,225	-12,731	-3,504
Foreign currency translation effect	-118
Balance at December 31	$6,011	$6,366	$16,611

Incentive_Plans_Narrative_Deta

Incentive Plans (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Aug. 30, 2013	Feb. 28, 2013	Dec. 31, 2011
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Unvested share-based compensation arrangements, compensation costs to be expensed	$46,024,000
Unvested share-based compensation arrangements, number of years compensation costs to be expensed	2 years
Proceeds from exercise of stock options and employee stock purchase plans	210,000	3,409,000	12,324,000
Income tax benefits realized for the tax deductions from option exercises	5,364,000	7,435,000	5,920,000
Granted restricted stock, vesting scheme	Under the 2012 Long-Term Plan and the 2007 Long-Term Plan, one-half of each grant is generally exercisable after two years and the remainder after threeB years.
Total intrinsic value of options exercised	12,003,000	25,284,000	17,197,000
Reduction in stock option exercise price					$2.50
Income statement effect of reduced exercise price		6,454,000
Percentage increase in number of outstanding stock options				10.70%
Percentage decrease in exercise price of stock options				10.70%
Percentage increase in number of outstanding stock units				10.70%
Performance units outstanding	5,602,250
Incentive compensation plan expense	38,000,000	53,250,000	32,417,000
Maximum [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Option granted to date, term of years	7 years
2012 Long-Term Plan [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Long term plan expiration year	2022
Maximum number of shares available for issuance	8,700,000
Maximum number of shares available for issuance, annual rate	1.00%
Number of shares remained available		5,481,000
2012 Long-Term Plan and the 2007 Long-Term Plan [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Option granted to date, term of years	7 years
Stock Options [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Proceeds from exercise of stock options and employee stock purchase plans		2,395,000	10,375,000
Stock-based compensation, fair value assumption model	Black-Scholes option pricing model
Performance units outstanding	5,602,250	6,006,585	5,907,359			5,434,228
Stock Options [Member] | Maximum [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Stock-based compensation, vesting period	3 years
Stock Options [Member] | Minimum [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Stock-based compensation, vesting period	2 years
Time-Lapse Restricted Stock and Restricted Stock Units [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Granted restricted stock, valuation			$59.33
Time-Lapse Restricted Stock and Restricted Stock Units [Member] | Maximum [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Granted restricted stock, valuation	$60.85	$69.67
Time-Lapse Restricted Stock and Restricted Stock Units [Member] | Minimum [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Granted restricted stock, valuation	$55.20	$60.30
Performance Based Restricted Stock [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Stock-based compensation, vesting period	3 years
Stock-based compensation, fair value assumption model	Monte Carlo valuation model
Performance Based Restricted Stock [Member] | Maximum [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Granted restricted stock, valuation	$51.30	$68.01	$63.64
Performance Based Restricted Stock [Member] | Minimum [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Granted restricted stock, valuation	$33.90	$39.50	$54.90
Employee Stock Purchase Plan [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Number of shares remained available		280,202
Compensation expenses	55,000	143,000	272,000
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 will terminate on the earlier of the date that employees have purchased all 980,000 authorized shares or JuneB 30, 2017.
Employee stock purchases, shares	6,739	16,020	24,418
Employee stock purchases, per share	$56.22	$54.14	$48.54
Compensation costs estimation	Compensation costs related to the ESPP are estimated based on the value of the 10% discount and the fair value of the option that provides for the refund of participant withholdings
Fair value per share issued under ESPP	$6.49	$6.72	$7.30
Employee Stock Purchase Plan [Member] | Maximum [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Maximum number of shares available for issuance	980,000
Performance Units [Member]
Compensation Related Costs Share Based Payments Disclosure [Line Items]
Share based compensation settled in cash	$9,667,000	$9,436,000	$552,000

Incentive_Plans_ShareBased_Pla

Incentive Plans (Share-Based Plans, Amounts Recognized) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Incentive Plans [Abstract]
Compensation charged against income before tax benefit	$53,157	$66,976	$46,694
Related income tax benefit recognized in income	$15,604	$19,321	$14,443

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], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items]
Fair value per option grant	$12.84
Assumptions
Dividend yield	2.00%
Expected volatility	29.00%
Risk-free interest rate	1.62%
Expected life	5 years 4 months 6 days
Minimum [Member]
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items]
Fair value per option grant		$15.81	$12.37
Assumptions
Dividend yield		2.10%	1.80%
Expected volatility		34.00%	39.00%
Risk-free interest rate		0.96%	0.55%
Expected life		5 years 3 months	4 years
Maximum [Member]
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items]
Fair value per option grant		$20.62	$17.74
Assumptions
Dividend yield		2.30%	2.27%
Expected volatility		36.00%	39.62%
Risk-free interest rate		2.00%	0.77%
Expected life		6 years 6 months	5 years 2 months 12 days

Incentive_Plans_Changes_in_Sto

Incentive Plans (Changes in Stock Options Outstanding) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Number of Shares
Exercised	-119,994	[1]	-303,685	[1]	-482,974	[1]
Outstanding at end of year	5,602,250
Exercisable at end of year	3,030,105
Stock Options [Member]
Number of Shares
Outstanding at beginning of year	6,006,585		5,907,359		5,434,228
Granted at FMV	772,900		1,320,176		1,870,500
Exercised	-862,407		-1,335,355		-823,855
Forfeited	-314,828		-228,576		-573,514
Murphy USA Inc. spin-off adjustment			615,917
Outstanding at end of year	5,602,250		6,006,585		5,907,359
Exercisable at end of year	3,030,105		2,435,322		2,474,636		2,319,735
Average Exercise Price
Outstanding at beginning of year	$56.80		$55.17		$55.17
Granted stock options, exercise price	$55.82		$55.26		$57.96
Exercised	$49.27		$45.84		$38.37
Forfeited	$54.53		$58.01		$60.43
Surrendered in connection with separation of Murphy USA Inc.			$55.99
Murphy USA Inc. spin-off adjustment			$52.09
Outstanding at end of year	$57.95		$56.80		$55.17
Exercisable at end of year	$53.10		$51.79		$54.43		$51.14
Stock Options [Member] | Spin [Member]
Number of Shares
Surrendered in connection with separation of Murphy USA Inc.			-272,936
[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) (USD $)	12 Months Ended
	Dec. 31, 2014
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Options Outstanding	5,602,250
Options Outstanding, Avg. Life in Years	3 years 7 months 6 days
Options Outstanding, Aggregate Intrinsic Value	$8,319,271
Options Exercisable	3,030,105
Options Exercisable, Avg. Life in year	2 years 4 months 24 days
Options Exercisable, Aggregate Intrinsic Value	7,302,819
Range of Exercise Prices per Option $ 37.44 to $ 39.02 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices, lower limit	$37.44
Range of exercise prices, upper limit	$39.02
Options Outstanding	444,524
Options Outstanding, Avg. Life in Years	2 years 4 months 24 days
Options Outstanding, Aggregate Intrinsic Value	5,533,247
Options Exercisable	356,103
Options Exercisable, Avg. Life in year	1 year 10 months 24 days
Options Exercisable, Aggregate Intrinsic Value	4,516,795
Range of Exercise Prices per Option $ 43.88 to $ 51.63 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices, lower limit	$43.88
Range of exercise prices, upper limit	$51.63
Options Outstanding	1,772,764
Options Outstanding, Avg. Life in Years	1 year 9 months 18 days
Options Outstanding, Aggregate Intrinsic Value	2,786,024
Options Exercisable	1,162,708
Options Exercisable, Avg. Life in year	2 years 4 months 24 days
Options Exercisable, Aggregate Intrinsic Value	$2,786,024
Range of Exercise Prices per Option $ 54.21 to $ 63.46 [Member]
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Range of exercise prices, lower limit	$54.21
Range of exercise prices, upper limit	$63.46
Options Outstanding	3,384,962
Options Outstanding, Avg. Life in Years	4 years
Options Exercisable	1,511,294
Options Exercisable, Avg. Life in year	2 years 1 month 6 days

Incentive_Plans_Changes_in_Per

Incentive Plans (Changes in Performance-Based RSU Outstanding) (Details) (Equity-Settled Restricted Stock Units [Member])	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Equity-Settled Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Balance at beginning of year	1,560,292	1,426,238	1,174,492
Granted restricted stock	464,300	521,776	653,355
Awarded	-473,186	-380,150	-260,175
Forfeited	-154,366	-39,573	-141,434
Surrendered in connection with separation of Murphy USA Inc.		-116,568
Murphy USA Inc. spin-off adjustment		148,569
Balance at end of year	1,397,040	1,560,292	1,426,238

Incentive_Plans_Assumptions_us

Incentive Plans (Assumptions used in Valuation Performance Awards Granted) (Details) (Performance Based Restricted Stock [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	item		item
Assumptions
Expected volatility	29.00%		37.00%
Risk-free interest rate	0.65%		0.30%
Stock beta	0.843		0.913
Expected life	3 years	3 years	3 years
Minimum [Member]
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items]
Granted restricted stock, fair value	33.9	39.5	54.9
Assumptions
Expected volatility		31.00%
Risk-free interest rate		0.41%
Stock beta		0.907
Maximum [Member]
Share based Compensation Arrangement by Share based Payment Award, Fair Value Assumptions, Method Used [Line Items]
Granted restricted stock, fair value	51.3	68.01	63.64
Assumptions
Expected volatility		32.00%
Risk-free interest rate		0.62%
Stock beta		0.908

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])	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock and Restricted Stock Units [Member]
Schedule of Share based Compensation Arrangements by Share based Payment Award, Equity Instruments, Other Than Options, Restricted Stock Units [Line Items]
Balance at beginning of year	112,881	98,477	116,724
Granted restricted stock	278,892	38,184	42,256
Vested and issued	-54,884	-34,696	-44,980
Forfeited	-15,100		-15,523
Murphy USA Inc. spin-off adjustment		10,916
Balance at end of year	321,789	112,881	98,477

Employee_and_Retiree_Benefit_P2

Employee and Retiree Benefit Plans (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension and Other Postretirement Benefits Disclosure [Line Items]
Future annual rate of increase in cost of health care for 2014 to measure postretirement benefit obligations	7.20%
Ultimate rate of health care cost in 2020 and thereafter	4.50%
Provisions of the March 2010 Health Care Reform	In March 2010, the United States Congress enacted a health care reform law. Along with other provisions, the law (a)B eliminated the tax free status of federal subsidies to companies with qualified retiree prescription drug plans that are actuarially equivalent to Medicare Part D plans beginning in 2013; (b)B imposes a 40% excise tax on high-cost health plans as defined in the law beginning in 2018; (c)B eliminated lifetime or annual coverage limits and required coverage for preventative health services beginning in September 2010; and (d)B imposed a fee of $2 (subsequently adjusted for inflation) for each person covered by a health insurance policy beginning in September 2010.
Excise tax rate imposed on high-cost health plans beginning 2018	40.00%
Government imposed fee for each person covered by health insurance policy	$2
Equity securities minimum market capitalization	100,000,000
Weighted average expected return on plan asset	6.11%
Defined benefit plan, percentage of employer's matching contribution	6.00%	6.00%	6.00%
Thrift plan expense	10,229,000	13,839,000	12,594,000
Investment 2 [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Domestic plan, investment notice period	90 days
Investment 3 [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Domestic plan, investment lock up period	3 years
Domestic plan, investment notice period	95 days
Foreign Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Contributions to benefit plans	35,000
Expected benefit plan contributions to be made during next year	36,000
Domestic postretirement benefits plan [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Contributions to benefit plans	3,641,000
Expected benefit plan contributions to be made during next year	5,481,000
Domestic defined benefit pension plans [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Contributions to benefit plans	27,948,000
Expected benefit plan contributions to be made during next year	40,045,000
Foreign Defined Benefit Pension Plans [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Contributions to benefit plans	19,331,000
Expected benefit plan contributions to be made during next year	$18,739,000
United Kingdom [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Asset performance compared to a benchmark return, percent targeted to outperform the benchmark over three years	0.75%
Percentage fixed income allocation	95.00%
Maximum percentage of income investment in securities	5.00%
United Kingdom [Member] | Foreign Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Description of equity and fixed income securities allocation	Approximately one-half of the equity allocation is to be invested in U.K. securities and the remainder split between North American, European, Japanese and other Pacific Basin securities. A minimum of 95% of the fixed income allocation is to be invested in U.K. securities with up to 5% in international or high yield bonds.
Maximum [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Investment Manager's portfolio to be held in equity securities of any one issuer	10.00%
Equity securities [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Target allocations of plan assets, minimum	40.00%
Target allocations of plan assets, maximum	70.00%
Weighted average expected return on plan asset	7.72%
Equity securities [Member] | United Kingdom [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Target allocations of plan assets, minimum	27.00%
Target allocations of plan assets, maximum	98.00%
Target allocations of plan assets	60.00%
Equity securities [Member] | Canada [Member] | Foreign Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Target allocations of plan assets, minimum	40.00%
Target allocations of plan assets, maximum	75.00%
Target allocations of plan assets	60.00%
Fixed Income Securities [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Target allocations of plan assets, minimum	30.00%
Target allocations of plan assets, maximum	60.00%
Fixed income portfolio, maximum average maturity years	11 years
Weighted average expected return on plan asset	4.04%
Basis used to determine expected return on plan asset, percentage of expected return (expense)	0.53%
Fixed Income Securities [Member] | United Kingdom [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Target allocations of plan assets, minimum	25.00%
Target allocations of plan assets, maximum	60.00%
Target allocations of plan assets	40.00%
Fixed Income Securities [Member] | Canada [Member] | Foreign Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Target allocations of plan assets, minimum	25.00%
Target allocations of plan assets, maximum	45.00%
Target allocations of plan assets	35.00%
US long/short equity fund [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Target allocations of plan assets, minimum	0.00%
Target allocations of plan assets, maximum	15.00%
Cash equivalents [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Target allocations of plan assets, minimum	0.00%
Target allocations of plan assets, maximum	15.00%
Cash equivalents [Member] | United Kingdom [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Target allocations of plan assets, maximum	5.00%
Cash equivalents [Member] | Canada [Member] | Foreign Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Target allocations of plan assets, minimum	0.00%
Target allocations of plan assets, maximum	15.00%
Target allocations of plan assets	5.00%
Commingled equity fund [Member]
Pension and Other Postretirement Benefits Disclosure [Line Items]
Domestic plan, investment notice period	10 days

Employee_and_Retiree_Benefit_P3

Employee and Retiree Benefit Plans (Plans' Benefit Obligations and Fair Value of Assets and Statement of Funded Status) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Change in plan assets
Fair value of plan assets, Ending Balance	$560,978,000	$533,108,000
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Liabilities associated with assets held for sale	-151,548,000	-639,140,000
Pension Benefits [Member]
Change in benefit obligation
Obligation at January 1	825,552,000	707,254,000	721,531,000
Service cost	22,470,000	26,346,000	23,500,000
Interest cost	33,680,000	30,903,000	29,869,000
Plan amendments		1,989,000
Participant contributions	5,000	21,000
Actuarial loss (gain)	122,824,000	-9,876,000
Exchange rate changes	-14,614,000	1,852,000
Benefits paid	-35,044,000	-38,745,000
Special termination benefits		849,000
Curtailments	-11,023,000	-26,463,000
Obligation assumed by MUSA at separation		-1,153,000
Defined Benefit Plan, Benefit Obligation, Ending Balance	825,552,000	707,254,000	721,531,000
Change in plan assets
Fair value of plan assets, Beginning Balance	533,108,000	463,546,000
Actual return on plan assets	31,340,000	61,932,000
Employer contributions	47,279,000	46,726,000
Participant contributions	5,000	21,000
Exchange rate changes	-13,284,000	1,594,000
Benefits paid	-35,044,000	-38,745,000
Other	-2,426,000	-1,966,000
Fair value of plan assets, Ending Balance	560,978,000	533,108,000	463,546,000
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Deferred charges and other assets	7,899,000	10,254,000
Other accrued liabilities	-5,996,000	-5,565,000
Deferred credits and other liabilities	-252,237,000	-158,589,000
Liabilities associated with assets held for sale	-14,240,000	-20,246,000
Funded status and net plan liability recognized at the end of the period	-264,574,000	-174,146,000
Other Postretirement Benefits [Member]
Change in benefit obligation
Obligation at January 1	118,496,000	107,001,000	124,134,000
Service cost	2,459,000	4,566,000	3,958,000
Interest cost	4,617,000	5,189,000	5,174,000
Participant contributions	1,406,000	1,376,000
Actuarial loss (gain)	8,150,000	-8,324,000
Medicare Part D subsidy, Change in benefit obligation	404,000	384,000
Exchange rate changes	-55,000	-36,000
Benefits paid	-5,486,000	-5,211,000
Curtailments		-15,077,000
Defined Benefit Plan, Benefit Obligation, Ending Balance	118,496,000	107,001,000	124,134,000
Change in plan assets
Employer contributions	3,676,000	3,451,000
Participant contributions	1,406,000	1,376,000
Medicare Part D subsidy, Fair value of plan assets	404,000	384,000
Benefits paid	-5,486,000	-5,211,000
Funded status and amounts recognized in the Consolidated Balance Sheets at December 31
Other accrued liabilities	-5,515,000	-5,920,000
Deferred credits and other liabilities	-112,981,000	-101,081,000
Funded status and net plan liability recognized at the end of the period	($118,496,000)	($107,001,000)

Employee_and_Retiree_Benefit_P4

Employee and Retiree Benefit Plans (Amounts Included in Accumulated Other Comprehensive Income Not Recognized in Net Periodic Benefit Expense) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	($256,821)
Prior service (cost) credit	-2,456
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax, Total	-259,277
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	-21,948
Prior service (cost) credit	289
Pension and Other Postretirement Benefit Plans, Accumulated Other Comprehensive Income (Loss), before Tax, Total	($21,659)

Employee_and_Retiree_Benefit_P5

Employee and Retiree Benefit Plans (Amounts Included in Accumulated Other Comprehensive Income Expected to be Amortization into Net Periodic Benefit Expense) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	($16,706)
Prior service (cost) credit	-854
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year, Total	-17,560
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Net actuarial loss	-778
Prior service (cost) credit	82
Defined Benefit Plan, Amount to be Amortized from Accumulated Other Comprehensive Income (Loss) Next Fiscal Year, Total	($696)

Employee_and_Retiree_Benefit_P6

Employee and Retiree Benefit Plans (Projected Benefit Obligations, Accumulated Benefit Obligations and Fair Value of Plan Assets for Plans where Accumulated Benefit Obligation Exceeded Fair Value of Plan Assets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Funded Defined Benefit Pension Plans [Member] | Qualified Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Plans where accumulated benefit obligation exceeds fair value of plan assets, Projected benefit obligation	$658,618	$571,217
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate accumulated benefit Obligation	597,918	520,610
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate fair value of plan assets	533,165	502,308
Unfunded Defined Benefit Pension Plans [Member] | Non-Qualified Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Plans where accumulated benefit obligation exceeds fair value of plan assets, Projected benefit obligation	147,018	115,492
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate accumulated benefit Obligation	127,200	102,198
Unfunded Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Plans where accumulated benefit obligation exceeds fair value of plan assets, Projected benefit obligation	118,496	107,001
Plans where accumulated benefit obligation exceeds fair value of plan assets, Aggregate accumulated benefit Obligation	$118,496	$107,001

Employee_and_Retiree_Benefit_P7

Employee and Retiree Benefit Plans (Components of Net Periodic Benefit Expense) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$22,470	$26,346	$23,500
Interest cost	33,680	30,903	29,869
Expected return on plan assets	-33,723	-28,974	-25,826
Amortization of prior service cost	899	1,006	1,254
Amortization of transitional liability (asset)	-480	-514	-529
Recognized actuarial loss	9,471	17,338	16,389
Defined Benefit Plan, Gross Periodic Benefit Cost, Total	32,317	46,105	44,657
Termination benefits expense		849	6,177
Curtailment expense (benefit)		1,365
Net periodic benefit expense	32,317	48,319	50,834
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	2,459	4,566	3,958
Interest cost	4,617	5,189	5,174
Amortization of prior service cost	-82	-143	-173
Amortization of transitional liability (asset)		8	8
Recognized actuarial loss	5	1,484	1,317
Defined Benefit Plan, Gross Periodic Benefit Cost, Total	6,999	11,104	10,284
Curtailment expense (benefit)		-442
Net periodic benefit expense	$6,999	$10,662	$10,284

Employee_and_Retiree_Benefit_P8

Employee and Retiree Benefit Plans (Amount Related to Foreign Benefit Plans) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, Ending Balance	$560,978	$533,108
Foreign Defined Benefit Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation, Ending Balance	222,497	211,799
Fair value of plan assets, Ending Balance	202,305	188,575
Net plan liabilities recognized	20,192	23,224
Net periodic benefit expense	12,968	12,622
Foreign Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation, Ending Balance	648	541
Net plan liabilities recognized	648	541
Net periodic benefit expense	$152	$92

Employee_and_Retiree_Benefit_P9

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, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Expected return on plan assets	6.11%
Expected return on plan assets	6.11%
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligation, Discount rate	3.94%	4.78%
Expected return on plan assets	6.11%	6.24%
Benefit Obligation, Rate of compensation increase	3.69%	4.14%
Net periodic benefit expense, Discount rate	4.56%	4.23%
Expected return on plan assets	6.11%	6.24%
Net periodic benefit expense, Rate of compensation increase	3.69%	4.12%
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit Obligation, Discount rate	4.12%	4.91%
Net periodic benefit expense, Discount rate	4.91%	4.18%

Recovered_Sheet2

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) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2015	$33,516
2016	34,212
2017	35,144
2018	36,439
2019	37,671
2020-2024	208,294
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2015	6,349
2016	6,573
2017	6,730
2018	6,943
2019	7,225
2020-2024	$40,535

Recovered_Sheet3

Employee and Retiree Benefit Plans (One Percent Change in Assumed Health Care Cost Trend Rates) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014
Employee and Retiree Benefit Plans [Abstract]
Effect on total service and interest cost components of net periodic postretirement benefit expense for the year ended December 31, 2014	$1,190
Effect on the health care component of the accumulated postretirement benefit obligation at December 31, 2014	17,879
A 1% decrease effect on total service and interest cost components of net periodic postretirement benefit expense	-942
A 1% decrease effect on the health care component of the accumulated postretirement benefit obligation	($14,456)

Recovered_Sheet4

Employee and Retiree Benefit Plans (Weighted Average Asset Allocation for Company's Funded Pension Benefit Plans) (Details)	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	100.00%	100.00%
Equity securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	66.60%	68.40%
Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	32.50%	30.70%
Cash equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Weighted average asset allocation	0.90%	0.90%

Recovered_Sheet5

Employee and Retiree Benefit Plans (Fair Value Measurements of Retirement Plan Assets within Fair Value of Hierarchy) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	$560,978	$533,108
Domestic Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	358,673	344,533
Domestic Plans [Member] | Equity securities [Member] | US core equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	67,863	89,255
Domestic Plans [Member] | Equity securities [Member] | U.S. small/midcap [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	33,709	37,149
Domestic Plans [Member] | Equity securities [Member] | Hedged funds and other alternative strategies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	52,905	32,788
Domestic Plans [Member] | Equity securities [Member] | Commingled equity fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	19,908	9,654
Domestic Plans [Member] | Equity securities [Member] | Commingled trust fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	75,702	77,041
Domestic Plans [Member] | Fixed Income Securities [Member] | Commingled trust fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	17,559	14,865
Domestic Plans [Member] | Fixed Income Securities [Member] | U.S. fixed income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	80,577	72,240
Domestic Plans [Member] | Fixed Income Securities [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	8,069	8,549
Domestic Plans [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	2,381	2,992
Foreign Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	202,305	188,575
Foreign Plans [Member] | Equity securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets		99,085
Foreign Plans [Member] | Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets		57,030
Foreign Plans [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	1,363	1,660
Foreign Plans [Member] | Equity securities funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	106,694
Foreign Plans [Member] | Fixed income securities funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	66,435
Foreign Plans [Member] | Diversified pooled fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	27,813	30,800
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	105,316	131,056
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	103,953	129,396
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Plans [Member] | Equity securities [Member] | US core equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	67,863	89,255
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Plans [Member] | Equity securities [Member] | U.S. small/midcap [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	33,709	37,149
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Domestic Plans [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	2,381	2,992
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	1,363	1,660
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member] | Foreign Plans [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	1,363	1,660
Significant Other Observable Inputs (Level 2) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	421,710	369,264
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	220,768	182,349
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member] | Equity securities [Member] | Hedged funds and other alternative strategies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	18,953
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member] | Equity securities [Member] | Commingled equity fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	19,908	9,654
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member] | Equity securities [Member] | Commingled trust fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	75,702	77,041
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member] | Fixed Income Securities [Member] | Commingled trust fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	17,559	14,865
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member] | Fixed Income Securities [Member] | U.S. fixed income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	80,577	72,240
Significant Other Observable Inputs (Level 2) [Member] | Domestic Plans [Member] | Fixed Income Securities [Member] | Mutual fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	8,069	8,549
Significant Other Observable Inputs (Level 2) [Member] | Foreign Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	200,942	186,915
Significant Other Observable Inputs (Level 2) [Member] | Foreign Plans [Member] | Equity securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets		99,085
Significant Other Observable Inputs (Level 2) [Member] | Foreign Plans [Member] | Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets		57,030
Significant Other Observable Inputs (Level 2) [Member] | Foreign Plans [Member] | Equity securities funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	106,694
Significant Other Observable Inputs (Level 2) [Member] | Foreign Plans [Member] | Fixed income securities funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	66,435
Significant Other Observable Inputs (Level 2) [Member] | Foreign Plans [Member] | Diversified pooled fund [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	27,813	30,800
Significant Unobservable Inputs (Level 3) [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	33,952	32,788
Significant Unobservable Inputs (Level 3) [Member] | Domestic Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	33,952	32,788
Significant Unobservable Inputs (Level 3) [Member] | Domestic Plans [Member] | Equity securities [Member] | Hedged funds and other alternative strategies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	$33,952	$32,788

Recovered_Sheet6

Employee and Retiree Benefit Plans (Effects of Fair Value Measurements Using Significant Unobservable Inputs on Changes in Level 3 Plan Assets) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Insurance [Abstract]
Beginning Balance	$32,788	$14,654
Actual return on plan assets:
Relating to assets held at the reporting date	1,164	3,134
Purchases, sales and settlements		15,000
Ending Balance	$33,952	$32,788

Financial_Instruments_and_Risk2

Financial Instruments and Risk Management (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2015	Dec. 31, 2013	31-May-12
	contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Accounts receivable for final settlement of WTI contracts	$23,168,000
Number of open WTI contracts	0
Repayments Of Notes Payable		350,000,000
Repayments of debt		350,000,000
Scenario, Forecast [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Deferred loss charged to income			2,963,000
Commodity Derivative Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair value of foreign derivative contracts
Fair value of commodity derivative contracts
Interest Rate Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Deferred loss charged to income	2,963,000	1,852,000		2,963,000
Loss deferred for fair value of interest rate derivative contracts, net of tax	21,852,000
Loss deferred for fair value of interest rate derivative contracts	7,648,000
Face amount of notes					350,000,000
Foreign exchange derivative contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair value of foreign derivative contracts	25,000			26,000
Fair value of commodity derivative contracts
Foreign exchange derivative contract [Member] | Currency, U.S. Dollar
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Short-term derivative instruments	$21,000,000			$32,300,000

Financial_Instruments_and_Risk3

Financial Instruments and Risk Management (Fair Value of Derivative Instruments Not Designated as Hedging Instruments) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Commodity Derivative Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives
Liability Derivatives
Commodity Derivative Contracts [Member] | Accounts Receivable [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	23,168,000	1,970,000
Foreign exchange derivative contract [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives
Liability Derivatives	25,000	26,000
Foreign exchange derivative contract [Member] | Accounts Payable [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$25,000	$1,038,000

Financial_Instruments_and_Risk4

Financial Instruments and Risk Management (Recognized Gains and Losses for Derivative Instruments Not Designated as Hedging Instruments) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Commodity Derivative Contracts [Member] | Sales and other operating revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivative	$17,887	$2,104
Commodity Derivative Contracts [Member] | Discontinued operations [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivative		-1,604
Foreign Currency Contract [Member] | Interest and other income (loss) [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivative	4,226	-5,162
Nondesignated [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in Income on Derivative	$22,113	($4,662)

Stockholders_Equity_Narrative_

Stockholder's Equity (Narrative) (Details) (USD $)	0 Months Ended		12 Months Ended
	Aug. 06, 2014	Dec. 03, 2012	Dec. 31, 2014	20-May-14	Oct. 31, 2012
			item
Shareholders Equity [Line Items]
Special dividend, per outstanding common share		$2.50
Special dividend		$486,141,000
Special dividends record date			16-Nov-12
Share buyback program, authorization	500,000,000			125,000,000
Number of share buyback programs			2
Shares repurchased, shares	0
Maximum [Member]
Shareholders Equity [Line Items]
Share buyback program, authorization					$1,000,000,000

Earnings_per_Share_WeightedAve

Earnings per Share (Weighted-Average Shares Outstanding for Computation of Basic and Diluted Income per Common Share) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings per Share [Abstract]
Basic method	178,852,942	187,921,062	193,902,335
Dilutive stock options and restricted stock units	1,218,042	1,350,336	766,402
Diluted method	180,070,984	189,271,398	194,668,737

Earnings_per_Share_Anti_Diluti

Earnings per Share (Anti Dilutive Securities Not Included in Computation of Diluted EPS) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings per Share [Abstract]
Antidilutive stock options excluded from diluted shares	1,893,364	1,026,900	3,329,689
Weighted average price of these options	$55.21	$54.54	$64.72

Other_Financial_Information_Na

Other Financial Information (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Information Of Parent Company Only Disclosure [Abstract]
Net gains (losses) from foreign currency transactions	$40,596,000	$73,732,000	$5,092,000
Income taxes paid	573,799,000	457,006,000	566,999,000
Interest paid, net of amounts capitalized	$114,232,000	$60,501,000	$9,501,000

Other_Financial_Information_No

Other Financial Information (Noncash Operating Working Capital) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental Quarterly Information [Abstract]
Accounts receivable	$175,820	$224,281	($382,137)
Inventories	25,697	14,166	-94,907
Prepaid expenses	6,575	195,013	-245,881
Deferred income tax assets	6,884	15,510	-7,218
Accounts payable and accrued liabilities	-54,785	-176,543	534,353
Current income tax liabilities	-163,920	-6,098	27,610
Net (increase) decrease in noncash operating working capital	($3,729)	$266,329	($168,180)

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Loss) (Components of Accumulated Other Comprehensive Income) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	$172,119	[1]	$408,901	[1]
Before reclassifications to income	-350,894	[1]	-181,155	[1]
Reclassifications to income	8,520	[1]	-55,627	[1]
Net other comprehensive income (loss)	-342,374	[1]	-236,782	[1]	98,481
Ending Balance	-170,255	[1]	172,119	[1]	408,901	[1]
Reclassifications before taxes, included in net periodic benefit expense	9,813		18,570
Reclassifications income tax, included in net periodic benefit expense	3,206		8,132
Reclassifications before taxes, included in interest expense	2,963		2,963
Reclassifications income tax, included in interest expense	1,050		1,028
Foreign Currency Translation Gains (Losses) [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	305,192	[1]	613,492	[1]
Before reclassifications to income	-271,491	[1]	-240,300	[1]
Reclassifications to income			-68,000	[1],[2]
Net other comprehensive income (loss)	-271,491	[1]	-308,300	[1]
Ending Balance	33,701	[1]	305,192	[1]
Retirement and Postretirement Benefit Plan Adjustments [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	-116,956	[1]	-186,539	[1]
Before reclassifications to income	-79,403	[1]	59,145	[1]
Reclassifications to income	6,607	[1],[3]	10,438	[1],[3]
Net other comprehensive income (loss)	-72,796	[1]	69,583	[1]
Ending Balance	-189,752	[1]	-116,956	[1]
Deferred Loss On Interest Rate Derivative Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance	-16,117	[1]	-18,052	[1]
Reclassifications to income	1,913	[1],[4]	1,935	[1],[4]
Net other comprehensive income (loss)	1,913	[1]	1,935	[1]
Ending Balance	($14,204)	[1]	($16,117)	[1]
[1]	All amounts are presented net of income taxes.
[2]	Reclassification is included in income from discontinued operations, net of income taxes.
[3]	Reclassifications before taxes of $18,570 and $9,813 are included in the computation of net periodic benefit expense in 2013 and 2014, respectively. Related income taxes of $8,132 and $3,206 are included in Income tax expense in 2013 and 2014, respectively.
[4]	Reclassifications before taxes of $2,963 are included in Interest expense in both 2013 and 2014. Related income taxes of $1,028 and $1,050 are included in Income tax expense in 2013 and 2014, respectively.

Assets_and_Liabilities_Measure2

Assets and Liabilities Measured at Fair Value (Fair Value Measurements for Assets and Liabilities) (Details) (Fair Value, Measurements, Recurring [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Assets, Commodity derivative contracts	$23,168	$1,970
Liabilities, Nonqualified employee savings plan	-14,408	-13,267
Liabilities, Foreign currency exchange derivative contracts	-25	-1,038
Liabilities, Total	-14,433	-14,305
Quoted Prices in Active Markets for Identical Assets (Level 1) [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Assets, Commodity derivative contracts
Liabilities, Nonqualified employee savings plan	-14,408	-13,267
Liabilities, Foreign currency exchange derivative contracts
Liabilities, Total	-14,408	-13,267
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Assets, Commodity derivative contracts	23,168	1,970
Liabilities, Nonqualified employee savings plan
Liabilities, Foreign currency exchange derivative contracts	-25	-1,038
Liabilities, Total	-25	-1,038
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Assets, Commodity derivative contracts
Liabilities, Nonqualified employee savings plan
Liabilities, Foreign currency exchange derivative contracts
Liabilities, Total

Assets_and_Liabilities_Measure3

Assets and Liabilities Measured at Fair Value (Carrying Amounts and Estimated Fair Values of Financial Instruments) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Financial assets (liabilities), Carrying value
Canadian government securities with maturities greater than 90 days at the date of acquisition	$461,313	$374,842
Current and long-term debt	-3,001,626	-2,962,812
Financial assets (liabilities):
Canadian government securities with maturities greater than 90 days at the date of acquisition	462,056	375,623
Current and long-term debt	($2,774,065)	($2,822,827)

Commitments_Narrative_Details

Commitments (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2006
Commitments and Contingencies Disclosure [Line Items]
Operating lease rental payments due in 2015	$108,717,000
Operating lease rental payments due in 2016	71,573,000
Operating lease rental payments due in 2017	51,744,000
Operating lease rental payments due in 2018	45,669,000
Operating lease rental payments due in 2019	37,062,000
Rental expenses for non-cancellable lease, including contingent payments	144,981,000	192,482,000	178,292,000
Commitments for capital expenditures	1,423,139,000
Malaysia [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	416,892,000
Gulf of Mexico [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	279,395,000
Eagle Ford Shale [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	378,989,000
Namibia [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	86,894,000
Vietnam [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	52,400,000
Equatorial Guinea [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	79,036,000
Australia [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	43,764,000
Drilling Rigs And Associated Equipment [Member]
Commitments and Contingencies Disclosure [Line Items]
Commitments for capital expenditures	559,272,000
Processing Production Handling and Transportation Services [Member]
Commitments and Contingencies Disclosure [Line Items]
Operating lease rental payments due in 2015	64,928,000
Operating lease rental payments due in 2016	49,792,000
Operating lease rental payments due in 2017	40,512,000
Operating lease rental payments due in 2018	33,019,000
Operating lease rental payments due in 2019	16,763,000
Processing and transportation charges	34,597,000	40,254,000	19,733,000
El Dorado Promise Annual Commitment from 2007 to 2016 [Member]
Commitments and Contingencies Disclosure [Line Items]
Future commitments	5,000,000
Commitments for capital expenditures				38,700,000
Accretion costs	$541,000	$805,000	$1,063,000

Contingencies_Narrative_Detail

Contingencies (Narrative) (Details)	Dec. 31, 2014
	site
Contingencies [Abstract]
Superfund site for which company is considered to be Potentially Responsible Party (PRP)	1

Common_Stock_Issued_and_Outsta2

Common Stock Issued and Outstanding (Activity in the Number of Common Stock Shares Issued and Outstanding) (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Equity [Abstract]
At beginning of year	183,406,513		190,641,317		193,723,208
Stock options exercised	119,994	[1]	303,685	[1]	482,974	[1]
Restricted stock awards	339,985	[1]	300,910	[1]	224,296	[1]
Employee stock purchase and thrift plans	6,739		16,020		78,389
Treasury shares purchased	-6,373,718		-7,855,419		-3,867,550
At end of year	177,499,513		183,406,513		190,641,317
[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.

Subsequent_Events_Narrative_De

Subsequent Events (Narrative) (Details) (USD $)	12 Months Ended			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 29, 2015
Subsequent Event [Line Items]
Proceeds from sales of property, plant and equipment	$1,467,046,000	$1,650,000	$99,000
Subsequent Event [Member]
Subsequent Event [Line Items]
Percentage of interest in oil and gas property sold during period				10.00%
Proceeds from sales of property, plant and equipment				$417,200,000

Business_Segments_Narrative_De

Business Segments (Narrative) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Phillips 66 and Affiliated Companies [Member]
Segment Reporting Information [Line Items]
Percentage of net sales revenue in oil and natural gas production	14.00%	17.00%
Shell Oil and Affiliates [Member]
Segment Reporting Information [Line Items]
Percentage of net sales revenue in oil and natural gas production	20.00%	14.00%
Shell Oil [Member]
Segment Reporting Information [Line Items]
Percentage of net sales revenue in oil and natural gas production			17.00%
BP [Member]
Segment Reporting Information [Line Items]
Percentage of net sales revenue in oil and natural gas production			13.00%
Petronas [Member]
Segment Reporting Information [Line Items]
Percentage of net sales revenue in oil and natural gas production			12.00%

Business_Segments_Segment_Info

Business Segments (Segment Information) (Details) (USD $)	3 Months Ended										12 Months Ended
	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]
Net income for the year	$375,200,000		$245,700,000	$129,400,000	$155,300,000	$75,400,000		$284,800,000	$402,700,000	$360,600,000	$905,611,000		$1,123,473,000		$970,876,000
External Revenues											5,476,084,000		5,390,089,000		4,619,602,000
Income tax expense (benefit)											227,297,000		584,550,000		561,516,000
Significant noncash charges (credits)
Depreciation, depletion, amortization											1,906,247,000		1,553,394,000		1,253,095,000
Accretion of asset retirement obligations											50,778,000		48,996,000		38,361,000
Amortization of undeveloped leases											74,438,000		66,891,000		129,750,000
Impairment of assets											51,314,000		21,587,000		200,000,000	[1]
Total Assets	16,742,307,000					17,509,484,000					16,742,307,000		17,509,484,000
External Customer [Member]
Segment Reporting Information [Line Items]
External Revenues											5,476,100,000		5,390,100,000		4,619,600,000
United States [Member]
Segment Reporting Information [Line Items]
External Revenues											2,201,500,000		1,798,500,000		1,038,100,000
Canada [Member]
Segment Reporting Information [Line Items]
External Revenues											1,052,400,000		1,150,200,000		1,088,400,000
Significant noncash charges (credits)
Impairment of assets	37,047,000
Malaysia [Member]
Segment Reporting Information [Line Items]
External Revenues											2,233,000,000		2,337,500,000		2,415,600,000
Other [Member]
Segment Reporting Information [Line Items]
External Revenues											-10,800,000		103,900,000		77,500,000
Discontinued Operations [Member]
Segment Reporting Information [Line Items]
Net income for the year											-119,400,000		235,400,000		164,400,000
Interest income											0		0		0
Interest expense, net of capitalization											0		0		0
Income tax expense (benefit)											0		0		0
Significant noncash charges (credits)
Depreciation, depletion, amortization											0		0		0
Accretion of asset retirement obligations											0		0		0
Amortization of undeveloped leases											0		0		0
Impairment of assets											0		0		0
Deferred and noncurrent income taxes											0		0		0
Additions to property, plant, equipment											0		8,100,000		191,800,000
Total Assets	427,100,000					1,325,100,000					427,100,000		1,325,100,000		3,410,100,000
Discontinued Operations [Member] | External Customer [Member]
Segment Reporting Information [Line Items]
External Revenues											0		0		0
Operating Segments [Member]
Segment Reporting Information [Line Items]
Net income for the year											905,600,000		1,123,500,000		970,900,000
Interest income											7,700,000		3,900,000		6,500,000
Interest expense, net of capitalization											115,800,000		71,900,000		14,900,000
Income tax expense (benefit)											227,300,000		584,600,000		561,500,000
Significant noncash charges (credits)
Depreciation, depletion, amortization											1,906,200,000		1,553,400,000		1,253,100,000
Accretion of asset retirement obligations											50,800,000		49,000,000		38,400,000
Amortization of undeveloped leases											74,400,000		66,900,000		129,800,000
Impairment of assets											51,300,000		21,600,000		200,000,000
Deferred and noncurrent income taxes											-170,900,000		158,100,000		342,800,000
Additions to property, plant, equipment											3,317,800,000		3,532,200,000		4,133,800,000
Total Assets	16,742,300,000					17,509,500,000					16,742,300,000		17,509,500,000		17,522,600,000
Operating Segments [Member] | External Customer [Member]
Segment Reporting Information [Line Items]
External Revenues											5,476,100,000		5,390,100,000		4,619,600,000
Exploration and production [Member]
Segment Reporting Information [Line Items]
Net income for the year											1,189,800,000		1,028,800,000		905,000,000
Interest income											0		0		0
Interest expense, net of capitalization											0		0		0
Income tax expense (benefit)											285,700,000		656,300,000		605,000,000
Significant noncash charges (credits)
Depreciation, depletion, amortization											1,897,500,000		1,543,600,000		1,244,400,000
Accretion of asset retirement obligations											50,800,000		49,000,000		38,400,000
Amortization of undeveloped leases											74,400,000		66,900,000		129,800,000
Impairment of assets											51,300,000		21,600,000		200,000,000
Deferred and noncurrent income taxes											-152,100,000		173,800,000		375,100,000
Additions to property, plant, equipment											3,303,300,000		3,508,600,000		3,933,800,000
Total Assets	14,541,300,000					14,919,200,000					14,541,300,000		14,919,200,000		13,102,900,000
Exploration and production [Member] | External Customer [Member]
Segment Reporting Information [Line Items]
External Revenues											5,422,700,000		5,312,600,000		4,608,100,000
Exploration and production [Member] | United States [Member]
Segment Reporting Information [Line Items]
Net income for the year											387,100,000		435,400,000		168,000,000
Interest income											0		0		0
Interest expense, net of capitalization											0		0		0
Income tax expense (benefit)											214,800,000		241,600,000		99,800,000
Significant noncash charges (credits)
Depreciation, depletion, amortization											840,700,000		576,300,000		330,200,000
Accretion of asset retirement obligations											17,500,000		13,500,000		11,400,000
Amortization of undeveloped leases											50,100,000		30,300,000		71,600,000
Impairment of assets											14,300,000		0		0
Deferred and noncurrent income taxes											39,700,000		99,600,000		231,000,000
Additions to property, plant, equipment											2,028,700,000		1,785,900,000		1,615,900,000
Total Assets	5,745,700,000					4,530,000,000					5,745,700,000		4,530,000,000		3,625,900,000
Exploration and production [Member] | United States [Member] | External Customer [Member]
Segment Reporting Information [Line Items]
External Revenues											2,196,400,000		1,803,800,000		1,038,000,000
Exploration and production [Member] | Canada [Member]
Segment Reporting Information [Line Items]
Net income for the year											156,500,000		180,800,000		208,100,000
Interest income											0		0		0
Interest expense, net of capitalization											0		0		0
Income tax expense (benefit)											64,200,000		57,800,000		65,100,000
Significant noncash charges (credits)
Depreciation, depletion, amortization											316,700,000		374,600,000		345,800,000
Accretion of asset retirement obligations											15,200,000		16,200,000		13,600,000
Amortization of undeveloped leases											19,400,000		21,000,000		29,300,000
Impairment of assets											37,000,000		21,600,000		0
Deferred and noncurrent income taxes											43,300,000		26,100,000		72,300,000
Additions to property, plant, equipment											445,900,000		334,500,000		887,200,000
Total Assets	3,769,800,000					4,087,800,000					3,769,800,000		4,087,800,000		4,477,700,000
Exploration and production [Member] | Canada [Member] | External Customer [Member]
Segment Reporting Information [Line Items]
External Revenues											1,044,100,000		1,144,700,000		1,084,300,000
Exploration and production [Member] | Malaysia [Member]
Segment Reporting Information [Line Items]
Net income for the year											896,200,000		786,400,000		894,200,000
Interest income											0		0		0
Interest expense, net of capitalization											0		0		0
Income tax expense (benefit)											102,600,000		477,700,000		544,700,000
Significant noncash charges (credits)
Depreciation, depletion, amortization											735,000,000		588,200,000		532,100,000
Accretion of asset retirement obligations											18,100,000		15,000,000		12,500,000
Amortization of undeveloped leases											0		0		0
Impairment of assets											0		0		0
Deferred and noncurrent income taxes											-235,100,000		48,100,000		73,300,000
Additions to property, plant, equipment											818,000,000		1,323,400,000		1,426,700,000
Total Assets	4,887,100,000					6,121,000,000					4,887,100,000		6,121,000,000		4,811,500,000
Exploration and production [Member] | Malaysia [Member] | External Customer [Member]
Segment Reporting Information [Line Items]
External Revenues											2,183,500,000		2,280,500,000		2,428,100,000
Exploration and production [Member] | Other [Member]
Segment Reporting Information [Line Items]
Net income for the year											-250,000,000	[2]	-373,800,000	[2]	-365,300,000	[2]
Interest income											0	[2]	0	[2]	0	[2]
Interest expense, net of capitalization											0	[2]	0	[2]	0	[2]
Income tax expense (benefit)											-95,900,000	[2]	-120,800,000	[2]	-104,600,000	[2]
Significant noncash charges (credits)
Depreciation, depletion, amortization											5,100,000	[2]	4,500,000	[2]	36,300,000	[2]
Accretion of asset retirement obligations											0	[2]	4,300,000	[2]	900,000	[2]
Amortization of undeveloped leases											4,900,000	[2]	15,600,000	[2]	28,900,000	[2]
Impairment of assets											0	[2]	0	[2]	200,000,000	[2]
Deferred and noncurrent income taxes											0	[2]	0	[2]	-1,500,000	[2]
Additions to property, plant, equipment											10,700,000	[2]	64,800,000	[2]	4,000,000	[2]
Total Assets	138,700,000	[2]				180,400,000	[2]				138,700,000	[2]	180,400,000	[2]	187,800,000	[2]
Exploration and production [Member] | Other [Member] | External Customer [Member]
Segment Reporting Information [Line Items]
External Revenues											-1,300,000	[2]	83,600,000	[2]	57,700,000	[2]
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Net income for the year											-164,800,000		-140,700,000		-98,500,000
Interest income											7,700,000		3,900,000		6,500,000
Interest expense, net of capitalization											115,800,000		71,900,000		14,900,000
Income tax expense (benefit)											-58,400,000		-71,700,000		-43,500,000
Significant noncash charges (credits)
Depreciation, depletion, amortization											8,700,000		9,800,000		8,700,000
Accretion of asset retirement obligations											0		0		0
Amortization of undeveloped leases											0		0		0
Impairment of assets											0		0		0
Deferred and noncurrent income taxes											-18,800,000		-15,700,000		-32,300,000
Additions to property, plant, equipment											14,500,000		15,500,000		8,200,000
Total Assets	1,773,900,000					1,265,200,000					1,773,900,000		1,265,200,000		1,009,600,000
Corporate and Other [Member] | External Customer [Member]
Segment Reporting Information [Line Items]
External Revenues											$53,400,000		$77,500,000		$11,500,000
[1]	Results exclude corporate overhead, interest and discontinued operations.
[2]	Reclassified to conform to current presentation.

Business_Segments_Geographic_I

Business Segments (Geographic Information on Certain Long-Lived Assets) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	$13,331.40		$13,481.50		$13,217.40
United States [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	5,419.50		4,267.90		4,177.40
Canada [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	3,574.60		3,834.90		4,190.50
Malaysia [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	4,258.80		5,301.70		4,101.20
United Kingdom [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	0.4		0.4		703.2
Other [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Certain Long-Lived Assets	$78.10	[1]	$76.60	[1]	$45.10	[1]
[1]	Reclassified to conform to current presentation.

Business_Segments_Geographic_I1

Business Segments (Geographic Information on Revenues from External Customers) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues from External Customers and Long-Lived Assets [Line Items]
External Revenues	$5,476,084	$5,390,089	$4,619,602
United States [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
External Revenues	2,201,500	1,798,500	1,038,100
Canada [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
External Revenues	1,052,400	1,150,200	1,088,400
Malaysia [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
External Revenues	2,233,000	2,337,500	2,415,600
Other [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
External Revenues	($10,800)	$103,900	$77,500

Supplemental_Oil_and_Gas_Infor2

Supplemental Oil and Gas Information (Narrative) (Details)	12 Months Ended
	Dec. 31, 2014
Reserve Quantities [Line Items]
Percentage of bitumen from total bulk tar sand mined	10.00%
Percentage of bitumen removed by extraction process that is contained within the tar sand	90.00%
Metric tons of oil sand used to produce one barrel of synthetic crude oil	2
Natural gas proved reserves expected to receive sale proceeds, per thousand cubic foot	0.24
Future net cash flows annual discount factor, percentage	10.00%
Minimum [Member]
Reserve Quantities [Line Items]
Catalytic cracking process efficiency level	85.00%
Maximum [Member]
Reserve Quantities [Line Items]
Catalytic cracking process efficiency level	90.00%
Canada [Member] | Synthetic Oil [Member]
Reserve Quantities [Line Items]
Interest in synthetic oil operations at Syncrude in Western Canada, percentage	5.00%
Process of mining tar sands and converting the raw bitumen into a pipeline-quality crude	The high-density core-hole drilling, at a spacing of less than 500B meters (proved area), provides engineering and geologic data needed to estimate the volumes of tar sand in place and its associated bitumen content.
Malaysia [Member] | Oil Reserves [Member]
Reserve Quantities [Line Items]
Oil and natural gas reserves associated with the production sharing contracts	94.6
Malaysia [Member] | Natural Gas Reserves [Member]
Reserve Quantities [Line Items]
Oil and natural gas reserves associated with the production sharing contracts	635,600,000,000
Malaysia [Member] | Natural Gas Reserves [Member] | Kikeh Field [Member]
Reserve Quantities [Line Items]
Oil and natural gas reserves associated with the production sharing contracts	54,700,000,000

Supplemental_Oil_and_Gas_Infor3

Supplemental Oil and Gas Information (Summary of Proved Reserves Based on Average Prices) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMBbls	MMBbls	MMBbls	MMBbls
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	471,200,000	414,800,000	349,700,000
Revisions of previous estimates	-9,300,000	27,400,000	2,300,000
Improved recovery	7,500,000	27,400,000	7,200,000
Extensions and discoveries	42,600,000	69,600,000	84,000,000
Sales of properties	-24,300,000
Purchases of properties	6,100,000	-20,400,000	12,500,000
Production	-52,000,000	-47,600,000	-40,900,000
Proved developed and undeveloped reserves, Ending Balance	441,800,000	471,200,000	414,800,000
Proved developed reserves	324,100,000	289,900,000	267,700,000	238,500,000
Proved undeveloped reserves	117,700,000	181,300,000	147,100,000	111,200,000
Crude Oil [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	354,200,000	295,700,000	220,200,000
Revisions of previous estimates	-2,300,000	24,800,000	7,600,000
Improved recovery	7,500,000	27,400,000	7,200,000
Extensions and discoveries	42,600,000	69,600,000	84,000,000
Sales of properties	-24,300,000
Purchases of properties	6,100,000	-20,400,000	12,500,000
Production	-47,600,000	-42,900,000	-35,800,000
Proved developed and undeveloped reserves, Ending Balance	336,200,000	354,200,000	295,700,000
Proved developed reserves	218,500,000	172,900,000	148,600,000	118,000,000
Proved undeveloped reserves	117,700,000	181,300,000	147,100,000	102,200,000
Natural Gas Liquids Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	24,400,000
Revisions of previous estimates	5,100,000	15,700,000	300,000
Extensions and discoveries	4,700,000	10,000,000
Sales of properties	-200,000
Production	-3,400,000	-1,300,000	-300,000
Proved developed and undeveloped reserves, Ending Balance	30,600,000	24,400,000
Proved developed reserves	17,500,000	14,200,000
Proved undeveloped reserves	13,100,000	10,200,000
Natural Gas Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	1,153,600,000,000	1,137,000,000,000	1,106,100,000,000
Revisions of previous estimates	167,200,000,000	33,700,000,000	20,200,000,000
Improved recovery	7,000,000,000	3,200,000,000	7,200,000,000
Extensions and discoveries	696,800,000,000	153,400,000,000	173,500,000,000
Sales of properties	-162,600,000,000	-19,000,000,000
Purchases of properties	5,500,000,000		9,400,000,000
Production	-162,800,000,000	-154,700,000,000	-179,400,000,000
Proved developed and undeveloped reserves, Ending Balance	1,704,700,000,000	1,153,600,000,000	1,137,000,000,000
Proved developed reserves	812,100,000,000	786,200,000,000	706,000,000,000	711,600,000,000
Proved undeveloped reserves	892,600,000,000	367,400,000,000	431,000,000,000	394,500,000,000
United States [Member] | Crude Oil [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	191,500,000	142,600,000	55,300,000
Revisions of previous estimates	-3,200,000	13,100,000	13,000,000
Extensions and discoveries	32,700,000	52,400,000	77,300,000
Sales of properties	-300,000
Purchases of properties	6,100,000		6,500,000
Production	-21,900,000	-16,600,000	-9,500,000
Proved developed and undeveloped reserves, Ending Balance	204,900,000	191,500,000	142,600,000
Proved developed reserves	106,200,000	75,800,000	48,000,000	20,800,000
Proved undeveloped reserves	98,700,000	115,700,000	94,600,000	34,500,000
United States [Member] | Natural Gas Liquids Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	23,200,000
Revisions of previous estimates	5,000,000	15,600,000
Extensions and discoveries	4,000,000	8,700,000
Production	-3,100,000	-1,100,000
Proved developed and undeveloped reserves, Ending Balance	29,100,000	23,200,000
Proved developed reserves	16,500,000	13,100,000
Proved undeveloped reserves	12,600,000	10,100,000
United States [Member] | Natural Gas Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	185,000,000,000	209,700,000,000	98,400,000,000
Revisions of previous estimates	47,700,000,000	-38,600,000,000	16,500,000,000
Extensions and discoveries	24,100,000,000	33,300,000,000	107,200,000,000
Sales of properties	-3,700,000,000
Purchases of properties	5,500,000,000		7,000,000,000
Production	-32,300,000,000	-19,400,000,000	-19,400,000,000
Proved developed and undeveloped reserves, Ending Balance	226,300,000,000	185,000,000,000	209,700,000,000
Proved developed reserves	145,600,000,000	112,600,000,000	78,800,000,000	58,200,000,000
Proved undeveloped reserves	80,700,000,000	72,400,000,000	130,900,000,000	40,200,000,000
Canada [Member] | Crude Oil [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	38,700,000	36,800,000	36,600,000
Revisions of previous estimates	2,700,000	8,400,000	-3,400,000
Extensions and discoveries	2,400,000	200,000	2,900,000
Sales of properties	-500,000
Purchases of properties			6,000,000
Production	-5,900,000	-6,700,000	-5,300,000
Proved developed and undeveloped reserves, Ending Balance	37,400,000	38,700,000	36,800,000
Proved developed reserves	32,400,000	31,600,000	29,500,000	32,600,000
Proved undeveloped reserves	5,000,000	7,100,000	7,300,000	4,000,000
Canada [Member] | Synthetic Oil [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	117,000,000	119,100,000	129,500,000
Revisions of previous estimates	-7,000,000	2,600,000	-5,300,000
Production	-4,400,000	-4,700,000	-5,100,000
Proved developed and undeveloped reserves, Ending Balance	105,600,000	117,000,000	119,100,000
Proved developed reserves	105,600,000	117,000,000	119,100,000	120,500,000
Proved undeveloped reserves				9,000,000
Canada [Member] | Natural Gas Liquids Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	100,000
Extensions and discoveries	600,000	100,000
Proved developed and undeveloped reserves, Ending Balance	700,000	100,000
Proved developed reserves	200,000
Proved undeveloped reserves	500,000	100,000
Canada [Member] | Natural Gas Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	562,800,000,000	550,400,000,000	638,900,000,000
Revisions of previous estimates	105,600,000,000	34,000,000,000	-37,200,000,000
Extensions and discoveries	231,500,000,000	42,500,000,000	25,800,000,000
Purchases of properties			2,400,000,000
Production	-57,100,000,000	-64,100,000,000	-79,500,000,000
Proved developed and undeveloped reserves, Ending Balance	842,800,000,000	562,800,000,000	550,400,000,000
Proved developed reserves	467,400,000,000	384,000,000,000	415,800,000,000	427,100,000,000
Proved undeveloped reserves	375,400,000,000	178,800,000,000	134,600,000,000	211,800,000,000
Malaysia [Member] | Crude Oil [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	124,000,000	95,700,000	104,400,000
Revisions of previous estimates	-1,800,000	3,300,000	-700,000
Improved recovery	7,500,000	27,400,000	7,200,000
Extensions and discoveries	7,500,000	17,000,000	3,800,000
Sales of properties	-23,500,000
Production	-19,800,000	-19,400,000	-19,000,000
Proved developed and undeveloped reserves, Ending Balance	93,900,000	124,000,000	95,700,000
Proved developed reserves	79,900,000	65,500,000	67,000,000	57,200,000
Proved undeveloped reserves	14,000,000	58,500,000	28,700,000	47,200,000
Malaysia [Member] | Natural Gas Liquids Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	1,100,000
Revisions of previous estimates	100,000	100,000	300,000
Extensions and discoveries	100,000	1,200,000
Sales of properties	-200,000
Production	-300,000	-200,000	-300,000
Proved developed and undeveloped reserves, Ending Balance	800,000	1,100,000
Proved developed reserves	800,000	1,100,000
Malaysia [Member] | Natural Gas Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance	405,800,000,000	357,600,000,000	347,800,000,000
Revisions of previous estimates	13,900,000,000	38,300,000,000	41,400,000,000
Improved recovery	7,000,000,000	3,200,000,000	7,200,000,000
Extensions and discoveries	441,200,000,000	77,600,000,000	40,500,000,000
Sales of properties	-158,900,000,000
Production	-73,400,000,000	-70,900,000,000	-79,300,000,000
Proved developed and undeveloped reserves, Ending Balance	635,600,000,000	405,800,000,000	357,600,000,000
Proved developed reserves	199,100,000,000	289,600,000,000	197,300,000,000	210,500,000,000
Proved undeveloped reserves	436,500,000,000	116,200,000,000	160,300,000,000	137,300,000,000
United Kingdom [Member] | Crude Oil [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance		20,600,000	21,600,000
Revisions of previous estimates			300,000
Purchases of properties		-20,400,000
Production		-200,000	-1,300,000
Proved developed and undeveloped reserves, Ending Balance		0	20,600,000
Proved developed reserves			4,100,000	5,100,000
Proved undeveloped reserves			16,500,000	16,500,000
United Kingdom [Member] | Natural Gas Reserves [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance		19,300,000,000	21,000,000,000
Revisions of previous estimates			-500,000,000
Sales of properties		-19,000,000,000
Production		-300,000,000	-1,200,000,000
Proved developed and undeveloped reserves, Ending Balance			19,300,000,000
Proved developed reserves			14,100,000,000	15,800,000,000
Proved undeveloped reserves			5,200,000,000	5,200,000,000
Other [Member] | Crude Oil [Member]
Proved developed and undeveloped oil reserves:
Proved developed and undeveloped reserves, Beginning Balance			2,300,000
Revisions of previous estimates			-1,600,000
Production			-700,000
Proved developed reserves				2,300,000

Supplemental_Oil_and_Gas_Infor4

Supplemental Oil and Gas Information (Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Property acquisition costs
Unproved	$92.90		$35.60		$132.50
Proved	7.4		13.2		311.5
Total acquisition costs	100.3		48.8		444
Exploration costs	430.1	[1]	493.7	[1]	448	[1]
Development costs	3,282.70	[1]	3,939.60	[1]	3,521.70	[1]
Total Costs	3,813.10		4,482.10		4,413.70
Charged to expense
Dry hole expense	270		262.9		181.1
Geophysical and other costs	169.2		172.4		69
Total charged to expense	439.2		435.3		250.1
Property additions	3,373.90		4,046.80		4,163.60
Exploration costs	430.1	[1]	493.7	[1]	448	[1]
Development costs	3,282.70	[1]	3,939.60	[1]	3,521.70	[1]
Total Costs	3,813.10		4,482.10		4,413.70
United States [Member]
Property acquisition costs
Unproved	92.9		32.4		107.7
Proved	7.4		13.2		69.1
Total acquisition costs	100.3		45.6		176.8
Exploration costs	160	[1]	112.4	[1]	174.5	[1]
Development costs	1,934.70	[1]	1,773.20	[1]	1,352.70	[1]
Total Costs	2,195		1,931.20		1,704
Charged to expense
Dry hole expense	92.1		46.1		32.3
Geophysical and other costs	37.7		29.1		19.6
Total charged to expense	129.8		75.2		51.9
Property additions	2,065.20		1,856		1,652.10
Exploration costs	160	[1]	112.4	[1]	174.5	[1]
Development costs	1,934.70	[1]	1,773.20	[1]	1,352.70	[1]
Total Costs	2,195		1,931.20		1,704
Canada [Member]
Property acquisition costs
Unproved					14.6
Proved					242.4
Total acquisition costs					257
Exploration costs	1.7	[1]	21.8	[1]	57	[1]
Development costs	413.8	[1]	351.6	[1]	664.5	[1]
Total Costs	415.5		373.4		978.5
Charged to expense
Dry hole expense			32.1		8
Geophysical and other costs	1.7		0.7		2.5
Total charged to expense	1.7		32.8		10.5
Property additions	413.8		340.6		968
Exploration costs	1.7	[1]	21.8	[1]	57	[1]
Development costs	413.8	[1]	351.6	[1]	664.5	[1]
Total Costs	415.5		373.4		978.5
Malaysia [Member]
Property acquisition costs
Exploration costs	6.3	[1]	14.9	[1]	68.8	[1]
Development costs	926.6	[1]	1,787.70	[1],[2]	1,433.70	[1]
Total Costs	932.9		1,802.60		1,502.50
Charged to expense
Dry hole expense	47.4		20.7		26.1
Geophysical and other costs	1.3		4.6		1.1
Total charged to expense	48.7		25.3		27.2
Property additions	884.2		1,777.30		1,475.30
Exploration costs	6.3	[1]	14.9	[1]	68.8	[1]
Development costs	926.6	[1]	1,787.70	[1],[2]	1,433.70	[1]
Total Costs	932.9		1,802.60		1,502.50
Non-cash capital lease obligation			358
United Kingdom [Member]
Property acquisition costs
Exploration costs					-1	[1],[3]
Development costs			8.1	[1],[3]	46.6	[1],[3]
Total Costs			8.1	[3]	45.6	[3]
Charged to expense
Dry hole expense					-0.8	[3]
Geophysical and other costs					-0.2	[3]
Total charged to expense					-1	[3]
Property additions			8.1	[3]	46.6	[3]
Exploration costs					-1	[1],[3]
Development costs			8.1	[1],[3]	46.6	[1],[3]
Total Costs			8.1	[3]	45.6	[3]
Other Regions [Member]
Property acquisition costs
Unproved			3.2	[4]	10.2	[4]
Total acquisition costs			3.2	[4]	10.2	[4]
Exploration costs	262.1	[1],[4]	344.6	[1],[4]	148.7	[1],[4]
Development costs	7.6	[1],[4]	19	[1],[4]	24.2	[1],[4]
Total Costs	269.7	[4]	366.8	[4]	183.1	[4]
Charged to expense
Dry hole expense	130.5	[4]	164	[4]	115.5	[4]
Geophysical and other costs	128.5	[4]	138	[4]	46	[4]
Total charged to expense	259	[4]	302	[4]	161.5	[4]
Property additions	10.7	[4]	64.8	[4]	21.6	[4]
Exploration costs	262.1	[1],[4]	344.6	[1],[4]	148.7	[1],[4]
Development costs	7.6	[1],[4]	19	[1],[4]	24.2	[1],[4]
Total Costs	269.7	[4]	366.8	[4]	183.1	[4]
Asset Retirement Obligation Costs [Member]
Property acquisition costs
Exploration costs			0.2		-1.6
Development costs	70.6		171.9		173.3
Total Costs	70.6		172.1		171.7
Charged to expense
Exploration costs			0.2		-1.6
Development costs	70.6		171.9		173.3
Total Costs	70.6		172.1		171.7
Asset Retirement Obligation Costs [Member] | United States [Member]
Property acquisition costs
Exploration costs					-1.7
Development costs	36.5		70.1		37.9
Total Costs	36.5		70.1		36.2
Charged to expense
Exploration costs					-1.7
Development costs	36.5		70.1		37.9
Total Costs	36.5		70.1		36.2
Asset Retirement Obligation Costs [Member] | Canada [Member]
Property acquisition costs
Exploration costs			0.2		0.1
Development costs	-32.1		5.9		80.7
Total Costs	-32.1		6.1		80.8
Charged to expense
Exploration costs			0.2		0.1
Development costs	-32.1		5.9		80.7
Total Costs	-32.1		6.1		80.8
Asset Retirement Obligation Costs [Member] | Malaysia [Member]
Property acquisition costs
Development costs	66.2		95.9		48.6
Total Costs	66.2		95.9		48.6
Charged to expense
Development costs	66.2		95.9		48.6
Total Costs	66.2		95.9		48.6
Asset Retirement Obligation Costs [Member] | United Kingdom [Member]
Property acquisition costs
Development costs					-11.5
Total Costs					-11.5
Charged to expense
Development costs					-11.5
Total Costs					-11.5
Asset Retirement Obligation Costs [Member] | Other Regions [Member]
Property acquisition costs
Development costs					17.6
Total Costs					17.6
Charged to expense
Development costs					17.6
Total Costs					$17.60
[1]	Includes non-cash asset retirement costs as follows:B 2014Exploration costs$ -B -B -B -B -B -B Development costs 36.5B (32.1) 66.2B -B -B 70.6B $ 36.5B (32.1) 66.2B -B -B 70.6B 2013Exploration costs$ -B 0.2B - -B -B 0.2B Development costs 70.1B 5.9B 95.9B -B -B 171.9B $ 70.1B 6.1B 95.9B -B -B 172.1B 2012Exploration costs$ (1.7) 0.1B - -B -B (1.6)Development costs 37.9B 80.7B 48.6B (11.5) 17.6B 173.3B $ 36.2B 80.8B 48.6B (11.5) 17.6B 171.7
[2]	Includes property costs associated with non-cash capital lease of $358.0 million at the Kakap field.
[3]	The Company has accounted for U.K. operations as discontinued operations due to the sale of these operations in the first halfB of 2013.
[4]	Due to the shutdown of production operations in Republic of the Congo, the Company now includes the result of these operations in the Other exploration and production segment in the above table.

Supplemental_Oil_and_Gas_Infor5

Supplemental Oil and Gas Information (Results of Operations for Oil andGas Producing Activities) (Details) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Revenues
Revenues		$5,273,100,000	[1]	$5,306,300,000	[1]	$4,599,600,000	[1]
Other operating revenues		149,600,000	[1]	6,300,000	[1]	8,500,000	[1]
Results of Operations, Revenue from Oil and Gas Producing Activities, Total		5,422,700,000	[1]	5,312,600,000	[1]	4,608,100,000	[1]
Costs and expenses
Lease operating expenses		1,089,900,000	[1]	1,252,900,000	[1]	1,079,200,000	[1]
Severance and ad valorem taxes		107,200,000	[1]	87,300,000	[1]	35,600,000	[1]
Exploration costs charged to expense		439,200,000	[1]	435,300,000	[1]	251,100,000	[1]
Undeveloped lease amortization		74,400,000	[1]	66,900,000	[1]	129,800,000	[1]
Depreciation, depletion and amortization		1,897,500,000	[1]	1,543,600,000	[1]	1,244,400,000	[1]
Accretion of asset retirement obligations		50,800,000	[1]	49,000,000	[1]	38,400,000	[1]
Impairment of assets		51,314,000		21,587,000		200,000,000	[1]
Selling and general expenses		212,000,000	[1]	170,900,000	[1]	119,600,000	[1]
Other expenses		24,900,000	[1]
Other expenses		169,200,000		172,400,000		69,000,000
Total costs and expenses		3,947,200,000	[1]	3,627,500,000	[1]	3,098,100,000	[1]
Results of operations before taxes		1,475,500,000	[1]	1,685,100,000	[1]	1,510,000,000	[1]
Income tax expense (benefit)		285,700,000	[1]	656,300,000	[1]	605,000,000	[1]
Results of operations		1,189,800,000	[1]	1,028,800,000	[1]	905,000,000	[1]
Crude Oil and Natural Gas Liquids [Member]
Revenues
Revenues		4,587,100,000	[1]	4,631,500,000	[1]	3,854,500,000	[1]
Natural Gas [Member]
Revenues
Revenues		686,000,000	[1]	674,800,000	[1]	745,100,000	[1]
United States [Member]
Costs and expenses
Other expenses		37,700,000		29,100,000		19,600,000
United States [Member] | Oil Reserves [Member]
Revenues
Revenues		2,189,300,000	[1]	1,797,400,000	[1]	1,030,300,000	[1]
Other operating revenues		7,100,000	[1]	6,400,000	[1]	7,700,000	[1]
Results of Operations, Revenue from Oil and Gas Producing Activities, Total		2,196,400,000	[1]	1,803,800,000	[1]	1,038,000,000	[1]
Costs and expenses
Lease operating expenses		345,500,000	[1]	273,600,000	[1]	225,400,000	[1]
Severance and ad valorem taxes		96,500,000	[1]	77,500,000	[1]	27,000,000	[1]
Exploration costs charged to expense		129,800,000	[1]	75,200,000	[1]	51,900,000	[1]
Undeveloped lease amortization		50,100,000	[1]	30,300,000	[1]	71,600,000	[1]
Depreciation, depletion and amortization		840,700,000	[1]	576,300,000	[1]	330,200,000	[1]
Accretion of asset retirement obligations		17,500,000	[1]	13,500,000	[1]	11,400,000	[1]
Impairment of assets		14,300,000	[1]
Selling and general expenses		95,200,000	[1]	80,400,000	[1]	52,700,000	[1]
Other expenses		4,900,000	[1]
Total costs and expenses		1,594,500,000	[1]	1,126,800,000	[1]	770,200,000	[1]
Results of operations before taxes		601,900,000	[1]	677,000,000	[1]	267,800,000	[1]
Income tax expense (benefit)		214,800,000	[1]	241,600,000	[1]	99,800,000	[1]
Results of operations		387,100,000	[1]	435,400,000	[1]	168,000,000	[1]
United States [Member] | Crude Oil and Natural Gas Liquids [Member] | Oil Reserves [Member]
Revenues
Revenues		2,062,100,000	[1]	1,724,700,000	[1]	976,100,000	[1]
United States [Member] | Natural Gas [Member] | Oil Reserves [Member]
Revenues
Revenues		127,200,000	[1]	72,700,000	[1]	54,200,000	[1]
Canada [Member]
Costs and expenses
Impairment of assets	37,047,000
Other expenses		1,700,000		700,000		2,500,000
Canada [Member] | Conventional [Member]
Revenues
Revenues		654,600,000	[1]	705,300,000	[1]	621,500,000	[1]
Other operating revenues		-2,400,000	[1]	-1,900,000	[1]	-900,000	[1]
Results of Operations, Revenue from Oil and Gas Producing Activities, Total		652,200,000	[1]	703,400,000	[1]	620,600,000	[1]
Costs and expenses
Lease operating expenses		160,300,000	[1]	180,500,000	[1]	163,700,000	[1]
Severance and ad valorem taxes		5,600,000	[1]	5,000,000	[1]	3,500,000	[1]
Exploration costs charged to expense		1,700,000	[1]	32,800,000	[1]	10,500,000	[1]
Undeveloped lease amortization		19,400,000	[1]	21,000,000	[1]	29,300,000	[1]
Depreciation, depletion and amortization		262,700,000	[1]	319,200,000	[1]	290,500,000	[1]
Accretion of asset retirement obligations		6,000,000	[1]	5,900,000	[1]	5,100,000	[1]
Impairment of assets		37,000,000	[1]	21,600,000	[1]
Selling and general expenses		26,700,000	[1]	25,300,000	[1]	19,700,000	[1]
Other expenses		1,000,000	[1]
Total costs and expenses		520,400,000	[1]	611,300,000	[1]	522,300,000	[1]
Results of operations before taxes		131,800,000	[1]	92,100,000	[1]	98,300,000	[1]
Income tax expense (benefit)		42,400,000	[1]	19,900,000	[1]	25,100,000	[1]
Results of operations		89,400,000	[1]	72,200,000	[1]	73,200,000	[1]
Canada [Member] | Synthetic Oil [Member]
Revenues
Revenues		391,500,000	[1]	441,000,000	[1]	463,100,000	[1]
Other operating revenues		400,000	[1]	300,000	[1]	600,000	[1]
Results of Operations, Revenue from Oil and Gas Producing Activities, Total		391,900,000	[1]	441,300,000	[1]	463,700,000	[1]
Costs and expenses
Lease operating expenses		233,800,000	[1]	223,400,000	[1]	219,000,000	[1]
Severance and ad valorem taxes		5,100,000	[1]	4,800,000	[1]	5,100,000	[1]
Depreciation, depletion and amortization		54,000,000	[1]	55,400,000	[1]	55,300,000	[1]
Accretion of asset retirement obligations		9,200,000	[1]	10,300,000	[1]	8,500,000	[1]
Selling and general expenses		900,000	[1]	900,000	[1]	900,000	[1]
Total costs and expenses		303,000,000	[1]	294,800,000	[1]	288,800,000	[1]
Results of operations before taxes		88,900,000	[1]	146,500,000	[1]	174,900,000	[1]
Income tax expense (benefit)		21,800,000	[1]	37,900,000	[1]	40,000,000	[1]
Results of operations		67,100,000	[1]	108,600,000	[1]	134,900,000	[1]
Canada [Member] | Crude Oil and Natural Gas Liquids [Member] | Conventional [Member]
Revenues
Revenues		453,300,000	[1]	507,200,000	[1]	411,700,000	[1]
Canada [Member] | Crude Oil and Natural Gas Liquids [Member] | Synthetic Oil [Member]
Revenues
Revenues		391,500,000	[1]	441,000,000	[1]	463,100,000	[1]
Canada [Member] | Natural Gas [Member] | Conventional [Member]
Revenues
Revenues		201,300,000	[1]	198,100,000	[1]	209,800,000	[1]
Malaysia [Member]
Costs and expenses
Other expenses		1,300,000		4,600,000		1,100,000
Malaysia [Member] | Oil Reserves [Member]
Revenues
Revenues		2,037,700,000	[1]	2,279,000,000	[1]	2,427,100,000	[1]
Other operating revenues		145,800,000	[1]	1,500,000	[1]	1,000,000	[1]
Results of Operations, Revenue from Oil and Gas Producing Activities, Total		2,183,500,000	[1]	2,280,500,000	[1]	2,428,100,000	[1]
Costs and expenses
Lease operating expenses		350,300,000	[1]	384,400,000	[1]	422,700,000	[1]
Exploration costs charged to expense		48,700,000	[1]	25,300,000	[1]	27,200,000	[1]
Depreciation, depletion and amortization		735,000,000	[1]	588,200,000	[1]	532,100,000	[1]
Accretion of asset retirement obligations		18,100,000	[1]	15,000,000	[1]	12,500,000	[1]
Selling and general expenses		15,700,000	[1]	3,500,000	[1]	-5,300,000	[1]
Other expenses		16,900,000	[1]
Total costs and expenses		1,184,700,000	[1]	1,016,400,000	[1]	989,200,000	[1]
Results of operations before taxes		998,800,000	[1]	1,264,100,000	[1]	1,438,900,000	[1]
Income tax expense (benefit)		102,600,000	[1]	477,700,000	[1]	544,700,000	[1]
Results of operations		896,200,000	[1]	786,400,000	[1]	894,200,000	[1]
Malaysia [Member] | Crude Oil and Natural Gas Liquids [Member] | Oil Reserves [Member]
Revenues
Revenues		1,680,200,000	[1]	1,875,000,000	[1]	1,946,000,000	[1]
Malaysia [Member] | Natural Gas [Member] | Oil Reserves [Member]
Revenues
Revenues		357,500,000	[1]	404,000,000	[1]	481,100,000	[1]
Other Regions [Member]
Costs and expenses
Other expenses		128,500,000	[2]	138,000,000	[2]	46,000,000	[2]
Other Regions [Member] | Oil Reserves [Member]
Revenues
Revenues				83,600,000	[1],[3]	57,600,000	[1],[3]
Other operating revenues		-1,300,000	[1],[3]			100,000	[1],[3]
Results of Operations, Revenue from Oil and Gas Producing Activities, Total		-1,300,000	[1],[3]	83,600,000	[1],[3]	57,700,000	[1],[3]
Costs and expenses
Lease operating expenses				191,000,000	[1],[3]	48,400,000	[1],[3]
Exploration costs charged to expense		259,000,000	[1],[3]	302,000,000	[1],[3]	161,500,000	[1],[3]
Undeveloped lease amortization		4,900,000	[1],[3]	15,600,000	[1],[3]	28,900,000	[1],[3]
Depreciation, depletion and amortization		5,100,000	[1],[3]	4,500,000	[1],[3]	36,300,000	[1],[3]
Accretion of asset retirement obligations				4,300,000	[1],[3]	900,000	[1],[3]
Impairment of assets						200,000,000	[1],[3]
Selling and general expenses		73,500,000	[1],[3]	60,800,000	[1],[3]	51,600,000	[1],[3]
Other expenses		2,100,000	[1],[3]
Total costs and expenses		344,600,000	[1],[3]	578,200,000	[1],[3]	527,600,000	[1],[3]
Results of operations before taxes		-345,900,000	[1],[3]	-494,600,000	[1],[3]	-469,900,000	[1],[3]
Income tax expense (benefit)		-95,900,000	[1],[3]	-120,800,000	[1],[3]	-104,600,000	[1],[3]
Results of operations		-250,000,000	[1],[3]	-373,800,000	[1],[3]	-365,300,000	[1],[3]
Other Regions [Member] | Crude Oil and Natural Gas Liquids [Member] | Oil Reserves [Member]
Revenues
Revenues				$83,600,000	[1],[3]	$57,600,000	[1],[3]
[1]	Results exclude corporate overhead, interest and discontinued operations.
[2]	Due to the shutdown of production operations in Republic of the Congo, the Company now includes the result of these operations in the Other exploration and production segment in the above table.
[3]	Due to the shutdown of production operations in Republic of the Congo, the Company now includes the results of these operations in the Other exploration and production segment in the above table.

Supplemental_Oil_and_Gas_Infor6

Supplemental Oil and Gas Information (Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	$48,934.10	$50,150.50	$43,809.20
Future development costs	-6,882.70	-7,161.50	-6,786.90
Future production costs	-18,724.30	-16,808.10	-14,684.70
Future income taxes	-5,569.60	-6,696.20	-6,791.10
Future net cash flows	17,757.50	19,484.70	15,546.50
10% annual discount for estimated timing of cash flows	-7,852.30	-8,640	-7,433.70
Standardized measure of discounted future net cash flows	9,905.20	10,844.70	8,112.80	7,923.20
United States [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	20,767.40	20,638.60	15,547.50
Future development costs	-3,151.40	-3,833.90	-3,731.60
Future production costs	-6,378.50	-5,244.70	-3,466.60
Future income taxes	-2,930.10	-3,368.30	-2,527.60
Future net cash flows	8,307.40	8,191.70	5,821.70
10% annual discount for estimated timing of cash flows	-3,729.10	-4,020.20	-2,862.10
Standardized measure of discounted future net cash flows	4,578.30	4,171.50	2,959.60
Canada [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	16,257	16,112.90	15,511.60
Future development costs	-1,810.50	-1,882.30	-1,815.20
Future production costs	-7,770.20	-7,073	-7,336.40
Future income taxes	-1,389.60	-1,472.80	-1,714.90
Future net cash flows	5,286.70	5,684.80	4,645.10
10% annual discount for estimated timing of cash flows	-2,595.30	-2,999.10	-2,876.50
Standardized measure of discounted future net cash flows	2,691.40	2,685.70	1,768.60
Malaysia [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows	11,909.70	13,399	10,354.90
Future development costs	-1,920.80	-1,445.30	-966.9
Future production costs	-4,575.60	-4,490.40	-3,143.40
Future income taxes	-1,249.90	-1,855.10	-1,675.90
Future net cash flows	4,163.40	5,608.20	4,568.70
10% annual discount for estimated timing of cash flows	-1,527.90	-1,620.70	-1,322.90
Standardized measure of discounted future net cash flows	2,635.50	3,987.50	3,245.80
United Kingdom [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows			2,395.20
Future development costs			-273.2
Future production costs			-738.3
Future income taxes			-872.7
Future net cash flows			511
10% annual discount for estimated timing of cash flows			-372.2
Standardized measure of discounted future net cash flows			$138.80

Supplemental_Oil_and_Gas_Infor7

Supplemental Oil and Gas Information (Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]
Net changes in prices and production costs	($2,697.80)	$267.80	($2,461.10)
Net changes in development costs	-2,317.30	-3,456.80	-3,860.10
Sales and transfers of oil and gas produced, net of production costs	-4,076	-3,972.40	-3,493.30
Net change due to extensions and discoveries	3,251.60	4,608.90	4,466.30
Net change due to purchases and sales of proved reserves	-1,041	-135.6	347.4
Development costs incurred	3,169.30	3,326.80	3,299
Accretion of discount	1,462.50	1,109.30	1,153.50
Revisions of previous quantity estimates	518.9	1,646	728.1
Net change in income taxes	790.3	-662.1	9.8
Net increase (decrease)	-939.5	2,731.90	189.6
Standardized measure	$9,905.20	$10,844.70	$8,112.80	$7,923.20

Supplemental_Oil_and_Gas_Infor8

Supplemental Oil and Gas Information (Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	$1,227.10		$1,598
Proved oil and gas properties	21,368.70		20,214.70
Gross capitalized costs	22,595.80		21,812.70
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	-513.8		-518.3
Proved oil and gas properties	-8,862.30		-7,909.70
Net capitalized costs	13,219.70		13,384.70
Oil Reserves [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	1,227.10		1,598
Proved oil and gas properties	19,981.80		18,721.20
Gross capitalized costs	21,208.90		20,319.20
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	-513.8		-518.3
Proved oil and gas properties	-8,429.20		-7,492.10
Net capitalized costs	12,265.90		12,308.80
Synthetic Oil [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved oil and gas properties	1,386.90		1,493.50
Gross capitalized costs	1,386.90		1,493.50
Accumulated depreciation, depletion and amortization
Proved oil and gas properties	-433.1		-417.6
Net capitalized costs	953.8		1,075.90
United States [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	634.9		723.6
Proved oil and gas properties	7,810.90		5,816.90
Gross capitalized costs	8,445.80		6,540.50
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	-171.6		-178.1
Proved oil and gas properties	-2,944		-2,171.10
Net capitalized costs	5,330.20		4,191.30
Canada [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	424.1		475.9
Proved oil and gas properties	4,515.40		4,529.90
Gross capitalized costs	4,939.50		5,005.80
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	-245.6		-248.5
Proved oil and gas properties	-2,082.10		-2,006.80
Net capitalized costs	2,611.80		2,750.50
Malaysia [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties			233.5
Proved oil and gas properties	6,917.70		7,636.60
Gross capitalized costs	6,917.70		7,870.10
Accumulated depreciation, depletion and amortization
Proved oil and gas properties	-2,665.30		-2,576.40
Net capitalized costs	4,252.40		5,293.70
Other Regions [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Unproved oil and gas properties	168.1	[1]	165	[1]
Proved oil and gas properties	737.8	[1]	737.8	[1]
Gross capitalized costs	905.9	[1]	902.8	[1]
Accumulated depreciation, depletion and amortization
Unproved oil and gas properties	-96.6	[1]	-91.7	[1]
Proved oil and gas properties	-737.8	[1]	-737.8	[1]
Net capitalized costs	$71.50	[1]	$73.30	[1]
[1]	Due to the shutdown of production operations in Republic of the Congo, the Company now includes the results of these operations in the Other exploration and production segment in the above table.

Supplemental_Quarterly_Infomat

Supplemental Quarterly Infomation (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Supplemental Quarterly Information [Abstract]
Sales and other operating revenues	$1,218,800		$1,431,000		$1,357,900		$1,281,200		$1,331,700		$1,366,500		$1,315,600		$1,298,900		$5,288,933		$5,312,686		$4,608,563
Income from continuing operations before income taxes	217,000		396,500		304,600		334,200		194,800		463,700		454,200		360,000		1,252,270		1,472,687		1,368,010
Income from continuing operations	442,000		271,000		142,700		169,300		180,500		265,000		259,900		182,700		1,024,973		888,137		806,494
Net income	$375,200		$245,700		$129,400		$155,300		$75,400		$284,800		$402,700		$360,600		$905,611		$1,123,473		$970,876
Income from continuing operations per Common share, Basic	$2.49		$1.52		$0.80		$0.94		$0.98		$1.42		$1.38		$0.96		$5.73		$4.73		$4.16
Income from continuing operations per Common share, Diluted	$2.48		$1.51		$0.79		$0.93		$0.96		$1.41		$1.37		$0.95		$5.69		$4.69		$4.14
Net income per Common share, Basic	$2.11		$1.38		$0.72		$0.86		$0.41		$1.52		$2.13		$1.89		$5.06		$5.98		$5.01
Net income per Common share, Diluted	$2.10		$1.37		$0.72		$0.85		$0.40		$1.51		$2.12		$1.88		$5.03		$5.94		$4.99
Cash dividend per Common share	$0.35		$0.35		$0.31		$0.31		$0.31		$0.31		$0.31		$0.31		$1.32		$1.25		$3.67
Market price of Common Stock, High	$56.13	[1]	$67.75	[1]	$66.82	[1]	$63.70	[1]	$65.55	[1]	$71.84	[1]	$66.09	[1]	$63.81	[1]	$67.75	[1]	$71.84	[1]
Market price of Common Stock, Low	$44.39	[1]	$56.18	[1]	$59.61	[1]	$55.68	[1]	$59.93	[1]	$59.80	[1]	$59.98	[1]	$59.33	[1]	$44.39	[1]	$59.33	[1]
[1]	Prices are as quoted on the New York Stock Exchange.

Valuation_Accounts_and_Reserve1

Valuation Accounts and Reserves (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Allowance for doubtful accounts [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at January 1			$6.70		$7.90
Charged (Credited) to Expense			0.4		0.3
Deductions			-0.4		-1.5
Other			-5.1	[1]
Balance at December 31	1.6		1.6		6.7
Deferred tax asset valuation allowance [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Balance at January 1	633.7		524		445.8
Charged (Credited) to Expense	37.7		115.4		78.2
Other	-364.9	[1]	-5.7	[1]
Balance at December 31	$306.50		$633.70		$524
[1]	Amount in 2014 for deferred tax asset valuation allowance is primarily associated with final abandonment of certain foreign investments in 2014, essentially offsetting changes in deferred tax assets. Amounts in 2013 primarily arose due to separation of Murphy USA Inc. and presentation of U.K. downstream operations as assets held for sale.